<PAGE>

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

                                    FORM 1O-K

[X]    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
       EXCHANGE  ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
                                       OR

[ ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
       SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION
       PERIOD FROM ______________ TO _______________

                         Commission file number: 1-11748

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

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


                                Bank of New York
                             2 North Lasalle Street
                             Chicago, Illinois 60606
               (Address of principal executive office) (Zip Code)

                                 (312) 827-8560
              (Registrant's telephone number, including area code)

           Securities registered pursuant to Section 12(b) of the Act:

                                                        Name of Each Exchange
    Title of Each Class                                  On Which Registered
----------------------------                           -----------------------
Units of Beneficial Interest                           New York Stock Exchange

           Securities registered pursuant to Section 12(g) of the Act:

                                      None

    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 |X| No

    Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. |X|

    The aggregate market value of the 5,900,000 Units of Beneficial Interest in
Eastern American Natural Gas Trust held by non-affiliates of the registrant at
the closing sales price on March 15, 2001 of $16.85 was approximately $99
million.

    As of March 15, 2001, 5,900,000 Units of Beneficial Interest in Eastern
American Natural Gas Trust were outstanding.

    Documents Incorporated By Reference:     None

<PAGE>

                                TABLE OF CONTENTS

                                     PART I

<TABLE>
<S>   <C>                                                                                               <C>
Item  1. Business .......................................................................................1
         Description of the Trust .......................................................................1
         The Net Profits Interests ......................................................................2
         The Underlying Properties ......................................................................6
         Competition and Markets ........................................................................8
         Regulation of Natural Gas ......................................................................8
         Environmental Regulation ...................................................................... 8
         Description of Trust Units and Depositary Units ................................................9
         Federal Income Tax Matters ....................................................................11
         State Tax Considerations ......................................................................17
Item  2. Properties ....................................................................................18
Item  3. Legal Proceedings .............................................................................18
Item  4. Submission of Matters to a Vote of Unitholders ................................................18

                                     PART II

Item  5. Market for the Registrant's Common Equity
                  and Related Matters ................................................................. 19
Item  6. Selected Financial Data .......................................................................19
Item  7. Management's Discussion and Analysis of Financial
                  Condition and Results of Operations ..................................................20
Item  8. Financial Statements and Supplementary Data ...................................................22
Item  9. Changes in and Disagreements with Accountants on
                  Accounting and Financial Disclosure ..................................................22

                                    PART III

Item  10.Directors and Executive Officers of the Registrant ............................................23
Item  11.Executive Compensation ........................................................................23
Item  12.Security Ownership of Certain Beneficial Owners
                  and Management .......................................................................23
Item  13.Certain Relationships and Related Transactions ................................................23
Item  14.Exhibits, Financial Statement Schedules, and
                  Reports on Form 8-K. .................................................................23

 SIGNATURES.............................................................................................25
</TABLE>


<PAGE>


                                     PART I

ITEM 1.     BUSINESS

                            DESCRIPTION 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 ("Trustee"), and Wilmington
Trust Company, as Delaware Trustee (the "Delaware Trustee"). The Trust was
formed to acquire and hold net profits interests (the "Net Profits Interests")
created from the working interests owned by Eastern American in 650 producing
gas wells and 65 proved development well locations located in West Virginia and
Pennsylvania (the "Underlying Properties"). A portion of the production from the
wells burdened by the Net Profits Interests is eligible for credits ("Section 29
Credits") under the Internal Revenue Code of 1986 for production of gas from
Devonian shale or tight sand formations. The Net Profits Interests consist of a
royalty interest in 322 wells and a term interest in the remaining wells and
locations. Eastern American was obligated to drill and complete, at its expense,
65 development wells (the "Development Wells") on the development well locations
conveyed to the Trust. Eastern American has fulfilled its obligation with
respect to the drilling of the Development Wells. After May 15, 2012 and prior
to or on May 15, 2013 (the "Liquidation Date"), the Trustee is required to sell
the royalty interests and liquidate the Trust.

    On March 15, 1993, 5,900,000 Depositary Units were issued in a public
offering at an initial public offering price of $20.50 per Depositary Unit. Each
Depositary Unit consists of beneficial ownership of one unit of beneficial
interest ("Trust Unit") in the Trust and a $20 face amount beneficial ownership
interest in a $1,000 face amount zero coupon United States Treasury obligation
("Treasury Obligation") maturing on May 15, 2013. Of the net proceeds from such
offering, $27,787,820 was used to purchase $118,000,000 in face amount of
Treasury Obligations and $93,162,180 was retained by Eastern American 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.

    Effective May 8, 2000, The Bank of New York acquired the corporate trust
business of the Bank of Montreal Trust Company / Harris Trust. Consequently, the
Bank of New York serves as Trustee.

    The Net Profits Interests are passive in nature, and neither the Trustee nor
the Delaware Trustee has management control or authority over, nor any
responsibility relating to, the operation of the properties subject to the Net
Profits Interests. The Trust Agreement provides, among other things, that: the
Trust shall not engage in any business or commercial activity or acquire any
asset other than the Net Profits Interests initially conveyed to the Trust; the
Trustee may establish a reserve for payment of any liability which is
contingent, uncertain in amount or that is not currently due and payable; the
Trustee is authorized to borrow funds required to pay liabilities of the Trust,
provided that such borrowings are repaid in full prior to further distributions
to holders of Depositary Units ("Unitholders") and the Trustee will make
quarterly cash distributions to Unitholders from funds of the Trust. The
discussion of terms of the Trust Agreement contained herein is qualified in its
entirety by reference to the Trust Agreement itself, which is incorporated by
reference as an exhibit to this Form 10-K and is available upon request from the
Trustee.

    The Trust is responsible for paying all legal, accounting, engineering and
stock exchange fees, printing costs and other administrative expenses incurred
by or at the direction of the Trustee. The total fees paid to the Trustee for
2000 was $55,203. The total of all Trustee fees and Trust administrative
expenses for 2000 was $259,848, such cost could fluctuate in the future
depending primarily on the expenses the Trust incurs for professional services,
particularly legal, accounting and engineering services. In addition to such
expenses, in 2000, the Trust paid Eastern American an overhead reimbursement of
$267,180, which will increase by 3.5% per year, payable quarterly.

    The following descriptions of the Net Profits Interests, and the calculation
of amounts payable to the Trust in respect thereof, are subject to and qualified
by the more detailed provisions of the Conveyances, as defined below,
incorporated by reference as exhibits to this Form 10-K and available upon
request from the Trustee. The information contained herein relating to the
operations of the Underlying Properties, as well as information upon which the
reserve figures and financial information contained herein were derived, was
furnished to the Trustee by Eastern American.

THE NET PROFITS INTERESTS

                                        1

<PAGE>

THE CONVEYANCES

    The Net Profits Interests were conveyed to the Trust pursuant to two
conveyances - one conveying the Royalty NPI (the "Royalty NPI Conveyance") and
the other conveying the Term NPI (the "Term NPI Conveyance", and together with
the Royalty NPI Conveyance, the "Conveyances"). In limited circumstances,
Eastern American may transfer the Underlying Properties and require the Trust to
release the Net Profits Interests, subject to payment to the Trust of the fair
value of the interests released. See "Sale and Abandonment of Underlying
Properties; Sale of Royalty NPI."

    The Underlying Properties are subject to and burdened by the Net Profits
Interests. The interests of Eastern American comprising the Underlying
Properties represent, on average, a working interest of approximately 90% and a
net revenue interest of approximately 76%. The Conveyances provide that the
Trust is only entitled to gas produced from the specific wells identified in the
Conveyances and is not entitled to any gas produced from adjacent wells
(including adjacent wells subject to the same lease or farmout agreement as the
wells subject to the Net Profits Interests). Gas produced from the Underlying
Properties which is attributable to the Net Profits Interests is purchased from
the Trust by Eastern Marketing Corporation, a wholly-owned subsidiary of Eastern
American ("Eastern Marketing") pursuant to a gas purchase contract (the "Gas
Purchase Contract"). The volumes attributable to the Net Profits Interests and
the purchase price for such gas is calculated for each calendar quarter, and
payment for such gas is made to the Trust not later than the 10th day of the
third calendar month following the end of each calendar quarter.

    The Royalty NPI is not limited in term. Under the Trust Agreement, the
Trustee is directed to sell the Royalty NPI after May 15, 2012 and prior to May
15, 2013, and net proceeds from such sale will be distributed to Unitholders on
the first quarterly payment date following the receipt of such proceeds by the
Trust. The Term NPI will expire on the earlier of May 15, 2013 or such time as
41,683 MMcf of gas has been produced which is attributable to Eastern American's
net revenue interests in the properties burdened by the Term NPI. As of December
31, 2000, 15,574 MMcf of such gas had been produced.

    The definitions, formulas, accounting procedures and other terms governing
the computation of Net Proceeds are detailed and extensive, and reference is
made to both the Royalty NPI Conveyance and the Term NPI Conveyance for a more
detailed discussion of the computation thereof. Forms of the Conveyances have
been incorporated by reference as exhibits to this report.

    Eastern American may sell the Underlying Properties, subject to and burdened
by the Net Profits Interests, without the consent of the Trust or the
Unitholders. Eastern American may also require the Trust to release Net Profits
Interests from the Trust's ownership thereof, without the consent of the Trust
or the Unitholders, under certain circumstances. In addition, any abandonment of
a well included in the Underlying Properties or the Development Wells will
extinguish that portion of the Net Profits Interests that relate to such well.

CALCULATION OF NET PROCEEDS

    The Conveyances and the Gas Purchase Contract entitle the Trust to receive
an amount of cash for each calendar quarter equal to the Net Proceeds for such
quarter. "Net Proceeds" for any calendar quarter generally means an amount of
cash equal to (a) 90% of a volume of gas equal to (i) the volume of gas produced
during such quarter attributable to the Underlying Properties less (ii) a volume
of gas equal to Chargeable Costs, as defined below, for such quarter, multiplied
by (b) the applicable price for such quarter under the Gas Purchase Contract.
If, for any reason, the Gas Purchase Contract terminates prior to the
Liquidation Date, "Net Proceeds" will mean an amount of cash equal to (a) 90% of
a volume of gas equal to (i) the volume of gas produced during such quarter
attributable to the Underlying Properties less (ii) a volume of gas equal to
Chargeable Costs for such quarter, multiplied by (b) the applicable price for
such quarter determined in accordance with the Conveyances. Pursuant to the
Conveyances, the Trust will not be entitled to receive any natural gas liquids
produced from the Underlying Properties or any proceeds relating thereto.

    "Chargeable Costs" is that volume of gas which equates in value, determined
by reference to the relevant sales price under the Gas Purchase Contract or the
Conveyances, as applicable, to the sum of the "Operating Cost Charge", "Capital
Costs" and "Taxes". The Operating Cost Charge for 2000 was $488,672, for 1999
was $493,102, and for 1998 was $474,183. In 2001 and subsequent years, the
Operating Cost Charge will escalate based on increases in the index of

                                        2

<PAGE>

average weekly earnings of Crude Petroleum and Gas Production Workers (published
by the United States Department of Labor, Bureau of Labor Statistics), but not
more than 5% per year. The Operating Cost Charge will be reduced for each well
that is sold (free of the Net Profits Interests) or plugged and abandoned.
Capital Costs are defined as Eastern American'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 Eastern American's or the Trust's interests in
the Underlying Properties, or production therefrom.

    Although the Trust indirectly bears a share of Chargeable Costs in the
calculation of Net Proceeds, the Trust is not directly liable for any share of
the costs, risks, and liabilities associated with the ownership or operation of
the Underlying Properties. If the Trust ever receives payments in excess of the
Net Proceeds or other amounts it was not entitled to receive, the Trust will not
be required to refund the money, but Eastern American may recover the amount of
such overpayments in accordance with the Conveyances.

    The Conveyances require Eastern American to maintain books, records, and
accounts sufficient to calculate the volumes of gas and the share of Net
Proceeds payable to the Trust. Eastern American provides to the Trust quarterly
and annual statements of applicable production, revenues, and costs necessary
for the Trust to prepare quarterly and annual financial statements with respect
to the Net Profits Interests and the Underlying Properties. The financial
statements of the Trust are audited annually at the Trust's expense.

GAS PURCHASE CONTRACT

    Gas production attributable to the Net Profits Interests is purchased from
the Trust by Eastern Marketing, a wholly owned subsidiary of Eastern American,
pursuant to the Gas Purchase Contract which effectively commenced as of January
1, 1993 and expires upon the termination of the Trust.

    Pursuant to the Gas Purchase Contract, through December 31, 1999 (the
"Primary Term"), Eastern Marketing was obligated to purchase such gas production
at a purchase price per Mcf equal to the greater of the Index Price, as defined
below, or the Floor Price, as defined below. During 1999, the Floor Price was
$3.09. Effective January 1, 2000, 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 subsequent to the Primary Term, which
expired December 31, 1999, is determined solely by reference to the Variable
Price component, as defined below. Prior to December 31, 1999, the Index Price
for any quarter was a weighted average price determined by reference to the
Fixed Price component, which was given a 66 2/3% weighting and a Variable Price
component, which was given a 33 1/3% weighting during the Primary Term. The
Fixed Price, which escalated 5% per year during the Primary Term, was equal to
$3.39 per Mcf for calendar year 1998 and $3.56 per Mcf for 1999. The Variable
Price for any quarter is equal to the Henry Hub Average Spot Price (as defined)
per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment
for Btu content. The Henry Hub Average Spot Price is defined as the price per
MMBtu determined for any calendar quarter equal to the price obtained with
respect to each of the three months in such quarter, in the manner specified
below, and then taking the average of the prices determined for each of such
three months. The price determined for any month of such quarter is equal to the
average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures
Contracts (as defined), as reported in THE WALL STREET JOURNAL, for such
contracts which expired in each of the five months prior to such month, (ii) the
final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as
reported in THE WALL STREET JOURNAL, for such contracts which expire during such
month and (iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures
Contracts determined as of the contract settlement date for such month, as
reported in THE WALL STREET JOURNAL, for such contracts which expire in each of
the six months following such month. A Henry Hub Gas Futures Contract is defined
as a gas futures contract for gas to be delivered to the Henry Hub which is
traded on the New York Mercantile Exchange.

     The purchase price paid to the Trust pursuant to the Gas Purchase Contract
is a wellhead price and title to the gas purchased pursuant to the Gas Purchase
Contract passes to Eastern Marketing at the point of delivery. Payments to the
Trust for gas purchased pursuant to the Gas Purchase Contract are made by
Eastern Marketing on or before the tenth day of the third calendar month
following the end of each calendar quarter.

                                        3

<PAGE>


    The Trust Agreement provides that the Trustee may not agree to any amendment
to the Gas Purchase Contract which would materially and adversely affect the
revenues to the Trust without the approval of the holders of a majority of the
outstanding Trust Units. The Trust Agreement also provides that the Gas Purchase
Contract may not be terminated by the Trust without the approval of the holders
of a majority of the outstanding Trust Units. The Gas Purchase Contract and the
Trust Agreement have been filed as exhibits to this Form 10-K. The foregoing
summary of the principal provisions of the Gas Purchase Contract, and certain
provisions of the Trust Agreement, is qualified in its entirety by reference to
the terms of such agreements as set forth in such exhibits.

    Eastern Marketing's rights and obligations under the Gas Purchase Contract
are assignable under circumstances where the assignee unconditionally assumes
Eastern Marketing's obligations under the Gas Purchase Contract, and then, only
if such assignee (or assignee's parent corporation if such parent guarantees the
assignee's obligations) has a rating assigned to its unsecured long-term debt by
Moody's Investor Service of at least Baa+ and by Standard & Poor's Corporation
of at least BBB-. Under such circumstances, Eastern Marketing and Eastern
American would be released from their obligations under the Gas Purchase
Contract.

PERFORMANCE SUPPORT FOR GAS PURCHASE CONTRACT

    Gas production attributable to the Net Profits Interests will be purchased
by Eastern Marketing pursuant to the Gas Purchase Contract, which expires upon
the liquidation date of the Trust. Eastern American has agreed to make payment
under a standby performance agreement to the extent such payments are not made
by Eastern Marketing under the Gas Purchase Contract.

DISTRIBUTIONS AND INCOME COMPUTATIONS

     The Trustee determines for each quarter the amount of cash available for
distribution to holders of Depositary Units and the Trust Units evidenced
thereby. Such amount (the "Quarterly Distribution Amount") is equal to the
excess, if any, of the cash received by the Trust, on or before the 10th day of
the third month following the end of each calendar quarter ending prior to the
dissolution of the Trust, from the Net Profits Interests then held by the Trust
attributable to production during such quarter, plus, with certain exceptions,
any other cash receipts of the Trust during such quarter, over the liabilities
of the Trust paid during such quarter, subject to adjustments for changes made
by the Trustee during such quarter in any cash reserves established for the
payment of contingent or future obligations of the Trust. Quarterly Distribution
Amounts for each of the quarters in 2000 were $0.30, $0.37, $0.45, and $0.54
respectively. Based on the payment procedures relating to the Net Profits
Interests, cash received by the Trustee in a particular quarter from the Net
Profits Interests reflects actual gas production for a portion of such quarter
and a production estimate for the remainder of such quarter, such estimate to be
adjusted to actual production in the following quarter. The Quarterly
Distribution Amount for each quarter is payable to Unitholders of record on the
last day of the second month following the end of such calendar quarter or such
later date as the Trustee determines is required to comply with legal or stock
exchange requirements ("Quarterly Record Date"). It is expected that the Trustee
will continue to be able to distribute cash on or before the 15th day (or the
next succeeding business day following such day if such day is not a business
day) of the third month following the end of each calendar quarter to each
person who was a Unitholder of record on the Quarterly Record Date, together
with interest earned on such Quarterly Distribution Amount from the date of
receipt thereof by the Trustee to the payment date.

    The net taxable income of the Trust for each calendar quarter is reported by
the Trustee for tax purposes as belonging to the holders of record to whom the
Quarterly Distribution Amount was or will be distributed. Assuming that the
Trust will be classified for tax purposes as a "grantor trust," the net taxable
income will be realized by the holders for tax purposes in the calendar quarter
received by the Trustee, rather than in the quarter distributed by the Trustee.
Taxable income of a holder will differ from the Quarterly Distribution Amount
because the Treasury Obligations will be treated as generating interest income
for tax purposes. There may also be minor variances because of the possibility
that, for example, a reserve will be established in one quarter that will not
give rise to a tax deduction until a subsequent quarter, an expenditure paid for
in one quarter will have to be amortized for tax purposes over several quarters,
etc. See "Federal Income Tax Consequences."

    Each holder of Depositary Units (including the underlying Trust Units) of
record as of the record date for the final

                                        4

<PAGE>


quarter of the Trust's existence will be entitled to receive a liquidating
distribution 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.

SALE AND ABANDONMENT OF UNDERLYING PROPERTIES; SALE OF ROYALTY NPI

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

    Eastern American has the right, pursuant to the Conveyances, to sell all or
any portion of the Underlying Properties without restrictions; however, the
purchaser of any of the Underlying Properties will acquire such Underlying
Properties subject to the Net Profits Interests relating thereto (except in
certain circumstances described below where the Trust may be required to release
the Net Profits Interests, subject to its receipt of the fair value thereof).
Any such purchaser will be subject to the same standards of conduct with respect
to development, operation and abandonment of such Underlying Properties as set
forth in the preceding paragraph.

    Eastern American may sell the Underlying Properties, subject to and burdened
by the Net Profits Interests, without the consent of the Trust or the
Unitholders. In addition, prior to January 1, 2003, Eastern American may,
without the consent of the Trust or the Unitholders, require the Trust to
release Net Profits Interests associated with any well which accounts for 0.25%
or less of the total production from the Underlying Properties in the prior 12
months, provided that such releases cannot exceed five wells during any 12-month
period. In addition, until January 1, 2010, such releases cannot exceed an
aggregate value to the Trust of $500,000 during any 12-month period. Sales
subsequent to that time may be made without regard to dollar limitations. These
releases will be made only in connection with a sale by Eastern American of the
Underlying Properties and are conditioned upon the Trust receiving an amount
equal to the fair value to the Trust of such Net Profits Interests (taking into
account the existence of the Gas Purchase Contract with respect to the gas
attributable to the Net Profits Interests to be released). Any proceeds paid to
the Trust are distributable to Unitholders for the quarter in which they are
received.

    The Trustee is required to sell all of the Royalty NPI after May 15, 2012
and prior to the Liquidation Date. The proceeds of such sale, together with the
matured face amount of the Treasury Obligations, will be distributed to
Unitholders on or prior to the Liquidation Date. Under the Trust Agreement,
Eastern American has a right of first refusal to purchase any of the Royalty NPI
at the fair value to the Trust, or if applicable the offered third-party price,
prior to the Liquidation Date.

                            THE UNDERLYING PROPERTIES

GENERAL

    The Underlying Properties are comprised of Eastern American's working
interests in certain properties located in the Appalachian Basin states of West
Virginia and Pennsylvania. As of December 31, 2000, such properties consisted of
681 producing gas wells. The working interests of Eastern American comprising
the Underlying Properties are held

                                        5

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under leases and farmout agreements with third parties. Such working interests
are subject to landowner's royalties (typically 12-1/2%) and may be subject to
additional royalties or other obligations burdening the working interests. Such
royalties do not bear lease operating expenses, but reduce the revenue interests
attributable to the Underlying Properties. Eastern American's interests
comprising the Underlying Properties represent, on average, a working interest
of approximately 90% and a net revenue interest of approximately 76%. As of
December 31, 2000, proved developed reserves attributable to the Net Profits
Interests (reflecting quantities of gas free of future costs and expenses based
on estimated prices) were approximately 26,467 MMcf. (See "Reserves").

     The Appalachian Basin is a mature producing region with well known geologic
characteristics. Substantially all of the wells comprising the Underlying
Properties are relatively shallow, ranging from 2,500 to 5,500 feet, and many
are completed to multiple producing zones. In general, the wells to which the
Underlying Properties relate are proved producing properties with stable
production profiles and generally long-lived production, often with total
projected economic lives in excess of 25 years. Once drilled and completed,
ongoing operating and maintenance requirements are low and only minimal, if any,
capital expenditures are typically required.

    The Underlying Properties initially included 65 specified development well
locations for the drilling of the Development Wells by Eastern American. Eastern
American has fulfilled its obligation with respect to the drilling of the
Development Wells. Eastern American was obligated to bear the costs of drilling
and completing the Development Wells.

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

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

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

                                        6

<PAGE>


RESERVES

    PROVED RESERVES OF UNDERLYING PROPERTIES AND NET PROFITS INTERESTS. The
following table sets forth, as of December 31, 2000, certain estimated proved
reserves, estimated future net revenues and the discounted present value thereof
attributable to the Underlying Properties, the Royalty NPI and the Term NPI, in
each case derived from a report of oil and gas reserves attributable to the
Trust as of December 31, 2000 prepared by Ryder Scott Company (the "Reserve
Report"). Proved reserve quantities attributable to the Net Profits Interests
are calculated by subtracting an amount of gas sufficient, if sold at the prices
used in preparing the reserve estimates, to pay the future estimated costs and
expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves
attributable to the Net Profits Interests reflect quantities of gas that are
free of future costs or expenses if the price and cost assumptions set forth in
the Reserve Report occur. A decrease in the price assumption, or an increase in
the cost assumption used in the Reserve Report would reduce the estimates of
proved reserves, future net revenues and discounted future net revenues, set
forth herein and in the Reserve Report. The Term NPI excludes production beyond
the earlier of May 15, 2013 or such time as 41,683 MMcf of gas has been produced
which is attributable to Eastern American's net revenue interests in the
properties burdened by the Term NPI. The discounted present value of estimated
future net revenues was determined using a discount rate of 10%. A copy of the
Reserve Report is included as Exhibit A hereto.

<TABLE>
<CAPTION>
                                                 Proved Gas Reserves

                                       ----------------------------------------                        Discounted
                                                          (MMcf)                   Estimated           Estimated
                                                                                   Future Net          Future Net
                                          Developed     Undeveloped    Total       Revenues(2)         Revenues(2)
                                       --------------   ------------  ------      -----------         -----------

                                                                                        (Dollars
in thousands)

<S>                                        <C>              <C>       <C>            <C>              <C>
Underlying Properties(1).................. 47,434           0         47,434         $217,839         $89,757
                                           ======         ====        ======         ========         =======

Net Profits Interests:
         Royalty NPI...................... 14,983           0         14,983         $83,216          $35,074
         Term NPI......................... 11,484           0         11,484          63,779           39,646
                                           ------         ----        ------         -------          -------

              Total .....................  26,467           0         26,467         $146,995         $74,720
                                           ======         ====        ======         ========         =======
</TABLE>
------------------------

(1)     Reserve volumes and estimated future net revenues for Underlying
        Properties reflect volumes and revenues distributable to Eastern
        American's entire net revenue interest with respect to the Underlying
        Properties.

(2)     The effects of depreciation, depletion and federal income tax, including
        Section 29 Credits, have not been taken into account in estimating
        future net revenues. Estimated future net revenues and discounted
        estimated future net revenues are not intended, and should not be
        interpreted, as representing the fair market value for the estimated
        reserves.

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

                                        7

<PAGE>


DEFINITIONS

    As used herein, the following terms have the meanings indicated: "Mcf" means
thousand cubic feet of gas, "MMcf" means million cubic feet of gas, "Bbl" means
barrel (approximately 42 U.S. gallons), and "MBbl" means thousand barrels, "Btu"
means British thermal units and MMBtu" means million British thermal units .

                             COMPETITION AND MARKETS

    All of the production attributable to the Net Profits Interest is sold to
Eastern Marketing pursuant to the Gas Purchase Contract. See "The Net Profits
Interests - Gas Purchase Contract."

                            REGULATION OF NATURAL GAS

     The natural gas industry had historically been highly regulated by state
and federal authorities. Concerns about perceived pipeline monopolies and other
factors caused Congress to impose economic regulation on both pipelines and
producers. Federal agencies regulated tariffs and conditions of service offered
by interstate pipelines, and set maximum prices on the wellhead price of natural
gas sold into interstate commerce. States, and even local governments, also
regulated retail sales of natural gas by local utilities. Government agencies
also set production rates to avoid waste and imposed environmental and safety
regulations. At present, it appears that Federal regulation of wellhead natural
gas prices has ended. However there can be no assurance that price controls or
other similar economic regulations may not be reimposed in the future.

    Drilling and production of natural gas are heavily regulated in Pennsylvania
and West Virginia, as in most states. A well cannot be drilled without a permit,
and operations must be conducted in compliance with environmental, safety and
conservation laws and regulations. In contrast to many other states which have
substantial oil and gas production activity, the spacing of shallow wells (such
as the wells subject to the Net Profits Interests) is not regulated by any state
statute or regulatory agency in either West Virginia or Pennsylvania. Without
spacing requirements specified by state statute or regulation, drainage of
reserves from a property may occur from wells located in close proximity to such
property.

                            ENVIRONMENTAL REGULATION

    GENERAL. Activities on the Underlying Properties are subject to existing
Federal, state and local laws and regulations governing health, safety,
environmental quality and pollution control. It is anticipated that, absent the
occurrence of an extraordinary event, compliance with existing Federal, state
and local laws, rules and regulations regulating health, safety, the discharge
of materials into the environment or otherwise relating to the protection of the
environment will not have a material adverse effect upon the Trust. It cannot be
predicted what effect additional regulation or legislation, enforcement policies
thereunder, and claims for damages to property, employees, other persons and the
environment resulting from operations on the Underlying Properties could have on
the Trust. However, pursuant to the terms of the Conveyances, any costs or
expenses incurred in connection with environmental liabilities of Eastern
American arising out of or related to activities occurring on or in, or
conditions existing on or under, the Underlying Properties before the effective
date of the Conveyances will be borne by Eastern American and will not be
deducted in calculating Net Proceeds attributable to the Net Profits Interests.
Additionally, because Unitholders will have limited liability in accordance with
the Trust Agreement and Delaware law, Unitholders should be shielded from direct
liability for any environmental liabilities. See "Description of Trust Units and
Depositary Units--Liability of Unitholders." However, costs and expenses
incurred by Eastern American for certain Capital Costs associated with
environmental liabilities arising after the effective date of the Conveyances
would reduce Net Proceeds, and would therefore be borne, in part, by the
Unitholders.

                                        8

<PAGE>


    SOLID AND HAZARDOUS WASTE. The Underlying Properties include numerous
properties that have produced gas for a number of years but in which Eastern
American has held an interest for a relatively short period of time prior to the
effective date of the Conveyances. Although, to Eastern American's knowledge,
prior operators utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other solid or hazardous wastes may
have been disposed of or released on or under the Underlying Properties.
Federal, state and local laws applicable to gas-related wastes have become
increasingly more stringent. Under current laws, Eastern American or the
operator of the Underlying Properties could be required to remove or remediate
previously disposed wastes or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination.

    The operations of the Underlying Properties may generate wastes that are
subject to the Federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The Environmental Protection Agency (the "EPA") has
limited the disposal options for certain hazardous wastes and may adopt more
stringent disposal standards for nonhazardous wastes.

    SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability,
regardless of fault or the legality of the original conduct, on certain classes
of persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator of
a site and companies that disposed or arranged for the disposal of, the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in some
cases, private parties to take actions in response to threats to the public
health or the environment and to seek recovery from such responsible classes of
persons of the costs of such action. In the course of their operations, the
operators of the Underlying Properties have generated and will generate wastes
that may fall within CERCLA's definition of "hazardous substances". Eastern
American or the previous operator of the Underlying Properties may be
responsible under CERCLA for all or part of the costs to clean up sites at which
such substances have been disposed.

    AIR EMISSIONS. The operations of the Underlying Properties are subject to
Federal, state and local regulations concerning the control of emissions from
sources of air contaminants. Administrative enforcement actions for failure to
comply strictly with air regulations or permits are generally resolved by
payment of a monetary penalty and correction of any identified deficiencies.
Regulatory agencies could require the operators to forego or modify construction
or operation of certain air emission sources.

    OSHA. The operations of the Underlying Properties are subject to the
requirements of the Federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act and similar state statutes require that
information be organized and maintained about hazardous materials used or
produced in the operations. Certain of this information must be provided to
employees, state and local government authorities and citizens.

                 DESCRIPTION OF TRUST UNITS AND DEPOSITARY UNITS

    The following information is subject to the detailed provisions of the
Deposit Agreement entered into by Eastern American, the Trustee, and Bank of
Montreal Trust Company, or the Bank of New York subsequent to May 8, 2000, as
Depositary (the "Depositary") and all holders from time to time of Depositary
Units (the "Deposit Agreement"), which is incorporated by reference as an
exhibit to this Form 10-K and is available upon request.

    The functions of the Depositary under the Deposit Agreement are custodial
and ministerial in nature and for the benefit of Unitholders. The Deposit
Agreement and the issuance of Depositary Units thereunder provide Unitholders an
administratively convenient form of holding an investment in the Trust and a
Treasury Obligation. Each Depositary Unit is evidenced by a certificate, which
is issued by the Depositary and transferable only in denominations of 50
Depositary Units or an integral multiple thereof. Accordingly, each holder of 50
Depositary Units will own a beneficial interest in 50 Trust Units and the entire
beneficial interest in a discrete Treasury Obligation in a face amount of
$1,000, or $20 per Depositary Unit.

    The deposited Trust Units and Treasury Obligations are held solely for the
benefit of the Unitholders and do not



                                        9

<PAGE>


constitute assets of the Depositary or the Trust. The Depositary has no power to
assign, transfer, pledge or otherwise dispose of any of the Trust Units or
Treasury Obligations, except in the limited instances provided in the Deposit
Agreement.

    Generally, the holders of Depositary Units are entitled to participate in
distributions with respect to the Trust Units, the Treasury Obligations and to
the liquidation of the remaining assets of the Trust.

WITHDRAWAL OF TRUST UNITS AND RESTRICTIONS ON TRANSFER

    Upon presentation of Depositary Units in denominations of 50 or integral
multiples thereof for withdrawal of the Trust Units and discrete Treasury
Obligations evidenced thereby in accordance with the Deposit Agreement, the
Unitholder will receive an uncertificated direct interest in Trust Units. These
withdrawn Trust Units will be evidenced on the books of the Trustee by a
transfer of such Trust Units from the name of the Depositary to the name of the
withdrawing Unitholder. Holders of withdrawn Trust Units will be entitled to
receive Trust distributions and periodic Trust information (including tax
information) directly from the Trustee. Moreover, holders of Trust Units will be
entitled to each of the rights accorded Unitholders under the Trust Agreement,
including voting rights, as elsewhere described herein, except that withdrawn
Trust Units are not freely transferable as described below.

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

DISTRIBUTIONS AND INCOME COMPUTATIONS

    The Trustee determines for each quarter the Quarterly Distribution Amount
available for distribution to holders of Depositary Units and the Trust Units
evidenced thereby. The Quarterly Distribution Amount is equal to the excess, if
any, of the cash received by the Trust, on or before the 15th day of the third
month following the end of each calendar quarter ending prior to the dissolution
of the Trust, from the Net Profits Interests then held by the Trust attributable
to production during such quarter, plus, with certain exceptions, any other cash
receipts of the Trust during such quarter, over the liabilities for the Trust
paid during such quarter, subject to adjustments for changes made by the Trustee
during such quarter in any cash reserves established for the payment of
contingent or future obligations of the Trust. Based on the payment procedures
relating to the Net Profits Interests, cash received by the Trustee in a
particular quarter from the Net Profits Interests reflects actual gas production
for a portion of such quarter and a production estimate for the remainder of
such quarter, such estimate to be adjusted to actual production in the following
quarter. The Quarterly Distribution Amount for each quarter is payable to
Unitholders of record on the Quarterly Record Date, which is the last day of the
second month following the end of such calendar quarter or such later date as
the Trustee determines is required to comply with legal or stock exchange
requirements. The Trustee generally is able to distribute cash on or before the
15th day (or the next succeeding business day following such day if such day is
not a business day) of the third month following the end of each calendar
quarter to each person who was a Unitholder of record on the Quarterly Record
Date, together with interest earned on such Quarterly Distribution Amount from
the date of receipt thereof by the Trustee to the payment date.

    The net taxable income of the Trust for each calendar quarter is reported by
the Trustee for tax purposes as belonging to the holders of record to whom the
Quarterly Distribution Amount was or will be distributed. Assuming that the
Trust will be classified for tax purposes as a "grantor trust," the net taxable
income will be realized by the holders for tax purposes in the calendar quarter
received by the Trustee, rather than in the quarter distributed by the Trustee.
Taxable income of a holder may differ from the Quarterly Distribution Amount
because the Treasury Obligations will be treated as generating interest income
for tax purposes. There may also be minor variances because of the possibility
that, for example, a reserve will be established in one quarter that will not
give rise to a tax deduction until a subsequent quarter, an expenditure paid for
in one quarter will have to be amortized for tax purposes over several quarters.
See "Federal Income Tax Consequences".

                                       10

<PAGE>



    Each holder of Depositary Units (including the underlying Trust Units) of
record as of the record date for the final quarter of the Trust's existence will
be entitled to receive a liquidating distribution 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.

POSSIBLE DIVESTITURE OF DEPOSITARY UNITS AND TRUST UNITS

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

LIABILITY OF UNITHOLDERS

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

LIQUIDATION OF THE TRUST

    The Trust will be liquidated and the Royalty NPI will be sold prior to the
Liquidation Date. 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. Under the Trust Agreement, Eastern American 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.

                           FEDERAL INCOME TAX MATTERS

    This section is a summary of Federal income tax matters of general
application which addresses the material tax consequences of the ownership and
sale of Depositary Units. Except where indicated, the discussion below describes
general Federal income tax considerations applicable to individuals who are
citizens or residents of the United States. Accordingly, the following
discussion has only limited application to domestic corporations and persons
subject to specialized Federal income tax treatment, such as tax-exempt entities
(including IRAs), regulated investment companies and insurance companies. The
following discussion does not address tax consequences to foreign persons. It is
impractical to comment on all aspects of Federal laws that may affect the tax
consequences of the transactions contemplated hereby and of an investment in
Depositary Units as they relate to the particular circumstances of every
prospective Unitholder. EACH UNITHOLDER SHOULD CONSULT HIS OWN TAX ADVISOR WITH
RESPECT TO HIS PARTICULAR CIRCUMSTANCES INCLUDING, PARTICULARLY, HIS ALTERNATIVE
MINIMUM TAX CIRCUMSTANCES.

                                       11

<PAGE>


    This summary is based on current provisions of the Internal Revenue Code of
1986, as amended (the "Code"), existing and proposed regulations thereunder and
current administrative rulings and court decisions, all of which are subject to
changes that may or may not be retroactively applied. Some of the applicable
provisions of the Code have not been interpreted by the courts or the Internal
Revenue Service ("IRS").

    At the issuance of the Depositary Units, the Trust obtained an opinion of
counsel, based on certain representations and subject to certain qualifications,
that, for Federal income tax purposes, (a) the Trust will be taxed as a grantor
trust and not as an association taxable as a corporation, (b) the Term NPI will
be taxed as a production payment, (c) the income from the Royalty NPI will be
royalty income subject to the allowance for depletion, and (d) a Unitholder will
be eligible to claim Section 29 Credits with respect to certain sales of gas
production attributable to the Royalty NPI. The Trustee has reported the
operations of the Trust consistent with these opinions.

    No ruling has been or will be requested from the IRS with respect to any
matter affecting the Trust or Unitholders, and thus no assurance can be provided
that the statements set forth herein (which do not bind the IRS or the courts)
will not be challenged by the IRS or will be sustained by a court if so
challenged.

    On March 23, 1999, the United States Tax Court of Appeals for the Tenth
Circuit affirmed a lower court decision in TRUE OIL COMPANY V C.I.R. 170 F.3D
1294. The Court ruled that, in order to be eligible for credits under Section 29
of the Internal Revenue Code, each well from which gas is produced from Devonian
shale or a tight formation must receive a determination from the Federal Energy
Regulatory Commission ("FERC") that the gas produced is, in fact, produced from
Devonian shale or a tight formation. Eastern American has verified that most
producing gas wells subject to the Royalty NPI have received a well category
determination from FERC. Should that determination be challenged by the Internal
Revenue Service, Section 29 Credits attributable to any well that did not
receive a FERC determination could impact the Trust's tax reporting of such
credits in future years. SEE "SECTION 29 CREDIT."

TREATMENT OF DEPOSITARY UNITS

    A purchaser of a Depositary Unit will be treated, for Federal income tax
purposes, as purchasing directly an interest in the Treasury Obligations and a
Trust Unit. A purchaser will therefore be required to allocate the purchase
price of his Depositary Unit between the interest in the Treasury Obligations
and the Trust Unit in the proportion that the fair market value of each bears to
the fair market value of the Depositary Unit. Information regarding purchase
price allocations will be furnished to Unitholders by the Trustee.

CLASSIFICATION AND TAXATION OF THE TRUST

    The Trust is expected to be treated as a grantor trust and not as an
association taxable as a corporation. Consequently, the Trust will not be
subject to tax. For tax purposes, Unitholders will be considered to own and
receive the Trust's assets and income as though no trust were in existence. The
Trust will file an information return, reporting all items of income, credit or
deduction which must be included in the tax returns of the Unitholders. If the
Trust were determined to be an association taxable as a corporation, it would be
treated as a separate entity subject to corporate tax on its taxable income,
Unitholders would be treated as shareholders, and distributions to Unitholders
from the Trust would be treated as nondeductible corporate distributions. Such
distributions would be taxable to a Unitholder, first, as dividends to the
extent of the Unitholder's pro rata share of the Trust's earnings and profits,
then as a tax-free return of capital to the extent of his basis in his Trust
Units, and finally as capital gain to the extent of any excess.

DIRECT TAXATION OF UNITHOLDERS

    Assuming that the Trust will be treated as a grantor trust for Federal
income tax purposes, and a Unitholder will be treated for Federal income tax
purposes as owning a direct interest in the Treasury Obligations and the assets
of the Trust, each Unitholder will be taxed directly on his pro rata share of
the income attributable to the Treasury Obligations and the assets of the Trust
and will be entitled to claim his pro rata share of the deductions and credits
attributable to the Trust (subject to certain limitations discussed below).
Income, credits and expenses attributable to the assets of the Trust and the
Treasury Obligations will be taken into account by Unitholders consistent with
their method of accounting and without regard to the taxable year or accounting
method employed by the Trust.

    The Trust makes quarterly distributions to Unitholders of record on each
Quarterly Record Date. The terms of the



                                       12

<PAGE>


Trust Agreement, as described below, seek to assure to the extent practicable
that taxable income attributable to such distributions will be reported by the
Unitholder who receives such distribution, assuming that he is the owner of
record on the Quarterly Record Date. In certain circumstances, however, a
Unitholder will not receive the distribution attributable to such income. For
example, if the Trustee establishes a reserve or borrows money to satisfy
liabilities of the Trust, income associated with the cash used to establish that
reserve or to repay that loan must be reported by the Unitholder, even though
that cash is not distributed to him. In addition, Unitholders will be required
to recognize certain interest income attributable to the Treasury Obligations
with respect to which no current cash distributions will be made.

    The Trust allocates income, deductions and credits to Unitholders based on
record ownership at Quarterly Record Dates. The IRS could require income and
deductions of the Trust to be determined and allocated daily or require some
method of daily proration, which could result in an increase in the
administrative expenses of the Trust.

   Under current market conditions, it is anticipated that total distributable
cash will exceed taxable income through 2004. After 2004, taxable income will
exceed distributable cash, and the amount of such excess could be significant.
Such estimates are based on numerous assumptions as to the allocation of a
Unitholder's purchase price and the amount and treatment of operating costs,
development costs, Trust administrative expenses, production estimates and
depletion. No assurance can be given that the estimates will prove to be
correct, and the actual percentages could be materially higher or lower.

TREATMENT OF TRUST UNITS

   Assuming that the Trust is treated as a grantor trust for tax purposes, each
Unitholder will be treated as purchasing directly an interest in the Net Profits
Interests. The purchaser of a Depositary Unit will be required to allocate the
portion of his total purchase price allocated to the Trust Unit between the
Royalty NPI and the Term NPI in the proportion that the fair market value of
each bears to the total fair market value of both. Information regarding
purchase price allocations will be furnished to Unitholders by the Trustee.

INTEREST INCOME

    The Term NPI will be treated as a "production payment" under Section 636(a)
of the Code. Thus, each Unitholder will be treated as making a mortgage loan on
the Underlying Properties of the Term NPI to Eastern American in an amount equal
to the amount of the purchase price of each Depositary Unit allocated to the
Term NPI. Because it is treated as a debt instrument for tax purposes, the Term
NPI will be subject to the original issue discount income ("OID") rules of the
Code which generally require the periodic inclusion of the original issue
discount in income of the purchaser of a debt instrument. The Code also
authorizes the IRS to prescribe regulations modifying the statutory provisions
where, by reason of contingent payments such as those provided for by the Term
NPI, the tax treatment provided under the Code provisions does not carry out the
purposes of such provisions.

    The IRS has issued a series of proposed and final regulations dealing with
debt instruments which call for contingent payments. The initial set of proposed
regulations dealing with this topic were issued on April 8, 1986, and modified
on February 26, 1991 (the "Old Proposed Regulations"). A second set of proposed
contingent payment regulations were issued on January 19, 1993, but were
withdrawn prior to publication in the Federal Register. On December 15, 1994,
the IRS replaced the Old Proposed Regulations by issuing a third set of proposed
regulations addressing debt obligations that provide for contingent payments
(the "New Proposed Regulations"). The New Proposed Regulations were proposed to
be effective for debt obligations issued on or after the date that is sixty days
following the promulgation of the New Proposed Regulations in final form. In
this regard, the New Proposed Regulations have been adopted in final form (the
"Final Regulations"), though effective only for debt instruments issued after
August 12, 1996. Thus, by their terms, the New Proposed Regulations and the
Final Regulations do not apply to the Term NPI. However, the Preamble to the
Final Regulations provides that for debt instruments issued prior to the
effective date of the Final Regulations, a taxpayer may use any reasonable
method to account for such debt instruments, including a method that would have
been permitted under the proposed regulations when the debt instrument was
issued.

   Therefore, Eastern American, as obligor under the Term NPI, intends to
continue to treat the Term NPI in the manner provided under the Old Proposed
Regulations, which were proposed at the time the Term NPI was transferred to the
Trust and Trust Units were issued. Under this approach, each payment (at the
time the amount of such payment becomes fixed) made to the Trust with respect to
the Term NPI will be treated first as a payment of interest to the extent of
interest

                                       13

<PAGE>


deemed accrued under the OID rules and the excess (if any) will be treated as a
payment of principal. The total amount treated as principal will be limited to a
portion of the purchase price of each Depositary Unit allocated to the Term NPI.
For purposes of determining the amount of accrued interest, the Old Proposed
Regulations required the use of the Applicable Federal Rate based on the due
date of the final payment due under the terms of the production payment, which
for the Term NPI is May 15, 2013.

    Unitholders will also be required to recognize and report OID interest
income attributable to the Treasury Obligations. In general, the total amount of
OID a Unitholder will be required to recognize will be calculated as the
difference between the amount of the purchase price of a Depositary Unit
allocated to the Treasury Obligations and the pro rata portion of the face
amount of such Treasury Obligations attributable to the Depositary Unit. The
amount of OID so calculated will be included in income by a Unitholder on the
basis of a constant interest rate computation.

ROYALTY INCOME AND DEPLETION

    The income from the Royalty NPI will be royalty income subject to an
allowance for depletion. The depletion allowance must be computed separately by
each Unitholder for each oil or gas property (within the meaning of Code Section
614). The IRS presently takes the position that a net profits interest burdening
multiple properties is one property for depletion purposes. Accordingly, the
Trust has taken the position that the Royalty NPI is one property for depletion
purposes until such time as the issue is resolved in some other manner.

    The allowance for depletion with respect to a property is determined
annually and is the greater of cost depletion or, if allowable, percentage
depletion. Percentage depletion is generally available to "independent
producers" (generally persons who are not substantial refiners or retailers of
oil or gas or their primary products) on the equivalent of 1,000 barrels of
production per day. Percentage depletion is a statutory allowance equal to 15%
of the gross income from production from a property which is included in income
by a taxpayer.

    Percentage depletion is subject to a net income limitation which is 100% of
the taxable income from the property, computed without regard to depletion
deductions and certain loss carrybacks. The percentage depletion deduction for a
taxable year is limited to 65% of the taxpayer's taxable income for the year,
before percentage depletion and certain other deductions. Unlike cost depletion,
percentage depletion is not limited to the adjusted tax basis of the property,
although it reduces that adjusted tax basis (but not below zero).

    In computing cost depletion for each property for any year, the adjusted tax
basis of that property at the end of that year is divided by the estimated total
units (Mcf of gas) recoverable from that property to determine the per-unit
allowance for such property. The per-unit allowance is then multiplied by the
number of units produced and sold from that property during the year. Cost
depletion for a property cannot exceed the adjusted tax basis of such property.
Since the Trust will be taxed as a grantor trust, each Unitholder will compute
cost depletion using his basis in his Trust Units allocated to the Royalty NPI.
Information will be provided by the Trustee to each Unitholder reflecting how
that basis should be allocated.

SECTION 29 CREDIT

    Eastern American believes that most of the production attributable to the
Royalty NPI is gas produced from Devonian shale or a tight formation. Provided a
number of requirements are met, taxpayers are entitled to the Section 29 Credit
for gas produced from Devonian shale or a tight formation. The Section 29 Credit
generally applies only to gas produced from Devonian shale or a tight formation
in the United States and sold to an unrelated party prior to January 1, 2003,
from wells drilled after December 31, 1979, and prior to January 1, 1993.
Additionally, the Section 29 Credit applies only to gas produced from a tight
formation which, as of April 20, 1977, was committed or dedicated to interstate
commerce (as defined in Section 2(18) of the Natural Gas Policy Act, as in
effect on November 5, 1990), or which is produced from a well drilled after
November 5, 1990. A Unitholder will be eligible to claim the Section 29 Credit
with respect to certain sales of such gas attributable to the Royalty NPI.

    Section 29 Credits resulting from an investment in Depositary Units may only
be used to reduce a taxpayer's regular income tax liability. Section 29 Credits
available to a taxpayer in any taxable year may not be carried back but may be
carried forward for use by that taxpayer in a subsequent tax year only in a
limited fashion. See "Alternative Minimum


                                       14

<PAGE>


Tax" below.

OTHER INCOME AND EXPENSES

    From time to time the Trust may generate interest income on funds held as a
reserve or held until the next distribution date. Expenses of the Trust will
include administrative expenses of the Trustee. Under the Code, certain
miscellaneous itemized deductions of an individual taxpayer are deductible only
to the extent that in the aggregate they exceed 2% of the taxpayer's adjusted
gross income. Certain administrative expenses attributable to the Trust Units
may have to be aggregated with an individual Unitholder's other miscellaneous
itemized deductions to determine the excess over 2% of adjusted gross income. To
date the amount of such expenses has not been significant in relation to the
Trust's income.

ALTERNATIVE MINIMUM TAX

    The Code imposes a minimum tax (known as an "alternative minimum tax" or
"AMT") on each taxpayer to the extent that his "tentative minimum tax" in any
taxable year exceeds his regular tax for that year. For purposes of computing
the AMT, the taxpayer's taxable income is recomputed with various "adjustments"
plus "items of tax preference".

    A taxpayer is generally entitled to a credit against, or reduction in, his
regular tax liability in a subsequent year in an amount equal to the AMT he pays
for a prior taxable year. That credit can only be used to reduce his regular tax
liability for that subsequent year to the extent his regular tax liability for
that subsequent year exceeds his tentative minimum tax liability for that
subsequent year, however.

    The Section 29 Credit allowable to a taxpayer as a reduction of his
liability for any taxable year cannot exceed the excess of his regular tax
liability for such taxable year, as reduced by his foreign tax credits and
certain nonrefundable credits, over his tentative minimum tax liability for that
year. Any amount of Section 29 Credit disallowed for the tax year solely because
of this limitation will increase a taxpayer's credit for the prior year's AMT,
as described above. There is no provision for the carryback or carryforward of
the Section 29 Credit in any other circumstances. Therefore, a Unitholder may
not receive the full benefit of available Section 29 Credits, depending on his
particular AMT circumstances.

    Since the effect of the AMT varies depending upon each Unitholder's personal
tax and financial position, each Unitholder is advised to consult with his own
tax advisor concerning the effect of the AMT on him and Section 29 Credits
attributable to an investment in the Depositary Units.

NON-PASSIVE ACTIVITY

    The income, credits and expenses of the Trust will not be taken into account
in computing the passive activity losses and income under Code Section 469 for a
Unitholder who acquires and holds Depositary Units as an investment and did not
acquire them in the ordinary course of business.

UNRELATED BUSINESS TAXABLE INCOME

    Certain organizations that are generally exempt from tax under Code Section
501 are subject to tax on certain types of business income defined in Code
Section 512 as unrelated business income. The income of the Trust will not be
unrelated business taxable income within the meaning of Code Section 512 so long
as the Trust Units are not "debt-financed property" within the meaning of Code
Section 524(b). In general, a Trust Unit would be debt-financed if the
Unitholder incurs debt to acquire a Trust Unit or otherwise incurs or maintains
a debt that would not have been incurred or maintained if such Trust Unit had
not been acquired. Legislative proposals have been made from time to time which,
if adopted, would result in the treatment of income attributable to the Royalty
NPI as unrelated business income.

                                       15

<PAGE>


SALE OF DEPOSITARY UNITS; SALE OF TRUST UNITS OR TREASURY OBLIGATIONS

    Generally, a Unitholder will realize gain or loss on the sale or exchange of
his Depositary Units measured by the difference between the amount realized on
the sale or exchange and his adjusted basis for such Depositary Units. Gain or
loss on the sale of Depositary Units by a Unitholder who is not a dealer with
respect to such Depositary Units and who has a holding period for the Depositary
Units of more than one year will be treated as long-term capital gain or loss
except to the extent of the depletion recapture amount and any accrued market
discount as explained below. A Unitholder's initial basis in his Depositary
Units will be equal to the amount paid for such Depositary Units. Such basis
will be increased by the amount of OID income recognized by the Unitholder
attributable to the Treasury Obligations. Such basis will be reduced by
deductions for depletion claimed by the Unitholder (but not below zero). In
addition, such basis will be reduced by the amount of any payments attributable
to the Term NPI which are treated as payments of principal under the OID rules.

    For Federal income tax purposes, the sale of a Depositary Unit will be
treated as a sale by the Unitholder of his interest in the Treasury Obligations
and the assets of the Trust. Thus, upon the sale of Depositary Units, a
Unitholder must treat as ordinary income his depletion recapture amount, which
is an amount equal to the lesser of (i) the gain on that sale attributable to
disposition of the Royalty NPI or (ii) the sum of the prior depletion deductions
taken with respect to the Royalty NPI (but not in excess of the initial basis of
such Depositary Units allocated to the Royalty NPI). It is possible that the IRS
would take the position that a portion of the sales proceeds is ordinary income
to the extent of any accrued income at the time of sale allocable to the
Depositary Units sold, but which is not distributed to the selling Unitholder.

     A Unitholder who allocates his purchase price (or is required to allocate
his purchase price) to the Treasury Obligations in an amount less than the sum
of (a) his share of the initial issue price of the Treasury Obligations and (b)
his share of OID income recognized by prior holders of the Treasury Obligations
(any such difference represents "market discount") will generally be required to
recognize ordinary income to the extent of any accrued market discount upon sale
of the Depositary Units. In general, accrued market discount is an amount which
bears the same ratio to total market discount as the number of days which a
Unitholder holds a Depositary Unit bears to the number of days after the date
the Unitholder acquired the Depositary Unit and up to and including the
Liquidation Date.

WITHDRAWAL OF TRUST UNITS OR TREASURY OBLIGATIONS

    A Unitholder will recognize no gain or loss upon the withdrawal of the Trust
Units or Treasury Obligations from the Depositary. A sale of the Trust Units or
the Treasury Obligations will result in the recognition of income or loss.

SALE OF NET PROFITS INTERESTS OR PRODUCTION PAYMENT

    A sale by the Trust of Net Profits Interests will be treated for Federal
income tax purposes as a sale of Net Profits Interests by a Unitholder. Thus, a
Unitholder will recognize gain or loss on a sale of Net Profits Interests by the
Trust. A portion of that income may be treated as ordinary income to the extent
of depletion recapture. Receipt by the Trust of proceeds drawn from the letter
of credit supporting Eastern Marketing's obligations under the Gas Purchase
Contract will, in certain cases, be in consideration for the conveyance to
Eastern Marketing of a production payment interest in reserves attributable to
the Net Profits Interests or to compensate the Trust for damages from a breach
of the Gas Purchase Contract. All or a portion of such proceeds may be treated
as non-taxable loan proceeds attributable to a loan by Eastern Marketing
resulting from the production payment, may be treated as ordinary income not
subject to depletion or may receive some other treatment, depending upon facts
existing at that time. To the extent receipt of such proceeds is attributable to
a sale of reserves by the Trust, depletion and Section 29 Credits available to
the Unitholders for subsequent periods will be reduced.

BACKUP WITHHOLDING

    In general, distributions of Trust income will not be subject to "backup
withholding" unless (i) the Unitholder is an individual or other noncorporate
taxpayer and (ii) such Unitholder fails to comply with certain reporting
procedures.

                                       16

<PAGE>



TAX SHELTER REGISTRATION

    The Trust has been registered with the IRS as a "tax shelter," and has
received tax shelter registration number 93040000163. A "tax shelter," for
purposes of the registration requirement, is an investment with respect to which
a person could reasonably infer, from the representations made in connection
with any offer for sale of any interest in the investment, that the "tax shelter
ratio" for any investor may be greater than two to one as of the close of any of
the first five years ending after the date on which the investment is offered
for sale. The term "tax shelter ratio" with respect to an investment means the
ratio that the aggregate amount of gross deductions for any investor, determined
without regard to income derived from the investment, plus 350% of the credits
that are potentially available to an investor, bears to the investment base for
the year. The "investment base" is equal to the cash, plus the adjusted basis
(which may be less than the fair market value) of any other property invested.
Certain borrowings, however, including those from other participants in the
venture, are excluded from the investment base. While Eastern American has no
knowledge of any such borrowings, it is possible that, due to such borrowings,
the investment base of an investor would be substantially reduced or eliminated.

    A Unitholder who sells or otherwise transfers a Trust Unit must furnish to
the transferee the tax shelter registration number set forth above. The penalty
for failure of the transferor of a Trust Unit to furnish such tax shelter
registration number to a transferee is $100 for each such failure. Unitholders
must disclose the tax shelter registration number of the Trust on Form 8271 to
be attached to the tax return on which any deduction, loss, credit or other
benefit generated by the Trust is claimed or income of the Trust is included. A
Unitholder who fails to disclose the tax shelter registration number on his
return, without reasonable cause for such failure, will be subject to a $250
penalty for each such failure. (Any penalties discussed herein are not
deductible for income tax purposes.)

    ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED
BY THE IRS.

REPORTS

    Unitholders of record will be provided informational tax packages in order
to permit computation of their taxable income from ownership of Depositary
Units.

                            STATE TAX CONSIDERATIONS

    The following is intended as a brief summary of certain information
regarding state income taxes and other state tax matters affecting individual
Unitholders. Unitholders are urged to consult their own legal and tax advisors
with respect to these matters.

    The Trust owns the Net Profits Interests burdening the Underlying Properties
located in the states of Pennsylvania and West Virginia. Both of these states
have income taxes applicable to individuals and may require the Trust to
withhold taxes from distributions made to nonresident Unitholders. Withholding,
if required, is at the rate of 4% of taxable income attributable to West
Virginia and 2.8% of taxable income attributable to Pennsylvania. A Unitholder
may be required to file state income tax returns and/or to pay taxes in these
states and may be subject to penalties for failure to comply with such
requirements. Any state income taxes withheld by the Trust are treated as
deductions against income in the calculation of income taxes otherwise payable.

    The Depositary will provide information prepared by the Trustee concerning
the Depositary Units sufficient to identify the income from Depositary Units
that is allocable to each state. Unitholders of Depositary Units should consult
their own tax advisors to determine their income tax filing requirements with
respect to their share of income of the Trust allocable to states imposing a tax
on such income.

                                       17

<PAGE>


    The Trust Units may constitute real property or an interest in real property
under the tax, inheritance, estate and probate laws of either or both of
Pennsylvania and West Virginia. If the Depositary Units are held to be real
property or an interest in real property under the laws of a state in which the
Underlying Properties are located, the holders of Depositary Units may be
subject to ad valorem or other property tax, devolution, probate and
administration laws, and inheritance or estate and similar taxes, under the laws
of such state.

Item 2.     PROPERTIES.

    Reference is made to Item 1 of this Form 10-K.

Item 3.     LEGAL PROCEEDINGS.

    None

Item 4.     SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS.

    There were no matters submitted to a vote of Unitholders during the year
ended December 31, 2000.

                                       18

<PAGE>


                                     PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED MATTERS.

    The Depositary Units are traded on the New York Stock Exchange under the
ticker symbol "NGT". The high and low prices and distributions paid during the
quarters in the three-year period ended December 31, 2000 were as follows:

<TABLE>
<CAPTION>
                       Quarter
                       -------                                                        Distributions
                                                           High             Low           Paid
                                                           ----             ---           ----
<S>                                                    <C>              <C>             <C>
    1998:
    -----
    First (to March 31, 1998)                          $   20 1/8       $    17 5/16    $   0.47
    Second (to June 30, 1998)                          $   17 7/8       $    16 3/4     $   0.42
    Third (to September 30, 1998)                      $   17 1/2       $    15 1/4     $   0.36
    Fourth (to December 31, 1998)                      $   16 15/16     $    13 7/8     $   0.35

    1999:
    -----
    First (to March 31, 1999)                          $   15 3/8       $    13 1/2     $   0.36
    Second (to June 30, 1999)                          $   14 7/8       $    13 1/2     $   0.33
    Third (to September 30, 1999)                      $   14 1/4       $    13 1/8     $   0.42
    Fourth (to December 31, 1999)                      $   13 3/16      $     9 3/4     $   0.35

    2000:
    -----
    First (to March 31, 2000)                          $   13 5/16      $    10 3/8     $   0.30
    Second (to June 30, 2000)                          $   14 5/16      $    12 3/16    $   0.37
    Third (to September 30, 2000)                      $   15 3/8       $    13 15/16   $   0.45
    Fourth (to December 31, 2000)                      $   16 3/4       $    14 9/16    $   0.54
</TABLE>

    At March 15, 2001, the 5,900,000 Depositary Units outstanding were held by
approximately 365 Unitholders of record.

    With respect to the Treasury Obligations, the high and low asked prices per
$1,000 face amount for the period from October 1, 2000 to December 31, 2000 were
$515.00 and $460.90, respectively. The closing asked price on December 31, 2000
was $509.90 per $1,000 face amount.

ITEM 6.  SELECTED FINANCIAL DATA.

<TABLE>
<CAPTION>
                                            December        December       December      December     December
                                            31, 2000        31, 1999       31, 1998      31, 1997     31, 1996
                                            --------        --------       --------      --------     --------

<S>                                      <C>             <C>            <C>           <C>          <C>
Distributable Income and other
    Distributions Declared..............  $9,776,735      $8,561,984     $9,422,675    $9,803,863  $10,387,436
Distributable Income and other
    Distributions Declared per unit....        $1.66           $1.45          $1.60         $1.66        $1.76

Total assets at year end................ $50,964,669     $55,251,901    $61,009,470   $66,535,828  $72,813,708
</TABLE>


                                       19

<PAGE>



ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS.

CAUTIONARY STATEMENT

         The Trustee, its officers or its agents on behalf of the Trustee may,
from time to time, make forward-looking statements (other than statements of
historical fact). When used herein, the words "anticipates," "expects,"
"believes," "intends" or "projects" and similar expressions are intended to
identify forward-looking statements. To the extent that any forward-looking
statements are made, the Trustee is unable to predict future changes in gas
prices, gas production levels, economic activity, legislation and regulation,
and certain changes in expenses of the Trust. In addition, the Trust's future
results of operations and other forward looking statements contained in this
item and elsewhere in this report involve a number of risks and uncertainties.
As a result of variations in such factors, actual results may differ materially
from any forward-looking statements. Some of these factors are described below.
The Trustee disclaims any obligations to update forward looking statements and
all such forward-looking statements in this document are expressly qualified in
their entirety by the cautionary statements in this paragraph.

GENERAL

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

    During the Primary Term, which ended December 31, 1999, the Index Price for
any quarter was a weighted average price determined by reference to the Fixed
Price component, which was given a 66 2/3% weighting and a Variable Price
component, which was given a 33 1/3% weighting. Effective January 1, 2000, the
Index Price that the Trust will receive for any quarter will be equal to 100% of
the Variable Price component.

    During the Primary Term of the Trust, the Fixed Price component was
consistently higher than the Variable Price component. The Fixed Price, which
escalated 5% per year during the Primary Term, was equal to $3.39 per Mcf for
the calendar year 1998 and $3.56 per Mcf for 1999. The corresponding Variable
Price, was equal to $2.86 per Mcf for the calendar year 1998 and $2.82 per Mcf
for 1999.

    Accordingly, the Index Price payable to the Trust for production on and
after January 1, 2000 may be higher or lower than the price paid to the Trust
during the Primary Term, based on 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 unit holders.

  During 1999, the Trust received proceeds for seven (7) wells in which the
Trust owned a Net Profits Interest that were required to be plugged and
abandoned by the coal lessee of the property upon which the wells were drilled
since the wells interfered with proposed mining operations. The coal lessee had
the right to cause these wells to be plugged and abandoned pursuant to an
agreement entered into prior to the formation of the Trust. This prior agreement
is a Permitted Encumbrance under the Conveyances and the Trust accepted its Net
Profits Interest subject to this prior agreement. Pursuant to this prior
agreement the coal lessee is required to pay for the wells it causes to be
plugged and abandoned. During 1999, Eastern American received $559,371 pursuant
to this agreement, of which 90%, or $503,434, was allocated to the Trust.

    During 1998, the Trust received proceeds for seven (7) additional wells in
which the Trust owns a Net Profits Interest that were required to be plugged and
abandoned by the coal lessee. During 1998, Eastern American received $931,637 in
connection with these seven wells, of which 90%, or $838,474, was allocated to
the Trust.

    It is expected that additional wells will be required to be plugged over the
remaining life of the Trust as a result of this agreement.

  LIQUIDITY AND CAPITAL RESOURCES

      The Trust has no source of liquidity or capital resources other than the
distributions received from the Net Profits

                                       20

<PAGE>


Interests.

    In accordance with the provisions of the Conveyances, generally all revenues
received by the Trust, net of Trust administrative expenses and the amount of
established reserves, are distributed currently to the Unitholders.

RESULTS OF OPERATIONS

2000 COMPARED WITH 1999

    The Trust's total distributions declared per Unit were $1.66 for the twelve
months ended December 31, 2000 as compared to $1.45 for the twelve months ended
December 31, 1999. Such increase was due to an increase in the average price
payable to the Trust under the Gas Purchase Contract as discussed below ($4.27
per Mcf for the twelve months ended December 31, 2000; $3.31 per Mcf for the
twelve months ended December 31, 1999). This increase was partially offset by a
decrease in production of gas attributable to the Net Profits Interests for the
twelve months ended December 31, 2000 (2,717 MMcf) as compared to the twelve
months ended December 31, 1999 (2,922 MMcf) together with a decrease in Cash
Proceeds on Sale of Net Profits Interests. The production decreases were
attributable to the natural production declines associated with the Underlying
Properties and the required plugging and abandonment of certain wells in
previous periods. The distributable income includes no Cash Proceeds on Sale of
Net Profits Interests for the twelve months ended December 31, 2000, as compared
to $503,434 of Cash Proceeds for the twelve months ended December 31, 1999.

    The average price payable to the Trust for gas production attributable to
the Net Profits Interests was $4.27 per Mcf for the twelve months ended December
31, 2000 as compared to $3.31 per Mcf for the twelve months ended December 31,
1999. The average price per Mcf was higher for the twelve months ended December
31, 2000 than the corresponding twelve month period ended December 31, 1999 due
to an increase in the average spot market price for gas delivered at the Henry
Hub, near Henry, Louisiana ($3.59 per MMBtu for the twelve months ended December
31, 2000; $2.26 per MMBtu for the twelve months ended December 31, 1999). Due to
the expiration of the Primary Term on December 31, 1999, there is no Fixed Price
component for the twelve months ended December 31, 2000 as compared to the
twelve months ended December 31, 1999 ($3.56 per Mcf).

1999 COMPARED WITH 1998

    The Trust's total distributions declared per Unit were $1.45 for the twelve
months ended December 31, 1999 as compared to $1.60 for the twelve months ended
December 31, 1998. Such decrease was due to a decrease in production of gas
attributable to the Net Profits Interest for the twelve months ended December
31, 1999 (2,922 MMcf) as compared to the twelve months ended December 31, 1998
(3,180 MMcf) together with a decrease in Cash Proceeds on Sale of Net Profits
Interest as discussed below. The production decreases were attributable to the
natural production declines associated with the Underlying Properties and the
required plugging and abandonment of certain wells in previous and current
periods. This decrease was partially offset by an increase in the average price
payable to the Trust under the Gas Purchase Contract. The distributable income
includes Cash Proceeds on Sale of Net Profits Interests of $503,434 for the
twelve months ended December 31, 1999, as compared to $838,474 of Cash Proceeds
for the twelve months ended December 31, 1998.

    The average price payable to the Trust for gas production attributable to
the Net Profits Interests was $3.31 per Mcf for the twelve months ended December
31, 1999 compared to $3.21 per Mcf for the twelve months ended December 31,
1998. The price per Mcf was higher for the twelve months ended December 31, 1999
than for the corresponding prior twelve month period due to a higher Fixed Price
component of the Index Price under the Gas Purchase Contract ($3.56 per Mcf for
the twelve months ended December 31, 1999, compared to $3.39 per Mcf for the
twelve months ended December 31, 1998). Such higher Fixed Price was attributable
to the 5% annual escalation between years during the Primary Term. This increase
was partially offset by a lower Variable Price component ($2.82 per Mcf for the
twelve months ended December 31, 1999, compared to $2.86 per Mcf for the twelve
months ended December 31, 1998). Such lower Variable Price was directly
attributable to a decrease in the average futures spot market prices for gas
delivered at the Henry Hub, near Henry, Louisiana ($2.26 per MMBtu for the
twelve months ended December 31, 1999; $2.30 per MMBtu for the twelve months
ended December 31, 1998).

                                       21

<PAGE>


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

<TABLE>
<CAPTION>
                                                                          Page in this Form 10-K

<S>                                                                                    <C>
Financial Statements

     Report of Independent Accountants.................................................B-2
     Statements of Assets, Liabilities and Trust Corpus as of December 31,
         2000 and 1999.................................................................B-3
     Statements of Distributable Income for the years ended
         December 31, 2000, 1999 and 1998..............................................B-4
     Statements of Changes in Trust Corpus for the years ended
         December 31, 2000, 1999 and 1998..............................................B-5
     Notes to Financial Statements.....................................................B-6
</TABLE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE.

     None.


                                       22

<PAGE>


                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

     The Trust has no directors or executive officers. The Trustee is a
corporate trustee which may be removed by the affirmative vote of holders of a
majority of the Trust Units then outstanding at a meeting of the Unitholders of
the Trust at which a quorum is present. The Trust is not required to and does
not hold annual meetings of the Unitholders.

ITEM 11. EXECUTIVE COMPENSATION.

     The Trust has no officers or directors, and is administered by the Trustee.
For the years ended December 31, 2000, 1999 and 1998, the Trustee received
$55,203, $65,378 and $66,614, respectively, as Trustee fees and $204,645,
$149,395 and $148,907, respectively, as reimbursement of legal, accounting, and
other professional expenses for such services.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

     (a)      Security Ownership of Certain Beneficial Owners.

     Based on filings with the Securities and Exchange Commission, the Trust is
not aware of any person owning beneficially more than five percent of the Units
as of March 15, 2001.

     (b)      Security Ownership of Management.

     Not applicable.

     (c)      Changes in Control.

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     None.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

<TABLE>
<CAPTION>
                                                                             PAGE IN THIS FORM 10-K
                                                                             ----------------------
<S>                                                                                 <C>
Reports

     Reserve Report of Ryder Scott Company, Independent
         Petroleum Engineers....................................................... A-1 - A-7

Financial Statements

The following financial statements are included in this Annual Report on Form 10-K
on the pages indicated:
     Report of Independent Accountants...............................................  B-2
     Statements of Assets, Liabilities and Trust Corpus as of December 31,
          2000 and 1999..............................................................  B-3
     Statements of Distributable Income for the years ended
          December 31, 2000, 1999 and 1998...........................................  B-4
     Statements of Changes in Trust Corpus for the years ended
          December 31, 2000, 1999 and 1998...........................................  B-5
     Notes to Financial Statements................................................. B-6 - B-17
</TABLE>

Schedules

All schedules have been omitted because they are not required, not applicable or
the information required has been included elsewhere herein.

                                       23

<PAGE>


Exhibits

Except as otherwise indicated below, all exhibits are incorporated herein by
reference to the indicated exhibits to filings previously made by the registrant
with the Securities and Exchange Commission. All references are to the
registrant's Registration Statement on Form S-1, Registration No. 33-56336,
except for Exhibit 3.1, which is incorporated by reference to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1994.

<TABLE>
<CAPTION>
                                                                                                  Exhibit

                                                                                                  NUMBER

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

         Eastern American Marketing Corporation.....................................................10.4
10.5     Form of Assignment and Standby Performance Agreement.......................................10.5
</TABLE>



Reports on Form 8-K

No reports on Form 8-K were filed with the Securities and Exchange Commission
during the year ended December 31, 2000.

                                       24

<PAGE>


                                   SIGNATURES

         PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED ON THIS 29TH DAY OF
MARCH, 2001.

                                           EASTERN AMERICAN NATURAL GAS TRUST

                                           By:      Bank of New York, Trustee

                                           By:      /s/  Robert D. Foltz

                                           Name:    Robert D. Foltz

                                           Title:    Vice President

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

                                       25

<PAGE>


        [Ryder Scott Company, Independent Petroleum Engineers Letterhead]

                                December 27, 2000

Eastern American Natural Gas Trust
Bank of New York
2 North LaSalle Street
Chicago, Illinois 60606

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, 2000. The Trust is a grantor trust formed
to hold interests in certain domestic oil and gas properties owned by Eastern
American Energy Corporation (Eastern American). 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 estimated reserve quantities and future income quantities
presented in this report are related to a large extent to hydrocarbon prices.
Hydrocarbon prices in effect at December 31, 2000 were used in the preparation
of this report as required by Securities and Exchange Commission (SEC) and
Financial Accounting Standards Bulletin No. 69 (FASB 69) guidelines; however,
actual future prices may vary significantly from December 31, 2000 prices for
reasons discussed in more detail in other sections of this report. Therefore,
quantities of reserves actually recovered and quantities of income actually
received may differ significantly from the estimated quantities presented in
this report.

<TABLE>
<CAPTION>
                                                                            As of December 31, 2000
                                                             ------------------------------------------------
                                                                                Estimated           Present
                                                                                Future Net           Value

                                                               Gas             Cash Inflows          At 10%
                                                               (MMCF)              (M$)                (M$)
                                                             ---------          ---------           --------
<S>                                                             <C>               <C>                 <C>
Proved net developed and undeveloped
------------------------------------
Royalty NPI                                                     14,983             83,216             35,074
Term NPI                                                        11,484             63,779             39,646
                                                                ------             ------             ------
  Total                                                         26,467            146,995             74,720

Proved net developed
--------------------
Royalty NPI                                                     14,983             83,213             35,074
Term NPI                                                        11,484             63,779             39,646
                                                                ------             ------             ------
  Totals                                                        26,467            146,995             74,720
</TABLE>


                                       A-1

<PAGE>


            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, 2001 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 the interest held by the Trust and the interests to
be retained by Eastern American. 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 Eastern American will vary in
the future as relative estimates of future gross revenues and future net incomes
vary. Furthermore, Eastern American 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. For purposes of
this report, the "Term NPI" was limited to the 20 year period defined as the
term by the Trust.

            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.

            The proved reserves presented in this report comply with the
Securities and Exchange Commission's Regulation S-X Part 210.4-10 Sec. (a) as
clarified by subsequent Commission Staff Accounting Bulletins, and are based on
the following definitions and criteria:

            PROVED RESERVES of crude oil, natural gas, or natural gas liquids
are estimated quantities that geological and engineering data demonstrate with
reasonable certainty to be recoverable in the future from known reservoirs under
existing conditions. Reservoirs are considered proved if economic producibility
is supported by actual production or formation tests. In certain instances,
proved reserves may be assigned on the basis of a combination of core analysis
and electrical and other type logs which indicate the reservoirs are analogous
to reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as hydrocarbons are
produced and additional data becomes available. Proved natural gas reserves
consist of non-associated, associated and dissolved gas. An appropriate
reduction in gas reserves has been made for the expected removal of natural gas
liquids, for lease and plant fuel, and for the exclusion of non-hydrocarbon
gases if they occur in significant quantities.

                                       A-2

<PAGE>


            Reserves that can be produced economically through the application
of improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.

            Estimates of proved reserves do not include crude oil, natural gas,
or natural gas liquids being held in underground or surface storage.

                    (i) "developed reserves" which are those proved reserves
                    reasonably expected to be recovered through existing wells
                    with existing equipment and operating methods, including (a)
                    "developed producing reserves" which are those proved
                    developed reserves reasonably expected to be produced from
                    existing completion intervals now open for production in
                    existing wells, and (b) "developed non-producing reserves"
                    which are those proved developed reserves which exist behind
                    the casing of existing wells which are reasonably expected
                    to be produced through these wells in the predictable future
                    where the cost of making such hydrocarbons available for
                    production should be relatively small compared to the cost
                    of a new well; and

                    (ii) "undeveloped reserves" which are those proved reserves
                    reasonably expected to be recovered from new wells on
                    undrilled acreage, from existing wells where a relatively
                    large expenditure is required and from acreage for which an
                    application of fluid injection or other improved recovery
                    technique is contemplated where the technique has been
                    proved effective by actual tests in the area in the same
                    reservoir. Reserves from undrilled acreage are limited to
                    those drilling units offsetting productive units that are
                    reasonably certain of production when drilled. Proved
                    reserves for other undrilled units are included only where
                    it can be demonstrated with reasonable certainty that there
                    is continuity of production from the existing productive
                    formation.

            Because of the direct relationship between quantities of proved
undeveloped reserves and development plans, we include in the proved undeveloped
category only reserves assigned to undeveloped locations that we have been
assured will definitely be drilled and which are assigned to the Trust. Eastern
American has indicated that original drilling obligation to the Trust has been
satisfied and no undeveloped reserves remain.

                                       A-3

<PAGE>


            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, 2000 from this report
are presented in the following table:

<TABLE>
<CAPTION>
                                                                        As of December 31, 2000
                                                               --------------------------------------
                                                                Royalty           Term
                                                                  NPI              NPI        Totals
                                                               ---------         ------    ----------
<S>                                                               <C>            <C>          <C>
TOTAL PROVED
------------
  Future Cash Inflows (M$)                                        83,216         63,779       146,995
  Future Costs
    Production (M$)                                                    0              0             0
    Development (M$)                                                   0              0             0
                                                                 -------        -------      --------
      Total Costs (M$)                                                 0              0             0

Future Net Cash Inflows

  Before Income Tax (M$)                                          83,216         63,779       146,995

Present Value at 10%
  Before Income Tax (M$)                                          35,074         39,646        74,720
</TABLE>

<TABLE>
<CAPTION>
                                                                        As of December 31, 2000
                                                               --------------------------------------
                                                                Royalty          Term
                                                                  NPI             NPI          Totals
                                                               ---------        -------      --------
<S>                                                               <C>            <C>           <C>
Proved net developed reserves
-----------------------------
  Gas (MMCF)                                                      14,983         11,484        26,467

Proved net undeveloped reserves
-------------------------------
  Gas (MMCF)                                                           0              0             0

Total proved net reserves
-------------------------
  Gas (MMCF)                                                      14,983         11,484        26,467
</TABLE>

            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, Section 29 tax credits and federal income taxes have not been taken
into account in estimating future net cash inflows.

            Eastern American furnished us gas prices in effect at December 31,
2000 and with its forecasts of future gas prices which take into account
Securities and Exchange Commission guidelines, current market prices,
regulations under the Natural Gas Policy Act of 1978 and the Gas Decontrol Act
of 1989, contract prices and fixed and determinable price escalations where

                                       A-4

<PAGE>


applicable. In accordance with Securities and Exchange Commission guidelines,
the future gas prices used in this report make no allowances for future gas
price increases which may occur as a result of inflation nor do they account for
seasonal variations in gas prices which are likely to cause future yearly
average gas prices to be somewhat higher than December gas prices. In those
cases where contract market-out has occurred, the current market price was held
constant to depletion of the reserves. In those cases where market-out has not
occurred, contract gas prices including fixed and determinable escalations,
exclusive of inflation adjustments, were used until the contract expired and
then reduced to the current market price for similar gas in the area and held at
this reduced price to depletion of the reserves.

            This report utilized the terms of the gas contract between Eastern
Marketing 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
will escalate 5 percent per year on January 1 of each year during the primary
term beginning in 1994. The second component is the "Variable" price which for
any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu,
plus $0.30 per MMBtu, multiplied by 110 percent to effect a Btu adjustment. The
Henry Hub Average Spot Price is defined as the price per MMBtu determined for
any calendar quarter as the average price of the three months in such quarter
where each month's price is equal to the average of (i) the final settlement
prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported
in the WALL STREET JOURNAL, for such contracts which expired in each of the five
months prior to each month of such quarter, (ii) the final settlement price per
MmBtu for Henry Hub Gas Futures Contracts, as reported in the WALL STREET
JOURNAL, for such contracts which expire during such month and (iii) the closing
settlement prices per MMBtu of Henry Hub Gas Futures Contracts for such month,
as reported in the WALL STREET JOURNAL, for such contracts which expire in each
of the six months following such month. A Henry Hub Gas Futures Contract is
defined as a gas futures contract for gas to be delivered to the Henry Hub which
is traded on the New York Mercantile Exchange. The weighted average price is
determined by giving the "Fixed" price a 66 2/3 percent weighting and the
variable price a 33 1/3 percent weighting.

            Since the primary term is complete, the purchase price under the gas
contract will be equal to the "Variable" price. Eastern American computed the
"Variable" price under the gas contract as of December 31, 2000 as $5.554 per
Mcf, utilizing $4.749 as the Henry Hub Average Spot Price computed in accordance
with the gas contract.

            Operating costs for the leases and wells in this report were
supplied by Eastern American 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.

                                       A-5

<PAGE>


            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. Eastern American informed us that it has furnished us all
of the accounts, records, geological and engineering data and reports and other
data as were required for our investigation. The ownership interests, terms of
the Trust, prices, taxes, classification of wells for Section 29 Tax Credit, and
other factual data furnished to us in connection with our investigation were
accepted as represented. The estimates presented in this report are based on
data available through March, 2000. The projections were developed for the
Eastern American reserve report effective July 1, 2000. Eastern American has
advised Ryder Scott that there has been no material change in the performance of
these wells and therefore the July 1, 2000 projections developed for the Eastern
American report were mechanically adjusted to January 1, 2001 for use in this
report.

            At the time of formation of the Trust, Eastern American assigned The
Trust an interest in 65 undeveloped locations. During the period 1993 through
1998, Eastern American 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.

            The reserves included in this report are estimates only and should
not be construed as being exact quantities. They may or may not be actually
recovered. Moreover, estimates of proved reserves may increase or decrease as a
result of future operations of Eastern American. 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.

            The future production rates from properties now on production may be
more or less than estimated because of changes in market demand or allowables
set by regulatory bodies. Properties which are not currently producing may start
producing earlier or later than anticipated in our estimates of their future
production rates.

            The future prices received by Eastern American for the sale of its
production may be higher or lower than the prices used in this report as
described above, and the operating costs and other costs relating to such
production may also increase or decrease from existing levels; however, such
possible changes in prices and costs were, in accordance with rules adopted by
the Securities and Exchange Commission, omitted from consideration in preparing
this report.

                                       A-6

<PAGE>




            At the request of Eastern American Energy Corporation, we have
included the following table which summarizes the total net reserves estimates
from Eastern American's interest in the Underlying Properties:

                           Estimated Net Reserve Data
                         Certain Leasehold Interests of
                       Eastern American Energy Corporation
                             As of December 31, 2000

                                 SEC parameters

<TABLE>
<CAPTION>
                                                     Proved

                           -------------------------------------------------------
                                                                        Total
                                Developed         Undeveloped           Proved
                           -----------------     -------------      --------------
<S>                                   <C>                   <C>           <C>
Net Remaining Reserves
----------------------
Gas-MMCF                              47,434                 0             47,434
</TABLE>

            The estimated future net income associated with the foregoing
volumes and the 10 percent discounted estimated future net income was
$217,838,853 and $89,756,537, 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.

            Neither Ryder Scott Company nor any of its employees has any
interest in the subject properties and neither the employment to make this study
nor the compensation is contingent on our estimates of reserves and future cash
inflows for the subject properties.

                                Very truly yours,

                               RYDER SCOTT COMPANY
                               PETROLEUM ENGINEERS

                               /s/ Larry T. Nelms P.E.

                               Larry T. Nelms P. E.
                              Senior Vice President

LTN:ph


                                       A-7

<PAGE>










                       EASTERN AMERICAN NATURAL GAS TRUST

                                   ----------


                              FINANCIAL STATEMENTS

                        as of December 31, 2000 and 1999
                             and for the years ended

                        December 31, 2000, 1999 and 1998


<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS

To the Unitholders and Bank of New York, as Trustee for Eastern American Natural
Gas Trust:

We have audited the accompanying statements of assets, liabilities and trust
corpus of Eastern American Natural Gas Trust (the "Trust") as of December 31,
2000 and 1999, and the related statements of distributable income, and
changes in trust corpus for each of the three years in the period ended
December 31, 2000. These financial statements are the responsibility of the
Trustee. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by the Trustee, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As described in Note 2 to the financial statements, these financial statements
have been prepared on the basis of accounting prescribed by the Trust Agreement.

In our opinion, the financial statements audited by us present fairly, in all
material respects, the financial position of the Trust at December 31, 2000 and
1999, and the distributable income and changes in trust corpus for each of the
three years in the period ended December 31, 2000, on the basis of accounting
described in Note 2.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
March 15, 2001

                                       B-2

<PAGE>



                       EASTERN AMERICAN NATURAL GAS TRUST
               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
                        AS OF DECEMBER 31, 2000 AND 1999

<TABLE>
<CAPTION>
                                                           2000                1999
                                                     -----------         -----------

<S>                                                  <C>                 <C>
Assets:

        Cash                                         $       270         $     1,522
        Net Proceeds Receivable                        3,313,449           2,162,576
        Net Profits Interests in Gas Properties       93,162,180          93,162,180
        Accumulated Amortization                     (45,511,230)        (40,074,377)
                                                     -----------         -----------

           Total Assets                              $50,964,669         $55,251,901
                                                     ===========         ===========

Liabilities and Trust Corpus:

        Trust General and Administrative
           Expenses Payable                          $   128,885         $    95,041
        Distributions Payable                          3,184,834           2,069,057
        Trust Corpus (5,900,000 Trust Units
           authorized and outstanding)                47,650,950          53,087,803
                                                     -----------         -----------

           Total Liabilities and Trust Corpus        $50,964,669         $55,251,901
                                                     ===========         ===========
</TABLE>



   THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.


                                      B-3
<PAGE>

                       EASTERN AMERICAN NATURAL GAS TRUST
                       STATEMENTS OF DISTRIBUTABLE INCOME
                              FOR THE YEARS ENDED
                        DECEMBER 31, 2000, 1999 AND 1998

<TABLE>
<CAPTION>
                                                         2000                   1999                      1998
                                                      -----------            ----------                -----------

<S>                                                   <C>                    <C>                       <C>
Royalty Income                                        $11,569,718            $9,678,628                $10,217,526


Operating Expenses:
        Taxes on production and property                  784,871               660,089                    701,245
        Operating cost charges                            488,672               493,102                    474,138
                                                      -----------            ----------                -----------

           Total Operating Expenses                     1,273,543             1,153,191                  1,175,383
                                                      -----------            ----------                -----------


Net Proceeds to the Trust                              10,296,175             8,525,437                  9,042,143


General and Administrative Expenses                      (527,028)             (472,917)                  (464,937)

Interest Income                                             7,588                 6,030                      6,995

Cash Proceeds on Sale of Net Profits Interests                  0               503,434                    838,474
                                                      -----------            ----------                 ----------


        Distributable Income                           $9,776,735            $8,561,984                 $9,422,675
                                                      ===========            ==========                 ==========

Distributable Income Per Unit (5,900,000
        units authorized and outstanding)                 $1.6571               $1.4512                    $1.5971
                                                      ===========            ==========                 ==========
</TABLE>

   THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.


                                      B-4
<PAGE>


                       EASTERN AMERICAN NATURAL GAS TRUST
                     STATEMENTS OF CHANGES IN TRUST CORPUS
                              FOR THE YEARS ENDED
                        DECEMBER 31, 2000, 1999 AND 1998

<TABLE>
<CAPTION>
                                                                  2000                      1999                       1998
                                                              -----------               -----------                -----------
<S>                                                           <C>                       <C>                        <C>
Trust Corpus, Beginning of Period                             $53,087,803               $58,820,498                $64,315,517
Distributable Income                                            9,776,735                 8,561,984                  9,422,675
Distributions Paid or Payable to Unitholders                   (9,776,735)               (8,561,984)                (9,422,675)
Amortization of Net Profits Interests in
   Gas Properties                                              (5,436,853)               (5,732,695)                (5,495,019)
                                                              -----------               -----------                -----------

Trust Corpus, End of Period                                   $47,650,950               $53,087,803                $58,820,498
                                                              ===========               ===========                ===========
</TABLE>










   THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.


                                      B-5
<PAGE>


                       EASTERN AMERICAN NATURAL GAS TRUST
                          NOTES TO FINANCIAL STATEMENTS

                                   ----------

1.       ORGANIZATION OF THE TRUST:

The Eastern American Natural Gas Trust (the "Trust") was formed under the
Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust
Agreement") among 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"). Effective May 8, 2000 the
Bank of New York acquired the corporate trust business of the Bank of Montreal
Trust Company. As a result, the Bank of New York serves as Trustee (the
"Trustee"). The purpose of the Trust is to acquire and hold net profits
interests owned by Eastern American in 650 producing gas wells and 65 proved
development well locations in West Virginia and Pennsylvania (the "Underlying
Properties"). The Underlying Properties are operated by Eastern American. The
Net Profits Interests (the "Net Profits Interests") consist of a Royalty
interest in 322 wells and a Term interest in the remaining wells and locations.
Eastern American has fulfilled its obligation with respect to the drilling of
the Development Wells.

Four (4) of the remaining six (6) Development Wells were, as previously
disclosed, closely offset by third parties. Since the wells drilled by the third
parties were within 1,000 feet of these Development Wells, Eastern American had
a disagreement with the Trust over Eastern American's obligation to drill these
closely offset Development Wells. The Trust has agreed that, in lieu of drilling
these closely offset Development Wells Eastern American can provide the Trust,
on an annual basis commencing on April 1, 1997, and over the remaining life of
the Trust, a volume of gas which is equal to the projected volumes of the wells
as if they had been drilled. These volumes have been estimated by the Ryder
Scott Company.

The two (2) remaining Development Wells were not drilled because Eastern
American was unable to cure various title defects associated with these wells.
Eastern American advised the Trust that it made a diligent effort to cure title
but was unsuccessful. In West Virginia, an oil and gas well cannot be drilled
unless a full and complete 100% leasehold interest is first obtained. Drilling
an oil and gas well without obtaining the entire leasehold estate would expose
the oil and gas operator and the Trust to a possible suit for trespass. Pursuant
to the Term NPI Conveyance, if the state of title to the drill site to any
Development Well renders such property undrillable in the good faith opinion of
Eastern American under the Reasonably Prudent Operator Standard then such drill
site(s) shall be construed as a Development Well(s). Consequently, Eastern
American has fulfilled its commitment to the Trust to drill the required number
of Development Wells.


                                      B-6
<PAGE>


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
(see Note 6). Of the net proceeds from such offering, $27,787,820 was used
to purchase $118,000,000 in face amount of Treasury Obligations and
$93,162,180 was paid to Eastern American 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 properties subject to the
Net Profits Interests. The Trust Agreement provides, among other things,
that the Trust shall not engage in any business or commercial activity or
acquire any asset other than the Net Profits Interests initially conveyed to
the Trust; the Trustee may establish a reserve for payment of any liability
which is contingent, uncertain in amount or that is not currently due and
payable; the Trustee is authorized to borrow funds required to pay
liabilities of the Trust, provided that such borrowings are repaid in full
prior to further distributions to Unitholders; and the Trustee will make
quarterly cash distributions to Unitholders from funds of the Trust.

2.       SIGNIFICANT ACCOUNTING POLICIES:

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

BASIS OF ACCOUNTING:

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

CASH:

Cash consists of highly liquid instruments with maturities at the time of
acquisition of three months or less.


                                      B-7
<PAGE>


NET PROFITS INTERESTS IN GAS PROPERTIES:

The Net Profits Interests in gas properties are periodically assessed to
determine whether their net capitalized cost is impaired. 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 discounted
future net revenues attributable to proved gas reserves of the Underlying
Properties. Any such writedown would not reduce distributable income, although
it would reduce Trust Corpus.

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

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

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

REVENUES AND EXPENSES:

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

The Trust uses the accrual basis to recognize revenue, with royalty income
recorded as reserves are extracted from the Underlying Properties and sold.
Expenses are also recognized on an accrual basis. Operating expense which
include taxes on production and an Operating Cost Charge are recognized as
incurred pursuant to the Conveyances on a per well production basis. The payment
provisions of the gas purchase contract between the Trust and Eastern Marketing
Corporation 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.


                                      B-8
<PAGE>


USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS:

The preparation of financial statements requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.

SEGMENT INFORMATION:

In 1998, the Trust adopted SFAS 131, "Disclosure about Segments of an Enterprise
and Related Information." The Trust's sole activity is earning royalty income
from gas properties and, consequently, the Trust has only one operating segment,
net profits interests in gas properties. Substantially all of the Trust's net
profits interests are located in the Appalachian region.

3.       INCOME TAXES:

Tax counsel to the Trust advised the Trust at the time of formation that, under
then current tax laws, the Trust would be classified as a grantor trust for
federal and state income tax purposes and, therefore, would not be subject to
taxation at the Trust level. The Trust continues to be tax exempt. Accordingly,
no provision for federal or state income taxes has been made. However, the
opinion of tax counsel is not binding on taxing authorities.

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

4.       DISTRIBUTIONS TO UNITHOLDERS:

The Trustee determines for each quarter the amount available for distribution to
the Unitholders. Such amount will be equal to the excess, if any, of the cash
received by the Trust, on or before the tenth day of the third month following
the end of each calendar quarter ending prior to the dissolution of the Trust,
from the Net Profits Interests then held by the Trust attributable to production
during such quarter, plus, with certain exceptions, any other cash receipts of
the Trust during such quarter, over the liabilities of the Trust paid during
such quarter, subject to adjustments for changes made by the Trustee during such
quarter in any cash reserves established for the payment of contingent or future
obligations of the Trust. Cash received by the Trustee in a particular quarter
from the Net Profits Interests will reflect actual gas production for a portion
of such quarter and a production estimate for the remainder of such quarter,
such estimate to be adjusted to actual production in the following quarter.

Net proceeds receivable included in the Statement of Assets, Liabilities and
Trust Corpus as of December 31, 2000 and December 31, 1999 were received by the
Trust and distributed to the Unitholders on March 15, 2001 and March 15, 2000,
respectively.


                                      B-9
<PAGE>


5.       RELATED PARTY TRANSACTIONS:

The Trust is responsible for paying all legal, accounting, engineering and stock
exchange fees, printing costs and other administrative expenses incurred at the
direction of the Trustee. The total of all Trustee fees and Trust administrative
expenses was $259,848 for the year ended December 31, 2000, $214,773 for the
year ended December 31, 1999, and $215,521 for the year ended December 31, 1998.
In accordance with the Trust Agreement, the Trustee pays Eastern American an
annual fee which increases by 3.5% per year, payable quarterly, to reimburse
Eastern American for overhead expenses. The initial fee at the inception of the
Trust was $210,000. The Trustee paid Eastern American $267,180, $258,144 and
$249,416 for overhead expenses for 2000, 1999 and 1998 respectively. Operating
cost charges included in the Statement of Distributable Income are paid to
Eastern American.

Gas production attributable to the Net Profits Interests is purchased from the
Trust by Eastern Marketing Corporation ("Eastern Marketing"), a wholly owned
subsidiary of Eastern American, pursuant to a Gas Purchase Contract which
effectively commenced as of January 1, 1993 and expires upon the termination of
the Trust.

Pursuant to the Gas Purchase Contract, Eastern Marketing is obligated to
purchase such gas production at a purchase price per Mcf equal to the greater of
the Index Price, as defined below, and the Floor Price, as defined below, for
gas produced in any quarter during the Primary Term, which ended December 31,
1999. Effective January 1, 2000, Eastern Marketing is obligated to purchase such
gas production at a purchase price per Mcf equal to the Index Price for gas
produced in any quarter after the Primary Term.

The Index Price for any quarter subsequent to the Primary Term, which expired
December 31, 1999, is determined solely by reference to the Variable Price
component, as defined below. Prior to December 31, 1999, the Index Price for any
quarter was a weighted average price determined by reference to the Fixed Price
component, which was given a 66 2/3% weighting and a Variable Price component,
which was given a 33 1/3% weighting during the Primary Term. The Fixed Price,
which escalated 5% per year during the Primary Term, was equal to $3.39 per Mcf
for calendar year 1998 and $3.56 per Mcf for 1999. The Variable Price for any
quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus
$0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu
content. The Henry Hub Average Spot Price is defined as the price per MMBtu
determined for any calendar quarter equal to the price obtained with respect to
each of the three months in such quarter, in the manner specified below, and
then taking the average of the prices determined for each of such three months.
The price determined for any month of such quarter is equal to the average of
(i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts
(as defined), as reported in THE WALL STREET JOURNAL, for such contracts which
expired in each of the five months prior to such month, (ii) the final
settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in
THE WALL STREET JOURNAL, for such contracts which expire during such month and
(iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts
determined as of the contract settlement date for such month, as reported in THE
WALL STREET JOURNAL, for such contracts which expire in each of the six months
following such month. A Henry Hub Gas Futures Contract is defined as a gas
futures contract for gas to be delivered to the Henry Hub which


                                      B-10
<PAGE>


is traded on the New York Mercantile Exchange. Due to the increased variable
nature of the Index Price, future revenues can be more volatile in response to
changes in market conditions than in prior years.

Under a standby performance agreement Eastern American has agreed to make
payments under the Gas Purchase Contract to the extent such payments are not
made by Eastern Marketing.

6.       TREASURY OBLIGATIONS:

The Treasury Obligations are directly owned by the Unitholders and are not part
of the Trust Corpus. The Treasury Obligations are on deposit with the Trustee
pursuant to the Deposit Agreement.

The high and low closing prices of the Treasury Obligations, which have a $1,000
face principal amount, as quoted in the over-the-counter market for United
States Treasury Obligations, are as follows:

<TABLE>
<CAPTION>
                                                       HIGH              LOW
                                                     -------          -------
<S>                                                  <C>              <C>
       Quarter ended March 31, 1998                  $431.88          $395.43
       Quarter ended June 30, 1998                    456.29           425.35
       Quarter ended September 30, 1998               477.93           422.89
       Quarter ended December 31, 1998                487.34           443.40

       Quarter ended March 31, 1999                  $481.88          $429.45
       Quarter ended June 30, 1999                    448.70           407.50
       Quarter ended September 30, 1999               428.40           407.80
       Quarter ended December 31, 1999                425.30           401.10

       Quarter ended March 31, 2000                  $443.70          $396.70
       Quarter ended June 30, 2000                    454.70           420.40
       Quarter ended September 30, 2000               474.10           447.80
       Quarter ended December 31, 2000                515.50           460.90
</TABLE>

  On December 31, 2000, 1999 and 1998, the closing price of the Treasury
  Obligations, as quoted on such market, was $509.90, $403.30 and $462.23,
  respectively.

The Trust provides Unitholders with the option to separate the related Treasury
Obligation from the Trust Units. Upon exercising this option, the Unitholder
receives the current value of the Treasury obligation. As of December 31, 2000
and 1999, this option was exercised on Trust Units of 235,100 and 2,000
respectively.


                                      B-11
<PAGE>


7.       SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED):

Information regarding estimates of the proved gas reserves attributable to the
Trust are based on reports prepared by independent petroleum engineering
consultants. Such estimates were prepared in accordance with guidelines
established by the Securities and Exchange Commission. Accordingly, the
estimates were based on existing economic and operating conditions. Numerous
uncertainties are inherent in estimating reserve volumes and values and such
estimates are subject to change as additional information becomes available.

The reserves actually recovered and the timing of production of these reserves
may be substantially different from the original estimates.

The standardized measure of discounted future net cash flows was determined
based on reserve estimates prepared by the independent petroleum engineering
consultants. Fixed gas prices were used during the Primary Term, which ended
December 31, 1999. The gas prices used thereafter are based solely on the fourth
quarter 2000 Variable gas price component.

The reserves and revenue values for the Underlying Properties transferred to the
Trust were estimated from projections of reserves and revenue values
attributable to the combined Eastern American and Trust interests in these
properties. Reserve quantities are calculated differently for the Net Profits
Interests because such interests do not entitle the Trust to a specific quantity
of gas but to 90 percent of the Net Proceeds derived therefrom. Accordingly,
there is no precise method of allocating estimates of the quantities of proved
reserves between those held by the Trust and the interests to be retained by
Eastern American. For purposes of this presentation, the proved reserves
attributable to the Net Profits Interests have been proportionately reduced to
reflect the future estimated costs and expenses deducted in the calculation of
Net Proceeds with respect to the Net Profits Interests. The reserves presented
for the Net Profits Interests reflect quantities of gas that are free of future
costs or expenses. The allocation of proved reserves between the Trust and
Eastern American will vary in the future as relative estimates of future gross
revenues and future costs and expenses vary.

The royalty portion of the Net Profits Interests was calculated beyond the
liquidation date of the Trust (May 15, 2013), even though the terms of the Trust
Agreement require that the Royalty Net Profits Interest will be sold by the
Trustee on or about this date and a liquidating distribution from the sales
proceeds from such sale would be made to the Unitholders. The Term Net Profits
Interests was limited to the 20-year period as defined by the Trust Agreement.


                                      B-12
<PAGE>



The following table reconciles the change in proved reserves attributable to the
Trust's share of the Net Profits Interests ("NPI") from January 1, 1998 to
December 31, 2000:

<TABLE>
<CAPTION>
                                          Royalty            Term             Total
                                            NPI               NPI              NPI
                                           (MMcf)            (MMcf)           (MMcf)
                                           ------            ------           ------

<S>                                        <C>              <C>               <C>
     Balance, January 1, 1998              20,148           17,075            37,223

     Production                            (1,382)          (1,798)           (3,180)
     Revisions of previous estimates       (2,913)          (1,150)           (4,063)
                                           -------          -------           -------

     Balance, December 31, 1998            15,853           14,127            29,980

     Production                            (1,259)          (1,663)           (2,922)
     Revisions of previous estimates         (346)            (178)             (524)
                                          --------         --------          --------

     Balance, December 31, 1999            14,248           12,286            26,534

     Production                            (1,187)          (1,530)           (2,717)
     Revisions of previous estimates        1,922              728             2,650
                                            ------         --------           --------

     Balance, December 31, 2000            14,983           11,484            26,467
                                           ======           ======            ======
</TABLE>














                                      B-13
<PAGE>



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

<TABLE>
<CAPTION>
                                     Royalty            Term             Total
                                       NPI               NPI              NPI
                                     (MMcf)            (MMcf)           (MMcf)
                                     ------            ------           ------


<S>                                  <C>              <C>               <C>
         December 31, 1998           15,853           14,127            29,980
                                     ======           ======            ======

         December 31, 1999           14,248           12,286            26,534
                                     ======           ======            ======

         December 31, 2000           14,983           11,484            26,467
                                     ======           ======            ======
</TABLE>


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves:

The following is the standardized measure of discounted future net cash flows as
of December 31, 2000 (in thousands):

<TABLE>
<CAPTION>
                                                    Royalty          Term               Total
                                                      NPI             NPI                NPI
                                                      ---             ---               ----

<S>                                               <C>               <C>              <C>
         Future cash inflows                      $101,949          $72,235          $174,184
         Future production taxes                    (5,607)          (3,324)           (8,931)
         Future production costs                   (13,127)          (5,131)          (18,258)
                                                   --------          -------         ---------

         Future net cash inflows                    83,215           63,780           146,995
         10% discount factor                       (48,141)         (24,134)          (72,275)
                                                  --------          --------        ---------
         Standardized measure of discounted
            future net cash flows                  $35,074          $39,646           $74,720
                                                   =======          =======           =======
</TABLE>




                                      B-14
<PAGE>



The following is the standardized measure of discounted future net cash flows as
of December 31, 1999 (in thousands):

<TABLE>
<CAPTION>
                                                     Royalty             Term             Total
                                                      NPI                NPI               NPI
                                                      ---                ---               ----

<S>                                                  <C>              <C>              <C>
         Future cash inflows                         $61,045          $46,551          $107,596
         Future production taxes                      (3,349)          (2,125)           (5,474)
         Future production costs                     (11,732)          (4,793)          (16,525)
                                                     --------          -------          --------

         Future net cash inflows                      45,964           39,633            85,597
         10% discount factor                         (25,722)         (15,567)          (41,289)
                                                     --------         --------          --------

         Standardized measure of discounted
            future net cash flows                    $20,242          $24,066           $44,308
                                                     =======          =======           =======
</TABLE>

The following is the standardized measure of discounted future net cash flows as
of December 31, 1998 (in thousands):

<TABLE>
<CAPTION>
                                                   Royalty              Term            Total
                                                     NPI                NPI              NPI
                                                     ---                ---              ---

<S>                                                 <C>              <C>              <C>
         Future cash inflows                        $58,099          $46,365          $104,464
         Future production taxes                     (3,188)          (2,126)           (5,314)
         Future production costs                    (11,033)          (4,820)          (15,853)
                                                    --------          -------          --------

         Future net cash inflows                     43,878           39,419            83,297
         10% discount factor                        (24,259)         (15,713)          (39,972)
                                                    --------         --------         ---------

         Standardized measure of discounted
            future net cash flows                   $19,619          $23,706           $43,325
                                                    =======          =======           =======
</TABLE>



                                      B-15
<PAGE>


Changes in Standardized Measure of Discounted Future Net Cash Flows:

The following schedule reconciles the changes during 1998, 1999 and 2000 in the
standardized measure of discounted future net cash flows relating to proved
reserves (in thousands):

<TABLE>
<CAPTION>
                                                                   Royalty            Term        Total
                                                                      NPI              NPI         NPI
                                                                      ---              ---         ---


<S>                                                                   <C>             <C>          <C>
              Standardized measure, January 1, 1998                   $27,598         $32,420      $60,018

              Net proceeds to the Trust                                (4,781)         (4,261)      (9,042)
              Revisions of previous estimates                          (4,210)         (1,662)      (5,872)
              Accretion of discount                                     2,760           3,242        6,002
              Net change in price and production costs                 (3,139)         (2,555)      (5,694)
              Other                                                     1,391          (3,478)      (2,087)
                                                                   ----------        ---------    ---------

              Standardized measure, December 31, 1998                 $19,619         $23,706      $43,325

              Net proceeds to the Trust                                (4,578)         (3,947)      (8,525)
              Revisions of previous estimates                            (579)           (301)        (880)
              Accretion of discount                                     1,962           2,371        4,333
              Net change in price and production costs                  3,280           2,801        6,081
              Other                                                       538            (564)         (26)
                                                                      -------          -------     --------

              Standardized measure, December 31, 1999                 $20,242         $24,066      $44,308

              Net proceeds to the Trust                                (5,829)         (4,468)     (10,297)
              Revisions of previous estimates                           5,426           2,055        7,481
              Accretion of discount                                     2,024           2,407        4,431
              Net change in price and production costs                 15,062          12,405       27,467
              Other                                                    (1,851)          3,181        1,330
                                                                      --------      ---------    ---------

              Standardized measure, December 31, 2000                 $35,074         $39,646      $74,720
                                                                      =======         =======      =======
</TABLE>


                                      B-16
<PAGE>


8.       QUARTERLY FINANCIAL DATA (UNAUDITED):

The following is a summary of royalty income and distributable income declared
per unit by quarter in 2000, 1999 and 1998 (all amounts in thousands except
Distributable income per unit):

<TABLE>
<CAPTION>
         2000                    MAR 31              JUNE 30          SEPT 30         DEC 31        TOTAL
                                 ---------------------------------------------------------------------------

<S>                              <C>                 <C>              <C>            <C>            <C>
Royalty income                    $2,216              $2,577           $3,090         $3,687        $11,570

Distributable income              $1,763              $2,190           $2,639         $3,185        $ 9,777

Distributable income per unit    $0.2988             $0.3712          $0.4473        $0.5398        $1.6571

<CAPTION>
         1999                    MAR 31              JUNE 30          SEPT 30         DEC 31        TOTAL
                                 ---------------------------------------------------------------------------

<S>                              <C>                 <C>              <C>            <C>            <C>
Royalty income                    $2,361              $2,229           $2,636         $2,453        $ 9,679

Distributable income              $2,109              $1,931           $2,453         $2,069        $ 8,562

Distributable income per unit    $0.3574             $0.3274          $0.4157        $0.3507        $1.4512

<CAPTION>
         1998                    MAR 31              JUNE 30          SEPT 30         DEC 31        TOTAL
                                 ---------------------------------------------------------------------------

<S>                              <C>                 <C>              <C>            <C>            <C>
Royalty income                    $2,747              $2,471           $2,525         $2,475        $10,218

Distributable income              $2,745              $2,463           $2,142         $2,073        $ 9,423

Distributable income per unit    $0.4652             $0.4174          $0.3631        $0.3514        $1.5971
</TABLE>


                                      B-17