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, 2002.

                                       or

[ ]     TRANSITION  REPORT  PURSUANT  TO  SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ________ TO ________.

                       Commission file number 333-29001-01



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


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

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

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



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

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


Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding  12  months  (or  for such shorter period that the registrant was
required  to  file  such  reports),  and  (2)  has  been  subject to such filing
requirements  for  the  past  90  days.     Yes  [X]     No  [ ]


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


The  aggregate  number  of  shares  and  market  value  of  common stock held by
non-affiliates  of  the  registrant  at  August 31, 2002 was 40,200 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  August  31,  2002  was  624,467  shares.




                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE


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

                                      TABLE OF CONTENTS


                                                                                        Page
<S>                                                                                     <C>
Part I
  Item 1.    Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     4
  Item 2.    Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     7
  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. . . . . . . .    24
  Item 8.    Consolidated Financial Statements and Supplementary Data
               Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . .    25
               Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . .    26
               Statements of Operations. . . . . . . . . . . . . . . . . . . . . . . .    28
               Statements of Stockholders Equity (Deficit) . . . . . . . . . . . . . .    29
               Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . .    30
               Statements of Comprehensive Income. . . . . . . . . . . . . . . . . . .    31
               Notes to Consolidated Financial Statements. . . . . . . . . . . . . . .    32
               Supplemental Information on Oil and Gas Producing Activities (Unaudited)   46
Item 9.      Changes In and Disagreements With Accountants on Accounting
             and Financial Disclosure. . . . . . . . . . . . . . . . . . . . . . . . .    50
Part III
  Item 10.   Directors and Officers of Registrant. . . . . . . . . . . . . . . . . . .    50
  Item 11.   Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . .    53
  Item 12.   Security Ownership of Certain Beneficial Owners and Management. . . . . .    53
  Item 13.   Certain Relationships and Related Transactions. . . . . . . . . . . . . .    55
Part IV
  Item 14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . .    58
Part V
  Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    61
</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  engaged in the exploration, 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, 2002 ("fiscal year 2002"), the Company had total
revenues  from  continuing  operations  of  $86.1  million and EBITDAX (earnings
before  interest,  income taxes, impairment and exploratory costs, depreciation,
depletion  and  amortization)  from operations of $19.7 million.  As used herein
the  "Company"  refers  to the Company alone or together with one or more of its
subsidiaries.

     The  Company conducts business primarily 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
California  and Gulf Coast regions of the United States. WENZ is involved in oil
and  gas  exploration  and  development  in  New  Zealand.

     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.

BUSINESS ACTIVITY
-----------------

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

     The  Company's businesses constitute two operating segments (1) gas and oil
exploration  and  development  and  (2)  gas  aggregation  and  marketing.  For
financial  information  on  these  segments,  see  Note  16  to the Consolidated
Financial  Statements.

GAS  AND  OIL  EXPLORATION  AND  DEVELOPMENT
--------------------------------------------

OPERATIONS AND SIGNIFICANT DEVELOPMENTS

     The  Company's proved net gas and oil reserves are estimated as of June 30,
2002  at  183,345 Mmcf and 2,951 Mbbls, respectively.  For the fiscal year 2002,
the  Company's  net gas production was 9,941 Mmcf and net oil production was 124
Mbbls,  for  a  total  of  10,685  net  Mmcfe.

     DEVELOPMENT ACTIVITY

     The  Company  has  drilled  54  gross wells (48.15 net), with one dry hole,
adding  3,000  gross  Mcf  of  gas  production per day.  Also, a deposit of $1.2
million  was  paid for the purchase of certain oil and gas properties located in
southern  West  Virginia.  The  total  acquisition  will  be  $6.0 million.  The
purchase  includes  proved developed producing gas reserves, estimated at 4 Bcf,
90  producing  wells  and over 30,000 acres.  This acquisition is subject to the
approval  of  the  Public  Service  Commission  of  West  Virginia.


                                        4
<PAGE>
     EXPLORATORY ACTIVITY

     Exploration  wells  and  activity  are  summarized  under  their respective
project  areas.

     1.   Trenton/Rose  Run  --  New  York,  West  Virginia, Ohio, Kentucky. The
Company  drilled  three  successful  Rose  Run wells and one dry hole during the
fiscal  year. Two of the successful wells are located in northern Ohio where the
Company  is a 50% partner. Current production from the two wells is in excess of
1,500 Mcf per day. Additional 2-D and 3-D seismic is being planned for this area
during  the  next  fiscal year. The third Rose Run success is located in central
Ohio,  where  the  Company  has  a  50%  interest. The Company also drilled four
Trenton  wells  during  the  fiscal  year. The first Trenton well drilled in the
northern Ohio area was unsuccessful in the Trenton, but resulted in a successful
Clinton  completion. The first Trenton well drilled in the central West Virginia
is  a  discovery.  Completion options are currently being evaluated. One Trenton
well  in  New  York  and  one  Trenton  well  in  Kentucky  were  dry  holes.

     2.   Texas.  The Company drilled two successful wells, one completed in the
Frio formation and the other completed in the Yegua.  The Company's net interest
in  the  wells is 40%.  The wells are producing approximately 2,000 Mcf per day.
The  Company  drilled two deeper wells to the Wilcox / Meek formation which were
completed  but  were  not  economically  successful.

     3.   New  Zealand.  The  Company  drilled from onshore a stratigraphic test
of the offshore license.  This well was unsuccessful, but satisfied the offshore
permit  drilling  requirement.  The Company is continuing its efforts to farmout
the  East  Coast  offshore  prospects.

     4.   California.  The  Company  participated  in  the drilling of two field
extension  wells  in  the  Sawtelle  Field.  One  well  currently  is  producing
approximately  75 Bbl per day and the second well was a dry hole.  The Company's
interest  is  33%.

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,


                                        5
<PAGE>
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
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.  The  Company
believes  it  is  within  substantial  compliance with regulations affecting the
Company.


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  Company owns and operates approximately 2,000 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,  2002,  Eastern Marketing aggregated and sold an average of 44.2 Mmcf of gas
per day, of which 41.3 gross Mmcf per day represented sales of gas produced from
wells  operated by the Company. This represents a slight decrease in the overall
volumes  compared  to  fiscal  year  2001,  during  which  the Eastern Marketing
aggregated  and  sold  an  average  of 44.7 Mmcf of gas per day. The increase in
sales  from Company operated wells from 38.6 in 2001 to 41.3 Mmcf in 2002 is due
to  the  integration  of  production  from  the  Penn  Virginia acquisition into
marketing  sales.

GAS SALES AND PURCHASE CONTRACTS

     The  Company  has  satisfied  its obligations under all gas sales contracts
(16.1  Bcf  in  fiscal year 2002) 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 (15.1 Bcf in fiscal 2002), and from
natural  gas aggregated by the Company pursuant to its aggregation and marketing
activities  from  third  parties  (1.0  Bcf  in  fiscal  2002).

     The  Company  entered into a gas sale and purchase agreement with Allegheny
Energy  Services  Corporation  ("Allegheny"),  whereby  it began the delivery of
natural  gas  on November 1, 2001. The Company received a $10 million prepayment
pursuant  to  the agreement. 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's deliveries of natural
gas  average  3,100  Mmbtu  per day. As of June 30, 2002, 752,940 Mmbtu had been
delivered  at  a  value  of  $2.3  million.

     On November 30, 2001, the Company entered into a natural gas sales contract
with  Mountaineer  Gas  Company,  doing  business as Allegheny Power, to deliver
5,500 Dth per day.  Under the pricing terms, the Company will never receive less


                                        6
<PAGE>
than  $2.75  per Dth plus the Columbia Gas Transmission ("TCO") Appalachia Basis
or more than $4.85 per Dth plus the TCO Appalachia Basis.  The contract began on
December  1,  2001  and  continues  through  October  31,  2004.

     The  Company  has  a  gas  sales  contract  with  Dominion Hope ("Hope"), a
subsidiary  of  Dominion  Energy, which requires the Company to sell up to 4,800
but  not less than 3,200 Mmbtu per day to Hope beginning January 1, 2002 through
December 31, 2003. Pricing under the contract requires Hope to pay the Company a
10.5  cent  to  15.5  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.
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,  2002, the Company had approximately 213 full-time and 28
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
                               ------------------

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
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:


                                        7
<PAGE>
<TABLE>
<CAPTION>
                                                          2002      2001      2000
                                                        --------  --------  --------
<S>                                                     <C>       <C>       <C>
Net proved:
   Gas (Mmcf)                                            183,345   206,456   157,490
   Oil (Mbbls)                                             2,951     2,633       983
   Total (Mmcfe)                                         201,051   222,254   163,388

Net proved developed:
   Gas (Mmcf)                                            160,224   175,784   141,067
   Oil (Mbbls)                                             1,135       987       738
   Total (Mmcfe)                                         167,034   181,706   145,495

Estimated future net cash flows
   before income taxes (in thousands)                   $471,927  $557,352  $427,414
Present Value of estimated future net cash
   flows after income taxes (in thousands) (1)          $150,913  $172,281  $124,871

---------------
 (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 present value by region, as of June 30, 2002:

<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  $    430,590   91.2%        1,051       171,718      178,024
      Western Basins           27,738    5.9%        1,455         4,829       13,559
      Gulf Coast               12,903    2.7%          445         6,187        8,857
      New Zealand                 696    0.2%            -           611          611
                         ------------  ------  -----------  ------------  -----------
      Total              $    471,927  100.0%        2,951       183,345      201,051
                         ============  ======  ===========  ============  ===========
</TABLE>

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

     The  following  table sets forth certain information relating to productive
wells  at  June 30, 2002.  Wells are classified as oil or gas according to their
predominant  production  stream.

<TABLE>
<CAPTION>
                             Gross Wells        Net Wells
                         -----------------  ---------------------
                         Oil   Gas   Total  Oil    Gas     Total
                         ---  -----  -----  ---  -------  -------
<S>                      <C>  <C>    <C>    <C>  <C>      <C>
      Appalachian Basin    2  5,136  5,138  1.0  3,276.2  3,277.2
      Western Basins      11      2     13  3.3      2.0      5.3
      Gulf Coast           1      4      5  0.7      2.2      2.9
      New Zealand          -      3      3    -      3.0      3.0
                         ---  -----  -----  ---  -------  -------
      Total               14  5,145  5,159  5.0  3,283.4  3,288.4
                         ===  =====  =====  ===  =======  =======
</TABLE>


                                        8
<PAGE>
ACREAGE
-------

     The  following table sets forth the developed and undeveloped gross and net
acreage  held  at  June  30,  2002:

<TABLE>
<CAPTION>
                          Developed Acreage       Undeveloped Acreage
                         --------------------  ------------------------
                           Gross       Net        Gross         Net
                         ---------  ---------  -----------  -----------
<S>                      <C>        <C>        <C>          <C>
      Appalachian Basin  399,945.0  308,158.0    140,028.0     99,175.0
      Western Basins       1,840.0    1,441.9    208,024.3    111,578.3
      Gulf Coast           1,086.1      474.9     35,851.1     27,333.5
      New Zealand            700.0      700.0  2,969,076.1  2,969,076.1
                         ---------  ---------  -----------  -----------
      Total              403,571.1  310,774.8  3,352,979.5  3,207,162.9
                         =========  =========  ===========  ===========
</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>
                                                              2002     2001     2000
                                                             -------  -------  ------
<S>                                                          <C>      <C>      <C>
      Production Data:
         Oil (Mbbls)                                             124      116     113
         Natural gas (Mmcf)                                    9,941    9,371   7,399
         Natural gas equivalent (Mmcfe)                       10,685   10,067   8,079
      Average Sales Price (before the effect of hedging):
         Oil per Bbl                                         $ 21.11  $ 25.94  $21.64
         Natural gas per Mcf                                 $  2.86  $  5.43  $ 2.81
</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.


                                        9
<PAGE>
<TABLE>
<CAPTION>
                               2002         2001         2000
                           -----------  -----------  -----------
                           Gross   Net  Gross   Net  Gross   Net
                           -----  ----  -----  ----  -----  ----
<S>                         <C>   <C>   <C>    <C>   <C>    <C>
Development:
     Productive
        Appalachian         53.0  47.8   47.0  41.5   15.0  12.6
        Other                1.0   0.3      -     -      -     -
                           -----  ----  -----  ----  -----  ----
     Total                  54.0  48.1   47.0  41.5   15.0  12.6
                           =====  ====  =====  ====  =====  ====

     Nonproductive
        Appalachian          1.0   0.9    1.0   0.5      -     -
        Other                  -     -      -     -      -     -
                           -----  ----  -----  ----  -----  ----
     Total                   1.0   0.9    1.0   0.5      -     -
                           =====  ====  =====  ====  =====  ====
Exploratory:
     Productive
        Appalachian          4.0   1.6                 1.0   0.5
        Other                4.0   2.3    3.0   2.6    3.0   1.5
                           -----  ----  -----  ----  -----  ----
     Total                   8.0   3.9    3.0   2.6    4.0   2.0
                           =====  ====  =====  ====  =====  ====

     Nonproductive
        Appalachian          5.0   2.1    2.0   0.3      -     -
        Other                4.0   3.2    8.0   3.8   15.0   8.3
                           -----  ----  -----  ----  -----  ----
     Total                   9.0   5.3   10.0   4.1   15.0   8.3
                           =====  ====  =====  ====  =====  ====
</TABLE>

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

     As  previously disclosed, in June 2001, the Company filed a lawsuit against
Oracle  Corporation  for  breach  of contract, breach of warranty and rescission
with  respect  to  a  software  package  purchased  from  Oracle  and the failed
implementation thereof.  Oracle answered the complaint substantially denying all
of  the  Company's  allegations  and  filed  a  counterclaim against the Company
alleging  that  it  is  owed  approximately $1.2 million for prior services.  In
November  2001,  the Company amended its Complaint against Oracle to add a count
for  fraud.  Extensive discovery has been conducted by the parties.  The Company
intends  to  aggressively  prosecute  its  case against Oracle as well as defend
against  the  counterclaim  of  Oracle.  This  case  is  scheduled  for trial in
November  2002.

     As  previously  disclosed,  on  December  27,  2001, the Company received a
Notice  of  Default  from  certain  holders  of  its  $200 million 9-1/2% Senior
Subordinate Notes due 2007 (the "Notes") alleging a default under Section 4.9 of
the  Indenture  pursuant  to  which  the Notes were issued.  The alleged default
related to the proper calculation of Net Proceeds of an Asset Sale, particularly
with  respect  to  the  deduction  for taxes paid or payable as a result of such
sale.  On  December 28, 2001, the Company filed a declaratory judgment action in
the United States District Court for the Southern District of West Virginia (the
"Court")  against the holders of the Notes who issued the Notice of Default (the
"Noteholders"),  asking  the  Court  to  confirm  the  proper calculation of Net
Proceeds  of  an Asset Sale under the Indenture.  On January 25, 2002, the Court
entered  an  order  denying  the Noteholders' Motion to Dismiss and granting the
Company's  Motion  for  Partial  Summary  Judgment,  which  order  approved  the
Company's methodology in calculating taxes paid or payable in connection with an
Asset  Sale.  On  February  28,  2002,  the  Noteholders  filed  an  answer  and
counterclaim  in the declaratory judgment action.  The counterclaim alleges that
the  Company's  sale  of  Mountaineer  in  August  of 2000 constituted a sale of


                                       10
<PAGE>
substantially  all  assets  of  the  Company,  as  opposed to an Asset Sale, and
invoked  certain  obligations  under the Indenture to repurchase the outstanding
Notes.  On  March  25,  2002,  the  Company  filed its Second Motion for Partial
Summary  Judgment, asserting that the Noteholders were barred from asserting the
counterclaim.  On  June  3,  2002,  the  United  States  District  Court for the
Southern  District  of  West  Virginia  entered  an order granting the Company's
Second  Motion  for  Partial  Summary  Judgment,  which  order  dismissed  the
Noteholders'  claim  on the basis of judicial admissions and equitable estoppel.
On  May  22,  2002,  the  Noteholders filed a "Motion for Reconsideration of the
Court's January 25, 2002 Order and Permission to Take Limited Discovery in Order
to  Supplement  the  Record".  The  Court  entered an Order dated July 19, 2002,
denying  the  Noteholders'  Motion  for  Reconsideration.  On  July 27, 2002 the
Noteholders  filed  a  Notice of Appeal, and the appeal is pending in the United
States Court of Appeals for the Fourth Circuit.  The foregoing text is qualified
in  its  entirety  by Orders of the Court entered January 25, 2002, June 3, 2002
and  July  19,  2002,  which are attached as Exhibits and incorporated herein by
reference.

     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
August 31,  2002,  the  Company had 35 holders of record of its common stock.

     The  Company declared dividends in fiscal years 2002, 2001 and 2000 of $1.1
million,  $3.9  million  and  $0,  respectively.


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

(Dollars in thousands, except per share items)

                                                        Year Ended June 30,
                                        -----------------------------------------------------
                                          2002       2001       2000       1999       1998
                                        ---------  ---------  ---------  ---------  ---------
<S>                                     <C>        <C>        <C>        <C>        <C>
                                                                                          (1)
Operating revenue                       $ 86,142   $129,951   $101,919   $113,500   $193,459
Loss from continuing operations          (26,180)   (10,199)   (26,508)   (27,099)    (3,773)
Loss from continuing operations
   Per common share, basic and diluted    (39.80)    (15.34)    (40.11)    (40.27)     (5.67)
Total assets                             304,736    380,532    265,691    286,077    290,541
Long term debt                           198,701    198,902    212,575    219,886    201,507
Dividends declared per common share     $   1.60   $   5.80   $      -   $   0.95   $   1.70
</TABLE>
    (1)  Includes a $30.0 million contract settlement.


           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-K, 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>
CRITICAL  ACCOUNTING  POLICIES  AND  ESTIMATES
----------------------------------------------

     The  discussion  of  financial condition and results of operation are based
upon  the  information  reported  in the consolidated financial statements.  The
preparation  of  these  financial  statements  requires  the  Company  to  make
assumptions  and  estimates  that  affect  the  reported  amounts  of  assets,
liabilities,  revenues  and  expenses  as  well  as the disclosure of contingent
assets  and  liabilities at the date of the financial statements.  Decisions are
based on historical experience and various other sources that are believed to be
reasonable  under  the  circumstances.  Actual  results  may  differ  from  the
estimates  due to changing business conditions or unexpected circumstances.  The
Company  believes  the  following  policies  are  critical  to understanding our
business  and  results of operations.  For additional information on significant
accounting  policies,  see  Notes  to  Consolidated  Financial  Statements,
particularly  Note  2.

     REVENUE  RECOGNITION  -  The  Company  is  engaged  in  the  exploration,
development, acquisition, production and marketing of natural gas and crude oil.
The  revenue  recognition policy is significant because it is a key component of
the  results  of  operations  and  forward  looking  statements contained in the
Liquidity  and  Capital Resources section. Revenue is derived primarily from the
sale  of  produced  natural  gas and crude oil. Revenue is recorded in the month
production  is  delivered  to  the  purchaser, but payment is generally received
between  30 and 90 days after the date of production. Monthly, the Company makes
estimates  of  the amount of production delivered to the purchaser and the price
to  be  received.  The  Company  uses  its  knowledge  of properties, historical
performance,  NYMEX  and local spot market prices and other factors as the basis
for  these  estimates.  Variances  between  the estimates and the actual amounts
received  are  recorded  in  the  month  revenue  is  distributed.

     FAIR  VALUE  OF  DERIVATIVE INSTRUMENTS - As of July 1, 2000, the estimated
fair  values  of  the  derivative  instruments  are recorded on the consolidated
balance  sheet.  All  of the derivative instruments are entered into to mitigate
risks  related  to  the  prices  to  be  received for future natural gas and oil
production.  Derivative  instruments are not used for trading purposes. Although
derivatives  are reported on the balance sheet at fair value, to the extent that
instruments  qualify  for  hedge accounting treatment, changes in fair value are
recorded, net of taxes, directly to stockholders' equity until the hedged oil or
natural gas quantities are produced. To the extent changes in the fair values of
derivatives relate to instruments not qualifying for hedge accounting treatment,
such changes are recorded to income in the period they occur. In determining the
amounts  to  be  recorded,  we  are  required  to  estimate  the  fair values of
derivatives.  The estimates are based upon various factors that include contract
volumes  and  prices,  contract  settlement  dates, quoted closing prices on the
NYMEX  or  over-the-counter,  volatility  and  the  time  value  of options. The
calculation  of  the  fair  value  of collars and floors requires the use of the
Black-Scholes  option-pricing model. The estimated future prices are compared to
the  prices  fixed  by  the  derivatives  agreements and the resulting estimated
future  cash  inflows or outflows over the lives of the hedges are discounted to
calculate  the  fair  value  of  the  derivative  contracts.  These  pricing and
discounting  variables  are sensitive to market volatility as well as changes in
future  price  forecasts  and  regional  price  differences.  Periodically  the
valuations  are  validated  using  independent  third  party  quotations.

     RESERVE  ESTIMATES  -  The  Company's  estimate of gas and oil reserves are
projections  based  on  geologic  and  engineering data. There are uncertainties
inherent  in the interpretation of such data as well as the projection of future
rates  of  production  and  the  timing  of  development  expenditures.  Reserve
engineering  is  a subjective process of estimating underground accumulations of
gas  and oil that are difficult to measure. The accuracy of any reserve estimate
is  a  function  of  the  quality  of available data, engineering and geological
interpretation  and  judgment. Estimates of economically recoverable gas and oil
reserves  and future net cash flows depend upon a number of variable factors and
assumptions,  such  as  expected  future  production  rates, gas and oil prices,
operating  costs,  severance taxes, and development costs, all of which may vary
considerably  from  actual  results.  Expected cash flows are reduced to present


                                       13
<PAGE>
value  using  a  discount  rate.  Reserve estimates are inherently imprecise and
estimates  of  new discoveries are more imprecise than those of proved producing
oil  and  gas  properties.  The  future  drilling costs associated with reserves
assigned  to  proved  undeveloped locations may ultimately increase to an extent
that these reserves may be determined to be uneconomic. Any significant variance
in  the  assumptions could materially affect the estimated quantity and value of
the reserves, which could affect the carrying value of the Company's gas and oil
properties  and  their rates of depletion. Changes in these calculations, caused
by changes in reserve quantities or net cash flows are recorded on a prospective
basis.  Actual  production,  revenues  and  expenditures  with  respect  to  the
Company's  reserves  will  likely  vary from estimates and such variances may be
material.

     DEPLETION  -  The  capitalized  costs  of oil and gas properties related to
proved  reserves  are  amortized  on  a  unit-of-production  method  based on an
estimate  of  proved developed oil and gas reserves. The quantities of estimated
reserves are a significant component of amortization and revisions may alter the
rate  of  future expense. Generally, if reserve volumes increase or decrease the
amortization  rate  per  unit  of  production  will change inversely. Production
volumes  do  not  affect  the  per-unit  rate.

     VALUATION  OF LONG-LIVED AND INTANGIBLE ASSETS - Property and equipment are
recorded  at  cost. The carrying value of property and equipment is reviewed for
possible  impairment  whenever  events or changes in circumstances indicate that
the carrying amount may not be recoverable. Assets are determined to be impaired
if a forecast of undiscounted estimated future net operating cash flows directly
related to the asset, including disposal value if any, is less than the carrying
amount  of  the  asset.  If  any asset is determined to be impaired, the loss is
measured  as  the  amount  by which the carrying amount of the asset exceeds its
fair  value.  An  estimate  of  fair  value  is  based  on  the best information
available, including prices for similar assets. Different pricing assumptions or
discount  rates  would  result  in  a  different  calculated  impairment.

     INCOME  TAXES  -  The  Company  provides  for  deferred income taxes on the
difference  between  the  tax  basis  of  an asset or liability and its carrying
amount  in  the  financial  statements.  This  difference will result in taxable
income  or  deductions  in future years when the reported amount of the asset or
liability  is  recovered  or settled, respectively. Federal and state income tax
returns are generally not filed before the consolidated financial statements are
prepared,  therefore  we estimate the tax basis of assets and liabilities at the
end  of  each period as well as the effects of tax rate changes, tax credits and
net operating loss carryforwards. Adjustments related to differences between the
estimates  and  actual amounts are recorded in the period the income tax returns
are  filed.

COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2002 AND 2001
--------------------------------------------------------------------------------

     The Company recorded a net loss from continuing operations of $26.2 million
for  the  year  ended  June  30, 2002 compared to a net loss of $10.2 million in
2001.  The  increase  in net loss of $16.0 million is attributed to the net of a
$43.8  million  decrease  in  revenue,  a  $22.4  million  decrease in operating
expenses,  a $4.6 million decrease in other non-operating income, a $0.4 million
decrease  in  interest  expense  and  a  $9.6  million  increase  in  income tax
benefits.

     OPERATING  MARGINS.  Operating  Margins  (defined as revenue less operating
     ------------------
costs,  taxes  other  than  income  taxes  and direct general and administrative
expense)  for the Company's operating subsidiaries totaled $27.4 million for the
current  year  compared to $33.0 million for the prior period. The Company's Oil
and  Gas  Operating Margin (defined as oil and gas sales and well operations and
service  revenues  less  field  operating  expenses, taxes other than income and
direct  general  and  administrative) totaled $23.2 million versus $27.6 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 $3.7 million for the current period versus $3.9 million
for  the  prior  period.


                                       14
<PAGE>
     Production,  marketing  and  pipeline  volumes,  revenue  and average sales
prices  for the years ended June 30 and their related variances are as follows:

<TABLE>
<CAPTION>
                                                                             Variance
                                                                        -------------------
                                                      2002      2001     Amount    Percent
                                                     -------  --------  ---------  --------
<S>                                                  <C>      <C>       <C>        <C>
Natural Gas
   Production (Mmcf)                                   9,941    8,822(1)   1,119     12.68%
   Average sales price received ($per Mcf)              2.86     5.45      (2.59)   -47.52%
                                                     -------  --------  ---------  --------
   Sales ($in thousands)                              28,463   48,063    (19,600)   -40.78%
Oil
   Production (Mbbl)                                     124      108(1)      16     14.81%
   Average sales price received ($per Bbl)             21.11    25.94      (4.83)   -18.62%
                                                     -------  --------  ---------  --------
   Sales ($in thousands)                               2,618    2,812       (194)    -6.90%
Hedging                                                7,211   (9,567)    16,778    175.37%
Other                                                    647      247        400    161.94%
                                                     -------  --------  ---------  --------
Total oil and gas sales ($in thousands)              $38,939  $41,555   $ (2,616)    -6.30%
                                                     =======  ========  =========  ========
Marketing Revenue
   Volume (Mdth)                                       9,903   12,126     (2,223)   -18.33%
   Average sales price received ($per Dth)              3.14     5.42      (2.28)   -42.07%
                                                     -------  --------  ---------  --------
   Sales ($in thousands)                              31,125   64,890    (33,765)   -52.03%
Pipeline Revenue
   Volume (Mdth)                                       6,003    6,531       (528)    -8.08%
   Average sales price received ($per Dth)              1.68     2.47      (0.79)   -31.98%
                                                     -------  --------  ---------  --------
   ($in thousands)                                    10,084   16,152     (6,068)   -37.57%
                                                     -------  --------  ---------  --------
Total marketing and pipeline sales ($in thousands)   $41,209  $81,042   $(39,833)   -49.15%
                                                     =======  ========  =========  ========
Marketing Cost
   Volume (Mdth)                                       9,902   12,087     (2,185)   -18.08%
   Average price paid ($per Dth)                        2.98     5.16      (2.18)   -42.25%
                                                     -------  --------  ---------  --------
   Cost ($in thousands)                               29,525   62,219    (32,694)   -52.55%
Pipeline Cost
   Volume (Mdth)                                       4,870    5,455       (585)   -10.72%
   Average price paid ($per Dth)                        1.64     2.74      (1.10)   -40.15%
                                                     -------  --------  ---------  --------
   Cost ($in thousands)                                7,964   14,948     (6,984)   -46.72%
                                                     -------  --------  ---------  --------
Total marketing and pipeline cost ($in thousands)    $37,489  $77,167   $(39,678)   -51.42%
                                                     =======  ========  =========  ========
<FN>
(1)  Production does not include volumes related to the Penn Virginia
     acquisition between the effective date and the closing date.
</TABLE>

     REVENUES.  Total  revenues  decreased  $43.8  million  or 33.7% between the
     ---------
years.  The  net  decrease  was  due  to  a  49.2% decrease in gas marketing and
pipeline  sales,  a  6.3% decrease in oil and gas sales, a 6.9% decrease in well
operations and service revenues and a 65.4% decrease in other operating revenue.

     Revenues from gas marketing and pipeline sales decreased $39.8 million from
$81.0  million  during  the  period  ended June 30, 2001 to $41.2 million in the
period  ended  June 30, 2002. Gas marketing revenue decreased $33.7 million. The
price decline corresponds with related indexes. The decline was partially offset
by  a $0.5 million bad debt write off during the prior period. Pipeline revenue,
which  has  a  sales  and  transportation component, decreased $6.1 million. The
decrease in gas marketing and pipeline volumes is primarily due to the Company's
reduction  in  the  purchase  of  third  party  volumes.


                                       15
<PAGE>
     Revenues  from oil and gas sales decreased a net of $2.6 million from $41.5
million  for  the  year  ended June 30, 2001 to $38.9 million for the year ended
June  30,  2002. Natural gas sales declined $19.6 million and oil sales declined
$0.2  million.  The  net  decline  is attributed to the following variances; gas
price  decrease  $25.7  million, gas production increase $6.1 million, oil price
decrease  $0.6  million  and  oil  production  increase  $0.4 million. The price
decline  corresponds with related indexes. The increased volume is primarily due
to a full year of production related to the Penn Virginia acquisition, while the
prior  period  had  six  months.  The decreased production revenue was offset by
recognized  gains  on related hedging transactions, which totaled a gain of $7.2
million  for the year ended June 30, 2002 compared to a loss of $9.6 million for
the  year  ended  June  30, 2001. The average price per Mcfe, after hedging, was
$3.64  and  $4.39  for  the  years  ended  June  30,  2002  and  2001.

     Other  operating revenue decreased $1.0 million. The current year income of
$0.5  million is related to revenue earned by the Company's drilling subsidiary,
Deep Rig, with no related revenue in the prior period. The prior year revenue of
$1.5 million was related to a management contract with Allegheny that terminated
March  31,  2001.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses decreased $22.4
     ---------------------
million  or  16.8%  between  the  periods  primarily  as a net result of a 51.4%
decrease  in  gas  marketing  and  pipeline costs, a 22.5% increase in field and
lease  operating  expenses,  a  35.6%  increase  in  general  and administrative
expenses,  a  35.8% decrease in taxes other than income, a 33.1% increase in oil
and  gas  related  depreciation, depletion and amortization expenses and a 45.7%
increase  in  exploration  and  impairment  costs.

     Gas  marketing  and  pipeline  costs decreased $39.7 million. Gas marketing
cost  decreased  $32.7.  The  price  decline  corresponds  with related indexes.
Pipeline  costs  decreased  $7.0  million.  The  decrease  in  gas marketing and
pipeline  volumes  purchased  is  due  to  the  decline  in  volumes  sold.

     Field  and  lease operating expenses increased $2.0 million. A full year of
expenses  related  to  the Penn Virginia acquisition, while the prior period had
six  months,  accounted  for  a $0.4 million increase. The remaining increase is
primarily related to payroll expenses and for repairs to roads and dikes damaged
during  flooding.

     General  and  administrative  expenses  increased  $4.6  million because of
higher  costs,  primarily  related to payroll and employee benefits, legal fees,
bad  debt  reserves  and  increased  Texas  activity.

     Taxes  other  than  income decreased $1.2 million, of which $0.9 million is
due  to  decreased  oil  and  gas prices. Production taxes are based on wellhead
prices  and  are not affected by hedging activity. The remaining $0.3 million is
related  to  decreased  franchise  taxes.

     Oil  and  gas  related  depreciation,  depletion  and amortization expenses
increased  $3.1 million. The increase in production volumes primarily due to the
Penn Virginia acquisition, accounted for $0.9 million. The remaining increase is
primarily  a  result  of  increased  depletion  rates  and  production in Texas.

     Exploration  and  impairment  expenses increased $8.7 million. The expenses
were  primarily  due  to  dry  hole  costs, impairment of wells and property and
various  other  geological and geophysical costs. The breakdown of costs by area
are  $13.1  million in the Gulf Coast, $6.6 million in New Zealand, $4.4 million
in  the  Appalachian  basin  and  $3.4  million  in  the  West.


                                       16
<PAGE>
     OTHER  NON-OPERATING  INCOME.  Other  non-operating  income  decreased $4.7
     -----------------------------
million when comparing the periods. This is primarily the result of $6.0 million
less  interest  income  due to decreases in the cash balances and interest rates
when comparing the periods. This was partially offset by a $1.3 million decrease
in  other  non-operating  expense  in  fiscal  year  2002.

     INCOME  TAX. The benefit for income taxes increased $9.6 million due to the
     ------------
$25.6  million  increased  loss  from  continuing  operation.


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

     The Company recorded a net loss from continuing operations of $10.2 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 $16.3 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  $5.6  million  increase  in  other
non-operating  income  and  a  $4.6  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.


                                       17
<PAGE>
     Production,  marketing  and  pipeline  volumes,  revenue  and average sales
prices  for the years ended June 30 and their related variances are as follows:

<TABLE>
<CAPTION>
                                                                               Variance
                                                                          ------------------
                                                       2001       2000     Amount   Percent
                                                    ----------  --------  --------  --------
<S>                                                 <C>         <C>       <C>       <C>
Natural Gas
   Production (Mmcf)                           (1)      8,822     7,399     1,423     19.23%
   Average sales price received ($per Mcf)               5.45      2.81      2.64     93.95%
                                                    ----------  --------  --------  --------
   Sales ($in thousands)                               48,063    20,808    27,255    130.98%
Oil
   Production (Mbbl)                           (1)        108       113        (5)    -4.42%
   Average sales price received ($per Bbl)              25.94     21.64      4.30     19.87%
                                                    ----------  --------  --------  --------
   Sales ($in thousands)                                2,812     2,455       357     14.54%
Hedging                                                (9,567)     (967)   (8,600)  -889.35%
Other                                                     247     1,573    (1,326)   -84.30%
                                                    ----------  --------  --------  --------
Total oil and gas sales ($in thousands)             $  41,555   $23,869   $17,686     74.10%
                                                    ==========  ========  ========  ========
Marketing Revenue
   Volume (Mdth)                                       12,126    21,050    (8,924)   -42.39%
   Average sales price received ($per Dth)               5.42      2.92      2.50     85.62%
                                                    ----------  --------  --------  --------
   Sales ($in thousands)                               64,890    61,137     3,753      6.14%
Pipeline Revenue
   Volume (Mdth)                                        6,531     7,142      (611)    -8.56%
   Average sales price received ($per Dth)               2.47      1.54      0.93     60.39%
                                                    ----------  --------  --------  --------
   ($in thousands)                                     16,152    11,019     5,133     46.58%
                                                    ----------  --------  --------  --------
Total marketing and pipeline sales ($in thousands)  $  81,042   $72,156   $ 8,886     12.31%
                                                    ==========  ========  ========  ========
Marketing Cost
   Volume (Mdth)                                       12,087    21,048    (8,961)   -42.57%
   Average price paid ($per Dth)                         5.16      2.94      2.22     75.51%
                                                    ----------  --------  --------  --------
   Cost ($in thousands)                                62,219    61,893       326      0.53%
Pipeline Cost
   Volume (Mdth)                                        5,455     6,066      (611)   -10.07%
   Average price paid ($per Dth)                         2.74      1.35      1.39    102.96%
                                                    ----------  --------  --------  --------
   Cost ($in thousands)                                14,948     8,208     6,740     82.12%
                                                    ----------  --------  --------  --------
Total marketing and pipeline cost ($in thousands)   $  77,167   $70,101   $ 7,066     10.08%
                                                    ==========  ========  ========  ========
<FN>
     (1)  Production  does  not  include  volumes  related  to the Penn Virginia
          acquisition  between  the  effective  date  and  the  closing  date.
</TABLE>

     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.


                                       18
<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.
Pipeline  revenue  increased $5.1 million.  The decrease in volumes is primarily
related  to  the  Company's  decision  to  exit  the  end-user  market.

     Revenues  from oil and gas sales increased $17.7 million from $23.9 million
for  the  year  ended June 30, 2000 to $41.5 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 $5.45 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, 4.4%,
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 $1.0 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
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.


                                       19
<PAGE>
     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 $5.6
     ----------------------------
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 $4.6 million due to
     -----------
the  $20.9  million  increase  to  pre-tax  earnings  from continuing operation.


CAPITAL  EXPENDITURES
---------------------

     Expenditures  for  the  exploration, development and acquisition of oil and
gas  properties  are  the  Company's  primary  use  of  capital  resources.  The
following  table  summarizes  certain costs incurred for the years ended June 30
(in  thousands):

<TABLE>
<CAPTION>
               2002      2001     2000
              -------  --------  -------
<S>           <C>      <C>       <C>
Development   $10,977  $ 13,649  $ 5,869
Exploration    20,737    15,115    8,693
Acquisitions      717    80,394    4,160
              -------  --------  -------
    Total     $32,431  $109,158  $18,722
              =======  ========  =======
</TABLE>

ACQUISITIONS
------------

     During  the  year  ended  June  30,  2002,  the  Company made the following
significant  acquisitions:

  -  On  July  6,  2001, the Company paid $18.1 million for interests in various
     oil  and  gas  leases, seismic and technical data, 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. Also during fiscal
     year  2002,  the Company increased its working interest in Texas properties
     to  80% in deep rights and 40% in shallow rights through the acquisition of
     a  net  5,400  acres  for  $0.36  million.

  -  A  deposit of $1.2 million was paid for the purchase of certain oil and gas
     properties located in southern West Virginia. The total acquisition will be
     $6.0  million.  The  purchase  includes  proved  developed  producing  gas
     reserves,  estimated  at  4  Bcf, 90 producing wells and over 30,000 acres.
     This  acquisition  is  subject  to  the  approval  of  the  Public  Service
     Commission  of  West  Virginia.

  -  The  Company  purchased an interest in Alliance Energy Services Partnership
     for  $2.8  million.  The Company anticipates future expenditures related to
     this  investment. The investment is accounted for under the cost method, as
     the  Company  does  not  have  significant  influence  over  management and
     operation  of the partnership. The partnership provides energy solutions to
     customers.


                                       20
<PAGE>
LIQUIDITY  AND  CAPITAL  RESOURCES
----------------------------------

     The  Company's  financial  condition  has  declined  since  June  30, 2001.
Stockholders'  equity has decreased from $64.8 million at June 30, 2001 to $37.1
million  at  June  30,  2002. The Company's working capital decreased from $53.0
million  at  June  30, 2001 to $1.8 million at June 30, 2002. The Company's cash
decreased from $80.3 million at June 30, 2001 to $17.8 million at June 30, 2002.
The  Company's  cash  at  September  25,  2002  was  $18.2 million. In addition,
earnings  from  continuing  operations  before  interest  charges,  taxes,
depreciation,  depletion  and  amortization and impairment and exploratory costs
("EBITDAX")  decreased  from $33.7 million in the twelve month period ended June
30,  2001,  to $19.7 million in the twelve month period ended June 30, 2002. The
decrease  in  cash  during the year was a result of the net use of approximately
$62.5  million  of cash for various operating and capital expenditure activities
of  the  Company. The activities were primarily comprised of: the net investment
of  approximately  $37.6  million  in property, plant and equipment; payments of
approximately  $2.8 million for the acquisition of treasury stock and dividends;
and  the  use  of  approximately  $22.1 million of cash by operations during the
year.  The $22.1 million use of cash by operations during the year was primarily
due  to  the payment of $18.1 million in July 2001 for the Company's acquisition
of  certain  oil  and gas interests in Texas, which had been accrued at June 30,
2001.  (See  Note  3  of  Notes  to  Consolidated  Financial  Statements.)

     On  June  21,  2002  Moody's  Investors  Service ("Moody's") downgraded the
Company's  debt rating. With a negative outlook, Moody's downgraded to Caa3 from
Caa1  the  Company's  9.5% Senior Subordinated Notes ("Notes") due 2007. Moody's
stated  that;  "Further ratings actions are possible upon review of ECA's fiscal
year-end  June 30, 2002 reserve replacements after a year of heavy reinvestment,
funded with cash-on-hand, and depending on whether ECA incurs additional secured
debt  to  fund  its drilling program." Moody's also stated that; "The downgrades
reflect insufficient cash flow to cover interest expense and reserve replacement
capital  expenditures;  asset coverage that is below the par value of the bonds;
and declining production in spite of heavy FYE 2001 and FYE 2002 reinvestment in
reserve  acquisitions  and  development  and  exploration  drilling." This could
negatively  impact  the  Company's  ability  to  raise  capital in the future or
increase the cost of such capital. The Company's total proved reserves decreased
by  9.5%  in  the fiscal year ended June 30, 2002. At July 1, 2002, total proved
reserves were 201,050 Mmcfe compared to total proved reserves at July 1, 2001 of
222,254  Mmcfe.

     At  June 30, 2002, the Company's principal source of liquidity consisted of
$17.8  million  of cash, plus $2 million available under an unsecured short-term
credit  facility  currently  in  place.  At  June  30,  2002,  no  amounts  were
outstanding  or  committed  under  the  short-term  credit  facility.

     On  July  10, 2002, the Company entered into a $50 million revolving Credit
Agreement  (the  "Agreement")  with  Foothill  Capital Corporation ("Foothill").
Depending on its level of borrowing under the Agreement, the applicable interest
rates  are  based on Wells Fargo's prime rate plus 0.50% to 2.50%. The Agreement
expires  on  July  10,  2005.

     The  Agreement  is  secured  by  approximately  80%  of the existing proved
producing  oil and gas assets of the Company. The Agreement, among other things,
restricts  the  ability  of  the Company and its subsidiaries to incur new debt,
grant  additional security interests in its collateral, engage in certain merger
or  reorganization activities, or dispose of certain assets. Upon the occurrence
of  an event of default, the lenders may terminate the Agreement and declare all
obligations  thereunder  immediately  due and payable. As of September 25, 2002,
there  are  $10 million in outstanding borrowings under the Agreement. Under the
Indenture  for  the  Company's  Notes,  the Company is restricted from incurring
additional  debt  in  excess  of  the  $50 million available under the Agreement
unless  the  Company's fixed charge coverage ratio, as defined in the Indenture,
is  at  least  2.5 to 1. Currently, the Company's fixed charge coverage ratio is
less  than  2.5  to  1.


                                       21
<PAGE>
     The  Company's net cash requirements will fluctuate based on timing and the
extent  of  the  interplay of capital expenditures, cash generated by continuing
operations  and interest expense. Management anticipates that EBITDAX for fiscal
year  2003  will approximate $35 million as compared to $19.7 million for fiscal
year  2002;  however,  such  results will not be sufficient to fully fund fiscal
year  2003 projected interest charges of over $20 million and fund the Company's
anticipated  fiscal  year  2003 capital expenditures program of $32 million. The
Company's  ability  to achieve an EBITDAX of $35 million for fiscal year 2003 is
highly  dependant  on  product price and drilling success. The Company budget of
$4.00 per Mmbtu for the price of natural gas and the Company's budget assumption
for  gas  production is approximately 13.8 Bcf, which is an increase of 30% over
production  of  approximately  10.6  Bcf  in  fiscal  year 2002. There can be no
assurance  given  that  the Company will be able to achieve these goals. EBITDAX
for  fiscal  years 2002, 2001 and 2000 was $19.7 million, $33.7 million and $4.1
million,  respectively.  Although cash provided from oil and gas operations will
not  be  sufficient  to  fully  fund  the  Company's  fiscal year 2003 projected
interest charges and capital expenditures program, management believes that cash
generated  from  continuing  oil and gas operations, together with the liquidity
provided by existing cash balances and working capital, permitted borrowings and
the cash proceeds resulting from the sale of certain operating assets as well as
the  divestment  of  certain  non-core  assets,  will  be  sufficient to satisfy
commitments  for capital expenditures, debt service obligations, working capital
needs  and  other  cash  requirements  for  the  next  year.

     In order to reduce future cash interest payments, as well as future amounts
due at maturity or upon redemption, the Company may, from time to time, purchase
its  outstanding  debt  securities  in  open  market  purchases and/or privately
negotiated  transactions.  The  Company  will  evaluate any such transactions in
light  of  then  existing  market conditions, taking into account its liquidity,
uses of capital and prospects for future access to capital. The amounts involved
in  any  such  transaction,  individually  or in the aggregate, may be material.
Recently  the  Company  purchased  certain of the outstanding debt securities in
privately  negotiated  transactions.

     The  Company  believes that its existing capital resources and its expected
fiscal  year 2003 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,  levels  and  availability of
capital  resources  and  continuing  liquidity  are  dependent on future weather
patterns,  oil  and  gas  commodity  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. See Item 3 "Legal Proceedings"
for  a  discussion  related  to  the Company's receipt of Notice of Default from
certain  holders  of  the  Notes.

     In addition to the revolving credit facility and Notes discussed above, the
Company  had  various other obligations. The following table lists the Company's
contractual  obligations  at  June  30,  2002  (in  thousands):

<TABLE>
<CAPTION>
                                      2003      2004     2005   Thereafter    Total
                                    --------  --------  ------  -----------  --------
<S>                                 <C>       <C>       <C>     <C>          <C>
Senior subordinated notes                                       $   197,672  $197,672
Installment notes payable                213       213     213        1,006     1,645
Operating leases                       1,277     1,103     909          146     3,435
                                    --------  --------  ------  -----------  --------
Total contractual cash obligations  $  1,490  $  1,316  $1,122  $   198,824  $202,752
                                    ========  ========  ======  ===========  ========
</TABLE>


                                       22
<PAGE>
RECENT  ACCOUNTING  PRONOUNCEMENTS
----------------------------------

     In  June  2001,  the  Financial  Accounting Standards Board ("FASB") issued
Statement  of  Financial  Accounting  Standard  ("SFAS")  No.  141,  "Business
Combinations."  SFAS  No.  141  is  intended  to improve the transparency of the
accounting  and  reporting  for  business  combinations  by  requiring  that all
business combinations be accounted for under the purchase method.  The statement
also  establishes  criteria  to  assess  when  to  recognize  intangible  assets
separately  from  goodwill.  This  statement  is  effective  for  all  business
combinations  initiated  after  June 30, 2001.  At this time, the Company has no
pending  business  combinations  that  would be affected by the adoption of this
statement.

     In  June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets."  This  statement  addresses  the  accounting  for  goodwill  and  other
intangible  assets and provides specific guidance for testing goodwill and other
intangible  assets  for  impairment.  Under  this statement, goodwill as well as
other  intangibles  determined  to  have  an  infinite  life  will  no longer be
amortized. These assets are required to be reviewed for impairment on a periodic
basis. This statement is effective for the Company July 1, 2002. Management does
not  believe  the  adoption of this statement will have a material effect on the
Company's  financial  position  or  results  of  operations.

     In  June  2001,  the  FASB  issued  SFAS  No.  143,  "Accounting  for Asset
Retirement  Obligations."  SFAS No. 143 provides the accounting requirements for
retirement  obligations  associated  with  long-lived  assets.  The  statement
requires  companies  to  recognize  the  fair  value  of  an  asset's retirement
liability  in  the financial statements by capitalizing that cost as part of the
cost  of  the  related  long-lived  asset,  which  will  then  be systematically
allocated  to expense.  The statement is effective for the Company July 1, 2002.
As  a  preponderance  of  the  Company's wells are within the Appalachian Basin,
which  are  historically  long-lived,  disposal  costs  have  been  negligible.
Therefore,  management does not believe the adoption of this statement will have
a  material effect on the Company's financial position or results of operations.

     In  August  2001,  the  FASB  issued  SFAS  No.  144,  "Accounting  for the
Impairment  or  Disposal of Long-Lived Assets." This statement provides a single
accounting  model  for  long-lived  assets  to  be  disposed  of and changes the
criteria  that  would  have to be met to classify an asset as held-for-sale. The
statement  also  requires  expected  future  operating  losses from discontinued
operations to be recognized in the periods in which the losses are incurred. The
statement is effective for the Company July 1, 2002. Management does not believe
the  adoption  of  this  statement  will have a material effect on the Company's
financial  position  or  results  of  operations.

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No.  4,  44,  and  64,  Amendment  of  FASB  Statement  No.  13  and  Technical
Corrections."  One  of the statement's requirements is to classify the resulting
gain  or  loss  from  early  debt  retirement  as ordinary income.  Although the
statement is effective in fiscal years beginning after May 15, 2002, the Company
has  elected early adoption.  Therefore, the gain on the early extinguishment of
debt  during  fiscal  2001  has  been  reclassified  from extraordinary to other
non-operating  income.  The  adoption of the statement did not have a net effect
on  the  Company's  financial  position  or  results  of  operations.

     In  June  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for Costs
Associated  with Exit or Disposal Activities." The statement addresses financial
accounting  and  reporting for costs associated with exit or disposal activities
as certain costs were recognized as liabilities that did not meet the definition
of  a liability. This statement is effective for all exit or disposal activities
initiated  after  December 31, 2002. Management does not believe the adoption of
this  statement  will have a material effect on the Company's financial position
or  results  of  operations.


                                       23
<PAGE>
                ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
                -------------------------------------------------
                                ABOUT MARKET RISK
                                -----------------

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

     The  Company's  operations  consist  primarily of exploring for, producing,
aggregating  and  selling  natural  gas  and  oil.  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. 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. See Note 5 to
the  Consolidated  Financial  Statements for additional information. The Company
does  not hold or issue derivative instruments for trading purposes. The Company
has elected to enter into swap transactions, covering approximately 19.5% of its
natural  gas  production  through  June  2004.

     Notwithstanding the above, the Company's future cash flows from gas and oil
production  are  exposed  to  significant volatility as commodity prices change.
Assuming  total  oil  and  gas  production  and the percentage of gas production
hedged  under  physical  delivery  contracts  remain  at June 2002 levels, a 10%
change  in the average unhedged prices realized during the year would change the
Company's gas and oil revenues by approximately $2.3 million on an annual basis.

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.  As  of  June  30,  2002, all of the Company's debt has fixed
interest  rates.  There  is inherent rollover risk for borrowings as they mature
and  are  renewed  at  current  market  rates.  The  extent  of this risk is not
predictable  because  of  the  variability  of  future  interest  rates  and the
Company's  future  financing  needs.  The Company has not attempted to hedge the
interest  rate  risk  associated  with  its  debt.

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

     Some  of the Company's transactions are denominated in New Zealand 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.

                                   * * * * *


                                       24
<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, 2002 and 2001, 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, 2002.  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, 2002 and 2001, and the results of their operations
and  their  cash  flows for each of the three years in the period ended June 30,
2002  in  conformity with accounting principles generally accepted in the United
States  of  America.



DELOITTE  &  TOUCHE  LLP
Denver,  Colorado
September 20, 2002


                                       25
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------

ASSETS                                            2002       2001
                                                ---------  ---------
CURRENT ASSETS:
<S>                                             <C>        <C>
   Cash and cash equivalents                    $ 17,775   $ 80,336
                                                ---------  ---------
   Accounts receivable:
     Gas marketing and pipeline                    5,323      8,056
     Oil and gas sales                             7,284      7,525
     Other                                         6,924      8,264
                                                ---------  ---------
                                                  19,531     23,845
     Less allowance for doubtful accounts         (1,366)      (457)
                                                ---------  ---------
                                                  18,165     23,388

   Gas in storage, at lower of cost or market        199      1,069
   Income taxes receivable                         1,596          -
   Deferred income tax asset                       2,237      7,467
   Derivatives                                       454      4,391
   Prepaid and other current assets                4,035      1,978
                                                ---------  ---------
         Total current assets                     44,461    118,629

NET PROPERTY, PLANT AND EQUIPMENT (Note 2)       244,155    248,659
                                                ---------  ---------

OTHER ASSETS:
   Deferred financing costs, less accumulated
     amortization of $3,722 and $2,987             3,617      4,353
   Notes receivable - related parties              1,756      1,867
   Other                                          10,747      7,024
                                                ---------  ---------
         Total other assets                       16,120     13,244
                                                ---------  ---------

TOTAL                                           $304,736   $380,532
                                                =========  =========
<FN>
See notes to consolidated financial statements.            (Continued)
</TABLE>


                                       26
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------

LIABILITIES AND STOCKHOLDERS' EQUITY                          2002       2001
                                                            ---------  ---------
<S>                                                         <C>        <C>
CURRENT LIABILITIES:
  Accounts payable and accrued expenses                     $ 15,683   $ 18,979
  Current portion of long-term debt                              121        151
  Funds held for future distribution                          11,414     14,666
  Income taxes payable                                             -        470
  Accrued taxes, other than income                             8,221      7,860
  Deferred income tax liability                                  180          -
  Other current liabilities                                    7,078     23,462
                                                            ---------  ---------
        Total current liabilities                             42,697     65,588
LONG-TERM OBLIGATIONS:
  Long-term debt                                             198,701    198,902
  Gas delivery obligation and deferred trust revenue           5,886     11,321
  Deferred income tax liability                                9,887     29,888
  Other long-term obligations                                  8,689     10,007
  Minority interest                                            1,732          -
                                                            ---------  ---------
        Total liabilities                                    267,592    315,706
                                                            ---------  ---------

COMMITMENTS AND CONTINGENCIES (Note 14)

STOCKHOLDERS' EQUITY:
  Common stock, par value $1.00; 2,000 shares authorized;
    730 shares issued                                            730        730
  Class A non-voting common stock, no par value; 100
    shares authorized; 46 and 36 shares issued                 5,092      3,732
  Additional paid-in capital                                   5,503      5,503
  Retained earnings                                           36,422     63,653
  Treasury stock and notes receivable arising from
    issuance of common stock                                 (10,426)    (9,293)
  Accumulated other comprehensive income (loss)                 (177)       501
                                                            ---------  ---------
        Total stockholders' equity                            37,144     64,826
                                                            ---------  ---------
TOTAL                                                       $304,736   $380,532
                                                            =========  =========
</TABLE>

See notes to consolidated financial statements.


                                       27
<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)
-----------------------------------------------------------------------------------------------------------

                                                                              2002       2001       2000
                                                                            ---------  ---------  ---------
<S>                                                                         <C>        <C>        <C>
REVENUES:
  Oil and gas sales                                                         $ 38,939   $ 41,555   $ 23,869
  Gas marketing and pipeline sales                                            41,209     81,042     72,156
  Well operations and service revenues                                         5,490      5,899      5,894
  Other                                                                          504      1,455          -
                                                                            ---------  ---------  ---------
                                                                              86,142    129,951    101,919
                                                                            ---------  ---------  ---------
COSTS AND EXPENSES:
  Field operating expenses                                                    10,916      8,910      8,143
  Gas marketing and pipeline cost of sales                                    37,489     77,167     70,101
  Purchase commitment costs                                                        -          -      4,945
  General and administrative                                                  17,360     12,804     13,647
  Taxes, other than income                                                     2,175      3,389      1,492
  Depletion and depreciation of oil and gas properties                        12,362      9,290      8,847
  Depreciation of pipelines, other property and equipment                      2,934      2,763      2,892
  Exploration and impairment                                                  27,694     19,014      8,347
                                                                            ---------  ---------  ---------
                                                                             110,930    133,337    118,414
                                                                            ---------  ---------  ---------
        Loss from operations                                                 (24,788)    (3,386)   (16,495)
                                                                            ---------  ---------  ---------
OTHER (INCOME) AND EXPENSE:
  Interest expense                                                            19,671     20,094     22,302
  Gain on sale of assets                                                        (319)      (211)      (101)
  Interest income and other                                                   (1,135)    (5,838)      (377)
                                                                            ---------  ---------  ---------
                                                                              18,217     14,045     21,824
                                                                            ---------  ---------  ---------
Loss from continuing operations before income taxes and minority interest    (43,005)   (17,431)   (38,319)
Benefit for income taxes                                                     (16,822)    (7,232)   (11,811)
                                                                            ---------  ---------  ---------
Loss from continuing operations before minority interest                     (26,183)   (10,199)   (26,508)
Minority interest                                                                 (3)         -          -
                                                                            ---------  ---------  ---------
Loss from continuing operations                                              (26,180)   (10,199)   (26,508)
  Disposal of utility operations:
    Income (loss) from utility operations, net of tax                              -     (1,847)     8,077
    Gain on sale of utility, net of tax                                            -     84,402          -
                                                                            ---------  ---------  ---------
    Net income from disposal of utility operations                                 -     82,555      8,077
                                                                            ---------  ---------  ---------

NET INCOME (LOSS)                                                           $(26,180)  $ 72,356   $(18,431)
                                                                            =========  =========  =========

Earnings (loss) per common share, basic and diluted
   Loss from continuing operations                                          $ (39.80)  $ (15.34)  $ (40.11)
   Discontinued operations                                                         -     124.20      12.22
                                                                            ---------  ---------  ---------
   Earnings (loss) per common share                                         $ (39.80)  $ 108.86   $ (27.89)
                                                                            =========  =========  =========
</TABLE>

See notes to consolidated financial statements.


                                       28
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
--------------------------------------------------------------------------------------------------------------------
                                                   Class A    Additional    Retained                Notes Received/
                                          Common    Common     Paid-In      Earnings    Treasury      Issuance of
                                          Stock     Stock      Capital     (Deficit)     Stock           Stock
                                         --------  --------  ------------  ----------  ----------  -----------------
<S>                                      <C>       <C>       <C>           <C>         <C>         <C>
Balance, June 30, 1999                   $   721   $  2,940  $     4,656   $  13,598   $  (5,896)  $         (1,365)
  Comprehensive loss                                                         (18,388)
  Common stock issued for services             2                     146
  Redemption of common stock and
  related note receivable                     (5)                   (187)                                       192
  Purchase of treasury stock - common                                                       (223)
  Purchase of treasury stock - Class A                                                      (165)
  Reduction of notes receivable                                                                                  28
                                         --------  --------  ------------  ----------  ----------  -----------------
Balance June, 30, 2000                       718      2,940        4,615      (4,790)     (6,284)            (1,145)
  Comprehensive income                                                        72,991
  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                                                                                  56
                                         --------  --------  ------------  ----------  ----------  -----------------
Balance, June 30, 2001                       730      3,732        5,503      64,331      (8,204)            (1,089)
  Comprehensive loss                                                         (26,858)
  Dividends ($1.60 per share)                                                 (1,051)
  Class A stock issued for services                   1,360
  Purchase of treasury stock - common                                                     (1,262)
  Purchase of treasury stock - Class A                                                      (571)
  Reduction of notes receivable                                                                                 700
                                         --------  --------  ------------  ----------  ----------  -----------------
Balance, June 30, 2002                   $   730   $  5,092  $     5,503   $  36,422   $ (10,037)  $           (389)
                                         ========  ========  ============  ==========  ==========  =================


                                          Accum. Other
                                          Comprehensive    Stockholders'
                                          Income (Loss)       Equity
                                         ---------------  ---------------
<S>                                      <C>              <C>
Balance, June 30, 1999                   $         (177)  $       14,477
  Comprehensive loss                                             (18,388)
  Common stock issued for services                                   148
  Redemption of common stock and
  related note receivable                                              -
  Purchase of treasury stock - common                               (223)
  Purchase of treasury stock - Class A                              (165)
  Reduction of notes receivable                                       28
                                         ---------------  ---------------
Balance June, 30, 2000                             (177)          (4,123)
  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
                                         ---------------  ---------------
Balance, June 30, 2001                             (177)          64,826
  Comprehensive loss                                             (26,858)
  Dividends ($1.60 per share)                                     (1,051)
  Class A stock issued for services                                1,360
  Purchase of treasury stock - common                             (1,262)
  Purchase of treasury stock - Class A                              (571)
  Reduction of notes receivable                                      700
                                         ---------------  ---------------
Balance, June 30, 2002                   $         (177)  $       37,144
                                         ===============  ===============
</TABLE>

See notes to consolidated financial statements.


                                       29
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------------------------------------------

                                                                                      2002        2001       2000
                                                                                    ---------  ----------  ---------
<S>                                                                                 <C>        <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss from continuing operations                                                 $(26,180)  $ (10,199)  $(26,508)
  Adjustments to reconcile net loss to net cash provided (used) by
    operating activities:
       Depletion, depreciation and amortization                                       16,031      12,911     12,538
       Gain on sale of assets                                                           (319)       (211)      (101)
       Deferred income taxes                                                         (12,492)     28,359    (11,099)
       Exploration and impairment                                                     27,227      18,591      5,979
       Other, net                                                                      2,322      (4,711)     4,413
                                                                                    ---------  ----------  ---------
                                                                                       6,589      44,740    (14,778)
Changes in assets and liabilities:
    Accounts receivable                                                                3,187      (2,936)       420
    Gas in storage                                                                       870        (304)      (408)
    Income taxes receivable                                                           (2,066)    (33,821)     1,079
    Prepaid and other assets                                                          (1,900)        (32)       163
    Accounts payable                                                                  (2,218)      6,341        (42)
    Funds held for future distributions                                               (3,253)      1,678        902
    Other                                                                            (23,405)     14,631      7,670
                                                                                    ---------  ----------  ---------
       Net cash provided (used) by operating activities from continuing operations   (22,196)     30,297     (4,994)
       Net cash provided (used) by operating activities from disposed operations           -     (48,335)     7,286
                                                                                    ---------  ----------  ---------
       Net cash provided (used) by operating activities                              (22,196)    (18,038)     2,292
                                                                                    ---------  ----------  ---------
CASH FLOWS FROM INVESTING ACTIVITIES
    Expenditures for property, plant and equipment                                   (38,294)   (112,863)   (19,299)
    Proceeds from sale of assets                                                         704       1,517        428
    Notes receivable and other                                                            86      (4,192)      (300)
                                                                                    ---------  ----------  ---------
       Net cash used by investing activities from continuing operations              (37,504)   (115,538)   (19,171)
       Net cash provided (used) by investing activities from disposed operations           -     224,765    (23,842)
                                                                                    ---------  ----------  ---------
       Net cash provided (used) by investing activities                              (37,504)    109,227    (43,013)
                                                                                    ---------  ----------  ---------
CASH FLOWS FROM FINANCING ACTIVITIES
    Proceeds from long-term debt                                                           -       7,825     16,250
    Principal payment on long-term debt                                                 (145)    (21,850)   (29,094)
    Proceeds (payment) on short-term borrowing                                             -      (2,000)     2,000
    Purchase of treasury stock and other financing activities                         (1,663)     (1,072)      (214)
    Prepayment of future gas delivery                                                      -           -     10,000
    Dividends paid                                                                    (1,053)     (3,605)         -
                                                                                    ---------  ----------  ---------
       Net cash used by financing activities from continuing operations               (2,861)    (20,702)    (1,058)
       Net cash provided by financing activities from disposed operations                  -       6,539     32,926
                                                                                    ---------  ----------  ---------
       Net cash provided (used) by financing activities                               (2,861)    (14,163)    31,868
                                                                                    ---------  ----------  ---------
       Net increase (decrease) in cash and cash equivalents                          (62,561)     77,026     (8,853)
       Cash and cash equivalents, beginning of period                                 80,336       3,310     12,163
                                                                                    ---------  ----------  ---------
Cash and cash equivalents, end of period                                            $ 17,775   $  80,336   $  3,310
                                                                                    =========  ==========  =========
</TABLE>

See notes to consolidated financial statements.


                                       30
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
-------------------------------------------------------------------------------

                                                   2002       2001      2000
                                                 ---------  --------  ---------
<S>                                              <C>        <C>       <C>
Net income (loss)                                $(26,180)  $72,356   $(18,431)
                                                 ---------  --------  ---------
Other comprehensive income (loss), net of tax:
    Foreign currency translation adjustment:
       Current period change                        1,627    (1,980)        43
    Marketable securities:
       Unrealized gain (loss)                        (106)      136
    Oil and gas derivatives:
       Net cumulative effect adjustment                      (2,153)
       Current period transactions                  1,999      (541)
       Reclassification to earnings                (4,198)    5,173          -
                                                 ---------  --------  ---------
Other comprehensive income (loss), net of tax        (678)      635         43
                                                 ---------  --------  ---------
Comprehensive income (loss)                      $(26,858)  $72,991   $(18,388)
                                                 =========  ========  =========
</TABLE>

See notes to consolidated financial statements.


                                       31
<PAGE>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES

NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2002, 2001 AND 2000
--------------------------------------------------------------------------------

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  Texas,  California  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. Investments in affiliates in which the Company owns greater
     than  50%  are consolidated. Investments in which the Company owns from 20%
     to  50%  are  accounted  for  by  the  equity method if the Company has the
     ability  to  exert  significant influence over the investee. Investments in
     less than 20% owned affiliates and affiliates in which the Company does not
     exhibit  significant influence are accounted for under the cost method. 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  material 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  in  income.


                                       32
<PAGE>
     Other  property,  equipment, pipelines and buildings are stated at cost and
     are  depreciated using straight-line and accelerated methods over estimated
     useful  lives  ranging  from  three  to  40  years.

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

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

<TABLE>
<CAPTION>
                                                              2002        2001
                                                           ----------  ----------
<S>                                                        <C>         <C>
Oil and gas properties                                     $ 320,148   $ 317,225
Pipelines                                                     20,703      19,569
Other property and equipment                                  19,598      14,088
                                                           ----------  ----------
                                                             360,449     350,882
Less accumulated depletion, depreciation and amortization   (116,294)   (102,223)
                                                           ----------  ----------
Net property, plant and equipment                          $ 244,155   $ 248,659
                                                           ==========  ==========
</TABLE>

     Long-Lived  Assets  -  Statement of Financial Accounting Standards ("SFAS")
     ------------------
     No.  121,  "Accounting  for  the  Impairment  of  Long-Lived Assets and for
     Long-Lived  Assets  to  be  Disposed  Of", requires all companies to assess
     long-lived assets and assets to be disposed of for impairment. For the year
     ended  June  30,  2002,  the  Company  recognized impairment of oil and gas
     property  of  approximately  $19.3 million, and $0.1 million related to its
     natural gas fueling operations. 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.

     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  accounts using current
     exchange  rates  in  effect  at  the  balance  sheet  date.  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". A valuation allowance is established for any
     portion of a deferred tax asset for which it is more likely than not that a
     tax  benefit  will  not  be  realized.

     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 and pipeline
     -------------------------
     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.


                                       33
<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.

     Derivatives  -  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  monthly  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.

     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, 2002,
     the  Company  has not been fined or cited for any environmental violations,
     which  would  have  a  material  adverse  effect upon capital expenditures,
     operating  results  or  the  competitive  position  of  the  Company.

     Recent  Accounting  Pronouncements - In June 2001, the Financial Accounting
     ----------------------------------
     Standards  Board ("FASB") issued Statement of Financial Accounting Standard
     ("SFAS")  No.  141,  "Business  Combinations."  SFAS No. 141 is intended to
     improve  the  transparency  of  the  accounting  and reporting for business
     combinations  by  requiring that all business combinations be accounted for
     under  the  purchase  method.  The  statement  also establishes criteria to
     assess  when  to recognize intangible assets separately from goodwill. This
     statement  is  effective for all business combinations initiated after June
     30,  2001.  At  this time, the Company has no pending business combinations
     that  would  be  affected  by  the  adoption  of  this  statement.

     In  June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
     Assets."  This  statement  addresses  the accounting for goodwill and other
     intangible  assets  and provides specific guidance for testing goodwill and
     other  intangible  assets for impairment. Under this statement, goodwill as
     well  as  other  intangibles  determined  to  have an infinite life will no
     longer  be  amortized.  These  assets  are  required  to  be  reviewed  for
     impairment on a periodic basis. This statement is effective for the Company
     July  1,  2002.  Management does not believe the adoption of this statement
     will  have a material effect on the Company's financial position or results
     of  operations.


                                       34
<PAGE>
     In  June  2001,  the  FASB  issued  SFAS  No.  143,  "Accounting  for Asset
     Retirement  Obligations." SFAS No. 143 provides the accounting requirements
     for retirement obligations associated with long-lived assets. The statement
     requires  companies  to  recognize  the fair value of an asset's retirement
     liability  in the financial statements by capitalizing that cost as part of
     the cost of the related long-lived asset, which will then be systematically
     allocated  to  expense.  The statement is effective for the Company July 1,
     2002.  As a preponderance of the Company's wells are within the Appalachian
     Basin,  which  are  historically  long-lived,  disposal  costs  have  been
     negligible.  Therefore,  management  does  not believe the adoption of this
     statement  will  have a material effect on the Company's financial position
     or  results  of  operations.

     In  August  2001,  the  FASB  issued  SFAS  No.  144,  "Accounting  for the
     Impairment  or  Disposal  of  Long-Lived Assets." This statement provides a
     single accounting model for long-lived assets to be disposed of and changes
     the  criteria  that  would  have  to  be  met  to  classify  an  asset  as
     held-for-sale. The statement also requires expected future operating losses
     from  discontinued  operations to be recognized in the periods in which the
     losses  are  incurred.  The  statement is effective for the Company July 1,
     2002.  Management does not believe the adoption of this statement will have
     a  material  effect  on  the  Company's  financial  position  or results of
     operations.

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
     No.  4,  44,  and  64,  Amendment  of  FASB  Statement No. 13 and Technical
     Corrections."  One  of  the  statement's  requirements  is  to classify the
     resulting  gain  or  loss  from  early  debt retirement as ordinary income.
     Although the statement is effective in fiscal years beginning after May 15,
     2002,  the  Company  has elected early adoption. Therefore, the gain on the
     early  extinguishment of debt during fiscal 2001 has been reclassified from
     extraordinary  to other non-operating income. The adoption of the statement
     did not have a net effect on the Company's financial position or results of
     operations.

     In  June  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for Costs
     Associated  with  Exit  or  Disposal  Activities."  The statement addresses
     financial  accounting  and  reporting  for  costs  associated  with exit or
     disposal  activities  as  certain costs were recognized as liabilities that
     did not meet the definition of a liability. This statement is effective for
     all  exit  or  disposal  activities  initiated  after  December  31,  2002.
     Management  does  not  believe  the  adoption of this statement will have a
     material  effect  on  the  Company's  financial  position  or  results  of
     operations.

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

<TABLE>
<CAPTION>
                                                2002     2001     2000
                                               -------  -------  -------
<S>                                            <C>      <C>      <C>
Cash paid for:
   Interest                                    $18,935  $19,210  $21,360
   Income taxes, net                               114   37,983      242
Noncash investing and financing activities:
   Dividends declared and unpaid at year end       262      265        -
   Liabilities assumed in acquisition                -      824        -
</TABLE>


                                       35
<PAGE>
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 interests in various
     oil  and  gas  leases, seismic and technical data, 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. Also during fiscal
     year  2002,  the Company increased its working interest in Texas properties
     to  80% in deep rights and 40% in shallow rights through the acquisition of
     a  net  5,400  acres  for  $0.36  million.

     A  deposit of $1.2 million was paid for the purchase of certain oil and gas
     properties located in southern West Virginia. The total acquisition will be
     $6.0  million.  The  purchase  includes  proved  developed  producing  gas
     reserves,  estimated  at  4  Bcf, 90 producing wells and over 30,000 acres.
     This  acquisition  is  subject  to  the  approval  of  the  Public  Service
     Commission  of West Virginia.

     The  Company  purchased an interest in Alliance Energy Services Partnership
     for  $2.8  million.  The Company anticipates future expenditures related to
     this  investment. The investment is accounted for under the cost method, as
     the  Company  does  not  have  significant  influence  over  management and
     operation  of the partnership. The partnership provides energy solutions to
     customers.

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 were 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>
                                             2002   2001 (1)     2000
                                             -----  ---------  --------
<S>                                          <C>    <C>        <C>
Net sales                                    $   -  $  9,929   $178,882
                                             -----  ---------  --------
Income (loss) before income taxes                -    (3,164)    11,048
Income taxes provision (benefit)                 -    (1,317)     3,691
                                             -----  ---------  --------
Income (loss) from discontinued operations   $   -  $ (1,847)  $  7,357
                                             =====  =========  ========
<FN>
 (1)  Discontinued operations for one and one half months in fiscal year 2001
</TABLE>


5.   RISK  MANAGEMENT

     The  Company  periodically  hedges  a portion of its oil and gas production
     through futures and swap agreements. The purpose of the hedge is to provide
     a  measure  of  stability in the volatile environment of oil and gas prices
     and  to  manage  its  exposure to commodity price risk under existing sales
     commitments.  All  of  the Company's price swap agreements in place at June
     30,  2002 are designated as cash flow hedges. At June 30, 2001, the Company
     had  swap agreements maturing from July 2001 through December 2002 covering


                                       36
<PAGE>
     4,455,700  Mmbtu.  At June 30, 2001 the company had recorded a $2.5 million
     gain  in accumulated other comprehensive income, $4.4 million of short term
     derivative  assets,  $0.3  million  short term derivative liabilities, $0.1
     million  long  term  derivative  liability and $1.5 million in deferred tax
     liability.  At June 30, 2002, the Company had swap agreements maturing from
     July  2002  through June 2004 covering 2,292,200 Mmbtu. As of June 30, 2002
     the  Company  has  recorded  a  $0.3  million  gain  in  accumulated  other
     comprehensive  income,  $0.4  million  in short term derivative asset, $0.1
     million  in  long term derivative asset, $0.1 million short term derivative
     liability,  and  $0.1  million  in  deferred  tax  liability.

     For  the  year  ended  June  30,  2002 the Company recognized a net gain in
     revenues  on  its  natural  gas hedging activities of $6.7 million. For the
     years  ended  June  30, 2001 and 2000, the Company recognized a net loss in
     revenues  on  its  natural  gas hedging activities of $8.3 million and $0.9
     million,  respectively.  The  estimated  net  amount  of the existing gains
     within other comprehensive income that are expected to be reclassified into
     earnings  within  the  next  12  months  is  approximately  $0.3  million.

6.   DEBT

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

<TABLE>
<CAPTION>
                                                                      2002       2001
                                                                    ---------  ---------
<S>                                                                 <C>        <C>
ECA senior subordinated notes, interest at 9.5% payable
   semi-annually, due May 15, 2007                                  $197,672   $197,672
Installment notes payable, at imputed interest rates ranging from
   from 8.0% to 9.5%                                                   1,150      1,381
                                                                    ---------  ---------
                                                                     198,822    199,053
Less current portion                                                    (121)      (151)
                                                                    ---------  ---------
                                                                    $198,701   $198,902
                                                                    =========  =========
</TABLE>

     The  Company's  debt agreement contains certain restrictions and conditions
     among which are limitations on indebtedness, dividends and investments, and
     certain  interest  coverage  ratio requirements. The agreement requires the
     Company  to  maintain certain financial covenants, including 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, 2002 for
     each  of  the next five years and thereafter are as follows (in thousands):

<TABLE>
<CAPTION>
<S>                                    <C>
2003                                   $    213
2004                                        213
2005                                        213
2006                                        213
2007                                    197,781
Thereafter                                  684
                                       --------
Total payments                          199,317
Less:  imputed interest                     495
                                       --------
Present value of scheduled maturities  $198,822
                                       ========
</TABLE>


                                       37
<PAGE>
     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  a  gain  of  $0.56  million.

     Revolving Credit - On July 10, 2002, the Company entered into a $50 million
     ----------------
     revolving  Credit  Agreement  (the  "Agreement")  with  Foothill  Capital
     Corporation  ("Foothill").  Depending  on  its level of borrowing under the
     Agreement,  the  applicable interest rates are based on Wells Fargo's prime
     rate  plus  0.50%  to  2.50%.  The  Agreement expires on July 10, 2005. The
     Agreement  is  secured  by  approximately  80%  of the existing oil and gas
     assets  of  the  Company.  The Agreement, among other things, restricts the
     ability  of  the  Company  and  its  subsidiaries  to incur new debt, grant
     additional  security  interests in its collateral, engage in certain merger
     or  reorganization  activities,  or  dispose  of  certain  assets. Upon the
     occurrence  of an event of default, the lenders may terminate the Agreement
     and  declare  all obligations thereunder immediately due and payable. As of
     September  20,  2002,  there  are  currently  $10  million  in  outstanding
     borrowings  under  the  Agreement.

     Other  Credit  Facilities  - The Company has an unsecured revolving line of
     -------------------------
     credit  totaling  $2  million with a financial institution with an interest
     rate  of  prime  plus  0.5%, which expires November 30, 2002. There were no
     amounts  outstanding  under the line of credit as of June 30, 2002 and 2001
     respectively.

     Other  Notes  - In December 2000, the Company assumed a note as part of the
     ------------
     Penn  Virginia  acquisition.  Per  the  agreement,  the  Company  will  pay
     consecutive  equal  monthly payments with the first scheduled payment to be
     made by the Company on January 15, 2000 and the final scheduled payment due
     on  April  15, 2014. As of June 30, 2002 and 2001, the balance due was $1.2
     million  and  $1.3  respectively.

     The  Company purchased certain pipelines during 1998 constituting a natural
     gas  gathering  system  in the State of West Virginia. The Company will pay
     the  seller  $1.2  million  for  the  facilities.  In  accordance  with the
     agreement, the Company paid $0.3 million at closing with the balance due to
     the  seller in one hundred consecutive equal monthly installments beginning
     in  March 1998. As of June 30, 2002 and 2001, the balance due to the seller
     was  $0.5  and  $0.6  million  respectively.

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>
                                     2002       2001       2000
                                   ---------  ---------  ---------
<S>                                <C>        <C>        <C>
Current:
   Federal                         $ (3,436)  $(27,749)  $   (666)
   State                              1,385     (7,842)       (46)
                                   ---------  ---------  ---------
   Total current                     (2,051)   (35,591)      (712)
                                   ---------  ---------  ---------
Deferred:
   Federal                          (13,381)    23,115    (11,477)
   State                             (1,390)     5,244        378
                                   ---------  ---------  ---------
   Total deferred                   (14,771)    28,359    (11,099)
                                   ---------  ---------  ---------
   Total benefit for income taxes  $(16,822)  $ (7,232)  $(11,811)
                                   =========  =========  =========
</TABLE>

     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):


                                       38
<PAGE>
<TABLE>
<CAPTION>
                                                          2002       2001      2000
                                                        ---------  --------  ---------
<S>                                                     <C>        <C>       <C>
Tax benefit at the federal statutory rate               $(15,051)  $(6,101)  $(13,028)
State taxes, net of federal tax effects                   (2,516)   (1,151)    (1,781)
Effect of rate change                                        103      (176)
Section 29 tax credits                                         -    (2,277)
Change in valuation allowance on federal, foreign
  and state deferred tax assets, net of federal effect    (2,048)               2,000
Investment tax credit expiration                                                  532
Other, net                                                 2,690     2,473        466
                                                        ---------  --------  ---------
Benefit for income taxes                                $(16,822)  $(7,232)  $(11,811)
                                                        =========  ========  =========
</TABLE>

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

<TABLE>
<CAPTION>
                                               2002       2001
                                             ---------  ---------
<S>                                          <C>        <C>
  Deferred tax assets:
    Royalty Trust agreements                 $  7,830   $  7,501
    Tax credits and carryforwards              10,113      3,710
    Other                                       3,874      3,238
                                             ---------  ---------
      Total deferred tax assets                21,817     14,449
                                             ---------  ---------
  Deferred tax liabilities:
    Property, plant and equipment             (25,249)   (27,545)
    Federal income tax on state tax credits         -     (1,261)
    Other liabilities                          (4,218)    (4,913)
                                             ---------  ---------
      Total deferred tax liabilities          (29,467)   (33,719)
                                             ---------  ---------
  Valuation allowance                               -     (3,151)
                                             ---------  ---------
  Net deferred income tax liability            (7,650)   (22,421)
  Current deferred tax asset                    2,237      7,467
                                             ---------  ---------
  Net long-term deferred tax liability       $ (9,887)  $(29,888)
                                             =========  =========
</TABLE>

At June 30, 2002 the Company has the following federal and state tax credits and
carryforwards (in thousands):

<TABLE>
<CAPTION>
                                           Year of
                                 Amount   Expiration
                                 -------  ----------
<S>                              <C>      <C>
  AMT tax credits                $ 9,355  None
                                 -------
  Total federal credits          $ 9,355
                                 =======
  Net operating loss carryovers  $   758   2005-2021
                                 -------
  Total state carryovers         $   758
                                 =======
</TABLE>

     At  June  30, 2001, the Company had West Virginia state tax credits of $3.7
     million.  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  were  used  primarily to offset the payment of severance,
     property  and state income taxes. Based on the then existing future taxable
     temporary  differences  and  projections of future West Virginia severance,
     property  and  state  income  taxes,  management  had  provided a valuation
     allowance  of  $3.2  million  for that portion of the credits that were not
     expected  to  be  utilized.  At  June 30, 2002 the Company had utilized the
     entire  $3.7  million  of WV state tax credits and had reversed the related
     $3.2  million  valuation  allowance.


                                       39
<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 $0; $1.3 million and $0.9 million of profit sharing
     expense  during  the  years  ended  June  30,  2002,  2001  and  2000.

     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 $0.39 million, $0.24 million and $0.23 million
     for  the  years  ended  June  30,  2002,  2001,  and  2000.

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  agreements  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, 2002 49,710
     shares  were  subject  to  the agreements. 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, 2002, the Company had 104,984 shares of voting
     --------------
     common stock in treasury, carried at cost. The Company purchased 10,630 and
     16,342  shares  of voting common stock during the years ended June 30, 2002
     and  2001, respectively. At June 30, 2002, the Company had 14,380 shares of
     non-voting  Class  A  stock  in  treasury,  carried  at  cost.  The Company
     purchased  3,993  and  4,160  shares of non-voting Class A stock during the
     years  ended  June  30,  2002  and  2001.

     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:


                                       40
<PAGE>
<TABLE>
<CAPTION>
                                       Number of
 Exercise Period                        Shares
-------------------------------------  ---------
<S>                                    <C>
 January 1, 1999 to December 31, 2003     10,002
 January 1, 2000 to December 31, 2004     10,002
 January 1, 2001 to December 31, 2005      9,996
                                       ---------
                                          30,000
                                       =========
</TABLE>

     No  options  were  exercised for either of the years ended June 30, 2002 or
     2001.  Therefore,  as  of  June 30, 2002, all the options were exercisable.
     Fair  value  of the options at the grant dates, as estimated by management,
     was  nominal.

10.  EARNINGS  PER  SHARE

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

<TABLE>
<CAPTION>
                                  2002       2001      2000
                                ---------  --------  ---------
<S>                             <C>        <C>       <C>
Earnings (loss) (in thousands)  $(26,180)  $(10,199) $(26,508)
Shares                           657,707    664,673   660,928
Per share amount                $ (39.80)  $ (15.34) $ (40.11)
</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):


                                       41
<PAGE>
<TABLE>
<CAPTION>
                                           2002      2001      2000
                                         --------  --------  --------
<S>                                      <C>       <C>       <C>
Current assets                           $ 11,336  $10,744
Oil and gas properties                    100,833   84,050
Other assets                                1,966    3,233
                                         --------  --------
    Total assets                         $114,135  $98,027
                                         ========  ========
Current liabilities                      $ 14,505  $12,955
Long-term debt                             51,700   54,200
Other liabilities                           8,092    1,433
Redeemable preferred shares                34,287   33,650
Members' equity (deficit)                   1,764   (4,211)
Accumulated other comprehensive income      3,787        -
                                         --------  --------
   Total liabilities and equity          $114,135  $98,027
                                         ========  ========
Net sales                                $ 46,160  $36,551   $19,722
Operating income                           14,578    9,338       200
Net income (loss)                        $ 10,259  $ 5,267   $(1,517)
</TABLE>

12.  OPERATING  LEASES

     The  Company has noncancelable operating lease agreements for the rental of
     office  space,  computers  and  other  equipment.  Certain  of these leases
     contain  purchase  options or renewal clauses. Rental expense for operating
     leases  was  approximately  $1.4 million, $1.3 million and $1.2 million for
     the  years  ended  June  30,  2002,  2001  and  2000.

     At  June  30,  2002 future minimum lease payments for each of the next five
     years  and  thereafter  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
<S>         <C>
2003        $1,277
2004         1,103
2005           909
2006            98
2007            16
Thereafter      32
            ------
            $3,435
            ======
</TABLE>


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, $0.56 million and $0.42 million for the years ended
     June  30,  2002,  2001  and  2000.

     The  Company  advanced funds to certain officers and other related parties,
     at  7%  to  8% interest. Balances totaled $0.3 million and $0.6 million, at
     June  30, 2002 and 2001. 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.


                                       42
<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 $0.2 million
     at June 30, 2002 and $0.9 million at June 30, 2001. The notes have interest
     rates  of  6.5% and 8%. A provision in the agreements cancels the principal
     balance if the employee remains in the continuous employment of the Company
     through  December 31, 2005. In addition, between 1995 and 1997, the Company
     issued  19,200  shares of common stock as part of an incentive stock option
     agreement  with  two  officers  for promissory notes. The carrying value of
     these notes was $0.19 million at June 30, 2002 and 2001. 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. The
     remaining  book  value  of  this  asset  at  June 30, 2002 is $1.0 million.

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 is currently classified as other current
     and long-term liabilities. As of June 30, 2000, the Company determined that
     due  to  the  rising  cost  of transporting gas, the total deferred revenue
     would not be realizable. Therefore, $4.9 million, the amount related to the
     royalty  portion,  was impaired and $6.2 million, the amount related to the
     term  portion, was reclassified to other current and long-term liabilities.
     These  amounts  are  amortized  as  the  associated  volumes  are sold. The
     remaining  unamortized other current and long-term liabilities are $9.0 and
     $10.0  million  at  June  30,  2002  and  2001,  respectively.

     The Company has a gas sales contract, which requires the Company to sell up
     to  4,800  but  not less than 3,200 Mmbtu per day beginning January 1, 2002
     through  December  31, 2003. Under the contract the Company receives a 10.5
     cent  to  15.5  cent  premium  above  the  posted  Appalachian  Index.

     The  Company  entered into a gas sale and purchase agreement with Allegheny
     whereby  it  began  the  delivery  of  natural gas on November 1, 2001. The
     Company  received a $10 million prepayment pursuant to the agreement, which
     is  recorded  as  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.

     On November 30, 2001, the Company entered into a natural gas sales contract
     with Mountaineer Gas Company, doing business as Allegheny Power, to deliver
     5,500  Dth per day. Under the pricing terms, the Company will never receive
     less  than  $2.75  per  Dth  plus  the  Columbia  Gas  Transmission ("TCO")
     Appalachia  Basis or more than $4.85 per day plus the TCO Appalachia Basis.
     The  contract  began  on December 1, 2001 and continues through October 31,
     2004.

     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.


                                       43
<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, 2002, the fair value of
     the  Company's  debt  was  $129.6  million  and  the  book value was $198.8
     million.

     Derivative  Financial  Instruments - All derivative instruments held by the
     ----------------------------------
     Company are designated as hedges, have high correlation with the underlying
     exposure and are highly effective in offsetting underlying price movements.
     Accordingly,  gains  and  losses from changes in derivative fair values are
     deferred  until the underlying transaction occurs. Gains or losses are then
     recognized  in  the  income statement or recorded as part of the underlying
     assets  or  liability, depending on the circumstances. Derivative positions
     are  settled  if the underlying transaction is no longer expected to occur,
     with  the  related  gains  and  losses recognized in earnings in the period
     settlement occurs. Option premiums paid are recorded as assets and expensed
     over  the  life  of the option. Derivatives generally have initial terms of
     less  than  three years, and all currently hedged transactions are expected
     to occur within the next three years. See Note 5 for additional information
     regarding  the  Company's  derivative  holdings.

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,  income  taxes,  depreciation,  depletion,
     amortization  and  impairment 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
     drilling  rig  operations  and  corporate  items  (in  thousands):


                                       44
<PAGE>
<TABLE>
<CAPTION>
                                         Exploration    Marketing
                                             and           and
                                         Production     Pipeline     Other     Consolidated
                                        -------------  -----------  --------  --------------
<S>                                     <C>            <C>          <C>       <C>
                2002
Sales to unaffiliated customers         $     44,429   $   41,209   $   504   $      86,142
Depreciation, depletion, amortization         13,741          859       696          15,296
Impairment and exploratory costs              26,127           89     1,478          27,694
Operating profit (loss)                      (22,775)         279    (2,292)        (24,788)
Interest expense, net                         21,238       (6,922)    3,663          17,979
EBITDAX                                       18,795        1,498      (635)         19,658
Total assets                                 186,587       78,226    39,923         304,736
Capital expenditures                          33,679          145     4,470          38,294
--------------------------------------------------------------------------------------------
                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, net                         13,521       (5,355)    4,237          12,403
EBITDAX                                       19,759        1,316    12,656          33,731
Total assets                                 201,111       77,977   101,444         380,532
Capital expenditures                         108,343        1,315     3,205         112,863
--------------------------------------------------------------------------------------------
                2000
Sales to unaffiliated customers         $     29,763   $   72,156             $     101,919
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
--------------------------------------------------------------------------------------------
</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,  including
     drilling  rig, corporate and elimination items. Included in the exploration
     and  production segment are net long-lived assets located in New Zealand of
     $3.4  million, $3.0 million and $3.9 million, as of June 30, 2002, 2001 and
     2000  and  any  related  revenues  and  expenses.

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):


                                       45
<PAGE>
<TABLE>
<CAPTION>
                                                                 Quarter Ended
                                          ----------------------------------------------------
            2002                           September 30    December 31    March 31    June 30
                                          --------------  -------------  ----------  ---------
<S>                                       <C>             <C>            <C>         <C>
Total revenue                             $      23,394   $     21,157   $  18,573   $ 23,018
Gross profit (loss)                               1,943          1,119      (3,585)   (24,265)  *
Loss from continuing operations                  (1,517)        (2,086)     (5,358)   (17,219)
Loss per share on continuing
    operations, basic and diluted                 (2.31)         (3.17)      (8.15)    (26.17)
Net loss                                         (1,517)        (2,086)     (5,358)   (17,219)
                                                               Quarter Ended
                                          ----------------------------------------------------
            2001                          September 30    December 31    March 31    June 30
                                          --------------  -------------  ----------  ---------
Total revenue                             $      27,083   $     31,898   $  45,109   $ 25,861
Gross profit (loss)                               1,473          1,363      (2,386)    (3,836)
Loss from continuing operations                  (1,847)           106      (3,590)    (4,868)
Earnings (loss) per share on continuing
    operations, basic and diluted                 (2.77)          0.19       (5.41)     (7.35)
Net income (loss)                                82,661           (939)     (3,622)    (5,744)
</TABLE>


     *Gross  profit  decreased by $20.7 million from the quarter ended March 31,
     2002  to  the  quarter  ended  June  30,  2002  primarily  as  a  result of
     exploratory  dry  hole  cost and impairment recorded in the fourth quarter.

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>
                                                      2002       2001       2000
                                                    ---------  ---------  ---------
<S>                                                 <C>        <C>        <C>
Capitalized costs:
   Proved properties                                $310,495   $271,465   $208,271
   Unproved properties                                 9,653     45,760     10,988
                                                    ---------  ---------  ---------
   Total                                             320,148    317,225    219,259
   Less accumulated depletion and depreciation       (97,523)   (85,748)   (76,458)
                                                    ---------  ---------  ---------
Net capitalized costs                               $222,625   $231,477   $142,801
                                                    =========  =========  =========

Company's share of equity method investee's net
   capitalized costs (see Note 11)                  $ 25,185   $ 19,690   $ 18,693
                                                    =========  =========  =========

Costs incurred:
   Acquisition of proved and unproved properties    $    717   $ 80,394   $  4,160
   Development costs                                  10,977     13,649      5,869
   Exploration costs                                  20,737     15,115      8,693
                                                    ---------  ---------  ---------
Total costs incurred                                $ 32,431   $109,158   $ 18,722
                                                    =========  =========  =========

Company's share of equity method investee's total
   costs incurred (see Note 11)                     $  7,661   $  3,594   $  7,759
                                                    =========  =========  =========
</TABLE>


                                       46
<PAGE>
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>
                                                       2002     2001      2000
                                                     --------  -------  --------
<S>                                                  <C>       <C>      <C>
Revenues from sale of oil and gas                    $38,939   $41,555  $23,869
Less:
   Production costs                                    5,001     3,011    1,658
   Production taxes                                    2,077     3,000    1,198
   Exploration and impairment                         27,605    11,458    8,347
   Depletion, depreciation and amortization           12,362     9,290    8,847
   Income tax expense (benefit)                       (2,999)    5,475   (1,181)
                                                     --------  -------  --------
Income (loss) from oil and gas operations            $(5,107)  $ 9,321  $ 5,000
                                                     ========  =======  ========

Company's share of equity method investee's
   income from oil and gas operations (see Note 11)  $ 1,129   $ 5,054  $ 1,857
                                                     ========  =======  ========
</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.

Depletion,  depreciation  and  amortization  include  costs  associated  with
capitalized  acquisitions,  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.


                                       47
<PAGE>
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, 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
    Revisions of previous estimates                                 (23,812)         74
    Extensions and discoveries                                       10,642         368
    Purchases of reserves in place
    Production                                                       (9,941)       (124)
                                                                ------------  ----------
  June 30, 2002                                                     183,345       2,951
                                                                ============  ==========

Proved developed reserves:
  June 30, 2000                                                     141,067         738
  June 30, 2001                                                     175,784         987
  June 30, 2002                                                     160,224       1,135

Company's share of equity method investee's proved reserve at:
  June 30, 2000                                                       7,402      13,681
  June 30, 2001                                                       9,497      11,811
  June 30, 2002                                                       7,445      12,063
</TABLE>

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


                                       48
<PAGE>
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>
                                                       2002        2001        2000
                                                    ----------  ----------  ----------
<S>                                                 <C>         <C>         <C>
Future cash in flows                                $ 715,755   $ 828,403   $ 606,382
Future production and development costs              (243,828)   (271,051)   (178,968)
Future income tax expense                            (116,000)   (145,000)   (121,000)
                                                    ----------  ----------  ----------
Future net cash flows before discount                 355,927     412,352     306,414
10% discount to present value                        (205,014)   (240,071)   (181,543)
                                                    ----------  ----------  ----------
Standardized measure of discounted future net cash
   flows related to proved oil and gas reserves     $ 150,913   $ 172,281   $ 124,871
                                                    ==========  ==========  ==========

Company's share of equity method investee's
   standardized measure of discounted future net
   cash flows                                       $  53,838   $  69,478   $  54,362
                                                    ==========  ==========  ==========
</TABLE>

     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>
                                                    2002       2001       2000
                                                  ---------  ---------  ---------
<S>                                               <C>        <C>        <C>
Standardized measure of discounted future
   net cash flows at beginning of period          $172,281   $124,871   $ 84,883
Sales of oil and gas produced, net of
   production costs                                (26,525)   (28,347)   (13,446)
Net changes in prices and production costs         (13,507)     3,338     57,741
Changes in production rates and other               (5,867)    15,526    (10,418)
Extensions, discoveries and other additions, net
   of future production and development costs       13,622     33,991      2,886
Changes in estimated future development costs       (4,820)   (31,981)     2,099
Development costs incurred                          10,977      9,232      5,869
Revisions of previous quantity estimates           (24,772)   (15,677)     5,731
Purchase of reserves in place                                  58,868     10,572
Accretion of discount                               17,228     12,487      8,488
Net change in income taxes                          12,296    (10,027)   (29,534)
                                                  ---------  ---------  ---------
Standardized measure of discounted
   future net cash flows at end of period         $150,913   $172,281   $124,871
                                                  =========  =========  =========
</TABLE>


                                    * * * * *


                                       49
<PAGE>
              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.


                                    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, 2002 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 2001
annual meeting of stockholders. Executive officers are appointed by the Board of
Directors.

<TABLE>
<CAPTION>
<S>                      <C>  <C>
John Mork                 54  President and Chief Executive Officer; Director
Joseph E. Casabona        59  Executive Vice President; Director
Michael S. Fletcher       53  Chief Financial Officer
Donald C. Supcoe          46  Senior Vice President, Secretary and General Counsel
Edward J. Davies          60  Senior Vice President
J. Michael Forbes         42  Vice President and Treasurer
K. Ralph Ranson, II       60  Vice President Marketing
Julie Ann Kitano          46  Assistant Secretary
W. Gaston Caperton, III   61  Director
Peter H. Coors            54  Director
L. B. Curtis              77  Director
John J. Dorgan            77  Director
Arthur C. Nielsen, Jr.    82  Director
F. H. McCullough, III     54  Director
Julie Mork                51  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, West Virginia
Media  Holdings,  the  Benedum  Foundation,  National  Center  for  Learning
Disabilities,  and  Classroom,  Inc.

     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.


                                       50
<PAGE>
     Peter  H. Coors has been a Director of the Company since 1996. Mr. Coors is
Chairman  of  Coors Brewing Company and President 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. and H.J. Heinz Company. Mr. Coors
is a trustee and member of the executive board of the Denver Area Council of the
Boy  Scouts  of America and a member of the executive committee for the National
Western Stock Show Association. He is also a member of the International Chapter
of  Young  Presidents'  Organization,  a  member  of  the Advisory Board for the
University  of Denver's Daniels School of Business, and a trustee for the Adolph
Coors  Foundation,  Castle  Rock  Foundation,  Seeds  of Hope Foundation and the
University  of  Northern  Colorado.

     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 is Senior Vice President of the Company. 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


                                       51
<PAGE>
of  the  University  of  Southern  California  with a Bachelor of Arts Degree in
International  Economics  and two Masters Degrees in Business Administration and
Financial  Systems  Management.  He is a graduate of the Northwestern University
Kellogg  Graduate  School  of  Management  Executive  Marketing  Program.

     John Mork has been President and Chief Executive Officer of the Company and
a  Director  of  the  Company  since  its  formation. Mr. Mork served in various
capacities at Union Oil Company until 1972 when he joined Pacific States Gas and
Oil,  Inc. and subsequently founded Eastern American. Mr. Mork was President and
a Director of Eastern American from 1973 until 1993. Mr. Mork is a past Director
of the Independent Petroleum Association of America, and the Independent Oil and
Gas  Association  of  West  Virginia.  Mr. Mork was a member of and held various
positions  with  the  Young  Presidents'  Organization  from  1984-1998. He 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.


                                       52
<PAGE>
                        ITEM 11. EXECUTIVE COMPENSATION
                        -------------------------------

     The  following  table  sets  forth  for fiscal year 2002 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>  <C>
John Mork                                 2002  $258,892  $  125,000       $ 59,670       $          26,067
   President and Chief Executive Officer  2001   256,068   1,146,635          4,349                  35,251
                                          2000   253,141     116,350         29,041                  11,010

Joseph E. Casabona                        2002  $238,277  $  125,942       $  2,905       $           4,574
   Executive Vice President               2001   231,538   1,457,630  (2)     1,888                   4,454
                                          2000   223,762      55,853          2,603                   8,760

Michael S. Fletcher                       2002  $233,306  $  100,510       $    352       $           4,504
   Chief Financial Officer                2001   232,471      56,345        124,198  (3)              3,500
                                          2000   228,298     168,702         19,496                  10,557

Edward J. Davies                          2002  $223,930  $   95,714       $    120       $           4,592
   Senior Vice President                  2001   207,308      53,105            899                   4,181
                                          2000   184,885      31,000          1,507                   4,080

Donald C. Supcoe                          2002  $197,993  $  100,435       $  2,325       $           3,949
   Senior Vice President                  2001   188,447      54,545                                  1,482
                                          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.
(3)  Includes the forgiveness of debt to the Company.
</TABLE>

     DIRECTOR  COMPENSATION.  Directors  are compensated $2,000 per meeting plus
     ----------------------
reimbursement  for  travel  and  related  expenses.  The  Chairman  of the Board
receives  an  additional  $50,000.  Annually,  each  Director  also receives 160
shares  of  the  Company's  Class A Stock.  During the current fiscal year, each
Director  received  the  option  of  an additional 1,000 shares of the Company's
Common Stock or 600 shares and $60,000.  Directors John Mork and Julie Mork, his
wife,  declined  the  offer  of  either  cash  or  shares.  The  total  Board of
Directors'  compensation  for  fiscal  2002  was  $1.3  million.


    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


                                       53
<PAGE>
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
August 31, 2002.  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)                                 49,710     7.96%
W. Gaston Caperton, III                               6,680     1.07%
Joseph E. Casabona                                   31,376     5.02%
Peter H. Coors                                        2,946        *
L. B. Curtis                                         11,610     1.86%
Edward J. Davies                                      3,000        *
John J. Dorgan                                        2,130        *
Michael S. Fletcher                                   1,000        *
J. Michael Forbes                                     2,200        *
F. H. McCullough, III (3)                            71,009    11.37%
John Mork (2)                                       361,743    57.93%
Julie Mork (2)                                      361,743    57.93%
Arthur C. Nielsen, Jr.                               36,480     5.84%
K. Ralph Ranson, II                                     800        *
Donald C. Supcoe                                      3,583        *
                                                    584,267    93.56%
All officers and directors as a group (14 persons)
<FN>
---------------
  *  Less than one percent.
(1)  Pursuant to agreements Kenneth W. Brill granted the Company options to
     purchase all of the Company's Common Stock owned by him.
(2)  Includes 353,180 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 68,929 shares held by F.H. McCullough, III and Kathy McCullough as
     joint tenants, 880 shares held by the Katherine F. McCullough Trust, and
     400 shares held by each of the Lesley McCullough Trust, the Meredith
     McCullough Trust and the Kristin McCullough Trust.
</TABLE>

     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial  owner  of  more  than 5% of the outstanding shares of Class A Stock,
(ii)  the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive officers as a group, in each case as of August 31, 2002.  The business
address of each officer and director listed below is:  c/o Energy Corporation of
American,  4643  South  Ulster  Street,  Suite  1100,  Denver,  Colorado  80237.


                                       54
<PAGE>
<TABLE>
<CAPTION>
                                                  Beneficial Ownership
                                                     Class A Stock
                                                    ----------------
                                                    Shares  Percent
                                                    ------  --------
<S>                                                 <C>     <C>
Dale P. Andrews                                        443     1.42%
W. Gaston Caperton, III                              1,920     6.17%
Joseph E. Casabona                                   5,119    16.45%
Peter H. Coors                                       2,534     8.14%
L.B. Curtis                                          1,720     5.53%
Edward J. Davies                                     2,439     7.84%
John J. Dorgan                                       2,320     7.46%
Michael S. Fletcher                                  1,460     4.69%
F.H. McCullough, III                                 1,920     6.17%
John Mork (1)                                        3,458    11.11%
Julie Mork (1)                                       3,458    11.11%
Arthur C. Nielsen, Jr.                               3,080     9.90%
K. Ralph Ranson, II                                    487     1.57%
Donald C. Supcoe                                     1,877     6.03%
                                                    28,777    92.48%
All officers and directors as a group (14 persons)
<FN>
---------------
(1)  Includes 2,116 shares held by John and Julie Mork as joint tenants and
     1,342 shares held by Julie Mork individually.
</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
following  table  identifies  the  participants'  aggregate  investment  in  the
calendar  years  shown  (in  thousands):


                                       55
<PAGE>
<TABLE>
<CAPTION>
                            2002       2001       2000
                         ----------  ---------  ---------
                            (3)
<S>                      <C>         <C>        <C>
Dale P. Andrews                                 $   12.63
Gaston Caperton, III     $  100.02   $   56.76      98.58
Joseph E. Casabona           50.01       21.99      49.18
Peter Coors                 100.02       28.38      49.18
L.B. Curtis                 107.50       88.85     126.39
E.J. Davies                 215.00      140.78     126.39
John J. Dorgan               25.00       14.19      24.59
Michael S. Fletcher          50.01       28.38      49.18
J. Michael Forbes            25.00       14.19
John Frederick                           14.19
Thomas R. Goodwin            50.01       28.38     172.14
John Mork (1)             1,075.00      703.89     758.34
Alison Mork Trust (2)        50.01       28.38      24.59
Kyle Mork Trust (2)          50.01       28.38      24.59
Arthur C. Nielsen, Jr.       50.01       28.38      49.18
Kent Schamp                  27.31       15.34      25.28
Donald C. Supcoe             25.00       14.19          -
                         ----------  ---------  ---------
                         $1,999.91   $1,254.65  $1,590.24
                         ==========  =========  =========
<FN>
(1)  Interest of John Mork and Julie Mork held as joint tenants.
(2)  Trusts for the children of John Mork and Julie Mork.
(3)  These amounts represent only the amounts committed to the 2002 Drilling
     Program, the actual investment may vary based on the number of wells
     drilled and the related costs.
</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.  The Company is amortizing the notes over their seven
year  life  and  assuming  continued employment.  Certain of these notes will be
forgiven  one-quarter  per year, starting December 31, 2002.  The following were
indebted  to  the  Company  (in  thousands):

<TABLE>
<CAPTION>
                                  Unamortized
                      Original       as of
                        Note     June 30, 2002
                      ---------  --------------
<S>                   <C>        <C>
 Dale P. Andrews      $      63  $           21
 Joseph E. Casabona         187              63
 Michael S. Fletcher        187              63
 J. Michael Forbes           96              96
 K. Ralph Ranson, II         28              13
 Donald C. Supcoe           209             133
                      ---------  --------------
    Total             $     770  $          389
                      =========  ==============
</TABLE>

     Certain  officers, Directors and key employees of the Company have borrowed
money  from  the  Company  and  have  executed  promissory notes. The notes bear
interest  at  7% to 8% per annum. The following were indebted to the Company (in
thousands):


                                       56
<PAGE>
<TABLE>
<CAPTION>
                           Note Plus    Unamortized
                            Accrued        as of
                            Interest   June 30, 2002
                           ----------  --------------
<C>  <S>                   <C>         <C>
(1)   Michael S. Fletcher  $      265  $           83
(1)   Linda Given                  26               8
(1)   David Jordan                 52              16
(2)   Dennis McGowan               49              49
(1)   Donald C. Supcoe            158              49
                           ----------  --------------
                           $      550  $          205
                           ==========  ==============
<FN>
(1)  Promissory note is being forgiven and amortized over three years, assuming
       continuing employment.
(2)  Promissory note is being forgiven and amortized 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 as of June
30,  2002:

<TABLE>
<CAPTION>
                            Payment      Volumes
                        (in thousands)    Mmcf
                        ---------------  -------
<S>                     <C>              <C>
Dale P. Andrews         $            20     26.7
Gaston Caperton, III                600    800.0
Joseph E. Casabona                   50     66.7
Peter Coors                          50     66.7  (1)
L.B. Curtis                         150    200.0
E.J. Davies                         150    200.0
John J. Dorgan                       50     66.7
F.H. McCullough, III                150    200.0
John Mork                           750  1,000.0  (1)
Alison Mork Trust                    50     66.7  (1)
Kyle Mork Trust                      50     66.7  (1)
Arthur C. Nielsen, Jr.               94    125.3  (1)
                        ---------------  -------
                        $         2,164  2,885.5
                        ===============  =======
<FN>
(1)  During fiscal year 2002, all interest in these properties was assigned to
     the Company for nominal consideration
</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 2002. The Company believes that
such  rental  terms  are no less favorable than could have been obtained from an
unaffiliated  party.


                                       57
<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.
          *   10.10    Intentionally  omitted.


                                       58
<PAGE>
          *   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    Intentionally  omitted.
          *   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.


                                       59
<PAGE>
          *   10.37    Purchase  and  Sale  Agreement  dated June 28, 2001
                       between Tavener E&P Ltd and Westech Energy Corporation.
          *   10.38    Credit Agreement dated July 10, 2002 between Energy
                       Corporation of America and Foothill Capital Corporation,
                       as the Arranger and Administrative Agent for the Lenders.
              10.39    Purchase  and  Sale  Agreement  dated  August 2, 2002
                       between East Resources, Inc. and Energy Corporation of
                       America, without exhibits thereto.
              10.40    Amendment, effective as of June 29, 1997, to Buy-Sell
                       Stock Option Agreement between Energy Corporation of
                       America and Kenneth W. Brill.
              10.41    Agreement  dated  December  28,  1998  between Energy
                       Corporation of America and Kenneth W. Brill.
              21.1     Subsidiaries  of  Energy  Corporation  of  America.
              24.1     Power  of  Attorney  set  forth  on the signature page
                       contained in Part V.
          *   99.1     Order  of  the  United States District Court for the
                       Southern District of West Virginia entered January 25,
                       2002 in civil action number 3:01-1317.
          *   99.2     Order  of  the  United States District Court for the
                       Southern District of West Virginia entered June 3, 2002
                       in civil action number 3:01-1317.
              99.3     Order  of  the  United  States  District Court for the
                       Southern District of West Virginia entered July 2002 in
                       civil action number 3:01-1317.
     *     Previously  filed


(b)  Reports  on  Form  8-K

     The Company filed a report on Form 8-K, Item 5, dated December 28, 2001,
     reporting (1) a Notice of Default from certain holders of its $200 million
     9-1/2% Senior Subordinate Notes due 2007 and (2) that the Company had filed
     a declaratory judgment action in the United States District Court of the
     Southern District of West Virginia, civil action number 3:01-1317, asking
     the court to confirm the proper calculation of Net Proceeds of an Asset
     Sale under the Indenture.

     The Company filed a report on Form 8-K, Item 5, dated June 24, 2002,
     reporting that on June 3, 2002 the United States District Court of the
     Southern District of West Virginia entered an order granting the Company's
     Second Motion for Partial Summary Judgment, which order dismissed the
     Noteholder's claim on the basis of judicial admissions and equitable
     estoppel.

     The Company filed a report on Form 8-K, Item 5, dated July 12, 2002,
     reporting that the Company entered into a $50 million revolving Credit
     Agreement with Foothill Capital Corporation, as the Arranger and
     Administrative Agent for the Lenders.

                                  * * * * * *


                                       60
<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 30th day of
September  2002.

                                      ENERGY  CORPORATION  OF  AMERICA

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


                                       61
<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 30th day of September 2002, by the following persons in
the  capacities  indicated.


                                       62
<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




                                       63
<PAGE>
                                  CERTIFICATION
                                  -------------
            PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
            ---------------------------------------------------------
 (SUBSECTIONS (A) AND (B) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES
 -------------------------------------------------------------------------------
                                      CODE)
                                      -----


     Pursuant  to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a)
     ---------------------------------------------------------------------------
and  (b)  of  section  1350,  chapter  63  of title 18, United States Code), the
--------------------------------------------------------------------------------
undersigned  officer  of  Energy  Corporation  of  America,  a  West  Virginia
------------------------------------------------------------------------------
corporation  (the  "Company"),  hereby  certifies  that:
--------------------------------------------------------

     The  Annual  Report of the Company on Form 10-K for the year ended June 30,
2002  (the  "Report"),  fully complies with the requirements of section 13(a) or
15(d)  of  the Securities Exchange Act of 1934, and the information contained in
the  Report  fairly  presents, in all material respects, the financial condition
and  results  of  operations  of  the  Company.

     Dated:  September 27, 2002                       /s/  John  Mork
                                              ----------------------------------
                                              Name:   John  Mork
                                              Title:  Chief Executive Officer


     The  foregoing  certification is being furnished solely pursuant to section
906  of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350,
chapter  63  of  title 18, United States Code) and is not being filed as part of
the  Report  or  as  a  separate  disclosure  document.


                                       64
<PAGE>
                                  CERTIFICATION
                                  -------------
            PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
            ---------------------------------------------------------
 (SUBSECTIONS (A) AND (B) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES
 -------------------------------------------------------------------------------
                                      CODE)
                                      -----


     Pursuant  to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a)
     ---------------------------------------------------------------------------
and  (b)  of  section  1350,  chapter  63  of title 18, United States Code), the
--------------------------------------------------------------------------------
undersigned  officer  of  Energy  Corporation  of  America,  a  West  Virginia
------------------------------------------------------------------------------
corporation  (the  "Company"),  hereby  certifies  that:
--------------------------------------------------------

     The  Annual  Report of the Company on Form 10-K for the year ended June 30,
2002  (the  "Report"),  fully complies with the requirements of section 13(a) or
15(d)  of  the Securities Exchange Act of 1934, and the information contained in
the  Report  fairly  presents, in all material respects, the financial condition
and  results  of  operations  of  the  Company.

     Dated:  September 27, 2002                       /s/  Michael S. Fletcher
                                              ----------------------------------
                                              Name:   Michael  S.  Fletcher
                                              Title:  Chief Financial Officer


     The  foregoing  certification is being furnished solely pursuant to section
906  of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350,
chapter  63  of  title 18, United States Code) and is not being filed as part of
the  Report  or  as  a  separate  disclosure  document.


                                       65
<PAGE>
                                  CERTIFICATION
                                  -------------
            PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
            ---------------------------------------------------------
           (SECTION 7241, CHAPTER 98 OF TITLE 15, UNITED STATES CODE)
           ----------------------------------------------------------


     Pursuant  to  section  302 of the Sarbanes-Oxley Act of 2002 (section 7241,
     ---------------------------------------------------------------------------
chapter  98  of title 15, United States Code), the undersigned officer of Energy
--------------------------------------------------------------------------------
Corporation  of  America,  a  West  Virginia corporation (the "Company"), hereby
--------------------------------------------------------------------------------
certifies  that:
----------------

     I  have reviewed the Annual Report of the Company on Form 10-K for the year
ended  June  30,  2002 (the "Report"), and, to my knowledge, the Report does not
contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which
such  statements  were  made,  not  misleading, and the financial statements and
other  financial  information  contained  in  the Report fairly presents, in all
material  respects,  the  financial  condition,  results of operations, and cash
flows  of  the  Company  as  of  and  for  the  periods presented in the Report.


     Dated:  September 27, 2002                       /s/  John  Mork
                                              ----------------------------------
                                              Name:   John  Mork
                                              Title:  Chief Executive Officer

     The  foregoing  certification is being furnished solely pursuant to section
302  of  the  Sarbanes-Oxley  Act of 2002 (section 7241, chapter 98 of title 15,
United  States  Code)  and  is  not  being  filed  as part of the Report or as a
separate  disclosure  document.


                                       66
<PAGE>
                                  CERTIFICATION
                                  -------------
            PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
            ---------------------------------------------------------
           (SECTION 7241, CHAPTER 98 OF TITLE 15, UNITED STATES CODE)
           ----------------------------------------------------------


     Pursuant  to  section  302 of the Sarbanes-Oxley Act of 2002 (section 7241,
     ---------------------------------------------------------------------------
chapter  98  of title 15, United States Code), the undersigned officer of Energy
--------------------------------------------------------------------------------
Corporation  of  America,  a  West  Virginia corporation (the "Company"), hereby
--------------------------------------------------------------------------------
certifies  that:
----------------

     I  have reviewed the Annual Report of the Company on Form 10-K for the year
ended  June  30,  2002 (the "Report"), and, to my knowledge, the Report does not
contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which
such  statements  were  made,  not  misleading, and the financial statements and
other  financial  information  contained  in  the Report fairly presents, in all
material  respects,  the  financial  condition,  results of operations, and cash
flows  of  the  Company  as  of  and  for  the  periods presented in the Report.

     Dated:  September 27, 2002                       /s/  Michael S. Fletcher
                                              ----------------------------------
                                              Name:   Michael S. Fletcher
                                              Title:  Chief Financial Officer


     The  foregoing  certification is being furnished solely pursuant to section
302  of  the  Sarbanes-Oxley  Act of 2002 (section 7241, chapter 98 of title 15,
United  States  Code)  and  is  not  being  filed  as part of the Report or as a
separate  disclosure  document.


                                       67
<PAGE>