Exhibit 99.1

LOGO

January 26,
2011

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

Gentlemen:

Pursuant
to your request, we present below estimates of the net proved reserves attributable to the interests of the Eastern American Natural Gas Trust (Trust) as of December 31,
2010. The Trust is a grantor trust formed to hold interests in certain domestic oil and gas properties owned by Eastern American Energy Corporation (EAEC), a wholly owned subsidiary of Energy
Corporation of America (ECA). As of January 1, 2010 EAEC merged with and into ECA with ECA being the surviving entity and now ECA, by operation of law, is the owner of the underlying properties
burdened by the Net Profits Interest owned by the Trust. The interests conveyed to the Trust consist of a net profits interest derived from working and royalty interests in numerous properties. The
Net Profits Interest consists of (1) a life-of-properties interest ("Royalty NPI") and (2) a term interest ("Term NPI"). The properties included in the Trust are
located in the states of Pennsylvania and West Virginia.

The
properties evaluated by Ryder Scott represent 100 percent of the total net proved gas reserves of Eastern American Natural Gas Trust as of December 31, 2010.

The
estimated reserves and future net income amounts presented in this report, as of December 31, 2010 are related to hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic
averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements
as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income
actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below

As of December 31, 2010Proved Net Developed

Gas
(MMCF)

Estimated
Future Net
Cash Inflows
(M$)

Present
Value
At 10%
(M$)Royalty NPI


7,577


40,484


17,157Term NPI


1,571


8,395


7,502Total


9,148


48,879


24,659


Reserve
quantities are calculated differently for a Net Profits Interest because such interests do not entitle the Trust to a specific quantity of oil or gas but to 90 percent of
the Net Proceeds derived therefrom beginning on January 1, 2011 for natural gas. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves
attributable to the Net Profits Interest between

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the
interest held by the Trust and the interests to be retained by ECA. For purposes of this presentation, the proved reserves attributable to the Net Profits Interests have been proportionately
reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Interests. Accordingly, the reserves presented for the Net
Profits Interest reflect quantities of gas that are free of future costs or expenses based on the price and cost
assumptions utilized in this report. The allocation of proved reserves of the Net Profits Interest between the Trust and ECA will vary in the future as relative estimates of future gross revenues and
future net incomes vary. Furthermore, ECA requested that for purposes of our report the "Royalty NPI" be calculated beyond the Liquidation Date of May 15, 2013, even though by the terms of the
Trust Agreement the Royalty NPI will be sold by the Trustee on or about this date and a liquidating distribution of the sales proceeds from such sale would be made to holders of Trust Units. The Trust
Agreement provides that the "Term NPI" entitles the Trust to receive the net proceeds from the gas produced from the properties burdened by the "Term NPI" until the earlier of May 15, 2013 or
until such time as 41,683 MMCF of gas has been produced. For purposes of this report, the "Term NPI" was limited to May 15, 2013.

All
gas volumes are sales gas expressed in MMCF at the pressure and temperature bases of the area where the gas reserves are located. The estimated future net cash inflows are described
later in this report.

In
accordance with the requirements of FASB 69, estimates of future cash inflows, future costs and future net cash inflows before income tax, as well as estimated reserve
quantities, as of December 31, 2010 from this report are presented in the following table:

As of December 31, 2010Total Proved

Royalty
NPI

Term
NPI

TotalsFuture Cash Inflows (M$)


40,484


8,395


48,879Future CostsProduction (M$)


0


0


0Development (M$)


0


0


0Total Costs (M$)

$
0


0


0Future Net Cash InflowsBefore Income Tax (M$)


40,484


8,395


48,879Present Value at 10%Before Income Tax (M$)


17,157


7,502


24,659




As of December 31, 2010Proved Net Developed Reserves

Royalty
NPI

Term
NPI

TotalsGas (MMCF)


7,577


1,571


9,148Proved Net Undeveloped ReservesGas (MMCF)


0


0


0Total Proved Net ReservesGas (MMCF)


7,577


1,571


9,148


For
Net Profits Interest, the future cash inflows are, as described previously, after consideration of future costs or expenses based on the price and cost assumptions utilized in this
report. Therefore, the future cash inflows are the same as the future net cash inflows. The effects of depreciation, depletion and federal income taxes have not been taken into account in estimating
future net cash inflows.

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At
the request of ECA, we have included the following table which summarizes the total net reserves estimates from combined interest of ECA and the Trust in the Underlying Properties:

Estimated
Net Reserve Data
Certain Combined Leasehold Interests of
Energy Corporation of America
And The Trust
As of December 31, 2010
SEC Parameters

ProvedTotal
ProvedNet Remaining Reserves

Developed

UndevelopedGas-MMCF


27,234


0


27,234


The
estimated future net income associated with the foregoing volumes and the 10 percent discounted estimated future net income was $108,441,251 and $44,930,761, respectively.
This evaluation utilizes the same price and cost assumptions that were utilized for evaluating the Trust and discussed earlier in the letter. The properties which are included in the "Term NPI" were
allowed to run for their full economic life in this evaluation.

Reserves Included in This Report

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

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

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

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

Proved
oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for
proved reserves as a "high degree of confidence that the quantities will be recovered."

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

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

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

Our
reserve estimates are based upon a study of the properties in which the Trust has interests; however, we have not made any field examination of the properties. No consideration was
given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, in any, caused by past operating
practices.

At
the time of formation of the Trust, ECA assigned The Trust an interest in 65 undeveloped locations. During the period 1993 through 1998, ECA has completed it's drilling obligation. A
total of 59 wells were drilled over this period. Two wells were not drilled due to title failure and four wells were not drilled due to short spacing. Reserves and projections of future production are
included for the four locations which were not drilled due to short spacing.

Estimates of Reserves

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

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

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

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

The
proved reserves for the properties included herein are all proved producing and were estimated by performance methods. The performance method utilized was decline curve analysis
which utilized extrapolations of historical production data available through August, 2010. The data utilized in this analysis were furnished to Ryder Scott by ECA and were considered sufficient for
the purpose thereof.

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

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

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

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Future Production Rates

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

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

Hydrocarbon Prices

This report utilized the terms of the gas contract between Eastern Marketing Corporation (a wholly owned subsidiary of ECA) and the
Trust. Gas price is to be determined by a weighted price consisting of two components during a primary term defined to begin on January 1, 1993 and end December 31, 1999. The first
component is the "Fixed" price which has been defined as $2.66 per Mcf beginning January 1, 1993. This price escalates 5 percent per year on January 1 of each year during the
primary term beginning in 1994. The second component is the "Variable" price which for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu, plus $0.30 per MMBtu, multiplied
by 110 percent to effect a Btu adjustment. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter as the average price of the three months in
such quarter where each month's price is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in the Wall Street Journal,
for such contracts which expired in each of the five months prior to each month of such quarter, (ii) the final settlement
price per MMBtu for Henry Hub Gas Futures Contracts, as reported in theWall Street Journal, for such contracts which expire during such month and
(iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts for such month, as reported in theWall Street Journal, for such
contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on
the New York Mercantile Exchange. The weighted
average price is determined by giving the "Fixed" price a 662/3 percent weighting and the variable price a 331/3 percent weighting.

Since
the primary term is complete, the purchase price under the gas contract will be equal to the "Variable" price. ECA computed the "Variable" price under the gas contract as of
December 31, 2010 as $5.343 per Mcf, utilizing $4.557 as the Henry Hub Average Spot Price computed in accordance with the gas contract but utilizing the SEC guidelines that require the price to
be based on the 12-month period prior to the ending date of the period covered in this report.

Costs

Operating costs for the leases and wells in this report were supplied by ECA and include only costs defined as applicable under terms
of the Trust. The current operating costs were held constant throughout the life of the properties. This study does not consider the salvage value of the lease equipment or the abandonment cost.

No
deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments. No attempt
has been made to quantify or otherwise account for any accumulated gas production imbalances that may exist.

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Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout
the world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists
on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We
do not serve as officers or directors of any publicly traded oil and gas company and are separate and independent from the operating and
investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder
Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many
of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively
participating in ongoing continuing education.

Ryder
Scott requires that staff engineers and geoscientists have received professional accreditation, and are maintaining in good standing, a registered or certified professional
engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating
professional organization prior to becoming an officer of the Company.

We
are independent petroleum engineers with respect to Energy Corporation of America. Neither we nor any of any of our employees have any interest in the subject properties and neither
the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The
professional qualifications of the undersigned, the technical person primarily responsible for preparing the reserves information discussed in this report, are included as an
attachment to this letter.

Terms of Usage

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

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

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The
data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580GRAPHICLarry T. Nelms P. E. Managing Senior Vice PresidentGRAPHIC


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