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TABLE OF CONTENTS
PART IV
Item 8. Financial Statements and Supplementary Data.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K


ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

Commission file number: 1-11748

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


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

The Bank of New York 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 Registered

Depositary Units		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, 2013, 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, 2013, 2,021,400 Units of Beneficial Interest (the "Withdrawn Units") had 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, 2012 of $21.12 per unit was approximately $82 million.

Documents Incorporated By Reference: None

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TABLE OF CONTENTS


PART I		3
Item 1.	Business	3
	Description of the Trust	3
	The Net Profits Interests	6
	The Underlying Properties	10
	Competition and Markets	14
	Regulation of Natural Gas	15
	Health, Safety and Environmental Regulation	15
	Description of Trust Units and Depositary Units	17
	Federal Income Tax Matters	20
	State Tax Considerations	21
	Available Information	21
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
PART II		26
Item 5.	Market for Registrant's Common Equity, Related Unitholders Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	26
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operation	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 8.	Financial Statements and Supplementary Data	32
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	33
Item 9A.	Controls and Procedures	33
Item 9B.	Other Information	34
PART III		35
Item 10.	Directors, Executive Officers, and Corporate Goverance	35
Item 11.	Executive Compensation	35
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35
Item 13.	Certain Relationships and Related Transactions, and Director Independence	36
Item 14.	Principal Accounting Fees and Services	36
PART IV		37
Item 15.	Exhibits, Financial Statement Schedules	37
SIGNATURES		39

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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 or Trust 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 Bank of New York Mellon Trust Company, N.A., as trustee (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 prior to May 15, 2013 (the "Liquidation Date"). As described in the Trust's previous filings, the Trustee was required by the terms of the Trust Agreement to cause the sale of the Royalty NPI held by the Trust (the "Royalty NPI"). In accordance with the requirements of the Trust Agreement, the Trustee marketed the Royalty NPI during 2012 and entered into a Purchase and Sale Agreement with the highest bidder for the Royalty NPI (the "October 24, 2012 Agreement"). On November 5, 2012, ECA exercised its right of first refusal under the Trust Agreement to purchase the Royalty NPI on the terms set forth in the October 24, 2012 Agreement. As a consequence of ECA's exercise of its right of first refusal, the October 24, 2012 Agreement terminated in accordance with its terms, and the Trust became obligated to sell the Royalty NPI to ECA for the purchase price determined by the October 24, 2012 Agreement. On January 3, 2013, the

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Trust entered into a Purchase and Sale Agreement with ECA to document the terms of the sale of the Royalty NPI to ECA and to eliminate provisions of the October 24, 2012 Agreement that were inapplicable to the sale of the Royalty NPI to ECA. The sale of the Royalty NPI to ECA was completed on January 10, 2013. The price, after making the adjustment for gas price changes required by the October 24, 2012 Agreement, was $5,917,275, and was paid in cash.

Pursuant to the Trust Agreement, all proceeds of the sale of the Royalty NPI and all other receipts of the Trust received after December 31, 2012, will be retained by the Trustee until a final distribution is made. 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. Unitholders as of the close of business on May 31, 2013 will, on or about June 17, 2013, as a result of the liquidation and winding down of the Trust on May 15, 2013, receive the proceeds attributable to the mature Treasury Obligation ($20.00 per trust unit), unless the Treasury Obligation relating to such trust unit has previously been withdrawn. On or about August 15, 2013, such Unitholders will also receive their pro rata share of the net proceeds received from the Trust's sale in January 2013 of the Royalty NPI (estimated to be approximately $0.95 per trust unit, based on net proceeds of approximately $5.65 million) plus their pro rata share of revenues attributable to the term net profits interest for the period beginning October 1, 2012 through May 15, 2013, less any costs and expenses or reserves of the Trust during such period. Trading in the Units will be stopped at the end of regular trading on the New York Stock Exchange (the "NYSE") at the close of business on May 31, 2013, and no transfers will be permitted after that date. See "Description of Trust Units and Depository Units—Liquidation of the Trust."

On February 13, 2013 ECA commenced an exchange offer in which ECA offered to exchange up to 4,120,059 units of ECA Marcellus Trust I, a Delaware statutory trust also sponsored by ECA, for up to 3,197,385 Depositary Units of the Trust. The offer expired at 11:59 p.m. New York City Time, on March 13, 2013.

Until March 26, 2012, Eastern Marketing Corporation was a wholly-owned subsidiary of Energy Corporation of America. Effective March 26, 2012, Eastern Marketing Corporation was merged into Energy Corporation of America, with Energy Corporation of America being the surviving corporation. The merger of Eastern Marketing Corporation into its parent Energy Corporation of America has not had any effect on the Trust.

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 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

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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 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 included herewith). On or about May 15, 2013 (the "Liquidation Date"), the Trustee is required to sell the remaining royalty interests and begin the liquidation of the Trust. As described herein, the Trust completed the sale of the Royalty NPI on January 10, 2013. Because ECA acquired the rights to the distribution for the fourth quarter of 2012, the sale had an effective date of October 1, 2012. The Trust's remaining net profits interest is a Term NPI, which will terminate by its terms on May 15, 2013, and revert to ECA, and the Trust will receive no further value from the Term NPI after that date.

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

The Net Profits Interests are passive in nature, and neither the Trustee nor the Delaware Trustee has management control or authority over, nor any responsibility relating to, the operation of the Underlying Properties (defined above) subject to the Net Profits Interests. The Trust Agreement provides, among other things, that: the Trust shall not engage in any business or commercial activity or acquire any asset other than the Net Profits Interests initially conveyed to the Trust; the Trustee may establish a reserve for payment of any liability which is contingent, uncertain in amount or that is not currently due and payable; and 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.

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 2012 were $108,000. The total of all Trustee fees and Trust administrative expenses for 2012 was $1,017,119. Such costs could fluctuate in 2013 depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services, and may be materially higher during 2013 than they have been in the past as the Trust incurs expenses in connection with its liquidation in accordance with the Trust Agreement. In addition to such expenses, in 2012, the Trust paid ECA an overhead reimbursement of $403,724. The overhead reimbursement was established at the inception of the Trust, increased by 3.5% per year, and is payable quarterly.

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have previously been withdrawn. On or about August 15, 2013, such Unitholders will also receive their pro rata share of the net proceeds received from the Trust's sale in January 2013 of the Royalty NPI (estimated to be approximately $0.95 per trust unit, based on net proceeds of $5.65 million) plus their pro rata share of revenues attributable to the Term NPI for the period beginning October 1, 2012 through May 15, 2013, less any costs and expenses or reserves of the Trust during such period. Trading in the trust units will be stopped at the end of regular trading on the NYSE at the close of business on May 31, 2013, and no transfers will be permitted after that date.

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"). As described herein, the Trust sold its interest under the Royalty NPI Conveyance, including the right to the distribution for the fourth quarter of 2012, to ECA for $5.9 million on January 10, 2013, and the Trust's interest under the Term NPI Conveyance will terminate by its terms on May 15, 2013, and the Trust will receive no further value from it after that date. 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 represented, 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 ECA as successor to Eastern Marketing 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 will 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 Term NPI. As of December 31, 2012, 28,239 MMcf of such gas had been produced. Consequently, the Term NPI will terminate on May 15, 2013.

The Royalty NPI was not limited in term or amount. Under the Trust Agreement, the Trustee was directed to sell the Royalty NPI after May 15, 2012 and prior to May 15, 2013, and has done so.

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."

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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. As described herein, the Trust has sold its interest under the Royalty NPI Conveyance.

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 at the beginning of the year 2012 was estimated to be $599,556, for 2011 was $658,604 and for 2010 was $658,604. The 2012 Operating Cost Charge was decreased during the quarter ended December 31, 2012 as a result of wells sold during the fourth quarter. 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 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

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industry is generally adopting the same as a replacement. ECA, with the concurrence of the Trustee, will utilize this "Overhead Adjustment Index" to adjust the "Operating Cost Charge" so long as such index is published by COPAS.

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

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 was originally purchased by Eastern Marketing (which merged into ECA during 2012) 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, ECA, as successor by merger to Eastern Marketing, purchases gas for the benefit of the Trust at a variable price for each quarter equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal, for such contracts which expired in each of the five months prior to such month, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported 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 determined as of the contract settlement date for such month, as reported in The 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 pursuant to the Gas Purchase Contract is a wellhead price and title to the gas purchased passes at the point of delivery. Payments to the Trust are made by ECA 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

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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.

ECA's rights and obligations under the Gas Purchase Contract are assignable under circumstances where the assignee unconditionally assumes ECA'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, ECA would be released from its obligations under the Gas Purchase Contract.

Distributions and Income Computations

The Trustee determines for each quarter the amount of cash available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. Such amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of (i) the cash that the Trust receives on or before the tenth day of the third month after the end of each calendar quarter ending before the Trust is dissolved and that is attributable to production from the Net Profits Interest held by the Trust during that calendar quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over (ii) the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Quarterly Distribution Amounts per unit for each of the quarters in 2012 were $0.1457, $0.1352, $0.1330 and $0.0000, 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 has sold the Royalty NPI assets and will begin to liquidate in May 2013. Pursuant to the Trust Agreement, all receipts of the Trust received after December 31, 2012, will be retained by the Trustee until a final distribution to be made on or about August 15, 2013. 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."

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Sale and Abandonment of Underlying Properties

ECA and any transferees have the right to abandon any well or working interest included in the Underlying Properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between ECA and the Trust in determining whether a well is capable of producing in paying quantities, ECA is required under the Conveyances to make any such determination as would a reasonably prudent operator in the Appalachian Basin if it were acting with respect to its own properties, disregarding (i) the existence of the Net Profits Interests as a burden on such property and (ii) the direct or indirect effect, financial or otherwise, on ECA or any of its affiliates that may result from the performance by Eastern Marketing, and now with ECA as successor by merger, 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, ECA 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 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, 2012, such properties consisted of 329 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 12.5%) 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.

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

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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.

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

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

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

Reserves

Proved Reserves of Underlying Properties and Net Profits Interests. The following table sets forth, as of December 31, 2012, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, and the Term NPI, in each case derived from a report of oil and gas reserves attributable to the Trust as of December 31, 2012 prepared by Ryder Scott Company (the "Reserve Report"). The Reserve Report and the table below do not include any interest or amount attributable to the Royalty NPI, which the Trust sold in January 2013, with an effective date of October 1, 2012, as described herein. 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

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discount rate of 10% in accordance with applicable requirements. A summary of the Reserve Report is included as Annex A hereto.

	Proved Gas Reserves

	Proved Gas Reserves								Discounted Estimated Future Net Revenues(2)
	Developed		(MMcf) Undeveloped		Total		Estimated Future Net Revenues(2)		Discounted Estimated Future Net Revenues(2)
							(Dollars in thousands)
Underlying Properties(1)		14,210		0		14,210	$	34,740	$	14,883

Net Profits Interests:
Term NPI		226		0		226		814		796

Total		226		0		226	$	814	$	796

(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.

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

Preparation of reserve report.

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

The Trust retained Ryder Scott Company L.P. ("Ryder Scott"), which is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years, to prepare a third-party report of the reserves attributable to the net profits interest. A signed copy of the report, dated January 11, 2013, (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 September 2012. 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. Stephen E. Gardner, the technical person primarily responsible for overseeing the preparation of the Reserve Report are as follows. Mr. Gardner, an employee of Ryder Scott since 2006, is a Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is licensed

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Professional Engineer in the States of Colorado and Texas. He is also a member of the Society of Petroleum Engineers. As part of his 2012 continuing education hours, Mr. Gardner attended a six hour conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. In May 2012, Mr. Gardner attended the DUO Conference in Denver, Colorado, which focused on developed and emerging unconventional oil plays and on current issues in energy. In addition, Mr. Gardner attended an SPEE luncheon regarding valuation metrics in the Bakken play and Permian Basin. Finally, Mr. Gardner completed several days of informal study that included such topics as SPEE Monograph 3, utilization of economics evaluation softwares, and principles of waterflooding.

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 January 11, 2013 and has an effective date of December 31, 2012. 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, 2012 are related to hydrocarbon prices, computed in accordance with the gas contract described below and applicable SEC rules. The hydrocarbon prices used in the preparation of the Reserve Report are based on the average prices during the 12-month period prior to the ending date of the period covered in the Reserve Report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. For purposes of the Reserve Report, the proved reserves attributable to the net profits interest have been proportionately reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves presented reflect quantities of gas that are free of future costs or expenses based on the price and cost assumptions utilized in the Reserve Report. The Reserve Report utilized the terms of the gas contract between Eastern Marketing, and now with ECA as successor by merger, 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 the Wall 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 the 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 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

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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 Chief Operating Officer. 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 Engineering Manager has a Bachelor of Science degree in Petroleum Engineering. He has over six years of oil and gas industry experience in reservoir engineering. ECA's Chief Operating Officer 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 nine 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.

COMPETITION AND MARKETS

All of the production attributable to the Net Profits Interest is sold to ECA, as successor 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.

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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 at 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 such laws and regulations will not have a material adverse effect upon the Trust. It cannot be predicted what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations at 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 at or from, or conditions existing at, 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 are expect to 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 laws or regulations 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 at or from, or conditions existing at or from, 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 at or from the Underlying Properties. Federal, state and local laws applicable to drilling-, completion- and production-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

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property contamination (including groundwater contamination) or to perform remedial plugging operations to reduce the likelihood of 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, hazardous substance at any site where such a release has occurred. 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 released.

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.

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. 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. These regulations 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. In addition, certain 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

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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. 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. States regulations may apply to 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 imposition of more stringent state regulations on ECA's operations could require ECA to incur increased operating costs.

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

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the Deposit Agreement, the Unitholder will receive an uncertificated direct interest in Trust Units. These withdrawn Trust Units will be evidenced on the books of the Trustee by a transfer of such Trust Units from the name of the Depositary to the name of the withdrawing Unitholder. Holders of withdrawn Trust Units will be entitled to receive Trust distributions and periodic Trust information (including tax information) directly from the Trustee. Moreover, holders of Trust Units will be entitled to each of the rights accorded Unitholders under the Trust Agreement, including voting and liquidation rights, as elsewhere described herein, except that withdrawn Trust Units are not freely transferable as described below.

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

Distributions and Income Computations

Subject to the procedures set forth in the Trust Agreement relating to the pending liquidation of the Trust, the Trustee determines for each quarter the Quarterly Distribution Amount available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. Prior to 2013, 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. Prior to 2013, 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. In accordance with the procedures set forth in the Trust Agreement relating to the pending liquidation of the Trust, no further distributions relating to the Net Profits Interests will be made until a final distribution is made in connection with the 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. 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.

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Possible Divestiture of Depositary Units and Trust Units

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

Liability of Unitholders

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

Liquidation of the Trust

The Trust will be liquidated and terminate during 2013.

On August 16, 2012 the Trust entered into a Brokerage Agreement, pursuant to which the Trust engaged EnergyNet.com, Inc. ("EnergyNet") to perform sales brokerage and consulting services in connection with the Trust's anticipated sale of the Royalty NPI. EnergyNet subsequently informed the Trustee that its marketing activities resulted in 190 companies reviewing materials relating to the Royalty NPI, with approximately ten of the companies conducting more extensive reviews. EnergyNet then solicited bids for the Royalty NPI. In marketing the Royalty NPI, the Trustee solicited bids on the basis of the distribution for the third quarter of 2012 being for the account of the Trust, and the distribution for the fourth quarter of 2012 being for the account of the purchaser of the Royalty NPI.

Pursuant to the Trust Agreement, ECA, which held a right of first refusal to purchase the Royalty NPI from the Trust, had the right to require the Trust to engage an appraiser to appraise the Royalty NPI if the Trust had not sold the Royalty NPI by September 30, 2012. ECA also had the right to purchase the Royalty NPI at the appraised value. At the request of the Trustee, on September 25, 2012, ECA granted a waiver in order to allow the Trust additional time in which to market the Royalty NPI. ECA further agreed to waive the 20-business day notice of a proposed sale to which it was entitled under the Trust Agreement in order to allow the Trust additional time in which to market the Royalty NPI, and agreed to accept a shorter notice period.

Bids for the Royalty NPI were due in October 2012. The Trust accepted the highest bid, and entered into the October 24, 2012 Agreement described above. On November 5, 2012, ECA exercised its right of first refusal under the Trust Agreement to purchase the Royalty NPI on the terms set forth in the October 24, 2012 Agreement. As a consequence of ECA's exercise of its right of first refusal, the

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October 24, 2012 Agreement terminated in accordance with its terms, and the Trust became obligated to sell the Royalty NPI to ECA for the purchase price determined by the October 24, 2012 Agreement. On January 3, 2013, the Trust entered into a Purchase and Sale Agreement with ECA to document the terms of the sale of the Royalty NPI to ECA and to eliminate provisions of the October 24, 2012 Agreement that were inapplicable to the sale of the Royalty NPI to ECA. The sale of the Royalty NPI to ECA was completed on January 10, 2013. The price, after making the adjustment for gas price changes required by the October 24, 2012 Agreement, was $5,917,275, and was paid in cash. Expenses paid or to be paid in connection with the sale include the brokerage fee of approximately $158,000.

Unitholders as of the close of business on May 31, 2013 will, on or about June 17, 2013, as a result of the liquidation and winding down of the Trust beginning on May 15, 2013, receive the proceeds attributable to the mature Treasury Obligation ($20.00 per trust unit), unless the Treasury Obligation relating thereto has previously been withdrawn. On or about August 15, 2013, such Unitholders will also receive their pro rata share of the net proceeds received from the Trust's sale in January 2013 of the Royalty NPI (estimated to be approximately $0.95 per trust unit, based on net proceeds of $5.65 million) plus their pro rata share of revenues attributable to the term net profits interest for the period beginning October 1, 2012 through May 15, 2013, less any costs and expenses or reserves of the Trust during such period. Trading in the trust units will be stopped at the end of regular trading on the NYSE at the close of business on May 31, 2013, and no transfers will be permitted after that date.

FEDERAL INCOME TAX MATTERS

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

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:

The Bank of New York Mellon Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Ave., Suite 500
Austin, Texas 78701
Telephone: 1-800-852-1422

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 2012 federal and state income tax returns. This tax information booklet can be obtained at http://ngt.investorhq.businesswire.com.

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

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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 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

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widely in response to a number of factors that are beyond the control of ECA and the Trust. These factors include:

worldwide economic conditions;

weather conditions;

changes and expectations regarding natural gas production and transportation;

levels of actual and anticipated demand;

price and availability of alternative fuels;

the availability of gathering, transportation and processing facilities; and

the effects of worldwide energy conservation measures.

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 this Annual Report are estimates only, and actual quantities and values of natural gas are likely to differ from the estimated amounts. The discounted present values shown for the Net Profits Interests were prepared using guidelines established by the SEC for disclosure of reserves and should not be considered representative of market value.

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

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

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

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

Gas reserves are depleting assets.

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

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Compliance with governmental regulations may be expensive.

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

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

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

Administrative costs reduce distributions to Unitholders.

Administrative costs, including the Trustee's fee and other professional services fees and expenses, are deducted prior to distributions to Unitholders. Such costs could fluctuate in 2013 depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services, and may be materially higher during 2013 than they have been in the past as the Trust incurs expenses in connection with its liquidation in accordance with the Trust Agreement. 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

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Trust and, subject to certain limitations, would be entitled to claim depletion deductions and tax credits attributable to the Royalty NPI and would be entitled to claim his pro rata share of other deductions attributable to assets of the Trust. However, the opinion of counsel is not binding on the IRS or any court.

Taxable income could exceed cash distributions.

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

ECA and the Trust may have conflicts of interest.

The interests of ECA and the interests of the Trust and the Unitholders may at times be different. For example, ECA's interests may conflict with those of the Trust and Unitholders in situations involving the development, operation or abandonment of the Underlying Properties or adjacent properties. In making decisions with respect to such operations, or otherwise with respect to the development, operation or abandonment of the Underlying Properties, ECA is required to act as a reasonably prudent operator in the Appalachian Basin would act with respect to its own properties, without regard to the existence of the Net Profits Interests and without regard to any possible adverse effect on Eastern Marketing, and now with ECA as successor by merger, 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

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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 ECA, as successor to Eastern Marketing, to perform its obligations under the Gas Purchase Contract depends on its financial condition, which in turn depends upon the supply and demand for natural gas, economic conditions and upon financial, business and other factors, many of which are beyond the control of ECA.

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 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, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals increased 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, 2012 were as follows:

Quarter	High		Low		Distributions Paid

2011:
First (to March 31, 2011)	$	24.11	$	22.76	$	0.1784
Second (to June 30, 2011)	$	24.00	$	22.85	$	0.2689
Third (to September 30, 2011)	$	23.50	$	22.74	$	0.2427
Fourth (to December 31, 2011)	$	23.98	$	23.00	$	0.1597
2012:
First (to March 31, 2012)	$	23.32	$	22.14	$	0.1457
Second (to June 30, 2012)	$	22.40	$	21.06	$	0.1352
Third (to September 30, 2012)	$	21.70	$	21.14	$	0.1330
Fourth (to December 31, 2012)	$	21.20	$	20.14	$	0.0000

At February 28, 2013, the 5,900,000 Depositary Units outstanding were held by approximately 270 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, 2012 to December 31, 2012 were $1,000.20 and $996.30, respectively. The closing price on December 31, 2012 was $999.60 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 Ended

	December 31, 2012		December 31, 2011		December 31, 2010		December 31, 2009		December 31, 2008
Royalty Income	$	4,972,722	$	7,322,590	$	8,172,392	$	8,868,114	$	17,028,373
Distributable Income	$	2,658,927	$	5,263,272	$	5,730,157	$	6,526,597	$	14,049,648
Distribution Amount	$	2,442,227	$	5,013,272	$	5,730,157	$	6,526,597	$	14,049,648
Distributable Income per unit	$	0.4507	$	0.8921	$	0.9712	$	1.1062	$	2.3813
Distribution Amount per unit	$	0.4139	$	0.8497	$	0.9712	$	1.1062	$	2.3813
Total assets at year end	$	7,560,640	$	13,578,463	$	15,991,130	$	18,635,014	$	22,570,038

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

General

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

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Under the Gas Purchase Contract, ECA purchases gas for the benefit of the Trust at a variable price for any quarter equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal, for such contracts which expired in each of the five months prior to such month, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in The 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 in The 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 has 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 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, other 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 2012 was $1,017,119, including the Trustee's fee of $108,000. In addition to such expenses, in 2012, the Trust paid ECA an overhead reimbursement of $403,724. The overhead reimbursement increases by 3.5% per year and is payable quarterly. The costs the Trust incurs in 2013 will fluctuate depending primarily on the expenses

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the Trust incurs for professional services, particularly legal, accounting and engineering services and may be materially higher during 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 Royalty NPI is not limited in term or amount. Under the Trust Agreement, the Trustee was directed to sell all remaining Royalty NPI prior to May 15, 2013. The Trustee has done so, and net proceeds from selling such Royalty NPI will be distributed to Unitholders on or about August 15, 2013. 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, 2012, 28,239 MMcf of such gas had been produced.

Critical Accounting Policies

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

Basis of Accounting:

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

Net Profits Interests in Gas Properties:

The Net Profits Interests in gas properties are assessed to determine whether their net capitalized cost is impaired, whenever events or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to The Financial Accounting Standards Board ("FASB") Accounting Standards Codification 360, Property, Plant and Equipment ("ASC 360"). The Trust will determine if a writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that

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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.

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, 2012 except for the approximately $158,000 fee payable to EnergyNet.com, Inc. as the brokerage fee and the Trust's Royalty NPI sale to ECA as described herein, which closed in January 2013. At December 31, 2012, the Trust had General and Administrative Expenses Payable of $338,602 and no Distributions Payable.

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Results of Operations

2012 Compared with 2011

The Trust's Distributable Income was $2,658,927 for the year ended December 31, 2012 as compared to $5,263,272 for the year ended December 31, 2011. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2012 ($4,972,722) as compared to the year ended December 31, 2011 ($7,322,590). This decrease was due to a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2012 (1,398 Mmcf) as compared to the year ended December 31, 2011 (1,487 Mmcf).The decline in production is primarily attributable to the sale of the Royalty NPI and natural production declines. Offsetting this decrease was an increase in production from several wells in West Virginia which are located in an area experiencing increased drilling and completion activities. This decrease was also partially due to a decrease in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($3.609 per Mcf for the year ended December 31, 2012 as compared to $4.925 per Mcf for the year ended December 31, 2011). Taxes on Production and Property were $366,698 for the year ended December 31, 2012 as compared to $518,355 for the year ended December 31, 2011. The decrease in taxes is due directly to the decrease in Royalty Income as discussed above. Trust General and Administrative Expenses were $1,420,843 for the year ended December 31, 2012 as compared to $1,129,205 for the year ended December 31, 2011. 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 $5,424,875 for the year ended December 31, 2012 as compared to $2,325,766 for the year ended December 31, 2011. This increase was due to the impairment in the Underlying Properties recognized during quarter ended September 30, 2012 ($2.6 million) and quarter ended December 31, 2012 ($0.8 million). This increase was partially offset due to the decrease in the depletion rate to $1.4790 for the year ended December 31, 2012 from $1.5638 for the year ended December 31, 2011.

The average price payable to the Trust for gas production attributable to the Net Profits Interests was $3.609 per Mcf for the year ended December 31, 2012 and $4.925 per Mcf for the year ended December 31, 2011. The price per Mcf was lower for the year ended December 31, 2012 than for the year ended December 31, 2011 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.981 per Dth for the year ended December 31, 2012 as compared to $4.177 per Dth for the year ended December 31, 2011).

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.

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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).

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, and now with ECA as successor by merger, pursuant to the Gas Purchase Contract described herein.

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Item 8. Financial Statements and Supplementary Data.


Financial Statements
Report of Independent Registered Public Accounting Firm			F-2
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2012 and 2011			F-4
Statements of Distributable Income for the years ended December 31, 2012, 2011 and 2010			F-5
Statements of Changes in Trust Corpus for the years ended December 31, 2012, 2011 and 2010			F-6
Notes to Financial Statements			F-7
Supplemental Reserve Information (Unaudited)			F-14

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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, 2012, 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:

•: ECA and its consolidated subsidiaries manage information relating to the Trust, including (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, the effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures and (iii) geological data relating to reserves; and
•: The Trustee necessarily relies upon the independent reserve engineer, as an expert with respect to the annual reserve report, which includes projected production, operating expenses and capital expenses.

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 in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee's evaluation under the framework in Internal Control—Integrated Framework, the Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2012. The effectiveness of the Trust's internal control over financial reporting as of December 31, 2012 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, 2012, December 31, 2011 and December 31, 2010, The Bank of New York Mellon Trust Company, N.A., as Trustee, received $108,000 annually, as Trustee fees and $909,119, $631,133 and $671,064, respectively, as reimbursement of legal, accounting, and other professional expenses for such services. Effective January 1, 2005, the annual Trustee fee was fixed at $108,000.

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

(a) Security Ownership of Certain Beneficial Owners.

Based on filings with the Securities and Exchange Commission, the Trust is not aware of any person owning beneficially more than 5% of the Units as of March 1, 2013, except as follows:

Name		Number of Shares			Percent of Class

SoftVest, LP.(1) 400 Pine Street Suite 1010 Abilene, TX 79601			350,972			5.95	%

(1): Reference is hereby made to the Schedule 13G/A filed by SoftVest, LP on July 11, 2012 for information regarding the ownership of the reporting person.

(b) Security Ownership of Management.

Not applicable.

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

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

The Trust has no 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 required 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 the Trustee did so. As described above, on November 5, 2012, ECA exercised its right of first refusal under the Trust Agreement to purchase the Royalty NPI on the terms set forth in the October 24, 2012 Agreement. As a consequence of ECA's exercise of its right of first refusal, the October 24, 2012 Agreement terminated in accordance with its terms, and the Trust became obligated to sell the Royalty NPI to ECA for the purchase price determined by the October 24, 2012 Agreement. On January 3, 2013, the Trust entered into a Purchase and Sale Agreement with ECA to document the terms of the sale of the Royalty NPI to ECA and to eliminate provisions of the October 24, 2012 Agreement that were inapplicable to the sale of the Royalty NPI to ECA. The sale of the Royalty NPI to ECA was completed on January 10, 2013. The price, after making the adjustment for gas price changes required by the October 24, 2012 Agreement, was $5,917,275, and was paid in cash. See "Description of Trust Units and Depository Units—Liquidation of the Trust."

Reference is hereby made to Note 8 to the Financial Statements included under Item 8 of this report for descriptions of additional matters.

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 $155,500 in 2012 and $154,194 in 2011.

Audit-Related Fees

PricewaterhouseCoopers LLP billed the Trust additional fees of $28,113 for assurance and related services that are reasonably related to the performance of the audit or review of the Trust's financial statements. PricewaterhouseCoopers LLP did not bill the Trust any amount for audit related fees in 2011.

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 $125,000 in 2012 and $117,825 in 2011.

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.


Reports
Reserve Report of Ryder Scott Company, Independent Petroleum Engineers			A-1
Financial Statements
The following financial statements are included in this Annual Report on Form 10-K on the pages indicated:
Report of Independent Registered Public Accounting Firm			F-2
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2012 and 2011			F-4
Statements of Distributable Income for the years ended December 31, 2012, 2011 and 2010			F-5
Statements of Changes in Trust Corpus for the years ended December 31, 2012, 2011 and 2010			F-6
Notes to Financial Statements			F-7
Supplemental Reserve Information (Unaudited)			F-14

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 10.6, which is incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on August 16, 2012, Exhibit 10.7, which is incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on October 30, 2012, and Exhibit 10.8, which is incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2013.

Exhibit Number

	3.1		Second Amended and Restated Trust Agreement of Eastern American Natural Gas Trust
	4.1		Specimen Depositary Receipt
	4.2		Form of NPI Royalty Deposit Agreement
	10.1		Form of Conveyance
	10.2		Form of Term NPI Conveyance
	10.3		Form of Gas Purchase Contract between Eastern American Energy Corporation, Eastern American Marketing Corporation and Eastern American Natural Gas Trust
	10.4		Form of Conveyance of Production Payment/Assignment of Production from Eastern American Natural Gas Trust to Eastern American Marketing Corporation
	10.5		Form of Assignment and Standby Performance Agreement

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Exhibit Number

	10.6		Sale Brokerage/Consulting Agreement with EnergyNet.com, Inc. dated August 16, 2012.
	10.7		Purchase and Sale Agreement with Softvest, LP, dated October 24, 2012.
	10.8		Purchase and Sale Agreement with Energy Corporation of America dated January 3, 2013.
	31		Rule 13a-14(a)/15d-14(a) Certification
	32		Section 1350 Certification
	99.1		Report of Ryder Scott Company L.P. dated January 11, 2013

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 15th day of March, 2013.

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

January 11, 2013

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

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Eastern American Natural Gas Trust (the Trust) as of December 31, 2012. The subject properties are located in the states of Pennsylvania and West Virginia. The Trust is a grantor trust formed to hold interests in certain domestic oil and gas properties originally 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 a Net Profits Interest conveyed to the Trust. The Net Profits interest is derived from working and revenue interests in two groups of properties: the first group consists of a life-of-properties interest ("Royalty NPI"), and the second group consists of a term interest ("Term NPI"). In fourth-quarter 2012, the Trust entered into an agreement to sell the Royalty NPI to ECA, effective as of October 1, 2012. Consequently, this report only includes the remaining Term NPI properties still owned by the Trust.

The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 11, 2013 and presented herein, was prepared for public disclosure by the Trust in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The properties evaluated by Ryder Scott represent 100 percent of the total net proved gas reserves of the Trust as of December 31, 2012.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2012 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report were defined by contractual arrangements as permitted by the SEC regulations. Actual future prices may vary significantly from the current contractual prices used in this report; 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.

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SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
EASTERN AMERICAN NATURAL GAS TRUST
TERM NPI PROPERTIES
As of December 31, 2012

	Total Proved Developed Producing

*Net Remaining Reserves*
Gas—MMCF		226
*Income Data*
Future Gross Revenue	$	814,143
Deductions		0

Future Net Income (FNI)	$	814,143
Discounted FNI @ 10%	$	796,409

Reserve quantities included in this report 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 there from beginning on January 1, 2013. There is no precise method for allocating estimated quantities of proved reserves attributable to the Net Profits Interest between the interest held by the Trust and the interests to be retained by ECA. For purposes of this presentation, the proved reserves attributable to the Net Profits Interests have been proportionately reduced to reflect the future estimated costs that are 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, based on the price and cost assumptions utilized in this report. 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, which is the date that the Term NPI automatically reverts to ECA and the Trust begins to liquidate. All gas volumes are reported on an "as sold basis" expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

For Net Profits Interest, the future cash inflows are, as described previously, after consideration of future costs, based on the price and cost assumptions utilized in this report. Therefore, the future gross 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 flows.

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The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income As of December 31, 2012

Discount Rate Percent	Total Proved
8	$	799,906
9	$	798,154
15	$	787,769
20	$	779,278

At the request of ECA, we have included the following table which summarizes the total net proved reserves and income estimates from the combined interests of ECA and the Trust in the underlying properties.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Combined Leasehold Interests of
ECA and the TRUST
TERM NPI PROPERTIES
As of December 31, 2012

	Total Proved Developed Producing

*Net Remaining Reserves*
Gas—MMCF		14,210
*Income Data*
Future Gross Revenue	$	48,483,114
Deductions		13,742,680

Future Net Income (FNI)	$	34,740,434
Discounted FNI @ 10%	$	14,883,327

This evaluation of the combined interests utilizes the same price and cost assumptions that were utilized for evaluating the Trust and discussed earlier in the letter. Furthermore, the properties which are included in the "Term NPI" were allowed to run for their full economic life.

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 Status Definitions and Guidelines" in this report

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. At the request of ECA, the gas volumes included herein assume that any shrinkage attributable to gas consumed in operations is negligible.

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

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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 the 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. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, 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), 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 or geopolitical or 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 there from, and the actual costs related thereto, could be more or less than the estimated amounts.

As stated previously, the proved reserves reported herein attributable to the Trust are limited to the period prior its liquidation on May 15, 2013 and the automatic reversion of the Term NPI to ECA.

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, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, 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 significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which the Trust owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if 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 completed its 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

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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 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.

All of the proved producing reserves for the properties included herein were estimated by the decline curve analysis performance method, which utilized extrapolations of historical production data ending over a range from August through September 2012, depending on the availability of data for a given case. 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.

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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.

Future Production Rates

All wells are currently on production, and our forecasts of future production rates are based on historical performance data. The future production rates for these wells 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 (formerly a wholly owned subsidiary which merged with and into ECA effective as of March 26, 2012) 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 the Wall 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 the 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 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, 2012 as $3.609 per Mcf, utilizing $2.982 per MMbtu as the Henry Hub Average Spot Price computed in

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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 operating costs used in the preparation of this report were estimated by us based on information furnished by ECA. 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.

ECA's estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for ECA's estimate.

The current operating costs were held constant throughout the life of the properties.

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 ECA and the Trust. 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 the Trust.

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The Trust makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, the Trust has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 of the Trust of the references to our name as well as to the references to our third party report for the Trust, which appears in the December 31, 2012 annual report on Form 10-K of the Trust. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by the Trust.

We have provided the 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 the Trust and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work products 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-1580
		/s/ STEPHEN E. GARDNER Stephen E. Gardner, P. E. Colorado License No. 44720 Vice President

SEG

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EASTERN AMERICAN NATURAL GAS TRUST

FINANCIAL STATEMENTS

as of December 31, 2012 and 2011
and for the years ended
December 31, 2012, 2011 and 2010

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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, 2012 and 2011, 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, 2012. 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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust at December 31, 2012 and 2011, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control—Integrated Framework issued by COSO.

As described in Note 1, the Trust is required to liquidate by May 15, 2013.

/s/ PRICEWATERHOUSECOOPERS LLP
Pittsburgh, Pennsylvania
March 14, 2013

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EASTERN AMERICAN NATURAL GAS TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

as of December 31, 2012 and 2011

	2012			2011

Assets:
Cash	$	319,519		$	122,740
Net Proceeds Receivable		685,783			1,475,510
Net Profits Interests in Gas Properties		93,162,180			93,162,180
Accumulated Amortization		(86,606,842	)		(81,181,967	)

		6,555,338			11,980,213

Total Assets	$	7,560,640		$	13,578,463

Liabilities and Trust Corpus:
Trust General and Administrative Expenses Payable	$	338,602		$	206,150
Distributions Payable		—			942,100
Trust Corpus (5,900,000 units authorized and outstanding)		7,222,038			12,430,213

Total Liabilities and Trust Corpus	$	7,560,640		$	13,578,463

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, 2012, 2011 and 2010

	2012			2011			2010

Royalty Income	$	4,972,722		$	7,322,590		$	8,172,392
Operating Expenses:
Taxes on Production and Property		366,698			518,355			627,719
Operating Cost Charges		526,315			593,717			658,604

Total Operating Expenses		893,013			1,112,072			1,286,323

Net Proceeds to the Trust		4,079,709			6,210,518			6,886,069
General and Administrative Expenses		1,420,843			1,129,205			1,155,944
Interest Income		61			31			32
Cash Proceeds on Sale of Net Profit Interests		—			181,928			—

Distributable Income		2,658,927			5,263,272			5,730,157
Cash Reserve Refunded (Withheld)		(216,700	)		(250,000	)		—

Distribution Amount	$	2,442,227		$	5,013,272		$	5,730,157

Distributable Income Per Unit (5,900,000 units authorized and outstanding)	$	0.4507		$	0.8921		$	0.9712

Distribution Amount Per Unit (5,900,000 units authorized and outstanding)	$	0.4139		$	0.8497		$	0.9712

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, 2012, 2011 and 2010

	2012			2011			2010

Trust Corpus, Beginning of Period	$	12,430,213		$	14,505,979		$	16,894,759
Distributable Income		2,658,927			5,263,272			5,730,157
Distributions Paid or Cash to Unitholders		(2,442,227	)		(5,013,272	)		(5,730,157	)
Amortization and Impairment of Net Profits Interests in Gas Properties		(5,424,875	)		(2,325,766	)		(2,388,780	)

Trust Corpus, End of Period	$	7,222,038		$	12,430,213		$	14,505,979

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 prior to May 15, 2013, and net proceeds from selling such Royalty NPI will be distributed to Unitholders on or about August 15, 2013. 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, 2012, 28,239 MMcf of such gas had been produced.

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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.

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

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Significant Accounting Policies: (Continued)

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. See Note 4 for discussion of the impairment in the Underlying Properties recognized during the three month period ended September 30, 2012 and the three month period ended December 31, 2012.

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

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

Revenues and Expenses:

The Trust serves as a pass-through entity, with items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the Unitholders. Thus, the

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Significant Accounting Policies: (Continued)

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, and now with ECA as successor by merger, 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:

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. Impairment of Net Profits Interests in Oil and Gas Properties

As of August 16, 2012, the Trustee initiated the process to sell its Royalty NPI and engaged EnergyNet (a third party) to assist with the sale. As a result of this decision, at September 30, 2012, the Royalty NPI is considered to be a long-lived asset to be disposed of. Based upon the agreement described in Note 6, the fair value less cost to sell of the Royalty NPI was calculated to be $5.8 million. Since this amount together with the undiscounted estimated future cash flows of the Term NPI were less than the carrying value of the total NPI as of September 30, 2012, the Trustee assessed the recoverability of the remaining Term NPI and determined the fair value of the Term NPI to be $1.8 million. The difference between the calculated fair values of $7.6 million and the carrying amount of $10.2 million ($2.6 million) was recorded as a reduction to Net Profits Interests and the Trust Corpus.

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

4. Impairment of Net Profits Interests in Oil and Gas Properties (Continued)

As of December 31, 2012, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Eastern American Natural Gas Trust (the Trust). Based upon the agreement described in Note 6, the fair value less cost to sell of the Royalty NPI was calculated to be $5.8 million. Since this amount together with the undiscounted estimated future cash flows of the Term NPI were less than the carrying value of the total NPI as of December 31, 2012, the Trustee assessed the recoverability of the remaining Term NPI and determined the fair value of the Term NPI to be $0.8 million. The difference between the calculated fair values of $0.8 million and the carrying amount of $1.6 million ($0.8 million) was recorded as a reduction to Net Profits Interests and the Trust Corpus.

5. Income Taxes:

Tax counsel to ECA advised ECA at the time of formation that, under then current tax laws, the Trust would be classified as a grantor trust for federal and state income tax purposes and, therefore, would not be subject to taxation at the Trust level.

Accordingly, no provision for federal or state income taxes has been made. However, the opinion of tax counsel is not binding on taxing authorities.

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

6. Subsequent Events

The Trust entered into a Purchase and Sale Agreement dated October 24, 2012 (the "Softvest Purchase Agreement") with Softvest, LP, a Delaware limited partnership ("Softvest"), pursuant to which the Trust agreed to sell the Royalty NPI to Softvest. On November 5, 2012, ECA exercised its right of first refusal to purchase the Royalty NPI on the terms set forth in the Softvest Purchase Agreement. The sale price, after making the price adjustment required by the Softvest Purchase Agreement relating to decreases to the closing price of the NYMEX natural gas December 2012 contract, was $5,917,275. The sale of the Royalty NPI to ECA closed on January 10, 2013.

The expenses incurred in connection with the sale of the Royalty NPI include payment pursuant to the Sale Brokerage/Consulting Agreement dated August 16, 2012 (the "Brokerage Agreement") between the Trust and EnergyNet.com, Inc. ("EnergyNet"). The Brokerage Agreement provided that at the closing of a sale of the Royalty NPI or any portion thereof, during the term of the engagement or within 180 days following the end of the engagement, the Trust would pay EnergyNet a fee equal to 4.0% of the sales price if the sales price was $2 million or less, and an additional 2.0% of any amount of the sales price in excess of $2 million. The fee paid to EnergyNet pursuant to the Brokerage Agreement was $158,345.

In the Softvest Purchase Agreement, the Trust agreed to reimburse Softvest for up to $25,000 of Softvest's out-of-pocket expenses incurred on or after the date of the Softvest Purchase Agreement in connection with its review of title to the Royalty NPI if ECA exercised its right of first refusal after October 26, 2012. Because ECA exercised its right of first refusal after October 26, 2012, the Trust was required to reimburse Softvest for up to $25,000 of such expenses. ECA voluntarily reimbursed the

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

6. Subsequent Events (Continued)

Trust, for the benefit of the Trust unitholders, for the amount the Trust was required to pay to Softvest as reimbursement of Softvest's expenses.

In marketing the Royalty NPI, the Trustee solicited bids on the basis of the distribution for the third quarter of 2012 being for the account of the Trust, and the distribution for the fourth quarter of 2012 being for the account of the purchaser of the Royalty NPI. The Softvest Purchase Agreement, and the amount offered by Softvest, reflected that allocation of the distributions. Upon ECA's exercise of its right of first refusal, ECA became entitled to acquire the Royalty NPI on the terms of the Softvest Purchase Agreement, and consequently, ECA became entitled, to any distribution for the fourth quarter of 2012. Therefore, unitholders did not and will not receive any direct distribution relating to the fourth quarter of 2012 for revenues attributable to the Royalty NPI.

7. 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, 2012 are expected to be received by the Trust and distributed to the Unitholders on or about August 15, 2013. The December 31, 2011 Net Proceeds Receivable were received and distributed by the Trust on March 15, 2012.

8. 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 $1,017,119 for the year ended December 31, 2012, $739,133 for the year ended December 31, 2011 and $779,064 for the year ended December 31, 2010. 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 $403,724, $390,072 and $376,880 for overhead expenses for 2012, 2011 and 2010, respectively. Operating Cost Charges included in the Statements of Distributable Income are paid to ECA.

F-12

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Related Party Transactions: (Continued)

Gas production attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing, and now with ECA as successor by merger, 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, and now with ECA as successor by merger, 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, ECA is obligated to purchase such gas production at a purchase price per Mcf equal to the Index Price for gas produced in any quarter after the Primary Term.

The Index Price for any quarter subsequent to the Primary Term, which expired December 31, 1999, is determined solely by reference to the Variable Price component. The Variable Price for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported 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 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 determined as of the contract settlement date for such month, as reported in The 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 Trust Agreement required 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 the Trustee did so and entered into an agreement to sell the Royalty NPI dated October 24, 2012 (the "October 24, 2012 Agreement"). On November 5, 2012, ECA exercised its right of first refusal under the Trust Agreement to purchase the Royalty NPI on the terms set forth in the October 24, 2012 Agreement. As a consequence of ECA's exercise of its right of first refusal, the October 24, 2012 Agreement terminated in accordance with its terms, and the Trust became obligated to sell the Royalty NPI to ECA for the purchase price determined by the October 24, 2012 Agreement. On January 3, 2013, the Trust entered into a Purchase and Sale Agreement with ECA to document the terms of the sale of the Royalty NPI to ECA and to eliminate provisions of the October 24, 2012 Agreement that were inapplicable to the sale of the Royalty NPI to ECA. The sale of the Royalty NPI to ECA was completed on January 10, 2013. The price, after making the adjustment for gas price changes required by the October 24, 2012 Agreement, was $5,917,275, and was paid in cash.

ECA conducted an offer to exchange common units of ECA Marcellus Trust I, a Delaware statutory trust ("ECT"), for outstanding depositary units ("NGT Depositary Units") of Eastern American Natural Gas Trust, a Delaware statutory trust ("NGT"), until ECA has exchanged all 3,957,527 of the ECT common units that it owns ("ECT Common Units"). The exchange ratio was determined based on the volume weighted average trading prices of ECT Common Units for the

F-13

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Related Party Transactions: (Continued)

10-day period ending three days prior to the Settlement Date. The exchange offer terminated on March 13, 2013, with ECA accepting all NGT Depositary Units validly tendered and not withdrawn in the offer.

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-14

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Related Party Transactions: (Continued)

The following table reconciles the change in proved reserves attributable to the Trust's share of the Net Profits Interests ("NPI") from January 1, 2010 to December 31, 2012:

	Royalty NPI			Term NPI			Total NPI

	(MMcf)			(MMcf)			(MMcf)
Balance, January 1, 2010		8,383			2,317			10,700
Production		(654	)		(877	)		(1,531	)
Revisions of previous estimates		(152	)		131			(21	)

Balance, December 31, 2010		7,577			1,571			9,148
Production		(646	)		(841	)		(1,487	)
Revisions of previous estimates		272			167			439

Balance, December 31, 2011		7,203			897			8,100

Production		(574	)		(824	)		(1,398	)
Sales of reserves in place(1)		(6,629	)		—			(6,629	)
Revisions of previous estimates		—			153			153

Balance, December 31, 2012		—			226			226

(1): Sales of reserves in place are attributable to the sale of the Royalty NPI to ECA completed on January 10, 2013 with an effective date of October 1, 2012.

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

	Royalty NPI		Term NPI		Total NPI

	(MMcf)		(MMcf)		(MMcf)
December 31, 2010		7,577		1,571		9,148

December 31, 2011		7,203		897		8,100

December 31, 2012		—		226		226

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, 2012 (in thousands):

	Royalty NPI		Term NPI			Total NPI

Future cash inflows	$	—	$	1,029		$	1,029
Future production taxes		—		(55	)		(55	)
Future production costs		—		(160	)		(160	)

Future net cash inflows		—		814			814
10% discount factor		—		(18	)		(18	)

Standardized measure of discounted future net cash flows	$	—	$	796		$	796

F-15

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Related Party Transactions: (Continued)

The following is the standardized measure of discounted future net cash flows as of December 31, 2011 (in thousands):

	Royalty NPI			Term NPI			Total NPI

Future cash inflows	$	48,726		$	5,339		$	54,065
Future production taxes		(2,979	)		(267	)		(3,246	)
Future production costs		(10,275	)		(655	)		(10,930	)

Future net cash inflows		35,472			4,417			39,889
10% discount factor		(20,309	)		(300	)		(20,609	)

Standardized measure of discounted future net cash flows	$	15,163		$	4,117		$	19,280

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

	Royalty NPI			Term NPI			Total NPI

Future cash inflows	$	55,156		$	9,919		$	65,075
Future production taxes		(2,706	)		(418	)		(3,124	)
Future production costs		(11,965	)		(1,107	)		(13,072	)

Future net cash inflows		40,484			8,395			48,879
10% discount factor		(23,327	)		(893	)		(24,220	)

Standardized measure of discounted future net cash flows	$	17,157		$	7,502		$	24,659

F-16

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Related Party Transactions: (Continued)

Changes in Standardized Measure of Discounted Future Net Cash Flows:

The following schedule reconciles the changes during 2010, 2011 and 2012 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):

	Royalty NPI			Term NPI			Total NPI

Standardized measure, January 1, 2010	$	19,490		$	10,968		$	30,458
Net proceeds to the Trust		(5,703	)		(1,183	)		(6,886	)
Revisions of previous estimates		(410	)		353			(57	)
Accretion of discount		1,949			1,097			3,046
Net 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		$	24,659
Net proceeds to the Trust		(5,523	)		(688	)		(6,211	)
Revisions of previous estimates		647			398			1,045
Accretion of discount		1,716			750			2,466
Net 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
Net proceeds to the Trust		(3,945	)		(135	)		(4,080	)
Sales of reserves in place(1)		(10,219	)		—			(10,219	)
Revisions of previous estimates		—			311			311
Accretion of discount		1,516			412			1,928
Net change in price and production costs		(2,278	)		(25	)		(2,303	)
Other		(237	)		(3,884	)		(4,121	)

Standardized measure, December 31, 2012	$	—		$	796		$	796

(1): Sales of reserves in place are attributable to the sale of the Royalty NPI to ECA completed on January 10, 2013 with an effective date of October 1, 2012.

F-17

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

8. Related Party Transactions: (Continued)

Quarterly Financial Data (Unaudited):

The following is a summary of royalty income and distributable income per unit by quarter in 2012, 2011 and 2010 (all amounts in thousands except Distributable income per unit):

2012	Mar 31		June 30		Sept 30		Dec 31		Total

Royalty Income	$	1,499	$	1,269	$	1,388	$	817	$	4,973
Distributable Income	$	860	$	797	$	785	$	217	$	2,659
Distributable Income Per Unit	$	0.1457	$	0.1352	$	0.1330	$	0.0368	$	0.4507

2011	Mar 31		June 30		Sept 30		Dec 31		Total

Royalty Income	$	1,746	$	1,912	$	1,921	$	1,744	$	7,323
Distributable Income	$	1,052	$	1,587	$	1,432	$	1,192	$	5,263
Distributable Income Per Unit	$	0.1784	$	0.2689	$	0.2427	$	0.2021	$	0.8921

2010	Mar 31		June 30		Sept 30		Dec 31		Total

Royalty Income	$	2,153	$	2,067	$	2,060	$	1,892	$	8,172
Distributable Income	$	1,308	$	1,530	$	1,548	$	1,344	$	5,730
Distributable Income Per Unit	$	0.2217	$	0.2592	$	0.2625	$	0.2278	$	0.9712

F-18

EASTERN AMERICAN NATURAL GAS TRUST

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

/s/ MIKE ULRICH

Mike Ulrich

Vice President

EASTERN AMERICAN NATURAL GAS TRUST 10-K