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 September 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 November 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 Of the Outstanding Units, 2,277,950 Units of Beneficial Interest (the "Withdrawn Units") have been withdrawn from trading by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)

Nine Months Ended
September 30,

Three Months Ended
September 30,2012

2011

2012

2011Royalty Income

$
4,155,702

$
5,578,985

$
1,388,195

$
1,920,510Operating ExpensesTaxes on Production and Property


312,109


393,282


104,132


135,234Operating Cost Charges


449,667


450,695


149,889


143,022Total Operating Expenses


761,776


843,977


254,021


278,256Net Proceeds to the Trust


3,393,926


4,735,008


1,134,174


1,642,254General and Administrative Expenses


951,744


845,783


349,310


210,473Interest Income


44


20


21


20Cash Proceeds on Sale of Net Profit Interests





181,928





Distributable Income


2,442,226


4,071,173


784,885


1,431,801Distribution Amount


2,442,226


4,071,173


784,885


1,431,801Distributable Income Per Unit (5,900,000 units authorized and outstanding)

$
0.4139

$
0.6900

$
0.1330

$
0.2427Distribution Amount Per Unit (5,900,000 units authorized and outstanding)

$
0.4139

$
0.6900

$
0.1330

$
0.2427


2

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

September 30, 2012

December 31, 2011(Unaudited)Assets:Cash

$
335,002

$
122,740Net Proceeds Receivable


1,134,174


1,475,510Net Profits Interests in Gas Properties


93,162,180


93,162,180Accumulated Amortization


(85,554,207
)

(81,181,967
)7,607,973


11,980,213Total Assets

$
9,077,149

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

$
234,291

$
206,150Distributions Payable


784,885


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


8,057,973


12,430,213Total Liabilities and Trust Corpus

$
9,077,149

$
13,578,463


3

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

Nine Months
Ended
September 30, 2012

Nine Months
Ended
September 30, 2011Trust Corpus, Beginning of Period

$
12,430,213

$
14,505,979Distributable Income


2,442,226


4,071,173Distributions Payable to Unitholders


(2,442,226
)

(4,071,173
)Amortization and Impairment of Net Profits Interests in Gas Properties


(4,372,240
)

(1,739,961
)Trust Corpus, End of Period

$
8,057,973

$
12,766,018


4

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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). See Note 7Subsequent Events.

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 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.

5

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 1. Organization of the Trust (Continued)

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
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.

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

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 nine month periods ended September 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 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

7

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 4. Significant Accounting Policies (Continued)

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. See Note 5 for
discussion of the impairment in the Underlying Properties recognized during the three month period ended September 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. 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.

8

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS (Continued)

NOTE 6. 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.

9

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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, 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. 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 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 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 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.

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.

10

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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.

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. 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.

11

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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 inThe Wall Street Journal, for such contracts which expire during such month; and
(iii) the closing settlement price per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported inThe Wall
Street Journal, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to
be delivered to the Henry Hub 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.

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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
September 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 September 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. 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 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). 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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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. The highest bid submitted was the bid
submitted by Softvest, which subsequently entered into the Softvest Purchase Agreement with the Trust described above.

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

On
October 5, 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 Conveyance, and that if such a determination were made, the costs would be chargeable against future distributions to a future purchaser of
the Royalty NPI or to the Trust. During the approximately 20 years that the 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 Trust pursuant to either the Royalty NPI or the Term NPI. Although no final determination regarding the matter has been made, the Trustee was obligated to
advise EnergyNet and thus potential purchasers of the NPI of ECA's communication regarding the potential charges, and did so promptly.

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.

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

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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.

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. 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.

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

The
Net Profits Interest impairment test and the determination of amortization rates are dependent on estimates of proved gas reserves attributable to the Trust. Numerous uncertainties
are inherent in estimating reserve volumes and values, including economic and operating conditions, and such estimates are subject to change as additional information becomes available.

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.

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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 30, 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 30, 2012, the Trust had Trust General and Administrative Expenses Payable of $234,291 and Distributions Payable of $784,885.

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

The Trust's Distributable Income was $784,885 for the three months ended September 30, 2012 as compared to $1,431,801 for the
three months ended September 30, 2011.
This decrease was due to a decrease in Royalty Income of $532,315 ($1,388,195 for the three months ended September 30, 2012 as compared to $1,920,510 for the three months ended
September 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 ($3.427 per Mcf for the three
months ended September 30, 2012 as compared to $5.084 per Mcf for the three months ended September 30, 2011). Offsetting this decrease was an increase in production of gas attributable
to the Net Profits Interests for the three months ended September 30, 2012 (405 MMcf) as compared to the three months ended September 30, 2011 of (378 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 $104,132 for the three months ended September 30, 2012 as compared to $135,234 for the three 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 $349,310 for the three months ended September 30, 2012
as compared to $210,473 for the three 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 $3.427 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).

Financial
results depend on many factors, particularly the price of natural gas. During the third 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 Nine Months Ended September 30, 2012 and Nine Months Ended September 30, 2011

The Trust's Distributable Income was $2,442,226 for the nine months ended September 30, 2012 as compared to $4,071,173 for the
nine months ended September 30, 2011. This decrease was due to a

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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 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 $1,000.20 and $998.00, respectively. On September 30,
2012, the closing price of the Treasury Obligations, as quoted on such market, was $999.00.

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 30, 2012, this option had been exercised on 2,277,950 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.)

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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 September 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:



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.

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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.

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: November 9, 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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