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,  1999.

                                       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

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

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


The  aggregate  market  value  of  common  stock  held  by non-affiliates of the
registrant:  Class  of  Voting Stock and Number of Shares Held by Non-affiliates
at  September  1,  1999 was 95,477 Shares.  Market Value Held by Non-affiliates:
Unavailable.


The  number  of  shares  of  the  registrant's common stock, par value $1.00 per
share,  outstanding  at  September  1,  1999  was  645,964  shares.




                      DOCUMENTS INCORPORATED BY REFERENCE:

                                      NONE

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

                                     TABLE OF CONTENTS


                                                                                       Page
<S>           <C>                                                                        <C>
Part I
  Item 1.     Business                                                                    4
  Item 2.     Properties                                                                 15
  Item 3.     Legal Proceedings                                                          15
  Item 4.     Submission of Matters to a Vote of Security Holders                        16
Part II
  Item 5.     Market for the Registrant's Common Stock and Related Stockholder Matters   16
  Item 6.     Selected Financial Data                                                    16
  Item 7.     Management's Discussion and Analysis of Results of Operations
              and Financial Condition                                                    16
  Item 8.     Financial Statements and Supplementary Data
              Independent Auditor's Report                                               25
              Consolidated Balance Sheets                                                26
              Consolidated Statements of Operations                                      28
              Consolidated Statements of Stockholders Equity                             29
              Consolidated Statements of Cash Flows                                      30
              Notes to Consolidated Financial Statements                                 31
              Supplemental Information on Oil and Gas Producing Activities (Unaudited)   51
              Schedules                                                                  56
  Item 9.     Changes In and Disagreements With Accountants on Accounting
              and Financial Disclosure                                                   60
Part III
  Item 10.    Directors and Officers of Registrant                                       61
  Item 11.    Executive Compensation                                                     64
  Item 12.    Security Ownership of Certain Beneficial Owners and Management             64
  Item 13.    Certain Relationships and Related Transactions                             66
Part IV
  Item 14.    Exhibits, Financial Statement Schedules and Reports on Form 8-K            69
Part V
  Signatures                                                                             72
</TABLE>

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

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

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

GENERAL
-------

     Energy  Corporation  of  America  (the  "Company")  is  a  privately  held,
integrated  energy company primarily engaged in natural gas distribution in West
Virginia  and  in  the  development, production, transportation and marketing of
natural gas and oil, primarily in the Appalachian Basin.  The Company was formed
in  June  1993  through  an  exchange  of shares with the common stockholders of
Eastern  American  Energy Corporation ("Eastern American").  For the fiscal year
ended June 30, 1999, the Company had total revenues of $286.0 million and EBITDA
(earnings  before  interest,  taxes,  depreciation  and  amortization)  of $28.5
million.

     The  Company   conducts   business   through  its  principal  wholly  owned
subsidiaries, Mountaineer Gas Company ("Mountaineer"), Eastern American, Westech
Energy Corporation ("Westech") and Westech Energy New Zealand Limited ("WENZL").
Mountaineer  owns and operates the largest natural gas  distribution  utility in
West Virginia.  Eastern  American is one of the largest oil and gas operators in
the Appalachian Basin, including exploration, development and production, and is
engaged in the  transportation and marketing of natural gas. Westech is involved
in oil and gas exploration and development in the Rocky Mountain  region.  WENZL
is involved in oil and gas exploration and development in New Zealand.

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

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

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

     The  Company's  principal  businesses  constitute three operating segments.
For  financial  information  on  these segments, see Note 19 to the Consolidated
Financial  Statements.

NATURAL  GAS  DISTRIBUTION  UTILITY
-----------------------------------

     Mountaineer  owns  the  largest  natural  gas  distribution  system in West
Virginia,  consisting  of  approximately 3,900 miles of natural gas distribution
pipelines.  Mountaineer  provides  natural gas sales and transportation services
to  approximately  201,000  residential,  commercial,  industrial  and wholesale
customers  in  45  of  the 55 counties in West Virginia, including the cities of
Charleston,  Beckley,  Huntington and Wheeling.  During fiscal 1999, Mountaineer
sold  or  transported  57  Bcf  of  gas.

     Mountaineer  continues to pursue expansion of its customer base and to this
end acquired  substantially  all of the West Virginia  assets of Shenandoah  Gas
Company  effective July 1, 1999 at a cost of  approximately  $12.6 million.  The
acquired  assets  consist of natural  gas  distribution  facilities  and related
equipment,  including  approximately  3,600  customers,  located in the  eastern
panhandle of West Virginia.


                                        4
<PAGE>
COMPARATIVE  GAS  SALES  AND  TRANSPORTATION  DATA
--------------------------------------------------

     The  table  below  sets  forth  certain  information  with  respect  to the
operating  revenue  and  related  gas volumes of the utility for the years ended
June  30:

<TABLE>
<CAPTION>
                                          1999       1998       1997
                                        ---------  ---------  ---------
<S>                                     <C>        <C>        <C>
 Gas distribution revenue:
    Residential                            69.55%     69.90%     68.40%
    Commercial                             23.44%     23.40%     25.20%
    Transportation                          6.49%      6.30%      5.50%
    Industrial and other                    0.52%      0.40%      0.90%
                                        ---------  ---------  ---------
 Total                                    100.00%    100.00%    100.00%
                                        =========  =========  =========

 Gas distribution volumes:
    Residential                            28.30%     26.40%     28.20%
    Commercial                             10.30%      9.40%     11.20%
    Transportation                         61.30%     64.10%     60.10%
    Industrial and other                    0.10%      0.10%      0.50%
                                        ---------  ---------  ---------
 Total                                    100.00%    100.00%    100.00%
                                        =========  =========  =========

 Average use per customer (Mcf):
    Residential                               88         90         99
    Commercial                               312        339        432
    Transportation                        37,024     28,021     19,653
    Industrial and other                      24      6,803     27,458

 Average revenue per customer:
    Residential                         $    603   $    599   $    653
    Commercial                          $  1,978   $  2,121   $  2,636
    Transportation                      $ 10,918   $  6,908   $  4,931
    Industrial and other                $  1,754   $ 25,399   $121,377

 Average revenue per Mcf:
    Residential                         $   6.85   $   6.66   $   6.60
    Commercial                          $   6.34   $   6.26   $   6.10
    Transportation                      $   0.29   $   0.25   $   0.25
    Industrial and other                $   4.27   $   3.73   $   4.42

 Weighted average sales rate (per Mcf)  $   6.71   $   6.54   $   6.43
 Average gas cost per Mcf sold          $   3.35   $   3.81   $   3.96
 Weighted average Degree Days (1)          4,832      4,941      5,275
 Miles of distribution pipes               3,951      3,926      3,897
 Number of customers                     201,526    201,465    200,203
 ___________________________
<FN>
(1)   Degree  Days  measure  the  amount  by  which  the  average  of  the  high
      and  low  temperature  on  a  given  day  is below 65 degrees Fahrenheit.
</TABLE>


                                        5
<PAGE>
------
GAS  SUPPLY
-----------

     On  September  30,  1998,  Mountaineer  entered  into a Natural  Gas Supply
Management Agreement (the "Supply Agreement") with Coral Energy Resources,  L.P.
("Coral") an affiliate of Shell Oil Company,  pursuant to which Coral became the
principal gas supplier for Mountaineer for a three-year  period commencing as of
November  1,  1998.  The  term of  this  Supply  Agreement  coincides  with  the
three-year Rate Moratorium as discussed below.

     The Supply Agreement with Coral provides that Coral will be responsible for
supplying 100% of Mountaineer's annual gas requirements for the three-year term,
less 2.7 Bcf of local production.  The gas is supplied by Coral at a fixed price
per  dth at the city gate up to approximately 24.4 Bcf annually.  Any volumes in
excess  of  24.4  Bcf on an annual basis are priced at the lesser of a specified
index  or  a  previously  agreed  upon  maximum cost.  As a result of the Supply
Agreement  Mountaineer will purchase approximately 90% of its natural gas supply
from  Coral.  The  remaining  10% of the gas supply will be purchased from local
producers,  including  Company  owned  production.  Because  of the Coral Supply
Agreement,  during  fiscal  1999, natural gas sold by Mountaineer that came from
Company  operated  production  declined  from  43%  to  23%.

     Prior  to the  Supply  Agreement,  Mountaineer  purchased  its  gas  supply
pursuant to a balanced  portfolio of  intermediate  term (one to five years) and
short term (less than one year)  contractual  arrangements from various sources,
including  supplies  from the Gulf Coast and  Appalachian  regions of the United
States.  The following  table sets forth the volume of natural gas purchased and
percentage  of total  volume of natural  gas  purchases,  with  respect to those
suppliers accounting for five percent or more of Mountaineer's purchases for the
years ended June 30:

<TABLE>
<CAPTION>
                                     1999            1998            1997
                                --------------  --------------  --------------
                                Volume   % of   Volume   % of   Volume   % of
                                 Mmcf   Total    Mmcf   Total    Mmcf   Total
                                ------  ------  ------  ------  ------  ------
<S>                             <C>     <C>     <C>     <C>     <C>     <C>
 Company operated production     5,651     23%  10,972     43%  11,365     39%
 Coral Energy Resources,  L.P.  13,508     55%
 Idaho Power                     1,172      5%
 Conoco, Inc.                    1,114      5%
 Engage Energy, L.P.                             3,581     15%   2,555      9%
 Noble Gas Marketing                             2,297      9%   2,787     10%
 Equitable Resources                             1,639      6%   2,258      8%
 Texaco Natural Gas                              1,579      6%   2,346      8%
 Valero Gas Marketing                            1,555      6%
</TABLE>

     The  following  table  sets  forth  certain  information  relating  to
Mountaineer's  gas  supply  purchases  for  the  years  ended  June  30:

<TABLE>
<CAPTION>
                                    1999   1998   1997
                                    -----  -----  -----
<S>                                 <C>    <C>    <C>
 Interstate suppliers                 75%    55%    56%
 Company operated production          23%    43%    39%
 Other Appalachian Basin producers     2%     2%     5%
                                    -----  -----  -----
 Total                               100%   100%   100%
                                    =====  =====  =====
</TABLE>

                                        6
<PAGE>
TRANSPORTATION  AND  STORAGE  CAPACITY
--------------------------------------

     The  gas  purchased  from  producer/suppliers  in  the Gulf Coast region is
transported  through  the  interstate  pipeline  systems  of  Columbia  Gulf
Transmission  Company  ("Columbia  Gulf"), Columbia Gas Transmission Corporation
("Columbia  Gas"),  and  Tennessee  Gas  Pipeline  Company  ("Tennessee Gas") to
Mountaineer's local distribution facilities in West Virginia.  Approximately 83%
of  the gas purchased by Mountaineer in the Appalachian region is transported by
Columbia  Gas,  with  the  balance  transported  by  Tennessee  Gas  or directly
delivered  into  Mountaineer's  gas  utility  distribution  system.

     To  ensure  continuous, uninterrupted service to its customers, Mountaineer
has  in place long-term transportation and service agreements with Columbia Gas,
Columbia  Gulf  and  Tennessee  Gas.  These  contracts  cover  a  wide  range of
transportation services and volumes, ranging from firm transportation service to
no-notice  service  and  storage  with  such contracts expiring on various dates
ranging  from October 31, 2000 through October 31, 2004.  Under the terms of the
Supply Agreement, Coral has assumed the management and the financial obligations
of  virtually  all  of  Mountaineer's  total  firm  transportation  and  storage
entitlements.  The combination of this Supply Agreement and the Rate Moratorium,
discussed  below,  substantially  reduces  Mountaineer's  exposure  to  gas cost
fluctuations.

     Gas sales and/or transportation contracts with interruption provisions have
been  used  for load management by Mountaineer, and the gas industry as a whole,
for  many  years.  Under  such  contracts,  the  users  purchase  gas  with  the
understanding  that  they  may  be  forced  to  shut down or switch to alternate
sources of energy at times when the gas is needed for higher priority customers.
In addition, during times of special supply problems, curtailments of deliveries
to  customers  with  firm  contracts  may  be made in accordance with guidelines
established  by  appropriate  federal  and  state  regulatory  agencies.

REGULATION  AND  RATES
----------------------

     Mountaineer  is regulated by the Public Service Commission of West Virginia
("WVPSC").  Under  traditional  rate  making  in  West  Virginia, Mountaineer is
prohibited  from  increasing its base rate unless it obtains the approval of the
WVPSC.  In  general,  the  WVPSC  reviews any requested base rate increase based
upon  an  analysis  of the cost of service, as adjusted for known and measurable
changes  in  expenses  and  revenues,  and  a  reasonable  return on equity.  In
determining the overall rate of return on equity allowed in the rate proceeding,
the  WVPSC  employs  a  methodology,  which  computes  both  the  natural  gas
distribution  utility's  cost of debt capital as well as cost of equity capital.
The  allowable  return  on  equity is designed to compensate the equity owner at
rates  commensurate  with the rate of return on investments at comparable risks.
In  order  to  determine  the allowable return on equity, the WVPSC utilizes two
market-oriented  methodologies;  the  discounted cash flow and the capital asset
pricing  model.  A  further  review  utilized  by  the  WVPSC  to  check  the
reasonableness  of  the  allowable  return on equity involves an analysis of the
overall  return  required  to  provide  reasonable  interest  coverage, dividend
pay-out  ratios and internally generated cash flow.  Finally, the WVPSC utilizes
a sample group of approximately ten to twelve gas distribution utilities located
within  and outside of West Virginia for comparison purposes with respect to its
discounted  cash flow calculation and the capital asset pricing model.  The cost
of debt capital allowed is determined by utilizing the utility's actual interest
rates as set forth in its loan documents, provided the rate is determined by the
WVPSC  to  be  reasonable.  While  the cost of debt capital is normally based on
long-term  debt,  if  the  utility  uses short-term debt on a regular basis, the
WVPSC  may  determine  that  such  debt  should be treated as a component of the
utility's  debt  capital.  Because  the  rate  regulatory  process  has  certain
inherent  time  delays,  rate  orders may not reflect the operating costs at the
time  new  rates  are  put  into  effect.

                                        7
<PAGE>
     Any change to the rate that  Mountaineer  charges its customers for natural
gas costs must be approved by the WVPSC.  In order to obtain approval of changes
to gas purchase costs,  Mountaineer  makes purchase gas adjustment  filings with
the WVPSC on an annual basis which  include a forecast  for the upcoming  twelve
month period of gas costs and a true-up  mechanism  for the previous  period for
any  over or  under-recovery  balances.  The  WVPSC  reviews  Mountaineer's  gas
purchasing  activities during the previous year to determine the prudence of gas
purchase expenditures and to determine that dependable  lower-priced supplies of
natural gas are not readily  available from other  sources.  The forecast of gas
costs  submitted by  Mountaineer in its annual  filings  incorporates  known and
measurable pipeline fees during the upcoming period and an estimate of gas costs
based  on  several  natural  gas  futures   indices.   The  WVPSC  also  reviews
Mountaineer's forecast of gas costs in such filings for reasonableness.

     All of the requests of natural gas distribution  utilities in West Virginia
for rate  changes are reviewed by the staff of the WVPSC as well as the Consumer
Advocate  Division of the WVPSC. The Consumer  Advocate Division is charged with
representing and protecting the interests of residential customers in regulating
the utility.

     Prior to October 1995,  Mountaineer  was subject to traditional  regulatory
rate making in West  Virginia as that  procedure  is described  above.  However,
following a proposal by  Mountaineer,  the WVPSC issued an order  implementing a
three-year rate moratorium effective November 1995. The moratorium provided rate
certainty to Mountaineer's customers by fixing the price of gas for three years.
By entering into the moratorium,  Mountaineer  assumed the risks and benefits of
fixed  utility  rates,  its  gas  purchasing   activities,   ancillary  business
activities and achieving operational efficiencies.

     In  January  1998,  Mountaineer filed with the WVPSC for an increase in its
base  rates,  effective  upon expiration of the moratorium period on October 31,
1998.  In July 1998, Mountaineer agreed to a Joint Stipulation and Agreement for
Settlement  with  various  parties  including  the  staff  of  the WVPSC and the
Consumer Advocate Division regarding Mountaineer's rate filing.  Under the terms
of  the  agreement,  Mountaineer  was  granted  an  increase in its rates, which
assuming  certain  weather conditions, would generate additional annual revenues
of  approximately  $9.4  million.  The  agreement provides for a three year rate
moratorium  period  from  November  1,  1998 to October 31, 2001.  The terms and
conditions  of  the  agreement  are  similar  to  those  under which Mountaineer
operated  under  the earlier moratorium period.  Mountaineer is also required to
make  minimum  capital  expenditures  of  $9.0  million  per year in its utility
operations  during  the  moratorium  period.  In  addition,  as  a result of the
Shenandoah  Gas  Company  acquisition,  Mountaineer  is  required to spend, at a
minimum, an additional $1.5 million  in capital expenditures  over a three  year
period,  ending  October  31,  2001.

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

     Competition in the residential and commercial sales market from alternative
energy  sources  is  minimal in West Virginia.  Such competition comes primarily
from sources such as electricity, propane, and to a lesser degree, oil, coal and
wood.  However, natural gas continues to be the preferred fuel for West Virginia
homes  and  businesses.  Based  on  1990  census  data, approximately 51% of the
occupied  housing  units in the state utilized natural gas for home heating, 25%
utilized  electricity,  with  fuel  oil,  coal  and wood comprising the balance.

     Mountaineer's  demand from commercial and industrial customers is dependent
on local business  conditions and competition from alternate  sources of energy.
Demand  from  residential  customers  likewise  is subject to  competition  from
alternate  energy  sources.  Mountaineer  is also  subject to  competition  from
interstate and intrastate pipeline companies,  natural gas marketers,  producers
and  other  utilities  that  may be  able to  serve  commercial  and  industrial
customers from their transmission,  gathering and/or distribution facilities. In
certain markets, gas has a competitive  advantage over alternate fuels, while in
other markets it is not as price competitive.

                                        8
<PAGE>
     Mountaineer  began  offering gas  transportation  service to its industrial
customers   in  1984.   The   availability   of  both  firm  and   interruptible
transportation  service,  which enables  industrial  end users to purchase lower
cost gas supplies  directly from  producers  and/or  natural gas marketers is an
important  factor in maintaining  gas usage by those end users during periods of
low  residual  oil prices.  Continued  evolution  in the  natural gas  industry,
resulting  primarily from Federal Energy  Regulatory  Commission Order Nos. 436,
500 and 636, has served to increase the ability of large gas end users to bypass
Mountaineer  in obtaining gas supply and  transportation  services.  Although no
bypass by customers has occurred to date,  Mountaineer  generally realizes lower
transportation  revenues from large  industrial  and commercial end users due to
the  possibility  of such a bypass.  In  addition,  Mountaineer  has  negotiated
reduced rates for certain end users to: (1) provide  economic  relief to aid the
end user in remaining an ongoing concern;  and (2) add an incentive to end users
to add incremental load.

SEASONALITY
-----------

     More  than  95%  of  Mountaineer's residential and commercial customers use
natural  gas  for  heating  purposes.  Accordingly,  a  significant  portion  of
Mountaineer's  utility  gas volumes are attributable to sales during the heating
season,  with highest sales volumes occurring in December, January and February.
In fiscal 1999, gas sales from October through March accounted for approximately
78.1%  of utility gas sales.  Weather patterns experienced in the markets served
by  Mountaineer  significantly  impact  the  demand  for  natural  gas  sales,
particularly  during  the  peak  heating  season  and,  as a result, will have a
significant impact on Mountaineer's financial performance, liquidity and capital
resources.

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

     The  Company's proved net gas and oil reserves are estimated as of June 30,
1999 at 166 Bcf and 962 Mbbls, respectively.  For the fiscal year ended June 30,
1999,  the  Company's  net  gas production was approximately 8.8 Bcf and net oil
production was approximately 133.1 Mbbls, for a total of 9.6 net Bcfe.  Revenues
from  the  sale  of  oil  and gas production accounted for 7.6% of the Company's
consolidated  revenues  for  1999.

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

     APPALACHIAN  BASIN.  The Company holds interests in 4,783 gross (2,825 net)
     ------------------
wells  in  the  Appalachian Basin and serves as operator of substantially all of
such wells in which it has a working interest.  The Company's proved gas and oil
reserves  attributable  to  its Appalachian Basin properties are estimated as of
June  30,  1999  at 161 Bcfe, of which approximately 97% was gas reserves and 3%
was  oil  reserves.  For  the fiscal year ended June 30, 1999, the Company's gas
production  from its Appalachian Basin properties was approximately 8.8 net Bcf.
In  the  Appalachian  Basin,  the Company has interests in approximately 570,980
gross  acres  (433,550  net)  of  producing properties and an additional 112,890
gross  acres  (76,270  net)  of undeveloped properties located primarily in West
Virginia,  Pennsylvania  and  Ohio.  During  fiscal 1999, the Company drilled 26
successful  gross  wells  (19 net)  and  added  3.8  net  Bcfe  in  reserves.

     ROCKY  MOUNTAINS.  Westech  owns  developed  and  undeveloped  leasehold
     ----------------
interests  in  approximately  455,000  gross  acres (327,000 net) located in the
Rocky  Mountain  area.  The  Company has identified and is currently focusing on
five  exploratory  plays  which  are located in the Blanding Basin, Utah; Powder
River  Basin  (Minnelusa-Muddy),  Wyoming;  Williston  Basin, North Dakota; Wind
River  Basin, Wyoming and the Danforth area, Colorado.  Commencing in June 1999,
the  Company  entered  into a 10 well exploratory drilling program in the Powder
River  Basin.  Currently, six wells have been drilled, with one successful well.

                                        9
<PAGE>
     INTERNATIONAL.  WENZL  currently  operates  four  offshore  permits and two
     -------------
onshore  permits  on the East Coast of the North Island of New Zealand, totaling
7,237,000  gross acres (3,618,500 net).  Onshore, a total of six exploratory and
four  appraisal  wells have been drilled.  Currently, additional well testing is
being  performed  to  confirm  the  threshold  deliverability  requirements  for
commercialization.  Offshore  a  212 square mile 3-D survey has been acquired to
define  drillable  prospects.  WENZL  has  also  been  awarded three new onshore
permits  in  the  producing  Taranaki  Basin  of the North Island of New Zealand
totaling  20,000  gross  and net acres.  WENZL's obligations under these permits
require  a  10  square  mile  3-D  survey,  which is planned during fiscal 2000.
Westech  is  negotiating  an  agreement to acquire a 35% working interest in the
Cooper  Basin, Queensland, Australia.  Two wells are planned during fiscal 2000.

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 providing for determinable escalation.
Operating  costs,  production  and ad valorem taxes and future development costs
are  based  on  current  costs  with  no  escalations.

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

<TABLE>
<CAPTION>
                                                   1999      1998      1997
                                                 --------  --------  --------
<S>                                              <C>       <C>       <C>
 Net proved:
   Gas (Mmcf)                                     166,268   169,460   160,331
   Oil (Mbbls)                                        962     1,330     1,233
   Total (Mmcfe)                                  172,040   177,440   167,729

 Net proved developed:
   Gas (Mmcf)                                     144,643   138,935   141,116
   Oil (Mbbls)                                        717       733       748
   Total (Mmcfe)                                  148,945   143,333   145,604

 Estimated future net cash flows
   before income taxes (in thousands)            $280,636  $286,846  $301,245
 Present Value of estimated future net cash
   flows before income taxes (in thousands) (1)  $117,227  $113,898  $128,440
 _______________
<FN>
(1)  Discounted  using  an  annual  discount  rate  of  10%.
</TABLE>

                                       10
<PAGE>
     The  following table sets forth the Company's estimated proved reserves and
the  related  estimated  future  value  by  region,  as  of  June  30,  1999:

<TABLE>
<CAPTION>
                     Present Value
                    ---------------------                             Natural Gas
                       Amount              Oil & NGLs   Natural Gas   Equivalent
 Region             (thousands)      %       (Mbbls)       (Mmcf)       (Mmcfe)
------------------  ------------  -------  -----------  ------------  -----------
<S>                 <C>           <C>      <C>          <C>           <C>
 Appalachian Basin  $    110,245   94.04%          750       156,405      160,905
 Rocky Mountains           1,312    1.12%          212           227        1,499
 New Zealand               5,670    4.84%                      9,636        9,636
------------------  ------------  -------  -----------  ------------  -----------
 Total              $    117,227  100.00%          962       166,268      172,040
                    ============  =======  ===========  ============  ===========
</TABLE>

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

     The  following  table sets forth certain information relating to productive
wells  at  June 30, 1999.  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   13  4,770  4,783    4  2,821  2,825
 Rocky Mountains      8      4     12    3      1      4
                    ---  -----  -----  ---  -----  -----
 Total               21  4,774  4,795    7  2,822  2,829
                    ===  =====  =====  ===  =====  =====
</TABLE>

ACREAGE
-------

     The  following table sets forth the developed and undeveloped gross and net
acreage  held  at  June  30,  1999  (in  thousands).

<TABLE>
<CAPTION>
                   Developed Acreage  Undeveloped Acreage
                    ----------------  --------------------
                     Gross     Net      Gross       Net
                    -------  -------  ---------  ---------
<S>                 <C>      <C>      <C>        <C>
 Appalachian Basin  570,979  433,549    112,887     76,266
 Rocky Mountains        560      168    454,440    326,832
 New Zealand              -        -  7,237,000  3,618,500
                    -------  -------  ---------  ---------
 Total              571,539  433,717  7,804,327  4,021,598
                    =======  =======  =========  =========
</TABLE>

                                       11
<PAGE>
PRODUCTION
----------

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

<TABLE>
<CAPTION>
                                    1999    1998    1997
                                   ------  ------  -------
<S>                                <C>     <C>     <C>
 Production Data:
   Oil (Mbbls)                        133     127      447
   Natural gas (Mmcf)               8,840   8,525    9,106
   Natural gas equivalent (Mmcfe)   9,638   9,287   11,788
 Average Sales Price:
   Oil per Bbl                     $10.76  $14.30  $ 18.13
   Natural gas per Mcf             $ 2.30  $ 2.61  $  2.39
</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.

<TABLE>
<CAPTION>
                             1999          1998         1997
                      ----------------  -----------  ----------
                        Gross     Net   Gross  Net   Gross  Net
                      ----------  ----  -----  ----  -----  ---
<S>                   <C>         <C>   <C>    <C>   <C>    <C>
 Development:
      Productive
         Appalachian        21.0  16.6   27.0  21.6   18.0  9.1
         Other               3.0   0.4    5.0   0.9      -    -
                      ----------  ----  -----  ----  -----  ---
      Total                 24.0  17.0   32.0  22.5   18.0  9.1
                      ==========  ====  =====  ====  =====  ===

     Nonproductive
         Appalachian         2.0   1.6    3.0   1.8      -    -
         Other               3.0   1.3    1.0   0.2      -    -
                      ----------  ----  -----  ----  -----  ---
     Total                   5.0   2.9    4.0   2.0      -    -
                      ==========  ====  =====  ====  =====  ===

 Exploratory:
     Productive
         Appalachian         5.0   2.4      -     -      -    -
         Other               1.0   0.2    4.0   0.9    1.0  0.7
                      ----------  ----  -----  ----  -----  ---
      Total                  6.0   2.7    4.0   0.9    1.0  0.7
                      ==========  ====  =====  ====  =====  ===

     Nonproductive
         Appalachian         2.0   0.9      -     -      -    -
         Other               9.0   4.1   10.0   3.4    8.0  3.7
                      ----------  ----  -----  ----  -----  ---
     Total                  11.0   5.0   10.0   3.4    8.0  3.7
                      ==========  ====  =====  ====  =====  ===
</TABLE>

                                       12
<PAGE>
COMPETITION
-----------

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

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

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

     The  Company's  operations are affected by extensive regulation pursuant to
various  federal,  state  and  local  laws  and  regulations  relating  to  the
exploration  for  and  development,  production,  gathering,  marketing,
transportation  and  storage  of  oil  and  gas.  These regulations, among other
things, can affect the rate of oil and gas production.  The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the  discharge  of  materials  into  the  environment  or  otherwise relating to
environmental protection.  These laws and regulations require the acquisition of
a  permit  before  drilling  commences,  restricts  the  types,  quantities  and
concentration of various substances that can be released into the environment in
connection  with  drilling  activities on certain lands lying within wilderness,
wetlands  and  other  protected  areas,  and  impose substantial liabilities for
pollution  which  might  result  from  the  Company's  operations.


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

     The  Company,  primarily  through  the  wholly  owned subsidiary of Eastern
American,  Eastern  Marketing  Corporation  ("Eastern  Marketing"),  aggregates
natural  gas  through  the  purchase  of  production  from  properties  in  the
Appalachian  Basin  in  which  the  Company has an interest, the purchase of gas
delivered  through  the Company's gathering pipelines located in the Appalachian
Basin, the purchase of gas from smaller Appalachian Producers that are not large
enough  to  have  marketing  departments,  the  purchase  of gas produced in the
Southwestern areas of the United States pursuant to contractual arrangements and
the  purchase  of  gas  in  the spot market.  The Company sells gas to local gas
distribution companies, industrial end users located in the Northeast, other gas
marketing  entities  and  into the spot market for gas delivered into interstate
pipelines.  The  Company has historically attempted to balance its gas sales mix
with  approximately  one-third of its total gas sales being made under long term
contracts  (contracts  with  terms  of five years or more), one-third being sold
under  intermediate  term contracts (contracts with terms of one to five years),
and  one-third  being  sold  under short term contracts (contracts with terms of
less  than  one  year)  or  on  a  spot  market basis.  The demand for long term
contracts  has  decreased  substantially  and  no  new  long term contracts were
entered  into  in  fiscal year 1999.  Volumes that became available from expired
long  term  contracts  were  sold under intermediate and short term contracts.

                                       13
<PAGE>
     The  Company owns and operates approximately 2,100 miles of gathering lines
and  intrastate  pipelines  that are used in connection with its gas aggregation
and  marketing  activities.  In addition, the Company has entered into contracts
with  interstate  pipeline  companies  that  provide it with rights to transport
specified  volumes  of natural gas.  During the fiscal year ended June 30, 1999,
the Company aggregated and sold an average of 95.7 Mmcf of gas per day, of which
39.7  Mmcf  per day represented sales of gas produced from wells operated by the
Company.  This  represents a decrease compared to fiscal year 1998, during which
the  Company  aggregated  and  sold  an  average of 129.5 Mmcf of gas per day.

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

     The  termination  of one long term and one intermediate term sales contract
resulted  in  the  33.8 Mmcf per day decrease in sales in fiscal year 1999.  The
sale  of  gas  on  a  contract  basis  to the Company's natural gas distribution
utility  expired  on  October 31, 1998 (23.8 Mmcf per day).  The Company elected
not  to  renew the contract, allowing both parties to seek more economical sales
and  purchases  of  natural  gas  from  independent  third  parties.

     The Company  satisfied  its  obligations  under all gas sales  contracts in
fiscal year 1999 through gas production attributable to its own interests in oil
and gas properties and through production  attributable to third party interests
in oil and gas  properties  (14.5  Bcf in fiscal  1999),  and from  natural  gas
aggregated by the Company  pursuant to its aggregation and marketing  activities
from third parties (20.5 Bcf in fiscal 1999).

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

     In  March  1993,  the  Company conveyed to the Eastern American Natural Gas
Trust  (the  "Royalty  Trust"),  a  trust whose units are traded on the New York
Stock Exchange, certain net profits interests derived from the Company's working
interest  in  certain  natural  gas  properties located in the Appalachian Basin
whose  production  is  eligible for tax credits under Section 29 of the Internal
Revenue  Code.  In  connection with the Royalty Trust, Eastern Marketing entered
into  a gas purchase contract to purchase all gas production attributable to the
Royalty  Trust until termination of the Royalty Trust in May 2013.  The purchase
price under this gas purchase contract through December 1999 is based in part on
a  fixed  price  component, which escalates each year, and in part on a variable
price component, which fluctuates with certain spot market prices, provided that
the  purchase  price  during such period will not be less than a specified floor
price.  The floor price was $2.84 per Mcf in calendar year 1998 and is $3.09 per
Mcf in calendar year 1999.  The fixed price component was $3.39 in calendar year
1998  and  is  $3.56  in calendar year 1999.  The variable price is equal to the
future  contract  price  per  Mmbtu  for  natural  gas  delivered  to Henry Hub,
Louisiana plus $0.30 per Mmbtu, multiplied by 110% to reflect a fixed adjustment
for  Btu content.  The fixed price component is given a weighting of 66 2/3% and
the  variable  price  component is given a weighting of 33 1/3% through December
1999.  Beginning  in  January  2000,  the purchase price under this gas purchase
contract  will be determined solely by reference to the variable price component
without regard for any minimum purchase price.  Eastern American is a party to a
standby  performance agreement with the Royalty Trust to support the obligations
of  Eastern  Marketing  under  this  gas  purchase  contract.

                                       14
<PAGE>
MARKET  POSITION
-----------------

     During fiscal 1999, Eastern Marketing purchased call options on 5,000 Mmbtu
of  natural  gas  per  day  for the period March 1999 through October 1999.  The
options  were purchased for approximately $0.4 million, or $0.31 per Mmbtu.  The
options  provided  the  Company with the right to purchase up to 5,000 Mmbtu per
day  during  the  option  period  at  a  price  of  $2.25  per  Mmbtu.

MARKETING  FOCUS  CHANGE
-------------------------

     At  the  close  of  the  1999  fiscal year, it was determined that Eastern
Marketing would no longer enter into contracts to purchase independent producers
gas  as  this  business was becoming less economical to maintain each year.  The
strong  competition  among  various  marketing  companies  for  this business is
causing  margins  to "shrink" each year, and in the Company's opinion, this type
of  business  is  rapidly  losing  its  economic validity.  Third party contract
business  is  labor  intensive,  requiring  a sales staff and related accounting
services.  It  is the intention of Eastern Marketing to sell this portion of its
business,  provided  an  acceptable  offer  can  be  achieved, or to operate the
existing  contracts  until  they  expire.  Most of the effected contracts expire
within  a  one  year  period.  With  this new marketing focus, Eastern Marketing
should  be  better  poised  to  concentrate  its  efforts  on  marketing Eastern
American's  natural  gas.

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

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


EMPLOYEES
---------

     As of June 30, 1999, the Company had approximately 760 full-time employees.
Approximately  290  employees  are covered by six separate collective bargaining
agreements.  None  of  these agreements will expire during the next fiscal year.
Management  believes  that  its  relationship  with  its  employees  is  good.


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

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


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

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


                                       15
<PAGE>
         ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
         -------     ---------------------------------------------------

     No  matters  were submitted to a vote of security holders during the fourth
quarter  of  fiscal  year  1999.

                                     PART II
                                     -------

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

     The  Company's  common  stock  is not  traded  in a  public  market.  As of
September 1, 1999, the Company had 25 holders of record of its common stock.

     The Company  declared  dividends  in fiscal  years  1999,  1998 and 1997 of
$644,505, $1,131,000 and $1,007,000, respectively.


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

<TABLE>
<CAPTION>
                                                            Year Ended June 30,
                                           -------------------------------------------------
                                             1999       1998      1997      1996      1995
                                           ---------  --------  --------  --------  --------
                                             (Dollars in Thousands, except per share items)
<S>                                        <C>        <C>       <C>       <C>       <C>
 Operating revenue                         $285,603   $364,336  $373,961  $375,794  $145,494
 Income (loss) from continuing operations   (14,887)     3,014     2,018     7,820     1,185
 Income (loss) from continuing operations
    Per common share, basic                  (22.12)      4.53      2.93     11.16      1.68
    Per common share, assuming dilution      (22.12)      4.53      2.93     11.15      1.68
 Total assets                               436,942    439,945   434,757   461,504   471,497
 Long term debt                             280,021    261,507   260,089   254,647   267,647
 Dividends declared per common share       $   0.95   $   1.70  $   1.50  $   2.10  $   0.65
</TABLE>


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

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

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

                                       16
<PAGE>
     Important factors that could cause actual results to differ materially from
the  forward-looking  statements  include,  but  are  not  limited  to,  weather
conditions, changes in production volumes, worldwide demand and commodity prices
for  petroleum natural resources, the timing and extent of the Company's success
in  discovering,  acquiring,  developing  and  producing  oil  and  natural  gas
reserves,  risks  incident  to the drilling and operation of oil and natural gas
wells,  future  production  and  development  costs,  the effect of existing and
future  laws, governmental regulations and the political and economic climate of
the  United  States  and  New  Zealand,  the  effect  of hedging activities, and
conditions  in  the  capital  markets.

COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1999 AND 1998
--------------------------------------------------------------------------------

     The  Company  recorded a net loss of $14.9  million for the year ended June
30, 1999 compared to net income of $3.0 million for the same period in 1998. The
decrease in income of $17.9 million is attributed to a $78.7 million decrease in
revenue,  which was partially  offset by a $60.7  million  decrease in operating
expenses,  an $11.1 million increase in impairment and exploratory costs, a $3.9
million  increase  in other  income and a $7.2  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 $49.4 million for the
current  year  compared  to  $33.9  million for the prior period.  The Company's
Utility  Operating  Margin (defined as total revenue less utility gas purchased,
utility  operations  and  maintenance expense, taxes other than income taxes and
direct general and administrative expense) totaled $32.6 million for the current
period  versus  $20.8  million  for  the  prior year.  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 $12.3 million versus $15.4 million for the
prior  year.  The  Company's Marketing and Pipeline Operating Margin (defined as
gas  marketing  and  pipeline  sales  less gas marketing pipeline cost of sales)
totaled  $4.5  million  for the current period versus a loss of $2.3 million for
the  prior  period.

     REVENUES.  Total  revenues  decreased  $78.7  million  or  21.6% during the
     --------
periods.  The decrease was due to a 32.4% decrease in gas marketing and pipeline
sales,  a  12.0%  decrease  in  oil and gas sales, and a 95.6% decrease in other
operating  revenue.  Utility  gas  sales and transportation and well and service
operating  revenue  remained  relatively  constant  between  the  periods.

     Revenues from gas marketing and pipeline sales decreased $46.6 million from
$144.1  million  during  the  period ended June 30, 1998 to $97.5 million in the
period  ended  June 30, 1999.  The decrease in revenue is primarily attributable
to  a  12%  decrease  in  the  average  unit price from $2.63 to $2.32 and a 27%
decline  in  marketed  volumes  from  50.7  million dth at June 30, 1998 to 37.2
million  dth at June 30, 1999.  The decrease in volumes is primarily a result of
the termination of two contracts that accounted for 9.5 Bcfe and reduced volumes
associated  with  trading  activities.  See  other  operating revenue, discussed
below.

     Revenues from oil and gas sales  decreased  $3.0 million from $24.7 million
for the period  ended June 30, 1998 to $21.7  million for the period  ended June
30, 1999. The decrease in revenue is primarily  attributable to a 29.6% decrease
in the  average  oil sales  price  from  $15.30  to $10.76  per Bbl and an 8.59%
decrease in the average gas sales price from $2.52 to $2.30 per Mcf between June
30, 1998 and June 30, 1999. The price decline was partially offset by production
increasing 6.21% for oil and 1.23% for gas.

                                       17
<PAGE>
     Other operating revenues decreased $30.8 million from $32.2 million to $1.4
million  between  the periods.  This was primarily because 1998 included revenue
from  the  termination of a long-term gas delivery contract.  See Note 17 to the
Consolidated  Financial  Statements  for  discussion.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses decreased $60.7
     --------------------
million  or  18.9% during this period primarily as the result of a 13.3% decline
in  the  cost  of  utility  gas purchased, a 36.5% decrease in gas marketing and
pipeline  costs,  which  was  partially offset by a 7.6% increase in general and
administrative  expenses,  a  10.0%  increase  in  depreciation,  depletion  and
amortization  and  a 134.7% increase in impairment and exploratory costs.  Field
and lease operating expenses, utility operations and maintenance costs and taxes
other  than  income  remained  relatively  constant  between  the  periods.

     The  $11.3  million  decline  in the  cost of  utility  gas  purchased  was
primarily the result of the nonrecurring effect of the initial implementation of
Mountaineer's  gas supply  management  agreement  with a third party,  which was
effective November 1, 1998.

     The $53.4 million decrease in gas marketing and pipeline costs is primarily
the result of a 27% decline in purchased gas volumes from 51.1 Bcfe to 37.6 Bcfe
from  June 30, 1998 and June 30, 1999.  Contributing to the decline in costs was
a 15% decrease in the average price paid for gas purchased, from $2.67 per Mmbtu
to  $2.26 per Mmbtu between the respective periods.  Additionally, approximately
$2.4  million of purchased gas costs was charged against a reserve for losses on
future  gas  purchases,  which was primarily related to the contract settlement.
See  Note  17  to  the  Consolidated  Financial  Statements  for  discussion.

     General and  administrative  expense  increased $1.8 million as a result of
higher  labor and benefit  costs at the utility  and  increased  overhead at the
corporate level.

     Depreciation,  depletion  and  amortization  costs  increased  $2.0 million
primarily  due to  additions  to the utility gas plant in service and  corporate
fixed assets.

     Impairment and exploratory  expenses  increased $11.1 million primarily due
to the current  year cost of drilling  exploratory  dry holes of $5.9 million in
New Zealand and $1.6  million  domestically.  In  addition,  approximately  $2.2
million of leasehold and well in progress  costs were written off late in fiscal
1999.

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

     OTHER  (INCOME) EXPENSE.  Other income increased $3.9 million primarily due
     -----------------------
to the recognition of gains on the sale of property during fiscal 1999, compared
to losses in the prior year.  Also, during fiscal 1998 a reserve of $1.1 million
was  established  against  a  note  receivable.

     PROVISION  FOR  INCOME  TAXES.  The provision for income taxes changed $7.2
     -----------------------------
million  primarily  because  of  the  current  year  loss.


COMPARISON  OF  RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1998 AND 1997
--------------------------------------------------------------------------------

     The  Company  recorded  net  income and income before extraordinary loss of
$3.0  million  for  the  year ended June 30, 1998 compared to a net loss of $5.8
million and income before extraordinary loss of $2.0 million for the same period
in  1997.  The  increase  in income before extraordinary loss of $1.0 million is
attributed  to  the  contract  settlement  under  which  the  company  received
approximately $30 million (net) in cash and related partnership distributions as
described  in  Note  17  to the Consolidated Financial Statements.  The increase
resulting  from  the  contract  settlement was partially offset by a $15 million
decrease  in  operating  income resulting generally from the effects of a warmer
heating  season resulting in a $1.3 million reduction in operating income, lower
oil  and  gas sales, and lower gas marketing and pipeline margins resulting in a
$12.5  million reduction in operating income and increased corporate expenses of
$1.0 million.  Additionally, interest expense increased $2.5 million and gain on
sales  of  assets  and other income and expenses decreased $11.7 million between
the  two  periods.

                                       18
<PAGE>
     OPERATING  MARGINS.  Total  Operating  Margins  for the Company's operating
     ------------------
subsidiaries  totaled $33.9 million for 1998 compared to $50.6 million for 1997.
The  Company's  Utility  Operating Margin decreased from $22.3 for 1997 to $20.8
million  for  1998.  The  Company's  Oil and Gas Operating Margin decreased from
$18.9  million  for 1997 to $15.4 million for 1998.  The Company's Marketing and
Pipeline  Operating  Margin  decreased from $9.3 million for the prior year to a
loss  of  $2.3  million  for  the  current  year.

     REVENUES.  Total  revenues  decreased  $9.6  million  or  2.6%  during  the
     --------
periods.  The  decrease  was  due  to  a  9.7% decrease in utility gas sales and
transportation,  an  10.1%  decrease  in  gas marketing and pipeline sales and a
25.9%  decrease  in  oil  and  gas sales, which were partially offset by a $31.9
million  increase  in  other operating revenue.  See Note 17 to the Consolidated
Financial  Statements  for  discussion.

     Revenues from utility gas sales and transportation  decreased $16.9 million
or 9.7% from  $173.5  million  during  the year  ended  June 30,  1997 to $156.6
million for the same period ended June 30, 1998.  The decrease is primarily  due
to  approximately  3.0  million Mcf less in volumes of gas sold as a result of a
6.3%  decrease  in the  weighted  average  number of Degree  Days in the current
period,  partially  offset by a 3.2% increase in  transportation  revenue due to
increased usage by commercial and industrial customers.

     Revenues from gas marketing and pipeline sales decreased $16.2 million from
$160.3  million  during  the period ended June 30, 1997 to $144.1 million in the
period  ended  June 30, 1998.  The decrease in revenue is primarily attributable
to  a  3.7%  decrease  in  the average unit price and a 7.5% decline in marketed
volumes  from  56.0 million dth at June 30, 1997 to 51.8 million dth at June 30,
1998.  The  decrease  in  volumes  is a result of a change in pipeline sales and
transportation  components,  discontinued  pipeline  sales  to  a  customer, and
reduced  volumes  associated  with  trading  activities.

     Revenues from oil and gas sales  decreased  $8.6 million from $33.3 million
for the period  ended June 30, 1997 to $24.7  million for the period  ended June
30, 1998. The decrease in revenue is primarily  attributable  to a 22.9% decline
in units sold from 12.4 Bcfe at June 30, 1997 to 9.3 Bcfe and a 3.9% decrease in
the  average  unit sales  price from $2.69 to $2.58 per Mcfe for the  respective
periods.  The 22.9%  decline in units sold  between  June 30,  1997 and 1998 was
primarily as a result of the sale of the Company's limited partnership interests
in Westside Operating Partnership LP ("WOPLP"), which accounted for 2.7 Bcfe and
96.8% of the total  decline in units sold.  The sale of WOPLP  occurred in March
1997.

     Other  operating  revenues  increased  $31.9  million  between  the periods
primarily  as  a  result  of an agreement to terminate an existing long-term gas
delivery  contract.  See  Note  17  to the Consolidated Financial Statements for
discussion.

     COSTS  AND  EXPENSES.  The  Company's  costs  and  expenses decreased $25.0
     --------------------
million or 7.0% during this period primarily as the result of a 15.5% decline in
the cost of utility gas purchased, a 3.0% decrease in gas marketing and pipeline
costs,  a  29.5%  decline in the field and lease operating expenses and an 18.4%
decline  in  impairment  and  exploratory  expenses.

                                       19
<PAGE>
     The $15.6  million  decline in the cost of utility  gas  purchased  was the
result of a decrease in  purchased  gas volumes of 3.7 Bcf and a decrease in the
average commodity price of natural gas of approximately  $0.15 per Mcf purchased
and a $1.9 million  decrease in demand charges  resulting  primarily from a rate
settlement with Columbia Gas Transmission Corporation during fiscal year 1997.

     The $4.6 million decrease in gas marketing and pipeline costs is the result
of  a  3.9 million dth decline in volumes marketed offset by a $0.09 increase in
the  average  unit  cost  of  gas  sold  during  fiscal  year  1997.

     The $4.1 million decline in field and lease operating expense was primarily
the result of the reduction in operating  costs of $3.5 million  associated with
the sale of the limited partnership interests previously discussed.

     Utility  operations  and  maintenance  costs  increased 3.8% as a result of
increased  outside  services  ($0.3  million)  and  increased  labor costs ($0.3
million)

     General  and  administrative  expense  increased  3.0% as a  result  of the
inclusion  of the  selling  expenses  of Mapcom  Systems,  Inc.  ($1.3  million)
acquired by  Mountaineer in November 1997  partially  offset by generally  lower
expenses for outside services.

     Taxes  other than  income  decreased  7.5%  generally  as a result of lower
revenues.

     Impairment and exploratory expenses decreased $1.9 million primarily due to
non-recurring write-offs of exploratory properties in fiscal 1997 resulting from
decreased domestic exploratory activities and unsuccessful exploratory drilling.

     Depreciation  of pipelines,  other  property and equipment  increased  $1.7
million or 16.8% as a result of higher  depreciation  related to an  increase in
property in service and the effective depreciation rate.

     Depletion  and  depreciation  of oil  and  gas  properties  decreased  $0.7
million. The decrease related to the sale of the WOPLP properties in fiscal year
1997 which  accounted  for 2.7 Bcfe of  production  partially  offset by a 17.0%
increase in depletion and depreciation rates.

     INTEREST  EXPENSE.  Interest  expense increased 10.5% from $23.9 million to
     -----------------
$26.4  million  in  the  current  year.  The  increase was due to the additional
average  long-term  debt  outstanding  during  the  periods  resulting  from the
issuance  of  the Senior Subordinated Notes and higher interest rates during the
fiscal  year  ended  June  30,  1998.

     OTHER  (INCOME) EXPENSE.  Other income decreased $9.5 million primarily due
     -----------------------
to  the  sale of WOPLP, which occurred in March 1997 resulting in a gain of $7.8
million  compared  to  a loss of $1.2 million on the disposal of certain oil and
gas  properties  during  the  year  ended  June  30,  1998.

     PROVISION  FOR  INCOME TAXES.  The provision for income taxes excluding the
     ----------------------------
tax  benefit  for  the  extraordinary  loss was relatively unchanged between the
years.

EXTRAORDINARY  LOSS.  The  extraordinary  loss  of  $7.9  million (net of a $4.2
--------------------
million tax benefit) recorded during the fiscal year ended June 30, 1997 was due
to  the  early  extinguishment  of  debt.  In  May 1997, the Company issued $200
million  Senior Subordinated Notes using the proceeds therefrom to repay debt at
Eastern Systems Corporation ("ESC") and Eastern American of $35 million and $136
million,  respectively.


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

     Despite  improved  Operating  Margins (as defined above) from the Company's
operating  subsidiaries,  $49.4  million  for  the  current  period versus $33.9
million  for the prior period, the Company's financial condition declined during
the  current  period.  The  Company's  consolidated  working  capital  and funds
available  from  unused  short-term  credit  facilities  and  revolving  credit
facilities declined from $105.7 million at June 30,1997 to $89.5 million at June
30,  1998  and  $37.3  million  at  June  30,  1999.

     Historically,  the Company's  growth has been  accomplished  through direct
investment in utility  operations  ($11.4 million 1999, $15.8 million 1998, $9.9
million 1997) and exploration and development drilling activities ($25.3 million
1999, $20.6 million 1998, $18.0 million 1997).  These investments were primarily
financed  through a combination  of cash provided  from  operations  and through
short and long-term debt  financing  consisting of $6.2 million cash provided by
operating  activities and $22.0 million in proceeds from debt facilities for the
current  period,  $6.6 million  (excluding  $30.1  million from a  non-recurring
transaction)  and $4.5  million  respectively  for the  prior  period  and $11.4
million and $22.4 million for the period ending June 30, 1997.

     In general, the investment return on the Company's capital expenditures for
its utility  subsidiary  has enabled  management  of the utility to increase its
Operating  Margins and cash provided  (used) from  operations from $22.3 million
and $(5.1)  million in 1997, to $20.8 million and $25.2 million in 1998 to $32.6
million  and  $28.7  million  in 1999,  respectively.  However,  returns  on the
Company's investments in its oil and gas operating subsidiaries has fallen below
expectations of management during the same three year period.  Operating Margins
and cash provided  (used) in operations  for the Company's oil and gas operating
subsidiaries totaled $18.9 million and $14.2 million for 1997, $15.4 million and
$6.3 million for 1998, and $12.3 million and $0.4 million in 1999, respectively.
As a result of the lower than expected  returns on the Company's  investments in
its oil  and gas  operating  subsidiaries,  the  Company's  primary  sources  of
liquidity  (cash provided by operating  activities and short and long-term debt)
has been adversely impacted.

     In addition to, and primarily as a result of the foregoing, the Company was
in violation of certain  covenants of its Revolving  Debt  Agreement at June 30,
1999  relating to (1) Tangible  Net Worth,  (2) Current  Ratio,  and (3) Minimum
Interest  Coverage Ratio.  The Company's  lenders have not accelerated the debt.
However, as a result of the non-monetary violations described above, the Company
was prohibited from drawing down additional  borrowings under the Revolving Debt
Agreement.  Moreover,  if the debt had been accelerated,  the Company would have
been required to repay the $25 million drawn under the Revolving Debt Agreement.
Furthermore,  an  acceleration  of the debt under the Revolving  Debt  Agreement
would have also  triggered  a  cross-default  provision  of the  Company's  $200
million Senior  Subordinated  Notes. Under this circumstance,  the Company would
have considered  various  alternatives,  including seeking new and or additional
credit facilities, the sale of certain assets, or other options, to acquire such
funds or restructure its debt.

                                       21
<PAGE>
     Since June 30,  1999,  the Company and its lenders have agreed to amend the
Revolving Debt  Agreement to include (1) a reduction of the credit  availability
under the Revolving Debt Agreement from $50 million to $22 million, (2) a waiver
of the non-monetary violations as described above, and (3) certain amendments to
the Revolving Debt Agreement which would restructure certain financial covenants
as follows (a) Tangible Net Worth, as defined in the Amendment, will not be less
than $20 million plus fifty  percent  (50%) of  Consolidated  Net Income  earned
during the period  from June 30,  1997,  after  adding  back  approximately  $19
million, (b) Current Ratio, as defined in the Amendment, requirement from 1 to 1
to 0.6 to 1 through December 30, 1999 and 1 to 1 thereafter,  such current ratio
calculation  shall be calculated  without including any payments of principal on
the Notes or Subordinated  Notes which might be required to be repaid within one
year from the time of the  calculation,  and (c)  Interest  Coverage  ratio,  as
defined in the  Amendment,  reduced  from a minimum of 1.5 to 1 to 1.15 to 1 for
the next four quarters and 1.5 to 1 thereafter,  except that Adjusted EBITDA, as
defined  in  the  Amendment,  and  as  utilized  in the  numerator  within  such
calculation  shall  have  an  amount  of $19  million  added  thereto  and  such
adjustment  shall be effective for the  calculation  during the fiscal  quarters
ended September 30, 1999, December 31, 1999, March 31, 2000, and June 30, 2000.

     As part of the foregoing waivers and amendments,  the Company has agreed to
(1) make an immediate principal  reduction payment of $3 million,  (2) make four
consecutive quarterly principal payments of $750,000,  (3) set the interest rate
on  borrowed  amounts  at LIBOR  plus 300 basis  points,  (4) pay  certain  fees
totaling $335,000,  and (5) permit subsequent  redeterminations of the Borrowing
Base as defined under the Revolving Debt  Agreement,  to be  determined,  at the
discretion of the lenders, more than once during a fiscal year.

     Mountaineer  plans  to  issue   approximately  $40  million  in  unsecured,
long-term  notes during the fourth  quarter of calendar  1999. The proceeds from
this issuance will be used to reduce  short-term  borrowings  ($16.8  million at
June 30,  1999)  and for  general  corporate  uses of the  utility.  While  this
financing   will   significantly   improve  the   consolidated   current  ratio,
restrictions  limit dividend and other payments to the Company from Mountaineer.
Currently,  Mountaineer  has $67 million of  unsecured  revolving  bank lines of
credit, under which approximately $16.8 million (see above discussion) was drawn
at June 30, 1999.  Under  Mountaineer's  debt  covenants,  which  restrict  cash
outflow,  $7.3 million of dividends are available to the Company.

     The Company  believes  that its  existing  capital  resources  and expected
fiscal year 2000  results of  operation  will be  sufficient  for the Company to
remain  in  compliance  with the  requirements  of the  amended  Revolving  Debt
Agreement,   and  its  Senior   Subordinated   Note   Agreement,   and  to  fund
non-discretionary  capital expenditures.  However,  although the Company expects
that  Operating  Margins and cash provided  from  operations  will improve,  the
Company can give no assurances that such  improvements  will be realized or that
certain   violations  of  the  amended   Revolving  Debt  Agreement  and  Senior
Subordinated Note Agreement will not occur, since the future profitability, debt
service   capability  and  levels  of  capital   resource  as  well  as  capital
availability will depend to a great extent on future weather  patterns,  oil and
gas prices,  and future  exploration and development  drilling  success.  In the
event that  Operating  Margins and cash  provided  from  operations  do not meet
expectations  of  management  or if  additional  debt  covenant or debt  service
violations  occur,  the Company may elect to increase  debt levels,  restructure
debt agreements,  sell certain assets or operating  subsidiaries,  defer certain
discretionary   capital   spending   (including  oil  and  gas  exploration  and
development drilling activities),  consolidate certain field operations, or take
other actions to mitigate  liquidity  short-falls  and remedy any foreseeable or
potential  debt covenant  issues,  although no assurances can be given that such
actions will be successful.

     YEAR  2000  COMPLIANCE.  The  year  2000  issue arose because many computer
     ----------------------
systems  and  software applications as well as embedded computer chips currently
in  use  were  constructed  using  an abbreviated date field that eliminates the
first  two  digits of the year.  On January 1, 2000, these systems, applications
and  embedded  computer  chips  may incorrectly recognize the date as January 1,
1900.  Accordingly,  many computer systems and software applications, as well as
embedded  chips,  may  incorrectly process financial or operating information or
fail  to  process  such  information  completely.  The  company  recognized this
problem  and  is  addressing  its  potential  effects  on  its computer systems,
software  applications  and  operating  assets.

     The  Company  began  its  Year  2000  compliance  efforts  in 1996  and has
substantially  completed its assessment of its key business  information systems
to determine what issues, if any, exist regarding these systems' compliance with
Year 2000 issues and is taking the necessary steps to ensure its systems will be
compliant by the year 2000.

                                       22
<PAGE>
     These  steps  include  the  purchase  and  implementation  of an integrated
application  software  package,  that  together with the associated hardware and
external  consulting  resources, is expected to cost approximately $7.1 million.
In  addition,  the  Company  is  presently  in the process of modifying existing
operating  and  application  systems  that  are  not  Year  2000  compliant  and
anticipates  that  it will be successful in completing such modifications before
the calendar year ended 1999.  With the exception of the new application package
discussed  above,  the  Company  anticipates  that it can complete the necessary
modifications  to  its  information  systems  to  ensure  Year  2000  compliance
utilizing  internal  resources.

     The  costs associated with modification of existing information systems are
expected  to  consist  primarily of personnel expense for staff dedicated to the
effort.  The  Company's  policy  is  to  expense  these  costs as incurred.  The
Company also may invest in new or upgraded technology, which has definable value
lasting  beyond  2000.  In  these  instances,  such as the implementation of the
integrated  software  application  discussed  above,  the  Company  anticipates
capitalizing  and  depreciating  such  costs  over  their estimated useful life.

     In  addition  to  reviewing  its  own  computer  operating  and application
systems, the Company has initiated communications with its significant suppliers
and  vendors  to determine the extent to which these parties have addressed Year
2000 issues.  To the extent such vendors cannot provide reasonable assurances to
the  Company  of  their  readiness to handle Year 2000 issues, contingency plans
will  be  developed.  There  is  no assurance that such parties can complete the
necessary  modifications and conversions in a timely manner.  To the extent such
modifications  and  conversions  are  not completed on a timely basis and issues
outside  of  the  companies  control  arise,  the  Year 2000 issue could have an
adverse  impact  on  the  operations  of  the  Company.

     The costs associated with addressing Year 2000 issues and the date on which
the Company believes it will complete the necessary modifications are based upon
management's  best  estimates.  There  can  be no guarantee that these estimates
will  be  achieved  and  actual  results  could  differ  from those anticipated.


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

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

     Interest  rate risk is  attributable  to the  Company's  debt.  The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment needs.  There is inherent rollover risk for borrowings as they mature
and are  renewed  at  current  market  rates.  The  extent  of this  risk is not
predictable  because  of the  variability  of  future  interest  rates  and  the
Company's future financing needs. If interest rates changed by 1%, it would have
an impact of approximately $0.4 million.  The Company has not attempted to hedge
the interest  rate risk  associated  with its floating  rate debt of which $41.8
million was outstanding at year end. The Company has fixed interest rate debt of
$261.7 million, representing 86.2% of the total debt.

                                       23
<PAGE>
COMMODITY  RISK
----------------

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

     The Company periodically enters into hedging activities on a portion of its
projected  natural gas  production  through a variety of financial  and physical
arrangements  intended to support  natural gas prices at targeted  levels and to
manage  its  exposure  to  price  fluctuations.  The  Company  may  use  futures
contracts,  swaps,  options  and fixed  price  physical  contracts  to hedge its
commodity  prices.  Realized  gains and  losses  from the  Company's  price risk
management  activities  are  recognized in oil and gas sales when the associated
production occurs. The Company does not hold or issue derivative instruments for
trading  purposes.  For fiscal  2000,  the  Company  has elected to enter into a
combination  of forward  sale  collars and floors,  covering the majority of its
Appalachian natural gas.

     Mountaineer  has  entered into a new rate moratorium with the WVPSC through
2001  thereby potentially exposing itself to volatility in its gas supply costs.
If  such  risk was left unhedged, its future cash flows could vary significantly
from  historical  cash flows.  Mountaineer has entered into the Supply Agreement
with  Coral,  under  which  Mountaineer  will  purchase approximately 90% of its
natural  gas supply at a fixed cost for the full duration of the rate moratorium
thereby  substantially  reducing  its  exposure  to  market  volatility.

                                       24
<PAGE>

             ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
             -------     -------------------------------------------





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

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

We  have  audited  the  accompanying  consolidated  balance  sheets  of  Energy
Corporation  of  America  and Subsidiaries as of June 30, 1999 and 1998, and the
related  consolidated  statements  of operations, stockholders' equity, and cash
flows for each of the three years in the period ended June 30, 1999.  Our audits
also  included the financial statement schedules listed in the Index at Item 14.
These  financial  statements  and  financial  statement  schedules  are  the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these financial statements and financial statement schedules based on
our  audits.

We  conducted  our  audits  in  accordance  with  generally  accepted  auditing
standards.  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, 1999 and 1998, and the results of their operations
and  their  cash  flows for each of the three years in the period ended June 30,
1999  in conformity with generally accepted accounting principles.  Also, in our
opinion,  such financial statement schedules, when considered in relation to the
basic  consolidated financial statements taken as a whole, present fairly in all
material  respects  the  information  set  forth  therein.




DELOITTE  &  TOUCHE  LLP
Denver,  Colorado
September  27,  1999

                                       25
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  BALANCE  SHEETS
JUNE  30,  1999  AND  1998
(AMOUNTS  IN  THOUSANDS)
-----------------------------------------------------------------------------------

ASSETS                                                          1999        1998
                                                            ------------  ---------
<S>                                                         <C>           <C>
 CURRENT ASSETS:
   Cash and cash equivalents                                $    13,557   $ 21,547
                                                            ------------  ---------
   Accounts receivable:
     Utility gas and transportation                              14,259     13,027
     Gas marketing and pipeline                                   4,311      5,528
     Oil and gas sales                                            6,686      7,595
     Other                                                        9,220      7,959
                                                            ------------  ---------
                                                                 34,476     34,109
     Less allowance for doubtful accounts                        (1,622)    (1,281)
                                                            ------------  ---------
                                                                 32,854     32,828
   Gas in storage, at average cost                                  357     13,249
   Income taxes receivable                                        3,580      4,310
   Deferred income tax asset                                      3,702
   Prepaid winter gas service                                    18,474
   Prepaid and other current assets                               3,444      5,839
                                                            ------------  ---------
         Total current assets                                    75,968     77,773

 NET PROPERTY, PLANT AND EQUIPMENT (Note 2)                     315,316    318,547
                                                            ------------  ---------

 OTHER ASSETS:
   Deferred financing costs, less accumulated
     amortization of $2,485 and $1,046                            8,523      9,545
   Notes receivable, less allowance for doubtful accounts
     of $440 and $400                                             1,531      2,902
   Notes receivable - related party                               2,013      2,716
   Deferred utility charges                                      18,785     18,233
   Other                                                         14,806     10,229
                                                            ------------  ---------
         Total other assets                                      45,658     43,625
                                                            ------------  ---------

 TOTAL                                                      $   436,942   $439,945
                                                            ============  =========
</TABLE>

See notes to consolidated financial statements.             (Continued)


                                       26
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  BALANCE  SHEETS
JUNE  30,  1999  AND  1998
(AMOUNTS  IN  THOUSANDS,  EXCEPT  SHARES)
------------------------------------------------------------------------------------


LIABILITIES AND STOCKHOLDER'S EQUITY                              1999       1998
                                                                ---------  ---------
<S>                                                             <C>        <C>
CURRENT LIABILITIES:
  Accounts payable and accrued expenses                         $ 40,049   $ 38,883
  Current portion of long-term debt                                6,634        581
  Short-term debt                                                 16,799     19,174
  Funds held for future distribution                               5,378      5,716
  Accrued taxes, other than income                                 7,635      8,472
  Overrecovered gas costs                                          3,927      6,485
  Deferred income tax liability                                               5,643
  Other current liabilities                                        8,465      8,115
                                                                ---------  ---------
        Total current liabilities                                 88,887     93,069
LONG-TERM OBLIGATIONS
  Long-term debt                                                 280,021    261,507
  Gas delivery obligation and deferred trust revenue              13,839     16,127
  Deferred income tax liability                                   27,868     24,552
  Other long-term obligations                                     11,850     12,837
                                                                ---------  ---------
        Total liabilities                                        422,465    408,092
                                                                ---------  ---------

COMMITMENTS AND CONTINGENCIES (Note 15)

MINORITY INTEREST                                                      -      1,883
                                                                ---------  ---------

STOCKHOLDER'S EQUITY:
  Common stock, par value $1.00; 2,000,000 shares authorized;
     721,000 and 720,000 shares issued in 1999 and 1998              721        720
  Class A non-voting common stock, no par value; 100,000
     shares authorized; 26,000 shares issued in 1999               2,940          -
  Additional paid-in capital                                       4,656      4,510
  Retained earnings                                               13,598     29,132
  Treasury stock and notes receivable arising from
     issuance of common stock                                     (7,261)    (4,082)
  Accumulated comprehensive loss                                    (177)      (310)
                                                                ---------  ---------
        Total stockholder's equity                                14,477     29,970
                                                                ---------  ---------
TOTAL                                                           $436,942   $439,945
                                                                =========  =========
</TABLE>

See  notes  to  consolidated  financial  statements.           (Concluded)

                                       27
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  OPERATIONS
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
(AMOUNTS  IN  THOUSANDS,  EXCEPT  PER  SHARE  DATA)
------------------------------------------------------------------------------------------------------------


                                                                                1999       1998      1997
                                                                              ---------  --------  ---------
<S>                                                                           <C>        <C>       <C>
REVENUES:
  Utility gas sales and transportation                                        $158,439   $156,579  $173,463
  Gas marketing and pipeline sales                                              97,467    144,133   160,345
  Oil and gas sales                                                             21,727     24,689    33,301
  Well operations and service revenues                                           6,540      6,751     6,526
  Contract settlement and other                                                  1,430     32,184       306
                                                                              ---------  --------  ---------
                                                                               285,603    364,336   373,941
                                                                              ---------  --------  ---------
COSTS AND EXPENSES:
  Utility gas purchased                                                         73,842     85,166   100,774
  Gas marketing and pipeline cost of sales                                      92,981    146,367   150,967
  Field operating expenses                                                       9,214      9,788    13,913
  Utility operations and maintenance                                            22,496     22,084    21,320
  General and administrative                                                    25,112     23,330    22,640
  Taxes, other than income                                                      15,260     14,882    16,094
  Depletion and depreciation of oil and gas properties                           8,409      8,021     8,756
  Depreciation of pipelines, other property and equipment                       13,629     12,017    10,289
  Exploration and impairment                                                    19,388      8,262    10,121
                                                                              ---------  --------  ---------
                                                                               280,331    329,917   354,874
                                                                              ---------  --------  ---------
        Income from operations                                                   5,272     34,419    19,067
                                                                              ---------  --------  ---------
OTHER (INCOME) AND EXPENSE:
  Interest                                                                      26,554     26,386    23,881
  Loss (gain) on sale of assets                                                    (91)     1,208    (8,303)
  Other                                                                         (1,079)     1,551      (647)
                                                                              ---------  --------  ---------
                                                                                25,384     29,145    14,931
                                                                              ---------  --------  ---------
Income (loss) before income taxes, minority interest and extraordinary loss    (20,112)     5,274     4,136
Provision (benefit) for income taxes                                            (5,232)     2,017     1,966
                                                                              ---------  --------  ---------
Income (loss) before minority interest and extraordinary loss                  (14,880)     3,257     2,170
Minority interest                                                                    7        243       152
                                                                              ---------  --------  ---------
Income (loss) before extraordinary loss                                        (14,887)     3,014     2,018
Extraordinary loss on early extinguishment of debt (net of income
   tax benefit of $4,233)                                                            -          -     7,861
                                                                              ---------  --------  ---------

NET INCOME (LOSS)                                                             $(14,887)  $  3,014  $ (5,843)
                                                                              =========  ========  =========

Earnings per common share
   Income before extraordinary loss                                           $ (22.12)  $   4.53  $   2.93
   Extraordinary loss                                                                -          -  $ (11.42)
                                                                              ---------  --------  ---------
   Basic earnings (loss) per common share                                     $ (22.12)  $   4.53  $  (8.49)
                                                                              =========  ========  =========
   Diluted earnings (loss) per common share                                   $ (22.12)  $   4.53  $  (8.49)
                                                                              =========  ========  =========
</TABLE>

See  notes  to  consolidated  financial  statements.


                                       28
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  STOCKHOLDERSEQUITY
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
(AMOUNTS  IN  THOUSANDS,  EXCEPT  PER  SHARE  DATA)
------------------------------------------------------------------------------------------------------------------



                                                                     Class A   Additional
                                                            Common    Common     Paid-In     Retained    Treasury
                                                             Stock    Stock      Capital     Earnings     Stock
                                                            -------  --------  -----------  ----------  ----------
<S>                                                         <C>      <C>       <C>          <C>         <C>
Balance, June 30, 1996                                      $   711  $      -  $     4,086  $  34,099   $  (1,121)

  Components of comprehensive loss:
    Foreign currency translation adjustment
    Net loss                                                                                   (5,843)

  Comprehensive loss
  Dividends ($1.50 per share)                                                                  (1,007)
  Exercise of employee stock options for notes receivable         3                    125
  Issuance of common stock                                                              10
  Purchase of treasury stock                                                                               (2,054)
  Reduction of notes receivable
                                                            -------  --------  -----------  ----------  ----------

Balance, June 30, 1997                                          714         -        4,221     27,249      (3,175)

  Components of comprehensive income:
    Foreign currency translation adjustment
    Net income                                                                                  3,014

  Comprehensive income
  Dividends ($1.70 per share)                                                                  (1,131)
  Issuance of common stock                                        3                    164
  Exercise of employee stock options for notes receivable         3                    125
  Purchase of treasury stock                                                                                 (523)
  Reduction of notes receivable
                                                            -------  --------  -----------  ----------  ----------

Balance, June 30, 1998                                          720         -        4,510     29,132      (3,698)

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

  Comprehensive loss
  Dividends ($0.95 per share)                                                                    (647)
  Common stock issued for services                                1                    146
  Conversion of minority interest                                       2,040
  Employee stock purchases                                                900
  Purchase of treasury stock - common                                                                      (1,761)
  Purchase of treasury stock - Class A                                                                       (437)
  Reduction of notes receivable
                                                            -------  --------  -----------  ----------  ----------
Balance, June 30, 1999                                      $   721  $  2,940  $     4,656  $  13,598   $  (5,896)
                                                            =======  ========  ===========  ==========  ==========


                                                             Notes Received/     Accumulated
                                                               Issuance of      Comprehensive    Stockholders
                                                                  Stock         Income (Loss)       Equity
                                                            -----------------  ---------------  --------------
<S>                                                         <C>                <C>              <C>
Balance, June 30, 1996                                      $           (250)  $           25   $      37,550
                                                                                                --------------
  Components of comprehensive loss:
    Foreign currency translation adjustment                                              (176)           (176)
    Net loss                                                                                           (5,843)
                                                                                                --------------
  Comprehensive loss                                                                                   (6,019)
  Dividends ($1.50 per share)                                                                          (1,007)
  Exercise of employee stock options for notes receivable               (128)                               -
  Issuance of common stock                                                (8)                               2
  Purchase of treasury stock                                                                           (2,054)
  Reduction of notes receivable                                          126                              126
                                                            -----------------  ---------------  --------------
Balance, June 30, 1997                                                  (260)            (151)         28,598
                                                                                                --------------
  Components of comprehensive income:
    Foreign currency translation adjustment                                              (159)           (159)
    Net income                                                                                          3,014
                                                                                                --------------
  Comprehensive income                                                                                  2,855
  Dividends ($1.70 per share)                                                                          (1,131)
  Issuance of common stock                                                                                167
  Exercise of employee stock options for notes receivable               (128)                               -
  Purchase of treasury stock                                                                             (523)
  Reduction of notes receivable                                            4                                4
                                                            -----------------  ---------------  --------------
Balance, June 30, 1998                                                  (384)            (310)         29,970
                                                                                                --------------
  Components of comprehensive loss:
    Foreign currency translation adjustment                                               133             133
    Net loss                                                                                          (14,887)
                                                                                                --------------
  Comprehensive loss                                                                                  (14,754)
  Dividends ($0.95 per share)                                                                            (647)
  Common stock issued for services                                                                        147
  Conversion of minority interest                                       (150)                           1,890
  Employee stock purchases                                              (856)                              44
  Purchase of treasury stock - common                                                                  (1,761)
  Purchase of treasury stock - Class A                                                                   (437)
  Reduction of notes receivable                                           25                               25
                                                            -----------------  ---------------  --------------
Balance, June 30, 1999                                      $         (1,365)  $         (177)  $      14,477
                                                            =================  ===============  ==============
</TABLE>

                 See notes to consolidated financial statements.


                                       29
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
CONSOLIDATED  STATEMENTS  OF  CASH  FLOWS
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
(AMOUNTS  IN  THOUSANDS)
-----------------------------------------------------------------------------------------------



                                                                 1999       1998        1997
                                                               ---------  ---------  ----------
<S>                                                            <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss)                                            $(14,887)  $  3,014   $  (5,843)
  Adjustments to reconcile net income (loss) to net cash
  provided by operating activities:
    Minority interest                                                 7        243         152
    Depletion, depreciation and amortization                     22,837     20,825      19,955
    Write-off of deferred financing costs                                                4,363
    Loss (gain) on sale of assets                                   (91)     1,208      (8,304)
    Deferred income taxes                                        (7,574)     1,482      (2,534)
    Exploration and impairment                                   16,778      8,262      10,121
    Provision for losses on accounts receivable                   2,295      2,572       2,102
    Other, net                                                   (2,245)    (3,539)     (2,319)
                                                               ---------  ---------  ----------
                                                                 17,120     34,067      17,693
 Changes in assets and liabilities:
    Accounts receivable                                          (2,313)     2,631       1,407
    Gas in storage                                               12,892       (608)       (353)
    Income taxes receivable                                         730     (2,918)      1,850
    Prepaid and other assets                                    (16,079)    (1,725)     (3,014)
    Accounts payable and other current liabilities                1,163      7,846      (5,905)
    Funds held for future distribution                             (338)      (299)        823
    Overrecovered gas costs                                      (2,558)    (3,165)     (2,128)
    Other                                                        (4,382)       897        (849)
                                                               ---------  ---------  ----------
        Net cash provided by operating activities                 6,235     36,726       9,524
                                                               ---------  ---------  ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Expenditures for property, plant and equipment                (36,659)   (38,693)    (26,376)
  Proceeds from sale of oil and gas properties                    3,444        568       1,114
  Proceeds from sale of limited partnership interest                  -          -      11,250
  Notes receivable and other                                         70       (238)     (1,556)
                                                               ---------  ---------  ----------
        Net cash provided by (used in) investing activities     (33,145)   (38,363)    (15,568)
                                                               ---------  ---------  ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from issuance of long-term debt                       27,500      1,298     271,000
  Principal payments on long-term debt                           (3,084)      (296)   (255,854)
  Short-term borrowings, net                                     (2,375)     3,450       7,332
  Purchase of treasury stock                                     (2,198)      (523)     (2,054)
  Dividends                                                        (967)      (834)     (1,007)
  Other equity transactions                                          44       (124)        299
  Deferred financing costs                                            -       (601)     (7,055)
                                                               ---------  ---------  ----------
        Net cash provided by (used in) financing activities      18,920      2,370      12,661
                                                               ---------  ---------  ----------
        Net increase (decrease) in cash and cash equivalents     (7,990)       733       6,617
Cash and cash equivalents, beginning of year                     21,547     20,814      14,197
                                                               ---------  ---------  ----------

CASH AND CASH EQUIVALENTS, END OF YEAR                         $ 13,557   $ 21,547   $  20,814
                                                               =========  =========  ==========
</TABLE>

See  notes  to  consolidated  financial  statements.


                                       30
<PAGE>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
NOTES  TO  CONSOLIDATED  FINANCIAL  STATEMENTS
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
---------------------------------------------------------

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 integrated
energy  company.  All  references to the "Company" include Energy Corporation of
America  and  its  consolidated  subsidiaries.

Natural Gas Distribution System - The Company operates, through its wholly owned
-------------------------------
subsidiary  Mountaineer  Gas Company ("Mountaineer"), a natural gas distribution
system in West Virginia.  Mountaineer provides natural gas sales, transportation
and  distribution  service  to residential, commercial, industrial and wholesale
customers.  As  a  public  utility,  Mountaineer is subject to regulation by the
Public  Service  Commission  of  West  Virginia  ("WVPSC").

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

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

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; Eastern Systems
Corporation  ("ESC")  and  its  wholly  owned  subsidiary,  Mountaineer  and its
subsidiaries;  Westech  and  WENZL and its investment in certain New Zealand oil
and  gas exploration joint ventures.  The Company has investments in oil and gas
limited  partnerships  and  joint  ventures and has recognized its proportionate
share  of  these  entities'  revenues,  expenses,  assets  and liabilities.  All
significant  intercompany  transactions  have  been  eliminated in consolidation
except  gas  sales  between  Eastern  American  and  Mountaineer  (see Note 14).

The  Company  owned an 80% interest in a limited partnership, Westside Operating
Partnership  LP  ("WOPLP"),  until  the  end  of  March 1997 (see Note 3).  This
investment  had  been  consolidated  prior  to  March  31,  1997  (see Note 12).

Fourth  Quarter  Results - During the fourth quarter of fiscal 1999, the Company
------------------------
had  the  normal  weather  related  decline  in  earnings  and unproved property
impairments.  However,  due to significantly more drilling and other exploratory
related  activities  in  New Zealand and the Rocky Mountains, the fourth quarter
loss  is  greater  than  usual.

                                       31
<PAGE>
Cash  and  Cash  Equivalents  -  Cash  and  cash  equivalents include short-term
----------------------------
investments  maturing  in  three  months  or  less  from  the  date  acquired.

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

The  provision  for  depreciation  of  Mountaineer's utility plant is based on a
composite  straight-line  method.  The  average  composite depreciation rate was
3.98%,  3.73%  and  3.77%  for 1999, 1998 and 1997, respectively.  Mountaineer's
property,  plant and equipment includes capitalized overhead for payroll related
costs  and  administrative  and general expenses and an allowance for funds used
during  construction  in  accordance  with  WVPSC  policies.

Other  property,  equipment,  pipelines and buildings are stated at cost and are
depreciated  using  straight-line  and accelerated methods over estimated useful
lives  ranging  from  three  to  30  years.  During fiscal 1999, $8.6 million of
retired other property and equipment was charged against its related accumulated
depreciation.

Repairs  and  maintenance  costs  are  charged  against  income  as  incurred;
significant  renewals  and betterments are capitalized.  Gains or losses related
to  retirement  of  utility property, net of any salvage and cost of removal are
credited  or  charged  to  accumulated  depreciation.  Gains  and  losses  on
dispositions  of  other  property,  equipment,  pipelines  and  buildings  are
recognized  as  income.

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

<TABLE>
<CAPTION>
                                                                 1999        1998
                                                            ----------  ----------
<S>                                                         <C>         <C>
 Oil and gas properties                                     $ 216,650   $ 210,650
 Utility plant                                                182,590     170,721
 Other property and equipment                                  13,948      23,743
 Pipelines                                                     19,021      18,783
                                                            ----------  ----------
                                                              432,209     423,897
 Less accumulated depletion, depreciation and amortization   (116,893)   (105,350)
                                                            ----------  ----------
 Net property, plant and equipment                          $ 315,316   $ 318,547
                                                            ==========  ==========
</TABLE>

Long-Lived  Assets  -  Statement  of Financial Accounting Standards ("SFAS") No.
------------------
121,  "Accounting  for  the  Impairment  of Long-Lived Assets and for Long-Lived
Assets  to  be  Disposed Of", requires all companies to assess long-lived assets
and  assets  to  be  disposed  of  for  impairment  and  requires rate-regulated
companies  to  write-off  regulatory assets whenever those assets no longer meet
the  recognition criteria as defined by SFAS No. 71, "Accounting for the Effects
of  Certain  Types of Regulation".  For the three years ended June 30, 1999, the
Company  determined  that  no  impairment needed to be recognized for applicable
assets.

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

                                       32
<PAGE>
Deferred  Financing  Costs  -  Certain legal, underwriting fees and other direct
--------------------------
expenses  associated with the issuance of credit agreements, lines of credit and
other  financing  transactions have been capitalized.  These financing costs are
being  amortized  over  the  term  of  the  related  credit  agreement.

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

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

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

Revenues and Purchased Gas Costs - Utility gas sales and transportation revenues
--------------------------------
included in income are based on amounts billed to customers on a cycle basis and
estimated  amounts  for gas delivered but unbilled at the end of each accounting
period.

Gas costs are expensed as incurred.  For the years ended June 30, 1999, 1998 and
1997,  purchased  gas  costs  included  $2.8 million, $4 million and $4 million,
respectively,  in  amortization  of  overrecovered  gas  costs recorded prior to
November  1,  1995.  (See  Note  18).

Oil  and  gas sales are recognized as income when the oil or gas is produced and
sold.

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".

Hedging  Activities  -  The Company periodically hedges a portion of its oil and
-------------------
gas  production  through futures and swap agreements.  The purpose of the hedges
is  to provide a measure of stability in the volatile environment of oil and gas
prices.  The  Company  recognizes  gains  and  losses  in  the  futures and swap
agreements  at  the  time  the  hedged  volumes  are sold as part of oil and gas
revenues.

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

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

Regulatory Accounting - Mountaineer is subject to the provisions of SFAS No. 71,
---------------------
"Accounting  for  the  Effects  of  Certain  Types of Regulation."  Accordingly,
Mountaineer  has  recorded  certain  assets and liabilities that result from the
effects  of  the  ratemaking  process that would not be recorded under generally
accepted  accounting  principles  for  non-regulated entities.  Such amounts are
primarily  related  to future amounts recoverable for income taxes (see Note 6).
Discontinuance  of  cost-based regulation or increased competition might require
regulated entities to reduce their asset balances to reflect a market basis less
than  cost  and to write off their associated regulatory assets and liabilities.

                                       33
<PAGE>
The  Company  has  evaluated  the  continued  applicability  of  SFAS  No.  71,
considering  such  factors  as regulatory changes and the impact of competition.
The  Company  cannot  predict  the  likelihood  of  discontinuance of cost-based
regulation in the future or the impact of increased competition on the Company's
future  financial  position  and  results  of  operations.

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

Concentration of Credit Risk - The Company maintains its cash accounts primarily
----------------------------
with  a single bank and invests cash in money market accounts, which the Company
believes  to  have  minimal  risk.  As  operator  of  jointly  owned oil and gas
properties,  the  Company  sells oil and gas production to numerous U.S. oil and
gas  purchasers,  and  pays  vendors  on  behalf of joint owners for oil and gas
services.  Both  purchasers  and  joint  owners  are  located  primarily  in the
northeastern  United  States.  The risk of nonpayment by the purchasers or joint
owners is considered minimal.  The Company as owner of a utility has receivables
from both residential and commercial customers who are located in West Virginia,
where  no  one  customer  constitutes  a  significant  credit risk.  The risk of
nonpayment  by purchasers, joint owners or utility customers 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, 1999, the Company has not
been  fined  or  cited  for  any  environmental  violations,  which would have a
material  adverse  effect upon capital expenditures, earnings or the competitive
position  of  the  Company.

Recent  Accounting Pronouncements - The Company adopted SFAS No. 130, "Reporting
---------------------------------
Comprehensive  Income",  effective July 1, 1998.  The standard establishes rules
for  the  reporting  of  comprehensive income and its components.  The Company's
comprehensive income (loss) consists of foreign currency translation adjustments
and  is  presented  in  the Consolidated Statement of Stockholders' Equity.  The
adoption  of  SFAS  No.  130  had no impact on the Company's total Stockholders'
equity.  Prior  year  financial  statements  have  been reclassified to conform.
In  June  1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" was issued, which is effective for all fiscal quarters of all fiscal
years  beginning  after  June 15, 2000.  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.
The  Company has not fully analyzed the impact of the provisions of SFAS No. 133
will  have  on  the  Company's  financial  statements.

                                       34
<PAGE>
Supplemental  Disclosures  of  Cash  Flow  Information  - Supplemental cash flow
------------------------------------------------------
information  for  the  years  ended  June  30  is  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                         1999     1998      1997
                                                        -------  -------  --------
<S>                                                     <C>      <C>      <C>
 Cash paid (received) for:
   Interest (net of capitalized interest of $0, $37,
      and $323 in 1999, 1998 and 1997, respectively)    $25,670  $25,025  $19,921
   Income taxes, net                                      1,451    3,004   (1,142)
 Noncash investing and financing activities:
    Dividends declared and unpaid at year end                        316
    Seller financed acquisition                             150      943
    Acquisition of property for cancellation of notes     1,900
</TABLE>

3.     DISPOSITIONS

Westside  Operating  Partnerships  LP  -  In  March  1997, the Company exchanged
-------------------------------------
warrants  held  representing a 30% ownership interest of a third party for a 30%
interest  in  a  newly  formed  oil and gas limited liability company, Breitburn
Energy Company, LLC ("BEC"), the successor to WOPLP.  BEC redeemed the Company's
previous  interest  and  purchased  certain  oil  and gas properties, paying the
Company  $11.3  million  plus  a  $1.5  million  variable rate note with certain
conversion  options  and  distributing  certain WOPLP oil and gas properties and
real  estate  to  the Company.  The Company recognized a gain of $7.8 million in
fiscal  1997 on the transaction.  During fiscal 1999, BEC sold additional shares
of  stock,  which  reduced  the Company's interest to approximately 25.35%.  For
accounting  purposes,  the  Company's  equity interest carrying value in BEC has
been  eliminated  due to the recognition of its proportionate share of operating
losses.

4.     RISK  MANAGEMENT

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

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

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

                                       35
<PAGE>
Also  at  June 30, 1999, the Company had natural gas fixed price purchase option
contracts  for  the  purchase  and  physical  delivery  of  615,000 Mmbtu of gas
expiring  through  October  1999.  The  cost  of  these  options,  which totaled
approximately  $190,000 for the year ended June 30, 1999, is included in Cost of
Gas Sales for the month to which the options were applicable.  At June 30, 1999,
the  remaining  options,  for  the months of July 1999 through October 1999, are
carried  at  cost  that  totaled  $189,875  and  approximates  fair  value.

As  of  June  30,  1998,  the  Company  had natural gas swap agreements maturing
through October 1998 covering 320,000 Mmbtu.  At June 30, 1998, the market value
of these swaps, the net amount the Company would receive to terminate these swap
agreements  was  nominal.

For the years ended June 30, 1999 and 1998, the Company recognized a net loss on
its  natural  gas  hedging  activities  of  $32,240  and  $47,000, respectively.

Fixed  Price  Gas  Purchase Contracts - Mountaineer has entered into fixed price
-------------------------------------
contracts  to  purchase  gas  in  the  future.  Effective  November  1,  1998,
Mountaineer  entered  into  a  contract  with a third party to purchase up to 24
million  dth of natural gas annually for a fixed price.  The third party assumed
management  and  financial  obligation  of Mountaineer's firm transportation and
storage  agreements.  In  addition,  Mountaineer  transferred  ownership  of all
storage volumes owned on November 1, 1998 to the third party in exchange for the
third  party  to provide delivery of such volumes during the fiscal 1999 heating
season,  which  has  been  recorded  as  a  current asset.  The contract expires
October  31,  2001.


5.     DEBT

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

<TABLE>
<CAPTION>
                                                                   1999       1998
                                                                 ---------  ---------
<S>                                                              <C>        <C>
 ECA senior subordinated notes, interest at 9.5% payable
   semi-annually, due May 15, 2007                               $200,000   $200,000
 Mountaineer unsecured senior notes, interest at 7.59% payable
   semi-annually, due October 1, 2010                              60,000     60,000
 ECA revolving credit, interest floating at Prime, plus 1.5% or
    LIBOR plus 3%, due 2002                                        25,000
 Installment notes payable, collateralized by deeds of trust,
   at interest rates ranging from 6.2% to 8%, respectively          1,655      2,088
                                                                 ---------  ---------
                                                                  286,655    262,088
 Less current portion                                              (6,634)      (581)
                                                                 ---------  ---------
                                                                 $280,021   $261,507
                                                                 =========  =========
</TABLE>

The  Company's  various  debt  agreements  contain  certain  restrictions  and
conditions  among  which  are  limitations  on  indebtedness, funding of certain
subsidiaries, dividends and investments, and certain tangible net worth and debt
and interest coverage ratio requirements.  The agreements require the Company to
maintain  certain  financial  conditions,  including  a  minimum  net  worth,
restriction  on funded debt and restrictions on the amount of dividends that can
be  declared.  Additionally, under its debt covenants, Mountaineer is restricted
in  the  payment  of dividends to the Company.  As of June 30, 1999, Mountaineer
had  approximately  $7.3  million available for declaration  of  dividends.

                                       36
<PAGE>
Scheduled  maturities  of the Company's long-term debt at June 30, 1999 for each
of  the  next  five  years  and  thereafter  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
<S>          <C>
2000         $  6,634
2001            3,659
2002           22,461
2003            3,461
2004            3,461
 Thereafter   246,979
             --------
             $286,655
             ========
</TABLE>

Revolving  Credit  -  The  Company  had  a $50 million revolving credit facility
-----------------
secured  by  certain  properties,  interest and contracts.  The interest rate is
variable based on Eurodollars or other defined basis.  The annual commitment fee
ranges  between  0.3%  and  0.625% depending on usage.  As of June 30, 1999, $25
million  was  outstanding  under this facility.  The Company was in violation of
certain  financial  covenants  including  tangible  net worth, current ratio and
interest  coverage at June 30, 1999.  The lenders have waived the violations and
amended  the  agreement.  The amendment reduces the borrowing arrangement to $22
million,  requires a principal reduction of $6 million during fiscal 2000 and an
amendment  fee  of  $335,000.  Interest  rates were increased as reflected above
while  the minimum financial covenant requirements were reduced through June 30,
2000.

Extinguishment  of  Debt  -  In May 1997, the Company issued $200 million senior
------------------------
subordinated notes using the proceeds therefrom to repay debt outstanding at ESC
and  Eastern  American  of  $35  million  and  $136 million, respectively.  As a
result,  the  Company  recorded an extraordinary loss of $7.86 million, net of a
tax  benefit  of  $4.23  million.

Short-Term  Debt  -  Mountaineer had unsecured bank lines of credit totaling $67
----------------
million  and $74 million as of June 30, 1999 and 1998, respectively.  During the
years  ended  June  30, 1999 and 1998, the maximum outstanding balance was $53.2
million and $44.9 million, respectively, and the average daily balance was $32.5
million and $26.2 million, respectively.  The weighted average interest rate was
5.5%  and  6.02% on the balance outstanding during the years ended June 30, 1999
and  1998,  respectively.

Other  Credit  Facilities  -  Eastern  American  had a $3 million and $6 million
-------------------------
letter  of  credit, as of June 30, 1999 and 1998, respectively, issued by a bank
in  support of Eastern American's obligations under a gas purchase contract with
the  royalty trust (see Note 15).  The letter of credit reduces by $3 million on
June 30 of each year until its expiration on June 30, 2000.  As of June 30, 1999
and  1998,  no  amounts  had  been  drawn  under  the letter of credit.  Eastern
American  also  has  an  unsecured revolving line of credit totaling $2 million,
which expires December 31, 1999 and charges an interest rate of prime plus 0.5%.
As  of  June  30,  1999  and 1998, no amounts were outstanding under the line of
credit.

Seller  Financed  Note - The Company purchased a natural gas gathering system in
----------------------
West  Virginia  for  $1.2  million.  The  Company  paid $0.3 million in cash and
issued  a  note  for  the balance payable to the seller in 100 consecutive equal
monthly  payments.  As  of  June  30, 1999 and 1998, the balance of the note was
$0.8  million  and  $0.9  million.

                                       37
<PAGE>
6.     INCOME  TAXES

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

<TABLE>
<CAPTION>
                                                 1999     1998      1997
                                               --------  -------  --------
<S>                                            <C>       <C>      <C>
 Current:
   Federal                                     $ 2,273   $  586   $   491
   State                                            69      (51)     (224)
                                               --------  -------  --------
   Total current                                 2,342      535       267
                                               --------  -------  --------
 Deferred:
   Federal                                      (8,176)    (155)   (4,141)
   State                                           602    1,637     1,607
                                               --------  -------  --------
   Total deferred                               (7,574)   1,482    (2,534)
                                               --------  -------  --------
   Total provision (benefit) for income taxes  $(5,232)  $2,017   $(2,267)
                                               ========  =======  ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                          1999      1998      1997
                                                        --------  --------  --------
<S>                                                     <C>       <C>       <C>
 Tax expense (benefit) at the federal statutory rate    $(6,838)  $ 1,793   $(2,707)
 State taxes, net of federal tax effects                   (919)      358      (541)
 Foreign losses                                                       838       635
 Section 29 tax credits                                     921    (1,783)   (1,866)
 Change in valuation allowance on federal, foreign
  and state deferred tax assets, net of federal effect     (592)      571     1,805
 Investment tax credit expiration                           530
 IRS adjustment                                             519
 Other, net                                               1,147       240       407
                                                        --------  --------  --------
 Provision (benefit) for income taxes                   $(5,232)  $ 2,017   $(2,267)
                                                        ========  ========  ========
</TABLE>

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

                                       38
<PAGE>
Components  of  the  Company's  federal  and  state  deferred  tax  assets  and
liabilities,  as  of  June  30,  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                            1999                             1998
                                               -------------------------------  -------------------------------
                                                Federal     State      Total     Federal     State      Total
                                               ---------  ---------  ---------  ---------  ---------  ---------
<S>                                            <C>        <C>        <C>        <C>        <C>        <C>
  Deferred tax assets:
    Overrecovered gas costs                    $  1,339   $    354   $  1,693   $  2,209   $    583   $  2,792
    Bad debt allowance                              566        150        716        641        169        810
    Deferred compensation and profit sharing        162         43        205      1,155        304      1,459
    Postretirement and pension obligations          913        242      1,155        696        183        879
    Tax credits and carryforwards                13,058      8,774     21,832     14,892     10,553     25,445
    Other long-term obligations                   1,272        337      1,609        860        228      1,088
    Other                                        11,899      3,150     15,049      9,408      1,345     10,753
                                               ---------  ---------  ---------  ---------  ---------  ---------
      Total deferred tax assets                  29,209     13,050     42,259     29,861     13,365     43,226
                                               ---------  ---------  ---------  ---------  ---------  ---------
  Deferred tax liabilities:
    Property, plant and equipment               (39,529)   (10,543)   (50,072)   (48,897)   (13,263)   (62,160)
    Federal income tax on state tax credits      (2,983)               (2,983)    (3,588)               (3,588)
    Other liabilities                            (5,920)    (2,530)    (8,450)    (1,976)      (525)    (2,501)
                                               ---------  ---------  ---------  ---------  ---------  ---------
      Total deferred tax liabilities            (48,432)   (13,073)   (61,505)   (54,461)   (13,788)   (68,249)
                                               ---------  ---------  ---------  ---------  ---------  ---------
  Valuation allowance                                       (4,920)    (4,920)    (1,252)    (3,920)    (5,172)
                                                          ---------  ---------  ---------  ---------  ---------
  Net deferred income tax liability             (19,223)    (4,943)   (24,166)   (25,852)    (4,343)   (30,195)
                                                                                ---------
  Current deferred tax asset (liability)          2,926        776      3,702     (4,698)      (945)    (5,643)
                                               ---------  ---------  ---------  ---------  ---------  ---------
  Long-term deferred tax liability             $(22,149)  $ (5,719)  $(27,868)  $(21,154)  $ (3,398)  $(24,552)
                                               =========  =========  =========  =========  =========  =========
</TABLE>

At  June  30,  1999, the Company has the following federal and state tax credits
and  carryforwards  (in  thousands):

<TABLE>
<CAPTION>
                                          Year of
                                 Amount   Expiration
                                 -------  ----------
<S>                              <C>      <C>
 AMT and Section 29 tax credits  $12,445        None
 Investment tax credits              613   2000-2001
                                 -------
 Total federal credits           $13,058
                                 =======

 West Virginia tax credits       $ 8,774        2002
                                 =======
</TABLE>

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

Included  in  other  long-term  assets  as  of  June  30, 1999 and 1998 is a net
regulatory  asset  recorded  by  Mountaineer  in  accordance  with state utility
ratemaking  practices  related to future amounts recoverable for income taxes of
$10.9  million  and  $11.3  million,  respectively.

                                       39
<PAGE>
7.     EMPLOYEE  BENEFIT  PLANS

The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock Plan
(the  "Plan")  for  the  stated  purpose  of expanding and improving profits and
prosperity  and to assist the Company in attracting and retaining key personnel.
The  Plan  is  noncontributory,  and its continuance from year to year is at the
discretion  of  the Board of Directors.  The annual profit sharing pool is based
on  calculations  set forth in the Plan.  One-half of the pool is generally paid
to eligible employees within 120 days of the end of the fiscal year and one-half
is deferred to the following year.  Generally, to be eligible to participate, an
employee  must  have  been continuously employed for two or more years; however,
employees  with  less than two years of employment may participate under certain
circumstances.  The  Company  recognized  $0.5  million,  $2.6  million and $1.1
million  of  profit  sharing expense during the years ended June 30, 1999, 1998,
and  1997,  respectively.

For  certain  subsidiaries,  the Company sponsors a Section 401(k) plan covering
all  full-time  employees who wish to participate.  The Company's contributions,
which  are  principally based on a percentage of the employee contributions, and
charged  against income as incurred, totaled $182,600, $153,600 and $140,300 for
the  years  ended  June  30,  1999,  1998  and  1997,  respectively.

8.     PENSION  PLAN

Mountaineer sponsors a Retirement Income Plan (the "Pension Plan"), which covers
substantially  all  qualified  Mountaineer  employees  21 years of age and over.
Employees become fully vested upon completion of five years of credited service,
as  defined.  Retirement  income  is  based on credited years of service and the
employees'  level  of  compensation, as defined.  The Pension Plan is subject to
the provisions of the Employee Retirement Income Security Act of 1974 ("ERISA").
The  determination  of  contributions  is  made in consultation with the Pension
Plan's  actuary  and  is  based  upon  anticipated earnings of the Pension Plan,
mortality  and  turnover  experience,  the funded status of the Pension Plan and
anticipated  future  compensation levels.  Mountaineer's funding policy is to be
in  compliance  with  ERISA  guidelines  and to make annual contributions to the
Pension  Plan  to assure that all employees' benefits will be fully provided for
by  the  time  they  retire.

                                       40
<PAGE>
The  following  table  sets  forth  the Pension Plan's funded status and amounts
recognized in the consolidated balance sheets as of June 30, as determined by an
independent  actuary  (in  thousands):

<TABLE>
<CAPTION>
                                                           1999       1998
                                                       ---------  ---------
<S>                                                    <C>        <C>

 Reconciliation of Funded Status
   Funded status                                       $ (6,640)  $ (6,058)
   Unrecognized actuarial loss                            1,935      1,488
   Unrecognized prior service cost                          729          -
                                                       ---------  ---------
   Net pension accrued liability                         (3,976)    (4,570)
   Adjustment required to recognize minimum liability         -          -
                                                       ---------  ---------
   Net pension liability recognized                    $ (3,976)  $ (4,570)
                                                       =========  =========

 Change in Projected Benefit Obligation
   Benefit obligation at beginning of year             $(33,110)  $(29,777)
   Service cost                                            (750)      (717)
   Interest cost                                         (2,496)    (2,219)
   Plan amendments                                         (781)         -
   Actuarial loss                                          (145)    (3,318)
   Benefit payments                                       2,918      2,921
                                                       ---------  ---------
   Benefit obligation at end of year                   $(34,364)  $(33,110)
                                                       =========  =========

 Change in Plan Assets
   Fair value of plan assets at beginning of year      $ 27,052   $ 24,954
   Actuarial return on plan assets                        1,628      3,612
   Employer contribution                                  1,962      1,407
   Benefit payments                                      (2,918)    (2,921)
                                                       ---------  ---------
   Fair value of plan assets at end of year            $ 27,724   $ 27,052
                                                       =========  =========
</TABLE>

Net  periodic  pension  cost  for  the  years  ended June 30 as determined by an
independent  actuary,  included  the  following  components  (in  thousands):

<TABLE>
<CAPTION>
                                   1999      1998
                                 --------  --------
<S>                              <C>       <C>
 Service cost                    $   750   $   717
 Interest cost                     2,496     2,219
 Expected return on plan assets   (1,945)   (3,612)
 Prior service cost recognized        52
 Recognized gains or losses           14     1,753
                                 --------  --------
 Net periodic pension cost       $ 1,367   $ 1,077
                                 ========  ========
</TABLE>

                                       41
<PAGE>
The  assumptions  used  at  the  beginning  of the fiscal year in accounting for
Mountaineer's  Pension  Plan  at  June  30  are  as  follows:

<TABLE>
<CAPTION>
                                            1999   1998
                                            -----  -----
<S>                                         <C>    <C>
 Discount rate                              7.75%  7.75%
 Expected average increase in compensation  4.50%  4.50%
 Expected long-term rate of return          8.00%  8.00%
</TABLE>

9.     POST-RETIREMENT  MEDICAL  AND  LIFE  INSURANCE  BENEFITS

Mountaineer  provides  certain  medical  and life insurance benefits for retired
employees.  Substantially all employees, who meet the service requirements of 10
continuous  years of service prior to retirement at age 55 or 5 continuous years
of  service  prior  to  retirement  at  age  60, may become eligible for medical
benefits.  Medical  benefits  are  provided  to  retirees  until  age  65.  Life
insurance  benefits  of approximately two times annual salary are provided while
an  employee is active and working at Mountaineer.  On the date of an employee's
retirement  and on the date the employee reaches age 70, life insurance benefits
decrease  to approximately 80% and 50% of annual salary, respectively.  The plan
is  unfunded.

The  following  table  sets  forth the postretirement medical and life insurance
plans'  funded status and amounts recognized in the consolidated balance sheets,
as  determined  by  an  independent  actuary,  as  of  June  30  (in thousands):

<TABLE>
<CAPTION>
                                                           1999      1998
                                                         --------  --------
<S>                                                      <C>       <C>
 Reconciliation of funded status
   Funded status                                         $(7,628)  $(7,268)
   Unrecognized actuarial gain                              (197)      (18)
                                                         --------  --------
   Net postretirement benefit liability                  $(7,825)  $(7,286)
                                                         ========  ========

 Change in projected benefit obligation
   Benefit obligation at beginning of year               $(7,268)  $(6,993)
   Service cost                                             (461)     (437)
   Interest cost                                            (537)     (515)
   Participant contributions                                (140)     (128)
   Actuarial (gain) loss                                     182      (130)
   Benefit payments                                          596       935
                                                         --------  --------
   Benefit obligation at end of year                     $(7,628)  $(7,268)
                                                         ========  ========

 Components of net periodic postretirement benefit cost
   Service cost                                          $   461   $   437
   Interest cost                                             537       515
                                                         --------  --------
   Net periodic benefit cost                             $   998   $   952
                                                         ========  ========
</TABLE>

                                       42
<PAGE>
The  weighted  average  discount  rate  used  in  determining  the  accumulated
postretirement  benefit  obligation  was 7.75% for the years ended June 30, 1999
and  1998.  The  average  assumed  annual  rate  of salary increase for the life
insurance  benefit  plan  was  4.5  %  and  4.5% in 1999 and 1998, respectively.

The  assumed  health  care  cost  trend  rate  used in measuring the accumulated
postretirement  benefit obligation was 8.0% in 1999, declining by a half percent
to  5.5%  in  2004 and remaining at that level thereafter.  The health care cost
trend  rate  assumption has a significant effect on the amounts reported.  A one
percentage  point  increase  in  the  assumed  health care cost trend rate would
increase  the  aggregate service and interest cost by $63,000 for the year ended
June  30,  1999 and increase accumulated postretirement benefit obligation as of
June  30,  1999  by  $315,000.  A  one  percentage point decrease in the assumed
health  care  cost  trend rate would decrease the aggregate service and interest
cost  by  $57,000  for  the  year  ended  June 30, 1999 and decrease accumulated
postretirement  benefit  obligation  as  of  June  30,  1999  by  $290,000.

As  part  of a WVPSC rate order dated October 29, 1993, the WVPSC ruled that the
permitted  rate recovery mechanism for other post retirement benefits would be a
modified accrual method.  The modified accrual method allows for the recovery of
current  service  costs  on  an  accrual  basis  and  recovery of the transition
obligation  on  a  cash  basis.

10.     CAPITAL  STOCK

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

The Company has an agreement with a stockholder covering the sale or disposition
of  61,000  shares  of  common  stock,  at  June  30,  1999,  that  provides the
stockholder cannot sell stock without first offering such shares to the Company.
Under  certain  circumstances,  the  Company  would  be required to purchase the
related  stock  if  not  previously tendered to the Company or otherwise sold or
disposed  of  in  accordance  with  the  provisions  of  the  agreement.

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

Treasury  Stock  -  At  June  30,  1999, the Company had 75,352 shares of voting
---------------
common  stock  in  treasury,  carried at cost.  The Company purchased 20,704 and
6,980  shares  of  voting  common stock during the years ended June 30, 1999 and
1998,  respectively.  At  June  30,  1999,  the Company also had 4,516 shares of
non-voting  Class  A  stock  in  treasury,  carried  at  cost, all of which were
purchased  during  the  current  year.

                                       43
<PAGE>
Stock  Plans  -  During  fiscal  1999,  the  Company  created an incentive stock
------------
purchase  agreement,  primarily  for  outside  Directors.  Under  the agreement,
options  to  purchase voting common stock were granted at $75, based on the fair
market  value  as  determined  by  the  Board  of  Directors,  per share and are
exercisable  based  on  the  following  schedule:

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

A  summary  of  the  plan as of June 30, 1999 and the changes during the year is
presented  below:

<TABLE>
<CAPTION>
                                   Exercise
                                    Shares   Price
                                   --------  ------
<S>                                <C>       <C>
 Outstanding at beginning of year         -  $    -
 Granted                             30,000      75
 Exercised
 Outstanding at end of year          30,000  $   75
                                   ========  ======
 Options exercisable at year end     10,002
                                   ========
</TABLE>

Fair  value of the options at the date of grant, as estimated by management, was
nominal.

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

                                       44
<PAGE>
11.     EARNINGS  PER  SHARE

A  reconciliation  of  the components of basic and diluted net income (loss) per
common  share  as  of  June  30,  for  the  years  indicated,  is  as  follows:

<TABLE>
<CAPTION>
                                                                     Per-Share
                                                 Income      Shares    Amount
                                              -------------  -------  --------
<S>                                           <C>            <C>      <C>
1999
----
  Basic and Diluted Earnings per Share
     Loss available to common shareholders    $(14,887,000)  672,973  $(22.12)
1998
----
  Basic and Diluted Earnings per Share
     Income available to common shareholders  $  3,014,000   665,074  $  4.53
1997
----
  Basic and Diluted Earnings per Share
     Loss available to common shareholders    $ (5,843,000)  688,247  $ (8.49)
</TABLE>

The  effect  of stock options was not included in the computation of diluted net
loss  per  share  during  fiscal years 1997 and 1999 because to do so would have
been  antidilutive.  There were no stock options exercisable during fiscal 1998.


12.     UNCONSOLIDATED  AFFILIATE

The  Company's  investment  in BEC is accounted for under the equity method (see
Note 3).  Summarized financial information for BEC as of and for the years ended
June  30,  is  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                   1999      1998
                                 --------  --------
<S>                              <C>       <C>
 Current assets                  $ 5,914   $ 1,506
 Oil and gas properties           50,528    31,580
 Other assets                      1,359     2,508
                                 --------  --------
    Total assets                 $57,801   $35,594
                                 ========  ========

 Current liabilities             $ 5,340   $ 2,894
 Long-term debt                   26,200     4,300
 Other liabilities                   170       152
 Equity                           26,091    28,248
                                 --------  --------
   Total liabilities and equity  $57,801   $35,594
                                 ========  ========

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

BEC began operations in March 1997.  Results of operations were not material for
the  three  months  ended  June  30,  1997.

                                       45
<PAGE>
13.     OPERATING  LEASES

The  Company  has  noncancelable  operating  lease  agreements for the rental of
office  space,  computer  and  other equipment.  Certain of these leases contain
purchase  options  or  renewal clauses.  Rental expense for operating leases was
approximately  $1.8,  $1.7  and  $1.3 million for the years ended June 30, 1999,
1998  and  1997,  respectively.

At  June  30, 1999 future minimum lease payments for each of the next five years
and  thereafter  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
<S>         <C>
2000        $1,670
2001         1,135
2002           724
2003           486
2004           250
Thereafter     413
            ------
            $4,678
            ======
</TABLE>

14.     RELATED  PARTY  TRANSACTIONS

The  Company  has  entered  into  a  rental  arrangement for office space from a
partnership  in  which  certain  officers  are  partners.  Rent payments totaled
$374,200,  $339,470  and  $336,000  for  the years ended June 30, 1999, 1998 and
1997,  respectively.

Mountaineer purchases a portion of its gas supply requirements from a subsidiary
and  from Eastern American.  The price paid for such purchases has been approved
by  the  WVPSC.  During  1999, 1998 and 1997 Mountaineer purchased approximately
$5.4  million,  $5.6  million and $5.3 million respectively, from its subsidiary
and  $7.8  million,  $22.2  million and $23.2 million respectively, from Eastern
American.  The  contract  with  Eastern  American expired October 31, 1998.  The
related revenues and expenses between Mountaineer and its subsidiary and Eastern
American  have  not  been  eliminated  in  these financial statements due to the
regulated  nature  of  Mountaineer.

The  Company  advanced  funds  to  certain  officers,  generally at 8% interest.
Balances  totaled  $0.5 million and $0.2 million, respectively, at June 30, 1999
and  1998.

The  Company advanced funds to certain officers in 1991 and 1994, at 8% interest
that  were  secured  by  non-voting common shares of Eastern American.  Balances
totaled  $0  and  $320,400,  respectively,  at  June  30,  1999  and  1998.

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

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

                                       46
<PAGE>
15.     COMMITMENTS  AND  CONTINGENCIES

In  1993,  the  Company  sold  working  interests  in  certain  Appalachian  gas
properties  in  connection  with the formation of a 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.  Unamortized proceeds
totaling  $12.0  million  and  $13.5  million  at  June  30,  1999  and  1998,
respectively,  have  been  classified  as  deferred  trust  revenue.

Certain  gas  production  attributable  to  the  royalty trust is purchased by a
wholly  owned  subsidiary  of  the  Company pursuant to a gas purchase contract,
which  expires  in  2013.  The  purchase  price  under  the contract is based on
escalating  fixed  price  and spot market components.  The fixed price component
expires  on  January 1, 2000.  The obligation of the subsidiary to make payments
under  the  contract is partially supported by a standby letter of credit with a
face amount of $3 million.  The letter of credit is subject to annual reductions
of  $3  million  beginning  June  30,  1996, and fully expires on June 30, 2000.

The  Company  entered  into  an  agreement whereby it funded a specified monthly
amount,  through  December 31, 1996, to assist in the development of oil and gas
projects by a third party.  No remaining commitment existed as of June 30, 1998.
Amounts funded were accounted for as an advance and all outstanding amounts were
due  on  January  1,  1999.  As  settlement, during fiscal 1999, the third party
transferred  $1.0  million  of  property  and  the  Company  has written off the
remaining  balance  of  $0.3  million.

In  connection  with  an  existing  gas  delivery  obligation agreement, whereby
Eastern  American  received an advance payment, a subsidiary of Eastern American
entered into a credit line deed of trust, which has an available balance of $6.5
million  as  of  June  30,  1999  to collateralize its performance under the gas
delivery  obligation.  This credit line deed of trust declines at a rate of 7.5%
per  year.

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

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 below are not necessarily indicative of
the  amount  that the Company could realize upon the sale or refinancing of such
financial  instruments  (in  thousands):

<TABLE>
<CAPTION>
                                       1999                 1998
                               -------------------  -------------------
                               Carrying     Fair    Carrying     Fair
                                 Value     Value      Value     Value
                               ---------  --------  ---------  --------
<S>                            <C>        <C>       <C>        <C>
   Notes receivable            $   4,909  $  4,855  $   6,002  $  5,964
   Long-term debt              $ 286,655  $269,188  $ 262,088  $266,856
   Futures, swaps and options  $     490  $    430          -         -
</TABLE>

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

                                       47
<PAGE>
Notes  Receivable  - The notes receivable accrue interest at a fixed rate.  Fair
-----------------
value  was estimated using discounted cash flows based on current interest rates
for  notes  with  similar  credit  characteristics  and  maturities.

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

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


17.     CONTRACT  SETTLEMENT

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

Although  the  Company terminated all rights and obligations under the contract,
the  Company  retained  its 10% limited partnership interest in Seneca.  For the
fiscal  year ended June 30, 1998, the Company recorded partnership distributions
of  $10.0 million, comprised of $7.2 million in cash and $2.8 million of Niagara
common  stock.  The  Niagara  stock  was sold in November 1998 for $2.9 million.


18.     RATE  MATTERS

Since  November  1995,  Mountaineer  has  operated  under a regulatory structure
whereby  Mountaineer  maintains its rates at an agreed upon level for a specific
period  of  time  (the  "Rate  Moratorium").  In  addition,  during  the  Rate
Moratorium,  Mountaineer's annual purchased gas adjustment filing with the WVPSC
is  suspended.  This  regulatory  structure  results in Mountaineer assuming the
risks and rewards of changes in the cost of gas purchases, changes in interstate
pipeline  costs  and  of  all other aspects of Mountaineer's business.  The Rate
Moratorium  began  in  November  1995  and  ended  in October 1998.  During this
period, deferral accounting for the majority of gas purchase costs was suspended
and  Mountaineer  was  permitted  to  amortize  $12 million of the $12.7 million
recorded  balance  of  overrecovered  gas  costs  as  an offset to purchased gas
expense.  In  fiscal  1999,  Mountaineer  recorded  total  amortization  of $1.3
million in accordance with the Rate Moratorium.  The excess of the overrecovered
gas  costs  over the amount to be amortized and certain transportation revenues,
storage  balancing  fees and standby charges were subject to deferral accounting
in  accordance  with  the  Rate  Moratorium.

                                       48
<PAGE>
In  January  1998,  Mountaineer filed with the WVPSC for an increase in its base
rates,  which  would  become  effective  upon  expiration  of  the  initial Rate
Moratorium.  In  July  1998,  Mountaineer  agreed  to  a  Joint  Stipulation and
Agreement  for  Settlement (the "Settlement") with various parties including the
Staff  of  the  WVPSC and the Consumer Advocate Division regarding Mountaineer's
rate  filing.  Under  the  terms  of  the Settlement, Mountaineer was granted an
increase in its rates which, assuming certain weather conditions, would generate
additional  annual revenues of approximately $9.4 million and which provided for
a  new  three year Rate Moratorium which began on November 1, 1998 and continues
through  October  31,  2001.  Other  significant  terms  and  conditions  of the
Settlement  are  similar  to  those  under which Mountaineer operated during the
prior  Rate  Moratorium.  Beginning  November  1, 1998, the remaining balance of
overrecovered  gas  costs and certain transportation revenues, storage balancing
fees  and standby charges, totaling $6.4 million, previously deferred during the
initial  Rate  Moratorium  will  be  credited to gas expense over the three-year
period  ending  October 31, 2001.  During fiscal 1999, Mountaineer credited $1.4
million  against  gas  costs  in  accordance  with  the  Settlement.


19.     INDUSTRY  SEGMENTS

The  Company  adopted SFAS No. 131, "Disclosures About Segments of an Enterprise
and  Related  Information," in fiscal 1999.  The information for fiscal 1998 and
1997  has  been  restated  from  the prior year's presentation to conform to the
fiscal  1999  presentation.

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.  The  regulated  utility  segment  generates  revenue  from  the
transportation  and  sale  of natural gas at retail.  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.  The Company
utilizes  earnings before interest, taxes, depreciation, depletion, amortization
and  exploratory  costs  ("EBITDAX")  to  evaluate  each  segment's  operations.

                                       49
<PAGE>
Summarized  financial information for the Company's reportable segments is shown
in  the following table.  The "other" column includes items related to corporate
items  (in  thousands):

<TABLE>
<CAPTION>
                                         Exploration               Marketing
                                             and       Regulated      and
                                         Production     Utility     Pipeline    Other    Consolidated
                                        -------------  ----------  ----------  --------  -------------
<S>                                     <C>            <C>         <C>         <C>       <C>
                 1999
 Sales to unaffiliated customers        $     24,836   $  158,439  $  88,342   $ 1,430   $     273,047
 Intersegment revenues                         3,431            -      9,125         -          12,556
 Depreciation, depletion, amortization        10,208        9,027      1,312     1,491          22,038
 Exploratory costs                            19,388            -          -         -          19,388
 Operating profit                            (18,031)      26,175        649    (3,521)          5,272
 Interest expense                                113        6,583          -    19,858          26,554
 EBITDAX                                      12,014       35,385      1,962    (1,500)         47,861
 Total assets                                133,200      194,025     62,131    47,586         436,942
 Capital expenditures                         22,351       11,155        544     2,609          36,659
--------------------------------------  -------------  ----------  ----------  --------  -------------
                 1998                              -            -          -         -               -
 Sales to unaffiliated customers              27,835      156,579    143,140    11,584         339,138
 Intersegment revenues                         3,605            -     21,593         -          25,198
 Depreciation, depletion, amortization         9,707        7,777      1,270     1,284          20,038
 Exploratory costs                             8,262            -          -         -           8,262
 Operating profit                             (2,493)      15,499     14,933     6,480          34,419
 Interest expense                                248        6,414          9    19,715          26,386
 EBITDAX                                      11,893       23,362     16,202     8,260          59,717
 Total assets                                137,508      188,931     70,057    43,449         439,945
 Capital expenditures                         22,188       12,044        681     3,780          38,693
--------------------------------------  -------------  ----------  ----------  --------  -------------
                 1997                              -            -          -         -               -
 Sales to unaffiliated customers              36,163      173,463    135,466       306         345,398
 Intersegment revenues                         3,672            -     24,901       (30)         28,543
 Depreciation, depletion, amortization        10,376        6,387      1,222     1,060          19,045
 Exploratory costs                            10,121            -          -         -          10,121
 Operating profit                             (1,358)      17,100      5,481    (2,156)         19,067
 Interest expense                             11,916        6,511         48     5,406          23,881
 EBITDAX                                      27,354       23,490      6,703      (544)         57,003
 Total assets                                156,743       191,821     56,229    29,964         434,757
 Capital expenditures                   $     17,632   $   10,303  $    (183)  $(1,376)  $      26,376
--------------------------------------  -------------  ----------  ----------  --------  -------------
</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.  Intersegment  sales  between  the
exploration  and production and the utility segments have not been eliminated in
consolidation  because  of the regulated nature of the gas distribution segment.
The  'Other' column includes items related to non-reportable segments, corporate
and  elimination  items.  Included in the exploration and production segment are
net  long-lived assets located in New Zealand of $1.8, $1.4 and $0.1 million, as
of  June  30,  1999,  1998,  and  1997.

20.     SUBSEQUENT  EVENTS

On  July  1,  1999,  Mountaineer acquired substantially all of the West Virginia
assets  of  Shenandoah Gas Company for the purchase price of approximately $12.6
million.  The  acquired  assets  consist  primarily  of natural gas distribution
facilities  and  related  equipment  located  in  the  eastern panhandle of West
Virginia.


                                       50
<PAGE>
SUPPLEMENTAL  INFORMATION  ON  OIL  AND  GAS  PRODUCING  ACTIVITIES  (UNAUDITED)

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

<TABLE>
<CAPTION>
                                                      1999       1998       1997
                                                    ---------  ---------  ---------
<S>                                                 <C>        <C>        <C>
 Capitalized costs:
   Proved properties                                $207,400   $197,137    192,970
   Unproved properties                                 9,250     13,513      7,398
                                                    ---------  ---------  ---------
   Total                                             216,650    210,650    200,368
   Less accumulated depletion and depreciation       (68,833)   (64,770)   (57,001)
                                                   ---------  ---------  ---------
 Net capitalized costs                              $147,817   $145,880   $143,367
                                                    =========  =========  =========

 Company's share of equity method investee's net
   capitalized costs                                $ 11,607   $  9,474      8,877
                                                    =========  =========  =========


 Costs incurred:
   Acquisition of proved properties                 $  2,086   $  2,039   $    143
   Development costs                                   7,527     10,227     11,649
   Exploration costs                                  12,738      9,154      3,728
                                                    ---------  ---------  ---------
 Total costs incurred                               $ 22,351   $ 21,420   $ 15,520
                                                    =========  =========  =========

 Company's share of equity method investee's total
   costs incurred                                   $  3,966   $    944   $    115
                                                    =========  =========  =========
</TABLE>

                                       51
<PAGE>
Results  of  Operations  -  The  results of operations for oil and gas producing
-----------------------
activities,  excluding corporate overhead and interest costs for the years ended
June  30  are  as  follows  (in  thousands):

<TABLE>
<CAPTION>
                                                1999      1998     1997
                                              ---------  -------  -------
<S>                                           <C>        <C>      <C>
 Revenues from sale of oil and gas            $ 21,727   $24,689  $33,301
 Less:
   Production costs                              9,214     3,101    7,997
   Production taxes                                965     1,448    1,966
   Exploration and impairment                   19,388     8,262   10,121
   Depletion, depreciation and amortization      8,409     8,021    8,325
   Income tax expense (benefit)                 (5,681)    1,453    1,712
                                              ---------  -------  -------
 Income loss from oil and gas operations      $(10,562)  $ 2,404  $ 3,180
                                              =========  =======  =======

 Company's share of equity method investee's
   income from oil and gas operations         $    183   $   714  $   311
                                              =========  =======  =======
</TABLE>

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

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

Depletion,  depreciation  and  amortization  include  costs  associated  with
capitalized  acquisition,  exploration,  and  development  costs.

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

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

                                       52
<PAGE>
The  following table sets forth information for the years indicated with respect
to  changes  in the Company's proved reserves, substantially all of which are in
the  United  States.

<TABLE>
<CAPTION>
                                                                Natural    Crude
                                                                  Gas       Oil
                                                                 (Mmcf)   (Mbbls)
                                                                --------  -------
<S>                                                             <C>       <C>
Proved reserves:
  June 30, 1996                                                 159,449    6,668
    Revision of previous estimates                                  331     (197)
    Extensions and discoveries                                   13,331      545
    Sales of reserves in place                                   (3,674)  (5,336)
    Production                                                   (9,106)    (447)
                                                                --------  -------
  June 30, 1997                                                 160,331    1,233
    Revisions of previous estimates                                 825      (49)
    Extensions and discoveries                                   14,545      205
    Purchases of reserves in place                                2,284       79
    Sales of reserves in place                                               (11)
    Production                                                   (8,525)    (127)
                                                                --------  -------
  June 30, 1998                                                 169,460    1,330
    Revisions of previous estimates                               1,036     (224)
    Extensions and discoveries                                    5,286       74
    Purchases of reserves in place                                    -        -
    Sales of reserves in place                                     (674)     (85)
    Production                                                   (8,840)    (133)
                                                                --------  -------
  June 30, 1999                                                 166,268      962
                                                                ========  =======

Proved developed reserves:
  June 30, 1997                                                 141,116      748
                                                                ========  =======
  June 30, 1998                                                 138,935      733
                                                                ========  =======
  June 30, 1999                                                 144,643      717
                                                                ========  =======

Company's share of equity method investee's proved reserve at:
  June 30, 1997                                                   3,452    4,402
                                                                ========  =======
  June 30, 1998                                                   2,077    3,113
                                                                ========  =======
  June 30, 1999                                                   5,529    9,907
                                                                ========  =======
</TABLE>

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

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

                                       53
<PAGE>
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>
                                                        1999        1998        1997
                                                     ----------  ----------  ----------
<S>                                                  <C>         <C>         <C>
 Future cash in flows                                $ 445,872   $ 457,015   $ 473,464
 Future production and development costs              (165,236)   (170,169)   (172,219)
 Future income tax expense                             (63,000)    (57,000)    (50,607)
                                                     ----------  ----------  ----------
 Future net cash flows before discount                 217,636     229,846     250,638
 10% discount to present value                        (126,433)   (138,581)   (143,791)
                                                     ----------  ----------  ----------
 Standardized measure of discounted future net cash
   flows related to proved oil and gas reserves      $  91,203   $  91,265   $ 106,847
                                                     ==========  ==========  ==========

 Company's share of equity method investee's
   standardized measure of discounted future net
   cash flows                                        $  28,129   $  19,975   $  27,201
                                                     ==========  ==========  ==========
</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>
                                                     1999       1998       1997
                                                   ---------  ---------  ---------
<S>                                                <C>        <C>        <C>
 Standardized measure of discounted future
   net cash flows at beginning of period           $ 91,265   $106,847   $109,941
 Sales of oil and gas produced, net of
   production costs                                 (11,548)   (13,816)   (17,854)
 Net changes in prices and production costs            (249)   (12,729)    17,395
 Changes in production rates and other               (7,405)   (14,256)        50
 Extensions, discoveries and other additions, net
   of future production and development costs         4,177      5,910     12,185
 Changes in estimated future development costs        2,701     (1,495)    (7,609)
 Development costs incurred                           7,527     10,227     11,649
 Revisions of previous quantity estimates              (347)       422     (1,022)
 Purchase of reserves in place                            -      2,026
 Sales of reserves in place                            (922)       (56)   (25,075)
 Accretion of discount                                9,126     10,685     10,994
 Net change in income taxes                          (3,122)    (2,500)    (3,807)
                                                   ---------  ---------  ---------
 Standardized measure of discounted
   future net cash flows at end of period          $ 91,203   $ 91,265   $106,847
                                                   =========  =========  =========
</TABLE>

                                    * * * * *

                                       55
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA                                         SCHEDULE I
CONDENSED  FINANCIAL  INFORMATION  OF  REGISTRANT
CONDENSED  BALANCE  SHEETS  INFORMATION
JUNE  30,  1999  AND  1998
(DOLLARS  IN  THOUSANDS)
------------------------------------------------------------



ASSETS                                      1999      1998
                                          --------  --------
<S>                                       <C>       <C>
 CURRENT ASSETS:
   Cash                                   $ 12,388  $ 19,158
   Accounts receivable, affiliates          39,175    19,787
   Accounts receivable, other                  140       388
   Other current assets                      5,982     5,324
                                          --------  --------
     Total current assets                   57,685    44,657

 PROPERTY, PLANT AND EQUIPMENT - Net         5,476     3,226

 INVESTMENT IN SUBSIDIARIES                161,679   173,440

 OTHER ASSETS                               20,947    13,448
                                          --------  --------

 TOTAL                                    $245,787  $234,771
                                          ========  ========

 LIABILITIES AND STOCKHOLDER'S EQUITY
 CURRENT LIABILITIES:
   Accounts payable and accrued expenses  $ 11,934  $  3,833

 LONG-TERM LIABILITIES
   Long-term debt                          219,198   200,661

 STOCKHOLDER'S EQUITY                       14,655    30,277
                                          --------  --------

 TOTAL                                    $245,787  $234,771
                                          ========  ========
</TABLE>


 See  notes  to  condensed  financial  information.


                                       56
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA                                         SCHEDULE I
CONDENSED  FINANCIAL  INFORMATION  OF  REGISTRANT
CONDENSED  STATEMENTS  OF  OPERATIONS  INFORMATION
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
(DOLLARS  IN  THOUSANDS)
---------------------------------------------------------------------------------


                                                     1999       1998       1997
                                                   ---------  ---------  --------
<S>                                                <C>        <C>        <C>
 COSTS AND EXPENSES:
   General and administrative                      $  4,060   $  3,355   $ 2,608
   Depreciation of property, plant and equipment        350        160        40
                                                   ---------  ---------  --------

 LOSS FROM OPERATIONS                                (4,410)    (3,515)   (2,648)

 INTEREST EXPENSE                                    20,009     19,875     2,152

 OTHER (INCOME) EXPENSE                                (529)    (1,072)   (1,246)
                                                   ---------  ---------  --------

 LOSS BEFORE INCOME TAXES AND EQUITY
   IN EARNINGS OF SUBSIDIARIES                      (23,890)   (22,318)   (3,554)

 BENEFIT FROM INCOME TAXES                          (11,337)    (8,335)   (2,565)
                                                   ---------  ---------  --------

 LOSS BEFORE EQUITY IN EARNINGS OF
   SUBSIDIARIES                                     (12,553)   (13,983)     (989)

 EQUITY IN EARNINGS (LOSSES) OF
    SUBSIDIARIES                                     (2,334)    16,997    (4,854)
                                                   ---------  ---------  --------

 NET INCOME (LOSS)                                 $(14,887)  $  3,014   $(5,843)
                                                   =========  =========  ========
</TABLE>

 See  notes  to  condensed  financial  information.


                                       57
<PAGE>
<TABLE>
<CAPTION>

ENERGY CORPORATION OF AMERICA                                         SCHEDULE I
CONDENSED  FINANCIAL  INFORMATION  OF  REGISTRANT
CONDENSED  STATEMENTS  OF  CASH  FLOWS  INFORMATION
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
(DOLLARS  IN  THOUSANDS)
-------------------------------------------------------------------------------------------------



                                                                   1999        1998       1997
                                                                 ---------  ----------  ---------
<S>                                                              <C>        <C>         <C>
 CASH FLOWS FROM OPERATIONS:
   Net income (loss)                                             $(14,887)  $   3,014   $ (5,843)
   Adjustments to reconcile net income to cash
     Provided by (used in) operating activities:
     Equity in undistributed (earnings) losses of subsidiaries      2,334     (16,997)     4,854
     Depreciation and amortization                                  1,149         946        104
     Changes in operating assets and liabilities                   (2,089)     (9,524)     5,077
     Other                                                         (9,346)     (2,340)    (4,634)
                                                                 ---------  ----------  ---------
       Net cash used in operating activities                      (22,839)    (24,901)      (442)
                                                                 ---------  ----------  ---------

 CASH FLOWS FROM INVESTING ACTIVITIES:
   Advances to subsidiaries                                       (18,154)     (2,022)    (9,821)
   Expenditures for property                                       (2,600)     (2,358)      (229)
   Other investing activities                                        (141)     (3,137)         -
                                                                 ---------  ----------  ---------
       Net cash used in investing activities                      (20,895)     (7,517)   (10,050)
                                                                 ---------  ----------  ---------

 CASH FLOWS FROM FINANCING ACTIVITIES:
   Dividends paid                                                    (960)       (815)    (1,007)
   Proceeds from issuance of debt                                  27,500       1,298    200,000
   Principal payments on debt                                      (2,923)       (217)
   Contributions to capital of subsidiaries                                    (5,408)  (178,378)
   Deferred financing costs                                                      (601)    (7,055)
   Repurchase of stock                                             (2,198)       (523)    (2,054)
   Subsidiary dividends and other                                  15,545      41,650     11,724
                                                                 ---------  ----------  ---------
       Net cash provided by financing activities                   36,964      35,384     23,230
                                                                 ---------  ----------  ---------
 Net increase (decrease) in cash and cash equivalents              (6,770)      2,966     12,738
 Cash and cash equivalents, beginning of year                      19,158      16,192      3,454
                                                                 ---------  ----------  ---------

 CASH AND CASH EQUIVALENTS AT
    END OF YEAR                                                  $ 12,388   $  19,158   $ 16,192
                                                                 =========  ==========  =========
</TABLE>

 See notes to condensed financial information.


                                       58
<PAGE>
ENERGY  CORPORATION  OF  AMERICA                                     SCHEDULE  I
CONDENSED  FINANCIAL  INFORMATION  OF  REGISTRANT
NOTES  TO  CONDENSED  FINANCIAL  INFORMATION
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
---------------------------------------------------------

1.     SUMMARY  OF  SIGNIFICANT  ACCOUNTING  POLICIES

Investments  in Subsidiaries - The financial statements of Energy Corporation of
----------------------------
America  (the  "Company")  reflect  investments  in  Eastern  American  Energy
Corporation, Eastern Systems Corporation, Westech Energy Corporation and Westech
Energy  New  Zealand  Limited  ("the  subsidiaries"), wholly owned subsidiaries,
using  the  equity  method.

Income  Taxes  -  The benefit for income taxes is based on losses recognized for
-------------
financial  statement  purposes determined on a separate company basis.  Deferred
income taxes are recognized for the tax effects of temporary differences between
such  losses  and those recognized for income tax purposes.  The Company files a
consolidated  U.S.  income  tax  return  with  its  subsidiaries.

2.     CONSOLIDATED  FINANCIAL  STATEMENTS

Reference  is made to the Consolidated Financial Statements and related Notes of
Energy  Corporation  of  America  and  Subsidiaries  for additional information.

3.     LONG-TERM  DEBT

Information  concerning debt of the Company on a consolidated basis is disclosed
in  Note  5  of  the  Notes  to  Consolidated  Financial  Statements  of  Energy
Corporation  of  America  and  Subsidiaries  included  elsewhere  herein.  The
Company's $200 million in 9 1/2% senior subordinated notes are due in 2007.  The
Company's  $22  million  revolving  line  of  credit  is  due  in  2002.

4.     DIVIDENDS  RECEIVED

The  Company  received  dividends  from its subsidiaries of $15.5 million, $41.6
million  and  $10.4  million  for  the years ended June 30, 1999, 1998 and 1997,
respectively.

                                      *****

                                       59
<PAGE>
<TABLE>
<CAPTION>
ENERGY  CORPORATION  OF  AMERICA  AND  SUBSIDIARIES
VALUATION  AND  QUALIFYING  ACCOUNTS
FOR  THE  YEARS  ENDED  JUNE  30,  1999,  1998  AND  1997
(AMOUNTS IN THOUSANDS)                                                              SCHEDULE II
-----------------------------------------------------------------------------------------------


                                                                     1999      1998      1997
                                                                   --------  --------  --------
<S>                                                                <C>       <C>       <C>
 Allowance for doubtful accounts, balance at beginning of period   $ 1,681   $ 1,660   $ 1,744
 Charged to costs and expenses                                       2,109     2,572     2,102
 Charged to other accounts (1)                                         354        58       291
 Deductions (2)                                                     (2,082)   (2,609)   (2,477)
                                                                   --------  --------  --------

 Allowance for doubtful accounts, balance at end of period         $ 2,062   $ 1,681   $ 1,660
                                                                   ========  ========  ========
<FN>
(1)  Recoveries  of  accounts  previously  written  off
(2)  Accounts  written  off
</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.

                                       60
<PAGE>
                                    PART III
                                    --------


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

     The  executive  officers  and  Directors  of  the Company and the executive
officers  of its subsidiaries on June 30, 1999 are listed below, together with a
description  of  their  experience  and  certain  other information.  All of the
Directors  were  re-elected  for  a one year term at the Company's December 1998
annual  meeting  of stockholders.  Executive officers are appointed by the Board
of  Directors.

<TABLE>
<CAPTION>
Name                     Age               Position with Company or Subsidiary
-----------------------  ---  --------------------------------------------------------------
<S>                      <C>  <C>
John Mork                 51  President and Chief Executive Officer of the Company; Director
Joseph E. Casabona        56  Executive Vice President of the Company; Director
J. Michael Forbes         39  Vice President of the Company
Isobel M. Allan           42  Vice President/Treasurer of the Company
F. H. McCullough, III     52  Vice President of the Company; Director
Donald C. Supcoe          43  Secretary of the Company; Senior Vice President of Mountaineer
Richard E. Heffelfinger   41  President of Eastern American
Michael S. Fletcher       50  President  of Mountaineer
Edward J. Davies          57  President of Westech
W. Gaston Caperton, III   59  Director
Peter H. Coors            52  Director
L. B. Curtis              75  Director
John J. Dorgan            75  Director
Arthur C. Nielsen, Jr.    80  Director
Julie Mork                49  Director
</TABLE>

     Isobel M. Allan joined the Company as Vice President of Finance in November
1998.  Prior  to  joining  the  Company, Miss Allan was Assistant Treasurer with
Occidental  Petroleum  Corporation.  Miss Allan graduated from the University of
Edinburgh,  Scotland  with a Bachelor of Science degree with Honors and a Master
of  Science  degree  in  Business  Studies.

     W. Gaston Caperton, III, has been a Director of the Company since September
25,1997.  He served as the Governor of the State of West Virginia for two terms,
from  1989  to 1997.  Mr. Caperton presently serves as President of The Caperton
Group.  He  currently  serves  as  President  and Chief Executive Officer of The
College Board.  Mr. Caperton presently serves on the Board of Directors of Owens
Corning  and  United  Bankshares.

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

                                       61
<PAGE>
     Peter H. Coors has been a Director of the Company since 1996.  Mr. Coors is
Vice  Chairman of the Board and Chief Executive Officer of Coors Brewing Company
and Vice President of Adolph Coors Company.  He received his Bachelors Degree in
Industrial  Engineering  from  Cornell  University  in  1969,  and he earned his
Masters Degree in Business Administration from the University of Denver in 1970.
Mr.  Coors  also  serves  on  the  Board  of  Directors  of  First Bank Systems.

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

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

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

     Michael  S.  Fletcher  has  been President of Mountaineer Gas Company since
August  1998.  Prior  to  that  time,  he also held the positions of Senior Vice
President  and  Chief  Financial  Officer  of  Mountaineer.  Before  joining
Mountaineer  in  1987, Mr. Fletcher was a partner of Arthur Andersen and Company
and  was  employed  by  that  firm  for  fifteen  (15) years.  Mr. Fletcher is a
Certified  Public  Accountant  and  a  board  member  for  the Board of Risk and
Insurance  Management  for  the  State of West Virginia.  Mr. Fletcher graduated
from  Utah  State  University  with  a  Bachelors  Degree  in  Accounting.

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

     Richard  E.  Heffelfinger  is  President  of  Eastern  American and Eastern
Marketing.  Mr.  Heffelfinger joined Eastern American in 1980.  Mr. Heffelfinger
currently  serves  on  the  Board  of  Directors  of  Capital State Bank of West
Virginia.  He is a member of the Young Presidents' Organization, Mountain States
Chapter,  and  a  past President and current Board Member of the Independent Oil
and  Gas  Association of West Virginia.  In addition, Mr. Heffelfinger currently
serves  as  Chairman  of the Greater Kanawha Valley YMCA.  Mr. Heffelfinger is a
graduate  of  Glenville  State  College.

     F.  H. McCullough, III, has been a Director of the Company since 1993.  Mr.
McCullough  joined Eastern American in 1977.  Mr. McCullough currently serves as
Vice  President  of  the  Company.  Mr.  McCullough  was  a  Director of Eastern
American  from  1978 until 1993.  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.  Effective October 1, 1999,
Mr.  McCullough  resigned  as  Vice  President  of  the Company and retained his
position  as  Director.

                                       62
<PAGE>
     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.  He was  chapter  chairman  of  the  Young
Presidents'  Organization,  Inc.,  Rocky Mountain Chapter from 1994 to 1995. Mr.
Mork  also  founded  the  Mountain  State  Chapter  of  the  Young   Presidents'
Organization located in Charleston,  West Virginia. Mr. Mork holds a Bachelor of
Science  Degree  in  Petroleum  Engineering  from  the  University  of  Southern
California  and he is a graduate of the  Stanford  Business  School  Program for
Chief Executive Officers. He is the husband of Julie Mork.

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

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

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


                                       63
<PAGE>
                       ITEM 11.     EXECUTIVE COMPENSATION
                       --------     ----------------------

     The  following  table  sets  forth  for fiscal year 1999 the total value of
compensation  of  (i)  the Company's Chief Executive Officer and (ii) each other
executive  officer  of  the  Company.

<TABLE>
<CAPTION>
                                                     Salary    Bonus      Other      Total
                                                    --------  --------  ----------  --------
<S>                                                 <C>       <C>       <C>         <C>
John Mork                                           $246,820  $287,616  54,971 (1)  $589,407
   President and Chief Executive Officer
Joseph E. Casabona                                   215,086   144,250  10,300 (2)   369,636
   Executive Vice President
Edward J. Davies                                     181,091    90,150   6,682 (3)   277,923
   President of Westech Energy Corporation
Michael S. Fletcher                                  220,934   122,802  36,254 (4)   379,990
   President of Mountaineer Gas Company
Richard E. Heffelfinger                              188,356    91,320   4,403 (5)   284,079
   President of Eastern American Energy Coporation
_______________
<FN>
(1)  Includes $6,814 in compensation  related to insurance policies provided for
     the benefit of John Mork,  $43,036 for personal use of company owned assets
     and $5,121 in 401K matching contributions.
(2)  lncludes $4,410 in compensation  related to insurance policies provided for
     the benefit of Joseph E. Casabona, $2,379 for personal use of company owned
     assets and $3,511 in 401K matching contributions.
(3)  Includes $1,188 in compensation related to an insurance policy provided for
     the benefit of Edward J. Davies,  $2,095 for personal use of company  owned
     assets and $3,399 in 401K matching contributions.
(4)  Includes $924 in compensation  related to an insurance  policy provided for
     the benefit of Michael S.  Fletcher,  $19,332 for  personal  use of company
     owned assets and $16,008 for employee dependent tuition assistance.
(5)  Includes $275 in compensation  related to an insurance  policy provided for
     the benefit of Richard E.  Heffelfinger,  $617 for  personal use of company
     owned assets and $3,511 in 401K matching contributions.
</TABLE>


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

     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the  share  ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company  by  all directors and executive officers as a group, in each case as of
September  1,  1999.  The  business  address of each officer and director listed
below  is:  c/o  Energy  Corporation  of  America,  4643  S. Ulster, Suite 1100,
Denver,  Colorado  80237.


                                       64
<PAGE>
<TABLE>
<CAPTION>
                                                     Beneficial Ownership
                                                        Common Stock
                                                     -------------------
                                                      Number
                                                     of Shares  Percent
                                                     ---------  --------
<S>                                                  <C>        <C>
 Kenneth W. Brill (1)                                   65,210    10.09%
 W. Gaston Caperton, III                                   320        *
 Joseph E. Casabona                                     18,216     2.82%
 Peter H. Coors                                            703        *
 L. B. Curtis                                           12,100     1.87%
 John J. Dorgan                                            970        *
 J. Michael Forbes                                       2,400        *
 Richard E. Heffelfinger                                 4,860        *
 F. H. McCullough, III (3)(4)                           90,325    13.98%
 John Mork (2)                                         379,923    58.81%
 Julie Mork (2)                                        379,923    58.81%
 Arthur C. Nielsen, Jr.                                 36,320     5.62%
 Donald C. Supcoe                                        3,200        *

 All officers and Directors as a group (13 persons)    614,547    95.12%
 _______________
<FN>
  *  Less  than  one  percent.
(1)  Pursuant to  agreements  dated June 30,  1993 and July 8, 1996,  Kenneth W.
     Brill  granted the Company  options to purchase  15,400 and 75,850  shares,
     respectively,  of the Company  Common  Stock owned by him,  30,050 of which
     have been purchased by the Company.
(2)  Includes 371,520 shares held by John and Julie Mork as joint tenants, 2,503
     shares held by Julie Mork  individually,  and 2,950  shares held by each of
     the Alison Mork Trust and the Kyle Mork Trust.
(3)  Pursuant to an agreement dated May 20, 1997, F.H.  McCullough,  III and his
     wife,  Kathy L.  McCullough,  jointly  granted  the  Company  an  option to
     purchase 11,920 shares of the Company's Common Stock owned by them,  all of
     which have been purchased by the Company.
(4)  Includes 88,405 shares held by F.H. McCullough, III and Kathy McCullough as
     joint tenants,  720 shares held by the Katherine F. McCullough  Trust,  and
     400  shares  held by each of the  Lesley  McCullough  Trust,  the  Meredith
     McCullough Trust and the Kristin McCullough Trust.
</TABLE>

     The  following table sets forth certain information regarding (i) the share
ownership  of  the  Company  by  each  person  known  to  the  Company to be the
beneficial  owner  of  more  than 5% of the outstanding shares of Class A Stock,
(ii)  the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive  officers  as  a  group,  in  each  case as of September 1, 1999.  The
business  address  of  each  officer  an  director listed below is :  c/o Energy
Corporation  of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado
80237.


                                       65
<PAGE>
<TABLE>
<CAPTION>
                                                    Beneficial Ownership
                                                       Class A Stock
                                                    -------------------
                                                     Number
                                                    of Shares  Percent
                                                    ---------  --------
<S>                                                 <C>        <C>
 Joseph E. Casabona                                     5,791    27.57%
 Edward J. Davies                                       5,281    25.14%
 Michael S. Fletcher                                    2,500    11.90%
 Richard E. Heffelfinger                                  168        *
 John Mork (1)                                            796     3.79%
 Julie Mork (1)                                           796     3.79%
 Arthur C. Nielsen, Jr.                                 1,160     5.52%
 Donald C. Supcoe                                       1,667     7.94%

 All officers and Directors as a group (8 persons)     17,363    82.66%
_______________
<FN>
*    Less  than  one  percent
(1)  Includes  796  shares  held  by  John  and  Julie  Mork  as  joint tenants.
</TABLE>

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

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


                                       66
<PAGE>
<TABLE>
<CAPTION>
                                  1999 *      1998       1997
                                 --------  ----------  --------
<S>                              <C>       <C>         <C>
 Dale P. Andrews                 $ 10,000  $   13,137
 K.W. Brill                        25,000     173,755  $ 47,318
 Gaston Caperton                              392,150
 Joseph E. Casabona                40,000      52,732    41,871
 Peter Coors                       25,000      52,732
 L.B. Curtis                       50,000     108,688    39,877
 E.J. Davies                      125,000     101,051    26,985
 John J. Dorgan                    50,000      52,732    32,543
 J. Michael Forbes                              7,636    13,120
 Richard L. Grant                              27,905    21,287
 F.H. McCullough, III              75,000     159,793    97,458
 Lesley McCullough Trust (2)                    7,636       542
 Kristen McCullough Trust (2)                   7,636       542
 Meredith McCullough Trust (2)                  7,636       542
 Katherine McCullough Trust (2)                 7,636       542
 John Mork (1)                    250,000     798,966   321,317
 Alison Mork Trust (3)             25,000      40,984    37,300
 Kyle Mork Trust (3)               25,000      40,984    37,300
 Arthur C. Nielsen, Jr.            50,000     139,440    29,623
 Donald C. Supcoe                               7,636     4,979
 ECA Foundation                         -      78,127         -
                                 --------  ----------  --------
 Total                           $750,000  $2,278,992  $753,146
                                 ========  ==========  ========
 _______________
<FN>
*    These  amounts  represent  only the amounts  committed to the 1999 Drilling
     Program, the actual investment may vary.
(1)  Interest of John Mork and Julie Mork held as joint tenants.
(2)  Trusts for Minor children of F. H. McCullough, III and Kathy L. McCullough.
(3)  Trusts  for  Minor  children  of  John  Mork  and  Julie  Mork.
</TABLE>

     Certain  officers,  Directors  and  key employees of the Company have notes
payable  to  the  Company  related to employee incentive stock options that were
granted  and  exercised.  The  notes  bear  various interest rates, ranging from
LIBOR to 8% per annum.  As of June 30, 1999, in excess of $60,000, the following
were  indebted  to  the  Company  (in  thousands):

<TABLE>
<CAPTION>
<S>                       <C>
 Dale P. Andrews          $   63
 Joseph E. Casabona          187
 Edward J. Davies            319
 J. Michael Forbes            96
 Michael S. Fletcher         187
 Richard E. Heffelfinger     192
 Donald C. Supcoe            209
                          ------
    Total                 $1,253
                          ======
</TABLE>


                                       67
<PAGE>
     Certain  officers and Directors of the Company have borrowed money from the
Company  and  have executed promissory notes.  The notes bear interest at 8% per
annum.  As  of  June  30,  1999,  the following were indebted to the Company (in
thousands):

<TABLE>
<CAPTION>
<S>                      <C>
 Isobel M. Allan  *      $158
 Michael S. Fletcher  *   161
 F. H. McCullough, III    160
                         ----
    Total                $479
                         ====
 _______________
<FN>
 *  Promissory  notes  are  being  forgiven  over  three  years,  assuming
     continuing  employment.
</TABLE>

                                       68
<PAGE>
     During  fiscal  1999,  the  Company  purchased  from  certain  officers and
directors  volumetric  production from wells in New Zealand.  Future production,
otherwise  allocable  to  the  officers  and  directors will be allocated to the
Company.  The  following  table  identifies  the  participants'  interest:

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

     The Company  rents office space in  Charleston,  West  Virginia from Energy
Centre,  Inc. a  corporation  owned  40.0% by John Mork,  20.0% by each of F. H.
McCullough,  III and Joseph E.  Casabona  and 6.67% by each of Donald C. Supcoe,
Richard E. Heffelfinger and J. Michael Forbes.  The aggregate amount paid by the
Company for rent to Energy  Centre,  Inc. was $339,470 for fiscal year 1999. The
Company  believes that such rental terms are no less  favorable  than could have
been obtained from an unaffiliated party.


                                       69
<PAGE>
                                     PART IV
                                     -------

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

<TABLE>
<CAPTION>
<S>  <C>  <C>
(a)   1.  Financial Statements
          The Financial Statements are filed as a part of this annual report at Item 8.

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

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

                                       70
<PAGE>
       *   3.1   Articles of Incorporation of Energy Corporation of America
       *   3.2   Amended Articles of Incorporation of Energy Corporation of America
       *   3.3   Amended Bylaws of Energy Corporation of America
       *   4.1   Credit Agreement among Energy Corporation of America, General Electric
                 Capital Corporation as Agent, and the lenders named therein, dated as of
                 May 20, 1997.
       *   4.2   Note Purchase Agreement between Mountaineer Gas Company and The
                 John Hancock Mutual Life Insurance Company dated as of October 12, 1995.
       *   4.3   Indenture, dated as of May 23, 1997, between Energy Corporation of America
                 and The Bank of New York, as Trustee, with respect to the 9 1/2% Senior
                 Subordinated Notes Due 2007 (including form of 9 1/2% Senior Subordinated
                 Note Due 2007.
       *   4.4   Form of 9 1/2% Senior Subordinated Note due 2007, Series A.
       *   4.5   Registration Rights Agreement, dated as of May 20, 1997, among Energy
                 Corporation of America, as issuer, and Chase Securities Inc. and Prudential
                 Securities Inc.
       *  10.1   Eastern American Energy Corporation Profit/Incentive Stock Plan dated
                 as of June 4, 1997.
       *  10.2   Buy-Sell Stock Option Agreement dated as of May 19, 1997 among Energy
                 Corporation of America, F.H. McCullough, III and Kathy L. McCullough.
       *  10.3   Buy-Sell Stock Option Agreement dated as of July 8, 1996 between Energy
                 Corporation of America and Kenneth W. Brill.
       *  10.4   Gas Purchase Contract dated as of January 1, 1993 between Eastern
                 American Energy Corporation and Eastern Marketing Corporation.
       *  10.5   FTSI Service Agreement No. 37994 dated as of November 1,1993 between
                 Mountaineer Gas Company and Columbia Gulf Transmission Company.

                                       71
<PAGE>
       *  10.6   Service Agreement No. 42794 dated as of November 1,1994 between
                 Mountaineer Gas Company and Columbia Gulf Transmission Company.
       *  10.7   SST Service Agreement No. 38087 dated as of November 1,1993 between
                 Mountaineer Gas Company and Columbia Gas Transmission Corporation
       *  10.8   FTS Service Agreement No. 38137 dated as of November 1,1993 between
                 Mountaineer Gas Company and Columbia Gas Transmission Corporation.
                 (Previously misidentified as FTS Service Agreement No. 38037)
       *  10.9   Supplement No. 1 to Transportation Service Agreement No. 38137 dated
                 as of May 6, 1994 between Mountaineer Gas Company and Columbia Gas
                 Transmission Corporation.
       *  10.10  FSS Service Agreement No. 38077 dated as of November 1,1993 between
                 Mountaineer Gas Company and Columbia Gas Transmission Corporation.
       *  10.11  NTS Service Agreement No. 39272 dated as of November 1,1993 between
                 Mountaineer Gas Company and Columbia Gas Transmission Corporation.
       *  10.12  FTS Service Agreement No. 38113 dated as of November 1,1993 between
                 Mountaineer Gas Company and Columbia Gas Transmission Corporation.
       *  10.13  Supplement No. 1 to Transportation Service Agreement No. 38113 dated
                 as of May 6, 1994 between Mountaineer Gas Company and Columbia Gas
                 Transmission Corporation.
       *  10.14  Gas Transportation Agreement dated as of October 1, 1994 between
                  Mountaineer Gas Company and Tennessee Gas Pipeline Company.
       *  10.15  Amendment No. 1 to Gas Transportation Agreement dated as of May 5, 1995
                 between Mountaineer Gas Company and Tennessee Gas Pipeline Company.
       *  10.16  FTS Service Agreement No. 60266 dated May 20, 1998 between Mountaineer
                 Gas Company and Columbia Gas Transmission Corporation.
       *  10.17  Incentive Stock Purchase Agreement dated February 12, 1999 by and
                 between Energy Corporation of America and Michael S. Fletcher.
          10.18  Incentive Stock Purchase Agreement dated December 16, 1998 by and
                 between Energy Corporation of America and Joseph E. Casabona.
          10.19  Incentive Stock Purchase Agreement dated December 16, 1998 by and
                 between Energy Corporation of America and Edward J. Davies.
          10.20  Incentive Stock Purchase Agreement dated December 16, 1998 by and
                 between Energy Corporation of America and Donald C. Supcoe.
          10.21  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                 between Energy Corporation of America and Gaston Caperton.
          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.

                                       72
<PAGE>
          10.25  Incentive Stock Purchase Agreement dated March 19, 1999 by and
                 between Energy Corporation of America and A. C. Nielsen, Jr.
          10.26  Stock Purchase Agreement dated February 17, 1999 by and among Westech
                 Energy Corporation, Westech Energy New Zealand Limited and Edward
                 J. Davies
          10.27  First Amendment to Credit Agreement and Assignment and Waiver dated
                 September 26, 1997 by and among Energy Corporation of America, General
                 Electric Capital Corporation, The Bank of Nova Scotia and Union Bank of
                 California, N.A.
          10.28  Second Amendment to Credit Agreement dated April 2, 1999 by
                 and among Energy Corporation of America, General Electric Capital Corporation,
                 The Bank of Nova Scotia and Union Bank of California, N.A.
          10.29  Third Amendment to Credit Agreement dated September 27, 1999 by
                 and among Energy Corporation of America, General Electric Capital Corporation,
                 The Bank of Nova Scotia and Union Bank of California, N.A.
          10.30  Natural Gas Supply Management Agreement dated September 30, 1998, by and
                 Between Coral Energy Resources, L.P., Coral Energy, L.P. and Mountaineer.
           21.1  Subsidiaries of Energy Corporation of America.
           25.1  Power of Attorney set forth on the signature page contained in Part V.
           27.1  Financial Data Schedule.

       *  Previously filed.

(b)       Reports on Form 8-K
          No reports on Form 8-K have been filed during the fiscal year ended June 30, 1999.
</TABLE>


                                       73
<PAGE>
                                     PART V
                                     ------


SIGNATURES

     Pursuant  to  the  requirements  of  Section  13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its  behalf  by  the  undersigned thereunto, duly authorized, on the 27th day of
September  1999.

                                  ENERGY  CORPORATION  OF  AMERICA

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

                                       74
<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  Isobel M. Allan and each of them (with full power to each of them
to  act  alone), his true and lawful attorney-in-fact and agent, with full power
of  substitution, for him and on his behalf and in his name, place and stead, in
any  and  all  capacities,  to  sign,  execute and file this Form 10-K under the
Securities  Act  of  1934,  as  amended,  and  any or all amendments (including,
without  limitation,  post-effective  amendments), with all exhibits and any and
all documents required to be filed with respect thereto, with the Securities and
Exchange  Commission  or  any  regulatory  authority,  granting  unto  such
attorneys-in-fact  and  agents,  and  each  of them acting alone, full power and
authority  to do and perform each of every act and thing requisite and necessary
to be done in and about the premises in order to effectuate the same, as full to
all  intents and purposes as he himself might or could do if personally present,
hereby  ratifying  and  confirming all the such attorneys-in-fact and agents, or
any  of them, or their substitute or substitutes, may lawfully do or cause to be
done.

     Pursuant to the  requirements of the Securities Act of 1934, this Form 10-K
has been signed on the ___ day of September  1999, by the  following  persons in
the capacities indicated.


                                       75
<PAGE>
<TABLE>
<CAPTION>
Signature                                              Title
--------------------------  -----------------------------------------------------------
<S>                         <C>
/s/ John Mork
--------------------------
John Mork                   President, Chief Executive Officer and Director
                            (principal executive officer)

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

/s/ Isobel M. Allan
--------------------------
Isobel M. Allan             Vice President (principal accounting and financial officer)

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

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

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

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

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

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

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


                                       76
<PAGE>