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, 2003.

                                       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 13, 2003 was 38,250 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  13,  2003  was  616,893  shares.



                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE


                                        2
<PAGE>
                          ENERGY CORPORATION OF AMERICA

                                TABLE OF CONTENTS

                                                                            Page

Part I
     Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4
     Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .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 . . . . . . . . . . . . . . . . . 27
               Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . 28
               Statements of Operations . . . . . . . . . . . . . . . . . . . 30
               Statements of Stockholders Equity. . . . . . . . . . . . . . . 31
               Statements of Cash Flows . . . . . . . . . . . . . . . . . . . 32
               Statements of Comprehensive Income . . . . . . . . . . . . . . 33
               Notes to Consolidated Financial Statements . . . . . . . . . . 34
               Supplemental Information on Oil and Gas Producing
               Activities (Unaudited) . . . . . . . . . . . . . . . . . . . . 52
     Item 9. Changes In and Disagreements With Accountants on
             Accounting and Financial Disclosure. . . . . . . . . . . . . . . 55
Part III
     Item 10. Directors and Officers of Registrant. . . . . . . . . . . . . . 55
     Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . 59
     Item 12. Security Ownership of Certain Beneficial Owners
              and Management. . . . . . . . . . . . . . . . . . . . . . . . . 59
     Item 13. Certain Relationships and Related Transactions. . . . . . . . . 61
     Item 14. Controls and Procedures . . . . . . . . . . . . . . . . . . . . 63
Part IV
     Item 15. Exhibits, Financial Statement Schedules and Reports
              on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . 65
Part V
     Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

     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),  billion  cubic  feet  (Bcf),  dekatherm (Dth), or thousand
dekatherms  (Mdth).  A  dekatherm  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.  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 assumed to have the energy equivalent of six Mcf of natural gas.  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, gathering and
marketing  of  natural  gas and oil, primarily in the Appalachian Basin and Gulf
Coast  region.  The  Company  conducts  business primarily through its principal
wholly  owned  subsidiaries,  Eastern  American  Energy Corporation ("Eastern"),
Westech  Energy Corporation ("Westech") and Westech Energy New Zealand ("WENZ").
Eastern  is  one  of the largest oil and gas operators in the Appalachian Basin,
including  exploration,  development  and  production,  and  is  engaged  in the
gathering  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.  As  used  herein  the  "Company"  refers  to the Company alone or
together  with  one  or  more  of  its  subsidiaries.

     The  Company was formed in June 1993 through an exchange of shares with the
common  stockholders  of  Eastern.

     As  of  June  30,  2003, the Company had approximately 226 full-time and 22
part-time  employees.  None  of  the  employees  were  covered  by  a collective
bargaining  agreement.  Management  believes  that  its  relationship  with  its
employees  is  good.

     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  17  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,
2003  at  190,796 Mmcf and 2,366 Mbbls, respectively.  For the fiscal year ended
June  30,  2003,  the  Company's  net  gas production was 9,755 Mmcf and net oil
production  was  104  Mbbls,  for  a  total  of  10,379  net  Mmcfe.

     DEVELOPMENT  ACTIVITY

     The  Company,  in fiscal year 2003, drilled 45 productive gross wells (39.1
net), and recompleted 9 wells, adding 2,224 gross Mcf of gas production per day.
The  company  also participated in 2 gross (0.4 net) wells drilled in California
which  added  596  gross  Mcfe  per  day  of  production.


                                        4
<PAGE>
     EXPLORATORY ACTIVITY

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

     1.     Newburg/Rose  Run  -- West Virginia, Ohio.  The Company drilled four
successful  exploration  wells and two dry holes during the fiscal year. Current
production  from  the  Newburg discovery is 850 Mcf per day and 21 Bbls per day,
net.  The  Company  has  an exploration plan for the area following the drilling
success  and  acquisition  of  3-D  seismic.

     2.     Texas.  The Company, as operator, drilled eight wells with a success
rate of 67%. The principal producing formations are the Yegua and Meek at depths
ranging  from 7,500 to 16,000 feet. The wells are producing approximately 16,000
Mcf  per day, and 5,000 Mcf per day net. The Company is working on a development
drilling  plan  to  exploit  the  exploration  success.

     3.     New  Zealand.  The  Company  drilled  a  successful  well in the Mt.
Messenger  formation  in  the  Taranaki  region  which  is  currently producing.
Therein,  the  Company  is  continuing its exploration efforts on the East Coast
offshore  prospects.

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  may  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.


                                        5
<PAGE>
REGULATIONS  AFFECTING  OPERATIONS

     The  Company's  operations are affected by extensive regulation pursuant to
various  federal,  state  and  local  laws  and  regulations  relating  to  the
exploration  for  and  development,  production,  gathering,  marketing,
transportation  and  storage  of  oil  and  gas.  These regulations, among other
things, can affect the rate of oil and gas production.  The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the  discharge  of  materials  into  the  environment  or  otherwise relating to
environmental protection.  These laws and regulations require the acquisition of
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  its  wholly  owned  subsidiary  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,  2003,  Eastern Marketing aggregated and sold an average of 41.2 Mmcf of gas
per day, of which 39.1 Mmcf per day represented sales of gas produced from wells
operated  by  the  Company. This represents a 7% decrease in the overall volumes
compared to fiscal year 2002, during which Eastern Marketing aggregated and sold
an average of 44.2 Mmcf of gas per day.

GAS  SALES  AND  PURCHASE  CONTRACTS

     The  Company  has  satisfied  its obligations under all gas sales contracts
(15.1  Bcf  in  fiscal year 2003) through gas production attributable to its own
interests in oil and gas properties and through production attributable to third
party  interests  in  the same oil and gas properties (14.3 Bcf in fiscal 2003),
and  from  natural gas aggregated by the Company pursuant to its aggregation and
marketing  activities  from  third  parties  (0.8  Bcf  in  fiscal  2003).

     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.  Through  May  31,  2003, 1,681,242 Mmbtu had been
delivered  at  a  value of $6.9 million. This agreement was terminated as of May
31,  2003  pursuant  to a settlement agreement effective as of May 14, 2003, and
the  Company's  obligations  are deemed fully satisfied (See Item 8, Note 14 for
additional  detail).


                                        6
<PAGE>
     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 minimum price to be received by
the  Company  is  $2.75  per  Dth  plus  the  Columbia  Gas Transmission ("TCO")
Appalachia  Basis  and  the maximum to be received is $4.85 per Dth plus the TCO
Appalachia  Basis.  The pricing terms also allow the Company to fix the price on
50% of the volumes.  The Company has locked the price on 50% of the volumes from
July  1,  2003 through October 31, 2004 at a weighted average price of $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  Inside  FERC  Dominion
Transmission  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.


                             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>
                                                        2003      2002      2001
                                                      --------  --------  --------
<S>                                                   <C>       <C>       <C>
      Net proved:
        Gas (Mmcf)                                     190,796   183,345   206,456
        Oil (Mbbls)                                      2,366     2,951     2,633
        Total (Mmcfe)                                  204,992   201,051   222,254

      Net proved developed:
        Gas (Mmcf)                                     161,796   160,224   175,784
        Oil (Mbbls)                                      1,064     1,135       987
        Total (Mmcfe)                                  168,180   167,034   181,706

      Estimated future net cash flows
        before income taxes (in thousands)            $916,885  $471,927  $557,352
      Present value of estimated future net cash
        flows before income taxes (in thousands) (1)  $382,094  $200,087  $232,866
<FN>
      ______________
     (1)  Discounted using an annual discount rate of 10%.
</TABLE>

     The  following table sets forth the Company's estimated proved reserves and
the related estimated present value by region, as of June 30, 2003:

<TABLE>
<CAPTION>
                             Present Value
                         --------------------                           Natural Gas
                            Amount                 Oil      Natural Gas  Equivalent
           Region        (thousands)     %       (Mbbls)       (Mmcf)     (Mmcfe)
     ------------------  ------------  ------  ------------  -----------  --------
<S>                      <C>           <C>     <C>           <C>          <C>

     Appalachian Basin   $    306,838   80.3%           631      166,539   170,325
     Western Basins            17,717    4.6%         1,191        4,285    11,431
     Gulf Coast                53,858   14.1%           225       18,933    20,283
     New Zealand                3,681    1.0%           319        1,039     2,953
                         ------------  ------  ------------  -----------  --------
     Total               $    382,094  100.0%         2,366      190,796   204,992
                         ============  ======  ============  ===========  ========
</TABLE>

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

     The  following  table sets forth certain information relating to productive
wells  at  June  30, 2003. 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   12.0  5,372.0  5,384.0   7.0  3,223.0  3,230.0
     Western Basins      11.0      2.0     13.0   3.4      0.2      3.6
     Gulf Coast             -     13.0     13.0     -      3.9      3.9
     New Zealand            -      4.0      4.0     -      4.0      4.0
                         ----  -------  -------  ----  -------  -------
     Total               23.0  5,391.0  5,414.0  10.4  3,231.1  3,241.5
                         ====  =======  =======  ====  =======  =======
</TABLE>


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

     The  following table sets forth the developed and undeveloped gross and net
acreage  held  at  June  30,  2003:

<TABLE>
<CAPTION>
                           Developed Acreage     Undeveloped Acreage
                         --------------------  ------------------------
                           Gross       Net        Gross         Net
                         ---------  ---------  -----------  -----------
<S>                      <C>        <C>        <C>          <C>
      Appalachian Basin  402,870.0  310,441.0    144,041.0    117,982.0
      Western Basins       1,920.0    1,457.9     86,864.4     45,228.3
      Gulf Coast           1,913.5      670.8     33,758.8     20,024.4
      New Zealand            740.0      736.3  3,181,413.1  2,776,411.9
                         ---------  ---------  -----------  -----------
      Total              407,443.5  313,306.0  3,446,077.3  2,959,646.6
                         =========  =========  ===========  ===========
</TABLE>


PRODUCTION
----------

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

<TABLE>
<CAPTION>
                                                             2003     2002     2001
                                                            -------  -------  -------
<S>                                                         <C>      <C>      <C>

      Production Data:
        Oil (Mbbls)                                             104      124      116
        Natural gas (Mmcf)                                    9,755    9,941    9,371
        Natural gas equivalent (Mmcfe)                       10,379   10,685   10,067
      Average Sales Price (before the effect of hedging):
        Oil per Bbl                                         $ 25.97  $ 21.11  $ 25.94
        Natural gas per Mcf                                 $  5.13  $  2.86  $  5.43
</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>
                              2003         2002         2001
                           -----------  -----------  -----------
                           Gross  Net   Gross  Net   Gross  Net
                           -----  ----  -----  ----  -----  ----
<S>                        <C>    <C>   <C>    <C>   <C>    <C>
      Development:
          Productive
             Appalachian    45.0  39.1   53.0  47.8   47.0  41.5
             Other           2.0   0.4    1.0   0.3      -     -
                           -----  ----  -----  ----  -----  ----
          Total             47.0  39.5   54.0  48.1   47.0  41.5
                           =====  ====  =====  ====  =====  ====

          Nonproductive
             Appalachian     3.0   2.7    1.0   0.9    1.0   0.5
             Other             -     -      -     -      -     -
                           -----  ----  -----  ----  -----  ----
          Total              3.0   2.7    1.0   0.9    1.0   0.5
                           =====  ====  =====  ====  =====  ====
      Exploratory:
          Productive
             Appalachian     4.0   1.4    4.0   1.6
             Other           9.0   4.0    4.0   2.3    3.0   2.6
                           -----  ----  -----  ----  -----  ----
          Total             13.0   5.4    8.0   3.9    3.0   2.6
                           =====  ====  =====  ====  =====  ====

          Nonproductive
             Appalachian     2.0   1.0    5.0   2.1    2.0   0.3
             Other           4.0   2.2    4.0   3.2    8.0   3.8
                           -----  ----  -----  ----  -----  ----
          Total              6.0   3.2    9.0   5.3   10.0   4.1
                           =====  ====  =====  ====  =====  ====
</TABLE>

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

     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 alleged that
the  Company's  sale  of  Mountaineer  in  August  of 2000 constituted a sale of
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


                                       10
<PAGE>
Order  dated July 19, 2002, denying the Noteholders' Motion for Reconsideration.
On  July 27, 2002, the Noteholders filed a Notice of Appeal in the United States
Court  of  Appeals  for the Fourth Circuit. The Noteholders subsequently filed a
motion  to  voluntarily  dismiss  the  appeal without prejudice. This motion was
granted  and  the  matter was remanded to the District Court. The District Court
entered  a  Stipulation  and  Final  Judgment on December 3, 2002 and a Judgment
Order  dated  December  4, 2002. This discussion is qualified in its entirety by
the  foregoing  Stipulation  and  Final  Judgment dated December 3, 2002 and the
Judgment  Order dated December 4, 2002, which have been previously filed and are
incorporated  herein  by  reference.

     On  December  9,  2002, certain Noteholders filed a Notice of Appeal to the
United  States  Court of Appeals for the Fourth Circuit from the Stipulation and
Final  Judgment  Order dated December 3, 2002, and the Judgment order entered on
December 4, 2002.  Briefing is complete and oral argument has been scheduled for
September  25,  2003.

     The Company and Prudential Securities Incorporated ("Prudential") have been
in  a long-standing dispute related to certain fees.  In March 2003, the dispute
resulted  in  Prudential  filing suit against the Company in the District Court,
City  and County of Denver, Colorado.  Management does not believe the merits of
Prudential's  allegations, and is of the opinion that the matter is not material
regardless  of  the  outcome.

     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
13,  2003,  the  Company  had  33  holders  of  record  of  its  common  stock.

     The  Company declared dividends in fiscal years 2003, 2002 and 2001 of $1.1
million,  $1.1  million  and  $3.9  million,  respectively.


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

(Dollars in thousands, except per share items)
                                                           Year Ended June 30,
                                           ----------------------------------------------------
                                             2003      2002       2001       2000      1999
                                           --------  ---------  ---------  ---------  ---------
<S>                                        <C>       <C>        <C>        <C>        <C>

Operating revenue                          $117,426  $ 86,142   $129,951   $101,919   $113,500
Income (loss) from continuing operations      9,917   (26,180)   (10,199)   (26,508)   (27,099)

  Earnings per common share, basic            15.12    (39.80)    (15.34)    (40.11)    (40.27)
                             diluted          14.79    (39.80)    (15.34)    (40.11)    (40.27)
Total assets                                295,834   304,736    380,532    265,691    286,077
Long term debt                              173,197   198,701    198,902    212,575    219,886
Dividends declared per common share        $   1.72  $   1.60   $   5.80   $      -   $   0.95
</TABLE>

     (a)  The  effect  of  outstanding  stock  options  was  not included in the
     computation of diluted earnings per share for years ended 2002, 2001, 2000,
     or  1999  because  to  do  so  would  have  been  antidilutive.

         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.

     DERIVATIVE  INSTRUMENTS  - As of July 1, 2000, the estimated fair values of
all  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  in  operations in the period they occur. In determining the amounts to
be recorded, the Company is 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 of 10%, as required by accounting standards. 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.

     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, 2003 AND 2002
------------------------------------------------------------------------------

     The  Company  recorded  net income  of $9.9 million for the year ended June
30,  2003  compared  to a net loss of $26.2 million in 2002.  The improvement of
$36.1  million  was  primarily attributable to the net effect of a $31.3 million
increase  in  revenue,  a  $0.2  million  decrease in costs and expenses, a $3.3
million decrease in interest expense, a $0.7 decrease in gain on sale of assets,
$24.7  million  increase  in  other  non-operating  income  and  a $22.9 million
increase  in  income  tax  expense.

     OPERATING  MARGINS.  Operating  Margins  (defined as revenue less operating
     ------------------
costs  and  taxes  other  than  income  taxes)  for  the  Company's  operating
subsidiaries  totaled  $50.3  million  for  the  current  year compared to $35.6
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  and  taxes  other than income) totaled $43.5 million
versus  $31.3  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 $6.8 million for the current period versus
$3.7  million  for  the  prior  period.  Other revenue was $0.04 million for the
current  period  versus  $0.50  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>
                                                        TWELVE MONTHS ENDED
                                                              JUNE 30          VARIANCE
                                                          ---------------  ------------------
                                                           2003     2002    AMOUNT   PERCENT
                                                          -------  ------  --------  --------
<S>                                                       <C>      <C>     <C>       <C>
      Natural Gas
        Production (Mmcf)                                  9,755    9,941     (186)     -1.9%
        Average sales price received ($/Mcf)                5.13     2.86     2.27      79.4%
                                                          -------  ------  --------  --------
        Sales ($ in thousands)                            50,031   28,462   21,569      75.8%
      Oil
        Production (Mbbl)                                    104      124      (20)    -16.1%
        Average sales price received ($/Bbl)               25.97    21.11     4.86      23.0%
                                                          -------  ------  --------  --------
        Sales ($ in thousands)                             2,701    2,618       83       3.2%
      Hedging                                             (4,843)   7,212  (12,055)   -167.2%
      Other                                                3,521      647    2,874     444.2%
                                                          -------  ------  --------  --------
      Total oil and gas sales ($ in thousands)            51,410   38,939   12,471      32.0%
                                                          =======  ======  ========  ========
      Marketing Revenue
        Volume (Mdth)                                      9,285    9,903     (618)     -6.2%
        Average sales price received ($ per Dth)            4.86     3.14     1.72      54.7%
                                                          -------  ------  --------  --------
        Sales ($ in thousands)                            45,145   31,125   14,020      45.0%
      Pipeline Revenue
        Volume (Mdth)                                      5,675    6,003     (328)     -5.5%
        Average sales price received ($ per Dth)            2.70     1.68     1.02      60.7%
                                                          -------  ------  --------  --------
        Sales ($ in thousands)                            15,338   10,084    5,254      52.1%
                                                          -------  ------  --------  --------
      Total marketing and pipeline sales ($ in thousands) 60,483   41,209   19,274      46.8%
                                                          =======  ======  ========  ========
      Marketing Gas Cost
        Volume (Mdth)                                      9,285    9,902     (617)     -6.2%
        Average price paid ($ per Dth)                      4.48     2.98     1.50      50.3%
                                                          -------  ------  --------  --------
        Cost ($ in thousands)                             41,636   29,526   12,110      41.0%
      Pipeline Gas Cost
        Volume (Mdth)                                      4,550    4,870     (320)     -6.6%
        Average price paid ($ per Dth)                      2.65     1.64     1.01      61.6%
                                                          -------  ------  --------  --------
        Cost ($ in thousands)                             12,057    7,963    4,094      51.4%
                                                          -------  ------  --------  --------
      Total marketing and pipeline cost ($ in thousands)  53,693   37,489   16,204      43.2%
                                                          =======  ======  ========  ========
      ---------------------------------------------------------------------------------------
</TABLE>

     REVENUES.  Total  revenues  increased  $31.3  million  or 36.3% between the
     --------
years.  The  net  increase  was  due to a 32.0% increase in oil and gas sales, a
46.8%  increase  in  gas  marketing  and pipeline sales, a 0.1% increase in well
operations and service revenues and a 93.1% decrease in other operating revenue.


                                       15
<PAGE>
     Revenues from oil and gas sales increased a net of $12.5 million from $38.9
million  for  the  year  ended June 30, 2002 to $51.4 million for the year ended
June 30, 2003. Natural gas sales increased $21.6 million and oil sales increased
$0.08  million.  The  net increase is attributed to the following variances; gas
price  increase  $22.1  million,  gas production decrease $.5 million, oil price
increase  $0.5  million  and  oil  production  decrease  $0.4 million. The price
increase corresponds with related indexes. The decrease in production was due in
part  to  the  sale  of certain oil and gas properties, extended curtailments on
third  party transmission facilities, as well as normal production declines. The
decrease  in  production was partially offset by the purchase of certain oil and
gas  properties  and the drilling of new wells. The increased production revenue
was  offset  by  recognized  losses  on  related  hedging transactions including
derivative  instruments and fixed price delivery contracts, which totaled a loss
of  $4.8  million  for  the  year ended June 30, 2003 compared to a gain of $7.2
million  for  the  year  ended  June 30, 2002. The average price per Mcfe, after
hedging,  was  $4.99  and  $3.65  for  the  years  ended June 30, 2003 and 2002,
respectively.

     Revenues from gas marketing and pipeline sales increased $19.3 million from
$41.2  million  during  the  period  ended June 30, 2002 to $60.5 million in the
period  ended June 30, 2003. Gas marketing revenue increased $14.0 million while
pipeline  revenue,  which has sale and transportation components, increased $5.3
million. The increase in gas marketing and pipeline sales is attributable to the
increase  in  average  sales price received. The price increase corresponds with
related  indexes.

     Other  operating  revenue decreased $.5 million. The current year income of
$0.03  million  is  related  to revenue earned by the Company's participation in
Deep  Rig,  L.P.,  while  $0.5  million  was  recognized  in  the  prior  year.

     COSTS AND EXPENSES. The Company's costs and expenses decreased $0.2 million
     -------------------
or  0.2%  between  the  periods  primarily as a net result of a 7.2% decrease in
field  and  lease  operating  expenses,  a  43.2%  increase in gas marketing and
pipeline costs, a 11.1% decrease in general and administrative expenses, a 51.1%
increase  in  taxes  other  than  income, a 1.8% decrease in oil and gas related
depreciation,  a  46.4%  increase  in  depletion  and  amortization  expenses of
pipelines,  property  and  equipment  and  a  57.6%  decrease in exploration and
impairment  costs.

     Field  and lease operating expenses decreased $0.8 million. The decrease in
lease  operating  expenses is primarily related to a reduction in contract labor
expenses,  road  and  dike  repair  costs,  and  various  other  field and lease
operating  expenses.

     Gas  marketing  and  pipeline  costs increased $16.2 million. Gas marketing
cost  increased  $12.1  million while pipeline costs increased $4.1 million. The
increase  in  gas  marketing  and  pipeline cost of sales is attributable to the
increase  in  average  price  paid.  The price increase corresponds with related
indexes.

     General and administrative expenses decreased $1.9 million primarily due to
an increase in exploration and development drilling capitalized costs, lower bad
debt  expense,  legal  fees,  and  board  fees.

     Taxes other than income increased $1.1 million as a result of increased oil
and  gas  sales.  Average wellhead oil and gas sales prices, on which production
taxes  are  based,  were  higher  for  the  current  year.

     Oil  and  gas  related  depreciation,  depletion  and amortization expenses
decreased  $0.2  million.  The decrease in depletion is primarily due to reduced
production volumes resulting from the sale of


                                       16
<PAGE>
certain  oil and gas properties and normal production declines, partially offset
by  production  related to the acquisition of certain oil and gas properties and
from  new  wells  drilled  during  the  year.

     Exploration and impairment expenses decreased $16.0 million. In the current
year,  the  expenses were primarily due to dry hole costs, impairment of oil and
gas  property  and various other geological and geophysical costs. The breakdown
of  costs  by  area in the current year are $6.8 million in the Gulf Coast, $1.0
million  in  New Zealand, $2.8 million in the Appalachian Basin and $1.1 million
in  the  West.

     INTEREST  EXPENSE. Interest expense decreased $3.3 million primarily due to
     -----------------
the repurchase of $65.6 million face value of the Company's senior notes for the
year  ended  June  30,  2003.

     INTEREST  INCOME  AND  OTHER.  Other  non-operating  income increased $24.7
     ----------------------------
million  when comparing the periods. This is primarily the result of the Company
purchasing  a  portion  of  its  senior  bonds  and  recognizing a gain of $23.7
million.  The  Company  also  recognized  $4.5  million  in  income  from  legal
settlements  and  $1.4  million  in  net  contract  settlements  associated with
Allegheny  Energy.  Offsetting this increase in other non-operating income was a
reduction  in  interest  income  of  $1.1  million  due to decreases in the cash
balances  and  interest  rates  when  comparing  the  periods.  The Company also
recognized  a  loss  of  $2.1 million due to the write down of its investment in
Alliance  Gas.

     INCOME  TAX.  Income  tax  expense increased by $22.9 million in 2003 to an
     -----------
income  tax expense of $6.1 million as compared to an income tax benefit in 2002
of  $16.8  million.  This increase was due to a $58.8 million increase in income
from  continuing  operations.

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


     The  Company  recorded  a net loss 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
year  ended  June  30, 2002 as compared to $33.0 million for the year ended June
30,  2001.   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 for the year ended June 30, 2002 versus $27.6 million for the year ended
June  30,  2001.  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.


                                       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
                                                                              -------------------
                                                           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%
                                                          -------  ---------  ---------  --------
      Sales ($ 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 acquisition of certain properties
            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.


                                       18
<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 participation in Deep
Rig,  L.P.,  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.

     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.

     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.

     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.


                                       19
<PAGE>
     INTEREST  INCOME  AND  OTHER.  Other  non-operating  income  decreased $4.6
     ----------------------------
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  income  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.

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>
                          2003     2002      2001
                         -------  -------  --------
<S>                      <C>      <C>      <C>
           Development   $14,105  $10,977  $ 13,649
           Exploration    15,292   20,737    15,115
           Acquisitions    5,879      717    80,394
                         -------  -------  --------
             Total       $35,276  $32,431  $109,158
                         =======  =======  ========
</TABLE>

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

     On  February  5, 2003, the Company purchased certain oil and gas properties
located  in  southern West Virginia for $5.6 million, after certain adjustments.
The  purchase  included  proved developed producing gas reserves, estimated at 4
Bcf, 90 producing wells and over 30,000 acres.


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

     The  Company's financial condition has improved since June 30, 2002, but at
the  same  time,  there  has  been  a  decrease  in  the  Company's  liquidity.
Stockholders'  equity has increased from $37.1 million at June 30, 2002 to $43.7
million  at  June  30,  2003.  However,  the  Company's  working capital of $1.8
million at June 30, 2002 decreased to a negative $12.9 million at June 30, 2003.
The Company's cash decreased from $17.8 million at June 30, 2002 to $4.8 million
at  June 30, 2003.  The Company's cash at August 28, 2003 was $1.4 million.  The
change  in  cash  during  the  year of approximately $12.9 million resulted from
various  operating,  investing  and  financing  activities  of the Company.  The
activities  were  primarily  comprised  of: the borrowing of approximately $39.2
million  under  the  Company's  $50  million  revolving  Credit  Agreement  (the
"Agreement");  the  borrowing  of $1 million under an unsecured credit facility;
the  net  investment  of  approximately  $34.1  million  in  property, plant and
equipment; payments of approximately $40.9 million for the purchase of a portion
of  the  Company's outstanding Notes; payments of approximately $2.5 million for
the acquisition of treasury stock and dividends; and approximately $23.2 million
of  cash  provided  by  operations  during  the  year.

     On  December  13,  2002,  Standard & Poor's Rating Services ("S&P"), with a
negative  outlook,  lowered  its  corporate credit rating on the Company to CCC+
from  B,  and  its  rating  on the Notes to CCC- from CCC+. S&P stated that "the
ratings  downgrade  reflects  ECA's  burdensome  debt  leverage  with  limited,
near-term  prospects  for  significant  deleveraging  and  a  likely  decline in
liquidity  through  2003 as S&P expects ECA to outspend its internally generated
cash  flow.  Given  the  probable  cash  flow  generation


                                       20
<PAGE>
of  ECA's  properties,  it  may  be very challenging for the Company to continue
servicing  its  debt  while  averting  depletion."

     At  June 30, 2003, the Company's principal source of liquidity consisted of
$4.8  million  of  cash, $1 million available under an unsecured credit facility
currently  in  place,  plus  amounts  available  under  the  Foothill  Capital
Corporation  (Foothill)  Agreement. At June 30, 2003, $1 million was outstanding
or  committed  under  the  short-term  credit  facility  and  $39.2  million was
outstanding  under  the  Agreement.

     On  July  10,  2002, the Company entered into the Agreement with 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 certain 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 August
28, 2003, there are $38.9 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  estimated  to  be  greater  than  2.5  to  1.

     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,  cash generated by the sale of assets and interest expense. EBITDAX,
before  inclusion of the gain on the purchase of the Company's Notes, for fiscal
year  2003  was  $37.2 million. EBITDAX for fiscal years 2002 and 2001 was $19.7
million  and  $33.7  million,  respectively. See Note 17. Management anticipates
that  EBITDAX  from oil and gas operations for fiscal year 2004 will approximate
$50  million.  The  Company's ability to achieve EBITDAX of $50 million from oil
and gas operations for fiscal year 2004 is highly dependant on product price and
continued  drilling  success.  For  fiscal 2004, the Company is using an average
price  assumption of over $5 per Mcfe and production of approximately 14.0 Bcfe,
which  is  an  increase  of  approximately  35%  in  the  production  amount  of
approximately  10.4  Bcfe  in  fiscal year 2003. There can be no assurance given
that  the  Company  will  be able to achieve these goals. Although cash provided
from  oil  and  gas operations may not be sufficient to fully fund the Company's
fiscal  year  2004  projected  interest  charges  of  over  $15 million, capital
expenditures  program  of  $32 million, and other uses, management believes that
cash  generated  from  continuing  oil  and  gas  operations,  together with the
liquidity  provided by existing cash balances, permitted borrowings and the cash
proceeds  resulting  from  the  sale  of  certain  assets, will be sufficient to
satisfy  commitments for capital expenditures, debt service obligations, working
capital  needs  and  other  cash  requirements  for  the  next  fiscal  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  Notes  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.

     The  Company  believes that its existing capital resources and its expected
fiscal  year 2004 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


                                       21
<PAGE>
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,  2003  (in  thousands):

<TABLE>
<CAPTION>
                                           2004    2005    2006    Thereafter    Total
                                          ------  ------  -------  -----------  --------
<S>                                       <C>     <C>     <C>      <C>          <C>
      Senior subordinated notes           $    -  $    -  $     -  $   132,073  $132,073
      Installment notes payable              213   1,213   39,440          793    41,659
      Operating leases                       909   1,019      402        1,364     3,694
                                          ------  ------  -------  -----------  --------
      Total contractual cash obligations  $1,122  $2,232  $39,842  $   134,230  $177,426
                                          ======  ======  =======  ===========  ========
</TABLE>


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

     The  FASB and representatives of the accounting staff of the Securities and
Exchange  Commission  ("SEC") are currently engaged in discussions regarding the
application  of certain provisions of SFAS No. 141, "Business Combinations," and
SFAS  No.  142,  "Goodwill  and  Other  Intangible  Assets," to companies in the
extractive  industries,  including  oil  and gas companies. The FASB and the SEC
staff  are  considering  whether  the provisions of SFAS No. 141 and SFAS No.142
require  registrants to classify costs associated with mineral rights, including
both  proved  and  unproved lease acquisition costs, as intangible assets in the
balance  sheet,  apart  from  other  capitalized oil and gas property costs, and
provide  specific  footnote  disclosures. Historically, the Company has included
oil and gas lease acquisition costs as a component of oil and gas properties. In
the  event  the  FASB and SEC staff determine that costs associated with mineral
rights  are required to be classified as intangible assets, a portion of our oil
and  gas  property costs incurred since the June 30, 2001 effective date of SFAS
Nos.  141  and  142  would  be  separately  classified  on our balance sheets as
intangible  assets.  However, our results of operations and cash flows would not
be  affected  since  such  intangible  assets  would continue to be depleted and
assessed  for  impairment in accordance with successful efforts accounting rules
and  impairment  standards.

     Effective  July  1, 2002, the Company adopted SFAS No. 143, "Accounting for
Asset  Retirement  Obligations."  SFAS  No.  143  provides  the  accounting
requirements  for  retirement  obligations  associated  with tangible long-lived
assets.  When  the  liability  is initially recorded, the entity capitalizes the
cost,  thereby  increasing  the carrying amount of the related long-lived asset.
Over  time,  the  liability is accreted, and the capitalized cost is depreciated
over  the  useful  life  of  the  related  asset.

     For  the  Company,  asset  retirement  obligations  primarily relate to the
abandonment  of oil and gas producing facilities. While assets such as pipelines
and  gas  marketing  assets  may have retirement obligations covered by SFAS No.
143, certain of those obligations are not recognized since the fair value cannot
be  estimated  due  to the uncertainty of the settlement date of the obligation.

     The  initial  application  of this accounting standard by ECA as of July 1,
2002,  resulted  in  an  increase  in net plant assets of $0.4 million, an asset
retirement  obligation  liability  of $0.5 million, and a cumulative effect of a
change  in  accounting principle of $0.1 million. Due to a change in estimate by


                                       22
<PAGE>
ECA  in  fiscal  year  2003  regarding SFAS No. 143, the initial application was
changed to an asset retirement obligation liability of $0.7 million, a net plant
asset  increase  of  $0.6  million,  and  a  cumulative  effect  of  a change in
accounting  principle  of  $0.1  million  as  of  June  30,  2003.

     (IN THOUSANDS)
     --------------
     ASSET RETIREMENT OBLIGATIONS AS OF JULY 1, 2002:                    $  471

          Liabilities  incurred:
              Additional  wells  drilled                                    181

          Liabilities  settled:
              Reduction  for  wells  sold                                   (86)

          Accretion expense (included in depletion, deprec.,
          amortiz.-other)                                                    33

          Change  in  estimate                                              125
                                                                         -------

     Asset retirement obligations as of June 30, 2003                    $  724
                                                                         =======


     In  July  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for Costs
Associated  with Exit or Disposal Activities" This Statement addresses financial
accounting  and  reporting for costs associated with exit or disposal activities
and  nullifies  EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination  Benefits  and  Other  Costs  to Exit an Activity (including Certain
Costs  Incurred  in a Restructuring)".  This Statement requires recognition of a
liability  for  a  cost  associated  with  an exit or disposal activity when the
liability  is  incurred,  as  opposed to when the entity commits to an exit plan
under  EITF  No.  94-3.  SFAS  No. 146 is to be applied prospectively to 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.

     In  December  2002,  the  FASB  approved  Statement of Financial Accounting
Standards  No.  148,  "Accounting  for Stock-Based Compensation - Transition and
Disclosure  -  an  amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No.
148  amends Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based  Compensation"  (SFAS  No.  123)  to  provide alternative methods of
transition  for  a voluntary change to the fair value based method of accounting
for  stock-based  employee  compensation.  In  addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual  and  interim  financial  statements  about  the method of accounting for
stock-based  employee compensation and the effect of the method used on reported
results.  SFAS  No.  148  is effective for financial statements for fiscal years
ending after December 15, 2002. 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".

     In  April  2003,  FASB  issued SFAS No. 149, "Amendment of Statement 133 on
Derivative  Instruments  and  Hedging Activities" to amend and clarify financial
accounting  and  reporting  for  derivative  instruments,  including  certain
derivative instruments embedded in other contracts for hedging activities.  This
Statement  is  effective  for  contracts entered into or modified after June 30,
2003,  and for hedging relationships designated after June 30, 2003.  Management
believes  SFAS  No.  149  has  no  material  impact  on  the Company's financial
condition  or  results of operation as of June 30, 2003.  The Company will adopt
this  Statement  as  of  July  1,  2003.


                                       23
<PAGE>
     In May 2003 the FASB issued Statement of Financial Accounting Standards No.
150,  "Accounting for Certain Financial Instruments with Characteristics of both
Liabilities  and  Equity".  SFAS No. 150 establishes standards for how an issuer
classifies  and  measures  certain financial instruments with characteristics of
both  liabilities  and equity, and will require instruments that fall within the
scope  of this pronouncement to be classified as liabilities.  This statement is
effective for financial instruments entered into or modified after May 31, 2003,
and  otherwise  is  effective  at  the  beginning  of  the  first interim period
beginning  after  June  15,  2003.  The Company does not believe the adoption of
this  statement  will have a material effect on the Company's financial position
or  results  of  operations.

     In  November  2002,  the  FASB  issued  Financial  Interpretation  No.  45,
"Guarantor's  Accounting  and  Disclosure Requirements for Guarantees, including
Indirect  Guarantee  of  Indebtedness of Others" (FIN 45).  FIN 45 requires that
upon  issuance  of a guarantee, the guarantor must recognize a liability for the
fair  value  of  the  obligation  it  assumes  under  that  guarantee.  FIN 45's
provisions  for  initial  recognition  and  measurement  should  be applied on a
prospective basis to guarantees issued or modified after December 31, 2002.  The
guarantor's  previous accounting for guarantees that were issued before the date
of  FIN  45's  initial application may not be revised or restated to reflect the
effect of the recognition and measurement provisions of the Interpretation.  The
disclosure  requirements  are effective for financial statements of both interim
and  annual periods that end after December 15, 2002.  The Company's adoption of
FIN  45  on  January l, 2003 did not effect its financial position or results of
operations.

     In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of  Variable  Interest  Entities" (FIN 46).  FIN 46 clarifies the application of
Accounting  Research  Bulletin  No.  51,  "Consolidated Financial Statements" to
certain  entities in which equity investors do not have the characteristics of a
controlling  financial interest or do not have sufficient equity at risk for the
entity  to  finance  its activities without additional subordinated support from
other  parties.  FIN  46  requires  existing  unconsolidated  variable  interest
entities  to  be  consolidated by their primary beneficiaries if the entities do
not  effectively  disperse  risks  among  parties  involved.  All companies with
variable interests in variable interest entities created after January 31, 2003,
shall  apply  the provisions of FIN 46 to those entities immediately.  FIN 46 is
effective  for  the first fiscal year or interim period beginning after June 15,
2003,  for  variable  interest  entities  created  before February 1, 2003.  The
Company  will  prospectively  apply the provisions of FIN 46 that were effective
January  31,  2003.


              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  various  transactions,  covering


                                       24
<PAGE>
approximately  55%  to  65% of its estimated natural gas production through June
2004  and 25% to 35% of its estimated natural gas production for the fiscal year
ended  June  2005.

<TABLE>
<CAPTION>
As  of  June  30,  2003, the Company's open gas derivative instruments and fixed
price  delivery  contracts  were  as  follows:

                                                       Total     Average
                                          Market      Volumes    Contract      Unrealized
                 Time period              Index       (MMBtu)      Price     (Gains) Losses
     ---------------------------------  ----------  -----------  ---------  ----------------
<S>                                     <C>         <C>          <C>        <C>
     Derivatives:

        Natural Gas Swaps

            July 2003 - March 2004      NYMEX           720,000  $    6.32  $      (456,385)

            July 2003 - June 2004       NYMEX         1,098,000       4.05        1,479,305

            July 2004 - June 2005       NYMEX         3,240,000       4.54        1,319,482
                                                    -----------             ----------------

            Unrealized (Gains) Losses                 5,058,000                 $ 2,342,402
                                                    -----------             ================

     Physical Contracts:

        Fixed Price Delivery Contracts

            July 2003 - June 2004                     5,735,500  $    4.50

            July 2003 - June 2004                       338,250       4.85
                                                    -----------

     Total                                           11,131,750
                                                    ===========
</TABLE>

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  or  subject  to  fixed price contracts remain at June 2003 levels, a 10%
change  in the average unhedged prices realized during the year would change the
Company's gas and oil revenues by approximately $1.5 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, 2003, all but $40.2 million 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.  Assuming the variable interest debt remained
at  the June, 2003 level, a 10% change in rates would have a $0.3 million impact
on  interest expense on an annual basis.  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


                                       25
<PAGE>
the  period.  Gains  and  losses resulting from foreign currency translation are
included  as  a  component  of  other  comprehensive  income.

                                    * * * * *


                                       26
<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, 2003 and 2002, and the
related consolidated statements of operations, stockholders' equity, cash flows,
and  comprehensive  income  for each of the three years in the period ended June
30,  2003.  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, 2003 and 2002, and the results of their operations
and  their  cash  flows for each of the three years in the period ended June 30,
2003  in  conformity with accounting principles generally accepted in the United
States  of  America.

As  discussed  in  Note  2 to the consolidated financial statements, in 2001 the
Company adopted Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and in 2003 adopted Statement
of  Financial  Accounting  Standards  No.  143, "Accounting for Asset Retirement
Obligations".





DELOITTE  &  TOUCHE  LLP
Denver,  Colorado
August  29,  2003


                                       27
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------


ASSETS                                            2003       2002
                                                ---------  ---------
<S>                                             <C>        <C>
CURRENT ASSETS:
   Cash and cash equivalents                    $  4,831   $ 17,775
   Accounts receivable:
     Oil and gas sales                            10,380      7,284
     Gas marketing and pipeline                    9,458      5,323
     Other                                         4,616      6,924
                                                ---------  ---------
         Accounts receivable                      24,454     19,531
   Less allowance for doubtful accounts           (1,616)    (1,366)
                                                ---------  ---------
         Accounts receivable net of allowance     22,838     18,165

   Income taxes receivable                             -      1,596
   Deferred income tax asset                          41      2,237
   Deferred taxes - comprehensive income             787          -
   Derivatives                                         -        454
   Prepaid and other current assets                3,019      4,234
                                                ---------  ---------
         Total current assets                     31,516     44,461

NET PROPERTY, PLANT AND EQUIPMENT (Note 2)       253,270    244,155
                                                ---------  ---------

OTHER ASSETS:
   Deferred financing costs, less accumulated
     amortization of $4,728 and $3,722             3,098      3,617
   Other                                           7,950     12,503
                                                ---------  ---------
         Total other assets                       11,048     16,120
                                                ---------  ---------

TOTAL                                           $295,834   $304,736
                                                =========  =========
</TABLE>

See notes to consolidated financial statements.          (Continued)


                                       28
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------

LIABILITIES AND STOCKHOLDERS' EQUITY                          2003       2002
                                                            ---------  ---------
<S>                                                         <C>        <C>
CURRENT LIABILITIES:
  Accounts payable and accrued expenses                     $ 13,734   $ 15,683
  Current portion of long-term debt                              133        121
  Funds held for future distribution                          17,217     11,414
  Income taxes payable                                         1,484          -
  Accrued taxes, other than income                             9,643      8,221
  Deferred taxes - comprehensive income                            -        180
  Derivatives                                                    810          -
  Other current liabilities                                    1,421      7,078
                                                            ---------  ---------
     Total current liabilities                                44,442     42,697
LONG-TERM OBLIGATIONS:
  Long-term debt                                             173,197    198,701
  Gas delivery obligation and deferred trust revenue           2,917      5,886
  Deferred income tax liability                               20,376      9,887
  Derivatives                                                  1,319          -
  Other long-term obligations                                  8,311      8,689
                                                            ---------  ---------
     Total liabilities                                       250,562    265,860
                                                            ---------  ---------

COMMITMENTS AND CONTINGENCIES (Note 15)

  Minority interest                                            1,594      1,732

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 shares issued                       5,092      5,092
  Additional paid-in capital                                   5,503      5,503
  Retained earnings                                           45,150     36,422
  Treasury stock and notes receivable arising from
     issuance of common stock                                (11,824)   (10,426)
  Accumulated other comprehensive loss                          (973)      (177)
                                                            ---------  ---------
        Total stockholders' equity                            43,678     37,144
                                                            ---------  ---------
TOTAL                                                       $295,834   $304,736
                                                            =========  =========
</TABLE>


See notes to consolidated financial statements.


                                       29
<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)
--------------------------------------------------------------------------------------------------------------------
                                                                                       2003       2002       2001
                                                                                     ---------  ---------  ---------
<S>                                                                                  <C>        <C>        <C>
REVENUES:
  Oil and gas sales                                                                  $ 51,410   $ 38,939   $ 41,555
  Gas marketing and pipeline sales                                                     60,483     41,209     81,042
  Well operations and service revenues                                                  5,498      5,490      5,899
  Other                                                                                    35        504      1,455
                                                                                     ---------  ---------  ---------
                                                                                      117,426     86,142    129,951
                                                                                     ---------  ---------  ---------
COSTS AND EXPENSES:
  Field operating expenses                                                             10,128     10,916      8,910
  Gas marketing and pipeline cost of sales                                             53,693     37,489     77,167
  General and administrative                                                           15,437     17,360     12,804
  Taxes, other than income                                                              3,287      2,175      3,389
  Depletion and depreciation of oil and gas properties                                 12,140     12,362      9,290
  Depreciation of pipelines, other property and equipment                               4,294      2,934      2,763
  Exploration and impairment                                                           11,729     27,694     19,014
                                                                                     ---------  ---------  ---------
                                                                                      110,708    110,930    133,337
                                                                                     ---------  ---------  ---------
     Income (loss) from operations                                                      6,718    (24,788)    (3,386)
                                                                                     ---------  ---------  ---------
OTHER (INCOME) AND EXPENSE:
  Interest expense                                                                     16,383     19,671     20,094
  (Gain) loss on sale of assets                                                           433       (319)      (211)
  Interest income and other                                                           (25,848)    (1,135)    (5,838)
                                                                                     ---------  ---------  ---------
                                                                                       (9,032)    18,217     14,045
                                                                                     ---------  ---------  ---------
Income (loss) from continuing operations before income taxes and minority interest     15,750    (43,005)   (17,431)
Income tax expense (benefit)                                                            6,073    (16,822)    (7,232)
                                                                                     ---------  ---------  ---------
Income (loss) from continuing operations before minority interest                       9,677    (26,183)   (10,199)
Minority interest                                                                         240          3          -
                                                                                     ---------  ---------  ---------
Income (loss) from continuing operations                                                9,917    (26,180)   (10,199)
Disposal of utility operations:
    Loss from utility operations, net of tax                                                -          -     (1,847)
    Gain on sale of utility, net of tax                                                     -          -     84,402
                                                                                     ---------  ---------  ---------
    Net income from disposal of utility operations                                          -          -     82,555
                                                                                     ---------  ---------  ---------
Income (loss) before cumulative effect of changes in accounting principle:              9,917    (26,180)    72,356

  Change in accounting principle, net of tax                                              (73)         -          -
                                                                                     ---------  ---------  ---------

NET INCOME (LOSS)                                                                    $  9,844   $(26,180)  $ 72,356
                                                                                     =========  =========  =========

Earnings (loss) per common share, basic:
  Income (loss) from continuing operations                                           $  15.23   $ (39.80)  $ (15.34)
  Discontinued operations                                                                   -          -     124.20
  Change in accounting principle, net of tax                                            (0.11)         -          -
                                                                                     ---------  ---------  ---------
  Basic earnings (loss) per common share                                             $  15.12   $ (39.80)  $ 108.86
                                                                                     =========  =========  =========
Earnings (loss) per common share, diluted:
  Income (loss) from continuing operations                                           $  14.90   $ (39.80)  $ (15.34)
  Discontinued operations                                                                   -          -     124.20
  Change in accounting principle, net of tax                                            (0.11)         -          -
                                                                                     ---------  ---------  ---------
  Diluted earnings (loss) per common share                                           $  14.79   $ (39.80)  $ 108.86
                                                                                     =========  =========  =========
See notes to consolidated financial statements.
</TABLE>


                                       30
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERSEQUITY
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, 2000                   $   718  $  2,940  $     4,615  $  (4,833)  $  (6,284)  $         (1,145)
  Comprehensive income                                                      72,356
  Dividends                                                                 (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  $  63,653   $  (8,204)  $         (1,089)
                                         =======  ========  ===========  ==========  ==========  =================
  Comprehensive Loss                                                       (26,180)
  Dividends                                                                 (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)
                                         =======  ========  ===========  ==========  ==========  =================
  Comprehensive income (loss)                                                9,844
  Dividends                                                                 (1,116)
  Purchase of treasury stock - common                                                     (854)
  Purchase of treasury stock - Class A                                                    (639)
  Reduction of notes receivable                                                                                95
                                         -------  --------  -----------  ----------  ----------  -----------------
Balance, June 30, 2003                   $   730  $  5,092  $     5,503  $  45,150   $ (11,530)  $           (294)
                                         =======  ========  ===========  ==========  ==========  =================


                                          Accum. Other
                                          Comprehensive    Stockholders
                                          Income (Loss)       Equity
                                         ---------------  --------------
<S>                                      <C>              <C>
Balance June, 30, 2000                   $         (134)  $      (4,123)
  Comprehensive income                              635          72,991
  Dividends                                                      (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                   $          501   $      64,826
                                         ===============  ==============
  Comprehensive Loss                               (678)        (26,858)
  Dividends                                                      (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
                                         ===============  ==============
  Comprehensive income (loss)                      (796)          9,048
  Dividends                                                      (1,116)
  Purchase of treasury stock - common                              (854)
  Purchase of treasury stock - Class A                             (639)
  Reduction of notes receivable                                      95
                                         ---------------  --------------
Balance, June 30, 2003                   $         (973)  $      43,678
                                         ===============  ==============
</TABLE>

See notes to consolidated financial statements.


                                       31
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
--------------------------------------------------------------------------------------------------------------------
                                                                                      2003       2002        2001
                                                                                    ---------  ---------  ----------
<S>                                                                                 <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Income (loss) from continuing operations                                            $  9,917   $(26,180)  $ (10,199)
  Adjustments to reconcile net income (loss) to net cash provided (used) by
    operating activities:
       Depletion, depreciation and amortization                                       16,434     16,031      12,911
       (Gain) loss on sale of assets                                                     433       (319)       (211)
       Gain on redemption of senior bonds                                            (23,672)         -           -
       Deferred income taxes                                                          12,685    (12,492)     28,359
       Exploration and impairment                                                     11,508     27,227      18,591
       Other, net                                                                      2,563      2,322      (4,711)
                                                                                    ---------  ---------  ----------
                                                                                      29,868      6,589      44,740
Changes in assets and liabilities:
    Accounts receivable                                                               (4,817)     3,187      (2,936)
    Gas in storage                                                                      (196)       870        (304)
    Income taxes                                                                       3,080     (2,066)    (33,821)
    Prepaid and other assets                                                          (1,364)    (1,900)        (32)
    Accounts payable                                                                    (627)    (2,218)      6,341
    Funds held for future distributions                                                5,803     (3,253)      1,678
    Other                                                                             (8,521)   (23,405)     14,631
                                                                                    ---------  ---------  ----------
       Net cash provided (used) by operating activities from continuing operations    23,226    (22,196)     30,297
       Net cash used by operating activities from disposed operations                      -          -     (48,335)
                                                                                    ---------  ---------  ----------
       Net cash provided (used) by operating activities                               23,226    (22,196)    (18,038)
                                                                                    ---------  ---------  ----------
CASH FLOWS FROM INVESTING ACTIVITIES
    Expenditures for property, plant and equipment                                   (37,632)   (38,294)   (112,863)
    Proceeds from sale of assets                                                       3,532        704       1,517
    Notes receivable and other                                                         1,259         86      (4,192)
                                                                                    ---------  ---------  ----------
       Net cash used by investing activities from continuing operations              (32,841)   (37,504)   (115,538)
       Net cash provided by investing activities from disposed operations                  -          -     224,765
                                                                                    ---------  ---------  ----------
       Net cash (used) provided by investing activities                              (32,841)   (37,504)    109,227
                                                                                    ---------  ---------  ----------
CASH FLOWS FROM FINANCING ACTIVITIES
    Proceeds from long-term debt                                                      72,635          -       7,825
    Principal payment on long-term debt                                              (73,434)      (145)    (21,850)
    Proceeds (payment) on short-term borrowing                                             -          -      (2,000)
    Purchase of treasury stock and other financing activities                         (1,447)    (1,663)     (1,072)
    Dividends paid                                                                    (1,083)    (1,053)     (3,605)
                                                                                    ---------  ---------  ----------
       Net cash used by financing activities from continuing operations               (3,329)    (2,861)    (20,702)
       Net cash provided by financing activities from disposed operations                  -          -       6,539
                                                                                    ---------  ---------  ----------
       Net cash used by financing activities                                          (3,329)    (2,861)    (14,163)
                                                                                    ---------  ---------  ----------
       Net (decrease) increase in cash and cash equivalents                          (12,944)   (62,561)     77,026
       Cash and cash equivalents, beginning of period                                 17,775     80,336       3,310
                                                                                    ---------  ---------  ----------
Cash and cash equivalents, end of period                                            $  4,831   $ 17,775   $  80,336
                                                                                    =========  =========  ==========
See notes to consolidated financial statements.
</TABLE>


                                       32
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
-------------------------------------------------------------------------------

                                                    2003      2002       2001
                                                  --------  ---------  --------
<S>                                               <C>       <C>        <C>

Net income (loss)                                 $ 9,844   $(26,180)  $72,356
                                                  --------  ---------  --------
Other comprehensive income (loss), net of tax:
    Foreign currency translation adjustment:
       Current period change                          854      1,627    (1,980)
    Marketable securities:
       Unrealized gain (loss)                          (5)      (102)      136
       Reclassification to earnings                   (25)        (4)
    Oil and gas derivatives:
       Net cumulative effect adjustment                 -          -    (2,153)
       Current period transactions                 (2,351)     1,999      (541)
       Reclassification to earnings                   731     (4,198)    5,173
                                                  --------  ---------  --------
Other comprehensive income (loss), net of tax        (796)      (678)      635
                                                  --------  ---------  --------
Comprehensive income (loss)                       $ 9,048   $(26,858)  $72,991
                                                  ========  =========  ========
</TABLE>

See notes to consolidated financial statements.


                                       33
<PAGE>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2003, 2002 AND 2001
--------------------------------------------------------------------------------

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  17.

     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, but does not
     otherwise  have  the ability to control. 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


                                       34
<PAGE>
     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.

     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  forty  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>
                                                                    2003        2002
                                                                 ----------  ----------
<S>                                                              <C>         <C>
      Oil and gas properties                                     $ 337,904   $ 320,148
      Pipelines                                                     20,594      20,703
      Other property and equipment                                  23,537      19,598
                                                                 ----------  ----------
                                                                   382,035     360,449
      Less accumulated depletion, depreciation and amortization   (128,765)   (116,294)
                                                                 ----------  ----------
      Net property, plant and equipment                          $ 253,270   $ 244,155
                                                                 ==========  ==========
</TABLE>

     Long-Lived  Assets  -  Statement of Financial Accounting Standards ("SFAS")
     ------------------
     No.  144,  "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,  2003,  the  Company  recognized impairment of oil and gas
     property  of  approximately  $3.1  million.  During  fiscal  year  2002, in
     addition  to  the impairment of oil and gas property of approximately $19.3
     million,  the Company recognized impairment expense of $0.1 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 translation
     adjustment  is  included  in  stockholders'  equity as a component of other
     comprehensive  income.

     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".


                                       35
<PAGE>
     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.

     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.

     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 and Texas. 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, 2003,
     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.

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

     Recent  Accounting  Pronouncements  -  The  FASB and representatives of the
     ----------------------------------
     accounting  staff  of  the  Securities  and Exchange Commission ("SEC") are
     currently  engaged  in  discussions  regarding  the  application of certain
     provisions  of  SFAS  No.  141,  "Business Combinations," and SFAS No. 142,
     "Goodwill  and  Other  Intangible  Assets,"  to companies in the extractive
     industries, including oil and gas companies. The FASB and the SEC staff are
     considering  whether the provisions of SFAS No. 141 and SFAS No.142 require
     registrants  to  classify  costs  associated with mineral rights, including
     both  proved  and unproved lease acquisition costs, as intangible assets in
     the balance sheet, apart from other capitalized oil and gas property costs,
     and  provide  specific  footnote disclosures. Historically, the Company has
     included  oil and gas lease acquisition costs as a component of oil and gas
     properties.  In  the  event  the  FASB  and  SEC staff determine that costs
     associated  with mineral rights are required to be classified as intangible
     assets, a portion of our oil and gas property costs incurred since the June
     30,  2001  effective  date  of  SFAS  Nos.  141 and 142 would be separately


                                       36
<PAGE>
     classified on our balance sheets as intangible assets. However, our results
     of  operations  and  cash flows would not be affected since such intangible
     assets  would  continue  to  be  depleted  and  assessed  for impairment in
     accordance  with  successful  efforts  accounting  rules  and  impairment
     standards.

     Effective  July  1, 2002, the Company adopted SFAS No. 143, "Accounting for
     Asset  Retirement  Obligations."  SFAS  No.  143  provides  the  accounting
     requirements for retirement obligations associated with tangible long-lived
     assets.  When  the  liability is initially recorded, the entity capitalizes
     the  cost, thereby increasing the carrying amount of the related long-lived
     asset.  Over  time,  the liability is accreted, and the capitalized cost is
     depreciated  over  the  useful  life  of  the  related  asset.

     For  the  Company,  asset  retirement  obligations  primarily relate to the
     abandonment  of  oil  and  gas  producing  facilities. While assets such as
     pipelines  and  marketing assets may have retirement obligations covered by
     SFAS  No.  143,  certain  of those obligations are not recognized since the
     fair  value  cannot  be  estimated due to the uncertainty of the settlement
     date  of  the  obligation.

     The  initial  application  of this accounting standard by ECA as of July 1,
     2002, resulted in an increase in net plant assets of $0.4 million, an asset
     retirement obligation liability of $0.5 million, and a cumulative effect of
     a  change  in  accounting  principle  of  $0.1  million. Due to a change in
     estimate  by  ECA  in  fiscal year 2003 regarding SFAS No. 143, the initial
     application was changed to an asset retirement obligation liability of $0.7
     million,  a  net  plant  asset  increase  of $0.6 million, and a cumulative
     effect  of  a change in accounting principle of $0.1 million as of June 30,
     2003.

     (IN THOUSANDS)
     --------------
     ASSET RETIREMENT OBLIGATIONS AS OF JULY 1, 2002:                    $  471

          Liabilities  incurred:
                 Additional  wells  drilled                                 181

          Liabilities  settled:
                 Reduction  for  wells  sold                                (86)

          Accretion expense (included in depletion, deprec.,
          amortiz.-other)                                                    33

          Change  in  estimate                                              125
                                                                         -------

     Asset retirement obligations as of June 30, 2003                    $  724
                                                                         =======


     In  July  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for Costs
     Associated  with  Exit  or  Disposal  Activities"  This Statement addresses
     financial  accounting  and  reporting  for  costs  associated  with exit or
     disposal  activities  and  nullifies  EITF  Issue  No.  94-3,  "Liability
     Recognition  for  Certain  Employee Termination Benefits and Other Costs to
     Exit  an  Activity  (including Certain Costs Incurred in a Restructuring)".
     This  Statement  requires  recognition of a liability for a cost associated
     with  an  exit  or  disposal  activity  when  the liability is incurred, as
     opposed  to  when  the  entity commits to an exit plan under EITF No. 94-3.
     SFAS  No. 146 is to be applied prospectively to 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.

     In  December  2002,  the  FASB  approved  Statement of Financial Accounting
     Standards  No.  148,  "Accounting for Stock-Based Compensation - Transition
     and  Disclosure  -  an amendment of FASB


                                       37
<PAGE>
     Statement  No.  123"  (SFAS  No.  148).  SFAS  No.  148 amends Statement of
     Financial  Accounting  Standards  No.  123,  "Accounting  for  Stock-Based
     Compensation"  (SFAS  No. 123) to provide alternative methods of transition
     for  a  voluntary  change  to the fair value based method of accounting for
     stock-based  employee  compensation.  In  addition, SFAS No. 148 amends the
     disclosure requirements of SFAS No. 123 to require prominent disclosures in
     both annual and interim financial statements about the method of accounting
     for  stock-based employee compensation and the effect of the method used on
     reported  results.  SFAS  No. 148 is effective for financial statements for
     fiscal  years  ending  after December 15, 2002. 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".

     In  April  2003,  FASB  issued SFAS No. 149, "Amendment of Statement 133 on
     Derivative  Instruments  and  Hedging  Activities"  to  amend  and  clarify
     financial  accounting  and  reporting for derivative instruments, including
     certain  derivative  instruments  embedded  in  other contracts for hedging
     activities.  This  Statement  is  effective  for  contracts entered into or
     modified  after  June  30,  2003,  and for hedging relationships designated
     after  June  30,  2003.  Management  believes  SFAS No. 149 has no material
     impact  on  the Company's financial condition or results of operation as of
     June  30,  2003.  The Company will adopt this Statement as of July 1, 2003.

     In May 2003 the FASB issued Statement of Financial Accounting Standards No.
     150,  "Accounting for Certain Financial Instruments with Characteristics of
     both Liabilities and Equity". SFAS No. 150 establishes standards for how an
     issuer  classifies  and  measures  certain  financial  instruments  with
     characteristics  of  both  liabilities  and  equity,  and  will  require
     instruments  that  fall  within  the  scope  of  this  pronouncement  to be
     classified  as  liabilities.  This  statement  is  effective  for financial
     instruments  entered  into or modified after May 31, 2003, and otherwise is
     effective at the beginning of the first interim period beginning after June
     15,  2003. The Company does not believe the adoption of this statement will
     have  a  material  effect on the Company's financial position or results of
     operations.

     In  November  2002,  the  FASB  issued  Financial  Interpretation  No.  45,
     "Guarantor's  Accounting  and  Disclosure  Requirements  for  Guarantees,
     including  Indirect  Guarantee  of Indebtedness of Others" (FIN 45). FIN 45
     requires  that upon issuance of a guarantee, the guarantor must recognize a
     liability  for  the  fair  value  of  the  obligation it assumes under that
     guarantee.  FIN  45's  provisions  for  initial recognition and measurement
     should  be  applied on a prospective basis to guarantees issued or modified
     after December 31, 2002. The guarantor's previous accounting for guarantees
     that were issued before the date of FIN 45's initial application may not be
     revised  or  restated  to  reflect  the  effect  of  the  recognition  and
     measurement  provisions  of the Interpretation. The disclosure requirements
     are  effective  for financial statements of both interim and annual periods
     that  end  after  December  15,  2002.  The Company's adoption of FIN 45 on
     January  l,  2003  did  not  effect  its  financial  position or results of
     operations.  In  January  2003, the FASB issued FASB Interpretation No. 46,
     "Consolidation  of  Variable  Interest Entities" (FIN 46). FIN 46 clarifies
     the  application  of  Accounting  Research  Bulletin  No. 51, "Consolidated
     Financial  Statements" to certain entities in which equity investors do not
     have the characteristics of a controlling financial interest or do not have
     sufficient  equity at risk for the entity to finance its activities without
     additional  subordinated  support  from  other  parties.  FIN  46  requires
     existing  unconsolidated  variable  interest entities to be consolidated by
     their  primary  beneficiaries  if  the entities do not effectively disperse
     risks  among  parties  involved.  All  companies with variable interests in
     variable  interest entities created after January 31, 2003, shall apply the
     provisions of FIN 46 to those entities immediately. FIN 46 is effective for
     the  first fiscal year or interim period


                                       38
<PAGE>
     beginning  after  June  15,  2003,  for  variable interest entities created
     before  February  1,  2003.  The  Company  will  prospectively  apply  the
     provisions  of  FIN  46  that  were  effective  January  31,  2003.

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

<TABLE>
<CAPTION>
                                                      2003      2002     2001
                                                    --------  --------  -------
<S>                                                 <C>       <C>       <C>
      Cash paid for:
        Interest                                    $16,383   $18,935   $19,210
        Income taxes                                     15       114    37,983
      Income taxes refunded                          (9,809)     (111)        -
      Noncash investing and financing activities:
         Dividends declared and unpaid at year end      297       262       265
         Liabilities assumed in acquisition               -         -       824
</TABLE>


3.   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.

     On  February  5, 2003, the Company purchased certain oil and gas properties
     located  in  southern  West  Virginia  for  $5.6  million,  after  certain
     adjustments. The purchase included proved developed producing gas reserves,
     estimated  at  4  Bcf,  90  producing  wells  and  over  30,000  acres.

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 year ended
     June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                               2001 (1)
                                              ---------
<S>                                           <C>
      Net sales                               $  9,929
                                              ---------
      Loss before income taxes                  (3,164)
      Income taxes benefit                      (1,317)
                                              ---------
      Loss from discontinued operations       $ (1,847)
                                              =========
<FN>

     (1)  Discontinued operations for one and one half months in fiscal year
          2001
</TABLE>


                                       39
<PAGE>
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,  2003 are designated as cash flow hedges. 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 had 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.  At June 30, 2003, the Company had swap agreements maturing
     from July 2003 through June 2005 covering 5,058,000 Mmbtu. At June 30, 2003
     the  company  had  recorded  a  $1.3  million  loss  in  accumulated  other
     comprehensive  income,  $0.8  million of short term derivative liabilities,
     $1.3  million  in  long  term  derivative  liabilities  and $0.8 million in
     deferred  tax  asset.

     For  the  year  ended  June  30,  2003 the Company recognized a net loss in
     revenues  on  its  natural  gas hedging activities of $1.2 million. 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 and a net loss of $8.3
     million  for  the year ended June 30, 2001. The estimated net amount of the
     existing  losses  within other comprehensive income that are expected to be
     reclassified  into  earnings within the next twelve months is approximately
     $0.5  million.

6.   DEBT

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

<TABLE>
<CAPTION>
                                                                            2003       2002
                                                                          ---------  ---------
<S>                                                                       <C>        <C>
      ECA senior subordinated notes, interest at 9.5% payable
        semi-annually, due May 15, 2007                                   $132,073   $197,672
      Revolving credit agreements, variable rates                           40,227          -
      Installment notes payable, at imputed interest rates ranging from
        from 8.0% to 9.5%                                                    1,030      1,150
                                                                          ---------  ---------
                                                                           173,330    198,822
      Less current portion                                                    (133)      (121)
                                                                          ---------  ---------
                                                                          $173,197   $198,701
                                                                          =========  =========
</TABLE>

     The  Company's  debt agreements contain 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.


                                       40
<PAGE>
     Scheduled  maturities  of the Company's long-term debt at June 30, 2003 for
     each  of  the next five years and thereafter are as follows (in thousands):

<TABLE>
<CAPTION>
<S>                                               <C>
     2004                                         $    213
     2005                                            1,213
     2006                                           39,440
     2007                                          132,182
     2008                                              100
      Thereafter                                       584
                                                  --------
      Total payments                               173,732
      Less:  imputed interest                          402
                                                  --------
      Present value of scheduled maturities       $173,330
                                                  ========
</TABLE>

     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.

     For  the year ended June 30, 2003 the Company purchased approximately $65.6
     million  of  the  Notes  that  resulted  in  a  gain  of  $23.7  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 then existing oil and gas
     assets  of  the  Company  at  the  time the Agreement was entered into. 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 August 28, 2003, there are currently
     $38.9  million  in  outstanding  borrowings  under  the  Agreement.

     Other  Credit  Facilities  - The Company has an unsecured revolving line of
     ------------------------
     credit  totaling $2.0 million with a financial institution with an interest
     rate  of prime plus 0.25%, which expires June 30, 2005. As of June 30, 2003
     there was $1.0 million outstanding under the line of credit with no amounts
     outstanding  as  of  June  30,  2002.

     Other  Notes - In December 2000 the Company assumed a note which stipulated
     ------------
     that 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, 2003 and
     2002,  the  balance  due  was  $1.1  million  and  $1.2  respectively.

     The  Company purchased certain pipelines during 1998 constituting a natural
     gas  gathering  system  in the State of West Virginia. The Company paid 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, 2003 and 2002, the balance due to the seller was $0.3
     and  $0.5  million  respectively.


                                       41
<PAGE>
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>
                                                      2003      2002       2001
                                                    --------  ---------  ---------
<S>                                                 <C>       <C>        <C>
      Current:
        Federal                                     $(6,610)  $ (3,436)  $(27,749)
        State                                            (2)     1,385     (7,842)
                                                    --------  ---------  ---------
        Total current                                (6,612)    (2,051)   (35,591)
                                                    --------  ---------  ---------
      Deferred:
        Federal                                      11,502    (13,381)    23,115
        State                                         1,183     (1,390)     5,244
                                                    --------  ---------  ---------
        Total deferred                               12,685    (14,771)    28,359
                                                    --------  ---------  ---------
        Total provision (benefit) for income taxes  $ 6,073   $(16,822)  $ (7,232)
                                                    ========  =========  =========
</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 from continuing operations for the years ended June
     30  is  summarized  below  (in  thousands):

<TABLE>
<CAPTION>
                                                              2003      2002       2001
                                                             -------  ---------  --------
<S>                                                          <C>      <C>        <C>
      Tax provision (benefit) at the federal statutory rate  $5,513   $(15,051)  $(6,101)
      State taxes, net of federal tax effects                   663     (2,516)   (1,151)
      Effect of rate change                                      12        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)
      Investment tax credit expiration
      Other, net                                               (115)     2,690     2,473
                                                             -------  ---------  --------
      Provision (benefit) for income taxes                   $6,073   $(16,822)  $(7,232)
                                                             =======  =========  ========
</TABLE>


                                       42
<PAGE>
     Components of the Company's deferred tax assets and liabilities, as of June
     30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                               2003       2002
                                             ---------  ---------
<S>                                          <C>        <C>
       Deferred tax assets:
         Royalty trust agreements            $  4,640   $  7,830
         Tax credits and carryforwards          7,795     10,113
         Other                                  2,512      3,874
                                             ---------  ---------
           Total deferred tax assets           14,947     21,817
                                             ---------  ---------
       Deferred tax liabilities:
         Property, plant and equipment        (28,920)   (25,249)
         Other liabilities                     (6,362)    (4,218)
                                             ---------  ---------
           Total deferred tax liabilities     (35,282)   (29,467)
                                             ---------  ---------

       Net deferred income tax liability      (20,335)    (7,650)
       Current deferred tax asset                  41      2,237
                                             ---------  ---------
       Net long-term deferred tax liability  $(20,376)  $ (9,887)
                                             =========  =========
</TABLE>

<TABLE>
<CAPTION>
At  June  30,  2003 and 2002 the Company has the following federal and state tax
credits  and  carryforwards  (in  thousands):     2003                2002
                                                     Year of              Year of
                                           Amount   Expiration  Amount   Expiration
                                           -------  ----------  -------  ----------
<S>                                        <C>      <C>         <C>      <C>
  AMT tax credits                          $ 4,444  None        $ 9,355   None
  Charitable Contribution Carryover              3  2007-2008         -
                                           -------              -------
  Total federal credits and carryforwards  $ 4,447              $ 9,355
                                           =======              =======

  State net operating loss carryovers      $ 3,348  2005-2022   $   758   2005-2021
                                           -------              -------
  Total state carryovers                   $ 3,348              $   758
                                           =======              =======

  Total federal and state carryovers       $ 7,795              $10,113
                                           =======              =======
</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. During 2003, the Company utilized $4.9
     million  in  AMT  Credits. The $4.4 million in remaining AMT credits may be
     utilized  in  future  periods.


                                       43
<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. 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  $2.4  million,  $0  and  $1.3 million of profit sharing expense
     during  the  years  ended  June  30,  2003,  2002  and  2001.

     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 $0.27 million, $0.25 million and $0.24 million
     for  the  years  ended  June  30,  2003,  2002,  and  2001.

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.

     Pursuant  to  an Agreement dated December 28, 1998, the Company is required
     to purchase all shares owned by Kenneth W. Brill upon notice by Mr. Brill's
     estate or promptly after the passage of two years from Mr. Brill's death if
     the  estate  does  not sooner tender the shares. Mr. Brill died on July 20,
     2003.  The  Agreement  provides  that  the  Company  shall make installment
     payments for the purchase of the stock over a five-year period. The Company
     has  not  yet  determined  the  purchase  price  of  the  stock.

     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, 2003, the Company had 111,246 shares of voting
     --------------
     common  stock in treasury, carried at cost. The Company purchased 6,262 and
     10,630  shares  of voting common stock during the years ended June 30, 2003
     and  2002, respectively. At June 30, 2003, the Company had 18,853 shares of
     non-voting  Class  A  stock  in  treasury,  carried  at  cost.  The Company
     purchased  4,473  and  3,993  shares of non-voting Class A stock during the
     years  ended  June  30,  2003  and  2002.

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

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


                                       44
<PAGE>
     No  options  were  exercised for either of the years ended June 30, 2003 or
     2002.  Therefore,  as  of  June 30, 2003, 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 income (loss)
     per  common  share  for  the  years  ended  June  30  is  as  follows:

<TABLE>
<CAPTION>
                                                      2003       2002       2001
                                                    ---------  ---------  ---------
<S>                                                 <C>        <C>        <C>
      Income (loss) from continuing operations      $  9,917   $(26,180)  $(10,199)
      Discontinued operations                                               82,555
      Change in accounting principle, net of tax    $    (73)
                                                    -------------------------------
      Net income (loss)                             $  9,844   $(26,180)  $ 72,356
     ==============================================================================

      Shares:
                       Basic                         651,205    657,707    664,673
                       Diluted                       665,471    657,707    664,673
     ==============================================================================

      Basic net income (loss) per common share:
      Income (loss) from continuing operations
         before extraordinary items                 $  15.23   $ (39.80)  $ (15.34)
      Discontinued operations                              -          -     124.20
      Change in accounting principle, net of tax       (0.11)         -          -
     ------------------------------------------------------------------------------
      Basic net income (loss) per common share      $  15.12   $ (39.80)  $ 108.86
     ==============================================================================

      Diluted net income (loss) per common share:
      Income (loss) from continuing operations
         before extraordinary items                 $  14.90   $ (39.80)  $ (15.34)
      Discontinued operations                              -          -     124.20
      Change in accounting principle, net of tax       (0.11)         -          -
     ------------------------------------------------------------------------------
      Diluted net income (loss) per common share    $  14.79   $ (39.80)  $ 108.86
     ==============================================================================
<FN>

     For fiscal years 2002 and 2001 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.
</TABLE>


                                       45
<PAGE>
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 and equity
     and earnings will not be recognized 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):

<TABLE>
<CAPTION>
                                                        2002       2001      2000
                                                      ---------  --------  --------
<S>                                                   <C>        <C>       <C>
      Current assets                                  $  6,679   $ 11,336  $10,744
      Oil and gas properties                           110,555    100,833   84,050
      Other assets                                       1,309      1,966    3,233
                                                      ---------  --------  --------
         Total assets                                 $118,543   $114,135  $98,027
                                                      =========  ========  ========
      Current liabilities                             $ 14,149   $ 14,505  $12,955
      Long-term debt                                    63,900     51,700   54,200
      Other liabilities                                  7,953      8,092    1,433
      Redeemable preferred shares                       34,925     34,287   33,650
      Members' equity (deficit)                          2,262      1,764   (4,211)
      Accumulated other comprehensive (loss) income     (4,646)     3,787        -
                                                      ---------  --------  --------
        Total liabilities and equity                  $118,543   $114,135  $98,027
                                                      =========  ========  ========
      Net sales                                       $ 38,002   $ 44,173  $36,551
      Operating income                                  13,872     16,737    9,338
      Net income                                      $  4,782   $ 10,259  $ 5,267
</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 for the each of the years ended June
     30,  2003  and  2002,  and  $1.3  million for the year ended June 30, 2001.

     At  June  30,  2003 future minimum lease payments for each of the next five
     years  and  thereafter  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
<S>                        <C>
     2004                  $  909
     2005                   1,019
     2006                     402
     2007                     336
     2008                     338
     Thereafter               690
                           ------
                           $3,694
                           ======
</TABLE>


                                       46
<PAGE>
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  for each of the years ended June 30, 2003 and 2002
     and  $0.47  million  for  the  year  ended  June  30,  2001.

     The  Company acquired interests in various Petroleum Exploration Permits in
     New  Zealand  during the year ended June 30, 2003 from an entity controlled
     by  an  officer  of  the  Company  for  approximately  $300,000.


     The  Company  advanced funds to certain officers and other related parties,
     at  7%  to  8% interest. Balances totaled $0.3 million at June 30, 2003 and
     2002.  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.

     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 $0.1 million
     at June 30, 2003 and $0.2 million at June 30, 2002. 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.

     Between  1995  and 1997, the Company issued 4,800 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 $0.2 million at
     June  30,  2003 and 2002. 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. During
     fiscal  years  2002  and  2003, certain officers and directors representing
     approximately  74% of the total production, assigned back their interest in
     these  properties  for  nominal  consideration. The remaining book value of
     this  asset  at  June  30,  2003  is  $1.0  million.

14.  CONTRACT  SETTLEMENTS

     Effective  May  14,  2003,  the Company entered into a Settlement Agreement
     (the  "Agreement")  with  Allegheny  Energy  ("Allegheny")  which  mutually
     resolved  all  outstanding  issues  and  claims.  Under  the Agreement, the
     Company  neither  received  nor paid any cash consideration, but recognized
     the  following  revenue  and expenses as a result of the settlement for the
     year ended June 30, 2003: (i) gas sales of $3.1 million was recognized as a
     result  of  the  termination  and  release  of  the  Gas  Sale and Purchase
     Agreement  ("Gas  Contract")  dated  December  20,  1999 which called for a
     prepayment  by  Allegheny  and  subsequent delivery of gas volumes from the
     Company  to  Allegheny  and  (ii) net other income of $1.4 million was also
     recorded  related  to  the  transaction.

     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.  The  Complaint was later amended to add a
     claim  for  fraud. Oracle answered the complaint, substantially denying all
     of the Company's allegations, and filed a counterclaim against the Company.
     The  case  was  scheduled  for trial in January 2003; however, prior to the
     commencement  of  the  trial, the case was settled on terms satisfactory to
     the  Company.


                                       47
<PAGE>
15.  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 $8.1 and
     $9.0  million  at  June  30,  2003  and  2002,  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.

     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.

16.  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 revolving
     lines  of credit with variable rates and fixed rate facilities. At June 30,
     2003, the estimated fair value of the Company's subordinated debt was $92.4
     million  and  the  book  value  was  $132.1  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.


                                       48
<PAGE>
     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.

17.  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"), a non-GAAP
     financial measure, to evaluate each segment's operations. Reconciliation of
     non-GAAP  financial  measure  is  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                      2003      2002       2001
                                                    --------  ---------  --------
<S>                                                 <C>       <C>        <C>
     Net income (loss)                              $ 9,844   $(26,180)  $72,356

     Add:
       Interest expense                              16,383     19,671    20,094
       Depletion, depreciation, amortization-o&g     12,140     12,362     9,290
       Depletion, depreciation, amortization-other    4,294      2,934     2,763
       Impairment & exploratory costs                11,729     27,693    19,015
       Income tax expense (benefit)                   6,073    (16,822)   (7,232)
     Subtract:
       Change in accounting principle, net of tax       (73)         -         -
       Discontinued operations                            -          -    82,555

                                                    --------  ---------  --------
     EBITDAX                                        $60,536   $ 19,658   $33,731
                                                    ========  =========  ========
</TABLE>


                                       49
<PAGE>
     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):


<TABLE>
<CAPTION>
                                               Exploration    Marketing
                                                   and           and
                                               Production     Pipeline      Other     Consolidated
                                              -------------  -----------  ---------  --------------
<S>                                           <C>            <C>          <C>        <C>
                  2003
      Sales to unaffiliated customers         $     56,907   $   60,484   $     35   $     117,426
      Depreciation, depletion, amortization         13,559          661      2,214          16,434
      Impairment and exploratory costs              11,729            -          -          11,729
      Operating profit                               1,556        3,922      1,240           6,718
      Interest expense, net                         21,982       (6,485)       273          15,770
      EBITDAX                                       29,125        4,718     26,693          60,536
      Total assets                                 191,191       88,831     15,812         295,834
      Capital expenditures                          36,147          241      1,244          37,632
     ----------------------------------------------------------------------------------------------
                  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
     ----------------------------------------------------------------------------------------------
</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
     $6.1  million, $3.4 million and $3.0 million, as of June 30, 2003, 2002 and
     2001  and  any  related  revenues  and  expenses.


                                       50
<PAGE>
18.  SELECTED  QUARTERLY  FINANCIAL  DATA  (UNAUDITED)

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

<TABLE>
<CAPTION>
                                                                               Quarter Ended
                                                          -----------------------------------------------------
          2003                                             September 30     December 31    March 31    June 30
                                                          ---------------  -------------  ----------  ---------
<S>                                                       <C>              <C>            <C>         <C>
      Total revenue                                       $       22,589   $     26,383   $  34,038   $ 34,416
      Gross profit (loss)                                            677         (1,720)      3,456      4,305
      Income (loss) from continuing operations                    (1,562)         8,320       3,348       (188)
      Income (loss) per share on continuing
         operations,  basic                                        (2.43)         12.77        5.15      (0.38)
                      diluted                                      (2.37)         12.49        5.04      (0.37)
      Net income (loss)                                           (1,562)         8,320       3,347       (261)

                                                                               Quarter Ended
                                                          -----------------------------------------------------
          2002                                            September 30     December 31    March 31    June 30
                                                          ---------------  -------------  ----------  ---------
      Total revenue                                       $       23,394   $     21,157   $  18,573   $ 23,018
      Gross profit (loss)                                          1,943          1,119      (3,585)   (24,265)  *
      Loss per share, basic and diluted                            (2.31)         (3.17)      (8.15)    (26.17)
      Net loss                                                    (1,517)        (2,086)     (5,358)   (17,219)
</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.


                                       51
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

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

<TABLE>
<CAPTION>
                                                     2003       2002       2001
                                                  ----------  ---------  ---------
<S>                                               <C>         <C>        <C>
Capitalized costs:
   Proved properties                              $ 327,958   $310,495   $271,465
   Unproved properties                                9,946      9,653     45,760
                                                  ----------  ---------  ---------
   Total                                            337,904    320,148    317,225
   Less accumulated depletion and depreciation     (107,233)   (97,523)   (85,748)
                                                  ----------  ---------  ---------
Net capitalized costs                             $ 230,671   $222,625   $231,477
                                                  ==========  =========  =========

Company's share of equity method investee's net
   capitalized costs (see Note 11) *              $  27,167   $ 23,908   $ 19,729
                                                  ==========  =========  =========

Costs incurred:
   Acquisition of proved and unproved properties  $   5,879   $    717   $ 80,394
   Development costs                                 14,105     10,977     13,649
   Exploration costs                                 15,292     20,737     15,115
                                                  ----------  ---------  ---------
Total costs incurred                              $  35,276   $ 32,431   $109,158
                                                  ==========  =========  =========

Company's share of equity method investee's total
   costs incurred (see Note 11) *                 $   7,674   $  2,309   $  2,695
                                                  ==========  =========  =========
</TABLE>

* For the years ended December 31, 2002, 2001 and 2000.

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>
                                                         2003      2002     2001
                                                        -------  --------  -------
<S>                                                     <C>      <C>       <C>
Revenues from sale of oil and gas                       $51,410  $38,939   $41,555
Less:
   Production costs                                       4,436    5,001     3,011
   Production taxes                                       3,233    2,077     3,000
   Exploration and impairment                            11,729   27,605    11,458
   Depletion, depreciation and amortization              12,140   12,362     9,290
   Income tax expense (benefit)                           7,353   (2,999)    5,475
                                                        -------  --------  -------
Income (loss) from oil and gas operations               $12,519  $(5,107)  $ 9,321
                                                        =======  ========  =======

Company's share of equity method investee's
   income from oil and gas operations (see Note 11) *   $ 4,354  $ 4,955   $ 3,224
                                                        =======  ========  =======
</TABLE>

* For the years ended December 31, 2002, 2001 and 2000.

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.


                                       52
<PAGE>
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.

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, 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
    Revisions of previous estimates                           (11,847)     (1,045)
    Extensions and discoveries                                 23,623         580
    Sales of reserves in place                                 (2,941)        (16)
    Purchases of reserves in place                              8,371           -
    Production                                                 (9,755)       (104)
                                                          ------------  ----------
  June 30, 2003                                               190,796       2,366
                                                          ============  ==========

Proved developed reserves:
  June 30, 2001                                               175,784         987
  June 30, 2002                                               160,224       1,135
  June 30, 2003                                               161,796       1,064

Company's share of equity method investee's proved reserve at:
  June 30, 2001                                                 9,497      11,811
  June 30, 2002                                                 7,445      12,063
  June 30, 2003                                                 7,755      11,427
</TABLE>


                                       53
<PAGE>
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.

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>
                                                        2003         2002        2001
                                                     -----------  ----------  ----------
<S>                                                  <C>          <C>         <C>
Future cash in flows                                 $1,152,845   $ 715,755   $ 828,403
Future production and development costs                (235,960)   (243,828)   (271,051)
Future income tax expense                              (290,000)   (116,000)   (145,000)
                                                     -----------  ----------  ----------
Future net cash flows before discount                   626,885     355,927     412,352
10% discount to present value                          (365,662)   (205,014)   (240,071)
                                                     -----------  ----------  ----------
Standardized measure of discounted future net cash
   flows related to proved oil and gas reserves      $  261,223   $ 150,913   $ 172,281
                                                     ===========  ==========  ==========

Company's share of equity method investee's
   standardized measure of discounted future net
   cash flows                                        $   67,375   $  53,838   $  69,478
                                                     ===========  ==========  ==========
</TABLE>


                                       54
<PAGE>
Principal  changes  in  the  standardized  measure of discounted future net cash
flows for the years ended June 30 are as follows (in thousands):

<TABLE>
<CAPTION>
                                                     2003       2002       2001
                                                   ---------  ---------  ---------
<S>                                                <C>        <C>        <C>
Standardized measure of discounted future
   net cash flows at beginning of period           $150,913   $172,281   $124,871
Sales of oil and gas produced, net of
   production costs                                 (35,155)   (26,525)   (28,347)
Net changes in prices and production costs          175,844    (13,507)     3,338
Changes in production rates and other                 1,015     (5,867)    15,526
Extensions, discoveries and other additions, net
   of future production and development costs        52,407     13,622     33,991
Changes in estimated future development costs       (16,243)    (4,820)   (31,981)
Development costs incurred                           14,105     10,977      9,232
Revisions of previous quantity estimates            (35,028)   (24,772)   (15,677)
Purchase of reserves in place                        16,185                58,868
Sale of reserves in place                            (5,560)
Accretion of discount                                15,246     17,228     12,487
Net change in income taxes                          (72,506)    12,296    (10,027)
                                                   ---------  ---------  ---------
Standardized measure of discounted
   future net cash flows at end of period          $261,223   $150,913   $172,281
                                                   =========  =========  =========
</TABLE>



                                    * * * * *





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

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


                                    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, 2003 are listed below, together with a
description  of  their  experience  and  certain  other information.  All of the
Directors  were  elected  or  re-elected  for  a  one year term at the Company's
December  2002 annual meeting of stockholders.  Executive officers are appointed
by  the  Board  of  Directors.


                                       55
<PAGE>
<TABLE>
<CAPTION>
        Name                           Position with Company or Subsidiary
-----------------------                -----------------------------------
<S>                      <C>  <C>
John Mork                 54  President and Chief Executive Officer; Director
Joseph E. Casabona        59  Executive Vice President; Director
Michael S. Fletcher       54  Chief Financial Officer
Donald C. Supcoe          47  Senior Vice President, Secretary and General Counsel
Edward J. Davies          61  Senior Vice President
J. Michael Forbes         43  Vice President and Treasurer
George V. O'Malley        51  Vice President Accounting
K. Ralph Ranson, II       60  Vice President Marketing
Julie Ann Kitano          46  Assistant Secretary
W. Gaston Caperton, III   62  Director
Peter H. Coors            55  Director
L. B. Curtis              78  Director (Chairman)
John J. Dorgan            78  Director
Arthur C. Nielsen, Jr.    83  Director
F. H. McCullough, III     55  Director
Julie Mork                52  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  Board  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 Board of Directors of the West Virginia and Pennsylvania Independent Oil and
Gas  Associations.

     Peter  H. Coors has been a Director of the Company since 1996. Mr. Coors is
Chairman  of  Coors  Brewing  Company  and  Chairman 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. Bancorp, 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  and  Seeds  of  Hope  Foundation.

     L.B.  Curtis  has  been  a  Director of the Company since 1993 and Chairman
since  1998. 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


                                       56
<PAGE>
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 and is responsible
for  the  Company's  operations  in the west and internationally, which includes
Westech  and WENZ. He has served as President of Westech since 1994. Previously,
Mr.  Davies  was  with  Conoco Inc., where he held various positions culminating
with 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  starting  in  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  1998  until the Company sold Mountaineer in
August  of  2000.  Prior to becoming President in 1998, he 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.  Mr.  McCullough  is  a  graduate  of  the  University  of Southern
California  with  a  Bachelor  of Arts Degree in International Economics and two
Masters  Degrees in Business Administration and Financial Systems Management. He
is  a  graduate  of  the  Northwestern  University  Kellogg  Graduate  School of
Management  Executive  Marketing  Program.

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


                                       57
<PAGE>
     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.  She  is  currently Managing Director of the ECA Foundation, Inc. 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.

     George  V.  O'Malley  has  been Vice President - Accounting for the Company
since  December  2002.  Before being elected Vice President, Mr. O'Malley served
as  Director  of Accounting.  Mr. O'Malley joined Eastern American in April 1991
and  served in various capacities including Vice President and Treasurer.  Prior
to  joining  the  Company,  he  held  various  positions  in industry and public
accounting.  Mr.  O'Malley  currently  serves as President Elect and a member of
the  Board  of  the West Virginia Society of CPA's.  Mr. O'Malley graduated from
Marshall  University  with  a Bachelor's Degree in Accounting and is a Certified
Public  Accountant.

     Arthur  C. Nielsen, Jr., Chairman Emeritus of A.C. Nielsen Co.,  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 1998 until its sale in August of 2000.
Prior to joining Mountaineer in 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.


                                       58
<PAGE>
                       ITEM 11.    EXECUTIVE COMPENSATION
                       ----------------------------------

     The  following  table  sets  forth  for fiscal year 2003 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                                 2003  $265,376  $  125,000       $ 77,045       $           5,867
       President and Chief Executive Officer   2002   258,892     125,000         59,670                  26,067
                                               2001   256,068   1,146,635          4,349                  35,251

     Joseph E. Casabona                        2003  $243,595  $   80,000       $  6,875       $           4,763
       Executive Vice President                2002   238,277     125,942          2,905                   4,574
                                               2001   231,538   1,457,630  (2)     1,888                   4,454

     Michael S. Fletcher                       2003  $238,504  $   45,000       $  2,477       $           4,558
       Chief Financial Officer                 2002   233,306     100,510            352                   4,504
                                               2001   232,471      56,345        124,198  (3)              3,500

     Edward J. Davies                          2003  $230,201  $   45,000       $    408       $           6,113
       Senior Vice President                   2002   223,930      95,714            120                   4,592
                                               2001   207,308      53,105            899                   4,181

     Donald C. Supcoe                          2003  $201,152  $   65,000       $  3,529       $           4,005
       Senior Vice President                   2002   197,993     100,435          2,325                   3,949
                                               2001   188,447      54,545                                  1,482
<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.  In prior years,  each Director also received
160  shares  of  the  Company's  Class  A  Stock.  The total Board of Directors'
compensation  for  fiscal  2003  was  $0.1  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
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 29, 2003.  The


                                       59
<PAGE>
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>
      W. Gaston Caperton, III                               6,680     1.08%
      Joseph E. Casabona                                   31,376     5.09%
      Colstab & Co. (Nominee for KWB Trust) (1)            49,110     7.96%
      Peter H. Coors                                        2,946        *
      L. B. Curtis                                         11,610     1.88%
      Edward J. Davies                                      3,000        *
      John J. Dorgan                                        2,130        *
      J. Michael Forbes                                     2,200        *
      F. H. McCullough, III (2)                            70,035    11.35%
      John Mork (3)                                       359,493    58.27%
      Julie Mork (3)                                      359,493    58.27%
      Arthur C. Nielsen, Jr.                               36,480     5.91%
      Donald C. Supcoe                                      3,583        *
                                                          -------  --------
                                                          578,643    93.80%

      All officers and directors as a group (12 persons)  529,533    85.84%
<FN>

     *    Less than one percent.
     (1)  Pursuant to an agreement dated December 28, 1998 (previously attached
          to the Company's Form 10-K as exhibit 10.41), the Company is required
          to purchase all shares owned by Kenneth W. Brill upon notice by Mr.
          Brill's estate or promptly after the passage of two years from Mr.
          Brill's death if the estate does not sooner tender the shares. Mr.
          Brill died on July 20, 2003. The Agreement provides that the Company
          shall make installment payments for the purchase of the stock over a
          five year period.
     (2)  Includes 67,955 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.
     (3)  Includes 280,930 shares held by John and Julie Mork as joint tenants,
          2,663 shares held by Julie Mork individually, and 37,950 shares held
          by each of the Alison Mork Trust and the Kyle Mork 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 29, 2003.  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.


                                       60
<PAGE>
<TABLE>
<CAPTION>
                                                        Beneficial Ownership
                                                           Class A Stock
                                                          ----------------
                                                          Shares  Percent
                                                          ------  --------
<S>                                                       <C>     <C>
      W. Gaston Caperton, III                              1,920     6.15%
      Joseph E. Casabona                                   3,619    11.60%
      Peter H. Coors                                       2,534     8.12%
      L.B. Curtis                                          1,560     5.00%
      John J. Dorgan                                       2,320     7.44%
      Michael S. Fletcher                                  3,355    10.75%
      F.H. McCullough, III                                 1,920     6.15%
      John Mork (1)                                        4,737    15.18%
      Julie Mork (1)                                       4,737    15.18%
      Arthur C. Nielsen, Jr.                               3,080     9.87%
      K. Ralph Ranson, II                                    487     1.56%
      Donald C. Supcoe                                     2,785     8.93%
                                                          ------  --------
                                                          28,317    90.75%

      All officers and directors as a group (12 persons)  28,317    90.75%
<FN>
_______________
     (1)  Includes  956  shares held by John and Julie Mork as joint tenants and
          1,342  shares held by Julie Mork individually and 1,220 shares held by
          the  Alison  Mork  Trust and 1,219 shares held by the Kyle Mork Trust.
</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):


                                       61
<PAGE>
<TABLE>
<CAPTION>
                                            2003       2002       2001
                                         ----------  ---------  ---------
                                            (3)
<S>                                      <C>         <C>        <C>
      Gaston Caperton, III               $  100.01   $   77.58  $   56.76
      Joseph E. Casabona                     50.00       38.77      21.99
      Peter Coors                           135.00       77.58      28.38
      L.B. Curtis                           135.00       83.36      88.85
      E.J. Davies                           270.00      166.72     140.78
      John J. Dorgan                         29.97       19.39      14.19
      Michael S. Fletcher                    50.00       38.77      28.38
      J. Michael Forbes                      25.00       19.39      14.19
      John Frederick                         25.00           -      14.19
      Thomas R. Goodwin                      25.00       38.77      28.38
      Denny McGowan                          25.00           -          -
      John Mork (1)                       1,350.00      833.60     703.89
      Alison Mork Trust (2)                  50.00       38.77      28.38
      Kyle Mork Trust (2)                    50.00       38.77      28.38
      Arthur C. Nielsen, Jr.                 50.00       38.77      28.38
      George O'Malley                        27.00           -          -
      Kent Schamp                            28.35       21.17      15.34
      Donald C. Supcoe                       25.00       19.39      14.19
                                         ----------  ---------  ---------
                                         $2,450.33   $1,550.80  $1,254.65
                                         ==========  =========  =========
<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 2003
          Drilling Program, the actual amount of 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 January 1, 2003 .  The following were
indebted  to  the  Company  (in  thousands):

<TABLE>
<CAPTION>
                               Outstanding     Unamortized
                              Balance as of       as of
                              June 30, 2003   June 30, 2003
                              --------------  --------------
<S>                           <C>             <C>
         Joseph E. Casabona   $          141  $           33
         Michael S. Fletcher             141              33
         J. Michael Forbes                96              96
         K. Ralph Ranson, II              28              16
         Donald C. Supcoe                180             116
                              --------------  --------------
            Total             $          586  $          294
                              ==============  ==============
</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):


                                       62
<PAGE>
<TABLE>
<CAPTION>
                                Note Plus    Unamortized
                                 Accrued        as of
                                 Interest   June 30, 2003
                                ----------  --------------
<S>       <C>                   <C>         <C>
     (1)   Michael S. Fletcher  $      284  $            7
     (1)   Linda Given                  28               1
     (1)   David Jordan                 56               1
     (2)   Dennis McGowan              166             133
     (1)   Donald C. Supcoe            169               4
                                ----------  --------------
                                $      703  $          146
                                ==========  ==============
<FN>
     (1)  Promissory note is being amortized over three years, as of August 29,
          2003 amounts have been forgiven.
     (2)  Of the $166,000 in promissory notes, $33,000 is being forgiven and
          amortized over the next two 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,  2003:

<TABLE>
<CAPTION>
                                     Payment      Volumes
                                 (in thousands)    Mmcf
                                 ---------------  -------
<S>                              <C>              <C>
      Joseph E. Casabona                      50     66.7
      L.B. Curtis                             75    100.0
      E.J. Davies                            150    200.0
      John J. Dorgan                          50     66.7
      F.H. McCullough, III                   150    200.0
                                 ---------------  -------
                                 $           475    633.4
                                 ===============  =======
</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 2003. The Company believes that
such  rental  terms  are no less favorable than could have been obtained from an
unaffiliated  party.

                        ITEM 14. CONTROLS AND PROCEDURES
                        --------------------------------

     Under  the  supervision  and  with  the  participation  of  our management,
including  our  principal executive officer and principal financial officer, the
Company  has  evaluated  the  effectiveness  of  the design and operation of our
disclosure  controls  and  procedures  within 90 days of the filing date of this
annual  report  and,  based on their evaluation, our principal executive officer
and  principal  financial  officer  have  concluded  that  these  controls  and
procedures  are  effective.  There  were  no significant changes in our internal
controls  or  in  other  factors  that could significantly affect these controls
subsequent  to the date of their evaluation.  Disclosure controls and procedures
are  our  controls  and  other  procedures  that  are


                                       63
<PAGE>
designed  to  ensure  that  information  required  to  be disclosed by us in the
reports  that  we  file  or submit under the Securities Exchange Act of 1934, as
amended,  is  recorded,  processed,  summarized  and  reported,  within the time
periods  specified  in the Securities and Exchange Commission's rules and forms.
Disclosure  controls  and  procedures  include, without limitation, controls and
procedures designed to ensure that information required to be disclosed by us in
the  reports  that  we file under the Securities Exchange Act is accumulated and
communicated  to  our  management, including our principal executive officer and
principal  financial officer, as appropriate to allow timely decisions regarding
required  disclosure.


                                       64
<PAGE>
                                     PART IV
                                     -------

                ITEM 15.  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
          Financial  statement  schedules have been omitted because they are not
          applicable  or  the information required therein is included elsewhere
          in  the  financial  statements  or  notes  thereto.


     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.


                                       65
<PAGE>
     *    10.8  Intentionally  omitted.
     *    10.9  Intentionally  omitted.
     *    10.1  Intentionally  omitted.
     *    10.11 Intentionally  omitted.
     *    10.12 Intentionally  omitted.
     *    10.13 Intentionally  omitted.
     *    10.14 Intentionally  omitted.
     *    10.15 Intentionally  omitted.
     *    10.16 Intentionally  omitted.
     *    10.17 Incentive  Stock  Purchase Agreement dated February 12, 1999 by
                and  between  Energy  Corporation  of  America  and  Michael  S.
                Fletcher.
     *    10.18 Incentive  Stock  Purchase Agreement dated December 16, 1998 by
                and between Energy Corporation of America and Joseph E.
                Casabona.
     *    10.19 Incentive  Stock  Purchase Agreement dated December 16, 1998 by
                and between  Energy Corporation of America and Edward J. Davies.
     *    10.2  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.
     *    10.3  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.


                                       66
<PAGE>
     *    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.
     *    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.
     *    10.4  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.
          31.1  Certification of Chief Executive Officer Pursuant to Section 302
                of  the  Sarbanes-Oxley  Act  of  2002
          31.2  Certification of Chief Financial Officer Pursuant to Section 302
                of  the  Sarbanes-Oxley  Act  of  2002
     *    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


                                       67
<PAGE>
     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.

                                   * * * * * *


                                       68
<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 25th day of
September  2003.

                                   ENERGY CORPORATION OF AMERICA

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


                                       69
<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 25th day of September 2003, by the following persons in
the  capacities  indicated.


/s/ John Mork                                 /s/ W. Gaston Caperton, III
--------------------------------------------  ---------------------------------
John Mork                                     W. Gaston Caperton, III, Director
President, Chief Executive Officer, Director

                                              /s/ Peter H. Coors
                                              ---------------------------------
/s/ Joseph E. Casabona                        Peter H. Coors, Director
--------------------------------------------
Joseph E. Casabona
Executive Vice President, Director

                                              /s/ L. B. Curtis
                                              ---------------------------------
/s/ Michael S. Fletcher                       L.B. Curtis, Director
--------------------------------------------
Michael S. Fletcher
Chief Financial Officer

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



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



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



                                              /s/ Arthur C. Nielsen, Jr.
                                              ---------------------------------
                                              Arthur C. Nielsen, Jr., Director


                                       70
<PAGE>