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

FORM 10-Q

(Mark One)ý

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended June 30, 2012ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                             to


Commission File Number 1-11748

EASTERN AMERICAN NATURAL GAS TRUST(Exact name of registrant as specified in its charter)

Delaware(State or other jurisdiction of
incorporation or organization)

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


The Bank of New York Mellon Trust Company, N.A, Trustee
Global Corporate Trust
919 Congress Avenue Suite 500
Austin, 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 August 1, 2012, 5,900,000 Units of Beneficial Interest in Eastern American Natural Gas Trust were issued, outstanding and held by
non-affiliates of the registrant (the "Outstanding Units"). Of the Outstanding Units, 2,024,400 Units of Beneficial Interest (the "Withdrawn Units") have been withdrawn from trading by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.





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PART IFINANCIAL INFORMATION

ITEM 1.    Financial Statements

EASTERN AMERICAN NATURAL GAS TRUST        CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME        (Unaudited)

Six Months Ended
June 30,

Three Months Ended
June 30,2012

2011

2012

2011Royalty Income

$
2,767,507

$
3,658,475

$
1,268,807

$
1,912,473Operating ExpensesTaxes on Production and Property


207,977


258,048


96,881


135,191Operating Cost Charges


299,778


307,673


149,889


143,022Total Operating Expenses


507,755


565,721


246,770


278,213Net Proceeds to the Trust


2,259,752


3,092,754


1,022,037


1,634,260General and Administrative Expenses


602,434


635,310


224,595


229,430Interest Income


24





15


Cash Proceeds on Sale of Net Profit Interests





181,928





181,928Distributable Income


1,657,342


2,639,372


797,457


1,586,758Distribution Amount


1,657,342


2,639,372


797,457


1,586,758Distributable Income Per Unit (5,900,000 units authorized and outstanding)

$
0.2809

$
0.4474

$
0.1352

$
0.2689Distribution Amount Per Unit (5,900,000 units authorized and outstanding)

$
0.2809

$
0.4474

$
0.1352

$
0.2689




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

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EASTERN AMERICAN NATURAL GAS TRUST        CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS        (Unaudited)

June 30,
2012

December 31,
2011Assets:Cash

$
367,183

$
122,740Net Proceeds Receivable


1,022,037


1,475,510Net Profits Interests in Gas Properties


93,162,180


93,162,180Accumulated Amortization


(82,348,405
)

(81,181,967
)10,813,775


11,980,213Total Assets

$
12,202,995

$
13,578,463Liabilities and Trust Corpus:Trust General and AdministrativeExpenses Payable

$
141,763

$
206,150Distributions Payable


797,457


942,100Trust Corpus (5,900,000 Trust Units authorized and outstanding)


11,263,775


12,430,213Total Liabilities and Trust Corpus

$
12,202,995

$
13,578,463




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

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EASTERN AMERICAN NATURAL GAS TRUST        CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS        (Unaudited)

Six Months
Ended
June 30, 2012

Six Months
Ended
June 30, 2011Trust Corpus, Beginning of Period

$
12,430,213

$
14,505,979Distributable Income


1,657,342


2,639,372Distributions Payable to Unitholders


(1,657,342
)

(2,639,372
)Amortization of Net Profits Interests in Gas Properties


(1,166,438
)

(1,149,118
)Trust Corpus, End of Period

$
11,263,775

$
13,356,861




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

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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 sell its assets and 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 remaining Royalty NPI interests have been sold.
Consequently, Unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for any final distribution to
be made after the sale of the Royalty NPI. 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 record date for the final quarter of the Trust's existence will be entitled to receive a terminating
distribution with respect to each Depositary Unit equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of
the proceeds from the matured Treasury Obligations (to the extent not previously withdrawn). Under the Trust Agreement, ECA has a right of first refusal to purchase the Royalty NPI at fair market
value, or, if applicable, the offered third-party price, prior to the Liquidation Date.

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 is not expected to have 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

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 1. Organization of the Trust (Continued)

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 (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").

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
June 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

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 1. Organization of the Trust (Continued)

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.

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 six month periods ended June 30, 2012 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. 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

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 4. Significant Accounting Policies (Continued)

distribution
to Unitholders before application of 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 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 attributable to proved gas reserves of the Underlying Properties. Any such writedown would
not reduce Distributable Income, although it would reduce Trust Corpus. No impairment in the Underlying Properties was recognized during the six months period ended June 30, 2012.

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

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

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

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.

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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" 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 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. 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. 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
Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Net Profits Interests, to distribute the cash proceeds to Unitholders which the
Trust receives in respect of the Net Profits Interests (net of Trust expenses), 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. The Trust has no source of liquidity or capital resources other than the cash flows from the Net Profits
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 will purchase 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. As discussed below, the 2011 Operating Cost
Charge was decreased during the quarter ended June 30, 2011 as a result of wells sold during the second

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quarter.
These sold wells reduced the Operating Cost Charge for the quarter ended June 30, 2012. 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. As a result of
selling wells, the Operating Cost Charge was reduced by $21,629 in the quarter ended June 30, 2011 and this reduction is applicable for all quarters thereafter. 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 inThe Wall Street Journal, for such contracts which expire during such month; and
(iii) the closing settlement price per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as

10

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reported
inThe Wall Street Journal, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is
defined as a gas futures contract for gas to be delivered to the Henry Hub 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
had a disagreement with the Trust in 1997 over ECA's obligation to drill certain Development Wells that were closely offset by third parties. The Trust agreed that in lieu of
drilling these closely offset Development Wells, ECA could 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 Ryder Scott Company, independent petroleum engineers. During the quarter ended
June 30, 2012, payment for an additional volume of 2,389 Mcf was delivered to the Trust, as compared to a payment for 2,582 Mcf for the quarter ended June 30, 2011. These additional
payments fulfill ECA's agreement to provide payment for the quarter for volumes for Development Wells that had been closely offset by third parties.

ECA
has fulfilled its obligation with respect to the drilling of the Development Wells. Since the inception of the Trust, ECA has drilled a total of 59 Development Wells, which are
online and producing. (See the Trust's Annual Report on Form 10-K for the year ended December 31, 2011, for a more complete description of the Development Wells.)

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

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.

Liquidation of the Trust

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

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

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

If
the Trustee has not sold the Royalty NPI on or prior to September 30, 2012, the Trustee is required to engage an independent appraiser (at the expense of the Trust) to appraise
the fair value of the NPI as of September 30, 2012, and to deliver a copy of such appraisal to ECA by November 15, 2012. ECA will then be entitled but not obligated to purchase the
Royalty NPI for cash at the appraised value (less the aggregate amount of distributions made to the Trust from the Royalty NPI since September 30, 2012) by delivery of a notice to the Trustee
given within ten business days from ECA's receipt of the appraiser's report. If ECA elects not to purchase the Royalty NPI, the Trustee is required to take all reasonable actions within its discretion
necessary to arrange for an unreserved auction or sealed bid sale (collectively, the "March 1, 2013 Sale") of the Royalty NPI to be held on March 1, 2013, and to sell the Royalty NPI to
the highest cash bidder at the auction or sale.

The
Trustee will mail notice of any March 1, 2013 Sale, if one occurs, to each Trust Unitholder at his or her address as it appears in the records of the Trustee at least
60 days prior to any such sale. However, no approval of the Trust Unitholders will be required or sought prior to any such sale of the Royalty NPI or any portion thereof as described herein. If
the Trustee sells the Royalty NPI prior to March 1, 2013, no notice of the sale will be mailed to Unitholders.

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

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

In
the event the Trustee gives notice of a proposed disposition of all or a portion of the Royalty NPI by auction or sealed bid at the March 1, 2013 Sale, the Trustee shall prior
to such auction or bid, unless the right of first refusal is waived by ECA, engage (at the expense of the Trust) an independent appraiser to appraise the fair value (as of the date of such notice) of
the portion of the Royalty NPI proposed to be sold. Upon receipt of the appraisal, ECA may exercise its option to acquire the portion of the Royalty NPI proposed to be sold for cash in the amount of
the appraised value (less the aggregate amount of distributions made to the Trust from that portion of the Royalty NPI since the
date of the appraised value) by delivery of a written election notice to the Trustee within ten business days from the date of receipt by ECA of the independent appraiser's report.

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

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

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.

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.

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.

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.

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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

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.

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 June 30, 2012. At June 30, 2012, the Trust had Trust General and Administrative Expenses Payable of $141,763 and
Distributions Payable of $797,457.

Comparison of Results of Operations for Three Months Ended June 30, 2012 and Three Months Ended June 30, 2011

The Trust's Distributable Income was $797,457 for the three months ended June 30, 2012 as compared to $1,586,758 for the three
months ended June 30, 2011. This decrease was due to a decrease in Royalty Income of $643,666 ($1,268,807 for the three months ended June 30, 2012 as compared to $1,912,473 for the three
months ended June 30, 2011). This decrease in Royalty Income was related to a decrease in the price payable to the Trust under the Gas Purchase Contract as discussed below ($3.190 per Mcf for
the three months ended June 30, 2012 as compared to $5.105 per Mcf for the three months ended June 30, 2011). Offsetting this decrease was an increase in production of gas attributable
to the Net Profits Interests for the three months ended June 30, 2012 (398 MMcf) as compared to the three months ended June 30, 2011 of (374 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 $96,881 for the three months ended June 30, 2012 as compared to $135,191 for the three months ended June 30, 2011. The decrease
in taxes is due directly to the decrease in Royalty Income as discussed above. General and Administrative Expenses were $224,595 for the three months ended June 30, 2012 as compared to $229,430
for the three months ended June 30, 2011. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees.

The
price payable to the Trust for gas production attributable to the Net Profits Interests was $3.190 per Mcf for the three months ended June 30, 2012 and $5.105 per Mcf for the
three months ended June 30, 2011. The price per Mcf was lower for the three months ended June 30, 2012 than for the corresponding three month period ended June 30, 2011 due to a
decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.600 per million British Thermal Units ("Dth") for the three months ended June 30, 2012 as
compared to $4.341 per Dth for the three months ended June 30, 2011).

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Financial
results depend on many factors, particularly the price of natural gas. During the second quarter of 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.

Comparison of Results of Operations for Six Months Ended June 30, 2012 and Six Months Ended June 30, 2011

The Trust's Distributable Income was $1,657,342 for the six months ended June 30, 2012 as compared to $2,639,372 for the six
months ended June 30, 2011. This decrease was due to a decrease in Royalty Income of $890,968 ($2,767,507 for the six months ended June 30, 2012 as compared to $3,658,475 for the six
months ended June 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 ($3.517 per Mcf for
the six months ended June 30, 2012 as compared to $4.976 per Mcf for the six months ended June 30, 2011). Offsetting this decrease was an increase in production of gas attributable to
the Net Profits Interests for the six months ended June 30, 2012 (789 MMcf) as compared to the six months ended June 30, 2011 (735 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 $207,977 for the six months ended June 30, 2012 as compared to $258,048 for the six months ended June 30, 2011. The decrease in taxes is
due directly to the decrease in Royalty Income as discussed above. General and Administrative Expenses were $602,434 for the six months ended June 30, 2012 as compared to $635,310 for the six
months ended June 30, 2011. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees.

The
price payable to the Trust for gas production attributable to the Net Profits Interests was $3.517 per Mcf for the six months ended June 30, 2012 and $4.976 per Mcf for the
six months ended June 30, 2011. The price per Mcf was lower for the six months ended June 30, 2012 than for the corresponding six month period ended June 30, 2011 due to a
decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.898 per Dth for the six months ended June 30, 2012 as compared to $4.224 per Dth for the
six months ended June 30, 2011).

Financial
results depend on many factors, particularly the price of natural gas. During the six months ended June 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 July 1, 2012 and May 15, 2013.

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 June 30, 2012, 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 $999.20 and $997.20, respectively. On June 30, 2012, the
closing price of the Treasury Obligations, as quoted on such market, was $998.70.

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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 June 30, 2012, this option had been exercised on 2,024,400 Trust Units. (See the Trust's Form 10-K
for the year ended December 31, 2011 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, 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 June 30, 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 may be deemed to include:



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Other
than reviewing the financial and other information provided to the Trust by ECA and the independent reserve engineer, the Trustee 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 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.

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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.

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

Description31.

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

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 TRUSTBy:

The Bank of New York Mellon Trust
Company, N.A., Trustee/s/ MIKE ULRICHName:

Mike UlrichTitle:

Vice PresidentThe Bank of New York Mellon
Trust Company, N.A.


Date:
August 8, 2012

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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