SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC  20549


                                    FORM 10-K


[X]     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
        ACT  OF  1934  FOR  THE  FISCAL  YEAR  ENDED  JUNE  30,  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 333-29001-01



                          ENERGY CORPORATION OF AMERICA
             (Exact name of registrant as specified in its charter)


                           WEST VIRGINIA   84-1235822
         (State or other jurisdiction of incorporation or organization)
                      (IRS Employer Identification Number)

                      4643 SOUTH ULSTER STREET, SUITE 1100
                             DENVER, COLORADO  80237
              (Address of principal executive offices and zip code)

                                 (303) 694-2667
              (Registrant's telephone number, including area code)



    Securities registered pursuant to Section 12(b) of the Act:          None

    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  [  ]


<PAGE>
Indicate  by  check mark if disclosure of delinquent filers pursuant to Item 405
of the Regulation S-K is not contained herein, and will not be contained, to the
best  of  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  common  stock  held  by non-affiliates of the
registrant:  Class  of  Voting Stock and Number of Shares Held by Non-affiliates
at  September  1,  2000 was 36,450 Shares.  Market Value Held by Non-affiliates:
Unavailable.


The  number  of  shares  of  the  registrant's common stock, par value $1.00 per
share,  outstanding  at  September  1,  2000  was  649,527  shares.



                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE


                                        2
<PAGE>
                          ENERGY CORPORATION OF AMERICA

                                TABLE OF CONTENTS

                                                                            Page
Part  I
    Item  1.     Business . . . . . . . . . . . . . . . . . . . . . . . .      4
    Item  2.     Properties . . . . . . . . . . . . . . . . . . . . . . .     10
    Item  3.     Legal  Proceedings . . . . . . . . . . . . . . . . . . .     10
    Item  4.     Submission of Matters to a Vote of Security Holders . .      10
Part  II
    Item  5.     Market for the Registrant's Common Stock and Related
                 Stockholder Matters . . . . . . . . . . . . . . . . . .      11
    Item  6.     Selected  Financial  Data . . . . . . . . . . . . . . .      11
    Item  7.     Management's  Discussion  and  Analysis  of  Results  of
                 Operations and  Financial  Condition. . . . . . . . . .      11
    Item  8.     Consolidated Financial Statements and Supplementary Data
                    Independent  Auditor's  Report . . . . . . . . . . .      20
                    Balance  Sheets . . . . . . . . . . . . . . . . . .       21
                    Statements  of  Operations . . . . . . . . . . . . .      23
                    Statements  of  Stockholders  Equity . . . . . . . .      24
                    Statements  of  Cash  Flows . . . . . . . . . . . .       25
                    Notes  to  Consolidated  Financial  Statements . . .      26
                    Supplemental  Information on Oil and Gas Producing
                    Activities (Unaudited) . . . . . . . . . . . . . . .      42

    Item  9.     Changes In and Disagreements With Accountants on
                 Accounting and  Financial  Disclosure. . . . . . . . . .     45
Part  III
    Item  10.    Directors  and  Officers  of  Registrant . . . . . . . .     46
    Item  11.    Executive  Compensation. . . . . . . . . . . . . . . . .     49
    Item  12.    Security Ownership of Certain Beneficial Owners
                 and Management . . . .  . . . . . . . . . . . . . . . . .    49
    Item  13.    Certain  Relationships  and  Related  Transactions . . .     51
Part  IV
    Item  14.    Exhibits,  Financial  Statement  Schedules and
                 Reports on Form 8-K. .  . . . . . . . . . . . . . . . . .    54
Part  V
    Signatures . . . . . . . . . .  . . . . . . . . . . . . . . . . . . .     58


     All  defined  terms  under Rule 4-10 (a) of Regulation S-X shall have their
statutorily prescribed meanings when used in this report.  Quantities of natural
gas  are expressed in this report in terms of thousand cubic feet (Mcf), million
cubic  feet  (Mmcf)  or billion cubic feet (Bcf).  Oil is quantified in terms of
barrels  (Bbls),  thousand  barrels (Mbbls) or million barrels (Mmbbls).  Oil is
compared to natural gas in terms of cubic feet of gas equivalent (Mcfe), million
of  cubic  feet equivalent (Mmcfe) or billion cubic feet equivalent (Bcfe).  One
barrel  of  oil is the energy equivalent of six Mcf of natural gas.  A dekatherm
(dth)  is equal to one million British Thermal Units (Btu).  A Btu is the amount
of  heat  required  to  raise  the  temperature of one pound of water one degree
Fahrenheit.  With  respect  to  information  relating  to  the Company's working
interest  in  wells or acreage, "net" oil and gas wells or acreage is determined
by multiplying gross wells or acreage by the Company's working interest therein.
Unless  otherwise  specified,  all  references  to  wells  and  acres are gross.


                                        3
<PAGE>
                                     PART I
                                     ------

                              ITEM 1.     BUSINESS
                              ---------------------

GENERAL
-------

     Energy  Corporation  of  America  (the  "Company")  is  a  privately  held,
integrated  energy  company  primarily  engaged  in the development, production,
transportation  and  marketing  of  natural  gas  and  oil,  primarily  in  the
Appalachian  Basin.  The  Company was formed in June 1993 through an exchange of
shares  with  the  common  stockholders  of  Eastern American Energy Corporation
("Eastern  American").  For the fiscal year ended June 30, 2000, the Company had
total  revenues  from  continuing  operations  of  $101.9  million  and  EBITDAX
(earnings  before  interest,  income  taxes,  impairment  and exploratory costs,
depreciation  and  amortization)  from  continuing  operations  of $4.1 million.

     The  Company   conducts   business   through  its  principal  wholly  owned
subsidiaries,  Eastern  American,  Westech Energy  Corporation  ("Westech")  and
Westech Energy New Zealand ("WENZ").  Eastern American is one of the largest oil
and gas operators in the Appalachian Basin, including  exploration,  development
and production,  and is engaged in the  transportation  and marketing of natural
gas. Westech is involved in oil and gas exploration and development in the Rocky
Mountain  and Gulf Coast  regions of the United  States and  Australia.  WENZ is
involved in oil and gas exploration and development in New Zealand.

     On  December  20,  1999, the Company entered into a stock purchase and sale
agreement, a copy of which was filed on the Company's form 8-K filed January 10,
2000, with Allegheny Energy, Inc., wherein the Company agreed to sell all of the
stock  of  its  wholly  owned  natural gas distribution company, Mountaineer Gas
Company  and  Subsidiaries  ("Mountaineer") for $323 million, which included the
assumption  of  approximately  $100  million  of  debt, ($223 million net to the
Company).  The  sale  was  subject  to regulatory approval by the Securities and
Exchange  Commission pursuant to the Public Utility Holding Company Act of 1935,
the  West  Virginia  Public Service Commission and the Federal Trade Commission.
Upon  receiving all necessary approvals, the sale was finalized August 18, 2000.
The  Company  expects  to  realize pre-tax gain of approximately $165 million on
this  transaction.  The  use of these proceeds are restricted by debt covenants.
See Note 3 to the Consolidated Financial Statements for a complete discussion of
the  transaction.

     The financial  statements  have been  reclassified to exclude the operating
results of Mountaineer from continuing  operations,  and for accounting purposes
to classify such results as discontinued  operations.  The following discussion,
unless otherwise noted, relates only to the Company's continuing operations.

     The  principal  offices of the  Company  are  located at 4643 South  Ulster
Street,  Suite 1100,  Denver,  Colorado 80237, and the telephone number is (303)
694-2667.

     As used herein the  "Company"  refers to the Company alone or together with
one or more of its subsidiaries, excluding Mountaineer.

SEGMENT  INFORMATION
--------------------

     The  Company's principal businesses constitute two operating segments.  For
financial  information  on  these  segments,  see  Note  16  to the Consolidated
Financial  Statements.


                                        4
<PAGE>
GAS  AND  OIL  EXPLORATION  AND  PRODUCTION
-------------------------------------------

     The  Company's proved net gas and oil reserves are estimated as of June 30,
2000 at 157 Bcf and 983 Mbbls, respectively.  For the fiscal year ended June 30,
2000,  the  Company's  net  gas production was approximately 7.4 Bcf and net oil
production  was  approximately  113  Mbbls,  for  a  total  of  8.1  net  Bcfe.

REGIONAL  OPERATIONS
--------------------

     APPALACHIAN  BASIN.  Eastern American holds interests in 4,440 gross (2,756
     ------------------
net)  wells in the Appalachian Basin and serves as operator of substantially all
of  such wells in which it has a working interest.  The Company's proved gas and
oil  reserves  attributable to its Appalachian Basin properties are estimated as
of June 30, 2000 at 152 Bcfe, of which approximately 97% was gas reserves and 3%
was  oil  reserves.  For  the fiscal year ended June 30, 2000, the Company's gas
production  from its Appalachian Basin properties was approximately 7.3 net Bcf.
In  the  Appalachian  Basin,  the Company has interests in approximately 573,196
gross acres (448,663 net) of producing properties and an additional 79,060 gross
acres (49,367 net) of undeveloped properties located primarily in West Virginia,
Pennsylvania  and  Ohio.  During  fiscal 2000, the Company drilled 16 successful
gross  wells (13.1 net) and recompleted 27 gross wells (26 net), which added 2.6
net  Bcfe  in  reserves.  The Company also acquired several existing partnership
interests  during  fiscal  2000.  The  acquired  producing  properties  added
approximately 9 net Bcfe in reserves.  The Company's drilling program for fiscal
year  2001,  within this Basin, contemplates drilling 8 gross exploratory wells,
71  gross  development  wells  and  27  gross  recompletion  wells.

     WESTERN  BASINS  AND  GULF  COAST.  Westech  owns developed and undeveloped
     ---------------------------------
leasehold  interests  in approximately 573,000 gross acres (342,000 net) located
in  the  Rocky Mountain and Gulf Coast areas.  This year, the Company drilled 14
exploratory  wells in the Powder River and Williston Basins, with one commercial
success  in  the  Powder  River  Basin.  The  fiscal  year 2001 drilling program
includes  two  development  wells in the Powder River Basin and four exploratory
wells  on  newly  acquired  acreage  holdings  in  the  Gulf  Coast.

     INTERNATIONAL.  WENZ  currently  operates  three  offshore  permits and six
     -------------
onshore  permits  on  the  North Island of New Zealand, totaling 6,114,000 gross
acres  (3,061,000  net).  The Tuhara 1 well was re-entered on the East Coast and
is  currently  suspended  until further drilling is undertaken with the Tuhara 2
well.  A total of 600 square km of 3-D seismic was acquired and evaluated on the
East Coast of New Zealand.  3-D seismic totaling 43.2 square km was acquired and
evaluated  on  the  West  Coast  permits.  Technical  evaluation  also  included
reprocessing of 750 km of offshore and 71 km of onshore 2-D data.  During fiscal
year  2001,  WENZ  plans  to  drill  four onshore exploratory wells, one onshore
appraisal  well  and  three  offshore  wells.  The Company's plans regarding the
funding  for  drilling  the  three  offshore  wells are incomplete at this time.
Drilling  costs,  net  to  the  Company,  are estimated at $10-$15 million.  The
Company's  options include funding the entire costs through internal or external
(borrowed)  funds, farming out a portion or all of its interests, or terminating
the  applicable  government  license.

     The  Company  participated  in  two  exploratory wells in the Cooper Basin,
Queensland,  Australia,  which  were  non-commercial.  The contractual agreement
lead  to  a small working interest in another well that will generate short-term
revenue  at  the  current  higher  oil  prices.

OIL  AND  GAS  RESERVES
-----------------------

     The following information relating to estimated reserve quantities, reserve
values  and discounted future net revenues is derived from, and qualified in its
entirety  by reference to, the more complete reserve and revenue information and
assumptions  included  in  the Company's Supplemental Oil and Gas Disclosures at
Item  8.  The Company's estimates of proved reserve quantities of its properties
have  been  subject  to  review  by  Ryder  Scott Company, independent petroleum
engineers.  There  are  numerous uncertainties inherent in estimating quantities
of  proved  reserves  and  projecting  future  rates of production and timing of
development  expenditures.  The  following  reserve  information  represents


                                        5
<PAGE>
estimates  only  and  should  not  be  construed as being exact.  Future reserve
values  are based on year-end prices except in those instances where the sale of
gas  and oil is covered by contract terms providing for determinable escalation.
Operating  costs,  production  and ad valorem taxes and future development costs
are  based  on  current  costs  with  no  escalations.

The  following  table  sets  forth  the  Company's  estimated  proved and proved
developed  reserves  and  the  related  estimated  future  value, as of June 30:

<TABLE>
<CAPTION>
                                                  2000      1999      1998
                                                --------  --------  --------
<S>                                             <C>       <C>       <C>
 Net proved:
   Gas (Mmcf)                                    157,490   148,587   152,780
   Oil (Mbbls)                                       983       959     1,332
   Total (Mmcfe)                                 163,388   154,341   160,772

 Net proved developed:
   Gas (Mmcf)                                    141,067   126,962   122,255
   Oil (Mbbls)                                       738       714       735
   Total (Mmcfe)                                 145,495   131,246   126,665

 Estimated future net cash flows
   before income taxes (in thousands)           $427,414  $252,192  $261,798
 Present Value of estimated future net cash
   flows after income taxes (in thousands) (1)  $124,871  $ 84,883  $ 74,913

<FN>
 _______________
 (1)  Discounted  using  an  annual  discount  rate  of  10%.
</TABLE>

     The  following table sets forth the Company's estimated proved reserves and
the  related  estimated  future  value  by  region,  as  of  June  30,  2000:

<TABLE>
<CAPTION>
                           Present Value
                     ========================                            Natural Gas
                       Amount                   Oil & NGLs  Natural Gas  Equivalent
    Region          (thousands)        %         (Mbbls)       (Mmcf)     (Mmcfe)
------------------  ------------  -----------  ------------  -----------  --------
<S>                 <C>           <C>          <C>           <C>          <C>
 Appalachian Basin  $    117,264        93.9%           788      147,661   152,389
 Rocky Mountains           1,937         1.6%           195          193     1,363
 New Zealand               5,670         4.5%             -        9,636     9,636
                    ------------  -----------  ------------  -----------  --------
 Total              $    124,871       100.0%           983      157,490   163,388
                    ============  ===========  ============  ===========  ========
</TABLE>

PRODUCING  WELLS
----------------

     The  following  table sets forth certain information relating to productive
wells  at  June 30, 2000.  Wells are classified as oil or gas according to their
predominant  production  stream.


                                        6
<PAGE>
<TABLE>
<CAPTION>
                           Gross Wells                 Net Wells
                    =========================  ===========================
                      Oil      Gas     Total     Oil      Gas      Total
                    -------  -------  -------  -------  -------  ---------
<S>                 <C>      <C>      <C>      <C>      <C>      <C>
 Appalachian Basin       17    4,423    4,440      5.4  2,750.6  2,756.0
 Rocky Mountains         11        -       11      4.2        -      4.2
                    -------  -------  -------  -------  -------  ---------
 Total                   28    4,423    4,451      9.6  2,750.6  2,760.2
                    =======  =======  =======  =======  =======  =========
</TABLE>

ACREAGE
-------

     The  following table sets forth the developed and undeveloped gross and net
acreage  held  at  June  30,  2000  (in  thousands).

<TABLE>
<CAPTION>
                                  Developed       Undeveloped
                                    Acreage        Acreage
                                 ============  ================
                                 Gross   Net    Gross     Net
                                 -----  -----  -------  -------
<S>                              <C>    <C>    <C>      <C>
 Appalachian Basin               573.2  448.7     79.1     49.4
 Rocky Mountains and Gulf Coast    0.1    0.1    572.8    341.6
 New Zealand                         -      -  6,114.0  3,061.0
                                 -----  -----  -------  -------
 Total                           573.3  448.8  6,765.9  3,452.0
                                 =====  =====  =======  =======
</TABLE>

     The  following  table  sets forth certain production data and average sales
prices  attributable  to  the  Company's properties for the years ended June 30:

<TABLE>
<CAPTION>
                                    2000    1999    1998
                                   ------  ------  ------
<S>                                <C>     <C>     <C>
 Production Data:
   Oil (Mbbls)                        113     133     125
   Natural gas (Mmcf)               7,399   7,184   7,266
   Natural gas equivalent (Mmcfe)   8,079   7,979   8,018
 Average Sales Price:
   Oil per Bbl                     $21.64  $10.95  $15.30
   Natural gas per Mcf             $ 2.81  $ 2.20  $ 2.42
</TABLE>

DRILLING  ACTIVITIES
--------------------

     The Company's gas and oil exploratory and developmental drilling activities
are  as follows for the years ended June 30.  The number of wells drilled refers
to  the number of wells commenced at any time during the respective fiscal year.
A  well  is  considered productive if it justifies the installation of permanent
equipment  for  the  production  of  gas  or  oil.


                                        7
<PAGE>
<TABLE>
<CAPTION>
                         2000          1999         1998
                      ===========  ===========  ===========
                      Gross  Net   Gross  Net   Gross  Net
                      -----  ----  -----  ----  -----  ----
<S>                   <C>    <C>   <C>    <C>   <C>    <C>
 Development:
     Productive
         Appalachian   15.0  12.6   19.0  15.0   24.0  17.4
         Other            -     -    3.0   0.7    5.0   0.5
                      -----  ----  -----  ----  -----  ----
      Total            15.0  12.6   22.0  15.7   29.0  17.9
                      =====  ====  =====  ====  =====  ====

     Nonproductive
         Appalachian      -     -    2.0   1.6    3.0   1.8
         Other            -     -    3.0   1.3    1.0   0.2
                      -----  ----  -----  ----  -----  ----
     Total                -     -    5.0    2.9   4.0   2.0
                      =====  ====  =====  ====  =====  ====
 Exploratory:
     Productive
         Appalachian    1.0   0.5    8.0   3.8    6.0   2.6
         Other          3.0   1.5    2.0   0.7    4.0   0.9
                      -----  ----  -----  ----  -----  ----
      Total             4.0   2.0   10.0   4.5   10.0   3.5
                      =====  ====  =====  ====  =====  ====

     Nonproductive
         Appalachian      -     -    3.0   1.7    5.0   2.6
         Other         15.0   8.3    7.0   3.2   12.0   4.2
                      -----  ----  -----  ----  -----  ----
     Total             15.0   8.3   10.0   4.9   17.0   6.8
                      =====  ====  =====  ====  =====  ====
</TABLE>

COMPETITION
-----------

     The  Company  encounters  substantial  competition in acquiring properties,
marketing  oil  and  gas,  securing  equipment  and  personnel and operating its
properties.  The  competitors  in  acquisitions,  development,  exploration  and
production  include  major  oil  companies,  numerous  independent  oil  and gas
companies,  gas  marketers,  individual  proprietors  and others.  Many of these
competitors have financial and other resources, which substantially exceed those
of  the  Company  and have been engaged in the energy business for a much longer
time  than  the  Company.  Therefore,  competitors  may  be able to pay more for
desirable  leases  and  to  evaluate,  bid  for and purchase a greater number of
properties or prospects than the financial or personnel resources of the Company
will  permit.

     Natural  gas  competes  with  other forms of energy available to customers,
primarily  based on price.  These alternate forms of energy include electricity,
coal  and  fuel  oils.  Changes  in  the availability or price of natural gas or
other  forms  of  energy,  as  well  as  business  conditions,  conservation,
legislation, regulations and the ability to convert to alternate fuels and other
forms  of  energy  may  affect  the  demand  for  natural  gas.

REGULATIONS  AFFECTING  OPERATIONS
----------------------------------

     The  Company's  operations are affected by extensive regulation pursuant to
various  federal,  state  and  local  laws  and  regulations  relating  to  the
exploration  for  and  development,  production,  gathering,  marketing,
transportation  and  storage  of  oil  and  gas.  These regulations, among other
things, can affect the rate of oil and gas production.  The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the  discharge  of  materials  into  the  environment  or  otherwise relating to
environmental  protection.


                                        8
<PAGE>
These  laws and regulations require the acquisition of a permit before drilling
commences,  restricts  the  types,  quantities  and  concentration  of  various
substances that can be released into the environment in connection with drilling
activities  on  certain  lands  lying  within  wilderness,  wetlands  and  other
protected  areas,  and  impose substantial liabilities for pollution which might
result  from  the  Company's  operations.


GAS  AGGREGATION  AND  MARKETING
---------------------------------

     The  Company,  primarily  through  the  wholly  owned subsidiary of Eastern
American,  Eastern  Marketing  Corporation  ("Eastern  Marketing"),  aggregates
natural  gas  through  the  purchase  of  production  from  properties  in  the
Appalachian  Basin  in  which  the  Company has an interest, the purchase of gas
delivered  through  the Company's gathering pipelines located in the Appalachian
Basin, the purchase of gas from smaller Appalachian Producers that are not large
enough  to  have  marketing  departments,  the  purchase  of gas produced in the
Southwestern areas of the United States pursuant to contractual arrangements and
the  purchase  of  gas  in  the spot market.  The Company sells gas to local gas
distribution companies, industrial end users located in the Northeast, other gas
marketing  entities  and  into the spot market for gas delivered into interstate
pipelines.  The  Company has historically attempted to balance its gas sales mix
with  approximately  one-third of its total gas sales being made under long term
contracts  (contracts  with  terms  of five years or more), one-third being sold
under  intermediate  term contracts (contracts with terms of one to five years),
and  one-third  being  sold  under short term contracts (contracts with terms of
less  than  one  year)  or  on  a  spot  market basis.  The demand for long term
contracts  has  decreased  substantially  and  no  new  long term contracts were
entered  into  in  fiscal year 2000.  Volumes that became available from expired
long  term  contracts  were  sold under intermediate and short term contracts.

     The  Company owns and operates approximately 2,100 miles of gathering lines
and  intrastate  pipelines  that are used in connection with its gas aggregation
and  marketing  activities.  In addition, the Company has entered into contracts
with interstate and intrastate pipeline companies that provide it with rights to
transport  specified  volumes of natural gas.  During the fiscal year ended June
30,  2000,  the  Company  aggregated and sold an average of 95.7 Mmcf of gas per
day,  of  which  39.7  Mmcf per day represented sales of gas produced from wells
operated  by  the  Company.  This  represents a decrease compared to fiscal year
1999,  during  which the Company aggregated and sold an average of 129.5 Mmcf of
gas  per  day.

GAS  SALES  AND  PURCHASE  CONTRACTS
-------------------------------------

     The  Company  satisfied its obligations under all gas sales contracts (23.0
Bcf  in  fiscal  year  2000)  through  gas  production  attributable  to its own
interests in oil and gas properties and through production attributable to third
party  interests  in  oil and gas properties (14.1 Bcf in fiscal 2000), and from
natural  gas aggregated by the Company pursuant to its aggregation and marketing
activities  from  third  parties  (8.9  Bcf  in  fiscal  2000).

     Eastern  American  has a gas sales contract with Hope Gas, Inc. ("Hope"), a
subsidiary  of  Dominion  Energy,  which requires Eastern American to sell up to
4,000 but not less than 1,500 Mmbtu per day during the winter months of November
through  March  to  Hope  through December 31, 2001.  Pricing under the contract
requires  Hope  to  pay  Eastern  American  a  ten cent premium above the posted
Appalachian  Index.


                                        9
<PAGE>
     In  March 1993, Eastern Marketing entered into a gas purchase contract with
the Eastern American Natural Gas Trust (the "Royalty Trust") to purchase all gas
production  attributable to the Royalty Trust until its termination in May 2013.
The  purchase  price  under this gas purchase contract through December 1999 was
based  in  part  on  an  escalating  fixed  price  component of $3.39 per Mcf in
calendar  year  1999  and  $3.56  per Mcf in calendar year 2000 and in part on a
Henry  Hub  based  variable  price component, which fluctuated with certain spot
market  prices, provided that the purchase price during such period was not less
than  a  specified  floor price of $2.84 per Mcf in calendar year 1999 and $3.09
per  Mcf  in  calendar year 2000.  Beginning in January 2000, the purchase price
under  this  gas  purchase  contract  is  determined  solely by reference to the
variable price component without regard to any minimum purchase price.  See Note
13,  for  further  discussion.

REGULATIONS  AFFECTING  MARKETING  AND  TRANSPORTATION
------------------------------------------------------

     As  a  marketer  of natural gas, the Company depends on the transportation
and  storage  services  offered  by  various  interstate and intrastate pipeline
companies  for the delivery and sale of its own gas supplies as well as those it
processes and/or markets for others.  Both the performance of transportation and
storage services by interstate pipelines and the rates charged for such services
are  subject  to  the jurisdiction of the FERC.  In addition, the performance of
transportation  and  storage  services  by  intrastate  pipelines  and the rates
charged  for  such  services are subject to the jurisdiction of state regulatory
agencies.

EMPLOYEES
---------

     As of June 30, 2000, the Company had approximately 215 full-time employees.
None  of  the  employees  were  covered  by  a  collective bargaining agreement.
Management  believes  that  its  relationship  with  its  employees  is  good.


                             ITEM 2.     PROPERTIES
                             ----------------------

     See  Item  1. Business, for information concerning the general location and
characteristics  of  the important physical properties and assets of the Company
and information regarding production, reserves, development and interests in oil
and  gas  producing  properties  of  the  Company.


                          ITEM 3.     LEGAL PROCEEDINGS
                          -----------------------------

     The  Company is involved in various legal actions and claims arising in the
ordinary  course  of  business.  While the outcome of these lawsuits against the
Company  cannot  be  predicted  with certainty, management does not expect these
matters  to  have  a  material  adverse  effect  on  the Company's operations or
financial  position.


         ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
         ---------------------------------------------------------------

     One  matter  was  submitted to a vote of security holders during the fourth
quarter  of fiscal year 2000 by Eastern Systems Corporation, a subsidiary of the
Company,  concerning  the  sale  of all the outstanding stock of Mountaineer Gas
Company  to  Allegheny  Energy,  Inc.,  dated  June  13,  2000.


                                       10
<PAGE>
                                     PART II
                                     -------

              ITEM 5.     MARKET FOR THE REGISTRANT'S COMMON STOCK
              ----------------------------------------------------
                         AND RELATED STOCKHOLDER MATTERS
                         -------------------------------

     The  Company's  common  stock  is  not  traded  in  a public market.  As of
September  1,  2000,  the  Company had 31 holders of record of its common stock.

     The  Company  declared dividends in fiscal years 2000, 1999 and 1998 of $0,
$644,505  and  $1,131,000,  respectively.

                       ITEM 6.     SELECTED FINANCIAL DATA
                       -----------------------------------

<TABLE>
<CAPTION>
  (Dollars in thousands, except per share items)
                                                          Year Ended June 30,
                                         -----------------------------------------------------
                                           2000       1999       1998       1997       1996
                                         ---------  ---------  ---------  ---------  ---------
<S>                                      <C>        <C>        <C>        <C>        <C>
 Operating revenue                       $101,919   $113,500   $193,459   $189,070   $180,828
 Loss from continuing operations          (26,508)   (27,099)    (3,773)    (4,086)    (3,324)
 Loss from continuing operations
    Per common share, basic and diluted    (40.11)    (40.27)     (5.67)     (5.94)     (4.75)
 Total assets                             265,691    286,077    290,541    302,446    273,627
 Long term debt                           212,575    219,886    201,507    200,089    159,647
 Dividends declared per common share     $      -   $   0.95   $   1.70   $   1.50   $   2.10
</TABLE>

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

     The  following  should  be read in conjunction with the Company's Financial
Statements  and  notes  (including  the  segment  information) at Item 8 and the
Selected  Financial  Data  at  Item  6.

     This  discussion  and  analysis  of  financial  condition  and  results  of
operations,  and  other  sections  of  this  Form  10-K, contain forward-looking
statements  that  are  based  on  management's  beliefs,  assumptions,  current
expectations,  estimates  and  projections  about  the oil and gas industry, the
economy  and  about the Company itself.  Words such as "anticipates," believes,"
"estimates,"  "expects,"  "forecasts,"  "intends,"  "is  likely,"  "plans,"
"predicts,"  "projects,"  variations  of  such words and similar expressions are
intended  to identify such forward-looking statements.  These statements are not
guarantees  of  future  performance and involve certain risks, uncertainties and
assumptions  that  are  difficult  to  predict  with  regard  to timing, extent,
likelihood and degree of occurrence.  Therefore, actual results and outcomes may
materially  differ  from  what  may  be  expressed  or  forecasted  in  such
forward-looking  statements.  Furthermore,  the Company undertakes no obligation
to  update,  amend or clarify forward-looking statements, whether as a result of
new  information,  future  events  or  otherwise.

     Important factors that could cause actual results to differ materially from
the  forward-looking  statements  include,  but  are  not  limited  to,  weather
conditions, changes in production volumes, worldwide demand and commodity prices
for  petroleum natural resources, the timing and extent of the Company's success
in  discovering,  acquiring,  developing  and  producing  oil  and  natural  gas
reserves,  risks  incident  to the drilling and operation of oil and natural gas
wells,  future  production  and  development  costs,  the effect of existing and
future  laws, governmental regulations and the political and economic climate of
the  United  States  and  New  Zealand,  the  effect  of hedging activities, and
conditions  in  the  capital  markets.


                                       11
<PAGE>
COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2000 AND 1999
--------------------------------------------------------------------------------

     The Company recorded a net loss from continuing operations of $26.5 million
for the year ended June 30, 2000 compared to a net loss of $27.1 million for the
same period in 1999.  The increase in income of $0.6 million is attributed to an
$11.6  million  decrease  in  revenue,  a  $5.3  million  decrease  in operating
expenses,  a  $10.9 million decrease in impairment and exploratory costs, a $2.2
million  increase  to  interest expense, a $0.5 million decrease in other income
and  a  $1.3  million  decrease  in  income  tax  benefits.

     OPERATING  MARGINS.  Operating  Margins  (defined as revenue less operating
     ------------------
costs,  taxes  other  than  income  taxes  and direct general and administrative
expense)  for  the Company's operating subsidiaries totaled $7.8 million for the
current  year compared to $13.4 million for the prior period.  The Company's Oil
and  Gas  Operating Margin (defined as oil and gas sales and well operations and
service  revenues  less  field  operating  expenses, taxes other than income and
direct general and administrative) totaled $10.7 million versus $9.2 million for
the  prior year.  The Company's Marketing and Pipeline Operating Margin (defined
as  gas  marketing  and  pipeline  sales less gas marketing and pipeline cost of
sales)  totaled  a  loss of $2.9 million for the current period versus income of
$4.1  million  for  the  prior  period.

     REVENUES.  Total  revenues  decreased  $11.6  million  or  10.2% during the
     --------
periods.  The  decrease  was  due  to  an  18.4%  decrease  in gas marketing and
pipeline  sales  and  a  9.9% decrease in well and service operations, which was
partially  offset  by  a  30.5%  increase  in  oil  and  gas  sales.

     Revenues from gas  marketing  decreased  $18.6  million and pipeline  sales
increased $2.3 million,  for a net decrease of $16.3 million from $88.5 million,
during the period ended June 30, 1999, to $72.2 million in the period ended June
30, 2000. The decrease in revenue is primarily  attributable  to a 35.3% decline
in marketed  volumes  from 37.2 Mmbtu at June 30, 1999 to 24.1 Mmbtu at June 30,
2000,  which was partially offset by a 26.1% increase in the average sales price
per  Mmbtu  from  $2.32 to $2.92  for the years  ended  June 30,  1999 and 2000,
respectively.  The decrease in volumes is primarily a result of the  termination
and non-renewal of marketing contracts as they expire.

     Revenues from well and service operations  decreased $0.6 million from $6.5
million  during the period  ended  June 30,  1999 to $5.9  million in the period
ended June 30, 2000.  The decrease in revenue is primarily  attributable  to the
acquisition of outside owner  interests in Company wells through the acquisition
of partnership interests.

     Revenues  from  oil and gas sales increased $5.6 million from $18.3 million
for  the  period  ended June 30, 1999 to $23.9 million for the period ended June
30, 2000.  The increase in revenue is primarily attributable to a 97.5% increase
in  the  average  oil  sales  price  from  $10.95  to $21.64 per Bbl and a 28.0%
increase in the average gas sales price from $2.20 to $2.81 per Mcf between June
30,  1999  and  June 30, 2000.  Lessening the effect of the higher prices on oil
and  gas  sales  is  a loss on related hedges of $0.8 million for the year ended
June  30,  2000  compared  to  a  loss of $0.1 for the year ended June 30, 1999.
Production  volumes  were  comparable  for  the  two  periods.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses  decreased $5.3
     --------------------
million or 4.6% during this period primarily as a result of an 11.1% decrease in
gas marketing and pipeline costs, which was partially offset by a 32.5% increase
in  general  and  administrative  expenses.  Field and lease operating expenses,
taxes  other  than  income and depreciation, depletion and amortization expenses
remained  relatively  constant  between  the  periods.


                                       12
<PAGE>
     The  $9.4 million decrease to gas marketing costs from $84.4 million during
the  period  ended  June  30, 1999 to $75.0 million in the period ended June 30,
2000,  is  comprised  of a $15.6 million decrease to gas marketing costs, a $1.3
million  increase  to  pipeline costs and a $4.9 million gas purchase commitment
charge  (See Note 13).  The overall decrease to gas marketing costs is primarily
the  result  of a 31.9% decline in purchased gas volumes from 39.8 Mmbtu to 27.1
Mmbtu  from  June 30, 1999 and June 30, 2000, which was partially mitigated by a
25.2% increase in the average price paid for gas purchased, from $2.26 per Mmbtu
to  $2.83  per  Mmbtu  between  the  respective  periods.

     General  and  administrative expense increased $3.3 million, primarily as a
result  of  impairing certain notes receivable issued by a subsidiary of Eastern
American,  relating  to  a  state  tax  incentive program, which had been deemed
uncollectible.  In  addition,  there  were increased profit sharing expenses and
increased  overhead  at  the  corporate  level.

     Impairment  and  exploratory expenses decreased $10.9 million primarily due
to  the  leasehold  and  well  costs  that were written off in fiscal 1999.  The
increase in fiscal year 1999 was due to programmed seismic costs and New Zealand
dry  holes.

     INTEREST  EXPENSE.  Interest  expense increased $2.2 million, primarily due
     -----------------
to  higher  interest  rates  throughout  fiscal  2000.

     OTHER  (INCOME) EXPENSE.  Other income decreased $0.5 million primarily due
     -----------------------
to  the  recognition  of  gains  on  the  sale  of  property during fiscal 1999.

     PROVISION  FOR  INCOME  TAXES.  The benefit for income taxes decreased $1.3
     -----------------------------
million  primarily  because  of  the  increased  income  in  the  current  year.

     DISPOSAL  OF  UTILITY  OPERATIONS.  Net  income for the year ended June 30,
     ---------------------------------
2000 was $8.1 million compared to $12.2 million the previous year, a decrease of
approximately  $4.1  million.  Revenues  for  the  current  year  increased $6.8
million  compared  to the prior year.  Utility revenues increased $10.7 million,
primarily  resulting  from  additional  revenues  provided  as  a  result of the
acquisition  of the West Virginia assets of Shenandoah Gas Company in July 1999.
One other significant change in revenue resulted from one customer changing from
sales  to  transportation service, which resulted in a decrease of $4.9 million,
which  had  no  significant  impact on operating income because it was offset by
reduced  gas  marketing  and  pipeline  costs.  Operating  expenses  increased
approximately  $12.5  million  during  the  current period compared to the prior
year.  This  increase  resulted  from  increased  gas  costs  of  $10.0 million,
partially  offset  by decreased gas marketing and pipeline costs of $4.2 million
(see  above),  and  increases  in  operations  and  maintenance  and general and
administrative  costs  of  $5.1  million.  The  increase  in  gas costs resulted
primarily  from  the  additional  costs  associated  with  Shenandoah  customers
amounting  to $6.8 million and the impact of the gas supply management agreement
amounting to approximately $4.4 million.  Operations and maintenance and general
and  administrative  costs  increased  primarily due to increased profit sharing
expenses  and  increased labor associated costs.  Depreciation expense increased
approximately  $1.0 million, resulting primarily from the addition of the assets
of  Shenandoah  acquired  on  July  1,  1999.  Interest  expense  increased
approximately  $1.7 million, principally the result of an additional $40 million
in  long  term  debt, which was issued in November 1999.  Income taxes decreased
$4.2 million, due to lower income before taxes of $20.1 million in 1999 to $11.8
million  in  the  current  year.


                                       13
<PAGE>
COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1999 AND 1998
--------------------------------------------------------------------------------

     The Company recorded a net loss from continuing operations of $27.1 million
for  the year ended June 30, 1999 compared to a net loss of $3.8 million for the
same  period  in 1998.  The decrease in income of $23.3 million is attributed to
an  $80.0  million  decrease  in  revenue, a $30.4 million decrease in operating
expenses,  an $11.0 million increase in impairment and exploratory costs, a $3.8
million  increase  in  other  income and an $11.1 million increase in income tax
benefits.

     OPERATING  MARGINS.  Operating  Margins  (defined as revenue less operating
     ------------------
costs,  taxes  other  than  income  taxes  and direct general and administrative
expense)  for the Company's operating subsidiaries totaled $13.3 million for the
current  year  compared to $9.0 million for the prior period.  The Company's Oil
and  Gas  Operating Margin (defined as oil and gas sales and well operations and
service  revenues  less  field  operating  expenses, taxes other than income and
direct general and administrative) totaled $9.2 million versus $11.9 million for
the  prior year.  The Company's Marketing and Pipeline Operating Margin (defined
as  gas  marketing  and  pipeline  sales less gas marketing and pipeline cost of
sales) totaled $4.1 million for the current period versus a loss of $2.9 million
for  the  prior  period.

     REVENUES.  Total  revenues  decreased  $80.0  million  or  41.3% during the
     --------
periods.  The decrease was due to a 34.6% decrease in gas marketing and pipeline
sales,  an  11.7%  decrease  in  oil and gas sales and a 99.4% decrease in other
operating  revenue.  Well  and  service  operating  revenue  remained relatively
constant  between  the  periods.

     Revenues from gas marketing and pipeline sales decreased $46.9 million from
$135.3  million  during  the  period ended June 30, 1998 to $88.5 million in the
period  ended  June 30, 1999.  The decrease in revenue is primarily attributable
to  a  12%  decrease  in  the  average  unit price from $2.63 to $2.32 and a 27%
decline  in  marketed  volumes  from 50.7 million Mmbtu at June 30, 1998 to 37.2
million  Mmbtu  at June 30, 1999.  The decrease in volumes is primarily a result
of  the  termination  of  two contracts that accounted for 9.5 Mmbtu and reduced
volumes  associated  with  trading  activities.  See  other  operating  revenue,
discussed  below.

     Revenues  from  oil and gas sales decreased $2.4 million from $20.7 million
for  the  period  ended June 30, 1998 to $18.3 million for the period ended June
30, 1999.  The decrease in revenue is primarily attributable to a 29.7% decrease
in the average oil sales price from $15.30 to $10.95 per Bbl and a 9.1% decrease
in the average gas sales price from $2.42 to $2.20 per Mcf between June 30, 1998
and  June  30,  1999.  The  price  decline  was  partially  offset by production
increasing  6.2%  for  oil  and  1.2%  for  gas.

     Other operating revenues decreased $30.4 million from $30.6 million to $0.2
million  between  the periods.  This was primarily because 1998 included revenue
from  the  termination of a long-term gas delivery contract.  See Note 15 to the
Consolidated  Financial  Statements  for  discussion.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses decreased $52.4
     --------------------
million  or 31.3% during this period primarily as the result of a 38.9% decrease
in  gas  marketing  and  pipeline  costs,  which was partially offset by a 12.0%
increase  in  general  and  administrative  expenses.  Field and lease operating
expenses,  taxes  other than income and depreciation, depletion and amortization
costs  remained  relatively  constant  between  the  periods.

     The $53.8 million decrease in gas marketing and pipeline costs is primarily
the  result  of  a  27% decline in purchased gas volumes from 51.1 Mmbtu to 37.6
Mmbtu  from  June  30,  1998  and June 30, 1999.  Contributing to the decline in
costs was a 15% decrease in the average price paid for gas purchased, from $2.67
per  Mmbtu  to  $2.26  per  Mmbtu between the respective periods.  Additionally,
approximately $2.4 million of purchased gas costs were charged against a reserve
for  losses on future gas purchases, which was primarily related to the contract
settlement.  See  Note  15  to  the  Consolidated  Financial  Statements  for
discussion.


                                       14
<PAGE>
     General  and  administrative  expense increased $1.1 million as a result of
increased  overhead  at  the  corporate  level.

     Impairment  and  exploratory expenses increased $11.0 million primarily due
to  the  current  year cost of drilling exploratory dry holes of $5.9 million in
New  Zealand  and  $1.5  million  domestically.  In addition, approximately $2.2
million  of leasehold and well in progress costs were written off late in fiscal
1999.

     INTEREST  EXPENSE.  Interest  expense  remained relatively constant between
     -----------------
the  periods.

     OTHER  (INCOME) EXPENSE.  Other income increased $3.8 million primarily due
     -----------------------
to the recognition of gains on the sale of property during fiscal 1999, compared
to  losses in the prior year.  In addition, during fiscal 1998 a reserve of $1.1
million  was  established  against  a  note  receivable.

     PROVISION  FOR  INCOME TAXES.  The provision for income taxes changed $11.1
     ----------------------------
million  primarily  because  of  the  increased  current  year  losses.

     DISPOSAL  OF  UTILITY  OPERATIONS.  Net  income for the year ended June 30,
     ---------------------------------
1999  was  $12.2 million compared to $6.8 million the previous year, an increase
of  approximately $5.4 million.  Operating revenues increased approximately $1.2
million  during  the  current  year,  primarily  due to increased sales rates in
accordance  with  Mountaineer's  new  rate  agreement,  which  became  effective
November  1, 1998.  Operating expenses decreased $8.1 million during the current
year,  primarily  driven  by  decreased  gas  purchase  costs as a result of the
initial  effect  of  the  implementation  of Mountaineer's gas supply management
agreement, which went into effect on November 1, 1998.  Slightly offsetting this
decrease  were increased labor associated costs and other miscellaneous costs of
$1.0  million.  Depreciation expense increased primarily due to additions to gas
plant in service and the elimination of a negative acquisition adjustment, which
reduced  expense by approximately $0.5 million in the prior year period.  Income
tax  expense  increased $3.9 million, due to higher income before taxes of $20.1
million  during  the  current  year compared to $10.8 million the previous year.


LIQUIDITY  AND  CAPITAL  RESOURCES
----------------------------------

     The  Company's  financial condition declined during the twelve month period
ended  June 30, 2000 ("current period").  The ratio of current assets to current
liabilities,  excluding  "net utility assets held for sale" of $56.8 million for
the  current period and $70.1 million for the period ended June 30, 1999 ("prior
period"),  decreased  from  1.04:1  at June 30, 1999 to 0.75:1 at June 30, 2000.
Cash  and  cash  equivalents  decreased  from  $12.2  million  to  $3.3 million.

     The  Company's  net  cash  used  by  operating  activities  from continuing
operations decreased from $24.1 million for the prior period to $5.0 million for
the current period.  The primary net uses of cash from continuing operations for
the  current  period versus the prior period were the net losses from continuing
operations  of $(26.5) million and $(27.1) million.  Non-cash charge adjustments
were  inclusive of depreciation, depletion and amortization of $12.5 million and
$12.0  million;  exploration  and  impairment of $6.0 million and $16.8 million;
provision  for  losses  on  notes  receivable  of $1.5 million and $0.4 million.
These  non-cash additions were offset by reduction of deferred revenue of $(2.2)
million  versus  $(2.3)  million  and  deferred  taxes of $(11.1) million versus
$(12.5)  million.  Net  cash  used  by  operating  activities  from  continuing
activities  was  also impacted by net collections in accounts receivable of $0.4
million  for  the  current  period;  decreases in gas in storage and prepaids of
$(0.2) million versus $1.7 million for the prior period; an increase in accounts
payable  $(6.3)  million  for  the  prior  period; increases of $0.9 million and
$(0.3)  million  in  funds held for distribution; and increases in other accrued
expenses  (mainly  income  taxes)  of  $8.8  million and $(11.6) million for the
periods,  respectively.


                                       15
<PAGE>
     The  Company  incurred  a  net cash outflow of $19.2 million from investing
activities  from  continuing  activities  for  the  current period versus a cash
outflow  of  $21.7  million  in  the  prior  period.  The  reduction  in capital
expenditure  activities of $5.9 million was related primarily to reduced oil and
gas  drilling  activities.  An  acquisition of miscellaneous oil and gas limited
partnership  interests  for  $3.0  million  dollars  occurred during the current
period.  The  use  of  cash for investing activities was offset by cash received
from  sales  of  non-core  assets by $0.4 million in the current period and $3.4
million  in  the  prior  period.

     The  Company's  financing  activities  from  continuing  activities  in the
current period resulted in the Company's long term debt balance being reduced by
the  net  payment of $12.8 million.  The Company's revolving credit facility was
paid  in  full  on  August 18, 2000 and the credit agreement was terminated (see
Note  5).  During  the  current  period,  $2.0  million  of  short-term debt was
incurred  for the acquisition of an 85% interest in 68.5 net wells with reserves
of  5.1  Bcf  at a cost of $3.0 million.  In addition, during the current period
the  Company  purchased  $0.4  million  of  treasury  stock  in  discretionary
transactions.  The  financing  activity net cash outflow of $1.1 million for the
current period was reduced primarily from the receipt of $10 million in the form
of  a  cash  prepayment  under  a  gas  sale agreement (see Note 3).  Under this
agreement, the Company will be obligated to begin delivery of certain volumes of
gas  on  July 1, 2001 or repay the monies advanced.  The primary sources of cash
from financing activities in the prior period were long-term borrowings of $27.5
million  offset  by  principal  repayments  on  long-term  debt of $3.1 million,
treasury  stock purchases of $2.2 million and dividend payments of $1.0 million.

     At June 30, 2000, the Company's principal sources of liquidity consisted of
$3.3  million  of  cash,  with  no  amounts  available  under  short-term credit
facilities currently in place.  On August 18, 2000, the Company paid in full the
$19.8 million then outstanding under its revolving line of credit facility.  The
Company  also  gave  notice  of  termination  of  the revolving credit facility,
effective  August  18,  2000.  Presently, the Company has not formally commenced
efforts  to  seek  a replacement for this credit facility.  At June 30, 2000 the
Company had $2 million drawn, the maximum permitted, under an additional line of
credit  facility.

     On  August  18,  2000,  the Company consummated the sale of Mountaineer and
Subsidiary  and  received  pre-tax proceeds of approximately $222.7 million (see
Note  3).  Pursuant  to  the  terms  of  the  Company's  $200  million  Senior
Subordinated  Notes  (the "Notes"), attached as Exhibit 4.3, the Company has the
option within 360 days of receipt of the net proceeds from the sale of the stock
of Mountaineer to apply such proceeds to (a) reduce debt senior to or pari passu
with  the  Notes  (provided  that in connection with the reduction of pari passu
debt,  a  pro  rata portion of the Notes is redeemed); (b) acquire a controlling
interest  in  another business engaged in either natural gas distribution or the
exploration,  development  or  operation  of  oil,  gas  or  other  hydrocarbon
properties  (an  "Energy Business"); (c) make capital expenditures in respect to
the  Company's  or  its  restricted subsidiaries' Energy Business; (d)  purchase
long  term  assets  that  are  used  or  useful  in  the Energy Business; or (e)
repurchase  the  Notes.  If  the  Company  elects  not  to  apply all of the net
proceeds  in accordance with one of the above options within 360 days of receipt
of such proceeds, then with respect to those net proceeds which were not applied
to  one  of  the above options, the Company must make an offer to the holders of
the  Notes,  (and  holders of the pari passu debt, to the extent required by the
terms  of the pari passu debt) to repurchase the maximum principal amount of the
Notes  and  any  pari  passu debt at an offer price in cash equal to 100% of the
principal  amount  thereof, plus accrued and unpaid interest thereon to the date
of  the  purchase.


                                       16
<PAGE>
     It is the intention of the Company to comply with reinvestment requirements
of  the Notes and seek to reinvest such proceeds into Energy Business assets.  A
component  of  the  Company's  reinvestment  strategy  will  be  to  expand  its
exploration  and  development activities, both domestically and internationally.
For fiscal year 2001, the Company plans to invest approximately $42.4 million in
capital projects.  The fiscal year 2001 capital expenditure program contemplates
spending  approximately  $11.7 million on 27 gross (25 net) recompletions and 73
gross  (60.3  net)  development  wells  as well as approximately $2.0 million on
acquisitions  of  producing  properties  primarily in the Appalachian Basin.  In
addition,  the  Company's fiscal year 2001 capital spending program contemplates
spending  approximately  $15.9 million (including estimated completion costs) on
exploratory  drilling projects.  These projects include funding $12.1 million on
domestic  exploration  drilling  opportunities and $3.8 million on international
exploration  drilling  opportunities.  This  funding program assumes drilling 14
gross  (5.9  net) domestic exploration wells and 8 gross (4.6 net) international
exploration  wells.  Other  capital  projects  include  $5.1 million for seismic
studies  and  for  leasehold  acquisitions  plus $7.7 million for infrastructure
projects.

     In  addition  to  the  Company's  exploration  and  development  drilling
activities  associated  with this reinvestment program, the Company will seek to
satisfy  the  reinvestment  requirement  by  engaging in acquisitions of utility
assets  or  oil  and  natural  gas  reserves  and  properties.  There  can be no
assurance  that  the  Company will be able to acquire exploration or development
drilling opportunities or to identify acquisition candidates in the required 360
day  time  period.  Further,  there  can  be  no  assurance  that  the  drilling
activities  associated  with  the  reinvestment  program will achieve commercial
success or that any future acquisitions made by the Company will achieve desired
profitability  objectives.

     Other  than  the  reinvestment  program  described above, the timing of the
Company's  capital expenditures is mostly discretionary with no material capital
expenditure  commitments.  However,  the Company has designated certain projects
as  non-deferrable commitments incurred in the normal course of business.  These
include  certain  drilling obligations, primarily in New Zealand and Texas, that
range  from  $5.9  million  to $8.1 million at June 30, 2000; the annual paydown
requirement,  under  the  Company's  line  of  credit,  which  has  $2.0 million
outstanding  at June 30, 2000; and the satisfaction of the obligations resulting
from  the  draw  down of $10.0 million under the gas purchase and sale agreement
(see Note 3).  Consequently, the Company has a significant degree of flexibility
to  adjust  its  level  of  its  capital  expenditures as circumstances warrant.

     The  Company's  cash  requirements  will  fluctuate based on timing and the
extent  of  the  interplay of the factors discussed above.  Moreover, management
anticipates  that  although projected earnings from continuing operations before
interest  charges,  taxes,  depreciation,  depletion  and  amortization,  and
impairment  and exploratory costs ("EBITDAX") for fiscal year 2001 will increase
to $25.4 million from $4.2 million for the current period, such results will not
be sufficient to fully fund fiscal year 2001 projected interest charges of $20.1
million  and fund the Company's fiscal year 2001 capital expenditures program of
$42.4  million.  Based  on  such  estimates,  the  Company may utilize a certain
portion  of  the  proceeds  from  the  sale  of  Mountaineer  to  make  capital
expenditures,  subject to limitations on such usage under the Notes, if any, and
may  seek  to  raise  additional  capital  or incur permitted indebtedness.  The
availability  and attractiveness of such sources of financing will depend upon a
number  of  factors,  some  of  which will relate to the financial condition and
performance  of  the  Company,  and  some  of which will be beyond the Company's
control,  such  as  prevailing  interest  rates,  oil  and  gas  prices, weather
patterns,  credit  agency  rating  reports  and  other  market  conditions.  The
Company's  liquidity is directly affected by such factors and the Company's cash
requirements  will fluctuate based on the timing and the extent of the interplay
of  these  factors.  However,  management  believes  that  cash  generated  from
continuing  oil  and  gas  operations,  the use of net proceeds from the sale of
Mountaineer  (as  permitted  under  provisions  of the related debt agreements),
together  with  the  liquidity  provided  by  existing  cash balances, permitted
borrowings  and  by investments in new "Energy Business" assets, if any, will be
sufficient  to  satisfy  commitments  for  capital  expenditures,  debt  service
obligations,  working  capital  needs  and  other cash requirements for the next
year.


                                       17
<PAGE>
     The  Company  believes  that its existing capital resources, its mitigating
management  efforts, and its expected fiscal year 2001 results of operations and
cash  flows  from  operating  activities  will  be sufficient for the Company to
remain  in compliance with the requirements of its Notes.  However, since future
results  of  operations,  cash  flow  from  operating  activities,  debt service
capability,  and  levels  and  availability  of capital resources and continuing
liquidity  are  dependent on future weather patterns, maintaining current levels
of  oil  and  gas  commodity  sales  prices and production volume levels, future
exploration  and  development  drilling  success  and  successful  acquisition
transactions,  no  assurance  can be given that the Company will not continue to
report substantial net losses from continuing operations or that debt service or
debt  covenant  violations  will  not occur.  In such instances, the Company may
elect to increase permitted borrowing levels (see discussion above), restructure
debt  agreements  (including debt agreements with additional lenders), sell core
and  non-core  assets, defer discretionary capital expenditures, curtail certain
domestic  and international oil and gas programs or take other actions necessary
to  mitigate  liquidity short-falls and debt agreement violations or acquire new
or  additional  capital resources, although no assurances can be given that such
actions  will  be  successful.

RECENT  ACCOUNTING  PRONOUNCEMENTS
----------------------------------

     As  of  July  1,  2000,  the  Company adopted SFAS No. 133, "Accounting for
Derivative  Instruments  and  Hedging Activities" as amended by SFAS No. 137 and
No.  138.  SFAS  No.  133  establishes  accounting  and  reporting standards for
derivative  instruments,  including  certain  derivative instruments embedded in
other  contracts,  and  hedging  activities.  It requires the recognition of all
derivative  instruments  as assets or liabilities in the Company's balance sheet
and measurement of those instruments at fair value.  The accounting treatment of
changes  in  fair value is dependent upon whether or not a derivative instrument
is  designated  as  a  hedge  and  if  so,  the  type of hedge.  For derivatives
designated  as  cash  flow hedges, changes in fair value are recognized in other
comprehensive  income  until  the  hedged  item  is  recognized  in  earnings.

     The  Company  periodically  hedges  a portion of its oil and gas production
through  futures and swap agreements.  The purpose of the hedges is to provide a
measure  of  stability  in the volatile environment of oil and gas prices and to
manage  its  exposure  to commodity price risk under existing sales commitments.
All  of  the  Company's  price swap agreements in place at June 30, 2000 will be
designated  as  cash  flow  hedges.  Adoption  of SFAS No.  133 on July 1, 2000,
resulted in recording $3.4 million of decline in fair value to accumulated other
comprehensive  income,  consisting  of  $3.8  million  to  short term derivative
liabilities,  $0.4  million to long term derivative liabilities and $0.8 million
to  short  term  derivative  assets.


              ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES
              -----------------------------------------------------
                                ABOUT MARKET RISK
                                -----------------

INTEREST  RATE  RISK
---------------------

     Interest  rate  risk  is  attributable  to the Company's debt.  The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment needs.  There is inherent rollover risk for borrowings as they mature
and  are  renewed  at  current  market  rates.  The  extent  of this risk is not
predictable  because  of  the  variability  of  future  interest  rates  and the
Company's  future  financing  needs.  The Company has not attempted to hedge the
interest rate risk associated with its floating rate debt of which $13.7 million
was  outstanding at year end.  If interest rates changed by 1%, it would have an
impact of approximately $0.14 million.  The Company has fixed interest rate debt
of  $200.0  million,  representing  93.1%  of  the  total  debt.


                                       18
<PAGE>
COMMODITY  RISK
----------------

     The  Company's  operations,  as  described  in  detail  at Item 1 Business,
consists  primarily of exploring for, producing, aggregating and selling natural
gas  and  oil.  The  Company  attempts  to  mitigate its commodity price risk by
entering  into a mix of short, medium and long-term supply contracts.  Contracts
to  deliver  gas  at  pre-established prices mitigate the risk to the Company of
falling  prices but at the same time limit the Company's ability to benefit from
the  effects  of  rising  prices.  The  Company  occasionally  uses  derivative
instruments  to  hedge its commodity price risk.  Notwithstanding the above, the
Company's  future  cash  flows  from  gas  and  oil  production  are  exposed to
significant  volatility  as  commodity  prices  change.

     The Company periodically enters into hedging activities on a portion of its
projected  natural gas  production  through a variety of financial  and physical
arrangements  intended to support  natural gas prices at targeted  levels and to
manage  its  exposure  to  price  fluctuations.  The  Company  may  use  futures
contracts,  swaps,  options  and fixed  price  physical  contracts  to hedge its
commodity  prices.  Realized  gains and  losses  from the  Company's  price risk
management  activities  are  recognized in oil and gas sales when the associated
production occurs. The Company does not hold or issue derivative instruments for
trading  purposes.  The  Company  has  elected to enter into swap  transactions,
covering approximately half of its Appalachian natural gas.


                                   * * * * *



                                       19
<PAGE>
             ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
             -------------------------------------------------------



INDEPENDENT  AUDITORS'  REPORT
------------------------------

To  the  Stockholders  and  Board of Directors of Energy Corporation of America:

We  have  audited  the  accompanying  consolidated  balance  sheets  of  Energy
Corporation  of  America  and Subsidiaries as of June 30, 2000 and 1999, and the
related  consolidated  statements of operations, stockholders' equity (deficit),
and  cash  flows  for each of the three years in the period ended June 30, 2000.
These  financial  statements are the responsibility of the Company's management.
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  management,  as well as evaluating the overall
financial  statement  presentation.  We  believe  that  our  audits  provide  a
reasonable  basis  for  our  opinion.

In  our  opinion,  such consolidated financial statements present fairly, in all
material  respects,  the financial position of Energy Corporation of America and
Subsidiaries  as  of June 30, 2000 and 1999, and the results of their operations
and  their  cash  flows for each of the three years in the period ended June 30,
2000  in conformity with accounting principles generally  accepted in the United
States of America.




DELOITTE  &  TOUCHE  LLP
Denver,  Colorado
September  27,  2000


                                       20
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  BALANCE  SHEETS
  AS  OF  JUNE  30
 (AMOUNTS  IN  THOUSANDS)
===================================================================================
ASSETS                                                          2000        1999
                                                            ------------  ---------
<S>                                                         <C>           <C>
 CURRENT ASSETS:
   Cash and cash equivalents                                $     3,310   $ 12,163
                                                            ------------  ---------
   Accounts receivable:
     Gas marketing and pipeline                                   9,249      9,271
     Oil and gas sales                                            1,081        870
     Other                                                        4,600      5,209
                                                            ------------  ---------
                                                                 14,930     15,350
     Less allowance for doubtful accounts                          (463)      (429)
                                                            ------------  ---------
                                                                 14,467     14,921
   Gas in storage, at average cost                                  765        357
   Income taxes receivable                                        2,502      3,580
   Deferred income tax asset                                                   191
   Net utility assets held for sale                              56,795     70,139
   Prepaid and other current assets                               1,921      2,084
                                                            ------------  ---------
         Total current assets                                    79,760    103,435

 NET PROPERTY, PLANT AND EQUIPMENT (Note 2)                     160,162    158,442
                                                            ------------  ---------

 OTHER ASSETS:
   Deferred financing costs, less accumulated
     amortization of $2,446 and $1,647                            5,210      6,009
   Notes receivable, less allowance for doubtful accounts
     of $0 and $440                                                          1,531
   Notes receivable - related party                               1,519      1,853
   Deferred income tax asset                                      4,405        292
   Other                                                         14,635     14,515
                                                            ------------  ---------
         Total other assets                                      25,769     24,200
                                                            ------------  ---------

 TOTAL                                                      $   265,691   $286,077
                                                            ============  =========

 See notes to consolidated financial statements.                        (Continued)
</TABLE>


                                       21
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  BALANCE  SHEETS
 AS  OF  JUNE  30
(AMOUNTS  IN  THOUSANDS)
===================================================================================
LIABILITIES AND STOCKHOLDERSEQUITY (DEFICIT)                      2000       1999
                                                                ---------  ---------
<S>                                                             <C>        <C>
CURRENT LIABILITIES:
  Accounts payable and accrued expenses                         $ 14,877   $ 15,471
  Current portion of long-term debt                                1,086      6,618
  Short-term debt                                                  2,000
  Funds held for future distribution                               6,280      5,378
  Accrued taxes, other than income                                 5,079      4,500
  Deferred income tax liability                                      329
  Other current liabilities                                        1,131
                                                                ---------  ---------
        Total current liabilities                                 30,782     31,967
LONG-TERM OBLIGATIONS
  Long-term debt                                                 212,575    219,886
  Gas delivery obligation and deferred trust revenue              15,443     13,839
  Deferred income tax liability                                               4,877
  Other long-term obligations                                     11,014      1,031
                                                                ---------  ---------
        Total liabilities                                        269,814    271,600
                                                                ---------  ---------

COMMITMENTS AND CONTINGENCIES (Note 13)

STOCKHOLDERS' EQUITY (DEFICIT):
  Common stock, par value $1.00; 2,000,000 shares authorized;
     718,000 and 721,000 shares issued                               718        721
  Class A non-voting common stock, no par value; 100,000
     shares authorized; 26,000 shares issued                       2,940      2,940
  Additional paid-in capital                                       4,615      4,656
  Retained earnings (deficit)                                     (4,833)    13,598
  Treasury stock and notes receivable arising from
     issuance of common stock                                     (7,429)    (7,261)
  Accumulated other comprehensive loss                              (134)      (177)
                                                                ---------  ---------
        Total stockholders' equity (deficit)                      (4,123)    14,477
                                                                ---------  ---------
TOTAL                                                           $265,691   $286,077
                                                                =========  =========

See  notes  to  consolidated  financial  statements.
</TABLE>


                                       22
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  OPERATIONS
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS  IN  THOUSANDS,  EXCEPT  PER  SHARE  DATA)
===========================================================================================================
                                                                              2000       1999       1998
                                                                            ---------  ---------  ---------
<S>                                                                         <C>        <C>        <C>
REVENUES:
  Gas marketing and pipeline sales                                          $ 72,156   $ 88,474   $135,348
  Oil and gas sales                                                           23,869     18,295     20,730
  Well operations and service revenues                                         5,894      6,540      6,751
  Contract settlement and other                                                             191     30,630
                                                                            ---------  ---------  ---------
                                                                             101,919    113,500    193,459
                                                                            ---------  ---------  ---------
COSTS AND EXPENSES:
  Gas marketing and pipeline cost of sales                                    70,101     84,417    138,211
  Purchase commitment costs                                                    4,945
  Field operating expenses                                                     8,143      8,198      8,545
  General and administrative                                                  13,647     10,299      9,192
  Taxes, other than income                                                     1,492      1,247      1,313
  Depletion and depreciation of oil and gas properties                         8,847      7,915      7,599
  Depreciation of pipelines, other property and equipment                      2,892      3,252      2,911
  Exploration and impairment                                                   8,347     19,261      8,262
                                                                            ---------  ---------  ---------
                                                                             118,414    134,589    176,033
                                                                            ---------  ---------  ---------
        Income (loss) from operations                                        (16,495)   (21,089)    17,426
                                                                            ---------  ---------  ---------
OTHER (INCOME) AND EXPENSE:
  Interest                                                                    22,302     20,122     20,123
  Loss (gain) on sale of assets                                                 (101)       (91)     1,208
  Other                                                                         (377)      (895)     1,638
                                                                            ---------  ---------  ---------
                                                                              21,824     19,136     22,969
                                                                            ---------  ---------  ---------
Loss from continuing operations before income taxes and minority interest    (38,319)   (40,225)    (5,543)
Provision (benefit) for income taxes                                         (11,811)   (13,133)    (2,013)
                                                                            ---------  ---------  ---------
Loss from continuing operations before minority interest                     (26,508)   (27,092)    (3,530)
Minority interest                                                                  -          7        243
                                                                            ---------  ---------  ---------
Loss from continuing operations                                              (26,508)   (27,099)    (3,773)
  Disposal of utility operations:
    Income from utility operations, net of income tax provision of
      $3,691, $7,901 and $4,030                                                8,077     12,212      6,787
                                                                            ---------  ---------  ---------

NET INCOME (LOSS)                                                           $(18,431)  $(14,887)  $  3,014
                                                                            =========  =========  =========

Earnings per common share
   Loss from continuing operations                                          $ (40.11)  $ (40.27)  $  (5.67)
   Discontiued operations                                                      12.22      18.15      10.20
                                                                            ---------  ---------  ---------
   Basic earnings (loss) per common share                                   $ (27.89)  $ (22.12)  $   4.53
                                                                            =========  =========  =========

See  notes  to  consolidated  financial  statements.
</TABLE>


                                       23
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  STOCKHOLDERSEQUITY  (DEFICIT)
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS  IN  THOUSANDS,  EXCEPT  PER  SHARE  DATA)
=================================================================================================================================
                                                                                                      Notes    Accum.
                                                                                                     Received/ Other
                                                          Class A   Additional Retained              Issuance  Compre-    Stock-
                                               Common     Common     Paid-In   Earnings   Treasury      of     hensive   holders'
                                                Stock      Stock     Capital   (Deficit)    Stock    Stock  Income (Loss)  Equity
                                              ---------  ---------  ---------  ----------  --------  --------  --------  --------
<S>                                           <C>        <C>        <C>        <C>         <C>       <C>       <C>       <C>
Balance, June 30, 1997                        $    714   $      -   $  4,221   $  27,249   $(3,175)  $  (260)  $  (151)  $28,598
                                                                                                                         --------
  Components of comprehensive income:
    Foreign currency translation adjustment                                                                       (159)     (159)
    Net income                                                                      3,014                                  3,014
                                                                                                                         --------
  Comprehensive income                                                                                                     2,855
  Dividends ($1.70 per share)                                                      (1,131)                                (1,131)
  Issuance of common stock                           3                   164                                                 167
  Exercise of employee stock options
  for notes receivable                               3                   125                              (128)                -
  Purchase of treasury stock                                                                   (523)                        (523)
  Reduction of notes receivable                                                                             4                  4
                                              ---------  ---------  ---------  ----------  --------  --------  --------  --------
Balance, June 30, 1998                             720          -       4,510      29,132    (3,698)     (384)     (310)   29,970
                                                                                                                         --------
  Components of comprehensive loss:
    Foreign currency translation adjustment                                                                       133        133
    Net loss                                                                     (14,887)                                (14,887)
                                                                                                                         --------
  Comprehensive loss                                                                                                     (14,754)
  Dividends ($0.95 per share)                                                      (647)                                   (647)
  Common stock issued for services                   1                   146                                                 147
  Conversion of minority interest                           2,040                                       (150)              1,890
  Employee stock purchases                                    900                                       (856)                 44
  Purchase of treasury stock - common                                                       (1,761)                       (1,761)
  Purchase of treasury stock - Class A                                                        (437)                         (437)
  Reduction of notes receivable                                                                           25                  25
                                              ---------  ---------  ---------  ----------  --------  --------  --------  --------
Balance, June 30, 1999                             721      2,940      4,656      13,598    (5,896)   (1,365)     (177)   14,477
                                                                                                                         --------
  Components of comprehensive loss:
    Foreign currency translation adjustment                                                                         43        43
    Net loss                                                                      (18,431)                               (18,431)
                                                                                                                        ---------
  Comprehensive loss                                                                                                     (18,388)
  Common stock issued for services                   2                   146                                                 148
  Redemption of common stock and related
  note receivable                                   (5)                 (187)                            192                   -
  Purchase of treasury stock - common                                                        (223)                          (223)
  Purchase of treasury stock - Class A                                                       (165)                          (165)
  Reduction of notes receivable                                                                           28                  28
                                              ---------  ---------  ---------  ----------  --------  --------  --------  --------
Balance, June 30, 2000                        $    718   $  2,940   $  4,615   $  (4,833)  $(6,284)  $(1,145)  $  (134)  $(4,123)
                                              =========  =========  =========  ==========  ========  ========  ========  ========

See  notes  to  consolidated  financial  statements.
</TABLE>


                                       24
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS
FOR  THE  YEARS  ENDED  JUNE  30
(AMOUNTS  IN  THOUSANDS)
===================================================================================================================
                                                                                      2000       1999       1998
                                                                                    ---------  ---------  ---------
<S>                                                                                 <C>        <C>        <C>
 CASH FLOWS FROM OPERATING ACTIVITIES
 Net loss from continuing operations                                                $(26,508)  $(27,099)  $ (3,773)
  Adjustments to reconcile net loss to net cash provided (used) by
    operating activities:
       Minority interest                                                                              7        243
       Depletion, depreciation and amortization                                       12,538     11,966     11,297
       Loss (gain) on sale of assets                                                    (101)       (91)     1,208
       Deferred income taxes                                                         (11,099)   (12,491)    (2,300)
       Exploration and impairment                                                      5,979     16,778      8,012
       Other, net                                                                      4,413      3,426       (589)
                                                                                    ---------  ---------  ---------
                                                                                     (14,778)    (7,504)    14,098
 Changes in assets and liabilities:
    Accounts receivable                                                                  420        (38)      (655)
    Gas in storage                                                                      (408)        92       (138)
    Income taxes receivable                                                            1,079     (4,344)     6,879
    Prepaid and other assets                                                             163      1,625     (3,375)
    Accounts payable                                                                     (42)    (6,348)     4,846
    Funds held for future distributions                                                  902       (337)      (301)
    Other                                                                              7,670     (7,252)   (10,583)
                                                                                    ---------  ---------  ---------
       Net cash provided (used) by operating activities from continuing operations    (4,994)   (24,106)    10,771
       Net cash provided by operating activities from disposed operations              7,286     30,009     25,338
                                                                                    ---------  ---------  ---------
       Net cash provided by operating activities                                       2,292      5,903     36,109
                                                                                    ---------  ---------  ---------
 CASH FLOWS FROM INVESTING ACTIVITIES
    Expenditures for property, plant and equipment                                   (19,299)   (25,245)   (22,901)
    Proceeds from sale of assets                                                         428      3,444        568
    Notes receivable and other                                                          (300)        70       (238)
                                                                                    ---------  ---------  ---------
       Net cash used by investing activities from continuing operations              (19,171)   (21,731)   (22,571)
       Net cash used by investing activities from disposed operations                (23,842)   (11,414)   (15,793)
                                                                                    ---------  ---------  ---------
       Net cash used by investing activities                                         (43,013)   (33,145)   (38,364)
                                                                                    ---------  ---------  ---------
 CASH FLOWS FROM FINANCING ACTIVITIES
    Proceeds from long-term debt                                                      16,250     27,500      1,298
    Principal payment on long-term debt                                              (29,094)    (3,084)      (296)
    Proceeds from short-term borrowing                                                 2,000
    Purchase of treasury stock and other financing activities                           (214)    (2,154)       161
    Prepayment of future gas delivery                                                 10,000          -
    Dividends paid                                                                         -       (967)      (834)
                                                                                    ---------  ---------  ---------
       Net cash provided (used) by financing activities from continuing operations    (1,058)    21,295        329
       Net cash provided (used) by financing activities from disposed operations      32,926     (2,375)     2,050
                                                                                    ---------  ---------  ---------
       Net cash provided by financing activities                                      31,868     18,920      2,379
                                                                                    ---------  ---------  ---------
       Net increase (decrease) in cash and cash equivalents                           (8,853)    (8,322)       124
       Cash and cash equivalents, beginning of period                                 12,163     20,485     20,361
                                                                                    ---------  ---------  ---------
 Cash and cash equivalents, end of period                                           $  3,310   $ 12,163   $ 20,485
                                                                                    =========  =========  =========

 The  accompanying  notes  are  an integral part of these condensed consolidated financial  statements.
</TABLE>


                                       25
<PAGE>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS
FOR  THE  YEARS  ENDED  JUNE  30,  2000,  1999  AND  1998
--------------------------------------------------------------------------------

1.   NATURE OF ORGANIZATION

     Energy  Corporation  of  America  (the  "Company")  was formed in June 1993
     through  an  exchange  of shares  with the common  stockholders  of Eastern
     American  Energy  Corporation  ("Eastern  American").  The  Company  is  an
     independent energy company.  All references to the "Company" include Energy
     Corporation  of America and its  consolidated  subsidiaries.  The Company's
     industry segments are discussed at Note 16.

     The Company, primarily through Eastern American, is engaged in exploration,
     development  and  production,  transportation  and marketing of natural gas
     primarily within the Appalachian  Basin of West Virginia,  Pennsylvania and
     Ohio.

     The  Company,   through  its  wholly  owned  subsidiaries   Westech  Energy
     Corporation  ("Westech") and Westech Energy New Zealand  ("WENZ"),  is also
     engaged  in the  exploration  for and  production  of oil and  natural  gas
     primarily in the Rocky Mountains, New Zealand and Australia.

     In  August  2000,   the  Company  sold  its  wholly  owned   regulated  gas
     distribution   utility,    Mountaineer   Gas   Company   and   Subsidiaries
     ("Mountaineer"). See Note 3.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

     Principles of Consolidation - The consolidated financial statements include
     ---------------------------
     the accounts of the Company; Eastern American and its subsidiaries; Westech
     and WENZ and its investment in certain New Zealand oil and gas  exploration
     joint  ventures.  The  Company  has  investments  in oil  and  gas  limited
     partnerships and joint ventures and has recognized its proportionate  share
     of  these  entities'  revenues,   expenses,  assets  and  liabilities.  All
     significant    intercompany    transactions   have   been   eliminated   in
     consolidation.

     Fourth  Quarter  Results  -  During  the fourth quarter of fiscal 2000, the
     ------------------------
     Company had the normal weather  related  decline in earnings.  In addition,
     the Company  reported a $4.9 million gas purchase  commitment  charge.  See
     Note 13.

     Cash  and  Cash  Equivalents - Cash and cash equivalents include short-term
     ----------------------------
     investments maturing in three months or less from the date acquired.

     Property,  Plant  and  Equipment - Oil and gas properties are accounted for
     --------------------------------
     using the  successful  efforts  method of  accounting.  Under this  method,
     certain expenditures such as exploratory  geological and geophysical costs,
     exploratory  dry hole  costs,  delay  rentals  and other  costs  related to
     exploration  are recognized  currently as expenses.  All direct and certain
     indirect costs  relating to property  acquisition,  successful  exploratory
     wells,   development  costs,  and  support  equipment  and  facilities  are
     capitalized. The Company computes depletion,  depreciation and amortization
     of capitalized oil and gas property costs on the units-of-production method
     using  proved  developed  reserves.  Direct  production  costs,  production
     overhead and other costs are charged against income as incurred.  Gains and
     losses  on the  sale  of oil  and  gas  property  interests  are  generally
     recognized as income.


                                       26
<PAGE>
     Other property,  equipment,  pipelines and buildings are stated at cost and
     are depreciated using  straight-line and accelerated methods over estimated
     useful lives ranging from three to 30 years.

     Repairs and  maintenance  costs are  charged  against  income as  incurred;
     significant  renewals and betterments are capitalized.  Gains and losses on
     dispositions of property, equipment, pipelines and buildings are recognized
     as income.

     At June 30 property,  plant and  equipment  consisted of the  following (in
     thousands):

     Other property,  equipment,  pipelines and buildings are stated at cost and
     are depreciated using  straight-line and accelerated methods over estimated
     useful lives ranging from three to 30 years.

     Repairs and  maintenance  costs are  charged  against  income as  incurred;
     significant  renewals and betterments are capitalized.  Gains and losses on
     dispositions of property, equipment, pipelines and buildings are recognized
     as income.

     At June 30 property,  plant and  equipment  consisted of the  following (in
     thousands):

<TABLE>
<CAPTION>
                                                                  2000       1999
                                                                ---------  ---------
<S>                                                               <C>        <C>
     Oil and gas properties                                     $219,259   $207,904
     Other property and equipment                                 14,167     13,675
     Pipelines                                                    18,842     19,021
                                                                ---------  ---------
                                                                 252,268    240,600
     Less accumulated depletion, depreciation and amortization   (92,106)   (82,158)
                                                                ---------  ---------
     Net property, plant and equipment                          $160,162   $158,442
                                                                =========  =========
</TABLE>

     Long-Lived  Assets  -  Statement of Financial Accounting Standards ("SFAS")
     ------------------
     No.  121,  "Accounting  for the  Impairment  of  Long-Lived  Assets and for
     Long-Lived  Assets to be Disposed  Of",  requires  all  companies to assess
     long-lived  assets and assets to be  disposed  of for  impairment.  For the
     three years ended June 30, 2000, the Company  determined that no impairment
     needed to be recognized for applicable assets.

     Gas  in  Storage - Gas in storage is stated at the lower of average cost or
     ----------------
     market  value.

     Deferred  Financing  Costs  -  Certain  legal,  underwriting fees and other
     --------------------------
     direct expenses associated with the issuance of credit agreements, lines of
     credit  and  other  financing  transactions  have been  capitalized.  These
     financing  costs are being  amortized  over the term of the related  credit
     agreement.

     Foreign  Currency  Translation  -  The  translation  of  applicable foreign
     ------------------------------
     currencies into U.S.  dollars is performed for balance sheet accounts using
     current  exchange rates in effect at the balance sheet date and for revenue
     and expense accounts using an average exchange rate during the period.  The
     cumulative translation adjustment is included in stockholders' equity.

     Income  Taxes  -  Deferred  income  taxes  reflect the impact of "temporary
     -------------
     differences"  between  assets  and  liabilities  recognized  for  financial
     reporting  purposes  and  such  amounts  as  measured  by tax  laws.  These
     temporary  differences  are  determined  in  accordance  with SFAS No. 109,
     "Accounting For Income Taxes".

     Gas  Delivery  Obligation  -  Gas  delivery  obligation represents deferred
     -------------------------
     revenues on gas sales where the  Company has  received an advance  payment.
     The Company  recognizes  the actual gas sales revenue in the period the gas
     delivery takes place.

     Revenues  and  Gas  Costs - Oil and gas sales are recognized as income when
     -------------------------
     the oil or gas is produced and sold. Gas costs are expensed as incurred.

     Stock  Compensation  -  As  permitted  under  SFAS No. 123, "Accounting for
     -------------------
     Stock-Based  Compensation",  the Company has elected to continue to measure
     compensation  costs for stock-based  employee  compensation plans using the
     intrinsic value method as prescribed by Accounting Principles Board Opinion
     No. 25, "Accounting for Stock Issued to Employees".


                                       27
<PAGE>
     Use  of  Estimates  - The preparation of financial statements in conformity
     ------------------
     with generally accepted  accounting  principles requires management to make
     estimates and  assumptions  that affect the reported  amounts of assets and
     liabilities and disclosure of contingent assets and liabilities at the date
     of the  financial  statements  and the  reported  amounts of  revenues  and
     expenses  during the  reporting  period.  Actual  results could differ from
     those estimates.

     The Company's  financial  statements  are based on a number of  significant
     estimates including oil and gas reserve quantities, which are the basis for
     the calculation of depletion, depreciation,  amortization and impairment of
     oil and gas properties.  Management  emphasizes that reserve  estimates are
     inherently imprecise. In addition,  utilization of tax credit carryforwards
     is based largely on estimates of future taxable income.

     Prior  Year Reclassifications - Certain amounts in the financial statements
     -----------------------------
     of prior  years  have been  reclassified  to conform  to the  current  year
     presentation.

     Concentration  of  Credit  Risk  -  The Company maintains its cash accounts
     -------------------------------
     primarily  with a single bank and invests  cash in money  market  accounts,
     which the Company  believes to have  minimal  risk.  As operator of jointly
     owned oil and gas  properties,  the Company sells oil and gas production to
     numerous U.S. oil and gas  purchasers,  and pays vendors on behalf of joint
     owners  for oil and gas  services.  Both  purchasers  and joint  owners are
     located primarily in the northeastern United States. The risk of nonpayment
     by the  purchasers  or joint  owners  is  considered  minimal  and has been
     considered in the Company's allowance for doubtful accounts.

     Environmental  Concerns  -  The  Company  is  continually taking actions it
     -----------------------
     believes  necessary in its operations to ensure  conformity with applicable
     federal,  state and local environmental  regulations.  As of June 30, 2000,
     the Company has not been fined or cited for any  environmental  violations,
     which  would have a material  adverse  effect  upon  capital  expenditures,
     earnings or the competitive position of the Company.

     Recent  Accounting Pronouncements - As of July 1, 2000, the Company adopted
     ---------------------------------
     SFAS  No.  133,   "Accounting   for  Derivative   Instruments  and  Hedging
     Activities"  as  amended  by SFAS  No.  137  and  No.  138.  SFAS  No.  133
     establishes accounting and reporting standards for derivative  instruments,
     including certain derivative  instruments embedded in other contracts,  and
     hedging   activities.   It  requires  the  recognition  of  all  derivative
     instruments  as assets or  liabilities  in the Company's  balance sheet and
     measurement of those instruments at fair value. The accounting treatment of
     changes  in fair  value  is  dependent  upon  whether  or not a  derivative
     instrument  is  designated  as a hedge and if so,  the type of  hedge.  For
     derivatives  designated  as cash flow  hedges,  changes  in fair  value are
     recognized  in  other  comprehensive   income  until  the  hedged  item  is
     recognized in earnings.

     The  Company  periodically  hedges a portion of its oil and gas  production
     through  futures  and swap  agreements.  The  purpose  of the  hedges is to
     provide a measure of stability in the volatile  environment  of oil and gas
     prices and to manage its  exposure to commodity  price risk under  existing
     sales  commitments.  All of the Company's price swap agreements in place at
     June 30, 2000 will be designated as cash flow hedges.  Adoption of SFAS No.
     133 on July 1, 2000,  resulted in recording $3.4 million of decline in fair
     value to accumulated other comprehensive income, consisting of $3.8 million
     to short term derivative liabilities,  $0.4 million to long term derivative
     liabilities and $0.8 million to short term derivative assets.


                                       28
<PAGE>
     Supplemental  Disclosures of Cash Flow Information - Supplemental cash flow
     --------------------------------------------------
     information for the years ended June 30 is as follows (in thousands):

<TABLE>
<CAPTION>
                                                             2000     1999     1998
                                                            -------  -------  -------
<S>                                                         <C>      <C>      <C>
      Cash paid for:
        Interest                                            $21,360  $19,192  $18,829
        Income taxes, net                                       242    1,376    1,234
      Noncash investing and financing activities:
         Dividends declared and unpaid at year end                                316
         Seller financed acquisition                                     150      943
         Acquisition of property for cancellation of notes            1,900
</TABLE>


3.   DISPOSITIONS

     On December 20, 1999, the Company agreed to sell its wholly-owned regulated
     gas  distribution   utility,   Mountaineer,   to  Allegheny  Energy,   Inc.
     ("Allegheny")  pursuant to a stock  purchase  agreement  for $323  million,
     which  includes the assumption of  approximately  $100 million of long term
     debt and was  subject to certain  adjustments.  The  transaction  closed on
     August 18, 2000 and will be  recorded  in the first  quarter of fiscal year
     2001.  The  transaction  will  result  in a  pre-tax  gain for the  Company
     estimated at approximately $165 million.

     The  Company  also  entered  into a gas sale and  purchase  agreement  with
     Allegheny whereby it will begin the delivery of natural gas beginning on or
     after July 1, 2001.  The  Company  has  received a $10  million  prepayment
     pursuant to the agreement,  which is recorded as long term deferred revenue
     on the balance sheet.  Potentially,  the Company has the ability to receive
     additional prepayments up to $20 million,  pending the ability to present a
     letter of credit equal to the prepayment.

     The  utility  operations  have  historically  been  reported  as a separate
     segment.  As a result of the  sale,  its  disposition  is  considered,  for
     accounting purposes, to be a discontinued business. Accordingly, amounts in
     the  financial  statements  and  related  notes  thereto  for  all  periods
     presented  therein have been  restated to reflect  discontinued  operations
     accounting.  Summarized financial statements for the disposed business,  as
     of and for the year ended June 30 are as follows, in thousands:


                                       29
<PAGE>
<TABLE>
<CAPTION>
                                               2000      1999
                                             --------  --------
<S>                                          <C>       <C>
      ASSETS
         Cash and cash equivalents           $  1,089  $    457
         Accounts receivable                   19,780    22,117
         Prepaid and other current assets      30,369    24,682
                                             --------  --------
            Total current assets               51,238    47,256
         Property, plant and equipment, net   167,121   156,873
         Deferred utility charges              15,983    18,785
         Other                                  2,605     2,674
                                             --------  --------
      TOTAL                                  $236,947  $225,588
                                             ========  ========
      LIABILITIES AND STOCKHOLDERS' EQUITY
         Accounts payable                    $ 13,111  $ 24,575
         Short term borrowings                  9,944    16,799
         Other current liabilities             17,829    18,596
                                             --------  --------
            Total current liabilities          40,884    59,970
         Long-term debt                       100,116    60,135
         Deferred income tax liability         22,472    22,991
         Other long-term obligation            10,096    10,819
                                             --------  --------
            Total liabilities                 173,568   153,915
            Total stockholders' equity         63,379    71,673
                                             --------  --------
      TOTAL                                  $236,947  $225,588
                                             ========  ========
</TABLE>


<TABLE>
<CAPTION>
                                                  2000      1999       1998
                                                --------  ---------  ---------
<S>                                             <C>       <C>        <C>
      REVENUES:
         Utility gas sales and transportation   $169,173  $158,439   $156,579
         Other revenue                             9,709    13,664     14,298
                                                --------  ---------  ---------
                                                 178,882   172,103    170,877
                                                --------  ---------  ---------
      COST AND EXPENSES:
         Utility gas purchased                    83,840    73,842     85,166
         Utility operations and maintenance       23,166    22,496     22,084
         General and administrative (1)           19,876    15,533     14,858
         Depreciation and depletion               11,764    10,871      9,527
         Taxes, other than income                 14,734    14,013     13,568
         Other                                     5,575     9,706      9,400
                                                --------  ---------  ---------
                                                 158,955   146,461    154,603
                                                --------  ---------  ---------
         Income from operations                   19,927    25,642     16,274
                                                --------  ---------  ---------
      OTHER (INCOME) EXPENSE
         Interest                                  8,146     6,432      6,264
         Other                                       733      (183)       (87)
                                                --------  ---------  ---------
         Income before income taxes               11,048    19,393     10,097
      Provision for income taxes                   3,691     7,901      4,030
                                                --------  ---------  ---------
      NET INCOME                                $  7,357  $ 11,492   $  6,067
                                                ========  =========  =========

<FN>
         (1)  Includes $720 in management fees paid to the  Company,  which is
              subsequently eliminated  in  consolidation.
</TABLE>


                                       30
<PAGE>
<TABLE>
<CAPTION>
                                                                2000       1999       1998
                                                              ---------  ---------  ---------
<S>                                                           <C>        <C>        <C>
      CASH FLOWS FROM OPERATING ACTIVITIES
         Net income                                           $  7,357   $ 11,492   $  6,067
         Adjustment to reconcile earnings to net cash
                    provided by operating activities
            Depletion, depreciation and amortization            11,764     10,871      9,528
            Other, net                                             745      1,540      4,173
         Changes in assets and liabilities:
         Current assets                                         (3,027)    (3,041)     3,715
         Current liabilities                                    (9,641)     7,822        341
                                                              ---------  ---------  ---------
            Net cash provided by operating activities            7,198     28,684     23,824
                                                              ---------  ---------  ---------
      CASH FLOWS FROM INVESTING ACTIVITIES
         Expenditures for property, plant and equipment        (23,842)   (11,414)   (15,793)
                                                              ---------  ---------  ---------
            Net cash used by investing activities              (23,842)   (11,414)   (15,793)
                                                              ---------  ---------  ---------
      CASH FLOWS FROM FINANCING ACTIVITIES
         Proceeds from long-term debt                           40,000
         Short term borrowings, net                             (6,855)    (2,375)     3,450
         Debt issuance costs and other                            (219)
         Dividends to parent company                           (15,650)   (15,500)   (10,875)
                                                              ---------  ---------  ---------
            Net cash provided (used) by financing activities    17,276    (17,875)    (7,425)
                                                              ---------  ---------  ---------
            Net increase in cash and cash equivalents              632       (605)       606
            Cash and cash equivalents, beginning of period         457      1,062        456
                                                              ---------  ---------  ---------
      Cash and cash equivalents, end of period                $  1,089   $    457   $  1,062
                                                              =========  =========  =========
</TABLE>

     The income from operations of utility  totaling $8.1 million,  net of a tax
     provision  of  $3.6  million,   includes  net  earnings  from  discontinued
     operations   for  the  six  month  period  ended  December  31,  1999  (the
     pre-measurement  period)  of $4.5  million,  net of tax  provision  of $2.3
     million and net earnings  from  discontinued  operations  for the six month
     period January 1, 2000 to June 30, 2000  (post-measurement  period) of $3.6
     million,  net of tax  provision of $1.4  million.  Net earnings  during the
     post-measurement  period are included  herein and not deferred and included
     within the gain on disposal  computation since such earnings are considered
     to have been realized.  Estimated net losses from  discontinued  operations
     for the period of July 1, 2000 to August 18, 2000  (disposal  date) of $1.9
     million, net of tax benefit of $1.2 million,  will be recorded in the first
     quarter  of  fiscal  year  2001  and  included,  as  a  reduction,  in  the
     computation of the gain on disposal of utility  segment.  When  aggregated,
     net earnings from  discontinued  operations  for the period of December 20,
     1999  (measurement  date) to August 18, 2000  (disposal  date)  totals $6.2
     million, net of tax provision $2.5 million.

4.   RISK MANAGEMENT


     Options,  Future  Contracts, and Swap Agreements -The Company is a party to
     ------------------------------------------------
     natural gas options,  future  contracts  and swap  agreements in the normal
     course of business. These instruments involve, to varying degrees, elements
     of  market  and  credit  risk in  excess of the  amount  recognized  in the
     consolidated balance sheets.


     At June 30, 2000, the Company had swap  agreements  maturing from July 2000
     through October 2001 covering  5,176,600 Mmbtu of gas. The Company receives
     a fixed  price in  exchange  for a variable  price on  4,760,000  Mmbtu and
     receives a variable  price in exchange for a fixed price on 416,600  Mmbtu.
     The  Company's  net  unrealized  loss  related  to  these   agreements  was
     approximately $3.4 million at June 30, 2000.

     At June 30, 1999, the Company had over-the-counter  natural gas futures and
     options contracts related to gas sale commitments  covering 3,553,000 Mmbtu
     of gas maturing  through June 2000. As these  contracts were  designated as
     hedges,  any gains or losses  resulting  from  market  price  changes  were
     included  in oil and gas  sales  for the  month to which  the  contract  is
     applicable.  The Company's net unrealized  loss related to these  contracts
     was approximately $88,000 at June 30, 1999.


                                       31
<PAGE>
     In  addition  to futures and  options  contracts,  the Company  enters into
     over-the-counter  price swap agreements to manage its exposure to commodity
     price risk under existing sales commitments.  At June 30, 1999, the Company
     had swap agreements  maturing from November 1999 through June 2000 covering
     772,000  Mmbtu under  which the Company  receives a fixed price in exchange
     for a variable  price.  The Company's net unrealized  gain related to these
     agreements was approximately $28,000 at June 30, 1999.

     In  addition,  at June 30,  1999,  the  Company had natural gas fixed price
     purchase option contracts for the purchase and physical delivery of 615,000
     Mmbtu of gas expiring  through  October  1999.  The cost of these  options,
     which totaled  approximately  $190,000 for the year ended June 30, 1999, is
     included  in Cost of Gas  Sales for the  month to which  the  options  were
     applicable. At June 30, 1999, the remaining options, for the months of July
     1999 through  October 1999,  are carried at cost that totaled  $189,875 and
     approximates fair value.

     For the years ended June 30, 2000, 1999 and 1998, the Company  recognized a
     net loss on its natural gas hedging  activities  of  $805,400,  $32,200 and
     $47,000, respectively.



5.   DEBT

     Long-Term Debt - At June 30  long-term  debt consisted of the following (in
     ---------------
     thousands):

<TABLE>
<CAPTION>
                                                                         2000       1999
                                                                       ---------  ---------
<S>                                                                    <C>        <C>
      ECA senior subordinated notes, interest at 9.5% payable
        semi-annually, due May 15, 2007                                $200,000   $200,000
      ECA revolving credit, interest floating at Prime, plus 1.5% or
         LIBOR plus 3%, due 2002                                         12,000     25,000
      Installment notes payable, at interest rates ranging from
        6.2% to 8%                                                        1,661      1,504
                                                                       ---------  ---------
                                                                        213,661    226,504
      Less current portion                                               (1,086)    (6,618)
                                                                       ---------  ---------
                                                                       $212,575   $219,886
                                                                       =========  =========
</TABLE>

     The Company's  various debt  agreements  contain certain  restrictions  and
     conditions among which are limitations on indebtedness,  funding of certain
     subsidiaries, dividends and investments, and certain tangible net worth and
     debt and interest coverage ratio  requirements.  The agreements require the
     Company to maintain certain financial  conditions,  including a minimum net
     worth,  restriction  on  funded  debt and  restrictions  on the  amount  of
     dividends that can be declared.


                                       32
<PAGE>
     Scheduled  maturities of the Company's  long-term debt at June 30, 2000 for
     each of the next five years and thereafter are as follows (in thousands):


                           2001      $          1,086
                           2002                12,113
                           2003                   113
                           2004                   113
                           2005                   113
                     Thereafter               200,123
                                    -----------------
                                      $       213,661
                                     ================


     Revolving  Credit - The Company had a $22 million revolving credit facility
     -----------------
     secured by certain properties, interest and contracts. The interest rate is
     variable based on Eurodollars or other defined basis. The annual commitment
     fee ranges between 0.3% and 0.625% depending on usage. As of June 30, 2000,
     $12.8 million was outstanding under this facility.  On August 18, 2000, the
     balance,  $19.8  million,  was paid in full and the  credit  agreement  was
     terminated.

     Other  Credit  Facilities  - As of June 30, 1999, Eastern American had a $3
     -------------------------
     million letter of credit, issued by a bank in support of Eastern American's
     obligations  under a gas purchase contract with the royalty trust (see Note
     13).  The  letter of credit  reduced  by $3 million on June 30 of each year
     until its  expiration  on June 30, 2000.  As of June 30, 2000 and 1999,  no
     amounts had been drawn under the letter of credit.  Eastern  American  also
     has an  unsecured  revolving  line of credit  totaling  $2  million,  which
     expires  November 30, 2000 and charges an interest rate of prime plus 0.5%.
     As of June 30, 2000 and 1999, $2 million and $0 were outstanding  under the
     line of credit.

     Seller  Financed  Note  -  In  1998,  the  Company  purchased a natural gas
     ----------------------
     gathering  system in West Virginia for $1.2 million.  The Company paid $0.3
     million in cash and issued a note for the balance  payable to the seller in
     100 consecutive equal monthly  payments.  As of June 30, 2000 and 1999, the
     balance of the note was approximately $0.7 million and $0.8 million.

6.   INCOME TAXES

     The  following  table  summarizes  components  of the  Company's  provision
     (benefit) for income taxes for the years ended June 30 (in thousands):

<TABLE>
<CAPTION>
                                                      2000       1999       1998
                                                    ---------  ---------  --------
<S>                                                 <C>        <C>        <C>
      Current:
        Federal                                     $   (666)  $   (340)  $   337
        State                                            (46)      (302)      (50)
                                                    ---------  ---------  --------
        Total current                                   (712)      (642)      287
                                                    ---------  ---------  --------
      Deferred:
        Federal                                      (11,477)    (9,386)   (3,733)
        State                                            378     (3,105)    1,433
                                                    ---------  ---------  --------
        Total deferred                               (11,099)   (12,491)   (2,300)
                                                    ---------  ---------  --------
        Total provision (benefit) for income taxes  $(11,811)  $(13,133)  $(2,013)
                                                    =========  =========  ========
</TABLE>


                                       33
<PAGE>
     A  reconciliation  of  the  provision  for  income  taxes  computed  at the
     statutory  rate  to  the  provision  for  income  taxes  as  shown  in  the
     consolidated  statements  of  operations  for the  years  ended  June 30 is
     summarized below (in thousands):

<TABLE>
<CAPTION>
                                                               2000       1999       1998
                                                             ---------  ---------  --------
<S>                                                          <C>        <C>        <C>
      Tax expense (benefit) at the federal statutory rate    $(13,028)  $(13,676)  $(1,885)
      State taxes, net of federal tax effects                  (1,781)    (2,664)     (260)
      Foreign losses                                                                   838
      Section 29 tax credits                                      216        921    (1,783)
      Change in valuation allowance on federal, foreign
       and state deferred tax assets, net of federal effect     2,000       (592)      571
      Investment tax credit expiration                            532        530
      IRS adjustment                                                         519
      Other, net                                                  250      1,829       506
                                                             ---------  ---------  --------
      Provision (benefit) for income taxes                   $(11,811)  $(13,133)  $(2,013)
                                                             =========  =========  ========
</TABLE>

     During fiscal 1999, the Company  finalized an IRS examination  resulting in
     payments for prior taxes of $0.5 million.  In addition,  Section 29 credits
     for 1998 were not utilized  because of reductions to regular taxable income
     and have been added to the current year's tax provision.

     Components  of the  Company's  federal  and state  deferred  tax assets and
     liabilities, as of June 30, are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                 2000                            1999
                                                      =============================  ==============================
                                                      Federal    State      Total     Federal    State      Total
                                                     ---------  --------  ---------  ---------  --------  ---------
<S>                                                  <C>        <C>       <C>        <C>        <C>       <C>
       Deferred tax assets:
         Bad debt allowance                          $    168   $    45   $    213   $    161   $    43   $    204
         Deferred compensation and profit sharing         162        43        205        162        43        205
         Tax credits and carryforwards                 19,678    10,904     30,582     13,058     8,774     21,832
         Other long-term obligations                    1,272       337      1,609      1,272       337      1,609
         Other                                         10,392     2,683     13,075      7,746     2,016      9,762
                                                     ---------  --------  ---------  ---------  --------  ---------
           Total deferred tax assets                   31,672    14,012     45,684     22,399    11,213     33,612
                                                     ---------  --------  ---------  ---------  --------  ---------
       Deferred tax liabilities:
         Property, plant and equipment                (15,887)   (4,206)   (20,093)   (16,181)   (4,283)   (20,464)
         Federal income tax on state tax credits       (2,999)              (2,999)    (2,983)              (2,983)
         Other liabilities                             (8,397)   (2,168)   (10,565)    (7,648)   (1,991)    (9,639)
                                                     ---------  --------  ---------  ---------  --------  ---------
           Total deferred tax liabilities             (27,283)   (6,374)   (33,657)   (26,812)   (6,274)   (33,086)
                                                     ---------  --------  ---------  ---------  --------  ---------
       Valuation allowance                                       (7,951)    (7,951)              (4,920)    (4,920)
                                                     ---------  --------  ---------  ---------  --------  ---------
       Net deferred income tax asset (liability)        4,389      (313)     4,076     (4,413)       19     (4,394)
       Current deferred tax asset (liability)            (259)      (70)      (329)       152        39        191
                                                     ---------  --------  ---------  ---------  --------  ---------
       Net long-term deferred tax asset (liability)  $  4,648   $  (243)  $  4,405   $ (4,565)  $   (20)  $ (4,585)
                                                     =========  ========  =========  =========  ========  =========
</TABLE>


                                       34
<PAGE>
     At June 30,  2000,  the  Company  has the  following  federal and state tax
     credits and carryforwards (in thousands):

<TABLE>
<CAPTION>
                                                 Year of
                                       Amount   Expiration
                                      --------  ----------
<S>                                   <C>       <C>
      AMT and Section 29 tax credits  $ 11,723        None
      Investment tax credits                80   2000-2001
      Net operating loss carryover       7,875        2020
                                      --------
      Total federal credits           $ 19,678
                                      ========

      West Virginia tax credits       $  8,820        2002
      Net operating loss carryover       2,084        2015
                                      --------
      Total state credits             $ 10,904
                                      ========
</TABLE>

     The Company is eligible for relocation  incentives taken in the form of tax
     credits  from  West  Virginia.   The  incentive   amounts  are  based  upon
     investments made and jobs created in that state.  Tax credits  generated by
     the Company are used primarily to offset the payment of severance, property
     and  state  income  taxes.  Based  on  existing  future  taxable  temporary
     differences and projections of future West Virginia severance, property and
     state income taxes,  management has provided a valuation allowance for that
     portion of the credits not expected to be utilized.

7.   EMPLOYEE BENEFIT PLANS

     The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock
     Plan (the "Plan") for the stated purpose of expanding and improving profits
     and  prosperity  and to assist the Company in attracting  and retaining key
     personnel.  The Plan is  noncontributory,  and its continuance from year to
     year is at the  discretion  of the Board of  Directors.  The annual  profit
     sharing pool is based on  calculations  set forth in the Plan.  One-half of
     the pool is generally paid to eligible employees within 120 days of the end
     of the  fiscal  year  and  one-half  is  deferred  to the  following  year.
     Generally,  to be  eligible  to  participate,  an  employee  must have been
     continuously employed for two or more years;  however,  employees with less
     than two years of employment may participate  under certain  circumstances.
     The Company recognized $0.9 million,  $0 and $1.7 million of profit sharing
     expense during the years ended June 30, 2000, 1999, and 1998, respectively.

     For  certain  subsidiaries,  the  Company  sponsors a Section  401(k)  plan
     covering all  full-time  employees who wish to  participate.  The Company's
     contributions,  which are principally based on a percentage of the employee
     contributions,  and charged against income as incurred,  totaled  $232,800,
     $182,600 and $153,600  for the years ended June 30, 2000,  1999,  and 1998,
     respectively.

8.   CAPITAL STOCK

     Voting  Common  Stock-  In  May 1995, the Company was reincorporated in the
     ---------------------
     State of West Virginia. As part of this  reincorporation,  each outstanding
     share of then existing no-par value common stock was converted to one share
     of $1 par value common stock.

     The  Company  has an  agreement  with a  stockholder  covering  the sale or
     disposition  of 59,600  shares  of common  stock,  at June 30,  2000,  that
     provides the  stockholder  cannot sell stock  without  first  offering such
     shares to the Company.  Under certain  circumstances,  the Company would be
     required to purchase the related  stock if not  previously  tendered to the
     Company or otherwise sold or disposed of in accordance  with the provisions
     of the agreement.


                                       35
<PAGE>
     Class  A  Non-Voting Common Stock - In August 1998, the Company amended its
     ---------------------------------
     articles of incorporation  authorizing the issuance of up to 100,000 shares
     of Class A non-voting  common stock. The Company then offered and exchanged
     13,517 shares of its new Class A stock for the outstanding Class A stock of
     its subsidiaries,  owned by certain employees,  officers and directors. The
     minority  interest  carrying value prior to exchange,  which  reflected the
     subsidiaries'  Class A shares, was the basis used to record the issuance of
     the Company's new Class A stock.

     Treasury  Stock - At June 30, 2000, the Company had 78,012 shares of voting
     ---------------
     common stock in treasury,  carried at cost. The Company purchased 2,660 and
     20,704  shares of voting  common stock during the years ended June 30, 2000
     and 1999, respectively. At June 30, 2000, the Company also had 6,227 shares
     of  non-voting  Class A stock in  treasury,  carried at cost.  The  Company
     purchased  1,711 and 4,516  shares of  non-voting  Class A stock during the
     years ended June 30, 2000 and 1999, respectively.

     Stock  Plans  -  During fiscal 1999, the Company created an incentive stock
     ------------
     purchase agreement,  primarily for outside Directors.  Under the agreement,
     options to purchase  voting common stock were granted at $75,  based on the
     fair market value as determined  by the Board of  Directors,  per share and
     are exercisable based on the following schedule:

<TABLE>
<CAPTION>
                                            Number of
      Exercise Period                        Shares
     -------------------------------------  ---------
<S>                                         <C>
      January 1, 1999 to December 31, 2003     10,002
      January 1, 2000 to December 31, 2004     10,002
      January 1, 2001 to December 31, 2005      9,996
                                            ---------
                                               30,000
                                            =========
</TABLE>

     No options  were  exercised  for either of the years ended June 30, 2000 or
     1999.  Therefore,  as of June 30,  2000,  a total of  20,004  options  were
     exercisable.  Fair value of the options at the grant dates, as estimated by
     management, was nominal.

     During fiscal 1999,  the Company  created an employee  stock purchase plan.
     Under the plan,  12,003  Class A shares were issued to employees at $75 per
     share in exchange for cash and promissory notes bearing interest of 6.5% or
     8%, depending on the initial cash payment and recourse nature of the notes.
     The  Company  has  agreed to forgive  the notes  over a seven  year  period
     assuming  continued  employment;  therefore,  the notes are being amortized
     over the term of employment.  The Company has a  right-of-first  refusal to
     repurchase  any  shares  employees  wish to sell and in the event of death,
     disability  or  termination,  the Company has an option to  repurchase  the
     shares.


                                       36
<PAGE>
9.   EARNINGS PER SHARE

     A  reconciliation  of the  components  of basic and  diluted  net loss from
     continuing  operations  per  common  share  as of June  30,  for the  years
     indicated, is as follows:

<TABLE>
<CAPTION>
                                                                          Per-Share
                                                      Income      Shares    Amount
                                                   -------------  -------  --------
<S>                                                <C>            <C>      <C>
2000
----
       Basic and Diluted Earnings per Share
          Loss available to common shareholders    $(26,508,000)  660,928  $(40.11)
1999
----
       Basic and Diluted Earnings per Share
          Loss available to common shareholders    $(27,099,000)  672,973  $(40.27)
1998
----
       Basic and Diluted Earnings per Share
          Income available to common shareholders  $ (3,773,000)  665,074  $ (5.67)
</TABLE>

     The effect of stock options was not included in the  computation of diluted
     net loss per share during fiscal years 2000 and 1999 because to do so would
     have been  antidilutive.  There were no stock  options  outstanding  during
     fiscal 1998.


10.  UNCONSOLIDATED AFFILIATE

     The  Company  owns a 25.4%  interest  in the  successor  limited  liability
     corporation, Breitburn Energy Corporation ("BEC"). The Company's investment
     in BEC is accounted for under the equity method.  As the Company's share of
     net losses in BEC has exceeded the carrying amount of the  investment,  the
     investment has been reduced to zero until the Company's share of net income
     equals  its  share  of  unrecognized  net  losses.   Summarized   financial
     information  for BEC as of and for the years  ended  June 30, is as follows
     (in thousands):

<TABLE>
<CAPTION>
                                        2000      1999      1998
                                       -------  --------  --------
<S>                                    <C>      <C>       <C>
      Current assets                   $ 8,644  $ 5,914
      Oil and gas properties            79,480   50,415
      Other assets                       3,157    1,742
                                       -------  --------
         Total assets                  $91,281  $58,071
                                       =======  ========

      Current liabilities              $10,100  $ 5,340
      Long-term debt                    52,900   26,200
      Other liabilities                  1,131      190
      Equity                            27,150   26,341
                                       -------  --------
        Total liabilities and equity   $91,281  $58,071
                                       =======  ========

      Net sales                        $17,658  $11,655   $ 8,969
                                       =======  ========  ========
      Gross profit                     $ 3,179  $(1,218)  $ 2,379
                                       =======  ========  ========
      Net income (loss)                $ 1,155  $(2,557)  $(1,772)
                                       =======  ========  ========
</TABLE>


                                       37
<PAGE>
11.  OPERATING LEASES

     The Company has noncancelable  operating lease agreements for the rental of
     office space, computer and other equipment. Certain of these leases contain
     purchase  options or renewal  clauses.  Rental expense for operating leases
     was approximately  $1.2, $1.2 and $1.0 million for the years ended June 30,
     2000, 1999 and 1998, respectively.

     At June 30, 2000 future  minimum  lease  payments for each of the next five
     years and thereafter are as follows (in thousands):


                             2001       $      1,243
                             2002              1,090
                             2003                957
                             2004                792
                             2005                680
                       Thereafter                  -
                                        ------------
                                        $      4,762
                                        ============

12.  RELATED PARTY TRANSACTIONS

     The Company has entered into a rental  arrangement  for office space from a
     partnership in which certain  officers are partners.  Rent payments totaled
     $415,700, $374,200 and $339,470 for the years ended June 30, 2000, 1999 and
     1998, respectively.

     The Company advanced funds to certain  officers,  generally at 8% interest.
     Balances totaled $0.1 million and $0.5 million,  respectively,  at June 30,
     2000 and 1999.

     In 1998, the Company issued  promissory notes to certain  employees as part
     of a Class A incentive stock purchase agreement, whereby 13,669 shares were
     issued at $75 per share. The carry value of these notes was $1.0 million at
     June 30,  2000 and 1999.  The notes have  interest  rates of 6.5% and 8%. A
     provision in the agreement  cancels the  principal  balance if the employee
     remains in the continuous  employment of the Company  through  December 31,
     2005. In addition,  between 1995 and 1997, the Company issued 19,200 shares
     of common stock as part of an incentive  stock  option  agreement  with two
     officers. Promissory notes were issued for $0.2 million, which was also the
     carrying value at June 30, 2000 and 1999.  Interest rates are calculated at
     LIBOR plus 1.5%.  No  cancellation  provision  was included with this stock
     incentive program.

     The Company  advanced funds in 1988 to certain officers and directors at 8%
     interest,  secured by interests in oil and gas  properties and were payable
     out of net proceeds from the oil and gas  production  on these  properties.
     During fiscal 1999, Eastern American purchased the related working interest
     from the officers and directors, canceling the related notes.

     During  fiscal  1999,  the Company  purchased  from  certain  officers  and
     directors,  for  $2.4  million,  volumetric  production  from  wells in New
     Zealand.  Future production,  totaling 3.3 million Mcf, otherwise allocable
     to the officers and directors will be allocated to the Company. The Company
     has recorded the payment as an investment in oil and gas properties.



13.  COMMITMENTS AND CONTINGENCIES

     In 1993,  the Company sold working  interests  in certain  Appalachian  gas
     properties in connection with the formation of a royalty trust.


                                       38
<PAGE>
     A portion of the proceeds from the sale of these interests,  representing a
     term net profits  interest,  was accounted for as a production  payment and
     was  classified  as  deferred   trust   revenue.   Certain  gas  production
     attributable to the royalty trust is purchased by a wholly owned subsidiary
     of the Company pursuant to a gas purchase contract,  which expires in 2013.
     The purchase  price under the contract is based on  escalating  fixed price
     and spot market components. The fixed price component expired on January 1,
     2000. As of June 30, 2000,  the Company  determined  that due to the rising
     cost of transporting  gas and diminishing  margins,  losses are expected on
     the  Company's  purchase  commitment.  A purchase  commitment  loss of $4.9
     million was accrued and $6.2 million was  reclassified  from deferred trust
     revenue to other long term obligations.  Unamortized deferred trust revenue
     is $4.3 million and $12.0 million at June 30, 2000 and 1999, respectively.

     In connection with an existing gas delivery obligation  agreement,  whereby
     Eastern  American  received an advance  payment,  a  subsidiary  of Eastern
     American  entered into a credit line deed of trust,  which has an available
     balance  of  $5.0  million  as  of  June  30,  2000  to  collateralize  its
     performance  under the gas  delivery  obligation.  This credit line deed of
     trust declines at a rate of 7.5% per year.

     The Company is involved in various legal actions and claims  arising in the
     ordinary  course of business.  Management  does not expect these matters to
     have a material  adverse  effect on the  Company's  financial  position  or
     results of operations.



14.  FINANCIAL INSTRUMENTS

     The estimated  fair values of the Company's  financial  instruments,  as of
     June 30, have been  determined  using  appropriate  market  information and
     valuation  methodologies.  Considerable judgment is required to develop the
     estimates  of fair  value;  thus,  the  estimates  provided  below  are not
     necessarily  indicative  of the amount that the Company  could realize upon
     the sale or refinancing of such financial instruments (in thousands):

<TABLE>
<CAPTION>
                                          2000               1999
                                 ====================  ===================
                                 Carrying      Fair    Carrying     Fair
                                   Value      Value      Value     Value
                                 ---------  ---------  ---------  --------
<S>                              <C>        <C>        <C>        <C>
        Notes receivable         $   2,657  $  2,657   $   4,749  $  4,695
        Long-term debt             212,575   140,000     226,504   206,505
        Futures, swaps, options          -    (3,400)        490       430
</TABLE>

     The Company in estimating the fair value of its financial  instruments used
     the following methods and assumptions:

     Notes  Receivable  -  The notes receivable accrue interest at a fixed rate.
     -----------------
     Fair value was  estimated  using  discounted  cash  flows  based on current
     interest   rates  for  notes  with  similar  credit   characteristics   and
     maturities.

     Long-Term  Debt  -  A portion of long-term debt was borrowed under a senior
     ---------------
     revolving credit  facility,  which accrues interest at variable rates; as a
     result,  carrying value approximates fair value. The Company's subordinated
     debt is traded  publicly.  The market value at the end of the year was used
     for valuation  purposes.  The remaining portion of the Company's  long-term
     debt is comprised of fixed rate  facilities;  for this portion,  fair value
     was  estimated  using  discounted  cash  flows  based  upon  the  Company's
     estimated current borrowing rates for debt with similar maturities.

     Futures,  swaps and options - The fair value of these instruments are based
     ---------------------------
     on  quoted  market  prices.


                                       39
<PAGE>
15.  CONTRACT SETTLEMENT

     In March 1998,  the  Company  entered  into a  Termination  Agreement  (the
     "Agreement") with Seneca Power Partners,  L.P.  ("Seneca"),  which provided
     for the termination of a long-term gas sale and purchase  contract  between
     the  Company  and  Seneca.  Prior  to such  termination,  the  Company  was
     obligated  to deliver up to 12,000 Mcf of natural  gas per day to  Seneca's
     cogeneration facility. The Agreement was a direct result of an amendment to
     the existing  Power  Purchase  Agreement by and between  Seneca and Niagara
     Mohawk Power Corporation ("Niagara").  Niagara negotiated amendments to all
     of its existing Power Purchase Agreements as part of a Master Restructuring
     Agreement.   Pursuant  to  the   Agreement,   the  Company   received  cash
     consideration of approximately $22 million on June 30, 1998. As a result of
     this  termination,  the Company  estimated it would incur future  losses of
     approximately $2 million on its gas purchase commitments.  Accordingly, the
     provision for anticipated  losses was recorded as an offset to the contract
     settlement  income in fiscal  1998 and  amortized  against  the cost of gas
     purchased during fiscal 1999.

     Although  the  Company  terminated  all  rights and  obligations  under the
     contract,  the Company  retained  its 10% limited  partnership  interest in
     Seneca.  For the fiscal  year ended June 30,  1998,  the  Company  recorded
     partnership  distributions  of $10.0 million,  comprised of $7.2 million in
     cash and $2.8 million of Niagara  common stock.  The Niagara stock was sold
     in  November  1998 for $2.9  million.  No  partnership  distributions  were
     received in fiscal years 2000 or 1999.


                                       40
<PAGE>
16.  INDUSTRY SEGMENTS

     The Company's  reportable  business  segments have been identified based on
     the  differences  in  products  and  service  provided.  Revenues  for  the
     exploration and production segment are derived from the production and sale
     of natural  gas and crude oil.  Revenues  for the  marketing  and  pipeline
     segment arise from the  marketing of both Company and third party  produced
     natural gas volumes and the  related  transportation.  Management  utilizes
     earnings before interest, taxes, depreciation,  depletion, amortization and
     exploratory costs ("EBITDAX") to evaluate each segment's operations.

     Summarized  financial  information for the Company's reportable segments is
     shown in the following  table. The "other" column includes items related to
     corporate items (in thousands):

<TABLE>
<CAPTION>
                                          Exploration    Marketing
                                              and           and
                                          Production     Pipeline     Other     Consolidated
                                         -------------  -----------  --------  --------------
<S>                                      <C>            <C>          <C>       <C>
                   2000
 Sales to unaffiliated customers         $     29,763   $   72,156             $     101,919
 Intersegment revenues                                                                     -
 Depreciation, depletion, amortization         10,349        1,031       359          11,739
 Exploratory costs                              8,347                                  8,347
 Operating profit (loss)                       (5,048)      (6,871)   (4,576)        (16,495)
 Interest expense                                 110            2    22,190          22,302
 EBITDAX                                        9,270       (1,287)   (3,914)          4,069
 Total assets                                 122,033       67,522    19,341         208,896
 Capital expenditures                          19,074          148        77          19,299
---------------------------------------  -------------  -----------  --------  --------------
                   1999
 Sales to unaffiliated customers         $     24,836   $   81,279   $   191   $     106,306
 Intersegment revenues                                       7,194                     7,194
 Depreciation, depletion, amortization          9,713        1,104       350          11,167
 Exploratory costs                             19,261                                 19,261
 Operating profit (loss)                      (17,794)         929    (4,224)        (21,089)
 Interest expense                                 113                 20,009          20,122
 EBITDAX                                       11,638        2,033    (3,353)         10,318
 Total assets                                 121,852       58,420    35,666         215,938
 Capital expenditures                          22,139          506     2,600          25,245
---------------------------------------  -------------  -----------  --------  --------------
                   1998
 Sales to unaffiliated customers         $     26,523   $  136,279   $10,030   $     172,832
 Intersegment revenues                            958       19,669                    20,627
 Depreciation, depletion, amortization          9,285        1,066       159          10,510
 Exploratory costs                              8,262                                  8,262
 Operating profit (loss)                       (3,471)      14,925     5,971          17,425
 Interest expense                                 248                 19,875          20,123
 EBITDAX                                       10,736       15,991     6,382          33,109
 Total assets                                 129,621       64,955    24,467         219,043
 Capital expenditures                          19,952          590     2,359          22,901
---------------------------------------  -------------  -----------  --------  --------------
</TABLE>

     Operating  profit  represents   revenues  less  costs  which  are  directly
     associated  with such  operations.  Revenues are priced and  accounted  for
     consistently  for both  unaffiliated  and  intersegment  sales. The 'Other'
     column  includes items related to  non-reportable  segments,  corporate and
     elimination  items.  Included in the exploration and production segment are
     net long-lived  assets  located in New Zealand and Australia of $3.9,  $1.8
     and $1.4 million, as of June 30, 2000, 1999, and 1998.


                                       41
<PAGE>
SUPPLEMENTAL  INFORMATION  ON  OIL  AND  GAS  PRODUCING  ACTIVITIES  (UNAUDITED)

Costs - The following tables set forth capitalized costs as of June 30 and costs
-----
incurred,  including  capitalized overhead, for oil and gas producing activities
for  the  years  ended  June  30  (in  thousands):

<TABLE>
<CAPTION>
                                                  2000       1999       1998
                                                ---------  ---------  ---------
<S>                                             <C>        <C>        <C>
 Capitalized costs:
   Proved properties                            $208,271   $196,554   $187,689
   Unproved properties                            10,988     11,351     14,428
                                                ---------  ---------  ---------
   Total                                         219,259    207,905    202,117
   Less accumulated depletion and depreciation   (76,458)   (68,804)   (61,521)
                                                ---------  ---------  ---------
 Net capitalized costs                          $142,801   $139,101   $140,596
                                                =========  =========  =========

 Companyshare of equity method investeenet
   capitalized costs                            $ 18,693   $ 11,607   $  9,474
                                                =========  =========  =========

 Costs incurred:
   Acquisition of proved properties             $  4,160   $  2,088   $    694
   Development costs                               5,869      7,527      9,336
   Exploration costs                               8,693     13,589      9,154
                                                ---------  ---------  ---------
 Total costs incurred                           $ 18,722   $ 23,204   $ 19,184
                                                =========  =========  =========

 Companyshare of equity method investeetotal
   costs incurred                               $  7,759   $  3,966   $    944
                                                =========  =========  =========
</TABLE>

Results  of  Operations  -  The  results of operations for oil and gas producing
-----------------------
activities,  excluding corporate overhead and interest costs for the years ended
June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                2000      1999       1998
                                              --------  ---------  --------
<S>                                           <C>       <C>        <C>
 Revenues from sale of oil and gas            $23,869   $ 18,295   $20,730
 Less:
   Production costs                             8,849      9,005     8,545
   Production taxes                             1,198        964     1,073
   Exploration and impairment                   8,347     19,261     8,262
   Depletion, depreciation and amortization     8,847      7,915     7,599
   Income tax expense (benefit)                (1,181)    (6,597)   (1,662)
                                              --------  ---------  --------
 Income (loss) from oil and gas operations    $(2,191)  $(12,253)  $(3,087)
                                              ========  =========  ========

 Companyshare of equity method investee
   income from oil and gas operations         $ 1,857   $    183   $   714
                                              ========  =========  ========
</TABLE>

Production costs include those costs incurred to operate and maintain productive
wells  and  related  equipment  and  include  costs  such  as labor, repairs and
maintenance, materials, supplies, fuel consumed and insurance.  Production costs
are  net of well tending fees, which are included in well operations revenues in
the  accompanying  consolidated  statements  of  operations.

Exploration  and  impairment  expenses  include  the  costs  of  geological  and
geophysical  activity,  unsuccessful  exploratory wells and leasehold impairment
allowances.


                                       42
<PAGE>
Depletion,  depreciation  and  amortization  include  costs  associated  with
capitalized  acquisition,  exploration,  and  development  costs.

The  provision  for income taxes is computed at the statutory federal income tax
rate  and  is  reduced  to  the  extent of permanent differences which have been
recognized  in  the Company's tax provision, such as investment tax credits, and
the  utilization  of  Federal  tax  credits  permitted  for fuel produced from a
non-conventional  source.

Reserve  Quantity  Information  -  Reserve  estimates  are  subject  to numerous
------------------------------
uncertainties inherent in the estimation of quantities of proved reserves and in
the  projection  of  future  rates  of  production  and  timing  of  development
expenditures.  The  accuracy  of  such estimates is a function of the quality of
available  data  and  of engineering and geological interpretation and judgment.
Results  of  subsequent drilling, testing and production may cause either upward
or  downward  revisions  of previous estimates.  Further, the volumes considered
commercially  recoverable  fluctuate with changes in prices and operating costs.
Reserve  estimates,  by  their  nature,  are  generally  less precise than other
financial  statement  disclosures.

The  following table sets forth information for the years indicated with respect
to  changes  in the Company's proved reserves, substantially all of which are in
the  United  States.

<TABLE>
<CAPTION>
                                                          Natural Gas   Crude Oil
                                                             (Mmcf)      (Mbbls)
                                                          ------------  ----------
<S>                                                       <C>           <C>
Proved reserves:
  June 30, 1997                                               145,780       1,233
    Revisions of previous estimates                              (945)        (49)
    Extensions and discoveries                                 14,209         205
    Purchases of reserves in place                              1,002          79
    Sales of reserves in place                                                (11)
    Production                                                 (7,266)       (125)
                                                          ------------  ----------
  June 30, 1998                                               152,780       1,332
    Revisions of previous estimates                            (1,384)       (229)
    Extensions and discoveries                                  5,049          74
    Sales of reserves in place                                   (674)        (85)
    Production                                                 (7,184)       (133)
                                                          ------------  ----------
  June 30, 1999                                               148,587         959
    Revisions of previous estimates                             4,656          71
    Extensions and discoveries                                  2,185          66
    Purchases of reserves in place                              9,461
    Production                                                 (7,399)       (113)
                                                          ------------  ----------
  June 30, 2000                                               157,490         983
                                                          ============  ==========

Proved developed reserves:
  June 30, 1998                                               122,255         735
  June 30, 1999                                               126,962         714
  June 30, 2000                                               141,067         738

Companyshare of equity method investeeproved reserve at:
  June 30, 1998                                                 2,077       3,113
  June 30, 1999                                                 5,529       9,907
  June 30, 2000                                                 7,402      13,681
</TABLE>

Standardized  Measure of Discounted Future Net Cash Flows - Estimated discounted
---------------------------------------------------------
future  net  cash  flows  and changes therein were determined in accordance with
SFAS  No.  69,  "Disclosures  About  Oil and Gas Producing Activities."  Certain
information concerning the assumptions used in computing the valuation of proved
reserves  and  their  inherent  limitations  are  discussed  below.  The Company
believes such information is essential for a proper understanding and assessment
of  the  data  presented.


                                       43
<PAGE>
Future  cash  inflows  are computed by applying period-end prices of oil and gas
relating  to the Company's proved reserves to the period-end quantities of those
reserves.  Future  price  changes  are considered only to the extent provided by
contractual  arrangements  in  existence  at  period-end.

The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, or their present
worth.  In  addition,  variations  from the expected production rates also could
result  directly  or  indirectly  from factors outside of the Company's control,
such  as  unintentional  delays  in development, changes in prices or regulatory
controls.  The  reserve  valuation  further  assumes  that  all reserves will be
disposed  of  by production.  However, if reserves are sold in place, this could
affect  the  amount  of  cash  eventually  realized.

Future  development  and  production  costs  are  computed  by  estimating  the
expenditures  to  be incurred in developing and producing the proved oil and gas
reserves  at  the  end  of  the  year,  based  on  period-end costs and assuming
continuation  of  existing  economic  conditions.

Future  income  tax  expenses  are computed by applying the appropriate year-end
statutory  tax  rates and existing tax credits, with consideration of future tax
rates  already  legislated,  to the future pretax net cash flows relating to the
Company's  proved  oil  and  gas  reserves.

An  annual discount rate of 10% was used to reflect the timing of the future net
cash  flows  relating  to  proved  oil  and  gas  reserves.

Information  with  respect to the Company's estimated discounted future net cash
flows related to its proved oil and gas reserves as of June 30 is as follows (in
thousands):

<TABLE>
<CAPTION>
                                                        2000        1999        1998
                                                     ----------  ----------  ----------
<S>                                                  <C>         <C>         <C>
 Future cash in flows                                $ 606,382   $ 396,466   $ 412,866
 Future production and development costs              (178,968)   (144,274)   (151,068)
 Future income tax expense                            (121,000)    (47,000)    (48,241)
                                                     ----------  ----------  ----------
 Future net cash flows before discount                 306,414     205,192     213,557
 10% discount to present value                        (181,543)   (120,309)   (138,644)
                                                     ----------  ----------  ----------
 Standardized measure of discounted future net cash
   flows related to proved oil and gas reserves      $ 124,871   $  84,883   $  74,913
                                                     ==========  ==========  ==========

 Companyshare of equity method investee
   standardized measure of discounted future net
   cash flows                                        $  54,362   $  28,129   $  19,975
                                                     ==========  ==========  ==========
</TABLE>


                                       44
<PAGE>
Principal  changes  in  the  standardized  measure of discounted future net cash
flows  for  the  years  ended  June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                     2000       1999      1998
                                                   ---------  --------  ---------
<S>                                                <C>        <C>       <C>
 Standardized measure of discounted future
   net cash flows at beginning of period           $ 84,883   $74,913   $100,353
 Sales of oil and gas produced, net of
   production costs                                 (13,446)   (8,059)   (11,111)
 Net changes in prices and production costs          57,741    (1,107)    (8,192)
 Changes in production rates and other              (10.418)    5,421    (33,132)
 Extensions, discoveries and other additions, net
   of future production and development costs         2,886     3,977      5,657
 Changes in estimated future development costs        2,099     2,701     (1,495)
 Development costs incurred                           5,869     7,527      9,336
 Revisions of previous quantity estimates             5,731    (2,234)      (809)
 Purchase of reserves in place                       10,572                1,126
 Sales of reserves in place                                      (918)       (55)
 Accretion of discount                                8,488     7,491     10,035
 Net change in income taxes                         (29,534)   (4,829)     3,200
                                                   ---------  --------  ---------
 Standardized measure of discounted
   future net cash flows at end of period          $124,871   $84,883   $ 74,913
                                                   =========  ========  =========
</TABLE>


                                    * * * * *



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

There  have  been  no changes in or disagreements with accountants on accounting
and  financial  disclosure.


                                       45
<PAGE>
                                    PART III
                                    --------


                ITEM 10.     DIRECTORS AND OFFICERS OF REGISTRANT
                --------     ------------------------------------

     The  executive  officers  and  Directors  of  the Company and the executive
officers  of its subsidiaries on June 30, 2000 are listed below, together with a
description  of  their  experience  and  certain  other information.  All of the
Directors  were  re-elected  for  a one year term at the Company's December 1999
annual  meeting  of stockholders.  Executive officers are appointed by the Board
of  Directors.


<TABLE>
<CAPTION>
Name                     Age               Position with Company or Subsidiary
-----------------------  ---  --------------------------------------------------------------
<S>                      <C>  <C>

John Mork                 52  President and Chief Executive Officer of the Company; Director
Joseph E. Casabona        57  Executive Vice President of the Company; Director
Michael S. Fletcher       51  Chief Financial Officer and Treasurer of the Company;
                              President of Mountaineer
J. Michael Forbes         40  Vice President of the Company
Donald C. Supcoe          44  Secretary of the Company; Senior Vice President of Mountaineer
Pamela T. Gates           53  Assistant Secretary of the Company
Edward J. Davies          58  President of Westech
W. Gaston Caperton, III   60  Director
Peter H. Coors            53  Director
L. B. Curtis              76  Director
John J. Dorgan            76  Director
Arthur C. Nielsen, Jr.    81  Director
F. H. McCullough, III     53  Director
Julie Mork                50  Director
</TABLE>


     W. Gaston Caperton, III, has been a Director of the Company since 1997.  He
served as the Governor of the State of West Virginia for two terms, from 1989 to
1997.  Governor Caperton is President and Chief Executive Officer of The College
Board  and  President of the Caperton Group.  Governor Caperton presently serves
on  the  Boards  of  Directors  of  Owens  Corning  and  United  Bankshares.

     Joseph  E. Casabona is Executive Vice President of the Company and has been
a  Director  since  its formation.  Mr. Casabona joined Eastern American in 1985
and  was  Executive  Vice President of Eastern American and a Director from 1987
until  1993.  Mr.  Casabona  was employed in various audit staff capacities from
1967 to 1979 in the Pittsburgh, Pennsylvania office of KPMG Main Hurdman ("KPMG,
Peat  Marwick"),  became a partner in the Firm in 1980 and was named Director of
Accounting  and  Auditing  of  the  Pittsburgh  office  in  1983.  Mr.  Casabona
graduated from the University of Pittsburgh with a Bachelor of Science Degree in
Business  Administration  and from the Colorado School of Mines with a Master of
Science  Degree  in Mineral Economics.  Mr. Casabona has been a Certified Public
Accountant  since  1969.  Mr.  Casabona  has  been  a  member  of  the Boards of
Directors  of  the  West  Virginia  and  Pennsylvania  Independent  Oil  and Gas
Associations.

     Peter H. Coors has been a Director of the Company since 1996.  Mr. Coors is
Chairman  of  the Board and Chief Executive Officer of Coors Brewing Company and
Chief  Executive  Officer  of  Adolph  Coors  Company.  He received his Bachelor
Degree  in  Industrial Engineering from Cornell University in 1969 and he earned
his  Master  Degree  in Business Administration from the University of Denver in
1970.  Mr.  Coors  also  serves  on  the  Board  of  Directors  of  USBank Corp.


                                       46
<PAGE>
     L.B.  Curtis has been a Director of the Company since 1993.  Mr. Curtis was
a Director of Eastern American from 1988 until 1993.  Mr. Curtis is retired from
a  career  at  Conoco,  Inc.  where  he  held  the position of Vice President of
Production  Engineering with Conoco Worldwide.  Mr. Curtis was highly recognized
across  the  Petroleum  Industry  in  the  upstream (exploration and production)
segment of the industry.  Mr. Curtis graduated from The Colorado School of Mines
with  an  Engineer  of  Petroleum  Professional  degree.

     Edward  J.  Davies  has  been President of Westech and Managing Director of
Westech  Energy  New Zealand since 1994.  Previously, Mr. Davies was with Conoco
Inc.,  where  his  most  recent  positions  were General Manager Exploration and
Managing  Director  Nigeria.  Mr.  Davies holds a Bachelor of Science in Geology
from  the  University  of  Wales,  a  Doctor  of  Philosophy in Geology from the
University  of Alberta, and a Master of Science from the Massachusetts Institute
of  Technology  Sloan  School  of  Management.

     John J. Dorgan has been a Director of the Company since 1993.  He served as
a  Director  for  Eastern  American  in  1992.  He  is  a  former Executive Vice
President and consultant to Occidental Petroleum Corporation where he had worked
in  various  capacities  since  1972.

     Michael  S.  Fletcher has been Chief Financial Officer and Treasurer of the
Company  since  December  1999.  In addition, Mr. Fletcher has been President of
Mountaineer  since  August 1998.  Prior to that time, he also held the positions
of  Senior  Vice  President  and Chief Financial Officer of Mountaineer.  Before
joining  Mountaineer  in 1987, Mr. Fletcher was a partner of Arthur Andersen and
Company  and  was  employed  by  that firm for fifteen years.  Mr. Fletcher is a
Certified  Public  Accountant  and  a  board  member  for  the Board of Risk and
Insurance  Management  for  the  State of West Virginia.  Mr. Fletcher graduated
from  Utah  State  University  with  a  Bachelor  Degree  in  Accounting.

     J. Michael Forbes has been Vice President of the Company since 1995.  Prior
to  that,  Mr.  Forbes  was an officer with Eastern American, which he joined in
1982.  Mr.  Forbes  graduated  with a Bachelor of Arts in Accounting and Finance
from  Glenville  State  College  and  is a Certified Public Accountant.  He also
holds  a  Master  of  Business  Administration from Marshall University and is a
graduate  of  Stanford  University's  Program  for  Chief  Financial  Officers.

Pamela  T.  Gates  has  been Assistant Secretary of the Company since 1999.  Ms.
Gates  joined  the  Company  in  1984 and is employed as an Executive Assistant.

     F.  H. McCullough, III, has been a Director of the Company since 1993.  Mr.
McCullough  was  a  Director  of  Eastern  American  from  1978 until 1993.  Mr.
McCullough  joined  Eastern  American  in  1977 and served in various capacities
until  1999.  He  is  currently  President of Neumedia, Inc. of Charleston, West
Virginia, a fiber optic carrier.  Mr. McCullough is a graduate of the University
of Southern California with a Bachelor of Arts Degree in International Economics
and  two  Masters  Degrees  in  Business  Administration  and  Financial Systems
Management.  He  is  a  graduate of the Northwestern University Kellogg Graduate
School  of  Management  Executive  Marketing  Program.

John  Mork  has  been President and Chief Executive Officer of the Company and a
Director  of  the  Company  since  its  formation.  Mr.  Mork  served in various
capacities at Union Oil Company until 1972 when he joined Pacific States Gas and
Oil, Inc. and subsequently founded Eastern American.  Mr. Mork was President and
a  Director  of  Eastern  American  from  1973  until  1993.  Mr. Mork is a past


                                       47
<PAGE>
Director  of  the  Independent  Petroleum  Association  of  America,  and  the
Independent  Oil  and Gas Association of West Virginia.  He was chapter chairman
of  the  Young  Presidents'  Organization,  Inc.,  Rocky  Mountain  Chapter  in
1994-1995.  Mr.  Mork  also  founded  the  Mountain  State  Chapter of the Young
Presidents' Organization located in Charleston, West Virginia.  Mr. Mork holds a
Bachelor  of  Science  Degree  in  Petroleum  Engineering from the University of
Southern California and he is a graduate of the Stanford Business School Program
for  Chief  Executive  Officers.  He  is  the  husband  of  Julie  Mork.

     Julie  M.  Mork  has  been a Director of the Company since 1993.  She was a
Director  of  Eastern  American  from  1974  until  1993.  Mrs. Mork served as a
founder  and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern
American.  Mrs.  Mork  received  a  Bachelor  of Arts Degree in History from the
University  of  California  in  Los  Angeles.  She  is  the  wife  of John Mork.

     Arthur  C.  Nielsen, Jr. has been a Director of the Company since 1993.  He
was a Director of Eastern American from 1985 until 1993.  He serves on the Board
of  Directors  of  General  Binding  Corporation.

     Donald  C.  Supcoe  has been the Senior Vice President of Mountaineer since
August  1998  and  has  served  as  the Corporate Secretary of the Company since
December  1998.  Prior to joining Mountaineer in August of 1998, he was the Vice
President,  General  Counsel  and Secretary of Eastern American with whom he had
been employed since 1981.  Mr. Supcoe is a past President of the Independent Oil
and  Gas  Association  of  West  Virginia  and  a  past  Vice  President  of the
Independent  Petroleum  Association  of America.  Mr. Supcoe graduated from West
Virginia  University  with  a  Bachelor  of  Science  Degree  in  Business
Administration.  Mr.  Supcoe received a Doctor of Jurisprudence Degree from West
Virginia  University  College  of  Law.


                                       48
<PAGE>
                       ITEM 11.     EXECUTIVE COMPENSATION
                       --------     ----------------------

     The  following  table  sets  forth  for fiscal year 2000 the total value of
compensation  of  (i)  the Company's Chief Executive Officer and (ii) each other
executive  officer  of  the  Company.

<TABLE>
<CAPTION>
                                                      Salary    Bonus     Other         Total
                                                     --------  --------  -------       --------
<S>                                                  <C>       <C>       <C>      <C>  <C>
John Mork                                            $253,141  $116,350  $40,051  (1)  $409,542
   President and Chief Executive Officer
Joseph E. Casabona                                    223,762    55,853   11,363  (2)   290,978
   Executive Vice President
Michael S. Fletcher                                   228,298   168,702   30,053  (3)   427,053
   Chief Financial Officer and Treasurer
   President of Mountaineer Gas Company
Edward J. Davies                                      184,885    31,000    5,587  (4)   221,472
   President of Westech Energy Corporation
Donald C. Supcoe                                      180,833    41,599   28,203  (5)   250,635
   Senior Vice President of Mountaineer Gas Company
_______________
<FN>
(1)  Includes  $7,141 in compensation related to insurance policies provided for the benefit of
     John  Mork, $29,041  for  personal  use  of  company  owned  assets  and  $3,869  in  401K
     matching contributions.
(2)  lncludes  $5,377 in compensation related to insurance policies provided for the benefit of
     Joseph  E.  Casabona,  $2,603  for  personal  use  of  company  owned  assets  and  $3,383
     in  401K  matching contributions.
(3)  Includes  $552  in compensation related to an insurance policy provided for the benefit of
     Michael  S.  Fletcher,  $19,496  for  personal  use  of  company  owned assets and $10,005
     for employee dependent tuition  assistance.
(4)  Includes  $681  in compensation related to an insurance policy provided for the benefit of
     Edward  J.  Davies, $1,507 for  personal  use  of  company  owned  assets  and  $3,399  in
     401K  matching contributions.
(5)  Includes  $216  in compensation related to an insurance policy provided for the benefit of
     Donald  C.  Supcoe,  and  $27,987  for  personal  use  of  company  owned  assets.
</TABLE>


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

     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the  share  ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company  by  all directors and executive officers as a group, in each case as of
September  1,  2000.  The  business  address of each officer and director listed
below  is:  c/o  Energy  Corporation  of  America,  4643  S. Ulster, Suite 1100,
Denver,  Colorado  80237.


                                       49
<PAGE>
<TABLE>
<CAPTION>
                                                     Beneficial Ownership
                                                        Common Stock
                                                     -------------------
                                                      Number
                                                     of Shares  Percent
                                                     ---------  --------
<S>                                                  <C>        <C>
 Kenneth W. Brill (1)                                   63,610     9.79%
 W. Gaston Caperton, III                                   480        *
 Joseph E. Casabona                                     30,376     4.68%
 Peter H. Coors                                            946        *
 L. B. Curtis                                           10,660     1.64%
 John J. Dorgan                                          1,130        *
 F. H. McCullough, III (3)                              90,485    13.93%
 John Mork (2)                                         369,943    56.95%
 Julie Mork (2)                                        369,943    56.95%
 Arthur C. Nielsen, Jr.                                 36,480     5.62%
 Donald C. Supcoe                                        3,200        *

 All officers and Directors as a group (11 persons)    607,310    93.49%
 _______________
<FN>
   *  Less  than  one  percent.
 (1)  Pursuant  to  agreements  dated June 30, 1993 and July 8, 1996, Kenneth W.
      Brill  granted  the  Company options to purchase 15,400 and 75,850 shares,
      respectively, of the Company Common Stock owned  by  him,  of which 31,650
      have been purchased by the Company.
 (2)  Includes  361,380  shares  held  by  John and Julie Mork as joint tenants,
      2,663 shares  held  by  Julie  Mork individually, and 2,950 shares held by
      each of the Alison Mork  Trust and  the  Kyle  Mork  Trust.
 (3)  Includes 88,405 shares held by F.H. McCullough, III and  Kathy  McCullough
      as  joint tenants, 880 shares  held  by the Katherine F. McCullough Trust,
      and 400 shares  held  by each of the Lesley McCullough Trust, the Meredith
      McCullough Trust and the Kristin McCullough  Trust.
</TABLE>

     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial  owner  of  more  than 5% of the outstanding shares of Class A Stock,
(ii)  the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive  officers  as  a  group,  in  each  case as of September 1, 2000.  The
business  address  of  each  officer  an  director  listed below is:  c/o Energy
Corporation  of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado
80237.


                                       50
<PAGE>
<TABLE>
<CAPTION>
                                                    Beneficial Ownership
                                                       Class A Stock
                                                    -------------------
                                                     Number
                                                    of Shares  Percent
                                                    ---------  --------
<S>                                                 <C>        <C>
 Joseph E. Casabona                                     5,791    30.02%
 Edward J. Davies                                       4,542    23.54%
 Michael S. Fletcher                                    2,250    11.60%
 John Mork (1)                                            796     4.13%
 Julie Mork (1)                                           796     4.13%
 Arthur C. Nielsen, Jr.                                 1,160     6.01%
 Donald C. Supcoe                                       1,667     8.64%

 All officers and Directors as a group (7 persons)     16,206    83.94%
_______________
<FN>

*    Less  than  one  percent
(1)  Includes  796  shares  held  by  John  and  Julie  Mork  as  joint tenants.
</TABLE>


                     ITEM 13.     CERTAIN RELATIONSHIPS AND
                     --------     -------------------------
                              RELATED TRANSACTIONS
                              --------------------

     Certain officers and Directors of the Company and members of their families
regularly  participate  in  the  wells drilled by the Company on an actual costs
basis and share in the costs and revenues on the same basis as the Company.  The
Company  has  the  right  to  select  the  wells drilled and each participant is
involved  in all wells included within a Company drilling program (the "Drilling
Program")  and cannot selectively choose the wells in which to participate.  The
Company  typically  has  a  development  drilling  component  and  an
exploration-drilling  component  within  each  year's  Drilling  Program.  The
officers  and  Directors  and  their family members may participate in either or
both  of  the  components.  The  following  table  identifies  the participants'
aggregate  investment  in  the  calendar  years  shown  (in  thousands):


                                       51
<PAGE>
<TABLE>
<CAPTION>
                                   (4)     (5)
                                  2000     1999    1998
                                 -------  ------  ------
<S>                              <C>      <C>     <C>
 Dale P. Andrews                 $   12   $  11   $   13
 K.W. Brill                                  60      174
 Gaston Caperton                    100              392
 Joseph E. Casabona                  50      37       52
 Peter Coors                         50      28       52
 L.B. Curtis                        129      70      109
 E.J. Davies                        129     113      101
 John J. Dorgan                      25      43       52
 Michael S. Fletcher                 50
 J. Michael Forbes                                     8
 Richard L. Grant                                     28
 F.H. McCullough, III                        85      160
 Lesley McCullough Trust (2)                           8
 Kristen McCullough Trust (2)                          8
 Meredith McCullough Trust (2)                         8
 Katherine McCullough Trust (2)                        8
 John Mork (1)                      771     351      799
 Alison Mork Trust (3)               25      28       41
 Kyle Mork Trust (3)                 25      28       41
 Arthur C. Nielsen, Jr.              50      43      139
 Kent Schamp                         26
 Donald C. Supcoe                                      8
 ECA Foundation                                       78
                                 -------  ------  ------
 Total                           $1,442   $ 897   $2,279
                                 =======  ======  ======
<FN>
 _______________
 (1)  Interest  of  John  Mork  and  Julie  Mork  held  as  joint  tenants.
 (2)  Trusts for minor children of F. H. McCullough, III and Kathy L. McCullough.
 (3)  Trusts  for  minor  children  of  John  Mork  and  Julie  Mork.
 (4)  These  amounts  represent  only the amounts committed to the 2000 Drilling
      Program,  the  actual investment  may  vary.
</TABLE>


     Certain  officers,  Directors  and  key employees of the Company have notes
payable  to  the  Company  related to employee incentive stock options that were
granted  and  exercised.  The  notes  bear  various interest rates, ranging from
LIBOR to 8% per annum.  As of June 30, 2000, in excess of $60,000, the following
were  indebted  to  the  Company  (in  thousands):

<TABLE>
<CAPTION>
<S>                   <C>
 Dale P. Andrews      $   63
 Joseph E. Casabona      187
 Edward J. Davies        319
 J. Michael Forbes        96
 Michael S. Fletcher     187
 Donald C. Supcoe        209
                      ------
    Total             $1,061
                      ======
</TABLE>


                                       52
<PAGE>
     Certain  officers and Directors of the Company have borrowed money from the
Company  and  have executed promissory notes.  The notes bear interest at 8% per
annum.  As  of  June  30,  2000,  the following were indebted to the Company (in
thousands):

<TABLE>
<CAPTION>
<S>                      <C>
 Michael S. Fletcher  *  $115
<FN>
 _______________
 *  Promissory  note  is  being  forgiven  over  three  years,  assuming
     continuing  employment.
</TABLE>


     During  fiscal  1999,  the  Company  purchased  from  certain  officers and
directors  volumetric  production from wells in New Zealand.  Future production,
otherwise  allocable  to  the  officers  and  directors will be allocated to the
Company.  The  following  table  identifies  the  participants'  interest:

<TABLE>
<CAPTION>
                             Payment      Volumes
                         (in thousands)    Mmcf
                         ---------------  -------
<S>                      <C>              <C>
 Dale P. Andrews         $            20     26.7
 K.W. Brill                          200    266.7
 Gaston Caperton                     600    800.0
 Joseph E. Casabona                   50     66.7
 Peter Coors                          50     66.7
 L.B. Curtis                         150    200.0
 E.J. Davies                         150    200.0
 John J. Dorgan                       50     66.7
 Thomas R. Goodwin                    50     66.7
 Richard L. Grant                     50     66.7
 F.H. McCullough, III                150    200.0
 John Mork                           750  1,000.0
 Alison Mork Trust                    50     66.7
 Kyle Mork Trust                      50     66.7
 Arthur C. Nielsen, Jr.               94    125.3
                         ---------------  -------
 Total                   $         2,464  3,285.6
                         ===============  =======
</TABLE>

     The  Company  rents  office  space in Charleston, West Virginia from Energy
Centre,  Inc.  a  corporation owned 42.86% by John Mork, 21.42% by each of F. H.
McCullough, III and Joseph E. Casabona and 7.15% by each of Donald C. Supcoe and
J.  Michael Forbes.  The aggregate amount paid by the Company for rent to Energy
Centre,  Inc. was $415,700 for fiscal year 2000.  The Company believes that such
rental  terms  are  no  less  favorable  than  could  have been obtained from an
unaffiliated  party.


                                       53
<PAGE>
                                     PART IV
                                     -------

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

(a)1.       Financial Statements
            The Financial Statements are filed as a part of this annual report
            at Item 8.

2.          Financial Statement Schedules
            The Financial Statements are filed as a part of this annual report
            at Item 8.

3.          Exhibits
            The following is a complete list of Exhibits filed as part of, or
            incorporated by reference to this Registration Statement:

     *     3.1     Articles  of  Incorporation of Energy Corporation of America.
     *     3.2     Amended  Articles  of  Incorporation of Energy Corporation of
                   America.
     *     3.3     Amended  Bylaws  of  Energy  Corporation  of  America.
     *     4.1     Credit Agreement among Energy Corporation of America, General
                   Electric  Capital  Corporation  as  Agent,  and  the lenders
                   named therein, dated  as  of  May  20,  1997.
     *     4.2     Note  Purchase  Agreement between Mountaineer Gas Company and
                   The John  Hancock  Mutual  Life Insurance Company dated as of
                   October 12,  1995.
     *     4.3     Indenture,  dated  as  of  May  23,  1997,  between  Energy
                   Corporation  of America and The Bank of New York, as Trustee,
                   with respect to the 9 1/2% Senior Subordinated Notes Due 2007
                   (including form of 9 1/2% Senior Subordinated Note Due  2007.
     *     4.4     Form  of  9 1/2% Senior Subordinated Note due 2007, Series A.
           4.5     Registration Rights Agreement, dated as of May 20, 1997,
                   among Energy  Corporation  of  America,  as issuer, and Chase
                   Securities Inc. and Prudential Securities  Inc.
     *    10.1     Eastern  American  Energy Corporation  Profit/Incentive Stock
                   Plan  dated  as  of  June  4,  1997.
     *    10.2     Buy-Sell  Stock  Option  Agreement  dated  as of May 19, 1997
                   among  Energy Corporation of  America, F.H.  McCullough,  III
                   and  Kathy  L. McCullough.
     *    10.3     Buy-Sell  Stock  Option  Agreement  dated  as of July 8, 1996
                   between  Energy Corporation of America and Kenneth W.  Brill.
     *    10.4     Gas  Purchase  Contract  dated as of January 1, 1993 between
                   Eastern  American  Energy  Corporation  and Eastern Marketing
                   Corporation.
     *    10.5     FTSI Service Agreement No. 37994 dated as of November 1,1993
                   between  Mountaineer  Gas  Company  and  Columbia  Gulf
                   Transmission Company.


                                       54
<PAGE>
     *    10.6     Service  Agreement  No.  42794  dated  as of November 1,1994
                   between  Mountaineer  Gas  Company  and  Columbia  Gulf
                   Transmission Company.
     *    10.7     SST  Service Agreement No. 38087 dated as of November 1,1993
                   between  Mountaineer  Gas  Company  and  Columbia  Gas
                   Transmission Corporation.
     *    10.8     FTS  Service Agreement No. 38137 dated as of November 1,1993
                   between  Mountaineer  Gas  Company  and  Columbia  Gas
                   Transmission Corporation.  (Previously misidentified as  FTS
                   Service Agreement No. 38037)
     *    10.9     Supplement  No.  1  to  Transportation Service Agreement No.
                   38137  dated  as  of  May  6,  1994  between Mountaineer Gas
                   Company and Columbia Gas Transmission  Corporation.
     *   10.10     FSS Service Agreement No. 38077 dated as of November 1,1993
                   between  Mountaineer  Gas  Company  and  Columbia  Gas
                   Transmission Corporation.
     *   10.11     NTS Service Agreement No. 39272 dated as of November 1,1993
                   between  Mountaineer  Gas  Company  and  Columbia  Gas
                   Transmission Corporation.
     *   10.12     FTS Service Agreement No. 38113 dated as of November 1,1993
                   between Mountaineer  Gas  Company  and  Columbia  Gas
                   Transmission Corporation.
     *   10.13     Supplement  No.  1  to Transportation Service Agreement No.
                   38113  dated  as  of  May 6, 1994 between Mountaineer Gas
                   Company and Columbia Gas Transmission  Corporation.
     *   10.14     Gas  Transportation  Agreement  dated as of October 1, 1994
                   between  Mountaineer  Gas  Company  and  Tennessee  Gas
                   Pipeline Company.
     *   10.15     Amendment No. 1 to Gas Transportation Agreement dated as of
                   May  5,  1995 between  Mountaineer  Gas  Company  and
                   Tennessee  Gas  Pipeline Company.
     *   10.16     FTS  Service Agreement No. 60266 dated May 20, 1998 between
                   Mountaineer  Gas  Company  and  Columbia  Gas  Transmission
                   Corporation.
     *   10.17     Incentive  Stock Purchase Agreement dated February 12, 1999
                   by and between  Energy  Corporation  of America and Michael
                   S. Fletcher.
     *   10.18     Incentive  Stock Purchase Agreement dated December 16, 1998
                   by and between  Energy  Corporation  of  America and Joseph
                   E. Casabona.
     *   10.19     Incentive  Stock Purchase Agreement dated December 16, 1998
                   by and between Energy Corporation  of  America  and  Edward
                   J. Davies.
     *   10.20     Incentive  Stock Purchase Agreement dated December 16, 1998
                   by  and between Energy Corporation of  America  and  Donald
                   C. Supcoe.
     *   10.21     Incentive  Stock Purchase Agreement dated March 19, 1999 by
                   and  between  Energy  Corporation  of America and W. Gaston
                   Caperton III.
     *   10.22     Incentive  Stock Purchase Agreement dated March 19, 1999 by
                   and  between  Energy  Corporation  of  America  and  Peter
                   H.  Coors.
     *   10.23     Incentive  Stock Purchase Agreement dated March 19, 1999 by
                   and  between  Energy  Corporation  of  America  and  L.B.
                   Curtis.
     *   10.24     Incentive  Stock Purchase Agreement dated March 19, 1999 by
                   and  between  Energy  Corporation  of  America  and  J.  J.
                   Dorgan.


                                       55
<PAGE>
     *   10.25     Incentive  Stock Purchase Agreement dated March 19, 1999 by
                   and  between  Energy  Corporation  of  America  and A. C.
                   Nielsen, Jr.
     *   10.26     Stock  Purchase  Agreement  dated  February 17, 1999 by and
                   among Westech Energy Corporation, Westech Energy New Zealand
                   Limited and Edward J.  Davies.
     *   10.27     First  Amendment  to  Credit  Agreement  and Assignment and
                   Waiver  dated  September  26,  1997  by  and  among  Energy
                   Corporation of America, General  Electric  Capital
                   Corporation, The Bank of Nova Scotia, and Union Bank  of
                   California,  N.A.
     *   10.28     Second  Amendment  to Credit Agreement dated  April 2, 1999
                   by and among Energy Corporation of America, General Electric
                   Capital Corporation, The Bank of Nova Scotia, and Union Bank
                   of California,  N.A.
     *   10.29     Third  Amendment  to  Credit Agreement dated  September 27,
                   1999 by  and  among  Energy  Corporation of America, General
                   Electric Capital Corporation,  The  Bank  of  Nova  Scotia,
                   and  Union  Bank  of California,  N.A.
     *   10.30     Natural Gas Supply management Agreement dated September 20,
                   1998  by  and between Coral  Energy  Resources,  L.P.,  Coral
                   Energy, L.P. and Mountaineer.
         10.31     Gas  Sale  and  Purchase  Agreement  dated December 20, 1999
                   between  Energy  Corporation  of America and Allegheny Energy
                   Service Corporation.
         10.32     Participation  Agreement  dated  December.  20, 1999 between
                   Energy  Corporation of America and Allegheny  Energy,  Inc.
         10.33     Management  Agreement dated December 20, 1999 between Energy
                   Corporation  of  America  and  Allegheny  Energy  ,  Inc.
         10.34     Oil and Gas Lease and Development Agreement dated August 16,
                   2000  between  Allegheny  Energy, Inc., Monongahela Power
                   Company, West Virginia  Power  and Transmission Company, and
                   Energy Corporation  of  America.
         10.35     Employment  Agreement effective as of August 18, 2000 by and
                   between  Energy  Corporation  of  America  and  Michael  S.
                   Fletcher.
         10.36     Employment  Agreement effective as of August 18, 2000 by and
                   between Energy Corporation of America and Donald C.  Supcoe.
         21.1      Subsidiaries  of  Energy  Corporation  of  America.
         25.1      Power  of  Attorney set forth on the signature page contained
                   in  Part V.
         27.1      Financial  Data  Schedule.

          previously  filed


                                       56
<PAGE>
(b)  Reports on Form 8-K

     The Company filed a report on Form 8-K, Item 5, dated January 10, 2000,
     reporting the arrangement to enter into a stock purchase agreement to sell
     its utility operations, Mountaineer Gas Company, to Allegheny Energy, Inc.

     The Company filed a report on Form 8-K, Item 2, dated August 18, 2000
     reporting the sale of its utility operations, Mountaineer Gas Company,
     to Allegheny Energy, Inc.

     The Company filed a report on Form 8-K, Item 5, dated August 18, 2000
     reporting the decision to terminate its revolving credit facility with
     General Electric Capital Corporation.


                                    * * * * *


                                       57
<PAGE>
                                     PART V
                                     ------


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 the 27th day of
September  2000.

                                   ENERGY  CORPORATION  OF  AMERICA

                           By:     /s/  John  Mork
                                   -----------------------------------------
                                   John  Mork
                                   President  and  Chief  Executive  Officer


                                       58
<PAGE>
                                POWER OF ATTORNEY
                                -----------------

     Each  of  the  undersigned  officers and directors of Energy Corporation of
America  (the  "Company")  hereby  constitutes and appoints John Mork, Joseph E.
Casabona  and  Michael  S. Fletcher and each of them (with full power to each of
them  to  act  alone), his true and lawful attorney-in-fact and agent, with full
power  of  substitution,  for  him  and on his behalf and in his name, place and
stead, in any and all capacities, to sign, execute and file this Form 10-K under
the  Securities  Act  of 1934, as amended, and any or all amendments (including,
without  limitation,  post-effective  amendments), with all exhibits and any and
all documents required to be filed with respect thereto, with the Securities and
Exchange  Commission  or  any  regulatory  authority,  granting  unto  such
attorneys-in-fact  and  agents,  and  each  of them acting alone, full power and
authority  to do and perform each of every act and thing requisite and necessary
to be done in and about the premises in order to effectuate the same, as full to
all  intents and purposes as he himself might or could do if personally present,
hereby  ratifying  and  confirming all the such attorneys-in-fact and agents, or
any  of them, or their substitute or substitutes, may lawfully do or cause to be
done.

Pursuant  to  the requirements of the Securities Act of 1934, this Form 10-K has
been  signed  on  the ___ day of September 2000, by the following persons in the
capacities  indicated.


                                       59
<PAGE>
<TABLE>
<CAPTION>
          Signature                              Title
--------------------------  ------------------------------------------------
<S>                         <C>
/s/ John Mork
--------------------------
John Mork                   President, Chief Executive Officer and Director
                            (Principal executive officer)

/s/ Joseph E. Casabona
--------------------------
Joseph E. Casabona          Executive Vice President and Director

/s/ Michael S. Fletcher
--------------------------
Michael S. Fletcher         Chief Financial Officer and Treasurer
                            (Principal accounting and financial officer)

/s/ F. H. McCullough III
--------------------------
F. H. McCullough III        Director

/s/ Gaston Caperton
--------------------------
Gaston Caperton             Director

/s/ Peter H. Coors
--------------------------
Peter H. Coors              Director

/s/ L. B. Curtis
--------------------------
L. B. Curtis                Director

/s/ John J. Dorgan
--------------------------
John J. Dorgan              Director

/s/ Julie Mork
--------------------------
Julie Mork                  Director

/s/ Arthur C. Nielsen, Jr.
--------------------------
Arthur C. Nielsen, Jr.      Director
</TABLE>


                                       60
<PAGE>