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

FORM 10-Q

(Mark One)
ý		QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012
For the quarterly period ended March 31, 2013
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, Texas
(Address of principal executive offices)

78701
(Zip Code)

(800) 852-1422
(Registrant's telephone number, including area code)

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 (§232.405 of this chapter) 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 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 ~~November~~May 1, ~~2012~~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, 2,~~277~~798,~~950~~650 Units of Beneficial Interest (the "Withdrawn Units") have been withdrawn from trading by voluntary action of Holders and may not be traded unless such Holders comply with certain requirements provided in the related Trust Agreement.

PART I—FINANCIAL INFORMATION

ITEM 1. Financial Statements

EASTERN AMERICAN NATURAL GAS TRUST

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

	Nine Months Ended September 30,					Three Months Ended September 30,
	Three Months Ended March 31,
	2012			2011		2012		2011
	2013			2012
Royalty Income	$	4819,~~155,702~~016		$	51,~~578~~498,~~985~~700	$	~~1,388,195~~	$	~~1,920,510~~
Operating Expenses
Taxes on Production and Property		~~312~~54,~~109~~915			~~393~~111,~~282~~095		~~104,132~~		~~135,234~~
Operating Cost Charges		~~449~~80,~~667~~481			~~450~~149,~~695~~889		~~149,889~~		~~143,022~~
Total Operating Expenses		~~761~~135,~~776~~396			~~843~~260,~~977~~984		~~254,021~~		~~278,256~~
Net Proceeds to the Trust		3683,~~393,926~~620			41,~~735~~237,~~008~~716		~~1,134,174~~		~~1,642,254~~
General and Administrative Expenses		~~951~~425,~~744~~035			~~845~~377,~~783~~839		~~349,310~~		~~210,473~~
Interest Income		44—			209		21		20
Cash Proceeds on Sale of Net Profit Interests		—5,917,275			~~181,928~~—		—		—
Distributable Income		26,~~442~~175,~~226~~860			4859,~~071,173~~886		~~784,885~~		~~1,431,801~~
Distribution Amount		2,442,226			4,071,173		784,885		1,431,801
Cash Reserve Refunded (Withheld)		(6,175,860	)		—
Distributable Income Per Unit (5,900,000 units authorized and outstanding)	$	0.4139		$	0.6900	$	0.1330	$	0.2427
Distribution Amount		—		$	859,886
Distribution Amount Per Unit (5,900,000 units authorized and outstanding)	$	0.4139		$	0.6900	$	0.1330	$	0.2427
Distributable Income Per Unit (5,900,000 units authorized and outstanding)(1)	$	1.0468		$	0.1457
Distribution Amount Per Unit (5,900,000 units authorized and outstanding)	$	0.0000		$	0.1457

(1): Distributable Income Per Unit includes Cash Proceeds on the Sale of Royalty NPI of $1.0029

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

EASTERN AMERICAN NATURAL GAS TRUST

CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

(Unaudited)

	September 30, 2012			December 31, 2011
	March 31, 2013			December 31, 2012
	(Unaudited)
Assets:
Cash	$	~~335~~6,~~002~~395,201		$	~~122~~319,~~740~~519
Net Proceeds Receivable		1683,~~134,174~~620			1685,~~475,510~~783
Net Profits Interests in Gas Properties		9387,~~162~~244,~~180~~905			93,162,180
Accumulated Amortization		(8587,~~554~~060,~~207~~062	)		(8186,~~181~~606,~~967~~842	)
		7,607,973			11,980,213
		184,843			6,555,338
Total Assets	$	97,~~077~~263,~~149~~664		$	137,~~578~~560,~~463~~640
Liabilities and Trust Corpus:
Trust General and Administrative Expenses Payable	$	~~234~~236,~~291~~261		$	~~206~~338,~~150~~602
Distributions Payable		~~784,885~~—			~~942,100~~—
Trust Corpus (5,900,000 Trust Units authorized and outstanding)		87,~~057~~027,~~973~~403			127,~~430~~222,~~213~~038
Total Liabilities and Trust Corpus	$	97,~~077~~263,~~149~~664		$	137,~~578~~560,~~463~~640

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

EASTERN AMERICAN NATURAL GAS TRUST

CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

	Nine Months Ended September 30, 2012			Nine Months Ended September 30, 2011
	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
Trust Corpus, Beginning of Period	$	127,~~430~~222,~~213~~038		$	1412,~~505~~430,~~979~~213
Distributable Income		26,~~442~~175,~~226~~860			4859,~~071,173~~886
Distributions Payable to Unitholders		~~(2,442,226~~—	)		(4859,~~071,173~~886	)
Amortization and Impairment of Net Profits Interests in Gas Properties		(4,372,240	)		(1,739,961	)
Sale of Royalty Net Profits Interests		(5,917,275	)		—
Trust Corpus, End of Period	$	8,057,973		$	12,766,018
Amortization and Impairment of Net Profits Interests in Gas Properties		(453,220	)		(578,480	)
Trust Corpus, End of Period	$	7,027,403		$	11,851,733

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

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

NOTE 1. Organization of the Trust

The Eastern American Natural Gas Trust (the "Trust") was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among Eastern American Energy Corporation ("Eastern American"), as grantor; Bank of Montreal Trust Company, as Trustee; and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee").

The Trust ~~will~~has ~~sell~~sold ~~its~~the ~~assets~~Royalty NPI as described below, and will begin to liquidate prior to May 15, 2013 (the "Liquidation Date"). Pursuant to the Trust Agreement, all ~~proceeds of any sale received by the Trustee after December 31, 2012, and all other~~ receipts of the Trust received after December 31, 2012, will be retained by the Trustee until ~~all~~the ~~remaining~~final ~~Royalty~~distribution ~~NPI~~is ~~interests have been sold~~made. Consequently, Unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for any final distribution to be made ~~after~~on or about August 15, 2013 and the ~~sale~~distribution on or about June 17, 2013 of the ~~Royalty~~proceeds ~~NPI~~of the matured Treasury Obligations (to the extent not previously withdrawn). 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 of record as of ~~the~~May 31, ~~record~~2013 ~~date for the final quarter of the Trust's existence~~ will be entitled to receive a terminating distribution with respect to each Depositary Unit equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations (to the extent not previously withdrawn). ~~See Note 7—Subsequent Events.~~

~~Until~~The ~~March 26,~~Trust ~~2012,~~expects ~~Eastern~~that ~~Marketing~~the ~~Corporation~~last ~~was~~day aon ~~wholly-owned~~which ~~subsidiary~~Units ofwill ~~Energy~~be ~~Corporation~~tradable ofon ~~America.~~the ~~Effective~~New ~~March~~York Stock Exchange will be May 2624, ~~2012,~~2013. ~~Eastern~~The ~~Marketing~~record ~~Corporation~~date for the determination of Unitholders ~~was~~entitled ~~merged~~to ~~into~~the ~~Energy~~distribution ~~Corporation~~on ofor ~~America~~about June 17, ~~with~~2013 ~~Energy~~of ~~Corporation~~the proceeds of ~~America~~the ~~being~~matured Treasury Obligations (to the ~~surviving~~extent ~~corporation.~~not ~~The~~previously ~~merger~~withdrawn) and for the final distribution of ~~Eastern~~all ~~Marketing~~other amounts ~~Corporation~~then ~~into~~payable ~~its~~to ~~parent~~Unitholders ~~Energy~~will ~~Corporation~~be the close of ~~America~~ isbusiness ~~not~~on ~~expected~~May 31, 2013. The Trust also expects to ~~have~~be ~~any~~delisted ~~effect~~from onthe New York Stock Exchange and expects to suspend its reporting obligations under the ~~Trust~~Securities Exchange Act of 1934, as amended, in early June 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 did not have 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 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.

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 1. Organization of the Trust (Continued)

~~The~~substantially ~~Trust~~all ~~was~~of ~~formed~~its tocorporate ~~acquire~~trust ~~and~~business ~~hold~~to ~~net~~The ~~profits~~Bank ~~interests~~of ~~(the~~New ~~"Net~~York. ~~Profits~~Consequently, ~~Interests")~~references ~~created~~herein ~~from~~to the ~~working~~"Trustee" ~~interests~~mean ~~owned~~Bank byof ~~ECA~~Montreal inTrust ~~650~~Company ~~producing~~until ~~gas~~May 8, ~~wells~~2000; ~~and~~The 65Bank ~~proved~~of ~~development~~New ~~well~~York ~~locations~~as ~~(the~~successor ~~"Development~~Trustee ~~Wells")~~from inMay 8, ~~West~~2000 ~~Virginia~~through ~~and~~December 31, ~~Pennsylvania~~2004; ~~(the~~JPMorgan ~~"Underlying~~Chase ~~Properties")~~Bank, N.A. ~~The~~as ~~Net~~successor ~~Profits~~Trustee ~~Interests~~from ~~consisted~~January 1, of2005 athrough ~~royalty~~October 2, ~~interest~~2006; ~~in 322 wells~~ and ~~a term~~ ~~interest~~The inBank ~~the~~of ~~remaining~~New ~~wells~~York ~~and~~Trust ~~development~~Company, ~~well locations~~N.A. ~~ECA~~(now ~~was~~known ~~obligated~~as toThe ~~drill~~Bank ~~and~~of ~~complete,~~New atYork ~~its~~Mellon ~~expense~~Trust Company, 65N.A.) ~~development~~as ~~wells~~successor ~~(the~~Trustee, ~~"Development~~effective ~~Wells")~~as onof ~~the~~October 2, ~~development~~2006. ~~well locations~~The ~~conveyed~~transfer toagent for the Trust. is ~~ECA~~Bondholder ~~has~~Communications, ~~fulfilled~~an ~~its~~affiliate ~~obligation~~of ~~with~~The ~~respect~~Bank toof ~~the~~New ~~drilling~~York ofMellon ~~the~~Trust ~~Development~~Company, ~~Wells~~N.A.

OnThe 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 (the "Development Wells") in West Virginia and Pennsylvania (the "Underlying Properties"). 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. 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 that is contingent, uncertain in amount or 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 and other holders of Trust Units (together, "Trust Unitholders").

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.

After the Trust was formed, 59 of the 65 Development Wells were drilled and completed. The remaining six Development Wells were not drilled. Clear title to two of the Development Wells could not be established, and they were excluded from the Trust in accordance with the conveyance transferring them to the Trust. ECA asserted that the remaining four undrilled Development Wells, if drilled, would be too close to then existing wells on adjoining property, and thereafter settled its dispute with the Trust about drilling those four Development Wells by agreeing instead to pay the Trust on an annual basis, commencing on April 1, 1997 and over the remaining life of the Trust for the annual volume of gas projected to be produced from those Development Wells as if they had been drilled.

The Net Profits Interests initially consisted of a royalty interest ("Royalty NPI") in 322 wells and a term interest ("Term NPI") in the remaining wells and locations. As of September 30, 2012, the Trust held Net Profits Interests in 587 wells, consisting of Royalty NPI in 258 wells and Term NPI in the remaining wells. The Term NPI will expire by its terms on May 15, 2013, or such earlier time as 41,683 MMcf of gas has been produced that is attributable to ECA's net revenue interest in the properties burdened by the Term NPI. As of December 31, 2011, based on the Independent Petroleum Engineer's Report, 27,415 MMcf of the maximum 41,683 MMcf had been produced. Consequently, the Term NPI is expected to terminate on May 15, 2013.

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 1. Organization of the Trust (Continued)

The Net Profits Interests initially consisted of a royalty interest ("Royalty NPI") in 322 wells and a term interest ("Term NPI") in the remaining wells and locations. As described elsewhere herein, the Trust was required to sell the Royalty NPI, and has done so. As of March 31, 2013, the Trust held only the Term NPI in 329 wells. The Term NPI will expire by its terms on May 15, 2013, or such earlier time as 41,683 MMcf of gas has been produced that is attributable to ECA's net revenue interest in the properties burdened by the Term NPI. As of December 31, 2012, based on the Independent Petroleum Engineer's Report, 28,239 MMcf of the maximum 41,683 MMcf had been produced. Consequently, the Term NPI will terminate on May 15, 2013.

NOTE 2. Basis of Presentation

The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Without limiting the foregoing statement, the information furnished is based upon certain estimates of the revenues attributable to the Trust from natural gas production for the three month ~~and~~period ~~nine month periods~~ ended ~~September~~March 3031, ~~2012~~2013 and is therefore subject to adjustment in future periods to reflect actual production for the periods presented.

The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. The accompanying unaudited interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, ~~2011~~2012. The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

NOTE 3. Recently Adopted Accounting Standards

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.

NOTE 4. Significant Accounting Policies

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, if any, is reflected in the Statements of Distributable Income as Cash Proceeds on Sale of Net Profit Interests to the Trust.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Because the Trust's financial statements are prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America, as described above, most accounting pronouncements are not applicable to the Trust's financial statements.

Revenue and Expenses:

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

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 4. Significant Accounting Policies (Continued)

~~Charges, are~~ ~~recognized~~Revenue ~~as incurred pursuant to the conveyances (the "Conveyances") on a per well production basis. The payment provisions of the Gas Purchase Contract originally 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. Expenses:

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 Production and Property and Operating Cost Charges, are recognized as incurred pursuant to the conveyances (the "Conveyances") on a per well production basis. The payment provisions of the Gas Purchase Contract originally 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.

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 FASB Accounting Standards Codification Topic 360, Property, Plant and Equipment ("ASC 360"). The Trust will determine if a writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the fair value of the investment in net profits ~~interests~~ 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 5 for discussion of the impairment in the Underlying Properties recognized during the three month period ended September 30, 2012.~~

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.

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

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

The conveyance of the Royalty and Term Interests to the Trust was accounted for as a purchase transaction. The $9387,~~162~~244,~~180~~905 reflected in the Statements of Assets, Liabilities and Trust Corpus as Net Profits Interests at in Gas Properties at March 31, 2013 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~~and ~~investment~~less in the ~~Royalty~~$5,917,275 ~~Interests is not necessarily indicative of the fair value of such Royalty Interests.~~

NOTE 5. 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 7, 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.

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 64. ~~Income~~Significant ~~Taxes~~ Accounting Policies (Continued)

from the sale of the Royalty NPI to ECA as described above. The carrying value of the Trust's investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.

NOTE 5. Income Taxes

The Trust is a grantor trust and is not required to pay federal or state income taxes. Accordingly, no provision for federal or state income taxes has been made. All income is taxed to the Unitholders of the Trust.

NOTE 7. 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, is expected to be $5,917,264. The Trust and ECA have agreed to close the sale of the Royalty NPI on January 10, 2013.

The expenses expected to be 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 provides 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 will pay EnergyNet a fee equal to 4.0% of the sales price if the sales price is $2 million or less, and an additional 2.0% of any amount of the sales price in excess of $2 million. The fee payable to EnergyNet pursuant to the Brokerage Agreement is expected to be $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 will be required to reimburse Softvest for up to $25,000 of such expenses. ECA has agreed to reimburse the Trust, for the benefit of the Trust unitholders, for any amounts the Trust may be 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 will be entitled, after the closing of the sale of the Royalty NPI, to any distribution for the fourth quarter of 2012. Therefore, although the purchase price for the Royalty NPI should reflect this allocation, unitholders will not receive any direct distribution relating to the fourth quarter of 2012 for revenues attributable to the Royalty NPI.

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Cautionary Statement

This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-Q, including without limitation the statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and all statements regarding the liquidation and termination of the Trust are forward-looking statements. Although ECA has advised the Trustee that it believes that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q and in the Trust's Annual Report on Form 10-K for the year ended December 31, ~~2011~~2012 and include the fact that none of the Trust, the Trustee or ECA is able to predict future gas prices, gas production levels, economic activity, legislation or regulation, or expenses of the Trust, including expenses that may be incurred with ~~the sale of the Royalty NPI and the~~ termination of the Trust. All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. The Trust, the Trustee and ECA disclaim any obligation to update any forward-looking statements except as required by law.

General

Unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for any final distribution to be made after the sale of the Royalty NPI as described herein, and the distribution of the proceeds of the Treasury Obligations (to the extent not previously withdrawn). 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 "—Liquidation of the Trust," below.

The last day of trading of the Units on the New York Stock Exchange is expected to be May 24, 2013. Unitholders as of the close of business on May 31, 2013 will, on or about June 17, 2013, receive the proceeds attributable to the mature Treasury Obligations ($20.00 per trust unit), unless the Treasury Obligations relating thereto have previously been withdrawn. On or about August 15, 2013, such Unitholders will also receive their pro rata share of the proceeds received from the Trust's sale in January 2013 of the Royalty NPI (approximately $1.00 per trust unit) plus their pro rata share of revenues attributable to the Term NPI for the period beginning October 1, 2012 through May 15, 2013, less the costs and expenses and reserves of the Trust during such period. See "—Liquidation of the Trust," below. The Trust was required by the terms of the Trust Agreement governing the Trust to sell the Royalty NPI prior to May 31, 2013, and the Trust has done so. The Trust entered into a Purchase and Sale Agreement dated October 24, 2012 (the "~~Softvest~~October 24, 2012 Purchase Agreement") with ~~Softvest, LP,~~ a ~~Delaware limited partnership~~ ~~("Softvest")~~third party, pursuant to which the Trust agreed to sell the Royalty NPI ~~to Softvest as described therein~~ for $6.5 million, subject to reduction based on decreases to the closing price of the NYMEX natural gas December 2012 contract compared to the price on October 18, 2012 and potential issues with title to the Royalty NPI. On November 5, 2012, ECA exercised its right of first refusal to purchase the Royalty NPI on the terms set forth in the ~~Softvest~~October 24, 2012 Purchase Agreement. The sale price, after making the price adjustment required by the ~~Softvest~~October 24, 2012 Purchase Agreement relating to decreases to the closing price of the NYMEX natural gas December 2012 contract, iswas ~~expected to be~~ $5,917,~~264~~275. ~~The~~On January 3, 2013 the Trust entered into a Purchase and Sale Agreement with ECA ~~have~~in order ~~agreed~~to document the terms of the sale to ~~close~~ECA and to eliminate certain provisions of the Purchase Agreement not applicable to the sale to ECA. The sale of the Royalty NPI to ECA closed on January 10, 2013.

Pursuant to the Softvest Purchase Agreement, Softvest had the right to a reduction of the purchase price in the event of defects in title to the Royalty NPI. However, in connection with its exercise of its right of first refusal, ECA noted that it will not require any review of the status of title to the Royalty NPI. Consequently, the Trust does not anticipate any reduction of the price for title issues.

InThe ~~the~~expenses ~~Softvest~~incurred ~~Purchase~~in ~~Agreement,~~connection with the ~~Trust~~sale ~~agreed~~of tothe ~~reimburse~~Royalty ~~Softvest~~NPI ~~for~~included uppayment pursuant to ~~$25,000~~the ofSale ~~Softvest's~~Brokerage/Consulting ~~out-of-pocket~~Agreement ~~expenses~~dated ~~incurred~~August 16, on2012 or(the ~~after~~"Brokerage Agreement") between the ~~date~~Trust ~~of the~~and ~~Softvest~~EnergyNet.com, Inc. ~~Purchase~~("EnergyNet"). The Brokerage Agreement inprovided ~~connection~~that ~~with~~at ~~its~~the ~~review~~closing of ~~title~~a tosale of the Royalty NPI ifor ~~ECA~~any ~~exercised~~portion ~~its~~thereof, ~~right~~during the term of the ~~first~~engagement ~~refusal~~or ~~after~~within ~~October~~180 ~~26,~~days ~~2012.~~following ~~Because~~the ~~ECA~~end ~~exercised its right~~ of ~~first~~ ~~refusal~~the ~~after October 26~~engagement, ~~2012,~~ the Trust ~~will~~would bepay ~~required~~EnergyNet a fee equal to 4.0% ~~reimburse~~of ~~Softvest~~the ~~for~~sales upprice toif ~~$25,000~~the ofsales ~~such~~price ~~expenses.~~was ~~ECA~~$2 million ~~has~~or ~~agreed~~less, toand ~~reimburse~~an ~~the~~additional ~~Trust,~~2.0% ~~for~~of ~~the~~any ~~benefit~~amount of the ~~Trust unitholders,~~sales ~~for~~price ~~any~~in ~~amounts~~excess ~~the~~of ~~Trust~~$2 million. ~~may~~The befee ~~required~~paid to ~~pay~~EnergyNet pursuant to the ~~Softvest~~Brokerage asAgreement ~~reimbursement~~was ~~of Softvest's expenses~~$158,345.

InPursuant ~~marketing~~to the ~~Royalty NPI~~October 24, ~~the~~2012 ~~Trustee~~Purchase ~~solicited~~Agreement, ~~bids on~~ the ~~basis~~third ofparty ~~the~~had ~~distribution for~~ the ~~third~~right ~~quarter~~to ofa ~~2012~~reduction ~~being for the account~~ of the ~~Trust,~~purchase ~~and~~price ~~the~~in ~~distribution for~~ the ~~fourth~~ ~~quarter~~event of ~~2012~~defects ~~being~~in ~~for~~title ~~the~~to ~~account of~~ the ~~purchaser of the~~ Royalty NPI. ~~The Softvest Purchase Agreement~~ However, ~~and~~in ~~the~~connection ~~amount~~with ~~offered~~its ~~by Softvest, reflected that allocation of the distributions. Upon ECA's~~ exercise of its right of first refusal, ECA ~~became~~waived ~~entitled to acquire the Royalty NPI on the terms of the Softvest Purchase Agreement, and consequently, ECA will be entitled, after the closing of the sale of the Royalty NPI, to~~ any ~~distribution~~adjustment ~~for the fourth quarter of 2012. Therefore, although the purchase price for the Royalty NPI should reflect this allocation, unitholders will not receive any direct distribution~~ relating to the ~~fourth~~status ~~quarter~~ of ~~2012~~title ~~for revenues attributable~~ to the Royalty NPI.

~~See~~In ~~"—Liquidation~~the October 24, 2012 Purchase Agreement, the Trust agreed to reimburse the third party for up to $25,000 of its out-of-pocket expenses incurred on or after the date of the October 24, 2012 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 the third party for up to $25,"000 ~~below~~of such expenses. ECA voluntarily reimbursed the Trust, for the benefit of the Trust unitholders, for the $17,850 the Trust was required to pay to the third party as reimbursement of its expenses.

~~The~~In ~~Trust~~marketing ~~does~~the ~~not~~Royalty ~~conduct~~NPI, ~~any~~the ~~operations~~Trustee orsolicited ~~activities.~~bids ~~The~~on ~~Trust's~~the ~~purpose~~basis ~~is,~~of inthe ~~general,~~distribution tofor ~~hold~~the third quarter of 2012 being for the ~~Net~~account ~~Profits~~of ~~Interests~~the Trust, toand ~~distribute~~the distribution for the fourth ~~cash~~quarter ~~proceeds~~of to2012 ~~Unitholders~~being ~~which~~for the ~~Trust~~ ~~receives~~account inof ~~respect~~the purchaser of the ~~Net~~Royalty ~~Profits~~NPI. ~~Interests~~The ~~(net~~October 24, of2012 ~~Trust~~Purchase ~~expenses)~~Agreement, and tothe ~~perform~~amount ~~certain~~offered ~~administrative~~by ~~functions~~the inthird ~~respect~~party, reflected that allocation of the ~~Net~~distributions. ~~Profits~~Upon ~~Interests~~ECA's ~~and~~exercise ~~the~~of ~~Depositary~~its ~~Units.~~right ~~The Trust~~of ~~derives~~first ~~substantially~~refusal, ~~all~~ECA became entitled to acquire the Royalty NPI on the terms of ~~its~~the ~~income~~October 24, 2012 Purchase Agreement, and consequently, ~~cash~~ECA ~~flows~~was ~~from~~entitled to the ~~Net~~distribution ~~Profits~~for ~~Interests.~~the ~~The~~fourth ~~Trust~~quarter ~~has~~of no2012, ~~source~~and ofunitholders ~~liquidity~~did ornot ~~capital~~receive ~~resources~~any ~~other~~direct ~~than~~distribution relating to the ~~cash~~fourth ~~flows~~quarter ~~from~~of ~~the~~2012 ~~Net~~for ~~Profits~~revenues ~~Interests~~attributable to the Royalty NPI or for any period subsequent to such time.

The ~~Net~~Trust ~~Profits~~does ~~Interests~~not ~~were~~conduct ~~created~~any ~~pursuant~~operations toor ~~Conveyances~~activities. ~~from~~The ~~ECA~~Trust's topurpose ~~the~~is, ~~Trust.~~in Ingeneral, ~~connection~~to ~~therewith,~~hold ~~ECA~~the ~~assigned~~Net ~~its~~Profits ~~rights~~Interests, ~~under~~to adistribute ~~gas~~the ~~purchase~~cash ~~contract~~proceeds ~~(the~~to ~~"Gas~~Unitholders ~~Purchase~~which the ~~Contract"),~~Trust ~~which~~receives ~~obligates~~in ~~Eastern~~respect ~~Marketing,~~of ~~and~~the ~~now~~Net ~~ECA~~Profits asInterests ~~successor~~(net byof ~~merger~~Trust expenses), and to ~~purchase~~perform ~~all~~certain administrative functions in respect of the ~~natural~~Net ~~gas~~Profits ~~produced~~Interests ~~from~~and the ~~Underlying~~Depositary ~~Properties~~Units. ~~that~~The Trust isderives ~~attributable~~substantially toall ~~the~~of ~~Net~~its ~~Profits Interests.~~income Asand acash ~~result~~flows offrom the ~~merger~~Net ~~ECA~~Profits ~~will~~Interests, ~~purchase~~including the ~~gas~~sale onof the ~~same~~Royalty ~~terms~~NPI onin ~~which~~January ~~Eastern~~2013. ~~Marketing~~The ~~would~~Trust ~~have~~has ~~been~~no ~~obligated~~source toof ~~purchase~~liquidity or capital resources other than the ~~gas~~cash ~~pursuant~~flows tofrom the ~~Gas~~Net ~~Purchase~~Profits ~~Contract~~Interests.

The Net Profits Interests were created pursuant to Conveyances from ECA to the Trust. In connection therewith, ECA assigned its rights under a gas purchase contract (the "Gas Purchase Contract"), which obligates Eastern Marketing, and now ECA as successor by merger, to purchase all of the natural gas produced from the Underlying Properties that is attributable to the Net Profits Interests. As a result of the merger ECA has purchased the gas on the same terms on which Eastern Marketing would have been obligated to purchase the gas pursuant to the Gas Purchase Contract.

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" for such quarter, multiplied by (b) the applicable price for such quarter under the Gas Purchase Contract. "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".

The "Operating Cost Charge" for 2012 was based on an annual rate of $599,556, and for 2011 was originally based on an annual rate of $658,604. 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 fluctuate 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 a December-to-December comparison.

The "Operating Cost Charge" for 2013 was reduced as a result of the sale of the Royalty NPI and was based on an annual rate of $321,924, and for 2012 was originally based on an annual rate of $599,556. As provided in the Conveyances, the Operating Cost Charge will fluctuate 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 a December-to-December comparison.

During 2003, the United States Department of Labor, Bureau of Labor Statistics converted all of its industry-based statistics to a different reporting system that was developed in cooperation with the United States' North American Free Trade Agreement Partners, Canada and Mexico, in an effort to standardize and modernize reporting codes. As a result of this conversion, the Crude Petroleum and Gas Production Workers index is no longer available for use in the annual calculation of overhead adjustment called for in the various Council of Petroleum Accountants Societies, or COPAS, model forms after March 2003.

Research by COPAS covering a ten year period indicated that by blending the Oil and Gas Extraction Index with the Professional and Technical Services Index, the results approximate the data from the old Crude Petroleum and Natural Gas Workers Index. Accordingly, COPAS has calculated the percentage change in the simple average of the Oil and Extraction Index and the Professional and Technical Services Index, commencing in April 2004. This "Overhead Adjustment Index" has been provided as a guidance to the industry as a replacement index for use in calculating the overhead adjustment. The adjustment for the effective time period is 5%. Since the Conveyance Documents do not specifically provide for a replacement index if the Crude Petroleum and Gas Production Workers Index was no longer published, ECA believes, and advised the Trustee, that the "Overhead Adjustment Index" as calculated by COPAS is a reasonable index to utilize since the industry is generally adopting the same as a replacement. ECA, with the concurrence of the Trustee, will utilize this "Overhead Adjustment Index" to adjust the "Operating Cost Charge" so long as such index is published by COPAS.

The Operating Cost Charge is 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.

Pursuant to the Gas Purchase Contract, ECA as successor by merger to Eastern Marketing, is obligated to purchase such gas production at a purchase price per Mcf equal to the Index Price. The Index Price for any quarter 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 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 that is traded on the New York Mercantile Exchange.

Accordingly, the Index Price payable to the Trust for production may be higher or lower based on the fluctuations in natural gas futures prices during the relevant calculation period. The price payable to the Trust will have a direct impact, positively or negatively, on the quarterly Distributions Payable by the Trust to its Unitholders.

~~ECA~~Accordingly, ~~had a disagreement with~~ the ~~Trust~~Index inPrice ~~1997~~payable ~~over ECA's obligation~~ to ~~drill~~the ~~certain Development Wells that were closely offset by third parties. The~~ Trust ~~agreed~~for ~~that~~production inmay ~~lieu~~be ~~of drilling~~higher ~~these~~or ~~closely~~lower ~~offset~~based ~~Development Wells, ECA could provide the Trust,~~ on ~~an annual basis commencing on April 1, 1997, and over~~ the ~~remaining~~fluctuations ~~life~~in ofnatural ~~the Trust, a volume of~~ gas ~~which~~futures ~~is equal~~prices toduring the ~~projected~~relevant ~~volumes~~calculation ~~of the wells as if they had been drilled~~period. ~~These volumes have been estimated by Ryder Scott Company, independent petroleum engineers. During the quarter ended~~ ~~September 30,~~The ~~2012,~~price ~~payment~~payable ~~for an additional volume of 2,389 Mcf was delivered~~ to the Trust, ashas ~~compared to~~ a ~~payment~~direct ~~for 2~~impact,~~582~~ ~~Mcf~~positively ~~for~~or ~~the quarter ended September 30~~negatively, ~~2011.~~on ~~These additional~~any ~~payments~~distributions ~~fulfill~~payable ~~ECA's~~by ~~agreement to provide payment for~~ the ~~quarter~~Trust ~~for~~to ~~volumes~~its ~~for Development Wells that had been closely offset by third parties~~Unitholders.

ECA ~~has~~had ~~fulfilled~~a ~~its~~disagreement ~~obligation~~ with ~~respect~~the Trust in 1997 over ECA's obligation to ~~the~~drill ~~drilling~~certain Development Wells that were closely offset by third parties. The Trust agreed that in lieu of drilling ~~the~~these closely offset Development Wells., ~~Since~~ECA could provide the ~~inception~~Trust, on an annual basis commencing on April 1, 1997, and over the remaining life of the Trust, ~~ECA~~a ~~has~~volume ~~drilled~~of agas ~~total~~which is equal to the projected volumes of 59the ~~Development~~wells ~~Wells~~as if they had been drilled. These volumes have been estimated by Ryder Scott Company, ~~which~~independent ~~are~~petroleum engineers. During the quarter ended ~~online~~March 31, ~~and~~2013, ~~producing.~~payment ~~(See~~for an additional volume of 2,389 Mcf was delivered to the Trust's, ~~Annual~~as ~~Report~~compared onto ~~Form 10-K~~a payment for ~~the~~2,582 ~~year~~Mcf for the quarter ended ~~December~~March 31, ~~2011,~~2012. ~~for~~These aadditional ~~more~~payments ~~complete~~fulfill ~~description~~ECA's ofagreement to provide payment for the quarter for volumes for Development Wells that had been closely offset by third parties.)

~~During~~Under the ~~first~~Trust ~~half of 2011~~Agreement, ~~ECA~~the ~~entered~~Trustee ~~into~~was ~~two~~directed ~~separate Purchase and Sale Agreements~~ to sell ~~certain~~all ~~assets~~Royalty toNPI ~~unrelated~~prior ~~third~~to ~~parties~~May 15, in2013. ~~which~~The ~~the~~Trustee ~~Trust~~has ~~owned~~done aso, ~~Net~~and ~~Profits Interest.~~net Asproceeds offrom ~~January 1,~~selling ~~2010~~such ~~ECA~~Royalty ~~can~~NPI ~~transfer~~will ~~the~~be distributed ~~Underlying~~to ~~Properties~~Unitholders ~~and~~on ~~require~~or ~~the~~about ~~Trust~~August 15, to2013. ~~release~~The ~~the~~Term NPI ~~burdening~~will ~~that~~expire ~~property,~~on ~~without~~ the ~~consent~~earlier of ~~the~~May 15, ~~Trustee~~2013 or ~~Unitholders, subject~~such totime ~~payment~~as to41,683 ~~the~~MMcf ~~Trust~~ of ~~the~~gas ~~fair~~has ~~value~~been ofproduced ~~the~~which ~~interest~~is ~~released.~~attributable to ECA's ~~finalized~~net ~~the~~revenue ~~sale~~interests ~~of the assets, as described~~ in the ~~Purchase~~properties ~~and~~burdened ~~Sale~~by ~~Agreements, in~~ the ~~quarter~~Term ~~ended June 30, 2011~~NPI. ~~ECA~~As ~~received sale proceeds for the wells in the amount~~ of ~~$588~~December 31,~~911.~~ ~~The~~2012, ~~Trust's share of the sales proceeds was $181~~28,~~928~~239 ~~and~~MMcf ~~was included in the Distributable Income~~ of ~~the~~such ~~Trust~~gas ~~during~~had ~~the quarter~~been ~~ended June 30, 2011~~produced.

~~Over~~The administrative costs the ~~remaining~~Trust ~~life~~incurs ofin the future will fluctuate depending primarily on the expenses the Trust incurs for professional services, ~~wells~~particularly ~~may~~legal, beaccounting ~~disposed~~and engineering ofservices, ~~from~~including ~~time~~expenses tothe ~~time~~Trust incurs in ~~accordance~~connection with the ~~documents~~liquidation ~~governing~~and termination of the Trust, which are expected to be significantly greater than the routine historical administrative expenses the Trust has typically incurred.

The administrative costs the Trust incurs in the future will fluctuate depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services, including expenses the Trust incurs in connection with its sale of the Royalty NPI, which are expected to be significantly greater than the routine historical administrative expenses the Trust has typically incurred. The expenses expected to be 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"). As previously disclosed, pursuant to the Brokerage Agreement, the Trust engaged EnergyNet to perform sales brokerage and consulting services in connection with the Trust's anticipated sale of the Royalty NPI. The Brokerage Agreement provides 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 will pay EnergyNet a fee equal to 4.0% of the sales price if the sales price is $2 million or less, and an additional 2.0% of any amount of the sales price in excess of $2 million. The fee payable to EnergyNet pursuant to the Brokerage Agreement is expected to be $158,345.

Liquidation of the Trust

The Trust will be liquidated and ~~the~~terminate ~~Royalty~~during ~~NPI~~2013. ~~will~~The belast ~~sold~~day ~~prior~~of totrading of the ~~Liquidation~~Units ~~Date,~~on ~~which~~the New York Stock Exchange is expected to ~~occur~~be inMay 24, 2013. Unitholders of record as of the ~~record~~close ~~date~~of ~~for~~business on May 31, 2013 will, on or about June 17, 2013, receive the ~~final~~proceeds ~~quarter~~attributable ofto the ~~Trust's~~mature ~~existence~~Treasury Obligations ~~will~~($20.00 beper ~~entitled~~trust tounit), ~~receive~~unless athe ~~terminating~~Treasury ~~distribution~~Obligations ~~with~~relating ~~respect~~thereto tohave ~~each~~previously ~~Depositary~~been ~~Unit~~withdrawn. ~~equal~~On toor aabout August 15, 2013, such Unitholders will also receive their pro rata ~~portion~~share of the ~~net~~ proceeds received from the Trust's sale in January 2013 of the Royalty NPI (toapproximately ~~the~~$1.00 ~~extent~~per ~~not~~trust ~~previously~~unit, ~~distributed)~~based ~~and~~on aproceeds ~~pro rata portion~~ of ~~the~~$5.92 million) ~~proceeds~~plus ~~from~~their ~~the~~pro ~~matured~~rata ~~Treasury~~share of ~~Obligations~~revenues (attributable to the ~~extent not~~term ~~previously~~net ~~withdrawn).~~profits ~~The~~interest ~~Term~~for ~~NPI~~the ~~will~~period ~~expire~~beginning byOctober 1, ~~its~~2012 ~~terms~~through ~~no later than~~ May 15, 2013, ~~and~~less ~~the~~any ~~Trust~~costs ~~will~~and ~~not~~expenses ~~realize~~or ~~any~~reserves ~~further~~of ~~value from~~ the ~~Term~~Trust ~~NPI~~during ~~after~~ such ~~date~~ period.

As described above, on August 16, 2012 the Trust entered into the Brokerage Agreement, pursuant to which the Trust engaged 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,

AsECA ~~described~~granted ~~above,~~a onwaiver ~~August 16,~~in ~~2012~~order ~~the Trust entered into the Brokerage Agreement, pursuant~~ to ~~which~~allow the Trust ~~engaged~~additional ~~EnergyNet~~time ~~to perform sales brokerage and consulting services~~ in ~~connection~~which ~~with~~to ~~the~~market ~~Trust's anticipated sale of~~ the Royalty NPI. ~~EnergyNet~~ECA ~~subsequently~~further ~~informed~~agreed ~~the~~to ~~Trustee~~waive ~~that~~the ~~its~~20-business ~~marketing~~day ~~activities~~notice ~~resulted~~of ina ~~190~~proposed ~~companies~~sale ~~reviewing materials relating~~ to ~~the~~which ~~Royalty~~it was ~~NPI,~~entitled ~~with~~under ~~approximately ten of~~ the ~~companies~~Trust ~~conducting~~Agreement ~~more~~in ~~extensive~~order ~~reviews.~~to ~~EnergyNet~~allow ~~then solicited bids for~~ the ~~Royalty~~Trust ~~NPI.~~additional ~~The~~time ~~highest~~in ~~bid~~which ~~submitted~~to ~~was~~market the ~~bid submitted~~Royalty ~~by Softvest~~NPI, ~~which~~and ~~subsequently~~agreed ~~entered~~to ~~into~~accept ~~the~~a ~~Softvest~~shorter ~~Purchase~~notice ~~Agreement with the Trust described above~~period.

~~Pursuant~~Bids tofor the Royalty NPI were due in October 2012. The Trust ~~Agreement~~accepted the highest bid, ~~ECA~~and entered into the October 24, ~~which~~2012 ~~held~~Agreement adescribed above. On November 5, 2012, ECA exercised its right of first refusal under the Trust Agreement to purchase the Royalty NPI ~~from~~on the ~~Trust,~~terms ~~had~~set forth in the ~~right~~October 24, to2012 ~~require~~Agreement. ~~the~~As ~~Trust~~a toconsequence ~~engage~~of anECA's ~~appraiser~~exercise toof ~~appraise~~its right of first refusal, the ~~Royalty~~October 24, ~~NPI~~2012 ifAgreement terminated in accordance with its terms, and the Trust ~~had~~became ~~not~~obligated ~~sold~~to sell the Royalty NPI to ECA for the purchase price determined by ~~September~~the October 3024, 2012 Agreement. ~~ECA~~On ~~also~~January 3, ~~had~~2013, the ~~right~~Trust toentered ~~purchase~~into ~~the~~a ~~Royalty~~Purchase ~~NPI~~and atSale ~~the~~Agreement ~~appraised~~with ~~value.~~ECA Atto document the ~~request~~terms of the sale of the Royalty NPI to ~~Trustee,~~ECA onand ~~September~~to eliminate provisions of the October 2524, 2012, ~~ECA~~Agreement ~~granted~~that awere ~~waiver~~inapplicable into ~~order~~the tosale ~~allow~~of the ~~Trust~~Royalty ~~additional~~NPI ~~time~~to inECA. ~~which~~The tosale ~~market~~of the Royalty NPI. to ECA ~~further~~was ~~agreed~~completed toon January 10, ~~waive~~2013. The price, after making the ~~20-business~~adjustment ~~day notice~~for ofgas aprice ~~proposed~~changes ~~sale~~required toby ~~which~~the itOctober 24, 2012 Agreement, was ~~entitled~~$5,917,275, ~~under~~and ~~the~~was ~~Trust~~paid ~~Agreement~~in cash. Expenses paid in connection ~~order~~with tothe ~~allow~~sale include the ~~Trust~~brokerage ~~additional~~fee ~~time~~of in$158,345. ~~which~~On toor ~~market~~about August 15, 2013, the ~~Royalty~~net ~~NPI,~~proceeds ~~and~~of ~~agreed~~the sale are expected to ~~accept~~be adistributed ~~shorter~~to ~~notice~~Unitholders of record as of the close ~~period~~of business on May 31, 2013 as described above.

OnIn ~~October 5,~~connection 2012 ECA informed the Trustee that ECA had estimated the present value of the Asset Retirement Obligation, as defined under Generally Accepted Accounting Principles, attributable to the Trust's Royalty NPI associated with ~~potential plugging and abandonment liabilities for wells in which the Trust holds~~ its Royalty NPI at between $2.7 million and $5.0 million. ECA further advised the Trustee that its estimate range is net of estimated salvage value. ECA noted that the Asset Retirement Obligation attributable to the Royalty NPI could be considered a Capital Cost under the terms of the Royalty NPI Conveyancetermination, ~~and that if such a determination were made,~~ the ~~costs~~Trust ~~would~~intends ~~be chargeable against future distributions~~ to arequest ~~future purchaser of the Royalty NPI or~~ to ~~the~~be ~~Trust.~~delisted ~~During~~from the ~~approximately~~New ~~20 years~~York ~~that~~Stock ~~the~~Exchange ~~Trust has been in existence, ECA has not charged any amounts for accrued or estimated future plugging~~ and ~~abandonment liabilities against amounts payable~~ to ~~the~~suspend ~~Trust~~its ~~pursuant~~reporting toobligations ~~either~~under the ~~Royalty~~Securities ~~NPI or the Term NPI. Although no final determination regarding the matter has been made, the Trustee was obligated to~~Exchange ~~advise~~Act ~~EnergyNet and thus potential purchasers~~ of ~~the~~1934, ~~NPI~~as ~~of ECA's communication regarding the potential charges~~amended, ~~and~~in ~~did~~early soJune ~~promptly~~2013.

As described above, on October 24, 2012 the Trust and Softvest entered into the Softvest Purchase Agreement. Subsequently, on November 5, 2012, ECA delivered a notice to the Trustee in which ECA elected to exercise its right of first refusal to purchase the Royalty NPI on the terms sets forth in the Purchase Agreement. The material terms of the Softvest Purchase Agreement and of ECA's exercise of its right of first refusal are described above. See "—General," above.

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

Royalty NPI, to any distribution for the fourth quarter of 2012. Therefore, although the purchase price for the Royalty NPI should reflect this allocation, unitholders will not receive any direct distribution relating to the fourth quarter of 2012 for revenues associated with the Royalty NPI.

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; (iii) the sale of the Net Profits Interests is reflected in the Statements of Distributable Income as cash proceeds to the Trust; and (iv) the presentation of a Statement of Cash Flows is not required.

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 5 to the Financial Statements.~~

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

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.

Recent Accounting Pronouncements

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 and operating expenses and the amount of established reserves, are distributed currently to the Unitholders.

The Trust did not have any contractual obligations as of ~~September~~March 3031, 2012 other than its contractual obligations to EnergyNet under the Brokerage Agreement described above. As described above, the fee payable to EnergyNet is expected to be $158,345, which will become payable upon the closing of the sale of the Royalty NPI, which is scheduled to occur on January 10, 2013. At ~~September~~March 3031, ~~2012~~2013, the Trust had Trust General and Administrative Expenses Payable of $~~234~~236,~~291~~261 and no Distributions Payable ~~of $784,885~~.

Comparison of Results of Operations for Three Months Ended ~~September~~March 3031, ~~2012~~2013 and Three Months Ended ~~September~~March 3031, ~~2011~~2012

The Trust's Distributable Income was $~~784~~6,~~885~~175,860 for the three months ended ~~September~~March 3031, ~~2012~~2013 as compared to $1859,~~431,801~~886 for the ~~three~~ three months ended ~~September~~March 3031, ~~2011~~2012. This ~~decrease~~increase was primarily due to athe ~~decrease~~sale ~~in Royalty Income~~ of ~~$532,315~~the ~~($1,388,195~~Royalty ~~for~~NPI ~~the~~to ~~three~~ECA ~~months~~that ~~ended~~closed ~~September~~on January 3010, ~~2012~~2013 asfor ~~compared to~~ $15,~~920~~917,~~510 for the three months ended September 30, 2011)~~275. ~~This~~Offsetting ~~decrease~~this inincrease ~~Royalty Income~~ was ~~related to~~ a decrease in ~~the~~Royalty ~~price~~Income ~~payable~~of to$679,684 ~~the Trust under the Gas Purchase Contract as discussed below~~ ($~~3.427~~819,016 ~~per Mcf~~ for the three months ended ~~September~~March 3031, ~~2012~~2013 as compared to $~~5.084~~1,498,700 ~~per Mcf~~ for the three months ended ~~September~~March 3031, ~~2011~~2012). ~~Offsetting~~This ~~this~~ decrease was andue ~~increase~~to a decrease in production of gas attributable to the Net Profits Interests for the three months ended ~~September~~March 3031, ~~2012~~2013 (~~405~~202 ~~MMcf~~Mmcf) as compared to the three months ended ~~September~~March 3031, ~~2011~~2012 of (~~378 MMcf~~391 Mmcf). The ~~increase~~decline in production is primarily attributable to ~~increased~~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 increase was also partially ~~offset~~due byto an increase in the average price payable to the Trust ~~natural~~under ~~production~~the ~~declines~~Gas Purchase Contract as discussed below ($4.043 per Mcf for the three months ended March 31, 2013 as compared to $3.845 per Mcf for the three months ended March 31, 2012). Taxes on Production and Property were $~~104~~54,~~132~~915 for the three months ended ~~September~~March 3031, ~~2012~~2013 as compared to $~~135~~111,~~234~~095 for the three months ended ~~September~~March 3031, ~~2011~~ 2012. The decrease in taxes is due directly to the decrease in Royalty Income as discussed above. General and Administrative Expenses were $~~349~~425,~~310~~035 for the three months ended ~~September~~March 3031, ~~2012~~ 2013 as compared to $~~210~~377,~~473~~839 for the three months ended ~~September~~March 3031, ~~2011~~2012. The increase in General and Administrative Expenses was due primarily to an increase in professional fees.

The price payable to the Trust for gas production attributable to the Net Profits Interests was $3.427 per Mcf for the three months ended September 30, 2012 and $5.084 per Mcf for the three months ended September 30, 2011. The price per Mcf was lower for the three months ended September 30, 2012 than for the corresponding three month period ended September 30, 2011 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.815 per million British Thermal Units ("Dth") for the three months ended September 30, 2012 as compared to $4.322 per Dth for the three months ended September 30, 2011). 15

~~Financial~~The ~~results~~price ~~depend~~payable onto ~~many~~the ~~factors,~~Trust ~~particularly~~for gas production attributable to the ~~price~~Net ofProfits ~~natural~~Interests ~~gas~~was $4.043 ~~During~~per Mcf for the ~~third~~three ~~quarter~~months ofended March 31, 2013 and $3.845 per Mcf for the three months ended March 31, 2012. The price per Mcf was higher for the three months ended March 31, 2013 than for the ~~Trust~~corresponding ~~experienced~~three amonth ~~significant~~period ~~decrease~~ended March 31, 2012 due to an increase in ~~natural~~the average spot market price for gas ~~prices~~delivered ~~from~~ at the ~~prior~~Henry ~~year~~Hub near Henry, Louisiana ($3.375 ~~Price~~per ~~variations~~million ~~may~~British ~~have~~Thermal aUnits ~~material~~("Dth") ~~impact~~for onthe three months ended March 31, 2013 as compared to $3.195 per Dth for the ~~financial~~three ~~statements~~months ended March 31, 2012).

Financial results ~~Comparison~~depend ofon ~~Results~~many factors, particularly the price of ~~Operations~~natural ~~for~~gas. ~~Nine~~During ~~Months~~the ~~Ended~~three ~~September~~months ended March 3031, ~~2012~~2013, ~~and~~the ~~Nine~~Trust ~~Months~~experienced ~~Ended~~an ~~September 30,~~increase ~~2011~~ in natural gas prices from the prior year. Price variations may have a material impact on the financial statements.

The Trust's ~~Distributable~~has ~~Income~~incurred ~~was~~expenses ~~$2,442,226~~in preparation for ~~the~~its ~~nine~~liquidation ~~months~~and ~~ended~~expects ~~September 30,~~to ~~2012~~incur assubstantial ~~compared~~additional toexpenses ~~$4,071,173~~in ~~for~~connection with the liquidation. All expenses must be paid, and ~~nine~~reserves established ~~months~~for ~~ended~~future ~~September 30~~and contingent expenses, ~~2011.~~before ~~This~~any ~~decrease~~final ~~was~~distribution ~~due~~will be made to athe Unitholders.

decrease in Royalty Income of $1,423,283 ($4,155,702 for the nine months ended September 30, 2012 as compared to $5,578,985 for the nine months ended September 30, 2011). The decrease in Royalty Income was due to a decrease in the price payable to the Trust under the Gas Purchase Contract as discussed below ($3.487 per Mcf for the nine months ended September 30, 2012 as compared to $5.012 per Mcf for the nine months ended September 30, 2011). Offsetting this decrease was an increase in production of gas attributable to the Net Profits Interests for the nine months ended September 30, 2012 (1,194 MMcf) as compared to the nine months ended September 30, 2011 (1,113 MMcf). The increase in production is primarily attributable to increased production from several wells in West Virginia which are located in an area experiencing increased drilling and completion activities, partially offset by natural production declines. Taxes on Production and Property were $312,109 for the nine months ended September 30, 2012 as compared to $393,282 for the nine months ended September 30, 2011. The decrease in taxes is due directly to the decrease in Royalty Income as discussed above. General and Administrative Expenses were $951,744 for the nine months ended September 30, 2012 as compared to $845,783 for the nine months ended September 30, 2011. The increase in General and Administrative Expenses was due primarily to an increase in professional fees.

The price payable to the Trust for gas production attributable to the Net Profits Interests was $3.487 per Mcf for the nine months ended September 30, 2012 and $5.012 per Mcf for the nine months ended September 30, 2011. The price per Mcf was lower for the nine months ended September 30, 2012 than for the corresponding nine month period ended September 30, 2011 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.870 per Dth for the nine months ended September 30, 2012 as compared to $4.256 per Dth for the nine months ended September 30, 2011).

Financial results depend on many factors, particularly the price of natural gas. During the nine months ended September 30, 2012, the Trust experienced a significant decrease in natural gas prices from the prior year. Price variations may have a material impact on the financial statements.

The Trust has incurred expenses in preparation for its sale of the Royalty NPI and liquidation and expects to incur substantial additional expenses in connection with its sale of the Royalty NPI and liquidation between October 1, 2012 and May 15, 2013. The expenses will include the fee payable to EnergyNet, which is expected to be $158,345, and will become payable upon the closing of the sale of the Royalty NPI.

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 would be material to investors.

Other Information

For the calendar quarter ended ~~September~~March 3031, ~~2012~~2013, the high and low closing prices of the Treasury Obligations (which have $1,000 face principal amount), as quoted in the over-the-counter market for United States Treasury obligations were $~~1,000~~999.2090 and $~~998~~999.0060, respectively. On ~~September~~March 3031, ~~2012~~ 2013, the closing price of the Treasury Obligations, as quoted on such market, was $999.0090.

The Trust provides Unitholders with the option to separate the related Treasury Obligation from the Trust Units. Upon exercising this option, the Trustee transfers such Trust Units from the name of the Depositary to the name of the withdrawing Unitholder. As of ~~September~~March 3031, ~~2012~~2013, this option had been exercised on 2,~~277~~798,~~950~~650 Trust Units. (See the Trust's Form 10-K for the year ended December 31, ~~2011~~2012 for a more complete description of the Withdrawal of Trust Units and Restriction on Transfer.)

ITEM 3. 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 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 2. As described elsewhere herein, gas production attributable to the Net Profits Interests is sold to ~~ECA~~Eastern Marketing, and now ECA as successor by merger ~~to Eastern Marketing~~, pursuant to the Gas Purchase Contract described herein, and the Trust's quarterly distributions are highly dependent on the price payable to the Trust for gas production attributable to the Net Profits Interests. Natural gas prices can fluctuate widely in response to many factors, all of which are out of the control of the Trust, the Trustee and ECA.

ITEM 4. 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 Securities and Exchange Commission's rules and forms. 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 ~~September~~March 3031, ~~2012~~2013, 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~~ 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 may be deemed to include:

•: ECA and its consolidated subsidiaries manage virtually all of the 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 on ECA for such information; 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 has 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 or all fraud. Further, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.

Changes in Internal Control ~~Over~~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.

PART II—OTHER INFORMATION

ITEM 1. Legal Proceedings.

None.

ITEM 1A. Risk Factors.

There have been no material changes in the risk factors disclosed under Part I, Item 1A of the Trust's Annual Report on Form 10-K for the year ended December 31, ~~2011~~2012.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

ITEM 3. Defaults Upon Senior Securities.

None.

ITEM 4. Mine Safety Disclosures.

Not applicable.

ITEM 5. Other Information.

None.

ITEM 6. Exhibits.

Exhibit Number			Description
	10.1		Purchase and Sale Agreement with Energy Corporation of America dated January 3, 2013 (incorporated by reference to exhibit 10.1 to the registrant's Form 8-K filed January 9, 2013 (File No. 001-11748)
	31.		Rule 13a-14(a)/15d-14(a) Certification
	32.		Section 1350 Certification

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SIGNATURES

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


EASTERN AMERICAN NATURAL GAS TRUST
By:	The Bank of New York Mellon Trust Company, N.A., Trustee
	/s/ MIKE ULRICH
	Name:	Mike Ulrich
	Title:	Vice President
		The Bank of New York Mellon Trust Company, N.A.

Date: May 9, 2013

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

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PART I—FINANCIAL INFORMATION

ITEM 1. Financial Statements

EASTERN AMERICAN NATURAL GAS TRUST CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (Unaudited)
EASTERN AMERICAN NATURAL GAS TRUST CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (Unaudited)
EASTERN AMERICAN NATURAL GAS TRUST CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)
EASTERN AMERICAN NATURAL GAS TRUST NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

ITEM 4. Controls and Procedures

PART II—OTHER INFORMATION

ITEM 1. Legal Proceedings.

ITEM 1A. Risk Factors.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.