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, 2001.

                                       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  [ ]


                                        1
<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  number  of  shares  and  market  value  of  common stock held by
non-affiliates  of  the  registrant at September 1, 2001 was 45,342 shares.  The
market  value  held  by  non-affiliates  is  unavailable.


The  number  of  shares  of  the  registrant's common stock, par value $1.00 per
share,  outstanding  at  September  1,  2001  was  635,685  shares.



                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE


                                        2
<PAGE>
<TABLE>
<CAPTION>
                                 ENERGY CORPORATION OF AMERICA

                                       TABLE OF CONTENTS

                                                                                              Page
<S>         <C>                                                                                <C>
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 . . . . . . . . . . . . . . .  11
Part  II
  Item 5.   Market for the Registrant's Common Stock and Related Stockholder Matters. . . . .  11
  Item 6.   Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  12
  Item 7.   Management's Discussion and Analysis of Results of Operations
             and Financial Condition. . . . . . . . . . . . . . . . . . . . . . . . . . . . .  12
  Item 7A.  Quantitative and Qualitative Disclosures About Market Risk. . . . . . . . . . . .  19
  Item 8.   Consolidated Financial Statements and Supplementary Data
              Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . . . . . .  20
              Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  21
              Statements of Operations. . . . . . . . . . . . . . . . . . . . . . . . . . . .  23
              Statements of Stockholders Equity (Deficit) . . . . . . . . . . . . . . . . . .  24
              Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . . . . .  25
              Statements of Comprehensive Income. . . . . . . . . . . . . . . . . . . . . . .  26
              Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . .  27
              Supplemental Information on Oil and Gas Producing Activities (Unaudited). . . .  41
  Item 9.   Changes In and Disagreements With Accountants on Accounting
             and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . .  44
Part  III
  Item 10.  Directors and Officers of Registrant. . . . . . . . . . . . . . . . . . . . . . .  45
  Item 11.  Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  48
  Item 12.  Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . .  49
  Item 13.  Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . .  50
Part  IV
  Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . .  53
Part  V
  Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  56
</TABLE>


     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 thousand cubic feet equivalent (Mcfe),
million  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 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,  2001,  the  Company had total revenues from
continuing  operations  of  $130  million and EBITDAX (earnings before interest,
income  taxes,  impairment and exploratory costs, depreciation and amortization)
from  continuing  operations  of  $33.2  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, California and Gulf Coast regions of the United States.  WENZ is
involved  in  oil  and  gas  exploration  and  development  in  New  Zealand.

     On  August  18,  2000,  the  Company  sold  its  wholly  owned  natural gas
distribution  company,  Mountaineer Gas Company and Subsidiaries ("Mountaineer")
to  Allegheny  Energy,  Inc ("Allegheny") for $325.7 million, which included the
assumption  of  approximately $100.1 million of debt, ($225.6 million net to the
Company).  The  Company  realized  an  after-tax  gain  of $84.4 million on this
transaction.  See Note 4 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.
This  document, 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 continuing businesses constitute two operating segments.  For
financial  information  on  these  segments,  see  Note  16  to the Consolidated
Financial  Statements.

GAS  AND  OIL  EXPLORATION  AND  PRODUCTION
-------------------------------------------

     The  Company's proved net gas and oil reserves are estimated as of June 30,
2001  at  206,456 Mmcf and 2,633 Mbbls, respectively.  For the fiscal year ended
June  30,  2001,  the  Company's  net  gas production was 9,371 Mmcf and net oil
production  was  116  Mbbls,  for  a  total  of  10,067  net  Mmcfe.


                                        4
<PAGE>
REGIONAL  OPERATIONS
--------------------

     APPALACHIAN BASIN.  The Company holds interests in 5,231gross (3,060.1 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,  2001  at 184,748 Mmcfe, of which approximately 96.8% was gas reserves
and  3.2%  was  oil  reserves.  For  the  fiscal  year  ended June 30, 2001, the
Company's gas production from its Appalachian Basin properties was approximately
8,800  net  Mmcf.  In  the  Appalachian  Basin,  the  Company  has  interests in
approximately  675,496  gross acres (520,463 net) of producing properties and an
additional  121,600  gross  acres (75,000 net) of undeveloped properties located
primarily  in  West  Virginia,  Pennsylvania,  Kentucky and Ohio.  During fiscal
2001,  the  Company drilled 47 successful gross wells (41.5 net) and recompleted
10  gross wells (9.3 net), which added 6,900 net Mmcfe in reserves.  On December
29, 2000 the Company purchased Penn Virginia Oil and Gas Corporation's interests
in  various  oil  and  gas  leases,  wells,  pipelines,  contracts,  partnership
interests,  rights  of  ways,  personal  property and tax credits.  The Company,
through  this acquisition purchased an interest in approximately 427 gross wells
and  added  approximately  42,000  net  Mmcfe  in  reserves.

     WESTERN  BASINS.  The  Company owns 640 gross developed acres (230 net) and
     ---------------
416,040  gross  undeveloped  acres  (229,120  net)  of  leasehold  interests  in
California,  Utah,  Colorado,  North Dakota, Montana and Wyoming.  This year the
Company drilled two wells in Wyoming (0.4 net) both of which failed to encounter
commercial  production.  Two  wells  were  reentered  in  Montana  (2.0 net) and
completed  as  gas wells with a combined initial production of 2.8 million cubic
feet  of  gas per day.  The budget for fiscal year 2002 includes two exploratory
wells  in  Montana  (1.0  net)  on  a  newly acquired 55 square mile 3-D seismic
survey.

     TEXAS  GULF  COAST.  The Company owns 1,060 gross developed acres (630 net)
     ------------------
and  49,260  gross  undeveloped  acres  (19,320  net) in Fort Bend County, Texas
covered  by  a  100  square  mile 3-D seismic survey.  Four wells (2.4 net) were
drilled  this  year  resulting in two discoveries (1.2 net), one suspended well,
which  will be deepened during the next fiscal year and one dry hole.  Effective
May  1,  2001,  the  Company  purchased interests in various oil and gas leases,
wells,  seismic  and  technical  data,  contracts,  right-of-ways  and  real and
personal  property  for  $18.1  million.  Total  fiscal year 2002 drilling plans
include four Wilcox development wells (2.4 net) and a minimum of three Frio-Cook
Mountain  wells  (0.9  net).

     INTERNATIONAL.  The  Company  operates  three  offshore  permits  and  five
     -------------
onshore  permits  on  the  North Island of New Zealand, totaling 3,114,580 gross
     -
acres,  (2,141,260  net).  Three exploratory wells (2.3 net) and three appraisal
wells  (2.5  net)  were drilled this year resulting in one gas discovery and one
gas appraisal well (2.0 net).  During the fiscal year 2002, the Company plans to
drill  two  exploratory  commitment  wells.  The  Company  plans to sell its 25%
interest  in  a  small  oil  well  in  Australia.

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.  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>
                                                     2001      2000      1999
                                                   --------  --------  --------
<S>                                                <C>       <C>       <C>
 Net proved:
   Gas (Mmcf)                                       206,456   157,490   148,587
   Oil (Mbbls)                                        2,633       983       959
   Total (Mmcfe)                                    222,254   163,388   154,341

 Net proved developed:
   Gas (Mmcf)                                       175,784   141,067   126,962
   Oil (Mbbls)                                          987       738       714
   Total (Mmcfe)                                    181,706   145,495   131,246

 Estimated future net cash flows
   before income taxes (in thousands)              $557,352  $427,414  $252,192
 Present Value of estimated future net cash
   flows after income taxes (in thousands) (1)     $172,281  $124,871  $ 84,883
<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,  2001:

<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  $    146,947   85.3%          976       178,892      184,748
 Rocky Mountains           8,531    5.0%        1,413         4,812       13,290
 Texas                    11,133    6.4%          244        13,116       14,580
 New Zealand               5,670    3.3%            -         9,636        9,636
                    ------------  ------  -----------  ------------  -----------
 Total              $    172,281  100.0%        2,633       206,456      222,254
                    ============  ======  ===========  ============  ===========
</TABLE>


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

     The  following  table sets forth certain information relating to productive
wells  at  June 30, 2001.  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    4  5,227  5,231  2.3  3,057.8  3,060.1
 Rocky Mountains     11            11  3.2               3.2
 Texas                -      2      2    -      1.2      1.2
                    ---  -----  -----  ---  -------  -------
 Total               15  5,229  5,244  5.5  3,059.0  3,064.5
                    ===  =====  =====  ===  =======  =======
</TABLE>


ACREAGE
-------

     The  following table sets forth the developed and undeveloped gross and net
acreage  held  at  June  30,  2001  (in thousands).

<TABLE>
<CAPTION>
                    Developed Acreage  Undeveloped Acreage
                   ------------------  ------------------
                     Gross      Net      Gross      Net
                    --------  -------  --------  -------
<S>                 <C>       <C>      <C>       <C>
 Appalachian Basin     675.5    520.5     121.6     75.0
 Western Basins          0.6      0.2     416.0    229.1
 Gulf Coast              1.1      0.6      49.3     19.3
 New Zealand               -        -   3,114.6  2,141.3
                    --------  -------  --------  -------
 Total                 677.2    521.3   3,701.5  2,464.7
                    ========  =======  ========  =======
</TABLE>


PRODUCTION
----------

     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>
                                                        2001     2000    1999
                                                       -------  ------  ------
<S>                                                    <C>      <C>     <C>
 Production Data:
   Oil (Mbbls)                                             116     113     133
   Natural gas (Mmcf)                                    9,371   7,399   7,184
   Natural gas equivalent (Mmcfe)                       10,067   8,079   7,979
 Average Sales Price (before the effect of hedging):
   Oil per Bbl                                         $ 25.94  $21.64  $10.95
   Natural gas per Mcf                                 $  5.43  $ 2.81  $ 2.20
</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>
                         2001          2000          1999
                      ------------  -----------  -----------
                      Gross   Net   Gross  Net   Gross  Net
                      ------  ----  -----  ----  -----  ----
<S>                   <C>     <C>   <C>    <C>   <C>    <C>
 Development:
      Productive
         Appalachian    47.0  41.5   15.0  12.6   19.0  15.0
         Other             -     -      -     -    3.0   0.7
                      ------  ----  -----  ----  -----  ----
      Total             47.0  41.5   15.0  12.6   22.0  15.7
                      ======  ====  =====  ====  =====  ====

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

     Nonproductive
         Appalachian     2.0   0.3      -     -    3.0   1.7
         Other           8.0   3.8   15.0   8.3    7.0   3.2
                      ------  ----  -----  ----  -----  ----
     Total              10.0   4.1   15.0   8.3   10.0   4.9
                      ======  ====  =====  ====  =====  ====
</TABLE>


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

     The  Company  encounters  substantial  competition in acquiring properties,
marketing  oil  and gas, securing drilling 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.  These laws and regulations require the acquisition of


                                        8
<PAGE>
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 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 demand for long term contracts
has  decreased substantially and no new long term contracts were entered into in
fiscal  year  2001.  Volumes  that  became  available  from  expired  long  term
contracts  were  sold  under  intermediate  and  short  term  contracts.

     The  Company owns and operates approximately 2,250 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,  2001,  the Eastern Marketing aggregated and sold an average of 44.7 Mmcf of
gas  per  day, of which 38.6 Mmcf per day represented sales of gas produced from
wells  operated  by  the Company.  This represents a decrease compared to fiscal
year  2000, during which the Eastern Marketing aggregated and sold an average of
63.1  Mmcf of gas per day.  The substantial decrease is due to the expiration of
third  party contracts that have not been renewed due to the change in marketing
focus.  Virtually  all of the third party agreements have expired as of June 30,
2001.

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

     The  Eastern  Marketing  satisfied  its  obligations  under  all  gas sales
contracts  (16.3 Bcf in fiscal year 2001) 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 2001),
and  from  natural gas aggregated by the Company pursuant to its aggregation and
marketing  activities  from  third  parties  (2.2  Bcf  in  fiscal  2001).

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

     In  March  1993,  the Company 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


                                        9
<PAGE>
per Mcf in calendar year 2000.  Beginning 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 14 to
the  Consolidated  Financial  Statements  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 Federal Energy Regulatory Commission.  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,  2001,  the  Company  had  approximately  215 full-time and 14
part-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
                         ------------------------------

     On  June 8, 2001, the Company filed a lawsuit against Oracle Corporation in
the  United  States  District  Court For the Southern District of West Virginia.
The Company had entered into a Software License and Service Agreement as well as
a  Time and Materials Contract with Oracle in early 1998.  The Company has spent
over $5.4 million to date trying to install and implement the software purchased
from  Oracle  without  any  success.  The Company believes that the software can
never  be  implemented as represented and therefore filed the complaint alleging
(i)  Breach  of  Contract  (ii)  Breach  of  Warranty  and  (iii)  Failure  of
Consideration.  The  Company  seeks  judgment  against Oracle in the approximate
amount of $5.4 million together with prejudgment interest and costs.  Oracle has
answered  the  Complaint  and  has  substantially  denied  all  of the Company's
allegations.  Oracle  has also filed a Counterclaim against the Company alleging
that it is owed approximately $1.2 million for prior services allegedly provided
to  the  Company.  The  case  is  in its early stages and the Company intends to
aggressively  prosecute  its  case  against Oracle as well as defend against the
Counterclaims  of  Oracle.

     On  February  21,  2001,  the Company, along with various other Appalachian
Basin  producers  filed  suit against MarkWest Hydrocarbon, Inc. ("MarkWest") in
the  Circuit  Court  of  Wayne  County,  West  Virginia.  The  Complaint seeks a
preliminary  injunction,  permanent injunction, declaratory judgment and damages
against  MarkWest  by  virtue  of  MarkWest  having  breached  the  terms of its
individual  processing agreements with the producers by having failed to deliver
to  the  producers  certain reimbursement volumes of gas on a timely basis.  The
claims  of  the  Appalachian  producers  are  similar to the claims of two other
lawsuits filed against MarkWest by (i) Columbia Gas Transmission Corporation and


                                       10
<PAGE>
Columbia  Natural  Resources  and  (ii)  Equitable Production Co., et al.  These
lawsuits are also pending in Wayne County.  These suits seek to require MarkWest
to  abide  by  the  terms  and  conditions of various agreements.  To the extent
MarkWest  fails  to  abide  by  such agreements, the Company believes it will be
damaged  and  will  be  entitled  to  damages.  MarkWest has answered and denied
substantially  all  of  the  allegations  of  the  producers  and  has  filed  a
Counterclaim  against  the producers alleging various causes of action including
Intentional Interference with Contract and Civil Conspiracy.  On August 13, 2001
the  Court  entered  an  Opinion  Order granting the Company's and the producers
motion for a Temporary Mandatory Injunction and required MarkWest to continue to
provide  the  reimbursement  volumes of gas on a timely basis.  The Court in its
Opinion Order, stated in part "The Plaintiffs (including the Company) are likely
to  prevail on the merits of their claim for a breach of contract".  The case is
still  in  its  early  stages  and  the  Company  and  the  producers  intend to
aggressively  prosecute  its case against MarkWest as well as defend against the
Counterclaims  of  MarkWest.

     The  Company  is involved in various other legal actions and claims arising
in  the  ordinary course of business.  While the outcome of these other 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
     ---------------------------------------------------------------

     None.


                                     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,  2001,  the  Company had 44 holders of record of its common stock.

     The  Company declared dividends in fiscal years 2001, 2000 and 1999 of $3.9
million  $0,  and  $0.6  million,  respectively.


                                       11
<PAGE>
                      ITEM 6.     SELECTED FINANCIAL DATA
                      -----------------------------------

<TABLE>
<CAPTION>

(Dollars in thousands, except per share items)

                                                          Year Ended June 30,
                                         -----------------------------------------------------
                                           2001       2000       1999       1998       1997
                                         ---------  ---------  ---------  ---------  ---------
<S>                                      <C>        <C>        <C>        <C>        <C>
                                                                                (1)        (2)
 Operating revenue                       $129,951   $101,919   $113,500   $193,459   $189,070
 Loss from continuing operations          (10,555)   (26,508)   (27,099)    (3,773)    (4,086)
 Loss from continuing operations
    Per common share, basic and diluted    (15.88)    (40.11)    (40.27)     (5.67)     (5.94)
 Total assets                             373,823    265,691    286,077    290,541    302,446
 Long term debt                           198,902    212,575    219,886    201,507    200,089
 Dividends declared per common share     $   5.80   $      -   $   0.95   $   1.70   $   1.50
<FN>
   (1) Includes a $30.0 million contract settlement.
   (2) Includes  a  $7.8  million  gain  on the sale of a limited partnership
       interest.
</TABLE>

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


SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
--------------------------------------------------------------------------------

     This  discussion  and  analysis  of  financial  condition  and  results  of
operations,  and  other  sections  of  this  Form  10-Q, contain forward-looking
statements  that  are  based  on  management's  beliefs,  assumptions,  current
expectations,  estimates,  intentions  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 under the
Private  Securities  Litigation  Reform  Act of 1995.  The Company cautions that
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, foreign currency exchange rates,
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.

     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.


                                       12
<PAGE>
DISPOSAL  OF  UTILITY  OPERATIONS
---------------------------------

On  August  18,  2000,  the  Company  sold  all of the stock of its wholly owned
natural  gas  distribution  company,  Mountaineer to Allegheny for approximately
$325.7  million,  which  included  the  assumption of $100.1 million of debt and
payment of approximately $225.6 million to the Company.  The Company realized an
after-tax  gain  of  $84.4  million  on  this  transaction.

     The financial statements exclude the operating results of this segment from
continuing  operations  and  for  accounting  purposes, classify such results as
discontinued  operations  (see  Note  4).  The  following  discussion,  unless
otherwise  noted,  relates  only  to  the  Company's  continuing  operations.

SIGNIFICANT  ACQUISITIONS
-------------------------

     During  the  year  ended  June  30,  2001,  the  Company made the following
     significant  acquisitions:

     -    Purchased Penn Virginia Oil and Gas Corporation's interests in various
          oil  and  gas  leases,  wells,  pipelines,  contracts,  partnership
          interests,  right-of-ways, personal property and tax credits for $57.2
          million.
     -    Purchased  a  66.6%  interest  in Deep Rig LLP for $2.8 million, which
          will  operate  an  onshore  deep well drilling rig for oil and natural
          gas.
     -    Acquired  interests  in  28  wells  in  Pennsylvania for $1.7 million.
     -    Purchased  interests in various oil and gas leases, wells, seismic and
          technical  data,  contracts,  right-of-ways  and  real  and  personal
          property  in  Texas  for  $18.1  million.


COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2001 AND 2000
--------------------------------------------------------------------------------

     The Company recorded a net loss from continuing operations of $10.6 million
for the year ended June 30, 2001 compared to a net loss of $26.5 million for the
same  period in 2000.  The improvement of $15.9 million is attributed to the net
of  a  $28.0  million  increase in revenue, a $4.2 million increase in operating
expenses,  a  $10.7 million increase in impairment and exploratory costs, a $2.2
million  decrease  to  interest  expense,  a  $5.0  million  increase  in  other
non-operating  income  and  a  $4.4  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 $33.0 million for the
current  year  compared to $7.8 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 $27.6 million versus $10.7 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) had income of $3.9 million for the current period versus a loss
of  $2.9  million  for  the  prior  period.

     REVENUES.  Total  revenues  increased  $28.0  million  or 27.5% between the
     --------
years.  The  net  increase  was  due  to  a  12.3% increase in gas marketing and
pipeline  sales,  a  74.1%  increase in oil and gas sales and a 100% increase in
other  operating  revenue.  Well  operations  and  service  revenues  remained
relatively  constant.


                                       13
<PAGE>
     Revenues  from gas marketing and pipeline sales increased $8.9 million from
$72.1  million  during  the  period ended June 30, 2000, to $81.0 million in the
period  ended  June  30,  2001.  Gas  marketing  revenue  increased $3.8 million
primarily  due  to  an  85.5% increase in the average sales price per Mmbtu from
$2.92  for  the  year  ended  June 30, 2000 to $5.42 for the year ended June 30,
2001.  This  increase  was  mitigated by a 41.6% decline in marketed gas volumes
from 20.7 million Mmbtu to 12.1 million Mmbtu for the same period.  The decrease
in  volumes  is primarily related to the Company's decision to exit the end-user
market.  Pipeline  revenue  increased  $5.1  million  primarily  due  to a 68.6%
increase in the average sales price per Mmbtu from $2.94 for the year ended June
30,  2000  to  $4.97  for  the  year  ended  June  30,  2001.  This increase was
diminished  by  a  9.9%  decline  in  gas  volumes from 3.4 million Mmbtu to 3.1
million  Mmbtu  for  the  same  period.

     Revenues  from oil and gas sales increased $17.7 million from $23.9 million
for  the  year  ended June 30, 2000 to $41.6 million for the year ended June 30,
2001 due to an increase in both price and net production.  The average Mcf price
received  for  the  year ended June 30, 2000 was $2.81 compared to $5.43 for the
year  ended  June 30, 2001.  The Company's net Mcf production for the year ended
June  30,  2000 compared to the year ended June 30, 2001 increased 1,423.6 Mmcf,
19.2%,  which  is  attributable  to  drilling and acquisitions.  The average Bbl
price  received  for  the year ended June 30, 2000 was $21.64 compared to $25.94
for  the  year  ended  June 30, 2001   This price increase was offset by a 5,092
Bbl,  4.5%,  drop  in  production  for  the  year.  The price and net production
increases  to  revenue  were  offset  by  recognized  losses  on related hedging
transactions,  which  totaled  $9.6  million  for  the  year ended June 30, 2001
compared  to  $0.8  million for the year ended June 30, 2000.  The average price
per  Mcfe,  after hedging, was $4.39 and $2.95 for the years ended June 30, 2001
and  2000.

     Revenues  from  other  operations increased from zero during the year ended
June 30, 2000 to $1.5 million during the year ended June 30, 2001.  The increase
in  revenue  is  due  to  a management contract with Allegheny, which terminated
March  31,  2001,  whereby  the  Company  provided  Mountaineer  with management
services,  subsequent  to  the  sale.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses  increased $4.2
     --------------------
million  or  3.9% between the years primarily as a result of a 10.1% increase in
gas  marketing  and  pipeline  costs  and  a 127.1% increase to taxes other than
income.  Field and lease operating expenses, general and administrative expenses
and  depreciation,  depletion  and  amortization  expenses  remained  relatively
constant  between  the  periods.

     Gas  marketing  and  pipeline  costs increased $7.1 million.  Gas marketing
cost  increased  $0.3  million  primarily due to a 75.6% increase in the average
price  paid  per  Mmbtu from $2.94 for the year ended June 30, 2000 to $5.16 for
the  year  ended June 30, 2001.  This increase was diminished by a 41.8% decline
in  purchased  gas volumes from 20.6 million Mmbtu to 12.0 million Mmbtu for the
same  period.  Pipeline  cost  increased  $6.8 million primarily due to a 109.6%
increase  in  the  average price paid for gas purchased from $2.23 per Mmbtu for
the  year  ended  June 30, 2000 to $4.67 for the year ended June 30, 2001.  This
increase was offset by a 10.9% decline in purchased gas volumes from 3.6 million
Mmbtu  to  3.2  million Mmbtu for the same period.  During fiscal year 2000, the
Company recognized a $4.9 million gas purchase commitment expense related to the
Royalty  Trust  with  no  similar costs recorded during the current fiscal year.
See  Note  14.

     Taxes  other  than  income increased $1.9 million as a result of higher oil
and  gas  prices  and volumes.  Production taxes are based on the wellhead price
received  and  are  not  affected  by  hedging  activities.

     EXPLORATION  AND  IMPAIRMENT.  Exploration  and  impairment costs increased
     ----------------------------
$10.7  million  when  comparing  the periods.  The primary costs related to this
increase  are the impairment of a computer conversion project, $5.7 million, and


                                       14
<PAGE>
impairment  of  the  investment in a fiber optic company due to bankruptcy, $1.6
million.  The  balance  of  the  increase  is  for other oil and gas exploratory
costs,  which  includes impairment of drilling costs related to dry holes, delay
rentals,  lease  expirations,  geological  and  geophysical  costs  and seismic.

     INTEREST  EXPENSE.  Interest  expense  decreased $2.2 million or 9.9%, when
     -----------------
comparing  the  periods.  This is primarily due to having 6.8% less debt at June
30,  2001.

     OTHER  NON-OPERATING  INCOME.  Other  non-operating  income  increased $5.1
     ----------------------------
million  when  comparing the periods ended June 30, 2001 to June 30, 2000.  This
is  primarily  due  to  interest  income  earned  on  cash and cash equivalents.

     INCOME  TAX.  The  provision for income taxes increased $4.4 million due to
     -----------
the  $20.3  million  increase  to  pre-tax  earnings  from continuing operation.


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.


                                       15
<PAGE>
     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 million 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.

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  14).  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 the
Company,  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


                                       16
<PAGE>
(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.


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

     The Company's financial condition has improved significantly since June 30,
2000.  Stockholders'  equity  has increased from a deficit of  $(4.1) million at
June 30, 2000 to $64.8 million at June 30, 2001.  The ratio of current assets to
current  liabilities,  excluding  "net  utility  assets  held for sale" of $56.8
million at June 30, 2000 increased from 0.75:1 at June 30, 2000 to 1.9:1 at June
30,  2001.  Cash  and  cash  equivalents increased from $3.3 million at June 30,
2000  to  $80.3 million at June 30, 2001.  In addition, earnings from continuing
operations  before  interest  charges,  taxes,  depreciation,  depletion  and
amortization  and  impairment  and  exploratory costs ("EBITDAX") increased from
$4.1 million in the twelve month period ended June 30, 2000, to $33.2 million in
the  twelve  month  period  ended  June  30,  2001.

     At June 30, 2001, the Company's principal sources of liquidity consisted of
$80.3  million  of  cash, and $2 million available under an unsecured short-term
credit  facility  currently  in  place.  At  June  30,  2001, the Company had no
letters  of  credit  issued  against  the  short-term  line  of credit facility.

     On  August  18,  2000,  the  Company  consummated  the sale of Mountaineer.
Pursuant  to  the  terms  of  its  Senior  Subordinated Notes (the "Notes"), the
Company  has  the  option,  within 360 days of receipt of the "Net Proceeds" (as
defined  in  the  Indenture dated May 23, 1997 between the Company as Issuer and
The  Bank  of New York as Trustee, hereinafter the "Indenture") 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  of  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 has not applied 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 that were not applied to one
of  the  above  options, such Net Proceeds are then deemed to constitute "Excess
Proceeds".  To  the  extent  the Excess Proceeds exceed $10 million, 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 that may be
purchased  out of the Excess Proceeds 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.

     Final  settlement,  with  respect  to  the  Mountaineer  sale,  occurred on
November  21,  2000.  Net  Proceeds from the sale of Mountaineer are as follows.
The  aggregate  cash proceeds of the sale were $225.6 million.  The direct costs
associated  with  the  sale included investment banking fees and expenses in the
amount  of $0.6 million, accounting fees in the amount of $0.1 million and legal


                                       17
<PAGE>
fees  in the amount of $0.5 million.  The "taxes paid or payable as a result [of
the sale] (after taking into account any available tax credits or deductions and
any  tax  sharing  arrangements)"  are  $83.8 million.  Although not yet finally
determined, the amount of taxes due from the Company to Federal and state taxing
authorities on a consolidated basis for fiscal year 2001 will be less than $83.8
million  because of the availability of net operating loss carry forwards of the
Company  from  the prior year, alternative minimum tax and Section 29 tax credit
carry  forwards  from  the  prior year, credit for the prior year's overpayment,
current  year  Section  29  credits,  and  current  year operating losses of the
Company,  none  of  which  was  a  result  of  the sale of stock of Mountaineer.
Certain bondholders and the Trustee have made inquiries to the Company as to the
interpretation  of the language "taxes paid or payable as a result [of the sale]
(after  taking  into account any available tax credits or deductions and any tax
sharing  arrangements)  ".  To  date, the inquiries have been essentially in the
nature of requests for information.  The Company has taken the position that the
correct  interpretation  of  such  language  is  that the amount of tax "paid or
payable"  is  $83.8  million  notwithstanding  the  unrelated losses and credits
mentioned  above.

Accordingly,  the  Net  Proceeds  of the sale, as defined in the Indenture, were
$140.6  million.  The Company has complied with the provisions of Section 4.9 of
the  Indenture in its application of the Net Proceeds. The Company repaid Senior
Debt  to  General Electric Credit Corporation in the amount of $19.75 million on
August  18,  2000.  The  Company  also  repaid the principal due under a line of
credit  to  a  bank in the amount of $2.0 million in September 2000. The Company
also  made  purchases  of  long-term  assets aggregating $80.4 million and has a
currently  outstanding  offer  to purchase long-term assets in the amount of $80
million.  The  Company  also  repurchased  Notes  pursuant  to a Tender Offer on
December  13,  2000  in  the amount of $1.746 million. Finally, the Company made
capital  expenditures  of  approximately  $32.5  million in fiscal year 2001 and
approximately  $4.3  million  in  July  2001.  The  capital  expenditures  made
subsequent  to  July  31,  2001  have  not  yet  been  determined.

     Management  anticipates  that EBITDAX for fiscal year 2002 will approximate
$40  million  as  compared  to $33.2 million for fiscal year 2001; however, such
results will not be sufficient to fully fund fiscal year 2002 projected interest
charges  of  $19.6  million  and  fund  the  Company's  fiscal year 2002 capital
expenditures  program  of $41.0 million.  However, management believes that cash
generated from oil and gas operations, the sale of certain non-strategic assets,
together  with  the  liquidity  provided by existing cash balances and permitted
borrowings  will  be sufficient to satisfy commitments for capital expenditures,
debt  service obligations, working capital needs and other cash requirements for
the  next  year.

     The  Company  believes that its existing capital resources and its expected
fiscal  year 2002 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,  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 remain in
compliance  with  the  requirements  of  its  Notes.


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

     SFAS  No.  143  "Accounting  for Asset Retirement Obligations" provides the
accounting  requirements  for  retirement  obligations  associated with tangible
long-lived  assets.  SFAS  No. 143 is effective for fiscal years beginning after
June  15,  2002,  and  early  adoption  is  permitted.  The Company is currently


                                       18
<PAGE>
assessing,  but  has  not  yet  determined,  the  impact  of SFAS No. 143 on its
consolidated  results  of  operations,  cash  flows  or  financial  position.


             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.  All of the Company's debt has fixed interest
rates.  The Company has not attempted to hedge the interest rate risk associated
with  its  debt.

COMMODITY  RISK
----------------

     The  Company's  operations  consist  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  hedges  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.  Unrecognized gains and
losses  are  included as a component of other comprehensive income.  The Company
does not hold or issue derivative instruments for trading purposes.  The Company
has elected to enter into swap transactions, covering approximately 46.4% of its
natural  gas  production  through  April 2002.  If gas prices changed by 10%, it
would  have  an  impact  of  approximately  $1.3  million.

FOREIGN  CURRENCY  EXCHANGE  RISK
----------------------------------

     Some  of  the  Company's  transactions  are  denominated  in New Zealand or
Australian  dollars.  For  foreign  operations  with  the  local currency as the
functional  currency,  assets  and  liabilities are translated at the period end
exchange  rates, and statements of income are translated at the average exchange
rates  during  the  period.  Gains  and  losses  resulting from foreign currency
translation  are  included  as  a  component  of  other  comprehensive  income.

                                   * * * * *


                                       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, 2001 and 2000, and the
related  consolidated  statements of operations, stockholders' equity (deficit),
cash  flows,  and comprehensive income for each of the three years in the period
ended  June  30, 2001.  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, 2001 and 2000, and the results of their operations
and  their  cash  flows for each of the three years in the period ended June 30,
2001  in  conformity with accounting principles generally accepted in the United
States  of  America.



DELOITTE  &  TOUCHE  LLP
Denver,  Colorado
September  25,  2001


                                       20
<PAGE>
<TABLE>
<CAPTION>

ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------

ASSETS                                            2001       2000
                                                ---------  ---------
<S>                                             <C>        <C>
 CURRENT ASSETS:
   Cash and cash equivalents                    $ 80,336   $  3,310
                                                ---------  ---------
   Accounts receivable:
     Gas marketing and pipeline                    8,056      9,249
     Oil and gas sales                               816      1,081
     Other                                         8,264      4,600
                                                ---------  ---------
                                                  17,136     14,930
     Less allowance for doubtful accounts           (457)      (463)
                                                ---------  ---------
                                                  16,679     14,467
   Gas in storage, at average cost                 1,069        765
   Income taxes receivable                                    2,502
   Deferred income tax asset                       7,467
   Derivatives                                     4,391
   Net utility assets held for sale                          56,795
   Prepaid and other current assets                1,978      1,921
                                                ---------  ---------
         Total current assets                    111,920     79,760

 NET PROPERTY, PLANT AND EQUIPMENT (Note 2)      248,659    160,162
                                                ---------  ---------

 OTHER ASSETS:
   Deferred financing costs, less accumulated
     amortization of $2,987 and $2,446             4,353      5,210
   Notes receivable - related parties              1,867      1,519
   Deferred income tax asset                                  4,405
   Other                                           7,024     14,635
                                                ---------  ---------
         Total other assets                       13,244     25,769
                                                ---------  ---------

 TOTAL                                          $373,823   $265,691
                                                =========  =========
</TABLE>

See notes to consolidated financial statements.          (Continued)


                                       21
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------

LIABILITIES AND STOCKHOLDERSEQUITY (DEFICIT)                  2001       2000
                                                            ---------  ---------
<S>                                                         <C>        <C>
CURRENT LIABILITIES:
  Accounts payable and accrued expenses                     $ 21,468   $ 14,877
  Current portion of long-term debt                              151      1,086
  Short-term debt                                                         2,000
  Funds held for future distribution                           7,957      6,280
  Income taxes payable                                           470
  Accrued taxes, other than income                             7,860      5,079
  Deferred income tax liability                                             329
  Other current liabilities                                   20,973      1,131
                                                            ---------  ---------
        Total current liabilities                             58,879     30,782
LONG-TERM OBLIGATIONS:
  Long-term debt                                             198,902    212,575
  Gas delivery obligation and deferred trust revenue          11,389     15,443
  Deferred income tax liability                               29,888
  Other long-term obligations                                  9,939     11,014
                                                            ---------  ---------
        Total liabilities                                    308,997    269,814
                                                            ---------  ---------

COMMITMENTS AND CONTINGENCIES (Note 14)

STOCKHOLDERSEQUITY (DEFICIT):
  Common stock, par value $1.00; 2,000 shares authorized;
    730 and 718 shares issued                                    730        718
  Class A non-voting common stock, no par value; 100
     shares authorized; 36 and 26 shares issued                3,732      2,940
  Additional paid-in capital                                   5,503      4,615
  Retained earnings (deficit)                                 63,653     (4,833)
  Treasury stock and notes receivable arising from
     issuance of common stock                                 (9,293)    (7,429)
  Accumulated other comprehensive income (loss)                  501       (134)
                                                            ---------  ---------
        Total stockholdersequity (deficit)                    64,826     (4,123)
                                                            ---------  ---------
TOTAL                                                       $373,823   $265,691
                                                            =========  =========
</TABLE>

See notes to consolidated financial statements.


                                       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)
-----------------------------------------------------------------------------------------------------------

                                                                              2001       2000       1999
                                                                            ---------  ---------  ---------
<S>                                                                         <C>        <C>        <C>
REVENUES:
  Gas marketing and pipeline sales                                          $ 81,042   $ 72,156   $ 88,474
  Oil and gas sales                                                           41,555     23,869     18,295
  Well operations and service revenues                                         5,899      5,894      6,540
  Other                                                                        1,455                   191
                                                                            ---------  ---------  ---------
                                                                             129,951    101,919    113,500
                                                                            ---------  ---------  ---------
COSTS AND EXPENSES:
  Gas marketing and pipeline cost of sales                                    77,167     70,101     84,417
  Purchase commitment costs                                                               4,945
  Field operating expenses                                                     8,910      8,143      8,198
  General and administrative                                                  12,804     13,647     10,299
  Taxes, other than income                                                     3,389      1,492      1,247
  Depletion and depreciation of oil and gas properties                         9,290      8,847      7,915
  Depreciation of pipelines, other property and equipment                      2,763      2,892      3,252
  Exploration and impairment                                                  19,014      8,347     19,261
                                                                            ---------  ---------  ---------
                                                                             133,337    118,414    134,589
                                                                            ---------  ---------  ---------
        Loss from operations                                                  (3,386)   (16,495)   (21,089)
                                                                            ---------  ---------  ---------
OTHER (INCOME) AND EXPENSE:
  Interest expense                                                            20,094     22,302     20,122
  Gain on sale of assets                                                        (211)      (101)       (91)
  Interest income and other                                                   (5,290)      (377)      (895)
                                                                            ---------  ---------  ---------
                                                                              14,593     21,824     19,136
                                                                            ---------  ---------  ---------
Loss from continuing operations before income taxes and minority interest    (17,979)   (38,319)   (40,225)
Benefit for income taxes                                                      (7,424)   (11,811)   (13,133)
                                                                            ---------  ---------  ---------
Loss from continuing operations before minority interest                     (10,555)   (26,508)   (27,092)
Minority interest                                                                  -          -          7
                                                                            ---------  ---------  ---------
Loss from continuing operations                                              (10,555)   (26,508)   (27,099)
  Disposal of utility operations:
    Income (loss) from utility operations, net of tax                         (1,847)     8,077     12,212
    Gain on sale of utility, net of tax                                       84,402          -          -
                                                                            ---------  ---------  ---------
    Net income from disposal of utility operations                            82,555      8,077     12,212
                                                                            ---------  ---------  ---------
Loss from continuing operations before extraordinary items                    72,000    (18,431)   (14,887)
  Extraordinary gain on extinguishment of debt, net of tax                       356          -          -
                                                                            ---------  ---------  ---------

NET INCOME (LOSS)                                                           $ 72,356   $(18,431)  $(14,887)
                                                                            =========  =========  =========

Earnings (loss) per common share, basic and diluted
   Loss from continuing operations                                          $ (15.88)  $ (40.11)  $ (40.27)
   Discontiued operations                                                     124.20      12.22      18.15
   Extraordinary gain on extinguishment of debt                                 0.54          -          -
                                                                            ---------  ---------  ---------
   Earnings (loss) per common share                                         $ 108.86   $ (27.89)  $ (22.12)
                                                                            =========  =========  =========
</TABLE>

See notes to consolidated financial statements.


                                       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)
------------------------------------------------------------------------------------------------------------------
                                                                     Class A    Additional    Retained
                                                            Common    Common     Paid-In      Earnings    Treasury
                                                            Stock     Stock      Capital     (Deficit)     Stock
                                                           --------  --------  ------------  ----------  ----------
<S>                                                        <C>       <C>       <C>           <C>         <C>
Balance, June 30, 1998                                     $   720   $      -  $     4,510   $  29,132   $  (3,698)

  Components of comprehensive loss:
    Foreign currency translation adjustment
    Net loss                                                                                   (14,887)

  Comprehensive loss
  Dividends ($0.95 per share)                                                                     (647)
  Common stock issued for services                               1                     146
  Conversion of minority interest                                       2,040
  Employee stock purchases                                                900
  Purchase of treasury stock - common                                                                       (1,761)
  Purchase of treasury stock - Class A                                                                        (437)
  Reduction of notes receivable

Balance, June 30, 1999                                         721      2,940        4,656      13,598      (5,896)

  Components of comprehensive loss:
    Foreign currency translation adjustment
    Net loss                                                                                   (18,431)

  Comprehensive loss
  Common stock issued for services                               2                     146
  Redemption of common stock and related note receivable        (5)                   (187)
  Purchase of treasury stock - common                                                                         (223)
  Purchase of treasury stock - Class A                                                                        (165)
  Reduction of notes receivable

Balance June, 30, 2000                                         718      2,940        4,615      (4,833)     (6,284)

  Components of comprehensive income:
    Foreign currency translation adjustment
    Marketable securities
    Oil and gas derivatives
    Net income                                                                                  72,356

  Comprehensive income
  Dividends ($5.80 per share)                                                                   (3,870)
  Common stock issued for services                              12                     888
  Class A stock issued for services                                       792
  Purchase of treasury stock - common                                                                       (1,455)
  Purchase of treasury stock - Class A                                                                        (465)
  Reduction of notes receivable
                                                           --------  --------  ------------  ----------  ----------
Balance, June 30, 2001                                     $   730   $  3,732  $     5,503   $  63,653   $  (8,204)
                                                           ========  ========  ============  ==========  ==========


                                                            Notes Received/    Accum. Other
                                                              Issuance of      Comprehensive    Stockholders
                                                                 Stock         Income (Loss)       Equity
                                                           -----------------  ---------------  --------------
<S>                                                        <C>                <C>              <C>
Balance, June 30, 1998                                     $           (384)  $         (310)  $      29,970
                                                                                               --------------
  Components of comprehensive loss:
    Foreign currency translation adjustment                                              133             133
    Net loss                                                                                         (14,887)
                                                                                               --------------
  Comprehensive loss                                                                                 (14,754)
  Dividends ($0.95 per share)                                                                           (647)
  Common stock issued for services                                                                       147
  Conversion of minority interest                                      (150)                           1,890
  Employee stock purchases                                             (856)                              44
  Purchase of treasury stock - common                                                                 (1,761)
  Purchase of treasury stock - Class A                                                                  (437)
  Reduction of notes receivable                                          25                               25
                                                           -----------------  ---------------  --------------
Balance, June 30, 1999                                               (1,365)            (177)         14,477
                                                                                               --------------
  Components of comprehensive loss:
    Foreign currency translation adjustment                                               43              43
    Net loss                                                                                         (18,431)
                                                                                               --------------
  Comprehensive loss                                                                                 (18,388)
  Common stock issued for services                                                                       148
  Redemption of common stock and related note receivable                192                                -
  Purchase of treasury stock - common                                                                   (223)
  Purchase of treasury stock - Class A                                                                  (165)
  Reduction of notes receivable                                          28                               28
                                                           -----------------  ---------------  --------------
Balance June, 30, 2000                                               (1,145)            (134)         (4,123)
                                                                                               --------------
  Components of comprehensive income:
    Foreign currency translation adjustment                                           (1,980)         (1,980)
    Marketable securities                                                                136             136
    Oil and gas derivatives                                                            2,479           2,479
    Net income                                                                                        72,356
                                                                                               --------------
  Comprehensive income                                                                                72,991
  Dividends ($5.80 per share)                                                                         (3,870)
  Common stock issued for services                                                                       900
  Class A stock issued for services                                                                      792
  Purchase of treasury stock - common                                                                 (1,455)
  Purchase of treasury stock - Class A                                                                  (465)
  Reduction of notes receivable                                          56                               56
                                                           -----------------  ---------------  --------------
Balance, June 30, 2001                                     $         (1,089)  $          501   $      64,826
                                                           =================  ===============  ==============
</TABLE>

See notes to consolidated financial statements.


                                       24
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------------------------------------------
                                                                                       2001       2000       1999
                                                                                    ----------  ---------  ---------
<S>                                                                                 <C>         <C>        <C>
 CASH FLOWS FROM OPERATING ACTIVITIES
 Net loss from continuing operations                                                $ (10,555)  $(26,508)  $(27,099)
  Adjustments to reconcile net loss to net cash provided (used) by
    operating activities:
       Depletion, depreciation and amortization                                        12,911     12,538     11,966
       Gain on sale of assets                                                            (211)      (101)       (91)
       Deferred income taxes                                                           28,359    (11,099)   (12,491)
       Exploration and impairment                                                      18,591      5,979     16,778
       Other, net                                                                      (4,186)     4,413      3,433
                                                                                    ----------  ---------  ---------
                                                                                       44,909    (14,778)    (7,504)
 Changes in assets and liabilities:
    Accounts receivable                                                                (2,936)       420        (38)
    Gas in storage                                                                       (304)      (408)        92
    Income taxes receivable                                                           (33,821)     1,079     (4,344)
    Prepaid and other assets                                                              (32)       163      1,625
    Accounts payable                                                                    6,172        (42)    (6,348)
    Funds held for future distributions                                                 1,678        902       (337)
    Other                                                                              14,631      7,670     (7,252)
                                                                                    ----------  ---------  ---------
       Net cash used by operating activities from continuing operations                30,297     (4,994)   (24,106)
       Net cash provided (used) by operating activities from disposed operations      (48,335)     7,286     30,009
                                                                                    ----------  ---------  ---------
       Net cash provided (used) by operating activities                               (18,038)     2,292      5,903
                                                                                    ----------  ---------  ---------
 CASH FLOWS FROM INVESTING ACTIVITIES
    Expenditures for property, plant and equipment                                   (112,863)   (19,299)   (25,245)
    Proceeds from sale of assets                                                        1,517        428      3,444
    Notes receivable and other                                                         (4,192)      (300)        70
                                                                                    ----------  ---------  ---------
       Net cash used by investing activities from continuing operations              (115,538)   (19,171)   (21,731)
       Net cash provided (used) by investing activities from disposed operations      224,765    (23,842)   (11,414)
                                                                                    ----------  ---------  ---------
       Net cash provided (used) by investing activities                               109,227    (43,013)   (33,145)
                                                                                    ----------  ---------  ---------
 CASH FLOWS FROM FINANCING ACTIVITIES
    Proceeds from long-term debt                                                        7,825     16,250     27,500
    Principal payment on long-term debt                                               (21,850)   (29,094)    (3,084)
    Proceeds (payment) on short-term borrowing                                         (2,000)     2,000
    Purchase of treasury stock and other financing activities                          (1,072)      (214)    (2,154)
    Prepayment of future gas delivery                                                             10,000          -
    Dividends paid                                                                     (3,605)         -       (967)
                                                                                    ----------  ---------  ---------
       Net cash provided (used) by financing activities from continuing operations    (20,702)    (1,058)    21,295
       Net cash provided (used) by financing activities from disposed operations        6,539     32,926     (2,375)
                                                                                    ----------  ---------  ---------
       Net cash provided (used) by financing activities                               (14,163)    31,868     18,920
                                                                                    ----------  ---------  ---------
       Net increase (decrease) in cash and cash equivalents                            77,026     (8,853)    (8,322)
       Cash and cash equivalents, beginning of period                                   3,310     12,163     20,485
                                                                                    ----------  ---------  ---------
 Cash and cash equivalents, end of period                                           $  80,336   $  3,310   $ 12,163
                                                                                    ==========  =========  =========
</TABLE>

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


                                       25
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------
                                                    2001      2000       1999
<S>                                               <C>       <C>        <C>
 Net income (loss)                                $72,356   $(18,431)  $(14,887)
                                                  --------  ---------  ---------
 Other comprehensive income (loss), net of tax:
    Foreign currency translation adjustment:
       Current period change                       (1,980)        43        133
    Marketable securities:
       Unrealized gain                                136
    Oil and gas derivatives:
       Net cumulative effect adjustment            (2,153)
       Current period transactions                   (541)
       Reclassification to earnings                 5,173
                                                  --------  ---------  ---------
 Other comprehensive income, net of tax               635         43        133
                                                  --------  ---------  ---------
 Comprehensive income (loss)                      $72,991   $(18,388)  $(14,754)
                                                  ========  =========  =========
</TABLE>

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


                                       26
<PAGE>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2001, 2000 AND 1999
--------------------------------------------------------------------------------
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,
     Ohio,  Virginia  and  Kentucky.

     The  Company,  through  its  other 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,  Texas  and  New  Zealand.

     In  August  2000,  the  Company  sold  its  wholly  owned  regulated  gas
     distribution  utility,  Mountaineer  Gas  Company  and  Subsidiaries
     ("Mountaineer").  See  Note  4.

2.   SUMMARY  OF  SIGNIFICANT  ACCOUNTING  POLICIES

     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.

     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.

     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  40  years.


                                       27
<PAGE>
     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>
                                                               2001       2000
                                                            ----------  ---------
<S>                                                         <C>         <C>
 Oil and gas properties                                     $ 317,225   $219,259
 Pipelines                                                     19,569     18,842
 Other property and equipment                                  14,088     14,167
                                                            ----------  ---------
                                                              350,882    252,268
 Less accumulated depletion, depreciation and amortization   (102,223)   (92,106)
                                                            ----------  ---------
 Net property, plant and equipment                          $ 248,659   $160,162
                                                            ==========  =========
</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. During
     fiscal  year  2001,  in  addition  to  the  usual impairment of oil and gas
     property  of approximately $11.4 million, the Company recognized impairment
     expense  of  $5.7  million related to a failed computer software conversion
     and  $0.3  million  related  to its natural gas fueling operations. For the
     years  ended  June  30, 2000 and 1999, the Company recognized impairment of
     oil  and gas property of $8.3 million and $19.3 million and determined that
     no  impairment  was  needed  on  other  applicable  assets.

     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 and marketing revenues 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".

     Use  of  Estimates  - The preparation of financial statements in conformity
     ------------------
     with  generally  accepted  accounting  principles  in  the United States of
     America  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.


                                       28
<PAGE>
     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, realization of deferred tax assets 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, 2001,
     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  -  SFAS  No.  143 "Accounting for Asset
     ----------------------------------
     Retirement Obligations" provides the accounting requirements for retirement
     obligations  associated  with  tangible  long-lived assets. SFAS No. 143 is
     effective  for  fiscal  years  beginning  after  June  15,  2002, and early
     adoption  is permitted. The Company is currently assessing, but has not yet
     determined,  the  impact  of  SFAS  No.  143 on its consolidated results of
     operations,  cash  flows  or  financial  position.

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

<TABLE>
<CAPTION>
                                                        2001     2000     1999
                                                       -------  -------  -------
<S>                                                    <C>      <C>      <C>
Cash paid for:
   Interest                                            $19,210  $21,360  $19,192
   Income taxes, net                                    37,983      242    1,376
Noncash investing and financing activities:
    Dividends declared and unpaid at year end              265
    Liabilities assumed in acquisition                     824
    Seller financed acquisition                                              150
    Acquisition of property for cancellation of notes                      1,900
</TABLE>


3.   ACQUISITIONS

     On  December  29,  2000,  the  Company  purchased Penn Virginia Oil and Gas
     Corporation's  ("Penn  Virginia")  interests in various oil and gas leases,
     wells, pipelines, contracts, partnership interests, right-of-ways, personal
     property and tax credits. After certain adjustments, the Company paid $57.2
     million  in  cash  and  assumed  a  $0.8  million  note.

     On  July  6,  2001,  the  Company paid $18.1 million for Taverner E&P Ltd's
     interests in various oil and gas leases, wells, seismic and technical data,


                                       29
<PAGE>
     contracts,  right-of-ways  and  real  and  personal  property in Texas. The
     acquisition  had  an  effective  date  before  year end and as a result was
     recorded  at  June  30,  2001  with  the  purchase price reflected in other
     current  liabilities.

4.   DISPOSITIONS

     On  August  18, 2000, the Company sold all of the stock of its wholly owned
     natural  gas distribution company, Mountaineer to a subsidiary of Allegheny
     Energy, Inc. ("Allegheny") for approximately $325.7 million, which included
     the  assumption  of  $100.1  million  of  debt and payment of approximately
     $225.6  million  to  the Company. The Company realized an after-tax gain of
     $84.4  million  on this transaction. Net proceeds from the sale are subject
     to  certain  reinvestment  provisions  of the Company's $200 million Senior
     Subordinated  Notes  (the  "Notes").

     The  operating  results  of the discontinued operations for the years ended
     June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                2001      2000      1999
                                              --------  --------  --------
                                                (1)
<S>                                           <C>       <C>       <C>
 Net sales                                    $ 9,929   $178,882  $172,103

 Income before income taxes                    (3,164)    11,048    19,393
 Income taxes provision (benefit)              (1,317)     3,691     7,901
                                              --------  --------  --------
 Income (loss) from discontinued operations   $(1,847)  $  7,357  $ 11,492
                                              ========  ========  ========
<FN>
(1)  Discontinued  operations  for  one and one half months in fiscal year 2001.
</TABLE>


5.   RISK  MANAGEMENT

     As  of  July  1,  2000,  the  Company adopted SFAS No. 133, "Accounting for
     Derivative  Instruments  and  Hedging Activities", as amended. 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,  to  the  extent the hedge is
     effective,  until  the  hedged  item  is  recognized  in  earnings.  Hedge
     effectiveness  is measured at least quarterly based on the relative changes
     in  fair  value  between  the  derivative contract and the hedged item over
     time.  Any  change in fair value resulting from ineffectiveness, as defined
     by  SFAS  No.  133,  is  recognized  immediately  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 are
     designated  as  cash  flow  hedges.  At June 30, 2000, the Company had swap
     agreements  maturing from July 2000 through October 2001 covering 5,176,600
     Mmbtu  of  gas.  At  July  1,  2000,  adoption of SFAS No. 133, resulted in
     recording a $3.4 million ($2.2 million net of tax) decline in fair value to


                                       30
<PAGE>
     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. At June 30,
     2001,  the  Company  had  swap  agreements  maturing from July 2001 through
     December  2002  covering  4,455,700  Mmbtu.  At  June  30, 2001 the Company
     recorded  a  $2.5  million  gain  (net  of  tax)  in  accumulated  other
     comprehensive  income,  $4.4  million  short  term  derivative  asset, $0.3
     million  short term derivative liability, $0.1 million long term derivative
     liability  and  $1.5  million  in  deferred  tax  liability.

     For  the  years  ended June 30, 2001 and 2000, the Company recognized a net
     loss  in  revenues  on  its  hedging  activities  for oil and gas sales and
     marketing  revenue  of  $8.3  million  and  $0.9 million, respectively. The
     estimated  net  amount  of  the  existing losses within other comprehensive
     income  that  are expected to be reclassified into earnings within the next
     12  months  is  approximately  $2.5  million.

6.   DEBT

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

<TABLE>
<CAPTION>
                                                                   2001       2000
                                                                ---------  ---------
<S>                                                             <C>        <C>
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007                                 $197,672   $200,000
ECA revolving credit, interest floating at Prime plus 1.5% or
LIBOR plus 3%, due 2002                                                      12,000
Installment notes payable, at interest rates ranging from
6.2% to 8%                                                         1,381      1,661
                                                                ---------  ---------
                                                                 199,053    213,661
Less current portion                                                (151)    (1,086)
                                                                ---------  ---------
                                                                $198,902   $212,575
                                                                =========  =========
</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.

     Scheduled  maturities  of the Company's long-term debt at June 30, 2001 for
     each  of  the next five years and thereafter are as follows (in thousands):


                   2002         $    151
                   2003              154
                   2004              158
                   2005              161
                   2006              165
            Thereafter           198,264
                                --------
                                $199,053
                                ========

     Early  Extinguishment  of  Senior Subordinated Notes - On November 9, 2000,
     ----------------------------------------------------
     the  Company  commenced  a  tender  offer to purchase, for cash, all of the
     Notes at a purchase price of $750 per $1,000 principal amount of Notes plus
     accrued  and  unpaid  interest.  The offer to purchase the Notes expired on
     December  11,  2000.  Approximately $2.3 million of the notes were tendered
     and  retired, which resulted in an extraordinary gain of $0.36 million, net
     of  $0.20  million  income  tax.


                                       31
<PAGE>
     Revolving  Credit - The Company had a $22 million revolving credit facility
     -----------------
     secured  by  certain  properties, interest and contracts. The interest rate
     was  variable  based  on  Eurodollars  or  other  defined basis. The annual
     commitment fee ranged between 0.3% and 0.625% depending on usage. On August
     18, 2000, the outstanding balance of $19.8 million was paid in full and the
     credit  agreement  was  terminated.

     Other  Credit  Facilities  - The Company has an unsecured revolving line of
     -------------------------
     credit  totaling $2 million with an interest rate of prime plus 0.5%, which
     expires  November 30, 2001. As of June 30, 2001 and 2000, $0 and $2 million
     were  outstanding  under  the  line  of  credit.

     Other  Notes  - In December 2000, the Company assumed a note as part of the
     ------------
     Penn  Virginia  acquisition,  with  a  balance  of  $0.8 million due in one
     hundred  sixty-one  remaining  consecutive  equal  monthly  installments.

     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, 2001 and 2000, the balance of the note was
     approximately  $0.6  million  and  $0.7  million.


7.   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>
                                     2001       2000       1999
                                   ---------  ---------  ---------
<S>                                <C>        <C>        <C>
Current:
   Federal                         $(27,899)  $   (666)  $   (340)
   State                             (7,884)       (46)      (302)
                                   ---------  ---------  ---------
   Total current                    (35,783)      (712)      (642)
                                   ---------  ---------  ---------
Deferred:
   Federal                           23,115    (11,477)    (9,386)
   State                              5,244        378     (3,105)
                                   ---------  ---------  ---------
   Total deferred                    28,359    (11,099)   (12,491)
                                   ---------  ---------  ---------
   Total benefit for income taxes  $ (7,424)  $(11,811)  $(13,133)
                                   =========  =========  =========
</TABLE>


                                       32
<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>
                                                          2001      2000       1999
                                                        --------  ---------  ---------
<S>                                                     <C>       <C>        <C>
 Tax benefit at the federal statutory rate              $(6,293)  $(13,028)  $(13,676)
 State taxes, net of federal tax effects                 (1,151)    (1,781)    (2,664)
 Effect of rate change                                     (176)
 Section 29 tax credits                                  (2,277)
 Change in valuation allowance on federal, foreign
  and state deferred tax assets, net of federal effect               2,000       (592)
 Investment tax credit expiration                                      532        530
 Other, net                                               2,473        466      3,269
                                                        --------  ---------  ---------
 Provision (benefit) for income taxes                   $(7,424)  $(11,811)  $(13,133)
                                                        ========  =========  =========
</TABLE>

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

<TABLE>
<CAPTION>
                                                  2001       2000
                                                ---------  ---------
<S>                                             <C>        <C>
  Deferred tax assets:
    Royalty Trust agreements                    $  7,501   $  5,689
    Tax credits and carryforwards                  3,710     30,582
    Other                                          3,238      9,413
                                                ---------  ---------
      Total deferred tax assets                   14,449     45,684
                                                ---------  ---------
  Deferred tax liabilities:
    Property, plant and equipment                (27,545)   (20,093)
    Federal income tax on state tax credits       (1,261)    (2,999)
    Other liabilities                             (4,913)   (10,565)
                                                ---------  ---------
      Total deferred tax liabilities             (33,719)   (33,657)
                                                ---------  ---------
  Valuation allowance                             (3,151)    (7,951)
                                                ---------  ---------
  Net deferred income tax asset (liability)      (22,421)     4,076
  Current deferred tax asset (liability)           7,467       (329)
                                                ---------  ---------
  Net long-term deferred tax asset (liability)  $(29,888)  $  4,405
                                                =========  =========
</TABLE>

     At  June  30, 2001, the Company had West Virginia state tax credits of $3.7
     million, which will expire in 2002. The Company was eligible for relocation
     incentives  taken  in  the  form  of  tax  credits  from West Virginia. The
     incentive amounts were 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.


                                       33
<PAGE>
8.   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 $1.3 million, $0.9 million and $0 of profit sharing
     expense during the years ended June 30, 2001, 2000, and 1999, respectively.

     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 $0.24 million, $0.23 million and $0.18 million
     for  the  years  ended  June  30,  2001,  2000,  and  1999,  respectively.

9.   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 common stock that provides the stockholder cannot sell stock
     without  first offering such shares to the Company. At June 30, 2001 49,500
     shares  were  subject  to  the  agreement. 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.

     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.

     Treasury  Stock - At June 30, 2001, the Company had 94,354 shares of voting
     ---------------
     common stock in treasury, carried at cost. The Company purchased 16,342 and
     2,660  shares  of  voting common stock during the years ended June 30, 2001
     and  2000, respectively. At June 30, 2001, the Company had 10,387 shares of
     non-voting  Class  A  stock  in  treasury,  carried  at  cost.  The Company
     purchased  4,160  and  1,711  shares of non-voting Class A stock during the
     years  ended  June  30,  2001  and  2000,  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 per share,
     based  on the fair market value as determined by the Board of Directors 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>


                                       34
<PAGE>
     No  options  were  exercised for either of the years ended June 30, 2001 or
     2000.  Therefore,  as  of  June 30, 2001, all the 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.

10.  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
                                              Earnings     Shares    Amount
                                            -------------  -------  --------
<S>                                         <C>            <C>      <C>
2001
----
  Basic and Diluted Earnings per Share
     Loss available to common shareholders  $(10,555,000)  664,673  $(15.88)
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)
</TABLE>

     The  effect of stock options was not included in the computation of diluted
     net  loss  per  share  because  to  do  so  would  have  been antidilutive.

11.  UNCONSOLIDATED  AFFILIATE

     The Company owns a 25.35% members' interest in Breitburn Energy Corporation
     ("BEC").  The Company's investment in BEC is accounted for under the equity
     method.  Although BEC has current year earnings, the Company's share of net
     losses  since  inception  continues  to  exceed  the carrying amount of the
     investment.  Therefore,  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
     December  31,  is  as  follows  (in  thousands):


                                       35
<PAGE>
<TABLE>
<CAPTION>
                                    2000      1999      1998
                                  --------  --------  --------
<S>                               <C>       <C>       <C>
 Current assets                   $10,744   $ 7,933
 Oil and gas properties            84,050    73,460
 Other assets                       3,233     2,659
                                  --------  --------
    Total assets                  $98,027   $84,052
                                  ========  ========

 Current liabilities              $12,955   $10,140
 Long-term debt                    54,200    47,300
 Other liabilities                  1,433       617
 Redeemable preferred shares       33,650    31,276
 Members' equity                   (4,211)   (5,281)
                                  --------  --------
   Total liabilities and equity   $98,027   $84,052
                                  ========  ========

 Net sales                        $36,551   $19,722   $ 8,128
                                  ========  ========  ========
 Operating income (loss)          $ 9,338   $   200   $  (740)
                                  ========  ========  ========
 Net income (loss)                $ 5,267   $(1,517)  $(2,520)
                                  ========  ========  ========
</TABLE>



12.  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 $1.3, $1.2 and $1.2 million for the years ended June 30,
     2001,  2000  and  1999,  respectively.

     At  June  30,  2001 future minimum lease payments for each of the next five
     years  and  thereafter  are  as  follows  (in  thousands):


                2002        $1,337
                2003         1,185
                2004         1,059
                2005           892
                2006            92
                Thereafter      14
                            ------
                            $4,579
                            ======


13.  RELATED  PARTY  TRANSACTIONS

     The  Company  has entered into a rental arrangement for office space from a
     corporation  in  which  certain  officers  are  shareholders. Rent payments
     totaled  $0.56 million, $0.42 million and $0.37 million for the years ended
     June  30,  2001,  2000  and  1999,  respectively.

     The  Company  advanced funds to certain officers and other related parties,
     at  7%  to  8%  interest.  Balances  totaled $0.6 million and $0.1 million,
     respectively,  at  June  30,  2001  and  2000. A provision in the agreement
     cancels  the  principal  balance  if the employee remains in the continuous
     employment  of  the  Company  for  three  to  four  years, depending on the
     agreement.


                                       36
<PAGE>
     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 carrying value of these notes was $0.9 million
     at  June 30, 2001 and 2000. The notes have interest rates of 6.5% and 8%. A
     provision  in  the  agreements  cancels the principal balance, except for a
     $0.15 million note, 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 for promissory notes. The carrying
     value  of these notes was $0.19 million at June 30, 2001 and 2000. Interest
     rates  are  calculated  at  LIBOR  plus 1.5%. No cancellation provision was
     included  with  this  stock  incentive  program.

     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.

14.  COMMITMENTS  AND  CONTINGENCIES

     In  1993,  the  Company  sold  working interests in certain Appalachian gas
     properties in connection with the formation of the Eastern American Natural
     Gas  Trust  ("Royalty  Trust").  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
     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 were 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  $1.1  million and $8.9 million at June 30, 2001 and 2000, respectively.

     The Company has a gas sales contract, which requires the Company to sell up
     to  4,000  but not less than 1,500 Mmbtu per day through December 31, 2001.
     Under  the contract the Company receives a ten to twelve cent premium above
     the  posted  Appalachian  Index.

     The  Company  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 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  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.


                                       37
<PAGE>
15.  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 are not necessarily
     indicative  of  the  amount that the Company could realize upon the sale or
     refinancing  of  such  financial instruments. 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  - 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. At June 30, 2001, the fair value of
     the  Company's  debt  was  $163.5  million  and  the  book value was $199.1
     million.


                                       38
<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>
                 2001
 Sales to unaffiliated customers         $     45,906   $   81,042   $  1,455   $     128,403
 Intersegment revenues                          1,548                                   1,548
 Depreciation, depletion, amortization         10,653          973        427          12,053
 Impairment and exploratory costs              11,458          287      7,269          19,014
 Operating profit (loss)                       (3,595)          41        168          (3,386)
 Interest expense                              15,565       (6,122)    10,651          20,094
 EBITDAX                                       19,759        1,316     12,109          33,184
 Total assets                                 142,647       77,977    153,199         373,823
 Capital expenditures                         108,343        1,315      3,205         112,863
----------------------------------------------------------------------------------------------
                 2000
 Sales to unaffiliated customers         $     29,763   $   72,156              $     101,919
 Intersegment revenues                                                                      -
 Depreciation, depletion, amortization         10,349        1,031        359          11,739
 Impairment and 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
 Impairment and 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
----------------------------------------------------------------------------------------------
</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 $3.0, $3.9
     and  $1.8  million,  as  of  June  30,  2001,  2000  and  1999.


                                       39
<PAGE>
17.  SELECTED  QUARTERLY  FINANCIAL  DATA  (UNAUDITED)

     The  following  represents selected quarterly financial information for the
     years  ended  June  30  (in  thousands,  except  per  share  data):

<TABLE>
<CAPTION>
                                                               Quarter Ended
                                         -----------------------------------------------------
                  2001                    September 30     December 31    March 31    June 30
                                         ---------------  -------------  ----------  ---------
<S>                                      <C>              <C>            <C>         <C>
 Total revenue                           $       27,083   $     31,898   $  45,109   $ 25,861
 Gross profit (loss)                              1,473          1,363      (2,386)    (3,836)
 Income (loss) before discontinued
    operations and extraordinary items           (1,847)          (250)     (3,590)    (4,868)
 Earnings per share on continuing
    operations, basic and diluted                 (2.77)         (0.38)      (5.41)     (7.35)
 Net income (loss)                               82,661           (939)     (3,622)    (5,744)

                                                               Quarter Ended
                                         -----------------------------------------------------
                  2000                   September 30     December 31    March 31    June 30
                                         ---------------  -------------  ----------  ---------
 Total revenue                           $       27,014   $     26,250   $  23,212   $ 25,443
 Gross profit (loss)                               (817)        (2,667)     (1,144)   (11,867)
 Income (loss) before discontinued
    operations and extraordinary items           (4,338)        (5,804)     (4,347)   (12,019)
 Earnings per share on continuing
    operations, basic and diluted                 (6.50)         (8.72)      (5.41)    (18.20)
 Net income (loss)                               (4,305)        (1,390)      2,554    (15,290)
</TABLE>


                                       40
<PAGE>
     SUPPLEMENTAL  INFORMATION  ON  OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

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

<TABLE>
<CAPTION>
                                                     2001       2000       1999
                                                   ---------  ---------  ---------
<S>                                                <C>        <C>        <C>
Capitalized costs:
   Proved properties                               $271,465   $208,271   $196,554
   Unproved properties                               45,760     10,988     11,351
                                                   ---------  ---------  ---------
   Total                                            317,225    219,259    207,905
   Less accumulated depletion and depreciation      (85,748)   (76,458)   (68,804)
                                                   ---------  ---------  ---------
Net capitalized costs                              $231,477   $142,801   $139,101
                                                   =========  =========  =========

Companyshare of equity method investeenet
   capitalized costs (see Note 11)                 $ 19,690   $ 18,693   $ 11,607
                                                   =========  =========  =========

Costs incurred:
   Acquisition of proved and unproved properties   $ 80,394   $  4,160   $  2,088
   Development costs                                 13,649      5,869      7,527
   Exploration costs                                 15,115      8,693     13,589
                                                   ---------  ---------  ---------
Total costs incurred                               $109,158   $ 18,722   $ 23,204
                                                   =========  =========  =========

Companyshare of equity method investeetotal
   costs incurred (see Note 11)                    $  3,594   $  7,759   $  3,966
                                                   =========  =========  =========
</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>
                                                      2001      2000      1999
                                                     -------  --------  ---------
<S>                                                  <C>      <C>       <C>
Revenues from sale of oil and gas                    $41,555  $23,869   $ 18,295
Less:
   Production costs                                   10,208    8,849      9,005
   Production taxes                                    3,000    1,198        964
   Exploration and impairment                         19,014    8,347     19,261
   Depletion, depreciation and amortization            9,290    8,847      7,915
   Income tax expense (benefit)                           16   (1,181)    (6,597)
                                                     -------  --------  ---------
 Income (loss) from oil and gas operations           $    27  $(2,191)  $(12,253)
                                                     =======  ========  =========

 Companyshare of equity method investee
   income from oil and gas operations (see Note 11)  $ 5,054  $ 1,857   $    183
                                                     =======  ========  =========
</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.


                                       41
<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, 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
    Revisions of previous estimates                           (13,405)        (99)
    Extensions and discoveries                                 22,077       1,380
    Purchases of reserves in place                             49,665         485
    Production                                                 (9,371)       (116)
                                                          ------------  ----------
  June 30, 2001                                               206,456       2,633
                                                          ============  ==========

Proved developed reserves:
  June 30, 1999                                               126,962         714
  June 30, 2000                                               141,067         738
  June 30, 2001                                               175,784         987

Companyshare of equity method investeeproved reserve at:
  June 30, 1999                                                 5,529       9,907
  June 30, 2000                                                 7,402      13,681
  June 30, 2001                                                 9,497      11,811

</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


                                       42
<PAGE>
     are discussed below. The Company believes such information is essential for
     a  proper  understanding  and  assessment  of  the  data  presented.

     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>
                                                       2001        2000        1999
                                                    ----------  ----------  ----------
<S>                                                 <C>         <C>         <C>
Future cash in flows                                $ 828,403   $ 606,382   $ 396,466
Future production and development costs              (271,051)   (178,968)   (144,274)
Future income tax expense                            (145,000)   (121,000)    (47,000)
                                                    ----------  ----------  ----------
Future net cash flows before discount                 412,352     306,414     205,192
10% discount to present value                        (240,071)   (181,543)   (120,309)
                                                    ----------  ----------  ----------
Standardized measure of discounted future net cash
  flows related to proved oil and gas reserves      $ 172,281   $ 124,871   $  84,883
                                                    ==========  ==========  ==========

Companyshare of equity method investee
  standardized measure of discounted future net
  cash flows                                        $  69,478   $  54,362   $  28,129
                                                    ==========  ==========  ==========
</TABLE>


                                       43
<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>
                                                     2001       2000       1999
                                                   ---------  ---------  --------
<S>                                                <C>        <C>        <C>
 Standardized measure of discounted future
   net cash flows at beginning of period           $124,871   $ 84,883   $74,913
 Sales of oil and gas produced, net of
   production costs                                 (28,347)   (13,446)   (8,059)
 Net changes in prices and production costs           3,338     57,741    (1,107)
 Changes in production rates and other               15,526    (10,418)    5,421
 Extensions, discoveries and other additions, net
   of future production and development costs        33,991      2,886     3,977
 Changes in estimated future development costs      (31,981)     2,099     2,701
 Development costs incurred                           9,232      5,869     7,527
 Revisions of previous quantity estimates           (15,677)     5,731    (2,234)
 Purchase of reserves in place                       58,868     10,572
 Sales of reserves in place                                                 (918)
 Accretion of discount                               12,487      8,488     7,491
 Net change in income taxes                         (10,027)   (29,534)   (4,829)
                                                   ---------  ---------  --------
 Standardized measure of discounted
   future net cash flows at end of period          $172,281   $124,871   $84,883
                                                   =========  =========  ========
</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.


                                       44
<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, 2001 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 2000
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                 53  President and Chief Executive Officer; Director
Joseph E. Casabona        58  Executive Vice President; Director
Michael S. Fletcher       52  Chief Financial Officer
Donald C. Supcoe          45  Senior Vice President, Secretary and General Counsel
Edward J. Davies          59  Senior Vice President
J. Michael Forbes         41  Vice President and Treasurer
K. Ralph Ranson, II       59  Vice President Marketing
Julie Ann Kitano          45  Assistant Secretary
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, United Bankshares, Corbin Ltd.,
Education  Networks  of  America  and  the  Benedum  Foundation.

     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"),  Certified  Public Accountants, 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 U. S. Bankcorp, Inc.


                                       45
<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 of the Company since
December  1999.  He  also  held  the  position  of Treasurer of the Company from
December 1999 through December 2000.  In addition, Mr. Fletcher was President of
Mountaineer  Gas  Company from August 1998 until the Company sold Mountaineer in
August  2000.  Prior  to  August 1998, 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  graduate  from Utah State University with a Bachelor
Degree  in  Accounting.

     J.  Michael  Forbes  is  Vice  President and Treasurer of the Company.  Mr.
Forbes  has  been  an officer of the Company since 1995 and prior to that 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.

     Julie Ann Kitano has been Assistant Secretary of the Company since December
2000.  Ms.  Kitano  joined  the  Company  in  1998  as a Paralegal.  She holds a
Bachelor  of  Arts  Degree  from  Whitman  College.

     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  telecommunications  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


                                       46
<PAGE>
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
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.

     K.  Ralph  Ranson, II, has been Vice President of Marketing for the Company
since  December  2000.  He  joined  Eastern  American  in 1993 and has served in
various  capacities,  most recently as Vice President of Land.  Prior to joining
Eastern  American,  Mr.  Ranson worked as an independent oil and gas consultant,
was  an officer with Alamco, Inc. and an officer and director of Union Drilling,
Inc.  Mr.  Ranson  is past President of the Independent Oil & Gas Association of
West  Virginia,  where  he  served two consecutive terms.  Mr. Ranson received a
Bachelor  of  Arts  Degree  from  West  Virginia  Wesleyan  College.

     Donald  C.  Supcoe  is  the  Senior Vice President, Corporate Secretary and
General  Counsel  of the Company and is responsible for the Company's operations
in  the  east,  which includes Eastern American.  Mr. Supcoe was the Senior Vice
President  of  Mountaineer Gas Company from August 1998 until its sale in August
2000.  Prior  to  joining  Mountaineer  in  August  of  1998,  he  was  the Vice
President, General Counsel and Corporate Secretary of Eastern American with whom
he  had  been  employed  in  various positions 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.


                                       47
<PAGE>
                       ITEM 11.     EXECUTIVE COMPENSATION
                       -----------------------------------

     The  following  table  sets  forth  for fiscal year 2001 the total value of
compensation  of  (i)  the Company's Chief Executive Officer and (ii) each other
executive  officer  of  the  Company.

<TABLE>
<CAPTION>
                                            Annual Compensation                         All Other
                                          Year   Salary     Bonus           Other    Compensation (1)
                                          ----  --------  ----------       --------  -----------------
<S>                                       <C>   <C>       <C>         <C>  <C>       <C>
John Mork                                 2001  $256,068  $1,146,635       $  4,349  $          35,251
   President and Chief Executive Officer  2000   253,141     116,350         29,041             11,010
                                          1999   246,820     287,616         43,036             11,935

Joseph E. Casabona                        2001   231,538   1,457,630  (2)     1,888              4,454
   Executive Vice President               2000   223,762      55,853          2,603              8,760
                                          1999   215,086     144,250          2,379              7,921

Michael S. Fletcher                       2001   232,471      56,345        124,198              3,500
   Chief Financial Officer                2000   228,298     168,702         19,496             10,557
                                          1999   220,934     122,802         19,332             16,932

Edward J. Davies                          2001   207,308      53,105            899              4,181
   Senior Vice President                  2000   184,885      31,000          1,507              4,080
                                          1999   181,091      90,150          2,095              4,587

Donald C. Supcoe                          2001   188,447      54,545                             1,482
   Senior Vice President                  2000   180,833      41,599         27,987                216
<FN>
__________________________
(1)  Includes  compensation  related  to  insurance  policies  provided  for the
     benefit  of  named  officer  and  401K  matching  contributions.

(2)  Includes  $900,000  received  as Class A stock and $340,000 cash as related
     tax  protection.
</TABLE>


DIRECTOR  COMPENSATION.  Directors  are  compensated  $2,000  per  meeting  plus
----------------------
reimbursement  for  travel  and  related expenses.  Annually, each Director also
receives  160  shares of the Company's Class A Stock, which is valued at $75 per
share.  During  the  current  fiscal  year, each Director received an additional
1,000  shares  of  the  Company's Common Stock, which was related to the sale of
Mountaineer.


                                       48
<PAGE>
                   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,  2001.  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.

<TABLE>
<CAPTION>
                                                   Beneficial Ownership
                                                       Common Stock
                                                     -----------------
                                                     Shares   Percent
                                                     -------  --------
<S>                                                  <C>      <C>
 Kenneth W. Brill (1)                                 50,710     7.98%
 W. Gaston Caperton, III                               6,680     1.05%
 Joseph E. Casabona                                   31,376     4.94%
 Peter H. Coors                                        2,946        *
 L. B. Curtis                                         12,110     1.90%
 Edward J. Davies                                      3,000        *
 John J. Dorgan                                        2,130        *
 Michael S. Fletcher                                   1,000        *
 F. H. McCullough, III (3)                            72,385    11.39%
 John Mork (2)                                       363,943    57.25%
 Julie Mork (2)                                      363,943    57.25%
 Arthur C. Nielsen, Jr.                               36,480     5.74%
 K. Ralph Ranson, II                                   1,000        *
 Donald C. Supcoe                                      3,583        *

 All Officers and Directors as a group (14 persons)  587,343    90.25%
<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 CompanyCommon Stock owned by him, of which 41,750 have
     been  purchased.
(2)  Includes 355,380 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 70,305 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


                                       49
<PAGE>
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, 2001.  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.

<TABLE>
<CAPTION>
                                                   Beneficial Ownership
                                                      Class A Stock
                                                     ----------------
                                                     Shares  Percent
                                                     ------  --------
<S>                                                  <C>     <C>
 Gaston Caperton                                      1,160     4.52%
 Joseph E. Casabona                                   5,141    20.02%
 Peter Coors                                          1,267     4.93%
 L.B. Curtis                                          1,160     4.52%
 Edward J. Davies                                     3,304    12.87%
 J.J. Dorgan                                          1,160     4.52%
 Michael S. Fletcher                                  2,250     8.76%
 F.H. McCullough                                      1,160     4.52%
 John Mork (1)                                        3,116    12.14%
 Julie Mork (1)                                       3,116    12.14%
 Arthur C. Nielsen, Jr.                               2,320     9.03%
 K. Ralph Ranson                                        417     1.62%
 Donald C. Supcoe                                     1,667     6.49%

 All officers and Directors as a group (13 persons)  24,122    93.94%
<FN>
_______________________
*    Less  than  one  percent
(1)  Includes  1,956  shares  held  by  John and Julie Mork as joint tenants and
     1,160  shares  held  by  Julie  Mork.
</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):


                                       50
<PAGE>
<TABLE>
<CAPTION>
                            2001       2000     1999
                          ---------  --------  ------
                             (3)
<S>                       <C>        <C>       <C>
 Dale P. Andrews                     $   12.6  $ 11.2
 K.W. Brill                                      60.0
 Gaston Caperton          $  100.0       98.6
 Joseph E. Casabona           38.7       49.2    36.8
 Peter Coors                  50.0       49.2    28.1
 L.B. Curtis                 124.0      126.4    70.2
 E.J. Davies                 248.0      126.4   113.5
 John J. Dorgan               25.0       24.5    42.5
 Michael S. Fletcher          25.0       49.2
 J. Michael Forbes            25.0
 John Frederick               25.0
 Thomas R. Goodwin            50.0      172.1     0.1
 F.H. McCullough, III                            84.7
 John Mork (1)             1,240.0      758.3   351.1
 Alison Mork Trust (2)        50.0       24.6    28.1
 Kyle Mork Trust (2)          50.0       24.6    28.1
 Arthur C. Nielsen, Jr.       50.0       49.2    42.5
 Kent Schamp                  27.0       25.3
 Donald C. Supcoe             25.0
                          ---------  --------  ------
 Total                    $2,152.7   $1,590.2  $896.9
                          =========  ========  ======
<FN>

_______________
(1)  Interest  of  John  Mork  and  Julie  Mork  held  as  joint  tenants.
(2)  Trusts  for  minor  children  of  John  Mork  and  Julie  Mork.
(3)  These  amounts  represent  only  the amounts committed to the 2001 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, 2001, the following were indebted to the
Company  (in  thousands):

 Dale P. Andrews      $   63
 Joseph E. Casabona      187
 Edward J. Davies        319
 J. Michael Forbes        96
 Michael S. Fletcher     187
 K. Ralph Ranson          28
 Donald C. Supcoe        209
                      ------
    Total             $1,089
                      ======

     Certain  officers,  Directors and other related parties of the Company have
borrowed  money  from the Company and have executed promissory notes.  The notes
bear  interest  at  7% to 8% per annum.  As of June 30, 2001, the following were
indebted  to  the  Company  (in  thousands):


                                       51
<PAGE>
<TABLE>
<CAPTION>
<S>                   <C>   <C>
 Michael S. Fletcher  $285  (1)
 Linda Given            28  (1)
 David Jordan           55  (1)
 Dennis McGowan         65  (2)
 Donald C. Supcoe      169  (1)
                      ----
                      $602
                      ====
<FN>
_______________
(1)  Promissory  note  is  being  forgiven over three years, assuming continuing
     employment.  As  of  June  30,  2001,  $0.24  million  had  been amortized.
(2)  Promissory  note  is  being  forgiven  over four 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 $0.56 million for fiscal year 2001. The Company believes that
such  rental  terms  are no less favorable than could have been obtained from an
unaffiliated  party.


                                       52
<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  report:


     *  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   Intentionally  omitted.
     *  4.2   Intentionally  omitted.
     *  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  Intentionally  omitted.
     *  10.6  Intentionally  omitted.
     *  10.7  Intentionally  omitted.
     *  10.8  Intentionally  omitted.
     *  10.9  Intentionally  omitted.


                                       53
<PAGE>
     *  10.10 Intentionally  omitted.
     *  10.11 Intentionally  omitted.
     *  10.12 Intentionally  omitted.
     *  10.13 Intentionally  omitted.
     *  10.14 Intentionally  omitted.
     *  10.15 Intentionally  omitted.
     *  10.16 Intentionally  omitted.
     *  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.
     *  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 Intentionally  omitted.
     *  10.28 Intentionally  omitted.
     *  10.29 Intentionally  omitted.
     *  10.30 Intentionally  omitted.
     *  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 Intentionally  omitted.
     *  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.


                                       54
<PAGE>
     *  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.
        10.37 Purchase and Sale Agreement dated June 28, 2001 between Tavener
              E&P  Ltd  and  Westech  Energy  Corporation.
        21.1  Subsidiaries  of  Energy  Corporation  of  America.
        25.1  Power  of  Attorney  set  forth  on  the  signature page
              contained  in  Part  V.


   *    Previously  filed


(b)       Reports  on  Form  8-K
          None

                                    * * * * *




                                       55
<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  2001.

                                       ENERGY CORPORATION OF AMERICA

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


                                       56
<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 2001, by the following persons in the
capacities  indicated.


                                       57
<PAGE>


        Signature                              Title
        ---------                              -----

/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
                            (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


                                       58
<PAGE>