<PAGE>

               SECURITIES AND EXCHANGE COMMISSION
                     Washington, D.C.  20549
                            FORM 10-K

        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
               THE SECURITIES EXCHANGE ACT OF 1934
           For the fiscal year ended December 31, 1998

                     Registrant;                  I.R.S. Employer
Commission       State of Incorporation;          Identification
File Number     Address; and Telephone Number         Number

 1-267          ALLEGHENY ENERGY, INC.               13-5531602
                (A Maryland Corporation)
                10435 Downsville Pike
                Hagerstown, Maryland 21740-1766
                Telephone (301) 790-3400

 1-5164         MONONGAHELA POWER COMPANY            13-5229392
                (An Ohio Corporation)
                1310 Fairmont Avenue
                Fairmont, West Virginia  26554
                Telephone (304) 366-3000

 1-3376-2       THE POTOMAC EDISON COMPANY           13-5323955
                (A Maryland and Virginia
                 Corporation)
                10435 Downsville Pike
                Hagerstown, Maryland  21740-1766
                Telephone (301) 790-3400

 1-255-2        WEST PENN POWER COMPANY              13-5480882
                (A Pennsylvania Corporation)
                800 Cabin Hill Drive
                Greensburg, Pennsylvania  15601
                Telephone (724) 837-3000

 0-14688        ALLEGHENY GENERATING COMPANY         13-3079675
                (A Virginia Corporation)
                10435 Downsville Pike
                Hagerstown, Maryland 21740-1766
                Telephone (301) 790-3400

Indicate by check mark whether the registrants (1) have 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
and  (2)  have 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 Regulation S-K is not contained  herein,
and will not be contained, to the best of registrants' 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]


<PAGE>


Securities registered pursuant to Section 12(b) of the Act:

                                                  Name of each exchange
Registrant              Title of each class       on which registered

Allegheny Energy, Inc.  Common Stock,             New York Stock Exchange
                          $1.25 par value         Chicago Stock Exchange
                                                  Pacific Stock Exchange
                                                  Amsterdam Stock Exchange

Monongahela Power
 Company              Cumulative Preferred
                        Stock,
                        $100 par value;
                        4.40%                     American Stock Exchange
                        4.50%, Series C           American Stock Exchange

                        8% Quarterly Income
                        Debt Securities,
                        Junior Subordinated
                        Deferrable Interest
                        Debentures,
                        Series A                  New York Stock Exchange

The Potomac Edison
 Company              Cumulative Preferred
                        Stock,
                        $100 par value:
                        3.60%                     Philadelphia Stock Exchange
                                                   Inc.
                        $5.88, Series C           Philadelphia Stock Exchange
                                                   Inc.

                        8% Quarterly Income
                        Debt Securities,
                        Junior Subordinated
                        Deferrable Interest
                        Debentures,
                        Series A                  New York Stock Exchange

West Penn Power       Cumulative Preferred
 Company                       Stock,
                        $100 par value:
                        4-1/2%                    New York Stock Exchange

                        8% Quarterly Income
                        Debt Securities,
                        Junior Subordinated
                        Deferrable Interest
                        Debentures,
                        Series A                  New York Stock Exchange


Securities registered pursuant to Section 12(g) of the Act:

Allegheny Generating
 Company                Common Stock
                         $1.00 par value          None


<PAGE>



                      Aggregate market value           Number of shares
                   of voting stock (common stock)      of common stock
                      held by nonaffiliates of         of the registrants
                         the registrants at              outstanding at
                          March 4, 1999                  March 4, 1998


Allegheny Energy, Inc.    $3,833,787,176                  122,436,317
                                                       ($1.25 par value)


Monongahela Power         None. (a)                         5,891,000
  Company                                              ($50 par value)

The Potomac Edison        None. (a)                        22,385,000
  Company                                                (no par value)


West Penn Power           None. (a)                        24,361,586
  Company                                                (no par value)


Allegheny Generating
  Company                 None. (b)                          1,000
                                                        ($1.00 par value)


(a)  All such common stock is held by Allegheny
     Energy, Inc., the parent company.

(b)  All such common stock is held by its parents,
     Monongahela Power Company,  The Potomac Edison
     Company, and West Penn Power Company.


<PAGE>


                              CONTENTS

PART I:                                                            Page


 ITEM 1.   Business                                                 1

           Factors That May Affect Future Results                   3
           Proposed Merger with DQE, Inc.                           4
           Competition                                              4
             Activities at the Federal Level                        5
             Activities at the State Level                          5
           Operating Subsidiaries' Sales                           10
             Regulatory Framework Affecting Power Sales            12
           Other Subsidiaries' Sales                               14
           Electric Facilities                                     15
           Allegheny Map                                           18
           Research and Development                                20
           Capital Requirements and Financing                      22
            Financing Programs                                     24
           Fuel Supply                                             26
           Rate Matters                                            27
           Environmental Matters                                   31
            Air Standards                                          31
            Water Standards                                        35
            Hazardous and Solid Wastes                             36
            Toxic Release Inventory                                36
            Global Climate Change                                  37
           Regulation                                              38
           Year 2000                                               38

 ITEM 2.   Properties                                              39

 ITEM 3.   Legal Proceedings                                       39

 ITEM 4.   Submission of Matters to a Vote of Security
            Holders                                                42

           Executive Officers of the Registrants                   43

PART II:


 ITEM 5.   Market for the Registrants' Common Equity
            and Related Shareholder Matters                        45

 ITEM 6.   Selected Financial Data                                 46

 ITEM 7.   Management's Discussion and Analysis of Financial
            Condition and Results of Operations                    47

 ITEM 8.   Financial Statements and Supplementary Data             48


<PAGE>

                            CONTENTS
                                                                 Page


PART III:

 ITEM  9.  Changes in and Disagreements with Accountants on
            Accounting and Financial Disclosure                    55


 ITEM 10. Directors and Executive Officers of the Registrants      55

 ITEM 11. Executive Compensation                                   56

 ITEM 12. Security Ownership of Certain Beneficial Owners
           and Management                                          62

 ITEM 13. Certain Relationships and Related Transactions           63


PART IV:


 ITEM 14. Exhibits, Financial Statement Schedules, and
           Reports on Form 8-K                                     63


<PAGE>


THIS  COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY ENERGY,
INC., MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY, WEST
PENN   POWER   COMPANY,   AND   ALLEGHENY   GENERATING   COMPANY.
INFORMATION   CONTAINED  HEREIN  RELATING   TO   ANY   INDIVIDUAL
REGISTRANT  IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF.   EACH
REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING  TO
THE OTHER REGISTRANTS.

                             PART I

ITEM 1.   BUSINESS

      Allegheny  Energy, Inc. (AE), incorporated in  Maryland  in
1925,  is an electric utility holding company which owns directly
and  indirectly various regulated and non-regulated  subsidiaries
(collectively and generically, Allegheny).  In 1998,  AE  derived
substantially  all  of  its  income  from  the  electric  utility
operations  of  its  direct and indirect  regulated  subsidiaries
Monongahela  Power  Company  (Monongahela),  The  Potomac  Edison
Company  (Potomac Edison), West Penn Power Company  (West  Penn),
and   Allegheny  Generating  Company  (AGC)  (collectively,   the
Regulated   Subsidiaries).   The  properties  of  the   Regulated
Subsidiaries   are  located  in  Maryland,  Ohio,   Pennsylvania,
Virginia, and West Virginia; are interconnected; and are operated
as a single integrated electric utility system (System), which is
interconnected with all neighboring utility systems.   The  three
electric utility operating subsidiaries are Monongahela,  Potomac
Edison, and West Penn (collectively, the Operating Subsidiaries).
The  Operating  Subsidiaries are doing business under  the  trade
name Allegheny Power.

      Monongahela,  incorporated in Ohio  in  1924,  operates  in
northern West Virginia and an adjacent portion of Ohio.  It  also
owns  generating  capacity in Pennsylvania.   Monongahela  serves
about  355,900 customers in a service area of about 11,900 square
miles  with  a  population of about 710,000.  The  seven  largest
communities  served  have  populations  ranging  from  10,900  to
33,900.   Monongahela's service area has navigable waterways  and
substantial deposits of bituminous coal, glass sand, natural gas,
rock  salt,  and  other natural resources.   Its  service  area's
principal  industries produce coal, chemicals,  iron  and  steel,
fabricated  products, wood products, and glass.   There  are  two
municipal  electric distribution systems and two  rural  electric
cooperative associations in its service area.  Except for one  of
the   cooperatives,  they  purchase  all  of  their  power   from
Monongahela.

      Potomac  Edison, incorporated in Maryland in  1923  and  in
Virginia in 1974, operates in portions of Maryland, Virginia, and
West Virginia.  It also owns generating capacity in Pennsylvania.
Potomac  Edison serves about 390,200 customers in a service  area
of  about  7,300 square miles with a population of about 782,000.
The  six largest communities served have populations ranging from
11,900  to  40,100.   Potomac Edison's service  area's  principal
industries produce aluminum, cement, fabricated products,  rubber
products,  sand,  stone, and gravel.  There  are  four  municipal
electric  distribution systems in its service area, all of  which
purchase  power  from  Potomac Edison,  and  six  rural  electric
cooperatives, one of which purchases power from Potomac Edison.


<PAGE>

                                 2

     West Penn, incorporated in Pennsylvania in 1916, operates in
southwestern and north and south-central Pennsylvania.   It  also
owns  generating  capacity in West Virginia.  In  December  1996,
Pennsylvania  enacted the Electricity Generation Customer  Choice
and  Competition  Act (Customer Choice Act)  to  restructure  the
electric  industry in Pennsylvania to create retail access  to  a
competitive electric energy generation market.  As of January  2,
1999,  two-thirds of West Penn's retail load was able  to  choose
their electric generation supplier.  See ITEM 1. COMPETITION  and
ITEM  1.  RATE  MATTERS  for  a  discussion  of  the  status   of
competition  in Pennsylvania.  As a consequence of  the  Customer
Choice  Act, West Penn reorganized into a Delivery Business  Unit
(supplying  transmission and distribution to  customers  in  West
Penn's  service territory), and a Supply Business Unit (supplying
retail  generation throughout Pennsylvania, outside  West  Penn's
service  area,  and  other  states  in  the  region  implementing
customer  choice,  and wholesale generation anywhere).  The  next
step for the Supply Business Unit is for it to become a separate,
unregulated  affiliate generation company, in  1999.   Only  one-
third of West Penn's retail load remains regulated, about 224,100
customers.  West Penn's service area contains about 9,900  square
miles  with  a  population of about 1,399,000.   The  10  largest
communities  served  by West Penn have populations  ranging  from
11,200  to  38,900.   West  Penn's  service  area  has  navigable
waterways and substantial deposits of bituminous coal, limestone,
and  other  natural  resources.   Its  service  area's  principal
industries  produce steel, coal, fabricated products, and  glass.
There  are three municipal electric distribution systems  in  its
service area, all of which purchase their power requirements from
West  Penn,  and  five  rural electric cooperative  associations,
located partly within the area, all of which purchase their power
from a pool that purchases a portion of its power from West Penn.

      AGC,  organized  in  1981 under the laws  of  Virginia,  is
jointly   owned  by  the  Operating  Subsidiaries   as   follows:
Monongahela, 27%; Potomac Edison, 28%; and West Penn,  45%.   AGC
has  no employees, and its only asset is a 40% undivided interest
in   the  Bath  County  (Virginia)  pumped-storage  hydroelectric
station,  which  was placed in commercial operation  in  December
1985,  and  its connecting transmission facilities.   AGC's  840-
megawatt  (MW) share of capacity of the station is  sold  to  its
three  parents.   The remaining 60% interest in the  Bath  County
Station is owned by Virginia Electric and Power Company (Virginia
Power).

      AE,  the Regulated Subsidiaries, and AYP Capital, Inc.  and
its  subsidiaries have no employees.  Their officers are employed
by  Allegheny  Power Service Corporation (APSC), a  wholly  owned
subsidiary  of  AE,  incorporated in Maryland  in  1963.   APSC's
employees  provide  all necessary services to AE,  the  Regulated
Subsidiaries, and AYP Capital, Inc. and its subsidiaries.   Those
companies   reimburse  APSC  for  services  provided  by   APSC's
employees.  On  December 31, 1998, APSC had  approximately  4,817
employees.

     AYP Capital, Inc. (AYP Capital), incorporated in Delaware in
1994, is a wholly owned nonutility subsidiary of AE.  AYP Capital
has  three  wholly  owned  subsidiaries--AYP  Energy,  Inc.  (AYP
Energy),  Allegheny  Communications  Connect,  Inc.  (ACC),   and
Allegheny  Energy  Solutions, Inc. (Allegheny Energy  Solutions),
all  Delaware corporations. AYP Capital is also part owner of APS
Cogenex,  a  limited liability company formed with  EUA  Cogenex.
APS  Cogenex


<PAGE>

                                  3

ceased  its marketing activities  in  1996  and  is
concluding existing projects.  (See ITEM 1. COMPETITION and  ITEM
7.  MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL  CONDITION
AND  RESULTS OF OPERATIONS - Significant Events in 1998, 1997 and
1996   for  a  further  description  of  AYP  Capital   and   its
subsidiaries' activities.)  AYP Capital and its subsidiaries have
no  employees.   However,  as  of  December  31,  1998,  25  APSC
employees  were  dedicated to AYP Capital and  its  subsidiaries'
activities  on  a full-time basis.  Other APSC employees  provide
services  to  AYP Capital as required.  AE's total investment  in
AYP  Capital  and its subsidiaries as of December 31,  1998,  was
$19.7  million.   AE is currently committed to invest  up  to  an
additional  $3.2  million in AYP Capital to  fund  AYP  Capital's
investment in two limited partnerships.

       The  move  to  a  more  competitive  environment  presents
Allegheny  with  a  new  set  of  opportunities  and  challenges,
including   determining  the  appropriate   industry   structure,
determining recovery of transition costs (those costs imposed  or
incurred  under  a  regulatory  structure  that  would   not   be
recoverable  in  a  competitive environment), retaining  existing
customers and acquiring new customers, and, in general,  changing
the way electric utilities do business.


             FACTORS THAT MAY AFFECT FUTURE RESULTS

      In addition to the historical information contained herein,
this report contains a number of "forward-looking statements"  as
defined in the Private Securities Litigation Reform Act of  1995.
These  include statements with respect to deregulation activities
and   movements  toward  competition  in  states  served  by  the
Operating   Companies,  the  merger  with  DQE,   Inc.,   capital
expenditures,  earnings  on  assets,  resolution  and  impact  of
litigation, regulatory matters, liquidity and capital  resources,
and accounting matters.  All such forward-looking information  is
necessarily  only  estimated.  There can  be  no  assurance  that
actual  results  will  not materially differ  from  expectations.
Actual results have varied materially and unpredictably from past
expectations.

     Factors that could cause actual results to differ materially
include,  but are not limited to:  the impact of general economic
changes  in the U.S.; the impact of deregulation on the  electric
utility  business;  increased competition  and  electric  utility
restructuring  in the U.S., including ongoing state  and  federal
activities;  potential Year 2000 operation problems; developments
in  the legislative, regulatory, and competitive environments  in
which   Allegheny  operates,  including  regulatory   proceedings
affecting   rates  charged  by  AE's  subsidiaries;  developments
relating  to the proposed merger of AE with DQE, Inc.,  including
expenses  that may be incurred in litigation; federal  and  state
regulatory  developments and changes in  law  which  may  have  a
substantial adverse impact on the value of the assets within  the
Allegheny  system;  timing and adequacy of rate  relief;  adverse
changes in electric load and customer growth; climatic changes or
unexpected  changes  in weather patterns; changing  fuel  prices;
generating plant and distribution facility performance, including
unscheduled  maintenance  or  repair  requirements;   and   other
circumstances that could affect anticipated revenues  and  costs,
such  as significant volatility in the market prices of wholesale
and retail power.


<PAGE>

                                4


                 PROPOSED MERGER WITH DQE, INC.

     On April 7, 1997, AE and DQE, Inc. (DQE) announced that they
had  entered into an Agreement and Plan of Merger dated April  5,
1997  (Merger Agreement).  The Merger Agreement provided for  the
business  combination of AE and DQE and was contingent  upon  the
approval  of  each company's shareholders and state  and  federal
regulators.   At separate meetings held on August  7,  1997,  the
shareholders of AE and DQE approved the merger.  AE and DQE  made
all  necessary  regulatory  filings.   Since  then,  AE  and  DQE
received  approval  from the Nuclear Regulatory  Commission,  the
Pennsylvania Public Utility Commission (Pennsylvania PUC) and the
Federal  Energy  Regulatory Commission (FERC).  The  Pennsylvania
PUC and FERC approvals are subject to certain conditions that are
acceptable   to  AE.   The  Maryland  Public  Service  Commission
(Maryland  PSC)  and the Ohio Public Utilities  Commission  (Ohio
PUC) have also indicated their approval of the merger.

     In a letter to AE dated October 5, 1998, DQE stated that it
had decided to unilaterally terminate the merger.  In response,
on October 5, 1998, AE filed a lawsuit in the United States
District Court for the Western District of Pennsylvania against
DQE for specific performance of the Merger Agreement or, in the
alternative, for damages.  AE also filed motions for a temporary
restraining order and preliminary injunction against DQE.  On
October 28, 1998, the court denied AE's motions for a temporary
restraining order and preliminary injunction.  On October 30,
1998, AE appealed the District Court's order to the United States
Court of Appeals for the Third Circuit.  On March 11, 1999, the
U.S. Court of Appeals for the Third Circuit vacated the district
court's denial of Allegheny's motion for preliminary injunction,
enjoining DQE from taking actions prohibited by the merger
agreement.  The Circuit Court stated that if DQE breached the
Merger Agreement, AE would be entitled to specific performance of
the Merger Agreement.  The Circuit Court also stated that AE
would be irreparably harmed if DQE took actions that would
prevent AE from receiving the specific performance remedy.  The
Circuit Court remanded the case to the District Court for further
proceedings consistent with its opinion.

     In the District Court, discovery is ongoing, and AE cannot
predict the outcome of this litigation.  However, AE believes
that DQE's basis for seeking to terminate the merger is without
merit.  Accordingly, AE continues to seek the remaining
regulatory approvals from the Department of Justice and the
Securities and Exchange Commission.  It is not likely either
agency will act on the requests unless AE obtains judicial relief
requiring DQE to move forward.


                           COMPETITION

     The electric supply portion of the electric utility industry
in  the  United  States is in the midst of becoming  competitive.
The  Energy  Policy  Act of 1992 (EPACT)  began  the  process  by
deregulating  wholesale power sales within the electric  industry
by  permitting  the  FERC to compel electric utilities  to  allow
third  parties  to sell electricity to wholesale  customers


<PAGE>

                                5


over their  transmission systems on a non-discriminatory basis.
Since  1992,  wholesale   electricity   markets   have   become
increasingly  competitive  as  companies  began  to  engage  in
nationwide  power  marketing.   In  addition, some  states have
taken  active  steps   toward  allowing  retail  customers  the
right  to  choose  their electric supplier.

                 Activities at the Federal Level

      Allegheny  has  been an advocate of federal legislation  to
mandate  competition in retail electricity markets nationwide  to
avoid regional dislocations and ensure level playing fields.  The
Operating Subsidiaries continue to participate in the Partnership
for  Customer Choice to seek enactment of federal legislation  to
bring  choice  to all retail electric customers,  deregulate  the
generation  and  sale  of electricity on a  national  level,  and
create  a  more  liquid,  free market for electric  power.  Fully
meeting  challenges in the emerging competitive environment  will
be  difficult  for  Allegheny unless certain outmoded  and  anti-
competitive laws, specifically the Public Utility Holding Company
Act  of  1935  (PUHCA)  and Section 210  of  the  Public  Utility
Regulatory  Policies  Act  of  1978  (PURPA),  are  repealed   or
significantly  revised.   Allegheny  continues  to  advocate  the
repeal  of PUHCA and PURPA, on the grounds that they are obsolete
and anti-competitive, and that PURPA results in utility customers
paying  above-market  prices  for  power.  (See  ITEM  3.   LEGAL
PROCEEDINGS for information concerning PURPA-related litigation.)

                 Activities at the State Level

      In  the  absence  of  federal  legislation,  state-by-state
implementation  has  begun.  All  of  the  states  the  Operating
Subsidiaries  serve  are at various stages of  implementation  or
investigation  of programs that allow customers to  choose  their
electric supplier.  Pennsylvania is furthest along with a program
in  place, while Maryland and Virginia are moving to adopt  plans
in  1999  to  implement retail choice.  Ohio  and  West  Virginia
continue to study this issue.

                          Pennsylvania

      The  Customer  Choice  Act  in  Pennsylvania  provides  for
customer   choice  of  electric  supplier  and  deregulation   of
generation in a competitive electric supply market.  Pursuant  to
the  Customer  Choice Act, all electric utilities in Pennsylvania
were  required to establish and administer retail customer choice
of electric supply pilot programs to 5% of the load of each class
of  their customer base.  In order to assure participation in the
pilot program, a credit was established by the Pennsylvania  PUC.
The  credit for West Penn's customers participating in the  pilot
was  artificially high, and resulted in West Penn's  suffering  a
net  loss of revenues of approximately $6.5 million for the total
pilot  period that ended December 31, 1998.  In order to mitigate
pilot losses, West Penn took action to become a licensed electric
supplier  to the pilot customers of the other electric  utilities
in  Pennsylvania.  However, sale prices were low and margins were
commensurately  thin.   As  a result, West  Penn  was  unable  to
completely offset its pilot


<PAGE>

                                6


losses with new revenues.<1>  West Penn has  authorization from the
Pennsylvania PUC to seek recovery  of this lost pilot revenue, and
intends to do so in 1999.

      Beginning  in  January  1999,  two-thirds  of  West  Penn's
customer  load  was  permitted to choose  an  alternate  electric
supplier.   All  of  West  Penn's customer  load  can  choose  an
electric supplier beginning in January 2000.  (See ITEM  1.  RATE
MATTERS for a discussion of the settlement agreement reached with
the Pennsylvania PUC, which included recovery of transition costs
and the ability to transfer generating assets to an affiliate  at
net  book value.)  One result of the Customer Choice Act was  the
bifurcation  of  West Penn's electricity supply  and  electricity
delivery   functions   into   two   separate   businesses.    The
transmission   and  distribution  business  remains   under   the
traditional  regulated  ratemaking.  As it  is  deregulated,  the
electric  supply  business  pricing will  be  determined  by  the
marketplace.    The   delivery  business  in   Pennsylvania   has
responsibility  as the electricity provider of last  resort  (for
those  customers  of  West  Penn who  choose  not  to  select  an
alternate supplier or whose alternate supplier does not  deliver)
and  will  generally obtain necessary electric  supply  for  this
function  from  the  market as the transition to  competition  is
implemented.  The electric supply business will be free  to  sell
West  Penn's deregulated generation in the wholesale  and  retail
markets,  subject  to  codes  of  conduct,  and  subject  to  the
restriction  that  it  may not, except under certain  conditions,
sell  at retail in West Penn's service territory through the year
2003.

                            Maryland

     The Maryland PSC, in December 1997, issued an order to
implement retail competition in that state.  The Maryland PSC's
order and its revised second order call for a deregulation
process, including a three-year phase-in beginning July 1, 2000,
with recovery of prudent transition costs after mitigation.  The
orders recognized that many details were yet to be decided and
called for roundtable discussions and adjudicatory proceedings
for that purpose.  On September 10, 1998, the Maryland PSC issued
a third order that clarified certain issues and questions
involved with the earlier orders.  The main roundtable created by
the orders has been meeting since April 1998.  This roundtable
formed six working groups to study various issues involved with
restructuring the electric industry.  Each of the working groups
submitted their interim reports to the Maryland PSC on November
1, 1998.  The roundtable's final report to the Maryland PSC is
due May 1, 1999, and the PSC's final order in connection with the
work of the roundtable is due August 1, 1999.  Potomac Edison and
other Maryland utilities appealed the Commission's orders on the
grounds that the PSC did not have sufficient authority to implement
its plan absent authorizing legislation.  In a settlement of the
appeal approved by the court, the Maryland PSC agreed that

_______________

<1>  In 1997, Allegheny formed Allegheny Energy Solutions, which also
     participated as a licensed electric supplier in the Pennsylvania
     pilot program in all electric utility service areas within
     Pennsylvania using electric energy purchased from the 
     competitive wholesale market.  (See p. 9 in ITEM 1. COMPETITION
     for a discussion of which part of the new corporate structure
     will be participating in the deregulated retail energy markets
     beginning in 1999.)


<PAGE>

                                7

its orders in this case were not final and the utilities withdrew
their appeal.  Authorizing legislation has been introduced in the
1999 session of the Maryland legislature that would permit the
Maryland PSC to implement its customer choice plan.

     Two adjudicatory proceedings were established by the
Maryland PSC to aid in its implementation of retail competition,
one dealing with stranded cost quantification and recovery
mechanisms, price protection and unbundled rates and the other
with market power protective measures.  Potomac Edison filed
testimony in the stranded cost proceeding on July 1, 1998.  The
other parties filed testimony in mid-December and hearings are
scheduled to begin April 26, 1999.  The parties are informally
exploring the possibility of settling this case subject to the
Maryland legislature passing necessary enabling legislation this
year.

                            Virginia

     In February 1998, the Virginia General Assembly passed
Senate Joint Resolution 91 (SJR 91), which established a
subcommittee of the General Assembly to study electric utility
restructuring.  The SJR 91 Subcommittee met throughout 1998 and
developed detailed restructuring legislation, which was
introduced in the 1999 session.  The legislation would implement
a transition to choice for all Virginia electric customers
beginning in 2002.  It allows for stranded and transition cost
recovery, and caps rates for retail customers during the
transition period.  A separate Tax Task Force examined tax issues
arising from proposed restructuring and also introduced
legislation in the 1999 session.  Both the restructuring and tax
bills passed the House and Senate in February and are awaiting
the Governor's signature.

     The Virginia State Corporation Commission (Virginia SCC)
issued an order in 1998 that required Virginia Power and American
Electric Power Company, Inc., to develop and submit retail pilot
programs for customer choice.  While Potomac Edison was not
required to develop a pilot for its customers in Virginia,
Potomac Edison is participating in the development of those
programs through pilot task forces established by the Virginia
SCC.  The Virginia SCC also issued an order in 1998 requiring
Virginia utilities to submit monthly reports on the progress of
any Independent System Operator (ISO) discussions in which the
utilities are involved.  Potomac Edison has reported on AE's
participation in certain activities related to the Midwest ISO.
AE's membership in the Midwest ISO is contingent upon its merger
with DQE.  Virginia's ISO reporting obligation is ongoing.

     By Order dated December 3, 1998, the Virginia SCC
established a proceeding to adopt interim rules to govern issues
common to both the natural gas and electricity restructuring
retail access pilot programs ordered in other cases, specifically
the issues of certification, code of conduct, and standards of
conduct governing relationships among entities participating in
pilot programs.  The Task Force created in connection with this
proceeding began meeting in early 1999 to consider proposed rules
and issued its final report to the Commission in March 1999.


<PAGE>

                                8


                          West Virginia

      In  December  1996, the Public Service Commission  of  West
Virginia (West Virginia PSC) issued an order initiating a general
investigation regarding the restructuring of the electric utility
industry.   A  Task Force was established to further  investigate
restructuring issues.  In December 1997, the Task Force  approved
legislative language that would have given the West Virginia  PSC
broad   authority  to  implement  retail  choice.   The  proposed
legislation  was  substantially modified  by  the  West  Virginia
Legislature  and passed in March 1998.  The legislation  directed
the  West  Virginia  PSC to meet with all interested  parties  to
develop  a restructuring plan, which plan would meet the dictates
and  goals of the legislation.  Interested parties formed  a  new
Task Force that met during 1998, but the Task Force was unable to
reach  a consensus on a model for restructuring.  The Task  Force
anticipates reconvening in 1999 to further discuss restructuring.
The Commission has since issued an order setting a schedule for a
series  of  hearings in 1999 on major issues such  as  transition
costs, codes of conduct, and customer protections.

                              Ohio
                                
     In 1998, the Ohio PUC continued informal roundtable
discussions on issues concerning competition in the electric
utility industry.  Several bills on restructuring and
deregulation were introduced in the Ohio Legislature and were the
subject of numerous hearings and negotiations at the committee
level but no consensus was achieved.  In early 1999, a group of
legislators began closed door discussions to develop a
restructuring plan to be introduced in the 1999 session.  The
legislators intend to reveal their plan in March 1999.

      Allegheny  over the past several years has taken  steps  to
better  position  itself to participate in  the  new  competitive
markets.   These include AYP Capital (AE's nonutility subsidiary)
forming  two  subsidiaries in 1996:   AYP  Energy  and  ACC.   In
addition,  in 1997 AYP Capital formed Allegheny Energy Solutions.
AYP Energy is a bulk power marketer.  In October 1996, AYP Energy
purchased  a  50% interest (276 MW) in Unit No.  1  of  the  Fort
Martin coal-fired power station in West Virginia.  AYP Energy  is
marketing  the output of its 50% interest in Unit No. 1  of  Fort
Martin,  as well as engaging in other power marketing activities.
AYP  Energy's losses in 1998 resulted primarily from low  selling
prices  in  competitive  markets and marketing  losses.   (For  a
discussion of the losses, see ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS  OF  FINANCIAL  CONDITION AND RESULTS  OF  OPERATIONS  -
Earnings  Summary.)  The operation of a merchant plant and  power
marketing in the wholesale market is essentially participation in
a  commodity  market, which creates certain risk exposures.   The
risks  to  which  AYP Energy is exposed include underlying  price
volatility,  credit  risk, and variation  in  cash  flows,  among
others.   To  manage these risks, Allegheny has  risk  management
policies  and  procedures, consistent with industry practice  and
its  goals.   (See also discussion in Note N to the  Consolidated
Financial  Statements  in  ITEM  8.   FINANCIAL  STATEMENTS   AND
SUPPLEMENTARY DATA.)


<PAGE>

                                9

      During 1998, AYP Capital made several investments in  funds
which  were  established in 1995.  They include an investment  in
EnviroTech  Investment  Fund  I,  L.P.  (EnviroTech),  a  limited
partnership formed to invest in emerging electrotechnologies that
promote  the  efficient  use  of  electricity  and  improve   the
environment.  AYP Capital committed to invest up to $5 million in
EnviroTech  over 10 years, beginning in 1995.  AYP  Capital  also
participates in the Latin American Energy and Electricity Fund I,
L.P.  (FONDELEC), a limited partnership formed to invest  in  and
develop  electric  energy opportunities in  Latin  America.   AYP
Capital  committed to invest up to $5 million  in  FONDELEC  over
eight  years, beginning in 1995.  Through FONDELEC,  AYP  Capital
has  invested  in  electric distribution companies  in  Peru  and
Argentina.   Both EnviroTech and FONDELEC may offer  AYP  Capital
opportunities  to identify investments in which AYP  Capital  may
coinvest  in  excess of its capital commitment  in  each  limited
partnership.

      AYP Capital is also developing other energy-related service
businesses.    For   example,  AYP  Capital  offers   engineering
consulting  services and project management for transmission  and
distribution facilities.

     In 1997, ACC, an exempt telecommunications company, formed a
limited liability company with Hyperion Communications of
Pennsylvania, Inc., known as Allegheny Hyperion
Telecommunications, L.L.C.  Allegheny Hyperion Telecommunications
began operations in the Altoona and State College markets in
October of 1998.  Allegheny Hyperion Telecommunications offers a
full range of telecommunications services, including high-
capacity dedicated telecommunications services between business
and commercial locations; services connecting business locations
with long-distance carriers; and local telephone service.

     In August 1998, ACC and AEP Communications, LLC, a
subsidiary of American Electric Power Company, Inc., announced
plans to connect and jointly market their fiber optic networks in
West Virginia, providing the state with increased access to high-
speed, broadband communications services. Through this venture,
the companies will provide high-speed communications services to
several West Virginia cities.  In November 1998, ACC and AEP
Communications, LLC, widened their agreement to include the fiber
optic networks of First Energy Telcom Corp. and GPU Telcom
Services, Inc.

      Allegheny  Energy Solutions was formed in  1997  to  market
electric energy to retail customers in deregulated retail markets
and  to  participate in the Pennsylvania pilot  as  an  alternate
supplier  to  customers with choice within and outside  the  West
Penn  service  area,  using electricity  it  purchased  from  the
competitive  wholesale  market.  The  limited  liability  company
formed   between  Allegheny  Energy  Solutions  and  DQE   Energy
Partners, Inc. to participate in the Pennsylvania pilot  will  no
longer   participate.   (For  a  discussion  of  the   activities
undertaken  by  Allegheny Energy Solutions in  1998  and  related
nonutility  losses,  see  ITEM  7.  MANAGEMENT'S  DISCUSSION  AND
ANALYSIS  OF  FINANCIAL  CONDITION AND RESULTS  OF  OPERATIONS  -
Earnings Summary.)  Because of organizational efficiencies gained
by  using  an  alternate  corporate structure,  Allegheny  Energy
Solutions  will not compete in deregulated retail energy  markets
beyond   1998.   Rather,  that  role  will  be  assumed  by   the
deregulated supply function of West Penn, acting under  the  name
of  Allegheny Energy Supply.  Allegheny Energy Supply has  gained
several


<PAGE>

                               10


hundred megawatts of load for 1999 through  Pennsylvania customers'
choice  of  Allegheny  Energy  Supply  as  their  new supplier of
generation services.


                  OPERATING SUBSIDIARIES' SALES

     In 1998, consolidated regulated kilowatt-hour (kWh) sales to
regular  customers  (retail and wholesale power)  increased  2.8%
from those of 1997 as a result of increases of .8%, 5.5% and 3.3%
in  residential,  commercial and industrial sales,  respectively.
Consolidated regulated revenues from residential sales  decreased
1.4%,  while commercial and industrial sales increased  2.2%  and
 .8%,  respectively.  (See  ITEM  1.  RATE  MATTERS  and  ITEM  7.
MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND
RESULTS OF OPERATIONS.)

      Allegheny's all-time combined generation customer peak load
of  7,500 MW occurred on February 5, 1996.  The control area peak
load in 1998 was 7,314 MW on July 22, 1998.

      Consolidated regulated electric operating revenues for 1998
were  derived  as  follows: Pennsylvania, 44.4%;  West  Virginia,
27.9%;  Maryland, 19.2%; Virginia, 6.1%; Ohio, 2.4% (residential,
37.8%;   commercial,  21.5%;  industrial,   32.3%;   bulk   power
transactions, 4.9%; and other, 3.5%).  The following  percentages
of  such  revenues were derived from these industries:  iron  and
steel,   6.5%;  aluminum  and  other  nonferrous  metals,   3.4%;
chemicals,  3.4%;  coal  mines, 3.3%;  cement,  2.6%;  fabricated
products, 1.8%; and all other industries, 11.4%.

      During  1998,  Monongahela's kWh sales to retail  customers
increased  3.9%.  Residential sales decreased .3% but  commercial
and  industrial  sales  increased 5.8%  and  5.5%,  respectively.
Revenues  from residential, commercial, and industrial  customers
increased .5%, 6.4%, and 6.0%, respectively, primarily due to  an
increase  in  the fuel and energy cost component as  well  as  an
increase  in  the number of customers and usage.   Revenues  from
bulk  power transactions and sales to affiliates decreased  3.8%.
Monongahela's  revenues represented 24.7%  of  Allegheny's  total
regulated  sales  to  regular customers.  Monongahela's  all-time
peak load of 1,844 MW occurred on July 21, 1998.

      Monongahela's electric operating revenues were  derived  as
follows:  West  Virginia,  91.2%, and  Ohio,  8.8%  (residential,
31.1%;   commercial,  19.6%;  industrial,   32.3%;   bulk   power
transactions, 3.1%; and other, 13.9%).

      During 1998, Potomac Edison's kWh sales to retail customers
increased  5.0%.   Residential, commercial and  industrial  sales
increased  2.6%,  7.2%  and  5.9%,  respectively.  Revenues  from
residential, commercial and industrial customers increased  3.1%,
5.9% and 4.3%, respectively, primarily due to an increase in  the
number  of  customers  and  usage.   Revenues  from  bulk   power
transactions  and  sales to affiliates increased  7.6%.   Potomac
Edison's   revenues   represented  31.9%  of  Allegheny's   total
regulated sales to regular customers.  Potomac Edison's  all-time
peak  load  of 2,614 MW occurred on January 17, 1997.   The  peak
load in 1998 was 2,413 MW on July 22, 1998.


<PAGE>

                               11

     Potomac Edison's electric operating revenues were derived as
follows:  Maryland,  61.9%; West Virginia  19.0%,  and  Virginia,
19.1%; (residential, 41.9%; commercial, 21.3%; industrial, 28.0%;
bulk  power transactions, 3.6%; and other, 5.2%).  Revenues  from
one  industrial  customer, the Eastalco aluminum reduction  plant
near  Frederick,  Maryland, amounted to $64.8  million  (8.8%  of
total  electric operating revenues).  Minimum annual  charges  to
Eastalco  under  an  electric service agreement  which  continues
through  March  31,  2000, with automatic  extensions  thereafter
unless  terminated on notice by either party, were $15.1  million
in 1998. This agreement may be canceled before the year 2000 upon
90 days' notice in the event of a governmental decision resulting
in a material modification of the agreement.

      During  1998,  West Penn's kWh sales to  retail  customers,
including   sales  to  Pennsylvania  retail  pilot  participants,
decreased 2.8% as a result of decreases of 4.6%, 1.6% and 2.2% in
residential,  commercial,  and  industrial  sales,  respectively.
Revenues  from  residential, commercial and industrial  customers
decreased 5.7%, 2.4%, and 4.1%, respectively, primarily due to  a
$25.1   million  rate  refund  resulting  from  the  Pennsylvania
restructuring  settlement agreement, a  reduction  in  previously
bundled   customers   (full  service  customers)   due   to   the
Pennsylvania  retail  pilot program, and a  reduction  in  usage.
Revenues  from  bulk power transactions and sales to  affiliates,
including  bulk power sales under the Pennsylvania  retail  pilot
program,   increased   43.3%.  West  Penn's  regulated   revenues
represented 43.4% of Allegheny's total regulated sales to regular
customers. West Penn's all-time peak load of 3,251 MW occurred on
July  15, 1997.  The regulated peak load in 1998 was 3,067 MW  on
June  25, 1998.  The territorial West Penn share of the Allegheny
control area peak load in 1998 was 3,192 MW on June 25, 1998.

      West  Penn's  electric operating revenues were  derived  as
follows:  Pennsylvania,  100%  (residential,  34.4%;  commercial,
20.2%;  industrial,  31.4%; bulk power  transactions,  6.4%;  and
other, 7.6%).

      In  1998, the Operating Subsidiaries provided approximately
3.0   billion  kWh  of  energy  to  nonaffiliated  companies  and
marketers  from generation facilities operated by  the  Operating
Subsidiaries.  Revenues from those sales of generation, including
Pennsylvania  retail pilot sales, from the Operating Subsidiaries
were approximately $69.8 million.

      The  Operating  Subsidiaries transmitted approximately  7.4
billion  kWh  to others located outside their service territories
under various forms of transmission service agreements.  Revenues
from those sales were about $45.2 million.

     Sales of generation and transmission services to others vary
with  the  needs of those customers for capacity and/or  economic
replacement power; the availability of generating facilities  and
excess power, fuel, and regional transmission facilities; and the
availability and price of competitive sources of power.  Revenues
from  sales  of transmission services to others by the  Operating
Subsidiaries increased in 1998 relative to 1997 despite decreased
transmission services activity.  The increase in revenues was due
in part to transmission services' reservation charges paid to the
Operating  Subsidiaries  by  others for  the  right  to  transmit
energy.   Transmission activity was affected as a result of  some
of  the reservations to transmit


<PAGE>

                               12

energy not being used.  Sales of power generated
by the Operating Subsidiaries increased in  1998
relative  to  1997 primarily from increased sales to brokers  and
power marketers due to increased sales that occurred primarily in
the  second  quarter as a result of warm weather which  increased
the  demand  and  price for energy, and increased  sales  due  to
participation   in   the  Pennsylvania  retail   pilot   program.
Substantially  all  of  the benefits of  power  and  transmission
service  sales  to  nonaffiliates by the Operating  Subsidiaries,
except  West Penn, were passed on to retail customers and,  as  a
result,  had  little  effect on Monongahela Power's  and  Potomac
Edison's net income.  Effective May 1, 1997, West Penn no  longer
passes these benefits on to retail customers.

      Pursuant  to  a  peak diversity exchange  arrangement  with
Virginia  Power,  the  Operating  Subsidiaries  annually   supply
Virginia  Power  with 200 MW during each June, July,  and  August
and,   in   return,   Virginia  Power  supplies   the   Operating
Subsidiaries  with 200 MW usually during each December,  January,
and  February,  at least through February 2000.  Beyond  February
2000, no diversity exchange is planned.

     The Operating Subsidiaries have an exchange arrangement with
Duquesne  Light  Company (Duquesne) which will  continue  through
February  2000.   In  this  exchange arrangement,  the  Operating
Subsidiaries have, in the past, supplied Duquesne with up to  200
MW  for a specified number of weeks, generally during each March,
April,   May,  September,  October,  and  November.   In  return,
Duquesne had supplied the Operating Subsidiaries with up  to  100
MW,  generally  during  each  December,  January,  and  February.
Currently,  there  are  no  exchanges  being  made  as   Duquesne
endeavors to sell off its generating assets.  The total number of
MWh  to be delivered by each utility to the other over the active
term of the arrangement will have been the same.

           Regulatory Framework Affecting Power Sales

      EPACT  initiated the restructuring of the electric  utility
industry  by  permitting competition in the wholesale  generation
market.   In  order to facilitate the efficient use of generation
facilities,  on  April 24, 1996, the FERC issued Orders  888  and
889.  On  March  4, 1997, the FERC issued Orders  888A  and  889A
reaffirming  and  clarifying  the  legal  and  policy  issues  as
originally  presented in the previous orders.    In  response  to
requests for rehearing, the FERC issued Orders 888B and  889B  on
November  25, 1997.  The Commission again supported its  original
intentions  and  presented explanations and  minor  revisions  to
specific sections of the orders.

      The FERC orders require all transmission providers to offer
service to entities selling generation services in a manner  that
is  comparable to their own use of the transmission system.   The
orders  required each transmission provider to file  standardized
open   access   transmission  service  tariffs;  therefore,   the
Operating  Subsidiaries  have on file a  pro  forma  open  access
tariff  under  which  they  sell  transmission  services  to  all
eligible  customers. The Operating Subsidiaries (and AYP  Energy,
when  appropriate)  also  arrange for transmission  services  for
their  own sales pursuant to the rates, terms, and conditions  of
the  open  access tariff.  The tariff was accepted for filing  by
the  FERC on November 25, 1998.  The Commission's order specified
a  December  6, 1995, effective date and required refunds  to  be
paid on the time


<PAGE>

                               13

value of money based upon the difference between the   originally
filed  rates  and  those  authorized   by   the  Commission.

       To   meet   the  objective  of  providing  comparable   or
nondiscriminatory transmission services, the FERC orders  further
require   that   utilities  functionally  unbundle   transmission
operations  and  reliability functions  from  wholesale  merchant
functions   within  the  Operating  Subsidiaries.    Accordingly,
discrete  businesses  have  been  formed,  including  a  Delivery
Business  Unit (inclusive of transmission) and a Supply  Business
Unit.   The  Delivery  Business Unit includes several  sub-units,
including  the  System  Planning  and  Operations  group,   which
provides   transmission   system   operations   and   reliability
functions.   Each  unit has its own management,  objectives,  and
facilities.  The Operating Subsidiaries conduct their business in
a manner that is consistent with FERC's Standards of Conduct.

      The  orders  require  that  all transmission  requests  for
service be made over the Open Access Same Time Information System
(OASIS).   The  OASIS,  an internet-based  nationwide  electronic
network,  became operational on January 3, 1997.   The  Operating
Subsidiaries,  in conjunction with a consortium  of  transmission
providers, continue to work to implement a revised version of the
OASIS  Standards and Communications Protocols document issued  by
FERC.  OASIS Phase 1A will become operational on March 1, 1999.

      The FERC established its jurisdiction over unbundled retail
as   well  as  wholesale  transmission  services  in  Order  888.
Although  states  retain  the authority to  determine  if  retail
wheeling should be adopted, retail transmission service under the
jurisdiction  of  the FERC is available once  these  historically
franchised customers have access to alternate generation sources.
Pennsylvania  enacted legislation authorizing retail  choice  for
selected customers as of November 1, 1997 (Customer Choice  Act).
The Operating Subsidiaries added Schedule 10--Retail Transmission
Service to their open access tariff authorizing the sale of  open
access  transmission  services  to  unbundled  retail  customers.
Initially,  the  Operating Subsidiaries will provide  service  to
Pennsylvania's  unbundled  retail  customers  and  eventually  to
retail   customers  with  choice  in  Maryland,  Virginia,   West
Virginia, and Ohio.

     In compliance with Pennsylvania's restructuring requirements
and  in  conjunction  with the merger plans,  AE  and  DQE  filed
jointly  with the FERC an Allegheny Energy open access tariff  in
August 1997.  No sales have been made under that tariff and  none
will be made until the merger is consummated.

     The Operating Subsidiaries also have on file with the FERC a
Standard  Generation  Service  Rate  Schedule  for  the  sale  of
wholesale  power  at  cost-based rates.   In  October  1997,  the
Operating  Subsidiaries submitted a new wholesale tariff  to  the
FERC,  asking for authority to sell power at market-based  rates.
The  Operating  Subsidiaries began selling power at  market-based
rates upon the filing's acceptance by the FERC in August 1998.

      The  Operating  Subsidiaries continue their involvement  as
General   Agreement   on   Parallel   Paths   (GAPP)   experiment
participants.   The  purpose  of the  experiment  is  to  collect
operating  data  on  the effect of parallel  power  flow  on  the
interconnected  transmission system and to develop  an  equitable


<PAGE>

                              14

compensation  system  reapportioning current contract  path-based
revenues  upon a reflection of the actual flow of  power  on  the
interconnected  electrical system.  During the two-year  term  of
the  experiment,  many of the GAPP principles  were  successfully
incorporated   into   certain  industry-wide   system   operating
practices  established by the North American Electric Reliability
Council (NERC).  When the experiment concludes on March 31, 1999,
the participants will publicly present information on the revenue
reallocation method they developed.

      AE  and  DQE,  Inc.,  conditionally executed  a  membership
agreement  with  the  Midwest ISO; the  commitment  to  join  the
Midwest  ISO  was  expressly contingent upon  consummation  of  a
proposed   merger  between  AE  and  DQE,  Inc.   The  membership
agreement was entered into on April 9, 1998, and filed  with  the
FERC   on   April  13,  1998.   AE's  membership  status  remains
conditional  until the merger is consummated or it is  determined
that the Merger Agreement is terminated.

      Under PURPA, certain municipalities, businesses and private
developers  have installed, are installing, or are  proposing  to
install,  generating facilities at various locations in  or  near
the  Operating  Subsidiaries' service areas with  the  intent  of
selling  some or all of the electric capacity and energy  to  the
Operating Subsidiaries at rates consistent with PURPA and ordered
by  appropriate  state commissions.  As a result  of  PURPA,  the
Operating Subsidiaries are committed to purchasing 299 MW of  on-
line  PURPA capacity.  Payments for PURPA capacity and energy  in
1998 totaled approximately $129.0 million, at an average cost  to
the  Operating Subsidiaries of 5.4 cents/kWh, as compared to  the
Operating Subsidiaries' own generating cost of about 3 cents/kWh.
The  Operating Subsidiaries project an additional 180 MW of PURPA
capacity (Warrior Run) to come on-line in 1999.  The Warrior  Run
project  will  result  in  rate increases  for  Potomac  Edison's
Maryland  customers  pursuant to a 1998 rate case  settlement  in
that   jurisdiction.  (See  ITEM  3.  LEGAL  PROCEEDINGS  for   a
description   of   litigation  and  regulatory   proceedings   in
Pennsylvania  and West Virginia concerning other  proposed  PURPA
projects.)


                    OTHER SUBSIDIARIES' SALES

      In  1998, AYP Energy provided 7.3 billion kWh of energy  to
nonaffiliated  customers, including generation from  Fort  Martin
Unit  No.  1, amounting to 1.8 billion kWh.  Revenues from  those
sales  were  approximately  $215.3  million.   Total  unregulated
operating  revenues in 1998, including sales by Allegheny  Energy
Solutions  under the Pennsylvania retail pilot program,  amounted
to  $247.0  million.  Allegheny Energy Solutions participated  in
the  pilot  program  as an alternate supplier to  customers  with
choice  within and outside the West Penn service  area.   (For  a
discussion of increases in nonutility losses in 1998, See ITEM 7.
MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND
RESULTS OF OPERATIONS - Earnings Summary.)


<PAGE>

                               15

                       ELECTRIC FACILITIES

      The  following table shows Allegheny's December  31,  1998,
operational  generating  capacity based on  the  maximum  monthly
normal  seasonal operating capacity of each unit.  The  Regulated
Subsidiaries' owned capacity totaled 8,121 MW, of which 7,091  MW
(87%)  are  coal-fired, 840 MW (10%) are pumped-storage,  132  MW
(2%)  are  oil-fired,  and  58 MW (1%)  are  hydroelectric.   AYP
Energy, an exempt wholesale generator in 1998, also owns  276  MW
of  coal-fired generation.  The term "pumped-storage"  refers  to
the  Bath  County station which stores energy for use principally
during peak load hours by pumping water from a lower to an  upper
reservoir,   using  the  most  economic  available   electricity,
generally  during  off-peak hours.  During the generating  cycle,
power  is  produced by water falling from the upper to the  lower
reservoir through turbine generators.

      The  weighted  average  age of the Regulated  Subsidiaries'
owned  steam stations shown on the following page is  about  28.6
years.  In 1998, their book value was $1.8 billion, average  heat
rate  was  9,939  Btu's/kWh, and their  availability  factor  was
85.8%.   The age of AYP Energy's owned generation is 32.0  years.
In  1998,  the  book value of AYP Energy's owned  generation  was
$163.5  million, average heat rate was 9,622 Btu's/kWh,  and  the
availability factor was 88.9%.


<PAGE>

                               16

                          Allegheny Stations
                      Maximum Generating Capacity
                            (Megawatts) (a)
                                                           AYP      Dates When
                             Station Monon-  Potomac West  Energy   Service
Station               Units   Total  gahela  Edison  Penn   (b)     Commenced(c)

Coal-fired (steam):
 Albright               3      292     216      76                    1952-4
 Armstrong              2      352                     352            1958-9
 Fort Martin            2    1,107     249     304     278    276     1967-8
 Harrison               3    1,920     480     629     811            1972-4
 Hatfield's
   Ferry                3    1,660     456     332     872            1969-71
 Mitchell               1      284                     284            1963
 Pleasants              2    1,252     313      376    563            1979-80
 Rivesville             2      142     142                            1943-51
 R. Paul Smith          2      115              115                   1947-58
 Willow Island          2      243     243                            1949-60
Oil-fired (steam): (a)
 Mitchell               2      132                     132            1948
Pumped-storage and Hydro:
 Bath County            6      840     227(d)   235(d) 378(d)         1985
 Lake Lynn(e)           4       52                      52            1926
 Potomac Edison (e)    21        6                6                   Various
Total Allegheny-owned
 Capacity              54    8,397   2,326    2,073   3,722    276

                           Other Generation
                      Maximum Generating Capacity
                            (Megawatts) (f)

                                                           AYP     Contract
                           Project Monon-  Potomac West   Energy Commencement
Project                     Total  gahela  Edison  Penn     (b)      Date
Coal-fired: (steam)
 AES Beaver Valley           125                    125              1987
 Grant Town                   80      80                             1993
 West Virginia
   University                 50      50                             1992

Hydro:
 Allegheny Lock and Dam 5      6                       6             1988
 Allegheny Lock and Dam 6      7                       7             1989
 Hannibal Lock and Dam        31      31                             1988

Total Other Capacity         299     161       0(g)  138       0

Total Allegheny-owned and
PURPA Committed            8,696   2,487   2,073   3,860     276
Generating Capacity (a)


<PAGE>

                               17

     (a)  Winter rating. Excludes West Penn oil-fired capacity of
          207  MW  at  Springdale Power Station which was  placed  on  cold
          reserve status as of June 1, 1983.  On December 31, 1994, 82  MW,
          and  on  July  1,  1998, 50 MW of the total MW at Mitchell  Power
          Station were reactivated.

     (b)  AYP Energy owns 50% of Unit No. 1 at Fort Martin.

     (c)  Where  more than one year is listed as a commencement
          date  for  a particular source, the dates refer to the  years  in
          which  operations  commenced  for the  different  units  at  that
          source.

      (d) Capacity entitlement through ownership of  AGC,  27%,
          28%,  and  45%  by Monongahela, Potomac Edison,  and  West  Penn,
          respectively.

      (e) West  Penn  has  a  30-year license  for  Lake  Lynn,
          effective   December   1994.   Potomac   Edison's   license   for
          hydroelectric facilities Dam No. 4 and Dam No. 5 will  expire  in
          2003.   Potomac  Edison has received 30-year licenses,  effective
          January  1994,  for  the Shenandoah, Warren, Luray,  and  Newport
          projects.   The FERC accepted Potomac Edison's surrender  of  the
          license  for  the  Harper's Ferry Dam No. 3 and issued  an  order
          effective October 1994.

      (f) Other  generating  capacity available  through  state
          utility commission-approved arrangements pursuant to PURPA.

      (g) The  180-MW Warrior Run project is under construction
          and  is planned to begin providing capacity and energy to Potomac
          Edison in 1999.


<PAGE>

                               18

                          ALLEGHENY MAP

      The  Allegheny  Power Map (Map), which  has  been  omitted,
provides  a  broad  illustration of  the  names  and  approximate
locations  of Allegheny Power's major generation and transmission
facilities, both existing and under construction, in a five-state
region  which  includes portions of Maryland, Ohio, Pennsylvania,
Virginia,  and West Virginia.  Additionally, Extra  High  Voltage
substations  are  displayed.  By use of  shading,  the  map  also
provides  a  general  representation  of  the  service  areas  of
Monongahela (portions of West Virginia and Ohio), Potomac  Edison
(portions  of  Maryland, Virginia, and West Virginia),  and  West
Penn (portions of Pennsylvania).

      Power  Stations  shown on the map which appear  within  the
Monongahela service area are Willow Island, Pleasants,  Harrison,
Rivesville, Albright, and Fort Martin.  The single power  station
appearing  within  the Potomac Edison service  area  is  R.  Paul
Smith.   The  Bath County Power Station appears on the  map  just
south of the westernmost portion of Potomac Edison's service area
formed  by  the  borders of Virginia and  West  Virginia.   Power
stations  appearing  within  the  West  Penn  service  area   are
Armstrong, Mitchell, Hatfield's Ferry, Springdale, and Lake Lynn.

      The map also depicts transmission facilities which are  (i)
owned  solely  by the Operating Subsidiaries; (ii) owned  by  the
Operating  Subsidiaries in conjunction with other  utilities;  or
(iii)   owned   solely  by  other  utilities.  The   transmission
facilities  portrayed range in capacity from 138 kV  to  765  kV.
Additionally,   interconnections   with   other   utilities   are
displayed.


<PAGE>

                               19

The following table sets forth the existing miles of tower and pole
transmission  and  distribution  lines  and  the   number   of
substations  of the Regulated Subsidiaries as of December  31, 1998:

             Miles of Above-Ground Transmission and
        Distribution Lines (a) and Number of Substations
                                
                                                                Number of
                                        Portion of Total      Transmission and
                            Total      Miles Representing       Distribution
                            Miles    500-Kilovolt (kV) Lines  Substations(b)

      Monongahela         21,035              283                   331
      Potomac Edison      18,135              202                   276
      West Penn           24,102              273                   709
      AGC(c)                  85               85                     1
      Total               63,272              843                 1,317


      (a)  The Operating Subsidiaries also have a total of 6,412 miles
           of underground distribution lines.

      (b)  The substations have an aggregate transformer capacity of
           56,317,204 kilovoltamperes.

      (c)  Total Bath County transmission lines, of which AGC owns an
           undivided 40% interest and Virginia Power owns the remainder.


     The Operating Subsidiaries have 12 extra-high-voltage (EHV),
345-kV  and  above,  and  31 lower-voltage interconnections  with
neighboring  utility systems. The interregional EHV  transmission
system,  including System facilities, continued to  operate  near
reliability limits during periods of heavy power flows  that  are
predominantly in a west-to-east orientation.  In early 1997, NERC
implemented the development of a national security process.   The
Operating  Subsidiaries serve as one of the 22 national  Security
Coordinators.   This  process  includes  a  Transmission  Loading
Relief   (TLR)  procedure  that  identifies  actual   flow   path
consequences  of  power  transactions,  reduces  loading  on  the
transmission  system  when  necessary and  effectively  addresses
parallel path flows.  The TLR procedure has been effective.   Its
use,  and conditions in the Midwest that reversed the predominant
west-to-east power flow pattern across the AE system  during  the
summer   of  1998,  resulted  in  fewer  constraints  on   System
transmission  facilities  that  would  require  curtailments   of
transmission service.
  
      Wholesale  generators and other wholesale customers  may
now  seek from owners of bulk power transmission facilities  a
commitment  to  supply transmission services. (See  discussion
under   ITEM   1.  SALES.)   Such  demand  on  the   Operating
Subsidiaries' transmission facilities may add to  heavy  power
flows  on  the  Operating Subsidiaries'  facilities  and  may,
eventually,  require  construction of additional  transmission
facilities.


<PAGE>

                               20

  
      The  Operating Subsidiaries have, since the early 1980s,
provided  managed  contractual access  to  their  transmission
facilities  under various tariffs.  As described earlier,  for
new  agreements  starting  in 1996,  managed  access  is  also
governed by the provisions of the Operating Subsidiaries' Open
Access  Transmission Tariff mandated by  and  filed  with  the
FERC.


                    RESEARCH AND DEVELOPMENT

      The  Operating  Subsidiaries spent  $7.9  million,  $7.4
million,   and  $7.7  million,  in  1998,  1997,   and   1996,
respectively,  for research programs.  Of these amounts,  $5.5
million,  $5.7  million, and $5.5 million  were  for  Electric
Power  Research Institute (EPRI) dues in 1998, 1997, and 1996,
respectively.   EPRI  is  an industry-sponsored  research  and
development institution.  The Operating Subsidiaries  plan  to
spend  approximately $7.8 million for research in  1999,  with
EPRI dues representing $5.6 million of that total.

      In addition to EPRI support, in-house research conducted
by   Allegheny   concentrated  on  environmental   protection,
generating  unit performance, future generation  technologies,
transmission  system performance, delivery systems,  customer-
related  research,  clean power technology  focused  on  power
quality,  and distributed resources technology for  customers,
delivery   equipment,  and  marketing.   All  Allegheny-funded
research  is related to adapting both competitive and  leading
edge technology to Allegheny's operations.

      Research  is  also being directed to help address  major
issues  facing our industry, including electric  and  magnetic
field  (EMF) assessment of employee exposure within  the  work
environment,  waste disposal and discharges, greenhouse  gases
(GHG),   renewable  resources,  fuel  cells,  new   combustion
turbines, cogeneration technologies, and transmission  loading
mitigation  using  Flexible  AC  Transmission  System  (FACTS)
devices.   An  investigation of the value of  biodiversity  of
lands  owned by Allegheny is being done.  The financial effect
of  these issues on Allegheny, if any, cannot be determined at
this  time.  During 1998, the Operating Subsidiaries supported
the  federal  government's National EMF  Research  and  Public
Information   Dissemination  Program,   a   project   on   the
interaction of biomechanisms and electric and magnetic  fields
(EMF); and an Edison Electric Institute (EEI) program to study
employee and public health effects, if any, of EMF.  The World
Health Organization, the Director of the National Institute of
Environmental  Health  Services,  and  an  interagency   group
consisting  of representation from nine federal agencies  plan
to  issue  reports over the next two to three  years  on  EMF,
which  may affect future R&D funding.  In addition,  there  is
continuing  evaluation  of technical  proposals  from  outside
sources  and  monitoring of developments  in  industry-related
literature,   law   and  litigation,  general   business   and
environmental  standards  (ISO  9000  and  ISO   14000),   and
intellectual property rights.

     Because of the nitrogen oxides (NOx) control requirements
of  the Clean Air Act Amendments of 1990 (CAAA), Allegheny  is
participating in a


<PAGE>

                               21

collaborative effort coordinated by EPRI to
gain  a greater understanding of the formation of ground level
ozone  and  how  measures to control NOx and volatile  organic
compounds affect ozone formation.  The North American Research
Strategy for Tropospheric Ozone-Northeast is focused  on  this
effort.    Other   research  is  directed   at   NOx   control
technologies   for   power   station   compliance,   including
optimizing existing low NOx burners to improve performance.

      The  Operating  Subsidiaries  continue  to  monitor  and
demonstrate  technical  solutions  to  greenhouse  gas   (GHG)
reduction,  sequestration, capture, and control.  As  part  of
their  response  to  EPACT and President Clinton's  subsequent
Climate Action Plan, the Operating Subsidiaries, as part of an
EEI   program,   have  agreed  to  participate   in   research
initiatives  which  are  designed  to  reduce,  sequester,  or
control  GHG.   This program is consistent with  filings  made
with  the  Department of Energy (DOE) in voluntary  compliance
with Section 1605(b) of EPACT.

      Electric  vehicle  (EV) research through  1998  included
participation  in  EV America and the Electric  Transportation
Coalition,  as  well as the development of appropriate  wiring
and  building code standards to accommodate electric vehicles.
As  a  result,  Allegheny is positioned to support  commercial
manufacturers  when  they move forward  with  EV  development.
Allegheny provided a grant to the University of Pittsburgh  to
build an electric car from the frame up.

      In  1998,  research was also directed into communication
systems to develop and demonstrate a high-speed digital  power
line  communication  system using existing  utility  wires  to
serve   information  and  automation  needs   of   Allegheny's
customers  and  to  support  system  requirements  in   retail
wheeling and marketing.

      Allegheny  continues to pursue beneficial uses  of  coal
combustion by-products.  In cooperation with the West Virginia
Division  of Environmental Protection, a project is under  way
to  investigate  the  feasibility  and  cost-effectiveness  of
injecting  fly  ash from Allegheny-owned power  stations  into
abandoned  underground mine sites in West Virginia  to  reduce
acid  mine drainage and mine surface subsidence.  The  project
cost  is  being  shared  with  EPRI  as  part  of  a  Tailored
Collaboration Agreement.  Also being investigated is  the  use
of  fly ash as a construction material for a residential  home
demonstration  and  the  use of flue-gas  desulfurization  by-
products for road building.

      As  part  of customer research, a model home program  is
under way and adjustable speed drives for customer motor loads
are  being used at a steel company and at an extrusion process
plant.  West  Penn  participated in 1998 in  the  Pennsylvania
Electric Energy Research Council (PEERC).  PEERC was formed in
1987 as a partnership of Pennsylvania-based electric utilities
and   the  State  of  Pennsylvania  to  promote  technological
advancements related to the electric utility industry.

      In 1998, the Operating Subsidiaries made research grants
to   regional  colleges  and  universities  to  encourage  the
development  of  technical resources related  to  current  and
future utility problems and to conduct


<PAGE>

                               22

research.  A grant  was provided to West Virginia University to
evaluate the effect of Distributed Resources on feeders and for
customer uses.


               CAPITAL REQUIREMENTS AND FINANCING

      Construction expenditures by the Regulated  Subsidiaries
in 1998 amounted to $229.4 million.  Construction expenditures
for 1999 and 2000 are expected to aggregate $280.1 million and
$283.6  million,  respectively.  Construction expenditures  by
AYP   Capital,   the  wholly  owned  nonutility  (unregulated)
subsidiary  of  AE, in 1998 amounted to $1.8 million  and  for
1999  and  2000  are expected to aggregate $34.9  million  and
$10.6  million,  respectively.  The 1999  and  2000  estimated
regulated   expenditures  include  $10.6  million  and   $55.7
million,  respectively, to cover the costs of compliance  with
the  CAAA.  Expenditures to cover the costs of compliance with
the  CAAA  and other environmental requirements have been  and
are  likely to continue to be significant.  Additionally,  new
environmental initiatives (See ITEM 1. ENVIRONMENTAL  MATTERS)
may    substantially    increase   Allegheny's    construction
requirements as early as 2000.

     On October 27, 1998, the EPA finalized rules for reducing
ground  level ozone.  The EPA is requiring 22 states  and  the
District  of  Columbia  to submit state  implementation  plans
(SIPs)  that address the regional transport of ozone.  All  of
the  states served by Allegheny are required to submit the SIP
call.  The intent of the SIP call is to reduce NOx emissions
from  power  plants, on average, to 0.15  pounds  of  NOx  per
million BTU (MBTU).  Although Allegheny has joined with  other
parties  to  contest the EPA's actions in court,  it  is  also
formulating  plans  to  comply  by  making  modifications   to
existing  generating units. The cost to comply will  be  about
$360  million of capital investments, to be spent  during  the
1999-2003  period.   Of  this amount, about  $50  million  was
already  scheduled to be spent, so an additional $310  million
of  capital will be required.  Under the EPA's plan, Allegheny
would  be required to reduce emissions to the 0.15 pounds  per
MBTU requirement by May 2003.


<PAGE>

                               23

                    Construction Expenditures


                                             1998       1999      2000

                                                 Millions of Dollars
                                             (Actual)       (Estimated)
Monongahela
Generation                                 $  25.5    $  26.1     $  26.9
Transmission                                   7.6       11.2         4.6
Distribution                                  39.7       38.4        47.7
Total*                                     $  72.8     $ 75.7     $  79.2

Potomac Edison
Generation                                 $  15.4     $  31.2    $  29.9
Transmission                                   0.9         2.1       13.8
Distribution                                  44.2        52.3       54.4
  Total*                                   $  60.5     $  85.6    $  98.1

West Penn
Generation                                 $  34.2     $  58.8    $  54.8
Transmission                                  10.2         2.3        4.2
Distribution                                  49.2        54.2       46.3
Other                                          2.4         3.4         .7
  Total*                                   $  96.0     $ 118.7    $ 106.0


AGC & APSC                                 $    .1     $   0.1    $   0.3

Total Construction Expenditures,           $ 229.4     $ 280.1    $ 283.6
  Regulated

Nonutility                                 $   1.8     $   34.9   $  10.6

Total Construction Expenditures            $ 231.2**   $ 315.0**  $ 294.2**


  *Includes  allowance  for funds used  during  construction
   (AFUDC),  or  capitalized  interest  in  the  case  of   the
   generation business of West Penn, for 1998, 1999,  and  2000
   of:   Monongahela $1.0, $1.7, and $1.3; Potomac Edison $1.6,
   $1.8, and $1.5; and West Penn $2.4, $3.5, and $2.7.

 **Includes  amounts for projects connected with  Allegheny's
   corporate  restructuring of $17.9, $5.9, and $0.0 for  1998,
   1999, and 2000, respectively.


<PAGE>

                               24

       These  capital  expenditures  include  major  projects  at
existing  generating stations, upgrading distribution  lines  and
substations,  and  the  strengthening  of  the  transmission  and
subtransmission systems.

      On  a  collective  basis  for the  Regulated  Subsidiaries,
expenditures  for  1998,  1999, and 2000 include  $12.8  million,
$62.8  million, and $84.9 million, respectively, for construction
of  currently mandated environmental control technology.  Outages
for  construction, CAAA compliance, and other environmental  work
is,  and  will  continue to be, coordinated  with  other  planned
outages, where possible.

      Allegheny  continues  to  study ways  to  reduce  and  meet
existing regulated customer generation service demand and  future
increases   in  that  demand,  including  demand-side  management
programs;  new and efficient electric technologies;  construction
of  various  types and sizes of generating units; increasing  the
efficiency  and availability of Allegheny generating  facilities;
reducing   internal   electrical   use   and   transmission   and
distribution losses; and acquisition of energy and capacity  from
third-party suppliers. The advent of retail choice of  generation
service  supplier  is  expected to have a significant  effect  on
regulated  generation  service  load  growth  and  the  Operating
Subsidiaries' obligation to meet such load growth.

      Current  forecasts,  which reflect  demand-side  management
efforts  and  other  considerations  and  assume  normal  weather
conditions,  project average annual winter and summer  peak  load
growth  rates for the regulated load of Monongahela  and  Potomac
Edison and the provider of last resort load of West Penn of  0.7%
and 0.6%, respectively, in the period 1999-2009.  Competition for
existing   loads   can  have  a  substantial  effect   on   those
projections.    It   is  anticipated  that  existing   resources,
purchased  power arrangements, reactivation of existing capacity,
and/or  the  acquisition  of  capacity  will  be  sufficient  for
Allegheny's future needs.

       In   connection  with  its  construction  and  demand-side
management  programs,  Allegheny  must  make  estimates  of   the
availability and cost of capital as well as the future demands of
its customers that are necessarily subject to regional, national,
and international developments, changing business conditions, and
other factors.  The construction of facilities and their cost are
affected  by  laws and regulations; lead times in  manufacturing;
availability   of  labor,  materials  and  supplies;   inflation;
interest  rates;  and licensing, rate, environmental,  and  other
proceedings  before regulatory authorities.  Decisions  regarding
construction of facilities must now also take into account retail
competition.  As a result, future plans of Allegheny are  subject
to continuing review and substantial change.

                       Financing Programs

      The Regulated Subsidiaries have financed their construction
programs  through  internally  generated  funds,  first  mortgage
bonds,  debentures,  medium-term  notes,  subordinated  debt  and
preferred  stock  issues,  pollution  control  and  solid   waste
disposal  notes, installment loans, long-term lease arrangements,
equity  investments  by  AE (or, in  the  case  of  AGC,  by  the
Operating Subsidiaries), and, where necessary, interim short-term
debt.   The  future  ability  of the  Regulated  Subsidiaries  to
finance  their  construction


<PAGE>

                               25

programs by these means  depends  on
many    factors,    including   effects   of   competition    and
creditworthiness,  and adequate revenues to produce  satisfactory
internally  generated  funds  and return  on  the  common  equity
portion of the Regulated Subsidiaries' capital structures and  to
support  their  issuance  of senior  and  other  securities.   AE
obtains  funds for equity investments in its subsidiaries through
retained  earnings and the issuance and sale of its common  stock
publicly.

      Beginning  in  the third quarter of 1997, AE  began  buying
shares in the open market for its Dividend Reinvestment and Stock
Purchase Plan, its Employee Stock Ownership and Savings Plan, and
in  1998 AE  began  buying  shares  in the open  market  for  the
Performance Share Plan.

      In February 1998, Monongahela, Potomac Edison and West Penn
issued $17.5 million, $30 million, and $45 million, respectively,
of   9-year  and  14-year  Pollution  Control  Revenue  Notes  to
Pleasants  County,  West Virginia.  Pleasants  County,  in  turn,
issued  $92.5  million  of 9-year and 14-year  Pollution  Control
Revenue Bonds with interest rates ranging from 4.70% to 5.05%  to
refund  $92.5 million of three series due in 2007 and 2012,  with
rates ranging from 6.125% to 6.375%.

      In  March  1998, Monongahela, Potomac Edison and West  Penn
issued   $6.06   million,  $3.2  million  and  $14.435   million,
respectively,  in  4-year, 9-year, and 14-year Pollution  Control
Revenue Notes to Greene County, Pennsylvania.  Greene County,  in
turn,  issued  $23.695  million of 4-year,  9-year,  and  14-year
Pollution Control Revenue Bonds with interest rates ranging  from
4.35%  to 5.10% to refund $23.695 million of three series due  in
2002, 2007, and 2012, with rates ranging from 6.1% to 6.4%.

     Also in March 1998, Monongahela issued $19.1 million in 4.5%
5-year Pollution Control Revenue Notes to Marion, Pleasants,  and
Preston Counties, West Virginia.  These counties, in turn, issued
$19.1 million of 5-year Pollution Control Revenue Bonds to pay at
maturity $19.1 million of three series, with rates of 6.875%.

      In  September  1998, Monongahela and West  Penn  issued  an
aggregate  of $77.025 million of unsecured medium-term  notes  at
interest  rates ranging from 5.56% to 5.71%.  Monongahela  issued
five-year unsecured medium-term notes totaling $43.475 million at
interest  rates  ranging from 5.56% to 5.71%.  West  Penn  issued
four-year unsecured medium-term notes totaling $33.55 million  at
interest rates of 5.56% and 5.66%.

      In  June  and October 1998, Monongahela and Potomac  Edison
redeemed  an  aggregate  $115 million of  First  Mortgage  Bonds.
Monongahela  exercised its right of optional redemption  in  June
1998  to  redeem its $65 million, 8.5% Series, prior to maturity.
Potomac  Edison  exercised its right of  optional  redemption  in
October  1998 to redeem its $50 million 8-7/8% Series,  prior  to
maturity.

      During  1998,  the rate for West Penn's 400,000  shares  of
market  auction preferred stock, par value $100 per share,  reset
approximately every 90 days at 3.95%, 4.084%, 4.019%, and  4.12%.
The rate set at auction on January 14, 1999, was 3.55%.


<PAGE>

                              26

     At December 31, 1998, short-term debt was outstanding in the
following  amounts:   AE  $258.8  million,  AGC  $66.8   million,
Monongahela  $49.0  million, and West  Penn  $65.1  million.   At
December 31, 1998, Potomac Edison had $76.1 million invested.

      The  Regulated  Subsidiaries' ratios of earnings  to  fixed
charges  for  the year ended December 31, 1998, were as  follows:
Monongahela, 4.40; Potomac Edison, 4.09; West Penn, excluding the
effect of the extraordinary charge, 3.52; and AGC, 3.41.

       Allegheny's  consolidated  capitalization  ratios  as   of
December  31, 1998, were: common equity, 46.4%; preferred  stock,
3.9%; and long-term debt, 49.7%, including Quarterly Income  Debt
Securities  (3.5%).  AE's long-term objective is to maintain  the
common equity portion above 46%.

      During  1999,  Monongahela, Potomac Edison, and  West  Penn
anticipate   meeting   their  capital  requirements   through   a
combination  of  internally generated funds, cash  on  hand,  and
short-term borrowing as necessary.

      However, due to the restructuring of electric generation by
Pennsylvania, a special-purpose subsidiary of West Penn is expected
to  issue  up  to $670 million of bonds to securitize  transition
costs related to West Penn's restructuring settlement, which West
Penn may use to reduce its capitalization.


                           FUEL SUPPLY

     Allegheny stations burned approximately 17.5 million tons of
coal  in  1998.   Of  that amount, 88% was  either  cleaned  (5.8
million  tons)  or used in stations equipped with scrubbers  (9.6
million  tons).   The use of desulfurization  equipment  and  the
cleaning  and  blending of coal make burning local  higher-sulfur
coal  practical.   In 1998, almost 100% of the coal  received  at
Allegheny-operated  stations came from mines  in  West  Virginia,
Pennsylvania,  Maryland, and Ohio.  Allegheny does  not  mine  or
clean any coal.  All raw, clean, or washed coal is purchased from
various suppliers as necessary to meet station requirements.

       Long-term  arrangements  are  in  effect  to  provide  for
approximately  14.3 million tons of coal in 1999.  The  Operating
Subsidiaries  will  depend on short-term  arrangements  and  spot
purchases  for  their remaining requirements.  Through  the  year
2001,  the  total coal requirements of present Allegheny-operated
stations are expected to be met with coal acquired under existing
contracts or from known suppliers.

      For  each of the years 1994 through 1997, the average  cost
per  ton  of coal burned was $35.88, $32.68, $32.25, and  $32.66,
respectively.  For the year 1998, the cost per ton  decreased  to
$32.26.

      Long-term  arrangements, subject to price  change,  are  in
effect and will provide for the lime requirements of scrubbers at
Allegheny's scrubbed stations.


<PAGE>

                              27

     In addition to using ash in various power plant applications
such  as  scrubber  by-product  stabilization  at  Harrison   and
Mitchell  Power  Stations,  the Operating  Subsidiaries  continue
their   efforts   to  market  coal  combustion  by-products   for
beneficial uses and thereby reduce landfill requirements.  (See a
discussion   of  research  projects  in  ITEM  1.  RESEARCH   AND
DEVELOPMENT.)   In  1998,  the  Operating  Subsidiaries  received
approximately $708,419 from the sale of 1,743,918 tons of fly ash
and 387,769 tons of bottom ash for various uses, including cement
replacement,  mine grouting, oil well grouting,  soil  extenders,
anti-skid material, and grit blast material.

     In 1998, the Operating Subsidiaries signed an agreement with
wallboard  manufacturers to supply a minimum of 600,000  tons  of
synthetic  gypsum  for  use in making wallboard.   The  Operating
Subsidiaries  will  break ground in early  1999  to  construct  a
processing  plant which will convert the Pleasants Power  Station
flue  gas  desulfurization by-product  into  a  commercial  grade
synthetic  gypsum for use in manufacturing wallboard.  This  will
reduce the amount of by-product going to landfill.

      The  Operating Subsidiaries own coal reserves estimated  to
contain  about 125 million tons of higher sulfur coal recoverable
by  deep  mining.   There  are no present  plans  to  mine  these
reserves  and,  in view of economic conditions now prevailing  in
the  coal  market, the Operating Subsidiaries plan  to  hold  the
reserves as a long-term resource.


                          RATE MATTERS

      On  November  19, 1998, the Pennsylvania  PUC  approved  an
agreement  between  West  Penn and  intervenors  in  West  Penn's
restructuring proceedings related to legislation in  Pennsylvania
to  provide  customer choice of electric supplier and  deregulate
electricity  generation.  (See Notes B and C to the  Consolidated
Financial Statements for details of the settlement agreement  and
other information about the deregulation process.)

      Under  the Customer Choice Act, all utilities were provided
an  opportunity to recover their transition (or stranded)  costs.
The   determination  of  transition  costs  relied   heavily   on
projections of future market prices of electricity.  West  Penn's
transition cost recovery claim of $1.2 billion was the subject of
significant  disagreement  and  debate  by  intervenors  in   the
restructuring proceedings, as were the transition cost claims  of
the other Pennsylvania utilities.

       Under  the  settlement  agreement,  West  Penn  has   been
authorized  to  recover $670 million ($630  million  if  the  DQE
merger is consummated) of transition costs, plus a return over  a
ten-year  period, and to record most of the income  therefrom  in
the  earlier  years  of  the transition period  when  electricity
market prices are assumed to be lowest.  Additionally, West  Penn
has  written  off  as an extraordinary item in  1998  about  $467
million  ($275.4  after  taxes) of  costs  which  it  deemed  not
recoverable under the deregulation process. Of this amount,  $451
million  ($265.4 million after taxes) was recorded in the  second
quarter and $16 million ($10 million after taxes) was recorded in
the  fourth  quarter.  The settlement also provides  for  a  rate


<PAGE>

                              28

refund  from  1998 revenue (about $25 million) via  a  2.5%  rate
decrease   throughout   1999,   capped   rate   provisions    and
authorization to issue bonds to securitize up to $670 million  in
transition costs.

      Under the terms of the settlement agreement, two-thirds  of
West  Penn's  customers  were permitted to  choose  an  alternate
electric  supplier  beginning in January  1999.   All  West  Penn
customers  can  do  so  beginning in January  2000.   (West  Penn
customers  represent about 45% of Allegheny's electricity  supply
business.)  They can choose to remain as a West Penn customer  at
West  Penn's  capped  generation rates or to alternate  back  and
forth.   Under  the law, all electric utilities,  including  West
Penn,  retain the responsibility of electricity provider of  last
resort  (PLR)  to  all  customers in their  respective  franchise
territories that do not choose an alternate supplier.

      Beginning  in  1999, in Pennsylvania, electric  supply  and
electric   delivery  will  be  two  separate   businesses.    The
transmission and distribution business will be under  traditional
regulated rate making, and the electric supply business  will  be
deregulated  with  pricing determined by the market  place.   The
transmission  and  distribution  business  will  have   the   PLR
responsibility and will generally obtain its electric supply from
the   market  primarily  by  bidding,  including  bids  from  the
affiliated supply business.

     The settlement agreement permits the transfer of West Penn's
generation  assets  to the unregulated supply  business  at  West
Penn's book values.  The new, unregulated supply business will be
free  to  sell,  subject  to  a  code  of  conduct,  West  Penn's
deregulated generation capacity and energy in the open  wholesale
and  retail markets, except that it is not permitted to  sell  at
retail, except under certain conditions, in West Penn's franchise
territory through the year 2003.

      Current electric supply prices are below the level required
to  produce results of operations equal to that obtained  in  the
regulated environment in part because, in Allegheny's opinion, of
abundant   generation  from  other  states,   as   well   as   in
Pennsylvania,  to supply the deregulated market of  Pennsylvania.
Allegheny believes that the utilities in states that are not  yet
deregulated  may  now  be  selling  and  may  continue  to   sell
electricity into Pennsylvania on average at a cost which is lower
than  their total cost since their fixed costs are recovered from
franchise customers in their home state territories.

      The  Pennsylvania  PUC's projections of electricity  market
prices recognized this possibility, among others, and accordingly
assumed  depressed prices in the earlier years of the  transition
process from regulation to deregulation.  The projections further
assumed  that  prices  would  increase  in  later  years  due  to
increasing  demand from deregulation in other states  and  normal
increases   in   customer   demand,   particularly   because   of
competition.

      As  stated  above, West Penn made a filing  concerning  its
transition cost requirements in Pennsylvania based on  its  early
1997 projection of market prices.  The Pennsylvania PUC issued an
order  on  May 29, 1998, to West Penn, as well as orders  to  all
other   Pennsylvania  electric  utilities  in  1998,   based   on
alternative  projections.   Current  prices,  which   West   Penn
believes  are  being  influenced, among other  things,  by  price
volatility in the summer of


<PAGE>

                               29

1998, are equal to and in some  cases
slightly  higher than the projections adopted by the Pennsylvania
PUC  in  its  deregulation orders issued to West Penn  and  other
utilities in Pennsylvania.  If the Pennsylvania PUC's projections
are  correct,  West  Penn  believes  that  the  transition  costs
provided  will be sufficient to permit it to recover its embedded
costs,  with  a return, during the transition from regulation  to
deregulation of electricity generation.

       The  forward-looking  statements  above  are  provided  to
describe  Allegheny's plans and its reasoning for actions  taken.
Of  necessity,  its  plans  are based on  assessments  of  future
events.   There can be no assurance that actual results will  not
materially  differ from those presented.  (For  a  discussion  of
West   Penn's   restructuring  plan,  see  ITEM  7.  MANAGEMENT'S
DISCUSSION  AND  ANALYSIS OF FINANCIAL CONDITION AND  RESULTS  OF
OPERATIONS  -  Significant Continuing Issues  -  Electric  Energy
Competition  and  Notes  B  and C to the  Consolidated  Financial
Statements  in  ITEM 8.  FINANCIAL STATEMENTS  AND  SUPPLEMENTARY
DATA.)

      After  substantial negotiations, Potomac Edison  reached  a
settlement  agreement  with various  parties  on  the  Office  of
People's  Counsel's  (OPC) petition for a  reduction  in  Potomac
Edison's   Maryland   rates.   The  agreement,   which   includes
recognition  and  dollar-for-dollar  recovery  of  costs  to   be
incurred from the Warrior Run PURPA project,  was filed with  the
Maryland PSC on July 30, 1998, and approved by that Commission on
October 27, 1998.  Rates to each customer class were approved  by
the  Maryland PSC on December 22, 1998.  Under the terms  of  the
agreement, Potomac Edison will increase its rates about  4%  ($13
million) in each of the years 1999, 2000, and 2001 (a $39 million
annual  effect in 2001).  The increases are designed  to  recover
additional  costs  of about $131 million, over the  period  1999-
2001,  for  capacity  purchases from the Warrior  Run  generation
project  net of alleged overearnings of $52 million for the  same
period absent these adjustments.  The net effect of these changes
over  the  1999-2001  time  frame results  in  a  pre-tax  income
reduction  of $12 million in 1999, $18 million in 2000,  and  $22
million  in  2001.   In  the  event  the  merger  with   DQE   is
consummated,  an  additional  rate  reduction  of  $4.4   million
annually  will  occur, based upon expected synergy  savings.   In
addition, the settlement requires that Potomac Edison share, on a
50%  customer, 50% shareholder basis, earnings above a  threshold
return  on  equity  (ROE)  level of 11.4%  for  1999-2001.   This
sharing  will  occur through an after-the-fact true-up  conducted
after  each  calendar  year  is  completed.   Warrior  Run  is  a
cogeneration  project  being built  by  AES  Enterprise,  a  non-
affiliated PURPA developer, in western Maryland.  Potomac  Edison
is  required  to  purchase the project's energy  at  above-market
prices pursuant to the requirements of the federal PURPA law.

      As required by the Maryland PSC, Potomac Edison, on July 1,
1998, filed testimony in Maryland's investigation into transition
costs,  price protection, and unbundled rates.  The  filing  also
requested  a  surcharge to recover the cost of  the  Warrior  Run
cogeneration  project, which is scheduled to commence  production
on  October  1, 1999.  Hearings are scheduled to begin  in  April
1999.   A  second  Maryland PSC proceeding is  planned  to  begin
examining  market  power protective measures  in  December  1999.
Under  the  Maryland PSC's current timetable,  and  assuming  the
necessary  legislation  is  passed,  one-third  of  the   state's
electricity  customers would be able to


<PAGE>

                               30

choose their  electricity supplier  beginning  in July 2000, and all
customers  would  have choice by mid-2002.

           The  West Virginia PSC, the Ohio PUC, and the Virginia
SCC  began or continued investigations during 1998 regarding  the
restructuring   of  and  competition  in  the  electric   utility
industry.   (See ITEM 1. BUSINESS - Competition for a description
of these activities.)

      On  September  23,  1998,  the Maryland  PSC  accepted  the
recommendations of Potomac Edison and its Collaborative  Partners
to  phase  out  three demand-side management  (DSM)  programs  in
Maryland.   Potomac  Edison reexamined the cost-effectiveness  of
the  programs, and removed the savings associated with production
capacity  and  energy beginning in the year 2000,  which  is  the
proposed  start date for competition in Maryland.   The  analysis
indicated that the current programs are no longer cost-effective.
As  a result, these programs will be terminated by December 1999.
Since  1993,  Potomac  Edison  has  spent  $20  million  to  help
customers  install  energy-saving measures  in  their  homes  and
businesses  through these programs.  During 1998, Potomac  Edison
expended $966,855 on program costs and rebates.  These costs  are
recoverable  through  a Commission-approved  energy  conservation
surcharge.

      In  1997,  the  Maryland  PSC instituted  a  proceeding  to
investigate  the  effect of the proposed AE  and  DQE  merger  on
Potomac Edison's Maryland customers and operations.  The Maryland
PSC  approved  a settlement agreement in this case on  March  28,
1998.   Upon  merger consummation, Maryland  retail rates will be
reduced  by  $4.4  million  annually  to  reflect  a  portion  of
expected synergy savings.

      Potomac  Edison and the Virginia Commission  Staff  entered
into  discussions  which  resulted in a settlement  agreement  of
Potomac  Edison's  Annual Informational Filing  (AIF)  which  the
Virginia  SCC  approved August 7, 1998.  Effective  September  1,
1998, Potomac Edison reduced base rates by $2.5 million and wrote
off  $2.3  million of restructuring costs which had been deferred
for  ratemaking  purposes only, and $0.5 of  loss  on  reacquired
debt.   The return on equity (ROE) range was maintained at 11-12%
with  the  computed  ROE, after adjustments, of  11.4%.   Potomac
Edison agreed to file a full AIF for calendar year 1998 by  March
31, 1999, with an earnings test.  In the event Potomac Edison  is
in  an  over-earning  position  at  that  time,  its  rates  will
immediately become interim.

       Currently,  all  state  regulatory  jurisdictions   except
Pennsylvania and the FERC use fuel clause procedures to recognize
changes  in  fuel  and  other  energy  costs  in  rates.    These
procedures use an expedited proceeding which permits energy costs
to  be  adjusted  on  a  more  timely  basis  than  other  costs.
Differences between revenues received for energy costs and actual
energy  costs are deferred until the next proceeding when  energy
rates  are  adjusted to return or recover previous overrecoveries
or  underrecoveries, respectively.  This procedure minimizes  the
effect on net income associated with changes in energy costs.

      On June 30, 1998, the West Virginia PSC issued an order  in
the  annual  Expanded  Net  Energy Cost proceedings  under  which
Monongahela and Potomac Edison received annual increases of  $8.9
million  and  $1.0  million,


<PAGE>

                               31

respectively.   The  increases  were primarily  due  to fuel cost
increases and  to the  removal  of  a credit,   which   had  been
 refunding  to  customers   a   prior overrecovery of fuel costs.
The new rates became effective  July 1, 1998.

      Fuel  proceedings  before the Ohio PUC require  a  mid-term
filing,  financial audit, management performance  audit,  and  an
annual filing.  The Ohio PUC approved a stipulated agreement  for
Monongahela on January 21, 1999, which granted a decrease of $1.4
million.  The new rate was effective February 3, 1999.

      On January 15, 1998, Potomac Edison filed with the Virginia
SCC  for  an  annual increase in fuel rates of  $2.1  million  to
become  effective March 9, 1998.  The increase was primarily  due
to  the need to collect prior underrecovery of fuel costs  and  a
small increase in fuel costs.  On February 25, 1998, the Virginia
SCC  approved the increase.  On January 15, 1999, Potomac  Edison
filed  for  an annual decrease in fuel rates of $2.2  million  to
become effective March 9, 1999.  The decrease is primarily due to
the refunding of a prior overrecovery of fuel costs, coupled with
a  small  decrease in projected energy costs.   On  February  25,
1999, the Virginia SCC approved the decrease.

      AGC's  rates are set by a formula filed with and previously
accepted by the FERC.  The only component that can change is  the
ROE.   Pursuant  to a settlement agreement filed April  4,  1996,
with  the  FERC,  AGC's  ROE was set at 11%  for  1996  and  will
continue until the time any affected party requests a change.  No
party has requested any change.


                      ENVIRONMENTAL MATTERS

      The operations of the Allegheny-owned facilities, including
generating  stations, are subject to regulation  as  to  air  and
water  quality,  hazardous and solid waste  disposal,  and  other
environmental  matters  by  various  federal,  state,  and  local
authorities.  That portion of Fort Martin Unit 1 (50%)  owned  by
AYP  Energy  is subject to the same environmental regulations  as
other  units  owned  by  the Operating Subsidiaries.   Compliance
strategies,  compliance assurance, permitting, compliance  costs,
allowance allocation, etc., for this unit are closely coordinated
with AYP Capital.

      Meeting known environmental standards is estimated to  cost
the  Operating  Subsidiaries about $260 million  in  construction
expenditures  over the next three years.  Additional  legislation
or  regulatory  control requirements have been proposed  and,  if
enacted,  will  require  modifying, supplementing,  or  replacing
equipment at existing stations at substantial additional cost.


                          Air Standards

       Allegheny  currently  meets  applicable  standards  as  to
particulate  and  opacity  at its power  stations  through  high-
efficiency  electrostatic precipitators, cleaned  coal,  flue-gas
conditioning, and, at times, reduction of output.  From  time  to
time,  minor  excursions  of  opacity,  normal  to  fossil


<PAGE>

                               32
fuel operations,   are  experienced  and  are  accommodated by the
regulatory process.

      Allegheny  meets current emission standards as  to  sulphur
dioxide  (SO2) by the use of scrubbers, the burning of low-sulfur
coal,  the purchase of cleaned coal to lower the sulfur  content,
and the blending of low-sulfur with higher sulfur coal.

      The  CAAA, among other things, requires an annual reduction
in total utility emissions within the United States of 10 million
tons  of  SO2  and  two million tons of NOx  from  1980  emission
levels,  to  be  completed in two phases, Phase I and  Phase  II.
Five coal-fired Allegheny plants are affected in Phase I, and the
remaining  plants will be affected in Phase II.  Installation  of
scrubbers  at  the  Harrison  Power  Station  was  the   strategy
undertaken  by  Allegheny  to  meet  the  required  SO2  emission
reductions for Phase I (1995-1999). Allegheny estimates that  its
banked emission allowances will allow it to comply with Phase  II
SO2  limits  through  2005.  Studies to  evaluate  cost-effective
options to comply with Phase II SO2 limits beyond 2005, including
those available in connection with the emission allowance trading
market, are continuing.  It is expected that burner modifications
at  most of the Allegheny-operated stations will satisfy the  NOx
emission  reduction  requirements for the acid  rain  (Title  IV)
provisions  of  the  CAAA.  Additional NOx reductions  are  being
mandated  in Maryland, Pennsylvania, and West Virginia for  ozone
nonattainment (Title I) reasons.  Continuous emission  monitoring
equipment has been installed on all Phase I and Phase II units.

      In  an  effort  to introduce market forces  into  pollution
control,  the CAAA created SO2 emission allowances.  An allowance
is  defined as an authorization to emit one ton of SO2  into  the
atmosphere.    Subject  to  regulatory  limitations,   allowances
(including bonus and extension allowances) may be sold or  banked
for  future use or sale.  Allegheny received, through an industry
allowance  pooling  agreement, a total of  approximately  554,000
bonus  and extension allowances during Phase I.  These allowances
are in addition to the CAAA Table A allowances that the Operating
Subsidiaries receive of approximately 356,000 per year during the
Phase  I  years.  Ownership of these allowances permits Allegheny
to  operate in compliance with Phase I, and, as noted  above,  is
expected to facilitate compliance during the early years of Phase
II.   As part of its compliance strategy, Allegheny continues  to
study  the  allowance  market  to  determine  whether  sales   or
purchases of allowances or participation in certain derivative or
hedging allowance transactions are appropriate.

      Pursuant to an option in the CAAA, Allegheny chose to treat
eight  Phase  II boilers as Phase-I-affected units  (Substitution
Units)  for  calendar year 1998. The status of  all  substitution
units  is evaluated on an annual basis to ascertain the financial
benefits of retaining these units as Phase I-affected units.   As
a  result of being Phase I-affected, these Substitution Units are
required to comply with the Phase I SO2 limits for each year that
they are accorded substitution status by Allegheny.

      Title  I of the CAAA established an Ozone Transport  Region
(OTR)  consisting of the District of Columbia, the northern  part
of  Virginia,  and 11 northeastern states including Maryland  and
Pennsylvania. Sources within the


<PAGE>

                               33

OTR will be required  to  reduce
NOx  emissions,  a  precursor of ozone, to a level  conducive  to
attainment  of  the ozone National Ambient Air  Quality  Standard
(NAAQS).   The  installation  of  Reasonably  Available   Control
Technology (RACT) (overfire air equipment and/or low NOx burners)
at  all  Pennsylvania and Maryland stations has  been  completed.
The  installation of RACT satisfies both Title I and Title IV NOx
reduction requirements.

      Title  I  of  the CAAA also established an Ozone  Transport
Commission (OTC), which has determined that utilities within  the
OTR  will  be  required to make additional NOx reductions  beyond
RACT  in order for the OTR to meet the ozone NAAQS.  Under  terms
of  a  Memorandum  of Understanding (MOU) among the  OTR  states,
Allegheny-operated stations located in Maryland and  Pennsylvania
are  required to reduce NOx emissions by approximately  55%  from
the  1990 baseline emissions, with a compliance date of May 1999.
RACT  controls installed in Allegheny's Maryland and Pennsylvania
generating  plants  are  expected  to  meet  the  55%   reduction
requirement  through the year 2002.  Further  reductions  of  75%
from  the  1990 baseline may be required by May 2003 under  Phase
III  of the MOU.  However, the MOU Phase III NOx reductions  will
most  likely be suspended by the EPA's NOx SIP call as  discussed
below.   Pennsylvania promulgated regulations to implement  Phase
II of the MOU in November 1997.  Maryland promulgated regulations
to implement Phase II of the MOU in May 1998.

      During  1995, the Environmental Council of States  and  the
U.S.  Environmental Protection Agency (EPA) established the Ozone
Transport Assessment Group (OTAG) to develop recommendations  for
the regional control of NOx and Volatile Organic Compounds in  37
states  east  of  and bordering the west bank of the  Mississippi
River plus Texas.  OTAG issued its final report in June 1997 that
recommended EPA consider a range of utility NOx controls  between
existing Clean Air Act (Title IV) controls and the less stringent
of  85%  reduction from the 1990 emission rate or 0.15  lb/mmBtu.
According  to  OTAG recommendations, the states  would  have  the
opportunity to conduct additional local and subregional  modeling
in  order to develop and propose appropriate levels and timing of
controls.  The EPA initiated the regulatory process to adopt  the
OTAG  recommendations  with a proposed SIP  call  issued  October
1998.  The EPA NOx SIP call requires the equivalent of a  uniform
0.15   lb/mmBtu  emission  rate  throughout  a  22-state  region,
including Maryland, Pennsylvania, and West Virginia, without  the
benefit  of the OTAG recommended additional subregional  modeling
evaluation.   Implementation  of controls  will  be  required  by
summer   2003.   States  are  required  to  develop  and   submit
implementing   regulations  to  the  EPA   by   September   1999.
Allegheny's  compliance  with  such  stringent  regulations  will
require  the  installation of expensive  post-combustion  control
technologies on most of its power stations, with a total  capital
cost of approximately $360 million.

      In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of  up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast  (West  Virginia included).  The  petitions  claim  NOx
emissions   from  these  upwind  sources  are  preventing   their
attainment  of  the  ozone  standard.  In  December   1997,   the
petitioning  states and EPA signed a Memorandum of  Agreement  to
address these petitions in conjunction with the OTAG-related  SIP
call mentioned above.  In October 1998, the EPA proposed approval
of  the  petitions.  However, the EPA has stated its


<PAGE>

                               34

belief  that implementation  of the NOx SIP call will alleviate
the  need  to grant  the petitions.  EPA intends to issue a final
rule by April 1999.

     The EPA is required by law to regularly review the NAAQS for
criteria  pollutants.  Recent court orders in litigation  by  the
American Lung Association have expedited these reviews.  The  EPA
in  1996  decided  not  to  revise the  SO2  and  NOx  standards.
Revisions   to  particulate  matter  and  ozone  standards   were
promulgated  by the EPA in July 1997. State attainment  plans  to
meet  the  revised  standards will not be developed  for  several
years.    Also,   in  July  1997,  EPA  proposed  regional   haze
regulations  to  improve  visibility in  Class  I  federal  areas
(natural  parks and wilderness areas).  If finalized,  subsequent
state  regulations  could  require additional  reduction  of  SO2
and/or  NOx  emissions from Allegheny facilities. The  effect  on
Allegheny of revision to any of these standards or regulations is
unknown at this time, but could be substantial.

      The  final outcome of the revised ambient standards,  Phase
III  of  the MOU, SIP calls, and Section 126 petitions cannot  be
determined   at   this  time.   All  are  being  challenged   via
rulemaking, petition, and/or litigation.

      In 1989, the West Virginia Air Pollution Control Commission
approved  the construction of a third-party cogeneration facility
in  the  vicinity of Rivesville, West Virginia.  Emissions impact
modeling  for that facility raised concerns about the  compliance
of  Monongahela's Rivesville Station with ambient  standards  for
SO2.   Pursuant to a consent order, Monongahela agreed to collect
on-site  meteorological  data and conduct  additional  dispersion
modeling in order to demonstrate compliance.  The modeling  study
and  a  compliance strategy recommending construction  of  a  new
"good  engineering practices" (GEP) stack were submitted  to  the
West  Virginia Department of Environmental Protection (WVDEP)  in
June 1993.  Costs associated with the GEP stack are approximately
$20 million.  Monongahela is awaiting action by the WVDEP.

      Under an EPA-approved consent order with Pennsylvania, West
Penn completed construction of a GEP stack at the Armstrong Power
Station  in  1982  at a cost of more than $13  million  with  the
expectation that  EPA's  reclassification  of Armstrong County to
"attainment  status"  under NAAQS for SO2  would  follow.   As  a
result  of  the  1985  revision of its stack  height  rules,  EPA
refused   to   reclassify   the  area   to   attainment   status.
Subsequently,  West Penn filed an appeal with the U.S.  Court  of
Appeals for the Third Circuit for review of that decision as well
as  a  petition for reconsideration with EPA.  In 1988, the Court
dismissed  West  Penn's appeal, stating it could not  decide  the
case while West Penn's request for reconsideration before EPA was
pending.    West  Penn  cannot  predict  the  outcome   of   this
proceeding.

      In  March  1998,  the EPA released its Utility  Air  Toxics
Report  to  Congress.   The  report  itself  does  not  recommend
regulatory  controls.  However, the EPA is  expected  to  make  a
recommendation on regulatory controls by December 2000.  The  EPA
has  identified  mercury emissions as requiring further  research
and  monitoring  because  of  the potential  concern  for  public
health.   While  it  appears that EPA wants  to  control  utility
mercury


<PAGE>

                               35

emissions,   it   currently   lacks   the    technical
justification.  In late November 1998, the EPA issued  a  mercury
data  collection request that requires utilities  to  sample  and
analyze coal shipments for mercury and chlorine throughout  1999.
In addition, some plants may be required to conduct stack testing
to  determine the effectiveness of existing particulate  and  SO2
control equipment in the reduction of mercury emissions.


                         Water Standards

      Under  the National Pollutant Discharge Elimination  System
(NPDES),  permits  for all of Allegheny's stations  and  disposal
sites  are in place.  However, NPDES permit renewals for  several
West  Virginia  and  Pennsylvania  disposal  sites  contain  what
Allegheny  believes  are overly stringent discharge  limitations.
Allegheny, in cooperation with the states and EPA, has  developed
alternate  water  quality  criteria which,  if  approved  by  the
agencies, will result in less stringent permit limits.  If  their
criteria  are not approved, installation of wastewater  treatment
facilities may become necessary.  The cost of such facilities, if
required, cannot be predicted at this time.

      As the result of a lawsuit by environmental groups, the EPA
and  WVDEP,  on  October 27, 1997, proposed total  maximum  daily
loads  (TMDLs)  for the Blackwater River and South  Fork  of  the
Potomac River and five of its tributaries.  This is the first  of
44  court-ordered waste load allocations for West Virginia to  be
issued  over six years which will, when implemented,  reduce  the
amount  of pollutants that can be discharged into rivers that  do
not  meet  water  quality standards.  The final  Blackwater  TMDL
allows the existing waste loads to continue but eliminates unused
waste  load  allocations,  including those  owned  by  Allegheny,
thereby  precluding further development in the area.  Because  of
the  precedent  setting nature of the Blackwater TMDL,  Allegheny
and  others  have  challenged the TMDL before the  West  Virginia
Environmental  Quality  Board.  Environmental  groups  have  also
filed   lawsuits   in   a  number  of  other  states,   including
Pennsylvania and Maryland, which will, when settled, force  these
states  and the EPA to develop and implement wastewater discharge
restrictions.  The direct result of these actions will be further
reductions in the amount of pollutants that can be discharged  by
certain company-owned power stations which are located on  rivers
whose  water  quality does not meet standards.   Indirectly,  the
TMDL  process  can  adversely affect  the  region's  economy  and
therefore  the  financial performance of  Allegheny  by  limiting
economic development and curtailing the wastewater discharges  of
existing  industrial  customers  in  certain  areas.   The  total
implications of the pending waste load allocations  will  not  be
known  until the agencies develop and implement TMDLs in specific
watersheds.

      The  Pennsylvania Land Recycling Act, adopted in 1996,  and
the  West Virginia Voluntary Cleanup Act, adopted in 1997,  allow
for  the development and application of site-specific, risk-based
groundwater  cleanup  standards  to  both  abandoned  and  active
industrial  sites.   The  intent is to  encourage  the  reuse  of
abandoned  but  contaminated industrial sites and  to  allow  for
continual  operation  of industrial sites whose  operation  began
before  groundwater protection statutes were in place -- as  long
as  it  can be demonstrated by the owner/operator that  there  is
little  or  no  risk  to  human


<PAGE>

                              36

health or  the  environment.  The
implementing  regulations  provide  for  reasonable   and   cost-
effective  groundwater cleanup of Allegheny facilities should  it
become  necessary  and  will encourage  economic  development  in
Allegheny's   service  territories  in  Pennsylvania   and   West
Virginia.


                   Hazardous and Solid Wastes

      Pursuant to the Resource Conservation and Recovery  Act  of
1976   (RCRA)  and  the  Hazardous  and  Solid  Waste  Management
Amendments  of 1984, the EPA regulates the disposal of  hazardous
and   solid   waste  materials.   Maryland,  Ohio,  Pennsylvania,
Virginia, and West Virginia have also enacted hazardous and solid
waste  management regulations that are as stringent  as  or  more
stringent than the corresponding EPA regulations.

     Allegheny is in a continual process of either permitting new
or  re-permitting  existing  disposal  capacity  to  meet  future
disposal needs.  All disposal areas are currently operated to  be
in compliance with their permits.

     Allegheny continues to actively pursue, with PADEP and WVDEP
encouragement,  ash  utilization  projects  such  as  deep   mine
injection   for   subsidence  and  water   quality   improvement,
structural fills for highway and building construction, and  soil
enhancement   for  surface  mine  reclamation.    The   Operating
Subsidiaries  will  break ground in early  1999  to  construct  a
processing  plant which will convert the Pleasants Power  Station
flue  gas  desulfurization by-product  into  a  commercial  grade
synthetic gypsum for use in manufacturing wallboard.

       Potomac   Edison  received  a  notice  from  the  Maryland
Department   of  the  Environment  (MDE)  in  1990  regarding   a
remediation  ordered under Maryland law at a facility  previously
owned  by Potomac Edison.  The MDE has identified Potomac  Edison
as   a   potentially  responsible  party  under   Maryland   law.
Remediation  is  being implemented by the current  owner  of  the
facility  which  is located in Frederick.  It is not  anticipated
that Potomac Edison's share of remediation costs, if any, will be
substantial.

      The  Operating  Subsidiaries are  also  among  a  group  of
potentially   responsible   parties   under   the   Comprehensive
Environmental Response, Compensation and Liability Act  of  1980,
as   amended  (CERCLA),  for  the  Jack's  Creek/Sitkin  Smelting
Superfund   Site  and  the  Butler  Tunnel  Superfund   Site   in
Pennsylvania.   (See ITEM 3. LEGAL PROCEEDINGS for a  description
of these Superfund cases.)


                  Toxic Release Inventory (TRI)

     On Earth Day 1997, President Clinton announced the expansion
of  TRI to include electric utilities, limited to facilities that
combust  coal and/or oil for the purpose of generating power  for
distribution in commerce.  The purpose of TRI is to provide site-
specific  information on chemical releases to the air, land,  and
water.  The first TRI report is due on July 1, 1999, for calendar
year 1998.  The reports will be filed with EPA and made available
through  publication of the reported information and  posting  on
the


<PAGE>

                                  37

 Internet.  Allegheny is actively working on a communications
plan  to proactively educate employees and the community  on  the
TRI  program and the amounts of reportable chemicals released  by
Allegheny.


                      Global Climate Change

       Climate  change  is  alleged  to  be  the  result  of  the
atmospheric  accumulation of certain gases collectively  referred
to as GHG, the most significant of which is carbon dioxide (CO2).
Human  activities,  including combustion  of  fossil  fuels,  are
alleged  to  be responsible for this accumulation  of  GHG.   The
Clinton Administration has signed an international treaty  called
the  Kyoto  Protocol,  which  will require  the  U.S.  to  reduce
emissions  of  GHG by 7% from 1990 levels in the  2008-2012  time
period.  The U.S. Senate must ratify the Kyoto Protocol before it
enters  into force, as must other nations subject to the treaty's
provisions.  The Senate passed a resolution in 1997 (S.R. 98)  by
a  vote  of 95-0 that placed two conditions on entering into  any
international  climate  change treaty.  First,  any  treaty  must
include  all  nations,  and, second, any treaty  must  not  cause
serious  harm to the U.S. economy.  The Kyoto Protocol  does  not
appear to satisfy either of these conditions and, therefore,  the
Clinton Administration has withheld it from consideration by  the
Senate.   Because coal combustion in power plants produces  about
33%  of  U.S. CO2 emissions, implementation of the Kyoto Protocol
would  raise considerable uncertainty about the future  viability
of coal as a fuel source for new and existing power plants.

      If  and when the need for reducing greenhouse gas emissions
has  been  identified  and  scientifically  supported,  Allegheny
believes  that a global solution involving all nations  and  must
give  credit  for  preventive actions taken.  Allegheny  believes
precipitous and urgent action under strict limits and  timetables
will  result in severe economic dislocation and is not warranted.
Allegheny  does believe that appropriate results can be  achieved
domestically by continuing to build upon the notable progress  of
existing voluntary programs.

      For  these  reasons, Allegheny actively participates  in  a
number of groups to address this environmental matter.  Allegheny
supports  research on the climate change issue through  EPRI  and
participates  in  a  number of organizations  to  help  influence
policy   matters  at  the  domestic  and  international   levels.
Allegheny  has  also  undertaken  a  program  to  identify  cost-
effective and voluntary measures that reduce emissions of GHG  in
all  areas  of its business and in other areas, such as forestry,
international projects, and emissions trading.

      The  Operating  Subsidiaries maintain  an  active  climate-
related research program and are responsive to the greenhouse gas
guidelines suggested in the 1992 National Energy Policy Act. As a
result, the Operating Subsidiaries have voluntarily reduced their
total  annual emissions of GHG by 1,090,501, as described in  the
latest filing with the Department of Energy.

      The Operating Subsidiaries support EPRI which funds climate
research targets at around $7 to $10 million per year and  Edison
Electric  Institute's  Climate  Challenge  Initiative  funded  at
$100,000 per-year; and have committed


<PAGE>

                              38

to invest $3.11 million  in an electrotechnology and renewable
energy venture capital fund.

      The  Operating Subsidiaries' in-house research program  has
contributed   to   applications  of  new  technology,   operating
efficiencies,  reduced electrical losses and  pollution  emission
reductions.

      West  Penn recently settled a restructuring plan  with  the
Pennsylvania  PUC  that included five important  climate  related
issues:  1)  Renewable Energy Development, 2) Sustainable  Energy
Fund ($11,425,721 paid on December 31, 1998), 3) Renewable Energy
Pilot   Program  ($300,000  each  year),  4)  Energy  Cooperative
Association of Pennsylvania (contribution of $4 million)  and  5)
Universal Service and Energy Conservation Program ($8.082 million
per year).

      In response to environmental issues over the past 18 years,
the  Operating  Subsidiaries spent over $1.6 billion  in  capital
expenditures   and   approximately  $200  million   annually   in
operations  and  maintenance and are committed  to  environmental
stewardship  and  the  research  needed  to  provide  answers  to
difficult  compliance problems.  These actions will mitigate  the
impact   of  the  Operating  Subsidiaries'  operations   on   the
environment and ameliorate the global warming problem.


                           REGULATION

      Allegheny is subject to the broad jurisdiction of  the  SEC
under  PUHCA.   The Regulated Subsidiaries are  regulated  as  to
substantially  all of their operations by regulatory  commissions
in the states in which they operate.  The Regulated Subsidiaries,
West  Penn's  unregulated generation, and  AYP  Energy  are  also
regulated  as to various aspects of their business by  the  FERC.
In addition, they are subject to numerous other local, state, and
federal laws, regulations, and rules.

     In June 1995, the SEC published its report which recommended
changes  to  PUHCA,  including a recommendation  to  Congress  to
repeal  the  entire  act.   Bills have  been  introduced  in  the
Congress to repeal PUHCA, but have not passed.  Allegheny  cannot
predict  what changes, if any, will be made to PUHCA as a  result
of these activities.

      In  1998, the Operating Subsidiaries continued to take part
in  and  fund  various  programs to assist low-income  customers,
customers  with  special  needs,  and/or  customers  experiencing
temporary financial hardship.


                            YEAR 2000

      Year 2000 (Y2K) readiness is a top priority.  Allegheny has
an  Executive  Task  Force,  led by a  Vice  President,  that  is
coordinating the efforts of 24 individual Y2K teams, representing
all  business  and  support units in Allegheny.   The  teams  are
actively  working  to  investigate, evaluate,  and  mitigate  all
critical Y2K concerns.


<PAGE>

                              39

      The  teams  have completed their inventory of all  critical
elements  (computer  hardware and software,  embedded  chips  and
vendors)  that  may be affected by Y2K and are  well  into  their
remediation,   testing,   and   contingency   planning   efforts.
Allegheny's goal is to have most mission critical components  and
systems Y2K-ready by the first quarter of 1999, and  all  of them
ready by mid-year.

      Allegheny's Y2K teams are involved in contingency  planning
and  are  working  with  other utilities,  customers,  government
agencies,  financial  institutions,  suppliers,  and  vendors  to
achieve  a  cooperative and thorough effort.  Allegheny  believes
its  critical  equipment will be ready for  the  Year  2000,  but
Allegheny  must prepare for any contingency.  In 1999,  Allegheny
will participate in two nationwide testing drills.



ITEM 2.   PROPERTIES

      Substantially  all  of  the  properties  of  the  Operating
Subsidiaries  are  held  subject to the  lien  of  the  indenture
securing each Operating Subsidiary's first mortgage bonds and, in
many  cases, subject to certain reservations, minor encumbrances,
and  title  defects which do not materially interfere with  their
use.   Some  of the Operating Subsidiaries' properties  are  also
subject  to  a second lien securing certain solid waste  disposal
and  pollution  control notes.  The indenture under  which  AGC's
unsecured  debentures and medium-term notes are issued  prohibits
AGC,   with   certain  limited  exceptions,  from  incurring   or
permitting  liens  to  exist on any of its properties  or  assets
unless the debentures and medium-term notes are contemporaneously
secured  equally and ratably with all other indebtedness  secured
by   such   lien.   Transmission  and  distribution   lines,   in
substantial  part, some substations and switching  stations,  and
some  ancillary  facilities at power stations  are  on  lands  of
others,  in  some  cases  by sufferance, but  in  most  instances
pursuant  to leases, easements, rights-of-way, permits  or  other
arrangements, many of which have not been recorded  and  some  of
which  are  not  evidenced by formal grants.  In some  cases,  no
examination  of  titles  has  been made  as  to  lands  on  which
transmission and distribution lines and substations are  located.
Each of the Operating Subsidiaries possesses the power of eminent
domain with respect to its public utility operations.  (See  also
ITEM 1. BUSINESS and ALLEGHENY MAP.)


ITEM 3.   LEGAL PROCEEDINGS

     In a letter to AE dated October 5, 1998, DQE stated that it
had decided to unilaterally terminate the merger.  In response,
on October 5, 1998, AE filed a lawsuit in the United States
District Court for the Western District of Pennsylvania against
DQE for specific performance of the Merger Agreement or, in the
alternative, for damages.  AE also filed motions for a temporary
restraining order and preliminary injunction against DQE.  On
October 28, 1998, the court denied AE's motions for a temporary
restraining order and preliminary injunction.  On October 30,
1998, AE appealed the District Court's order to the United States
Court of Appeals for the Third Circuit.  On March 11, 1999, the
U.S. Court of Appeals for the Third Circuit vacated the district
court's denial of Allegheny's motion for preliminary injunction,
enjoining DQE from taking actions prohibited by the merger
agreement.  The Circuit Court stated that if DQE breached the
Merger Agreement, AE would be entitled to


<PAGE>

                                 40


specific performance of the Merger Agreement.  The Circuit
Court also stated that AE would be irreparably harmed if
DQE took actions that would prevent AE from receiving the
specific performance remedy.  The Circuit Court remanded
the case to the District Court for further proceedings
consistent with its opinion.

     In the District Court, discovery is ongoing, and AE cannot
predict the outcome of this litigation.  However, AE believes
that DQE's basis for seeking to terminate the merger is without
merit.  Accordingly, AE continues to seek the remaining
regulatory approvals from the Department of Justice and the
Securities and Exchange Commission.  It is not likely either
agency will act on the requests unless AE obtains judicial relief
requiring DQE to move forward.

      On  September  29,  1997, the City of Pittsburgh  filed  an
antitrust  and  conspiracy lawsuit in the Federal District  Court
for  the Western District of Pennsylvania against AE, West  Penn,
DQE,  and Duquesne.  The complaint alleged eight counts,  two  of
which  were claimed violations of the antitrust statutes and  six
were state law claims.  The relief sought included a request that
the  proposed merger between AE and DQE be stopped, and requested
unspecified  monetary  damages  relating  to  alleged   collusion
between the two companies in their actions dealing with proposals
to  provide electric service to redevelopment zones in the  city.
On  October 27, 1997, all defendants filed motions to dismiss the
complaint.   On  January 6, 1998, the District  Court  issued  an
order which granted the motions to dismiss.  On January 14, 1998,
the City appealed the order to the United States Court of Appeals
for  the  Third  Circuit.  On June 12, 1998,  the  Third  Circuit
upheld  the District Court's order.  This matter was subsequently
settled.

      On September 7, 1995, MidAtlantic Energy (MidAtlantic) sued
Monongahela,  Potomac Edison, and AE in state court  in  Marshall
County,  W.Va., alleging failure to comply with PURPA regulations
in refusing to purchase capacity and energy from a proposed PURPA
project  and  interference with MidAtlantic's contract  with  the
Babcock  and Wilcox Company (B and W), among other things.   This
suit followed an unsuccessful complaint proceeding by MidAtlantic
requesting the West Virginia PSC to order Monongahela and Potomac
Edison  to  purchase capacity and energy from the  project.   The
MidAtlantic  suit also named B and W as a defendant.  MidAtlantic
seeks  compensatory and punitive damages.   Monongahela,  Potomac
Edison,  and AE filed an answer and B and W filed an  answer  and
counterclaim.  Monongahela, Potomac Edison, and AE cannot predict
the outcome of this litigation.

      On  August  13,  1996, American Bituminous Partners,  L.P.,
(AmBit), filed a request for arbitration alleging that the energy
rate  payable under its purchase power contract with  Monongahela
had  been improperly calculated.  The arbitration proceeding  was
bifurcated  into a liability phase and, if necessary,  a  damages
phase.   A  hearing  in the liability phase  of  the  arbitration
proceeding has been completed and briefed.  On February 18, 1998,
the  arbitration  panel  made a determination  in  the  liability
phase.   They determined that certain lime handling costs  should
have  been  a  component of the energy rate  and  therefore  were
improperly accounted for in 1995 and 1996.  The damages phase  of
the arbitration on this issue will be limited to determination of
the  extent  of  these costs and any related lime handling


<PAGE>

                               41

costs that AmBit can show should have been included in the calculation
of  the  energy rate.  Monongahela cannot predict the outcome  of
this proceeding.

      As  of  January 19, 1999, Monongahela has been named  as  a
defendant  along with multiple other defendants  in  a  total  of
7,680  pending  asbestos cases involving one or more  plaintiffs.
Potomac Edison and West Penn have been named as defendants  along
with multiple other defendants in approximately one-half of those
cases.   Because  these cases are filed in  a  "shot-gun"  format
whereby   multiple   plaintiffs  file  claims  against   multiple
defendants  in  the  same  case, it is  presently  impossible  to
determine  the  actual number of cases in which  plaintiffs  make
claims  against the Operating Subsidiaries.  However, based  upon
past  experience and available data, it is estimated  that  about
one-third  of  the  total number of cases filed actually  involve
claims  against  any or all of the Operating  Subsidiaries.   All
complaints  allege  that  the  plaintiffs  sustained  unspecified
injuries  resulting from claimed exposure to asbestos in  various
generating plants and other industrial facilities operated by the
various defendants, although all plaintiffs do not claim exposure
at   facilities  operated  by  all  defendants.   With  very  few
exceptions, plaintiffs claiming exposure at stations operated  by
the   Operating   Subsidiaries  were  employed   by   third-party
contractors,  not  the Operating Subsidiaries.  Three  plaintiffs
are   known   to  be  either  present  or  former  employees   of
Monongahela.  Each  plaintiff generally  seeks  compensatory  and
punitive  damages against all defendants in amounts of up  to  $1
million  and  $3  million, respectively;  in  those  cases  which
include  a  spousal  claim  for loss of consortium,  damages  are
generally sought against all defendants in an amount of up to  an
additional  $1 million.  A total of 94 cases have been previously
settled  and/or  dismissed  against  Monongahela  for  an  amount
substantially  less than the anticipated cost of defense.   While
the  Operating  Subsidiaries believe that all of  the  cases  are
without merit, they cannot predict the outcome nor are they  able
to determine whether additional cases will be filed.

      On January 27, 1995, Allegheny filed a declaratory judgment
action in the Court of Common Pleas of Westmoreland County,  Pa.,
against  its  historic  comprehensive  general  liability   (CGL)
insurers.   This suit seeks a declaration that the  CGL  insurers
have a duty to defend and indemnify the Operating Subsidiaries in
the  asbestos cases, as well as in certain environmental actions.
To  date, two insurers have settled.  However, the final  outcome
of this proceeding cannot be predicted.

     On March 4, 1994, the Operating Subsidiaries received notice
that  the  EPA  had  identified them as  potentially  responsible
parties  (PRPs)  under the Comprehensive Environmental  Response,
Compensation and Liability Act of 1980, as amended, with  respect
to the Jack's Creek/Sitkin Smelting Superfund Site (Site).  There
are   approximately   175  other  PRPs  involved.    A   Remedial
Investigation/Feasibility  Study  (RI/FS)  prepared  by  the  EPA
originally indicated remedial alternatives which ranged  as  high
as  $113 million, to be shared by all responsible parties.  A PRP
Group  consisting of approximately 40 members, and to  which  the
Operating  Subsidiaries belong, has been formed and has submitted
an  addendum  to  the  RI/FS which proposes a substantially  less
expensive  cleanup remedy.  In January 1998, this PRP  Group  has
made  a  good-faith offer to the EPA to settle  this  matter.   A
final   determination  has  not  been  made  for  the   Operating
Subsidiaries' share of the remediation costs


<PAGE>

                              42

based on the  amount of  materials  sent to the site.  However, at
this  time  it  is estimated  that  the  effect  on the  Operating
Subsidiaries will  not be material.

      Potomac Edison received a questionnaire on October 1, 1996,
from  the  EPA  concerning  a release or  threat  of  release  of
hazardous  substances,  pollutants,  or  contaminants  into   the
environment at the Butler Tunnel Site located in Luzerne  County,
Pa.   Potomac Edison notified the EPA that it has no  records  or
recollection of any business relations with the site  or  any  of
the  companies  identified  in  the  questionnaire.   It  is  not
possible  to  determine at this time what effect,  if  any,  this
matter may have on Potomac Edison.

       After   protracted  litigation  concerning  the  Operating
Subsidiaries'  application  for a license  to  build  a  1,000-MW
energy-storage  facility near Davis, W.Va.,  in  1988,  the  U.S.
District Court reversed the U.S. Army Corps of Engineers' (Corps)
denial  of  a  dredge and fill permit on the grounds that,  among
other   things,  the  Operating  Subsidiaries  were   denied   an
opportunity  to  review  and comment upon written  materials  and
other  communications used by the Corps in reaching its decision.
As  a  result,  the Court remanded the matter to  the  Corps  for
further  proceedings.  This remand order has been appealed.   The
Operating  Subsidiaries  cannot  predict  the  outcome  of   this
proceeding.

      In  1979, National Steel Corporation (National Steel) filed
suit against AE and certain subsidiaries in the Circuit Court  of
Hancock  County,  W.Va., alleging damages of  approximately  $7.9
million  as a result of an order issued by the West Virginia  PSC
requiring  curtailment of National Steel's use of electric  power
during the United Mine Workers' strike of 1977-8.  A jury verdict
in  favor  of AE and the subsidiaries was rendered in June  1991.
National Steel has filed a motion for a new trial, which is still
pending  before the Circuit Court of Hancock County.  AE and  the
subsidiaries  believe the motion is without merit; however,  they
cannot predict the outcome of this case.



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

      AE, Monongahela, Potomac Edison, West Penn, and AGC did not
submit  any  matters to a vote of shareholders during the  fourth
quarter of 1998.


<PAGE>

                               43

              Executive Officers of the Registrants


The  names of the executive officers of each company, their  ages
as  of December 31, 1998, the positions they hold, or held during
1998,  and  their business experience during the past five  years
appears below:

<TABLE>
<CAPTION>

                                              Position  (a)  and  Period  of Service
       Name                 Age       AE             MP          PE           WP          AGC


<S>                          <C>   <C>            <C>          <C>          <C>         <C>
Charles S. Ault              60                                             V.P.
                                                                            (1990-    )


Eileen   M.  Beck            57    Secretary      Secretary    Secretary    Secretary   Secretary
                                   (1988-    )    (1995-    )  (1996-)      (1996-    ) (1982-    )
                                   Previously     Previously,  Previously   Previously
                                   Asst.  Treas.  Asst. Treas. Asst.Sec.    Asst. Sec.
                                   (1979-95)      (1981-95)    (1988-95)    (1988-95)
                                                  Asst. Sec.
                                                  (1988-94)


Regis  F. Binder(b)          46    V.P. & Treas.  Treas.       Treas.       Treas.       Treas.
                                   (12/98-    )   (12/98-    ) (12/98-      (12/98-    ) (2/99-    )



Nancy L.Campbell(c)          59    V.P.           Treasurer    Treasurer    Treasurer    Treasurer
                                   (1994-12/98)   (1995-12/98) (1996-12/98) (1996-12/98) (1988-12/98)
                                   & Treas.                    Previously,               Previously,
                                   (1988-12/98)                Asst.Sec.                 Asst. Sec.
                                                               (1988-96)                 (1988-96)
                                                               Asst. Treas.
                                                               (1988-95)


C. Vernon Estel, Jr.(d)      43                   V.P.
                                                  (1996-10/98)

Richard  J.  Gagliardi       48     V.P.          Asst.   Sec.                            Asst.
                                    (1991-    )   (1990-96)                               Treas.
                                                                                         (1982-96)



James R. Haney(e)            42                   V.P.         V.P.          V.P.
                                                  (1998-    )  (1998-    )   (1998-    )


Thomas  K.  Henderson        58      V.P.         V.P.         V.P.          V.P.         Dir.& V.P.
                                     (1997-    )  (1995-    )  (1995-)       (1985-    )  (1996-    )


Kenneth M. Jones             61      V.P.                                   Dir.& V.P.
                                     (1991-    )                            (1991-2/99)
                                     Previously,
                                     Controllor.
                                     (1991-1998)


Thomas  J.  Kloc             46      V.P. &       Controller   Controller    Controller   Dir.& V.P.
                                     Controlle r  (1996-    )  (1988-   )    (1995-    )  (2/99-    )
                                     (1998-     )                                         Controller
                                                                                          (1988-    )
</TABLE>

<PAGE>

                               44

         Executive Officers of the Registrants, cont'd.

The  names of the executive officers of each company, their  ages
as  of December 31, 1998, the positions they hold, or held during
1998,  and  their business experience during the past five  years
appears below:

<TABLE>
<CAPTION>

                                   Position  (a)  and  Period  of Service
       Name                 Age       AE            MP          PE           WP          AGC


<S>                          <C>    <C>           <C>         <C>           <C>          <C>
James D. Latimer             60                   V.P.        V.P.          V.P.
                                                  (1995-    ) (1995-    )   (1995-    )
                                                              Previously,
                                                              Executive V.P.
                                                              (1994-95)
                                                              V.P.
                                                              (1988-94)


Michael P. Morrell(f)        50      Sr. V.P.     Dir & V.P.   Dir.& V.P.   Dir. & V.P.  Dir.& V.P.
                                     (1996-    )  (1996-    )  (1996-    )  (1996-    )  (1996-   )


Alan J. Noia                 51      Chairman     Chairman     Chairman     Chairman     Chairman,
                                     &   CEO      &  CEO       &  CEO       &   CEO      Pres.& CEO
                                     (1996-    )  (1996-    )  (1996-    )  (1996-    )  (1996-    )
                                     Pres.& Dir.  Dir.         Dir.         Dir.         Dir.& V.P.
                                     (1994-    )  (1994-    )  (1990-)      (1994-    )  (1994-96)
                                     Previously,               Previously,
                                     COO                       Pres.
                                     (1994-96)                 (1990-94)


Karl V. Pfirrmann            50                    V.P.        V.P.          V.P.
                                                   (1996-8/98) (1996-8/98)   (1996-8/98)


Jay  S.  Pifer               61      Sr.  V.P.     Pres.&Dir.  Pres.&Dir.    Pres.
                                     (1996-    )   1995-   )   (1995-    )   (1990-    )
                                                                             & Dir.
                                                                             (1992-    )


Victoria V. Schaff(g)        54      V.P.
                                     (1997-    )


Peter J. Skrgic              57      Sr. V.P.      V.P.        V.P.& Dir.    V.P.        V.P.& Dir.
                                     (1994-     )  (1996-    ) (1990-    )   (1996-    ) (1989-    )
                                     Previously,   & Dir.                    & Dir.
                                     V.P.          (1990-    )               (1990-    )
                                     (1989-94)


Robert R. Winter             55                    V.P.        V.P.          V.P.
                                                   (1987-    ) (1995-    )   (1995-    )

</TABLE>



(a)  All officers and directors are elected annually.
(b)  Prior to his appointment as Vice President and Treasurer  of
     AE and Treasurer of MP, PE, WPP, and AGC, Mr. Binder was
     Executive Director, Regulation and Rates for APSC (1997-1998);
     General Manager, Industrial Marketing for APSC (1996-1997);
     Director, Rates for  APSC (1995-1996); and Assisant Director
     Rates for APSC (1993-1995).
(c)  Ms. Campbell retired effective December 1, 1998.
(d)  Prior  to his appointment as Vice President, Mr. Estel  was
     Director, Communications (12/95-4/96),  Asst. Director
     Communications (10/95-12/95), Director, Human Resources
     (1/95-10/95) and Director, Personnel 12/90-1/95).  Mr. Estel
     resigned as a Vice President in October 1998.


<PAGE>

                               45


(e)  Prior  to  his  appointment  as  Vice  President  Customer
     Operations, Mr. Haney was Executive Director,  Operating
     Business Unit (8/98-10/98);  Director, Operations Services
     (5/96-8/98); Director,  Transmission  Projects  (12/95-5/96);
     Manager, Construction (APSC) (2/95-12/95); and Division Manager,
     Monongahela (12/90-2/95).

(f)  Prior  to  joining Allegheny, Mr. Morrell  was  V.P. - Regulatory
     and Public Affairs, Jersey Central Power & Light Company (JCP&L)
     (8/94-4/96); V.P. - Materials Services and Regulatory  Affairs,
     JCP&L (1/93-8/94);  and  V.P.  and Treasurer, GPU, Inc. and
     Subsidiaries (2/86-1/93).

(g)  Prior to joining Allegheny, Ms. Schaff was a Federal
     Affairs Representative with the Union Electric Company
     (4/88-12/95).


                             PART II

ITEM 5.   MARKET FOR THE REGISTRANTS' COMMON EQUITY
          AND RELATED STOCKHOLDER MATTERS

     AE

     AYE is the trading symbol of the common stock of AE on  the
New York, Chicago, and Pacific Stock Exchanges. The stock is also
traded  on the Amsterdam (Netherlands) and other stock exchanges.
As  of December 31, 1998, there were 48,869 holders of record  of
AE's common stock.

      The  tables below show the dividends paid and the high  and
low sale prices of the common stock for the periods indicated:

                            1998                          1997
                  Dividend  High      Low       Dividend  High      Low
1st Quarter       43 cents  $33-9/16  $30-1/8   43 cents  $31-5/8   $29-1/8
2nd Quarter       43 cents  34        $27-5/16  43 cents  $30-1/8   $25-1/2
3rd Quarter       43 cents  31-15/16  $26-5/8   43 cents  $30-3/8   $26-5/8
4th  Quarter      43 cents  34-15/16  $29-1/2   43 cents  $32-19/32 $27-1/4

      The  high and low prices through March 4, 1999 were $34-l/2
and $28-11/16.  The last reported sale on that date was at $31-5/16.

     Monongahela, Potomac Edison, and West Penn.  The information
required  by this Item is not applicable as all the common  stock
of the Operating Subsidiaries is held by AE.

       AGC.   The  information  required  by  this  Item  is  not
applicable as all the common stock of AGC is held by Monongahela,
Potomac Edison, and West Penn.


<PAGE>

                               46

ITEM 6. SELECTED FINANCIAL DATA

                                Page No.

AE                                D- 1

Monongahela                       D- 4

Potomac Edison                    D- 6

West Penn                         D- 8

AGC                               D-10


<PAGE>

                                                        Allegheny Energy, Inc.

Condensed Financial Statements

<TABLE>
<CAPTION>

                                          Monongahela    The Potomac    West Penn         Allegheny
                                          Power          Edison         Power Company     Energy, Inc.
Year ended December 31, 1998              Company        Company        and Subsidiaries  and Subsidiaries
(Thousands of Dollars)

<S>                                       <C>            <C>              <C>              <C>
Balance Sheets
Assets
Property, plant, and equipment:
At original cost*                         $2,007,876     $2,249,716      $3,365,784        $8,629,733
Accumulated depreciation                    (883,915)      (926,840)     (1,362,413)       (3,395,603)
                                           1,123,961      1,322,876       2,003,371         5,234,130

Investments in subsidiaries-excess of cost
  over book equity at acquisition                                                              15,077
Cash and temporary cash investments            1,835          1,805           4,523            17,559
Other current assets                         155,776        221,150         245,704           537,524
Regulatory assets                            154,882         66,792         475,776           704,506
Other                                         82,574         89,504         113,695           238,997
          Total                           $1,519,028     $1,702,127      $2,843,069        $6,747,793
*Includes construction work in progress   $   43,657     $   46,353      $   75,725        $  166,330

Capitalization and Liabilities
Common stock, other paid-in capital,
  and retained earnings                   $  570,188     $  762,912       $  732,161       $2,033,889
Preferred stock                               74,000         16,378           79,708          170,086
Long-term debt and QUIDS                     453,917        578,817          837,725        2,179,288
Short-term debt                               49,000                          65,066          258,837
Other current liabilities                     77,561        119,209          235,785          436,375
Unamortized investment credit                 16,155         19,592           42,630          125,396
Deferred income taxes                        242,805        170,349          260,477          842,193
Regulatory liabilities                        15,476         11,233           28,325           80,354
Adverse power purchase commitments                                           538,745          538,745
Other                                         19,926         23,637           22,447           82,630
Total                                     $1,519,028     $1,702,127       $2,843,069       $6,747,793

Statements of Income
Operating revenues                        $  645,122     $  737,494       $1,078,727       $2,576,436
Operating expenses                           533,636        598,698          912,195        2,136,929
Operating income                             111,486        138,796          166,532          439,507
Other income and deductions                    6,425          9,894           11,906            9,733

Income before interest charges, preferred
  dividends, and extraordinary charge, net   117,911        148,690          178,438          449,240
Interest charges and preferred dividends      40,523         48,026           69,214          186,232

Balance for common stock before extraordinary
 charge, net                                  77,388        100,664          109,224          263,008
Extraordinary charge, net                                                   (275,426)        (275,426)
Balance for common stock                  $   77,388     $  100,664       $ (166,202)      $  (12,418)

</TABLE>

                                D-1

<PAGE>

                                                       Allegheny Energy, Inc.

<TABLE>
<CAPTION>

Consolidated Statistics

Year ended December 31               1998           1997          1996          1995          1994       1993       1988

Summary of Operations (Millions of Dollars)

<S>                                  <C>           <C>           <C>           <C>         <C>         <C>         <C>
Operating revenues                   $2,576.4      $2,369.5      $2,327.6      $2,315.2    $2,184.6    $2,050.6    $1,852.6
Operation expense                     1,286.0       1,065.9       1,013.0       1,024.9     1,017.8       927.5       938.5
Maintenance                             217.5         230.6         243.          249.5       241.9       231.2       166.6
Restructuring charges and asset
  write-offs                                                        103.9          23.4         9.2
Depreciation                            270.4         265.7         263.2         256.3       223.9       210.4       165.7
Taxes other than income                 194.6         187.0         185.4         184.7       183.1       178.8       127.5
Taxes on income                         168.4         168.1         128.0         154.2       125.9       128.1       103.7
Allowance for funds used
  during construction                    (5.0)         (8.3)         (5.9)         (8.2)      (19.6)      (21.5)       (4.3)
Interest charges and
  preferred dividends                   189.7         197.2         191.1         196.9       184.1       180.3       155.1
Other income and deductions              (8.2)        (18.0)         (4.4)         (6.2)       (1.5)                   (5.3)
Consolidated income before extraordinary
  charge and cumulative effect of
  accounting change                     263.0         281.3         210.0         239.7       219.8       215.8       205.1
Extraordinary charge, net<a>           (275.4)
Cumulative effect of accounting change,
  Net<b>                                                                                       43.4
Consolidated net (loss) income       $  (12.4)     $  281.3      $  210.0       $ 239.7    $  263.2      $215.8     $ 205.1
Common Stock Data<C>
Shares outstanding (Thousands)        122,436       122,436       121,840       120,701     119,293     117,664     104,268
Average shares outstanding 
                   (Thousands)        122,436       122,208       121,141       119,864     118,272     114,937     103,460
Earnings per average share:<d>
  Consolidated income before extraordinary
   charge and cumulative effect of
   accounting change                 $   2.15      $   2.30      $   1.73       $  2.00    $   1.86    $   1.88    $   1.98
  Extraordinary charge, net<a>          (2.25)
  Cumulative effect of accounting 
    change<b>                                                                                   .37
  Consolidated net (loss) income     $   (.10)     $   2.30      $   1.73       $  2.00    $   2.23    $   1.88    $   1.98
Dividends paid per share             $   1.72      $   1.72      $   1.69       $  1.65    $   1.64    $   1.63    $   1.51
Dividend payout ratio<e>                 73.5%         74.7%         97.5%         82.5%       88.3%       86.9%       76.2%
Shareholders                           48,869        53,389        58,677        63,280      66,818      63,396      71,748
Market price per share:
  High                               $ 34-15/16    $ 32-19/32    $ 31-1/8       $ 29-1/4   $ 26-1/2   $ 28-7/16  $ 20-3/4
  Low                                $ 26-5/8      $ 25-1/2      $ 28             21-1/2   $ 19-3/4   $ 23-7/16  $ 17-15/16
  Close                              $ 34-1/2      $ 32-1/2      $ 30-3/8       $ 28-5/8   $ 21-3/4   $ 26-1/2   $ 18-11/16
Book value per share                 $  16.61      $  18.43      $  17.80       $  17.65   $  17.26   $  16.62   $  14.62
Return on average common equity<e>      12.42%        12.63%         9.69%         11.35%     10.96%     11.40%     13.64%
Capitalization Data (Millions of Dollars)
Common stock                         $2,033.9      $2,256.9      $2,169.1       $2,129.9   $2,059.3   $1,955.8   $1,524.9
Preferred stock:
  Not subject to mandatory
    redemption                          170.1         170.1         170.1          170.1      300.1      250.1      235.1
  Subject to mandatory redemption                                                              25.2       26.4       30.7
Long-term debt and QUIDS              2,179.3       2,193.1       2,397.1        2,273.2    2,178.5    2,008.1    1,586.0
Total capitalization                 $4,383.3      $4,620.1      $4,736.3       $4,573.2   $4,563.1   $4,240.4   $3,376.7
Capitalization ratios:
  Common stock                          46.4%          48.8%         45.8%          46.6%      45.1%      46.1%      45.1%
  Preferred stock:
    Not subject to mandatory
    redemption                           3.9            3.7           3.6            3.7        6.6        5.9        7.0
    Subject to mandatory redemption                                                              .6         .6         .9
Long-term debt and QUIDS                49.7           47.5          50.6           49.7       47.7       47.4       47.0
Total Assets (Millions of Dollars)  $6,747.8       $6,654.1      $6,618.5       $6,447.3   $6,362.2   $5,949.2   $4,334.4
Property Data (Millions of Dollars)
Gross property                      $8,629.7      $8,451.4       $8,206.2       $7,812.7   $7,586.8   $7,176.9   $5,493.1
Accumulated depreciation            (3,395.6)     (3,155.2)      (2,910.0)      (2,700.1)  (2,529.4)  (2,388.8)  (1,680.2)
Net property                        $5,234.1      $5,296.2       $5,296.2       $5,112.6   $5,057.4   $4,788.1   $3,812.9
Gross additions during year
  -utility                          $  229.4      $  284.7       $  289.5       $  319.1   $  508.3   $  574.0   $  199.5
  -nonutility                       $    1.8      $    1.4       $  178.5        
Ratio of provisions for depreciation
  To depreciable property               3.28%         3.34%          3.47%          3.50%      3.32%      3.37%      3.23%

</TABLE>


                                   D-2

<PAGE>

                                                       Allegheny Energy, Inc.

Consolidated Statistics (continued)

<TABLE>
<CAPTION>

<S>                                  <C>          <C>           <C>           <C>            <C>         <C>         <C>
Year ended December 31               1998         1997          1996          1995           1994        1993        1988
Revenues (Millions of Dollars)
Residential                          $ 880.6      $  892.9      $  932.2      $  927.0       $  863.7    $  818.4    $  635.1
Commercial                             501.4         490.5         492.7         493.7          459.3       430.2       328.8
Industrial                             753.5         748.1         752.9         770.2          728.0       673.4       564.8
Wholesale and street lighting           69.0          65.1          66.6          59.6           58.7        55.0        45.3
  Revenues from regular
  utility customers                  2,204.5       2,196.6       2,244.4       2,250.5        2,109.7     1,977.0     1,574.0
Other non-gWh                            9.9           6.4           7.7           6.5            7.1         5.3        10.4
Bulk power                              69.8          39.6          22.4          13.0           29.0        28.5       238.4
Transmission services                   45.2          41.1          52.4          45.2           38.8        39.8        29.8
  Total utility revenues            $2,329.4      $2,283.7      $2,326.9      $2,315.2       $2,184.6    $2,050.6    $1,852.6
Total nonutility revenues           $  247.0      $   85.8      $     .7
Sales Volumes-gWh
Residential                         12,939         12,832        13,328        13,003         12,630      12,514      10,772
Commercial                           8,626          8,176         8,132         7,963          7,607       7,440       6,260
Industrial                          19,675         19,040        18,568        18,457         17,708      16,967      16,005
Wholesale and street lighting        1,409          1,422         1,456         1,304          1,275       1,240       1,088
  Regular utility transactions      42,649         41,470        41,484        40,727         39,220      38,161      34,125
Bulk power                           3,037          1,667           966           507          1,086       1,145       9,604
Transmission services                7,345f        12,367        17,402        14,586          9,405      11,864      13,084
  Total utility transactions        53,031         55,504        59,852        55,820         49,711      51,170      56,813
Total nonutility transactions        8,278          3,734           109
Output and Delivery-gWh
Steam generation                    44,323         43,463        40,067        39,174         38,959      38,247      42,955
Hydro and pumped-storage generation  1,326          1,171         1,348         1,234          1,390       1,233       1,644
Pumped-storage input                (1,498)        (1,298)       (1,405)       (1,390)        (1,564)     (1,385)     (1,904)
Purchased power                     11,505          6,485         5,518         5,021          4,136       4,002       4,059
Transmission services                7,777         12,367        17,402        14,586          9,405      11,864      13,084
Losses and system uses              (2,124)        (2,950)       (2,969)       (2,805)        (2,615)     (2,791)     (3,025)
Total transactions as above         61,309         59,238        59,961        55,820         49,711      51,170      56,813
Utility Statistics
Year ended December 31               1998          1997           1996           1995           1994        1993       1988
Energy Supply
Generating capability-MW
  Utility-owned                      8,121          8,071         8,070          8,070          8,070       7,991       7,906
  Nonutility contracts<g>              299            299           299            299            299         292         160
Maximum hour peak-MW                 7,314          7,423         7,500          7,280          7,153       6,678       6,045
Load factor                           69.1%          68.3%         67.5%          68.3%          66.8%       70.0%       70.0%
Heat rate-Btu's per kWh              9,939          9,936         9,910          9,970          9,927      10,020       9,938
Fuel costs-cents per million Btu's  128.92         130.05        129.22         130.20         141.50      142.12      135.66
Customers (Thousands)
Residential                        1,236.9        1,224.9       1,213.7        1,204.4        1,189.7     1,176.6     1,102.3
Commercial                           154.7          151.5         148.5          146.0          143.0       140.1       125.6
Industrial                            25.5           25.2          25.0           24.6           24.2        23.8        21.8
Other                                  1.3            1.3           1.3            1.3            1.3         1.2         1.2
Total customers                    1,418.4        1,402.9       1,388.5        1,376.3        1,358.2     1,341.7     1,250.9
Average Annual Use-kWh per customer
Residential-Allegheny Energy      10,486         10,521        11,042         10,865         10,682      10,715       9,850
Residential-National               9,952h         9,552         9,713          9,583          9,378       9,394       9,082
All retail service-Allegheny
  Energy                          28,174         28,647        29,085         28,908         28,205      27,800      26,715
Average Rate-cents per kWh
Residential-Allegheny Energy        6.90           6.96          6.99           7.13           6.84        6.54        5.90
Residential-National                8.77h          8.94          8.86           8.87           8.83        8.73        7.78
All retail service-Allegheny Energy 5.32           5.36          5.46           5.58           5.43        5.23        4.65

</TABLE>

a  Write-off in connection with deregulation proceedings in Pennsylvania.
b  To record unbilled revenues, net of income taxes.
c  Reflects a two-for-one common stock split effective November 4, 1993.
d  Basic and diluted earnings per average share.
e  Excludes the cumulative effect of the accounting change in 1994, and the
   extraordinary charge, net and Pennsylvania restructuring activities
   in 1998. Includes the effect of internal restructuring in 1995 and 1996.
f  Excludes 432 gWh delivered to customers participating in the Pennsylvania
   pilot program that are included in regular utility transactions sales
   volumes.
g  Capability available through contractual arrangements with nonutility
   generators.

h  Preliminary
                                  D-3

<PAGE>

                                                   Monongahela Power Company

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

<TABLE>
<CAPTION>
                                                                   Quarter Ended
                                               1998                                            1997
                              Dec.       Sept.       June        March        Dec.       Sept.       June       March
Electric operating
  <S>                      <C>         <C>         <C>         <C>          <C>         <C>         <C>        <C>
  revenues .............   $155,712    $177,364    $153,774    $158,272     $163,190    $158,240    $144,078   $162,803
Operating income........     28,154      31,887      24,087      27,358       26,701      28,493      23,701     30,480
Net income..............     21,143      25,244      16,611      19,427       18,342      23,457      16,174     22,556

</TABLE>



SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)

<TABLE>
<CAPTION>

                                            1998        1997        1996        1995        1994        1993
Electric operating revenues:
  <S>                                     <C>         <C>         <C>         <C>         <C>         <C>
  Residential..........................   $200,896    $199,931    $206,033    $209,065    $190,861    $185,141
  Commercial...........................    126,464     118,825     121,631     124,457     116,201     110,762
  Industrial...........................    208,613     196,716     200,970     212,427     202,181     187,669
  Wholesale and street lighting........      7,656       7,600       7,513       7,255       7,142       6,663
    Revenues from regular customers....    543,629     523,072     536,147     553,204     516,385     490,235
  Affiliated...........................     77,314      83,600      74,825      73,216      79,674      61,677
  Other non-kWh........................      4,426       4,379       4,136       3,722       3,535       3,233
  Bulk power...........................      8,509       7,299       4,772       2,749       7,681       8,382
  Transmission services................     11,244       9,961      12,591      10,589       9,172       9,754
    Total revenues.....................    645,122     628,311     632,471     643,480     616,447     573,281

Operation expense......................    313,795     305,487     310,480     330,740     330,909     295,464
Maintenance............................     67,033      70,561      74,735      73,041      69,389      67,770
Internal restructuring charges
  and asset write-off..................                             24,299       5,493
Depreciation...........................     58,610      56,593      55,490      57,864      57,952      56,056
Taxes other than income................     44,742      38,776      40,418      38,551      40,404      34,076
Taxes on income........................     49,456      47,519      34,496      41,834      30,650      33,612
Allowance for funds used
  during construction..................     (1,043)     (1,386)       (672)     (1,393)     (2,946)     (5,780)
Interest charges.......................     36,153      38,730      38,604      39,872      38,156      37,588
Other income, net......................     (6,049)     (8,498)     (6,831)     (9,235)     (8,003)     (7,203)

Income before cumulative effect
  of accounting change.................     82,425      80,529      61,452      66,713      59,936      61,698
Cumulative effect of accounting
  change, net (a)......................                                                      7,945
Net income.............................   $ 82,425    $ 80,529    $ 61,452    $ 66,713    $ 67,881    $ 61,698

Return on average common equity (b)....      13.62%      13.99%      11.00%      11.92%      10.66%      11.83%

</TABLE>

(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994 and
    includes the effect of internal restructuring in 1995 and 1996.


<PAGE>

                               D-4


                                                    Monongahela Power Company

FINANCIAL AND OPERATING STATISTICS

<TABLE>
<CAPTION>

                                           1998         1997         1996        1995         1994         1993
PROPERTY, PLANT, AND EQUIPMENT
  at Dec. 31 (Thousands):
    <S>                              <C>          <C>          <C>          <C>          <C>          <C>
    Gross..........................  $2,007,876   $1,950,478   $1,879,622   $1,821,613   $1,763,533   $1,684,322
    Accumulated depreciation.......    (883,915)    (840,525)    (790,649)    (747,013)    (701,271)    (664,947)
      Net..........................  $1,123,961   $1,109,953   $1,088,973   $1,074,600   $1,062,262   $1,019,375

GROSS ADDITIONS TO PROPERTY
  (Thousands):.....................  $   72,795   $   78,139   $   72,577   $   75,458   $  103,975   $  140,748

TOTAL ASSETS at Dec. 31
  (Thousands)......................  $1,519,028   $1,493,254   $1,486,755   $1,480,591   $1,476,483   $1,407,453

CAPITALIZATION at Dec. 31
  (Thousands):
    Common stock...................  $  570,188   $  540,930   $  512,212   $  505,752   $  495,693   $  483,030
    Preferred stock................      74,000       74,000       74,000       74,000      114,000       64,000
    Long-term debt and QUIDS.......     453,917      455,088      474,841      489,995      470,131      460,129
                                     $1,098,105   $1,070,018   $1,061,053   $1,069,747   $1,079,824   $1,007,159

  Ratios:
    Common stock...................        51.9%        50.6%        48.3%        47.3%        45.9%        48.0%
    Preferred stock................         6.8          6.9          7.0          6.9         10.6          6.3
    Long-term debt and QUIDS.......        41.3         42.5         44.7         45.8         43.5         45.7
                                          100.0%       100.0%       100.0%       100.0%       100.0%       100.0%
GENERATING CAPABILITY--
  kW at Dec. 31:
    Company-owned..................   2,326,300    2,326,300    2,326,300    2,326,300    2,326,300    2,325,300
    Nonutility contracts (a).......     161,000      161,000      161,000      161,000      161,000      159,000

KILOWATT-HOURS (Thousands):
  Sales Volumes:
    Residential....................   2,757,067    2,764,630    2,815,414    2,807,135    2,674,664    2,689,830
    Commercial.....................   2,102,604    1,987,147    2,007,116    1,967,473    1,846,791    1,825,127
    Industrial.....................   5,510,925    5,224,364    5,024,257    5,114,126    4,942,388    4,656,921
    Wholesale and street lighting..     142,797      142,827      142,198      138,456      134,351      134,042
      Sales to regular customers...  10,513,393   10,118,968    9,988,985   10,027,190    9,598,194    9,305,920
    Affiliated.....................   1,950,803    2,080,542    1,694,722    1,596,081    1,791,099    1,431,519
    Bulk power.....................     301,656      249,505      196,843      105,126      285,048      338,476
    Transmission services..........   1,932,160    3,007,439    4,218,150    3,497,216    2,278,111    2,938,187
      Total sales volumes..........  14,698,012   15,456,454   16,098,700   15,225,613   13,952,452   14,014,102
  Output and Delivery:
    Steam generation...............  11,251,721   10,936,469   10,678,491   10,620,003   10,743,934   10,194,794
    Pumped-storage generation......     288,266      241,958      263,640      257,284      290,586      263,329
    Pumped-storage input...........    (370,822)    (310,565)    (337,451)    (330,915)    (373,116)    (337,737)
    Purchased power................   2,283,055    2,294,059    2,040,136    1,903,644    1,685,938    1,637,677
    Transmission services..........   1,932,160    3,007,439    4,218,150    3,497,216    2,278,111    2,938,187
    Losses and system uses.........    (686,368)    (712,906)    (764,266)    (721,619)    (673,001)    (682,148)
      Total transactions as above..  14,698,012   15,456,454   16,098,700   15,225,613   13,952,452   14,014,102

CUSTOMERS at Dec. 31:
  Residential......................     309,760      307,920      305,579      303,568      300,465      297,865
  Commercial.......................      37,929       37,168       36,323       35,793       35,268       34,626
  Industrial.......................       7,992        7,996        8,019        8,085        8,029        8,014
  Other............................         218          199          182          170          171          170
    Total customers................     355,899      353,283      350,103      347,616      343,933      340,675

RESIDENTIAL SERVICE:
  Average use-
    kWh per customer...............       8,938        9,023        9,256        9,306        8,957        9,093
  Average revenue-
    dollars per customer...........      651.29       652.53       677.37       693.11       639.16       625.87
  Average rate-
    cents per kWh..................        7.29         7.23         7.32         7.45         7.14         6.88


</TABLE>
(a) Capability available through contractual arrangements with nonutility
    generators.


                              D-5

<PAGE>
                                                   The Potomac Edison Company


QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

<TABLE>
<CAPTION>

                                                                   Quarter Ended
                                             1998                                              1997
                              Dec.       Sept.       June        March        Dec.       Sept.       June       March
Electric operating
  <S>                       <C>        <C>         <C>         <C>          <C>        <C>         <C>        <C>
  revenues..............    $177,744   $190,533    $177,519    $191,698     $176,222   $175,464    $164,867   $192,228
Operating income........      34,458     36,680      30,036      37,622       34,428     30,388      26,894     37,062
Net income..............      25,757     27,299      20,504      27,922       24,360     25,296      18,376     27,723


</TABLE>






SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)

<TABLE>
<CAPTION>

                                            1998        1997        1996        1995        1994        1993
Electric operating revenues:
  <S>                                     <C>         <C>         <C>         <C>         <C>         <C>
  Residential..........................   $309,058    $299,876    $324,120    $316,714    $296,090    $274,358
  Commercial...........................    156,973     148,287     146,432     145,096     135,937     124,667
  Industrial...........................    206,638     198,174     196,813     200,890     195,089     175,902
  Wholesale and street lighting........     27,667      30,443      32,907      27,028      26,109      24,351
    Revenues from regular customers....    700,336     676,780     700,272     689,728     653,225     599,278
  Affiliated...........................      9,401       9,687       2,399       2,525       2,716       3,041
  Other non-kWh........................      1,358      (1,273)       (405)       (961)     (4,647)      1,352
  Bulk power...........................     11,690      10,035       7,577       4,566       8,932       8,585
  Transmission services................     14,709      13,552      16,917      14,811      12,675      12,423
    Total..............................    737,494     708,781     726,760     710,669     672,901     624,679

Operation expense......................    369,998     359,350     373,133     374,731     362,167     325,239
Maintenance............................     52,186      56,815      62,248      60,052      58,624      64,376
Internal restructuring charges
  and asset write-off..................                             26,094       6,847
Depreciation...........................     74,344      71,763      71,254      68,826      59,989      56,449
Taxes other than income................     49,567      47,585      45,809      47,629      46,740      46,813
Taxes on income........................     52,603      44,496      34,132      36,936      33,126      30,086
Allowance for funds used
  during construction..................     (1,576)     (2,830)     (2,491)     (1,752)     (5,874)     (7,134)
Interest charges.......................     48,187      49,823      50,197      51,179      46,456      43,802
Other income, net......................     (9,297)    (13,976)     (11,791)    (12,044)    (10,310)    (8,419)

Income before cumulative effect
  of accounting change.................    101,482      95,755      78,175      78,265      81,983      73,467
Cumulative effect of accounting
  change, net (a)......................                                                     16,471
Net income.............................   $101,482    $ 95,755    $ 78,175    $ 78,265    $ 98,454    $ 73,467

Return on average common equity (b)....      13.90%      13.44%      11.42%      11.34%      11.86%      11.63%

</TABLE>


(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994 and
    includes the effect of internal restructuring in 1995 and 1996.

                                  D-6

<PAGE>


                                                   The Potomac Edison Company

FINANCIAL AND OPERATING STATISTICS

<TABLE>
<CAPTION>

                                                1998         1997        1996         1995         1994         1993
PROPERTY, PLANT, AND EQUIPMENT
  at Dec. 31 (Thousands):
    <S>                                      <C>         <C>         <C>          <C>          <C>          <C>
    Gross..................................  $2,249,716  $2,196,262  $2,124,956   $2,050,835   $1,978,396   $1,857,961
    Accumulated depreciation...............    (926,840)   (859,076)   (791,257)    (729,653)    (673,853)    (632,269)
      Net..................................  $1,322,876  $1,337,186  $1,333,699   $1,321,182   $1,304,543   $1,225,692

GROSS ADDITIONS TO PROPERTY
  (Thousands)..............................  $   60,525  $   78,298  $   86,256   $   92,240   $  142,826   $  179,433

TOTAL ASSETS at Dec. 31
  (Thousands)..............................  $1,702,127  $1,660,647  $1,677,886   $1,654,444   $1,629,535   $1,519,763

CAPITALIZATION at Dec. 31:
  (Thousands):
    Common stock...........................  $  762,912  $  689,781  $ 678,116   $  667,242   $  658,146   $  626,467
    Preferred stock:
      Not subject to mandatory redemption..      16,378      16,378     16,378       16,378       36,378       36,378
      Subject to mandatory redemption......                                                       25,200       26,400
    Long-term debt and QUIDS...............     578,817     627,012    628,431      628,854      604,749      517,910
                                             $1,358,107  $1,333,171  $1,322,925  $1,312,474   $1,324,473   $1,207,155
  Ratios:
    Common stock...........................        56.2%       51.8%      51.3%        50.8%        49.7%        51.9%
    Preferred stock:
      Not subject to mandatory redemption..         1.2         1.2        1.2          1.3          2.7          3.0
      Subject to mandatory redemption......                                                          1.9          2.2
    Long-term debt and QUIDS...............        42.6        47.0       47.5         47.9         45.7         42.9
                                                  100.0%      100.0%     100.0%       100.0%       100.0%       100.0%
GENERATING CAPABILITY--
  kW at Dec. 31                               2,073,292   2,073,292  2,072,292    2,072,292    2,072,292    2,076,592

KILOWATT-HOURS (Thousands):
  Sales Volumes:
    Residential............................   4,401,238   4,290,117  4,599,758    4,377,416    4,214,997    4,144,958
    Commercial.............................   2,498,546   2,331,789  2,288,229    2,213,052    2,136,081    2,091,930
    Industrial.............................   5,922,274   5,593,722  5,567,088    5,485,220    5,339,737    5,194,909
    Wholesale and street lighting..........     657,357     666,383    724,011      603,572      591,799      582,259
      Sales to regular customers...........  13,479,415  12,882,011 13,179,086   12,679,260   12,282,614   12,014,056
    Affiliated.............................     498,069     591,876     47,781       52,967       61,815       67,377
    Bulk power.............................     402,635     369,732    315,808      173,110      331,832      343,837
    Transmission services..................   2,470,365   4,044,837  5,617,912    4,740,010    3,031,339    3,693,330
      Total sales volumes..................  16,850,484  17,888,456 19,160,587   17,645,347   15,707,600   16,118,600
  Output and Delivery:
    Steam generation.......................  11,254,505  11,002,533 10,762,678   10,410,118   10,464,607   10,103,411
    Hydro and pumped-storage generation....     416,983     370,026    401,998      395,315      426,550      368,834
    Pumped-storage input...................    (486,823)   (426,087)  (455,142)    (452,151)    (506,213)    (433,885)
    Purchased power........................   4,190,098   3,934,815  3,639,519    3,318,302    3,033,744    3,174,838
    Transmission services..................   2,470,365   4,044,837  5,617,912    4,740,010    3,031,339    3,693,330
    Losses and system uses.................    (994,644) (1,037,668)  (806,378)    (766,247)    (742,427)    (787,928)
      Total transactions as above..........  16,850,484  17,888,456 19,160,587   17,645,347   15,707,600   16,118,600

CUSTOMERS at Dec. 31:
  Residential..............................     339,584     333,224    327,344      321,813      315,309      309,096
  Commercial...............................      44,828      43,794     42,670       41,759       40,927       40,173
  Industrial...............................       5,122       5,010      4,887        4,733        4,595        4,509
  Other....................................         641         598        571          543          524          510
    Total customers........................     390,175     382,626    375,472      368,848      361,355      354,288
RESIDENTIAL SERVICE:
  Average use-
    kWh per customer.......................      13,093      13,003     14,179       13,729       13,506       13,562
  Average revenue-
    dollars per customer...................      919.42      908.87     999.10       993.35       948.76       897.70
  Average rate-
    cents per kWh..........................        7.02        6.99       7.05         7.24         7.02         6.62

</TABLE>

                                    D-7


<PAGE>

                                                      West Penn Power Company
                                                             and Subsidiaries

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

<TABLE>
<CAPTION>

                                                                    Quarter Ended
                                               1998                                              1997
                                Dec.       Sept.       June        March        Dec.        Sept.       June       March

Electric operating
  <S>                        <C>         <C>         <C>         <C>         <C>        <C>         <C>         <C>
  revenues................   $246,729    $288,272    $263,023    $280,703    $280,155   $266,746    $252,731    $282,530
Operating income..........     17,038      56,248      40,627      52,619      55,850     43,865      35,661      47,271
Consolidated net (loss)
  income..................     (5,504)     42,835    (239,138)     39,001      41,468     34,333      21,963      36,901

</TABLE>




SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)

<TABLE>
<CAPTION>

                                             1998         1997         1996        1995         1994         1993
Electric operating revenues:
  <S>                                     <C>          <C>          <C>          <C>          <C>          <C>
  Residential..........................   $  370,636   $  393,036   $  402,083   $  401,186   $  376,776   $  358,900
  Commercial...........................      217,954      223,347      224,663      224,144      207,165      194,773
  Industrial...........................      338,254      352,730      355,120      356,937      330,739      309,847
  Wholesale and street lighting........       33,650       27,051       26,194       25,330       25,425       23,945
    Revenues from regular customers....      960,494      996,164    1,008,060    1,007,597      940,105      887,465
  Affiliated...........................       45,180       39,031       44,231       44,293       37,915       40,169
  Other non-kWh........................        4,152        6,377        3,903        3,765        3,980        3,692
  Bulk power...........................       49,605       22,188       10,012        5,687       12,339       11,547
  Transmission services................       19,296       18,402       22,918       19,751       16,998       17,625
    Total..............................    1,078,727    1,082,162    1,089,124    1,081,093    1,011,337      960,498

Operation expense......................      552,514      524,051      531,522      523,279      531,059      500,790
Maintenance............................       91,724       98,252      104,211      114,489      111,841       96,706
Internal restructuring charges
  and asset write-offs.................                                 53,343       11,099        8,919
Depreciation...........................      114,709      113,793      119,066      112,334       88,935       80,872
Taxes other than income................       88,722       90,140       90,132       89,694       87,224       89,249
Taxes on income........................       64,526       73,279       47,455       61,745       46,645       51,529
Allowance for funds used
  during construction..................       (2,403)      (4,085)      (2,723)      (5,041)     (10,777)      (8,566)
Interest charges.......................       67,640       69,629       71,072       67,902       60,274       60,585
Other income, net......................      (11,325)     (17,562)     (13,439)     (12,287)     (13,798)     (12,728)

Consolidated income before
  extraordinary charge and cumulative
  effect of accounting change..........      112,620      134,665       88,485      117,879      101,015      102,061
Extraordinary charge, net (a)..........     (275,426)
Cumulative effect of accounting
  change, net (b)......................                                                           19,031
Consolidated net (loss) income.........   $ (162,806)  $  134,665   $   88,485   $  117,879   $  120,046   $  102,061

Return on average common equity (c)....        13.12%       13.70%        8.72%       11.46%        9.94%       11.49%


</TABLE>

(a) Write-off in connection with Pennsylvania deregulation proceedings.
(b) To record unbilled revenues, net of income taxes.
(c) Excludes the cumulative effect of the accounting change in 1994, and the
    extraordinary charge, net and Pennsylvania restructuring activities in
    1998.  Includes the effect of internal restructuring in 1995 and 1996.

                                   D-8

<PAGE>


                                                      West Penn Power Company
                                                             and Subsidiaries

FINANCIAL AND OPERATING STATISTICS

<TABLE>
<CAPTION>

                                              1998          1997         1996        1995          1994        1993
PROPERTY, PLANT, AND EQUIPMENT
  at Dec. 31 (Thousands):
    <S>                                     <C>          <C>          <C>          <C>          <C>          <C>
    Gross.................................  $3,365,784   $3,293,039   $3,182,208   $3,097,522   $3,013,777   $2,803,811
    Accumulated depreciation..............  (1,362,413)  (1,254,900)  (1,152,383)  (1,063,399)  (1,009,565)    (962,623)
      Net.................................  $2,003,371   $2,038,139   $2,029,825   $2,034,123   $2,004,212   $1,841,188

GROSS ADDITIONS TO PROPERTY
  (Thousands).............................  $   95,975   $  128,054   $  130,606   $  149,122   $  260,366   $  251,017

TOTAL ASSETS at Dec. 31
  (Thousands).............................  $2,843,069   $2,747,159   $2,699,737   $2,771,164   $2,731,858   $2,544,763

CAPITALIZATION at Dec. 31:
  (Thousands):
    Common stock..........................  $  732,161   $  997,027   $  962,752   $  973,188   $  955,482   $  893,969
    Preferred stock.......................      79,708       79,708       79,708       79,708      149,708      149,708
    Long-term debt and QUIDS..............     837,725      802,319      905,243      904,669      836,426      782,369
                                            $1,649,594   $1,879,054   $1,947,703   $1,957,565   $1,941,616   $1,826,046
  Ratios:
    Common stock..........................        44.4%        53.1%        49.4%        49.7%        49.2%        49.0%
    Preferred stock.......................         4.8          4.2          4.1          4.1          7.7          8.2
    Long-term debt and QUIDS.............         50.8         42.7         46.5         46.2         43.1         42.8
                                                 100.0%       100.0%       100.0%       100.0%       100.0%       100.0%
GENERATING CAPABILITY--
  kW at Dec. 31:
    Company-owned.........................   3,721,408    3,671,408    3,671,408    3,671,408    3,671,408    3,589,408
    Nonutility contracts (a)..............     138,000      138,000      138,000      138,000      138,000      133,000

KILOWATT-HOURS (Thousands):
  Sales Volumes:
    Residential...........................   5,778,155    5,756,594    5,913,412    5,818,838    5,740,028    5,679,746
    Commercial............................   4,023,523    3,833,178    3,835,831    3,782,250    3,624,117    3,522,566
    Industrial............................   8,237,627    8,046,166    7,974,265    7,857,689    7,426,267    7,114,765
    Wholesale and street lighting.........     617,841      611,105      591,122      561,893      548,296      523,233
      Regular customer transactions.......  18,657,146   18,247,043   18,314,630   18,020,670   17,338,708   16,840,310
    Affiliated............................   1,974,497    1,789,476    1,068,712    1,059,852      982,557    1,297,956
    Bulk power............................   2,332,825    1,046,905      453,028      227,893      471,050      462,286
    Transmission services.................   2,942,868(b) 5,392,916    7,567,153    6,348,926    4,093,693    5,233,229
      Total transactions..................  25,907,336   26,476,340   27,403,523   25,657,341   22,886,008   23,833,781
  Output and Delivery:
    Steam generation......................  20,053,422   19,523,537   18,578,677   18,143,822   17,750,267   17,949,335
    Hydro and pumped-storage generation...     620,496      559,241      682,747      581,353      673,195      600,497
    Pumped-storage input..................    (640,242)    (561,135)    (612,877)    (606,953)    (684,715)    (613,290)
    Purchased power.......................   2,890,986    2,968,258    2,583,166    2,507,196    2,253,701    1,985,240
    Transmission services.................   3,850,394    5,392,916    7,567,153    6,348,926    4,093,693    5,233,229
    Losses and system uses................    (867,720)  (1,406,477)  (1,395,343)  (1,317,003)  (1,200,133)  (1,321,230)
      Total transactions as above.........  25,907,336   26,476,340   27,403,523   25,657,341   22,886,008   23,833,781

CUSTOMERS at Dec. 31:
  Residential.............................     587,503      583,745      580,816      578,983      573,963      569,601
  Commercial..............................      71,920       70,559       69,457       68,500       66,842       65,337
  Industrial..............................      12,389       12,142       12,051       11,801       11,563       11,218
  Other...................................         608          629          607          598          586          576
    Total customers.......................     672,420      667,075      662,931      659,882      652,954      646,732
RESIDENTIAL SERVICE:
  Average use-
    kWh per customer......................       9,775        9,903       10,223       10,096       10,041       10,025
  Average revenue-
    dollars per customer..................      644.98       674.73       695.08       696.06       659.07       633.48
  Average rate-
    cents per kWh.........................        6.60         6.81         6.80         6.89         6.56         6.32

</TABLE>

(a) Capability available through contractual arrangements with nonutility
    generators.
(b) Excludes 907,526 kWh (in thousands) delivered to customers
    participating in the Pennsylvania pilot program that are
    included in regular customer transactions sales volumes.

                                   D-9



<PAGE>

                                                 Allegheny Generating Company


QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

<TABLE>
<CAPTION>


                                                                   Quarter Ended
                                                   1998                                    1997
                                  Dec.      Sept.       June      March       Dec.         Sept.       June     March
Electric operating
  <S>                           <C>        <C>        <C>        <C>        <C>          <C>        <C>        <C>
  revenues..................    $17,783    $18,303    $19,126    $18,604    $16,170      $19,664    $20,408    $20,216
Operating income............      8,699      9,297      9,258      9,400      7,664       10,230     10,311     10,328
Net income..................      5,230      5,625      5,961      5,937      4,109       15,396      6,395      6,368


</TABLE>


                                   D-10


<PAGE>



                                                 Allegheny Generating Company

STATISTICS

SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)

<TABLE>
<CAPTION>
                                            1998        1997        1996        1995        1994        1993

<S>                                       <C>         <C>         <C>         <C>         <C>         <C>
Electric operating revenues............   $ 73,816    $ 76,458    $ 83,402    $ 86,970    $ 91,022    $ 90,606

Operation and maintenance expense......      4,592       4,877       5,165       5,740       6,695       6,609
Depreciation...........................     16,949      17,000      17,160      17,018      16,852      16,899
Taxes other than income taxes..........      4,662       4,835       4,801       5,091       5,223       5,347
Federal income taxes...................     10,959      11,213      13,297      13,552      14,737      13,262
Interest charges.......................     13,987      15,391      16,193      18,361      17,809      21,635
Other income, net......................        (86)     (9,126)         (3)        (16)        (11)       (328)
  Net Income...........................   $ 22,753    $ 32,268    $ 26,789    $ 27,224    $ 29,717    $ 27,182

Return on average common equity........      12.57%      15.98%      12.58%      12.46%      13.14%      11.72%

PROPERTY, PLANT, AND EQUIPMENT
  at Dec. 31 (Thousands):
    Gross..............................   $828,806    $828,658*   $837,050    $836,894*   $824,714    $824,904
    Accumulated depreciation...........   (210,198)   (193,173)   (176,178)   (159,037)   (143,965)   (128,375)
      Net..............................   $618,608    $635,485    $660,872    $677,857    $680,749    $696,529

GROSS ADDITIONS TO PROPERTY
  (Thousands)..........................   $     69    $    444    $    178    $ 14,165*   $  1,065    $  2,729

TOTAL ASSETS
  at Dec. 31 (Thousands)...............   $639,458    $663,920    $692,408    $710,287    $714,236    $735,929

CAPITALIZATION AND SHORT-TERM DEBT
  at Dec. 31:
    Amount (in thousands):
      Common stock.....................   $165,276    $199,523    $202,955    $214,153    $222,729    $228,512
      Long-term and short-term debt....    215,579     208,735     239,234     256,084     268,165     287,196
                                          $380,855    $408,258    $442,189    $470,237    $490,894    $515,708

  Ratios:
    Common stock.......................       43.4%       48.9%       45.9%       45.5%       45.4%       44.3%
    Long-term and short-term debt......       56.6        51.1        54.1        54.5        54.6        55.7
                                             100.0%      100.0%      100.0%      100.0%      100.0%      100.0%

KILOWATT-HOURS (Thousands):
  Pumping energy supplied by Parents...  1,497,887   1,297,787   1,405,470   1,390,019   1,564,044   1,384,912
  Pumped-storage generation............  1,164,325   1,011,366   1,098,278   1,081,112   1,218,446   1,079,985

</TABLE>


*Reflects a balance sheet reclassification in 1995 of $12 million from
 deferred charges to plant for a prior tax  payment, and a related
 settlement of $8.8 million in 1997 that was recorded as a reduction to plant.

                                  D-11


<PAGE>

                                   47



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


                           Page No.

AE                           M- 1

Monongahela                  M-21

Potomac Edison               M-36

West Penn                    M-51

AGC                          M-67


  

<PAGE>

                                                        Allegheny Energy, Inc.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

Factors That May Affect Future Results

     This management's discussion and analysis of financial condition and
results of operations contains forecast information items that are "forward-
looking statements" as defined in the Private Securities Litigation Reform
Act of 1995. These include statements with respect to deregulation
activities and movements toward competition in states served by the
Company, the merger with DQE, Inc. (DQE), parent company of Duquesne Light
Company in Pittsburgh, Pa., and results of operations. All such forward-
looking information is necessarily only estimated. There can be no
assurance that actual results will not materially differ from expectations.
Actual results have varied materially and unpredictably from past
expectations.

     Factors that could cause actual results to differ materially include,
among other matters, electric utility restructuring, including the ongoing
state and federal activities; potential Year 2000 operation problems;
developments in the legislative, regulatory, and competitive environments
in which the Company operates, including regulatory proceedings affecting
rates charged by the Company's subsidiaries; environmental, legislative,
and regulatory changes; future economic conditions; earnings retention and
dividend payout policies; developments relating to the proposed merger with
DQE, including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs such as
significant volatility in the market price of wholesale power, unscheduled
maintenance or repair requirements, weather, and  compliance with laws and
regulations.

Significant Events in 1998, 1997, and 1996

Pennsylvania Deregulation

     On November 19, 1998, the Pennsylvania Public Utility Commission
(Pennsylvania PUC) approved a settlement agreement between West Penn Power
Company (West Penn), the Company's Pennsylvania electric utility
subsidiary, and intervenors in West Penn's restructuring proceedings
related to legislation in Pennsylvania to provide customer choice of
electric suppliers and deregulate electricity generation.

     As a result of the May 29, 1998, Pennsylvania PUC Order and as revised
by the November 19, 1998, settlement agreement, West Penn determined that
under the provisions of Statement of Financial Accounting Standards No.
101, "Accounting for the Discontinuation of Application of FASB Statement
No. 71," an extraordinary charge of $466.9 million ($275.4 million after
taxes) was required to reflect a write-off of certain disallowances. In
addition, charges of $40.3 million ($23.7 million after taxes) related to
the West Penn revenue refund and energy program payments were also
recorded.

     Under the terms of the settlement agreement, two-thirds of West Penn's
customers were permitted to choose an alternate generation supplier
beginning in January 1999. All West Penn customers can do so beginning in
January 2000. They can also choose to remain as West Penn customers at West
Penn's capped generation rates or to alternate back and forth. Under the
law, all electric utilities, including West Penn, retain the responsibility
of electricity provider of last resort to all customers in their respective
franchise territories who do not choose an alternate supplier. See Notes B
and C to the consolidated financial statements for details of the
settlement agreement and other information about the deregulation process.

                                 M-1


<PAGE>

                                                       Allegheny Energy, Inc.

Merger with DQE

     See page 38 and also Note D to the consolidated financial statements
for more information about the merger.

Maryland Settlement and Deregulation

     The Company's Maryland subsidiary, The Potomac Edison Company (Potomac
Edison), reached a settlement agreement with various parties on the Office
of People's Counsel's
petition for a reduction in Potomac Edison's Maryland rates. Further
information on the settlement agreement is provided under Sales and
Revenues starting on page 31.

     On July 1, 1998, Potomac Edison filed testimony in Maryland's
investigation into transition costs, price protection, and unbundled rates.
See Electric Energy Competition on page 38 for more information regarding
the restructuring in Maryland.

Nonutility Operations

     In 1996, the Company's nonutility subsidiary, AYP Capital, Inc. (AYP
Capital) expanded its nonutility operations by forming AYP Energy, Inc.
(AYP Energy) and Allegheny Communications Connect, Inc. (ACC). ACC was
formed to develop opportunities in the deregulated telecommunications
market. AYP Energy is a bulk power marketer. In October 1996, AYP Energy
purchased for about $170 million a 50%, 276-megawatt (MW), interest in Unit
No. 1 of the Fort Martin coal-fired power station in West Virginia. Two of
the Company's utility subsidiaries own the other 50%.

     In 1997, AYP Capital formed Allegheny Energy Solutions, Inc.
(Allegheny Energy Solutions). Allegheny Energy Solutions was formed to
market electric energy to retail customers in deregulated markets. Because
of organizational efficiencies available in an alternate corporate
structure, Allegheny Energy Solutions no longer competes in deregulated
energy markets as of January 1999. Rather, that role has been assumed by
the Energy Supply Division of the Supply Business of West Penn. With
customer choice now under way in Pennsylvania, the Energy Supply Division
attracted about 1,300 MW of load for 1999. West Penn lost only about 400 MW
of load in this competitive environment, giving it a net gain of about 900
MW.

     AYP Capital, in its own name, also markets various services related to
the electric industry and has investments in two limited energy
partnerships.


PURPA Power Project Terminations

     On August 26, 1997, and December 3, 1997, West Penn announced that it
had negotiated agreements to buy out and settle disputes with developers of
proposed power plants (the Milesburg and Washington Power projects) for $15
million and $48 million, respectively, reducing costs over the proposed 30-
and 33-year lives of the projects by an estimated $1.4 billion. The
disputed projects were being developed under the Public Utility Regulatory
Policies Act of 1978 (PURPA) and would have required West Penn to buy 43 MW
and 80 MW of capacity and energy, respectively, over the lives of the
projects at

                               M-2


<PAGE>

                                                       Allegheny Energy, Inc.

prices well above current market price estimates. In 1996, West
Penn and the developers of a proposed Shannopin PURPA project reached an
agreement to terminate that project at a buyout price of $31 million. The
Shannopin buyout will reduce West Penn's costs approximately $665 million
over 30 years by eliminating the need to buy the uneconomic power.



Internal Restructuring

     In 1994, the Company and its subsidiaries initiated an internal
restructuring process to consolidate and re-engineer their utility
operations to meet the competitive challenges of the changing electric
utility industry. As a result of this process, the subsidiaries reduced
employment by about 1,000 employees through a voluntary separation plan,
attrition and layoffs, and changed processes to obtain efficiencies to
reduce operating and maintenance costs. This process resulted in internal
restructuring charges and an asset write-off in 1996 as described in Note E
to the consolidated financial statements.



Review of Operations

Earnings Summary

<TABLE>
<CAPTION>
                                                                                Basic and Diluted Earnings
                                                           Earnings                  Per Average Share
(Millions of Dollars Except Per Share Data)        1998      1997      1996      1998       1997      1996

Operations Before Restructuring Activities:
<S>                                              <C>        <C>       <C>       <C>        <C>       <C>
Utility                                          $ 307.0    $295.7    $275.5    $ 2.51     $2.42     $2.27
Nonutility                                         (20.3)    (14.4)     (2.9)     (.17)     (.12)     (.02)

Consolidated Income Before Restructuring
  Activities                                       286.7     281.3     272.6      2.34      2.30      2.25
Costs Related to Restructuring Activities*         (23.7)              (62.6)     (.19)               (.52)
Extraordinary Charge, Net (Notes B and C
to Consolidated Financial Statements)             (275.4)                        (2.25)
Consolidated Net (Loss) Income                  $  (12.4)   $281.3    $210.0    $ (.10)    $2.30     $1.73

</TABLE>

*Pennsylvania deregulation settlement costs in 1998 and internal
 restructuring costs in 1996.


     The increase in 1998 earnings from utility operations, before costs
related to Pennsylvania restructuring and settlement activities, resulted
from increased kilowatt-hour (kWh) sales to commercial and industrial
customers and from reduced power station operation and maintenance (O&M)
spending. The 1998 costs from restructuring activities and the
extraordinary charge are related to Pennsylvania deregulation and the
Pennsylvania restructuring Order. These costs are described in Notes B and
C to the consolidated financial statements. The 1996 restructuring costs
resulted from internal restructuring initiated in 1994 which is described
in Note E to the consolidated financial statements and Internal
Restructuring on page 30. The increase in 1997 earnings from utility
operations resulted primarily from reductions in O&M expenses from the
internal restructuring process and additional actions taken during the year
to achieve further O&M reductions in response to significant decreases in
residential kWh sales caused primarily by mild weather.

                               M-3


<PAGE>

                                                       Allegheny Energy, Inc.

     The increase in losses from nonutility operations in 1998 resulted
primarily from AYP Energy sales commitments for energy in excess of owned
generating capacity which required settlement by open market purchases
during a period of high wholesale prices. Other marketing activities served
to mitigate these losses as described on page 33. After purchasing a 50%
ownership interest in Unit No. 1 of Fort Martin power station in October
1996, AYP Energy completed its first full year of operation in 1997.
Because of considerable excess generating capacity pursuing limited demand
in 1997 and 1998, AYP Energy's operating margins were insufficient to cover
all of its fixed costs. This condition may continue until further deregulation
activities expand market opportunities and competing excess capacity is
absorbed by demand growth. Another item contributing to the nonutility
losses was Allegheny Energy Solutions' net losses of $1.7 million and $1.4
million in 1998 and 1997, respectively, for its participation in the
Pennsylvania pilot program (see Note B to the consolidated financial
statements for more information about the pilot program)


Sales and Revenues

Total operating revenues for 1998, 1997, and 1996
were as follows:

<TABLE>
<CAPTION>

(Millions of Dollars)                   1998         1997        1996

  Operating revenues:
      Utility revenues:
        <S>                             <C>          <C>          <C>
        Bundled retail sales            $2,135.5     $2,139.5     $2,184.6
        Unbundled retail sales              14.0          2.5
        Wholesale and other                 64.9         61.0         67.5
        Bulk power and transmission
         services sales                    115.0         80.7         74.8

          Total utility revenues         2,329.4      2,283.7      2,326.9
      Nonutility revenues:
        Retail and other                    31.7          4.9

        Bulk power sales                   215.3         80.9           .7

          Total nonutility revenues        247.0         85.8           .7
            Total operating revenues    $2,576.4     $2,369.5     $2,327.6

</TABLE>

                                M-4


<PAGE>

                                                       Allegheny Energy, Inc.

     Bundled retail sales revenues (full service sales to retail
customers) include a $25.1 million rate refund from 1998
revenues, pursuant to the terms of the Pennsylvania restructuring
settlement agreement. This refund to customers will be made in
1999. Excluding this rate decrease, bundled retail sales
increased $21.1 million in 1998 primarily due to increased kWh
sales to commercial and industrial customers. The increase in
1998 was also due to an increase in the number of customers.
Retail sales include sales to residential, commercial,
industrial, and street lighting customers.  Bundled retail sales
revenues were also affected by the Electricity Generation
Customer Choice and Competition Act (Customer Choice Act) in
Pennsylvania. As part of the Customer Choice Act, all utilities
in Pennsylvania were required to administer retail access pilot
programs under which customers, representing 5% of the load of
each rate class, would choose a generation supplier other than
their own local franchise utility. As a result, 5% of previously
fully bundled customers participated in the Pennsylvania pilot
program and were required to buy energy from another supplier of
their choice. The pilot program began on November 1, 1997, and
continued through December 31, 1998. Unbundled retail sales
revenues represent transmission and distribution revenues from
Pennsylvania pilot customers who chose another supplier to
provide their energy needs.

     To assure participation in the pilot program, pilot
participants received an energy credit from their local utility
and a price for energy pursuant to an agreement with an alternate
supplier. The credit established by the Pennsylvania PUC was
artificially high to encourage customer shopping, with the result
that West Penn incurred a revenue loss of $6.5 million for the
pilot. The Pennsylvania PUC has approved West Penn's pilot
compliance filing and thus has indicated its intent to treat the
revenue loss as a regulatory asset. Wholesale and other revenues
include an accrual of such revenue losses, as well as sales to
wholesale customers (cooperatives and municipalities that own
their own distribution systems and buy all or part of their bulk
power needs from the subsidiaries under Federal Energy Regulatory
Commission (FERC) regulation) and non-kWh revenues.

     On August 7, 1998, the Virginia State Corporation Commission
(Virginia SCC) approved an agreement reached between Potomac
Edison and the Staff of the Virginia SCC which reduced base rates
for Virginia customers beginning September 1, 1998, by about $2.5
million annually. The review of rates was required by an annual
information filing in Virginia.

     In 1999, utility revenues will reflect a reduction for a
settlement agreement with various parties on the Maryland Office
of People's Counsel's petition for a reduction in Potomac
Edison's Maryland rates. The agreement, which includes
recognition of costs to be incurred from the Applied Energy
Services (AES) Warrior Run PURPA cogeneration project, was
approved by the Maryland Public Service Commission (Maryland PSC)
on October 27, 1998. Under the terms of that agreement, Potomac
Edison will increase its rates about 4% ($13 million) in each of
the years 1999, 2000, and 2001 (a $39 million annual effect in
2001). The increases are designed to recover additional costs of
about $131 million over the period 1999-2001 for capacity
purchases from the AES Warrior Run cogeneration project, net of
alleged over-earnings of $52 million for the same period. The net
effect of these changes over the 1999-2001 timeframe results in a
pre-tax income reduction of $12 million in 1999,

                                M-5


<PAGE>

                                                       Allegheny Energy, Inc.


$18 million in 2000, and $22 million in 2001. In addition, the
settlement requires that Potomac Edison share, on a 50% customer, 50%
shareholder basis, earnings above a return on equity of 11.4% for
1999-2001. This sharing will occur through an annual true-up.

     Bundled retail revenues reflect not only changes in kWh
sales and base rate changes, but also any changes in revenues
from fuel and energy cost adjustment clauses (fuel clauses) which
are still applicable in all Company jurisdictions served, except
for Pennsylvania. Changes in fuel revenues in those jurisdictions
have no effect on consolidated net income because increases and
decreases in fuel and purchased power costs and sales of
transmission services and bulk power are passed on to customers
by adjustment of customers' bills through fuel clauses.

     Effective May 1, 1997, as a result of the Customer Choice
Act, West Penn obtained Pennsylvania PUC authorization to set its
fuel clause to zero and to roll its then-applicable fuel clause
rates into base rates. Thereafter, West Penn assumed the risks
and benefits of changes in fuel and purchased power costs and
sales of transmission services and bulk power. The decrease in
1997 bundled retail revenues resulted primarily from a decrease
in the fuel component of revenues and a decrease in residential
kWh sales due to mild weather in 1997.

     The increase in wholesale and other revenues in 1998 was due
primarily to deferred net revenue losses. West Penn recorded a
regulatory asset of $6.4 million in 1998 and $.1 million in 1997
to offset revenue losses suffered as a result of the pilot
program.

     Nonutility retail and other revenues increased in 1998 due
to Allegheny Energy Solutions' electric energy sales to retail
customers in deregulated markets.

     Utility and nonutility revenues include sales of bulk power
to power marketers and other utilities. Utility revenues also
include sales of transmission services to such marketers and
utilities. Significant bulk power sales in 1998 acted to offset
certain second and third quarter marketing losses in nonutility
operations. The Company has discontinued the types of marketing
activities which caused the losses. Bulk power and transmission
services sales for 1998, 1997, and 1996 were as follows:

                                         1998      1997      1996
KWh Transactions (in billions):

  Utility:
     Bulk power                         $  3.0      1.7       1.0
     Transmission services                 7.4     12.3      17.4
       Total utility                      10.4     14.0      18.4
  Nonutility bulk power                    7.3      3.7        .1
Revenues (in millions):
  Utility:
     Bulk power                         $ 69.8    $39.6     $22.4
     Transmission services                45.2     41.1      52.4
       Total utility                    $115.0    $80.7     $74.8
  Nonutility bulk power                 $215.3    $80.9     $  .7


                                  M-6


<PAGE>

                                                       Allegheny Energy, Inc.


     The 1998 increase in revenues from utility bulk power was
due to increased sales that occurred primarily in the second
quarter as a result of warm weather which increased the demand
and price for energy. In 1998, revenues from utility transmission
services were affected by a revenue refund resulting from a
reduction in the Company's standard transmission rate and rates
for ancillary services which were recently approved by the FERC.
A provision for these rate reductions was recorded in 1998, with
the revenues to be refunded to customers in the first quarter of
1999.

     Revenues from utility operations' transmission services in
1998 increased, despite decreased transmission services activity.
The increase in revenues was due in part to transmission
services' reservation charges paid to the Company by others for
the right to transmit energy. Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used.

     Revenues from utility operations' transmission services in
1997 decreased due to reduced demand, primarily because of mild
weather.

     In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The potential exists for such volatility to significantly
affect the Company's operating results. The effect may be either
positive or negative, depending on whether the Company's
subsidiaries are net buyers or sellers of electricity during such
periods, the open commitments which exist at such times, and
whether the effects of such transactions by the Company's utility
subsidiaries are includable in fuel or energy cost recovery
clauses in their respective jurisdictions. The effect of such
price volatility in June and the third quarter of 1998 differed
between the Company's utility and nonutility subsidiaries, but
was insignificant in total.

     The increase in nonutility bulk power revenues resulted
primarily from increased bulk power sales by the Company's
nonutility bulk power marketer, AYP Energy, which began
operations in late 1996, and from Allegheny Energy Solutions,
which was formed in the third quarter of 1997 to market energy to
retail customers in deregulated markets and other energy-related
services. Increased prices for energy in the wholesale market
also contributed to the increase. Allegheny Energy Solutions
recorded $24.9 million and $1.2 million of revenues in 1998 and
1997, respectively. Allegheny Energy Solutions ceased operations
as an electric generation supplier in January 1999. The Company
will continue to market nonutility energy supply to retail
customers under the brand name of Allegheny Energy Supply under
the direction of a newly created Energy Supply Division of the
Supply Business. The Energy Supply Division will also market
nonutility energy supply to wholesale customers.


Operating Expenses

                                  M-7


<PAGE>

                                                        Allegheny Energy, Inc.

Fuel expenses for 1998, 1997, and 1996 were as follows:

(Millions of Dollars)         1998      1997      1996

Utility operations            $545.4    $535.7    $512.5
Nonutility operations           21.1      24.2        .7

Total fuel expenses           $566.5    $559.9    $513.2



     Fuel expenses for utility operations in 1998 and 1997
increased 2% and 5%, respectively, due primarily to an increase
in kWhs generated. The increase in kWhs generated for utility
operations was primarily the result of increased bulk power sales
to power marketers and other utilities.

     Fuel expenses for nonutility operations reflect the kWhs
generated by the 50% of Unit No. 1 of the Fort Martin power
station purchased by AYP Energy in late 1996.

     The 1998 decrease in fuel expense for nonutility operations
was due to a decrease in kWhs generated as a result of
a scheduled outage at the unit.

     Purchased power and exchanges, net, represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under PURPA, and consists of the
following items:


(Millions of Dollars)               1998      1997      1996

Purchased power:
  Utility operations:
    From PURPA generation*         $129.0    $134.8    $132.7
    Other                            50.0      41.2      47.3

       Total purchased power for
        utility operations          179.0     176.0     180.0
     Power exchanges, net             (.7)       .3       3.3
  Nonutility operations             210.5      43.5       1.1

     Purchased power and
       exchanges, net              $388.8    $219.8    $184.4

*PURPA cost (cents per kWh)           5.4       5.6       5.5


     The decrease in utility purchased power from PURPA
generation in 1998 was due primarily to reduced generation at
hydroelectric plants due to river flow. PURPA purchased power
costs will be reduced $197 million during the period 1999-2016
related to the AES Beaver Valley nonutility generation contract
as a result of the 1998 extraordinary charge. See Notes B and C
to the consolidated financial statements for further information.

                                   M-8

<PAGE>

                                                      Allegheny Energy, Inc.



     The increase in other purchased power in 1998 for utility
operations resulted primarily from increased purchases for sales.
An increase in price caused by volatility in the spot prices for
electricity at the wholesale level in the second and third
quarters of 1998 also contributed to the increase. The decrease
in 1997 was a result of decreased demand due to decreased sales
to retail customers related to mild 1997 weather, as well as
increased availability of the subsidiaries' power stations.

     Nonutility operations purchased power is the result of power
replacement requirements and transaction opportunities by AYP
Energy which began operations in late 1996. The increases in
nonutility purchases in 1998 and 1997 are due primarily to an
increase in volume attributable to AYP Energy's increased
participation in the market and increased prices.

     The AES Warrior Run PURPA cogeneration project in Potomac
Edison's Maryland service territory, scheduled to commence
generation in October 1999, will increase the cost of power
purchases $60 million or more annually. The settlement, described
under Sales and Revenues starting on page 31, is designed to
recover all such costs through 2001.

     Other operation expenses for 1998, 1997, and 1996 were as
follows:


(Millions of Dollars)              1998      1997      1996

Utility operations                 $319.2    $292.3    $298.5
Nonutility operations                18.2      16.7       1.3

Total other operation expenses     $337.4    $309.0    $299.8    


     The increase in utility other operation expenses in 1998 was
due primarily to increased expenses related to competition and
the Pennsylvania restructuring Order ($24.3 million). See Note B
to the consolidated financial statements for additional
information related to Pennsylvania restructuring.

     Utility other operation expenses in 1997 include $3.3
million for increased allowances for uncollectible accounts and
$4.4 million of legal expenses incurred by West Penn to defend
itself against an antitrust lawsuit filed by the developers of
the proposed Washington Power PURPA project. The dispute was
settled in December 1997. Nevertheless, utility other operation
expense decreased in 1997 because of a reduction in embedded
expenses achieved through the 1996 internal restructuring
process. The increase in nonutility other operation expenses was
due to startup expenses incurred by the Company's nonutility
subsidiary, AYP Capital.

     Maintenance expenses for 1998, 1997, and 1996 were
as follows:

                                    M-9


<PAGE>

                                                       Allegheny Energy, Inc.

(Millions of Dollars)              1998      1997      1996

Utility operations                 $212.3    $227.1    $242.5
Nonutility operations                 5.3       3.5        .8

  Total maintenance expenses       $217.6    $230.6    $243.3


     The decrease in utility maintenance in 1998 was due
primarily to a management program to postpone such expenses for
the year in response to limited sales growth in the first quarter
due to the warm winter weather. The Company is postponing these
expenses primarily by extending the time between maintenance
outages. The 1997 decrease in utility maintenance expenses
resulted from reduced expenses achieved through internal
restructuring efforts and other cost controls. Maintenance
expenses represent costs incurred to maintain the power stations,
the transmission and distribution (T&D) system, and general
plant, and reflect routine maintenance of equipment and rights-of-
way, as well as planned major repairs and unplanned expenditures,
primarily from forced outages at the power stations and periodic
storm damage on the T&D system. Variations in maintenance expense
result primarily from unplanned events and planned major
projects, which vary in timing and magnitude depending upon the
length of time equipment has been in service without a major
overhaul and the amount of work found necessary when the
equipment is dismantled. The increases in nonutility maintenance
expense in 1998 and 1997, respectively, were primarily related to
a 1998 planned outage for maintenance of Unit No. 1 of the Fort
Martin power station, 50% owned by AYP Energy, and in 1997 due to
the first full year of AYP Energy operations.

     Internal restructuring charges and an asset write-off in
1996 resulted from internal restructuring activities, which have
been completed, and the write-off of previously accumulated costs
related to a proposed transmission line.

     Depreciation expenses for 1998, 1997, and 1996 were as
follows:

(Millions of Dollars)              1998      1997      1996

Utility operations                 $264.6    $259.1    $263.2
Nonutility operations                 5.8       6.6    

Total depreciation expense         $270.4    $265.7    $263.2


     Higher utility depreciation in 1998 resulted from increased
investment. The decrease in utility depreciation expense in 1997
was the result of a change in the retirement dates for West Penn
for the Mitchell power station and the Pleasants power station
scrubbers. The increase in nonutility depreciation expense in
1997 was the result of depreciation incurred by AYP Energy
because of its purchase in October 1996 of a 50% ownership in
Unit No. 1 of the Fort Martin power station.

                               M-10


<PAGE>

                                                       Allegheny Energy, Inc.


     Taxes other than income taxes for 1998, 1997, and 1996 were
as follows:

(Millions of Dollars)              1998      1997      1996

Utility operations                 $187.7    $181.4    $185.4
Nonutility operations                 6.9       5.6    

  Total taxes other than
    income taxes                   $194.6    $187.0    $185.4

     The increase in utility taxes other than income taxes in
1998 was due primarily to increased West Virginia Business and
Occupation Taxes (B&O) resulting from an adjustment for a prior
period and increased property taxes. The nonutility increase in
1998 was due to gross receipts taxes resulting from higher
revenues from retail customers. The 1997 increase in taxes other
than income taxes was due to an increase in nonutility taxes of
$5.6 million in B&O and property taxes resulting from AYP
Energy's purchase of an ownership interest in the Fort Martin
power station offset by a $4 million decrease in utility taxes
because of a decrease in gross receipts taxes due to lower retail
revenues and lower FICA taxes due to the Company's prior year
internal restructuring.

     The 1997 increase in federal and state income taxes was
primarily due to increased income in 1997 compared with 1996.
Note F to the consolidated financial statements provides a
further analysis of income tax expenses.
The decrease in allowance for other than borrowed funds used
during construction of $2.8 million in 1998 reflects lower-cost
short-term debt financing. The allowance for borrowed funds used
during construction component of the formula receives greater
weighting when short-term debt increases. The decrease also
reflects adjustments of prior periods.

     The decrease in other income, net, of $9.8 million in 1998
and the increase in 1997 of $13.6 million was primarily due to
1997 increases for an interest refund on a tax-related contract
settlement ($8.3 million, net of taxes) and income on the sale of
land ($2.8 million, net of taxes).

     Interest on long-term debt for 1998, 1997, and 1996 was as
follows:

(Millions of Dollars)              1998      1997      1996

Utility operations                 $151.0    $162.8    $164.3
Nonutility operations                10.1      10.8       2.1

  Total interest on long-term
   debt                            $161.1    $173.6    $166.4


     The decrease in interest on long-term debt in 1998 of $12.5
million resulted from reduced long-term debt and lower interest
rates. Interest on nonutility long-term debt in 1997 increased
due to October 1996 bank borrowings of $160 million by AYP Energy
related to its purchase of an ownership interest in the Fort
Martin power station. Other interest expense reflects changes in
the levels of short-term debt maintained by the companies
throughout the year, as well as the associated interest rates.

                               M-11


<PAGE>

                                                        Allegheny Energy, Inc.

     The extraordinary charge of $466.9 million ($275.4 million
after taxes) was required to reflect a write-off of certain
disallowances in the Pennsylvania PUC's May and November 1998
orders as described in Notes B and C to the consolidated
financial statements.

Financial Condition, Requirements, and Resources

Liquidity and Capital Requirements

     To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for their construction programs, the companies have
used internally generated funds and external financings, such as
the sale of common and preferred stock, debt instruments,
installment loans, and lease arrangements. The timing and amount
of external financings depend primarily upon economic and
financial market conditions, the companies' cash needs, and
capitalization ratio objectives. The availability and cost of
external financings depend upon the financial health of the
companies seeking those funds and market conditions.

     Construction expenditures of all the subsidiaries in 1998
were $231 million and, for 1999 and 2000, are estimated at $315
million and $294 million, respectively. The 1999 and 2000
estimated expenditures include $63 million and $85 million,
respectively, for construction of environmental control
technology. It is the Company's goal to constrain future utility
construction spending to the approximate level of depreciation
currently in rates. The subsidiaries also have additional capital
requirements for debt maturities (see Note K to the consolidated
financial statements).

Internal Cash Flow

     Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $381 million in 1998,
compared with $268 million in 1997. Reduced 1997 cash flow was
the result of the $48 million buyout of the Washington Power
PURPA project and payment of internal restructuring liabilities.
Current rate levels and reduced levels of construction
expenditures permitted the subsidiaries to finance all of their
construction expenditures in 1998 and nearly all in 1997 with
internal cash flow. As described under Environmental Issues
starting on page 39, the subsidiaries could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
regulated subsidiaries can continue to meet the majority of their
construction needs with internally generated cash is largely
dependent upon the outcome of these issues.

     Dividends paid on common stock in each of the years 1998 and
1997 were $1.72 per share. The dividend payout ratio, excluding
the extraordinary charge and Pennsylvania settlement costs in
1998, decreased slightly from 1997.

Financing

     The Company did not issue any common stock in 1998. The
shares for its Dividend Reinvestment and Stock Purchase Plan,
Employee Stock Ownership and

                                  M-12


<PAGE>

                                                       Allegheny Energy, Inc.


Savings Plan, and Performance Share Plan were purchased on the
open stock market. Short-term debt is used to meet temporary
cash needs. Short-term debt increased $52.4 million to $258.8
million in 1998. At December 31, 1998, unused lines of credit
with banks were $300 million. The utility subsidiaries anticipate
meeting their 1999 cash needs through internal cash generation,
cash on hand, and short-term borrowings as necessary. However,
West Penn is expected to issue up to $670 million of bonds to
"securitize" transition costs related to its restructuring
settlement described in Note B to the consolidated financial statements.

Significant Continuing Issues

Proposed Merger with DQE

     The Company believes that DQE's basis for seeking to
terminate the merger (described in Note D to the consolidated
financial statements) is without merit. Accordingly, the Company
continues to seek the remaining regulatory approvals from the
Department of Justice and the Securities and Exchange Commission
(SEC). It is not likely either agency will act on the requests
unless the Company obtains judicial relief requiring DQE to move
forward.

Electric Energy Competition

     The electricity supply segment of the electric utility
industry in the United States is in the midst of becoming a
competitive marketplace. The Energy Policy Act of 1992 began the
process of deregulating the wholesale exchange of power within
the electric industry by permitting the FERC to compel electric
utilities to allow third parties to sell electricity to wholesale
customers over their transmission systems. Since 1992, the
wholesale electricity market has become increasingly competitive
as companies began to engage in nationwide power trading. In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries have
investigated or implemented retail access to alternate
electricity suppliers. The Company has been an advocate of
federal legislation to create competition in the retail
electricity markets to avoid regional dislocations and ensure
level playing fields. In the absence of federal legislation,
state-by-state implementation has begun.

     The Customer Choice Act in Pennsylvania has created retail
access to a competitive electric energy market. Pursuant to the
Customer Choice Act, all electric utilities in Pennsylvania were
required in 1998 to establish and administer retail access pilot
programs to 5% of the load of each class of their customers.
Beginning in January 1999, two-thirds of West Penn's customers
were permitted to choose an alternate electricity supplier.
Remaining West Penn customers can do so in January 2000. See Note
B to the consolidated financial statements for additional
information on the settlement agreement reached with the
Pennsylvania PUC, which included transition costs and the ability
to transfer generating assets to an affiliate at net book value.

                                 M-13


<PAGE>

                                                      Allegheny Energy, Inc.


     One result of the Customer Choice Act is the bifurcation of
electricity supply and electricity delivery into two separate
businesses. The transmission and distribution (wires) business
remains under the traditional regulated ratemaking, while the
electricity supply business in Pennsylvania is deregulated, and
its pricing will be determined by the marketplace. The wires
business will have responsibility as the electricity provider of
last resort and will generally obtain its electricity supply from
the market, primarily by competitive bidding. Provider of last
resort service will continue to be regulated and provided at
capped rates. The electricity supply business will be free to
sell West Penn's generation capacity and energy in the open
wholesale and retail market, subject to codes of conduct and the
restriction that it may not sell at retail, except under certain
conditions, in West Penn's service territory through 2003.
Because of these new regulations, West Penn reorganized for 1999
into a Delivery Business (wires) and a Supply Business (marketing
capacity and energy). West Penn's Delivery Business will continue
to provide transmission and distribution service and will bill a
Competitive Transition Charge to native load customers exercising
choice.

     The Maryland PSC in December 1997 issued an Order to
implement retail competition in that state. The Maryland PSC's
Order and its revised second Order call for a deregulation
process, including a three-year phase-in beginning July 1, 2000,
with recovery of prudent transition costs after mitigation. On
September 10, 1998, the Maryland PSC issued a third Order which
clarified certain issues and questions involved with the earlier
orders. A court-approved settlement of appeals of these orders
provides that the Maryland PSC orders are not final. Roundtable
discussions created by the orders have been held since April
1998. The roundtable's final report to the Maryland PSC is due
May 1, 1999, and the Maryland PSC's final Order in connection
with the work of the roundtable is due August 1, 1999. As
required by the Maryland PSC, Potomac Edison, on July 1, 1998,
filed testimony in Maryland's investigation into transition
costs, price protection, and unbundled rates. The filing
requested recovery of transition costs and a surcharge to recover
the cost of the AES Warrior Run cogeneration project which is
scheduled to commence production on October 1, 1999. Hearings are
scheduled to begin in April 1999. Several electricity competition
bills have been introduced in the 1999 legislative session, and
we continue to support bringing customer choice to Maryland
customers.

     Throughout 1998, a Subcommittee of the Virginia General
Assembly studied electric utility restructuring and made
recommendations to the General Assembly. The process led to the
introduction of detailed restructuring legislation in both the
House and Senate in the 1999 session. The legislation would
implement a transition to choice beginning in 2002. The Senate
passed the bill and referred it to the House. We expect the bill
to be signed into law this year.

     In December 1996, the Public Service Commission of West
Virginia (W.Va. PSC) issued an Order initiating a general
investigation regarding the restructuring of the regulated
electric utility industry. A task force was established to
further investigate restructuring issues. Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the

                                M-14


<PAGE>

                                                      Allegheny Energy, Inc.

legislation, and to then submit that plan to the
Legislature for review and possible approval. The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.

     The Public Utilities Commission of Ohio (Ohio PUC) has
continued informal roundtable discussions on issues concerning
competition in the electric utility industry. The Governor
established a legislative committee from members of both the
Senate and House to further review issues regarding deregulation.
Several bills on restructuring and deregulation have been
introduced in the Ohio Legislature and are subject to continuing
hearings and negotiations at the committee level.

     Fully meeting challenges in the emerging competitive
environment will be challenging for the Company unless certain
outmoded and anti-competitive laws, specifically the Public
Utility Holding Company Act of 1935 (PUHCA) and Section 210 of
PURPA, are repealed or significantly revised. The Company
continues to advocate the repeal or reform of PUHCA and PURPA on
the grounds that they are obsolete and anti-competitive, and that
PURPA, in particular, results in utility customers paying above-
market prices for power.

Business Strategy

     Generation will continue to be a core part of the Company's
business. The Company's goal is to grow generation through
building and buying generating facilities. The energy delivery or
wires business will also continue to be a core part of the
Company's business. The Company plans to expand the energy
delivery business primarily through acquisitions of other
electric distribution properties. Existing nonutility businesses,
primarily telecommunications, that are closely tied to our core
business will continue to be developed.

     The Company's settlement agreement in Pennsylvania permitted
the transfer of West Penn's 3,722 MW of generating capacity to a
new, unregulated, wholly owned subsidiary. The Company plans to
transfer these generating assets at book value. The unregulated
generation will be sold in both the wholesale and retail
competitive marketplace, allowing greater earnings growth
potential, subject to market risk, while allowing us to
capitalize on the Company's strengths in the generation business.

     The Company continues to study ways to meet existing  and
future increases in regulated customer demand, including new and
efficient electric technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.


Environmental Issues

     In the normal course of business, the subsidiaries are
subject to various contingencies and uncertainties relating to
their operations and

                               M-15

                                                       Allegheny Energy, Inc.

construction programs, including legal actions and regulations
and uncertainties related to environmental matters.

     The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are being recovered currently from
customers in rates. The Company estimates that its banked
emission allowances will allow it to comply with Phase II sulfur
dioxide (SO2) limits through 2005. Studies to evaluate cost-
effective options to comply with Phase II limits beyond 2005,
including those available in connection with the emission
allowance trading market, are continuing.

     Title I of the CAAA established an Ozone Transport
Commission to ascertain additional nitrogen oxides (NOx)
reductions to allow the Ozone Transport Region (OTR) to meet the
ozone National Ambient Air Quality Standards (NAAQS). Under terms
of a Memorandum of Understanding (MOU) among the OTR states, the
Company's generating stations located in Maryland and
Pennsylvania were required to reduce NOx emissions by
approximately 55% from the 1990 baseline emissions, with a
compliance date of May 1999. Further reductions of 75% from the
1990 baseline may be required by May 2003 under Phase III of the
MOU. However, this reduction will most likely be suspended by the
proposed NOx State Implementation Plan (SIP) call rule discussed
below. While the SIP call is being litigated, the Company is
making preliminary plans to comply by applying NOx reduction
facilities to existing units at various power stations. If
reductions of 75% are required, installation of post-combustion
control technologies would be very expensive. Pennsylvania and
Maryland promulgated regulations to implement Phase II of the MOU
in November 1997 and May 1998, respectively.

     The Ozone Transport Assessment Group issued its final report
in June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998. The EPA's SIP call
rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states. The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis. The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.

     In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included). The petitions claim NOx
emissions from these upwind sources are

                               M-16

                                                       Allegheny Energy, Inc.


preventing their attainment with the ozone standard. In December
1997, the petitioning states and the EPA signed a Memorandum of
Agreement to address these petitions in conjunction with the related
SIP call mentioned above. In October 1998, the EPA proposed approval
of the petitions. However, the EPA believes implementation of the
NOx SIP call will alleviate the need to grant the petitions. The
EPA intends to issue a final rule by April 1999.

     The EPA is required by law to regularly review the NAAQS for
criteria pollutants. Recent court orders in litigation by the
American Lung Association have expedited these reviews. The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997. State attainment
plans to meet the revised standards will not be developed for
several years. Also, in July 1997, the EPA proposed regional haze
regulations to improve visibility in Class I federal areas
(national parks and wilderness areas). If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities. The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.

     The final outcome of the revised ambient standards, Phase
III of the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged by rulemaking,
petition, and/or the litigation process. Implementation dates are
also uncertain at this time, but could be as early as 2003, which
would require substantial capital expenditures in the 1999-2000
period. The Company's construction forecast includes the
expenditure of $360 million of capital costs during the 1999-2003
period to comply with the SIP call.

     Climate change is alleged to be the result of the
atmospheric accumulation of certain gases collectively referred
to as greenhouse gases (GHG), the most significant of which is
carbon dioxide (CO2). Human activities, particularly combustion
of fossil fuels, are alleged to be responsible for this
accumulation of GHG. The Clinton Administration has signed an
international treaty called the Kyoto Protocol, which will
require the United States to reduce emissions of GHG by 7% from
1990 levels in the 2008-2012 time period.  The United States
Senate must ratify the Kyoto Protocol before it enters into
force. The Senate passed a resolution in 1997 that placed two
conditions on entering into any international climate change
treaty. First, any treaty must include all nations, and, second,
any treaty must not cause serious harm to the United States'
economy. The Kyoto Protocol does not appear to satisfy either of
these conditions, and, therefore, the Clinton Administration has
withheld it from consideration by the Senate. Because coal
combustion in power plants produces about 33% of the United
States' CO2 emissions, implementation of the Kyoto Protocol would
raise considerable uncertainty about the future viability of coal
as a fuel source for new and existing power plants.

     The utility subsidiaries previously reported that the EPA
had identified them as potentially responsible parties, along
with approximately 175 others, in a Superfund site subject to
cleanup. A final determination has not been made for the utility
subsidiaries' share of the remediation costs based on the amount
of materials sent to the site. The utility subsidiaries

                               M-17


<PAGE>

                                                        Allegheny Energy, Inc.


have also been named as defendants along with multiple other
defendants in pending asbestos cases involving one or more
plaintiffs. The utility subsidiaries believe that provisions
for liability and insurance recoveries are such that final
resolution of these claims will not have a material effect
on their financial position.

Independent Transmission System Operator

     The Company conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of a proposed merger with DQE. The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998. The Company's membership status remains
conditional upon the outcome of the merger. Many industry
participants, including customers and regulatory authorities,
believe that an entity independent of the utilities which own the
transmission systems is needed to operate the systems to ensure
nondiscriminatory access to the transmission systems by all
users. Should these beliefs result in a mandate, the Company may
either voluntarily or involuntarily sustain membership or achieve
new membership in some form of Independent System Operator.

Year 2000 Readiness Disclosure

     As the Year 2000 (Y2K) approaches, most organizations,
including the Company, could experience serious problems related
to software and various equipment with embedded chips which may
not properly recognize calendar dates. To minimize such problems,
the Company is proceeding with a comprehensive effort to continue
operations without significant problems in 2000 and beyond. An
Executive Task Force is coordinating the efforts of 24 separate
Y2K Teams, representing all business and support units in the
Company.

     In May 1998, the North American Electric Reliability Council
(NERC), of which the Company is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts. The electric utility industry and the
Company have segmented the Y2K problem into the following
components:
-    Computer hardware and software;
-    Embedded chips in various equipment; and
-    Vendors and other organizations on which the Company relies
     for critical materials and services.

     The industry's and the Company's efforts for each of these
three components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.

     The NERC has established a goal of having the industry
achieve a state of Y2K readiness for critical systems by June 30,
1999, and, to monitor progress, requires each utility to prepare
and submit a monthly report showing progress and dated plans. By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to

                              M-18

                                                       Allegheny Energy, Inc.


file contingency plans by that date. The Company's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.

     Integrated electric utilities are uniquely reliant on each
other to avoid, in a worst case situation, cascading failure of
the entire electrical system. The Company is working with the
Edison Electric Institute, the Electric Power Research Institute,
the NERC, and the East Central Area Reliability Agreement group
to capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning. The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is clearly much more
work to be done, we have found that North America's electric
power supply and delivery systems are well on their way to being
Y2K ready."

     The SEC requires that each company disclose its estimate of
the "most reasonably likely worst case scenario" of a negative
Y2K event. Since the Company and the industry are working
diligently to avoid any disruption of electric service, the
Company does not believe it or its customers will experience any
significant long-term disruptions of electric service. It is the
Company's opinion that the "most reasonably likely worst case
scenario" is that there could be isolated problems at various
Company facilities or at the facilities of neighboring utilities
that may have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service. All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.

     The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems. Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions. To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.

     Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors will be
employed for some of the work, the Company believes it must rely
on its own employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $15 to $20 million. Of that amount, about $9
million has been incurred through 1998.

                              M-19


<PAGE>

                                                       Allegheny Energy, Inc.


     The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act. Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995. Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning activities. There
can be no assurance that actual results will not materially
differ from expectations.

                               M-20

                                                     Monongahela Power Company

                    1998 Financial Statements



                                                  Monongahela Power Company
                                                                           
                                                                           
                                                   Part of Allegheny Energy

                               M-21


<PAGE>

                                                   Monongahela Power Company


MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995.  These include
statements with respect to deregulation activities and movements
toward competition in states served by Monongahela Power Company
(the Company), the proposed merger of Allegheny Energy, Inc.
(Allegheny Energy) with DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., and results of
operations.  All such forward-looking information is necessarily
only estimated.  There can be no assurance that actual results
will not materially differ from expectations.  Actual results
have varied materially and unpredictably from past expectations.

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which the Company
operates, including regulatory proceedings affecting rates
charged by the Company; environmental, legislative, and
regulatory changes; future economic conditions; developments
relating to the proposed merger of Allegheny Energy with DQE,
including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.

SIGNIFICANT EVENTS IN 1998, 1997, AND 1996

Merger with DQE

See Page 7 and also Note B to the financial statements for
information about the proposed merger of Allegheny Energy with
DQE.

Internal Restructuring

In 1994, the Allegheny Energy integrated electric utility system
(the System), including the Company, initiated an internal
restructuring process to consolidate and re-engineer their
utility operations to meet the competitive challenges of the
changing electric utility industry.  As a result of this process,
the System reduced employment by about 1,000 employees through a
voluntary separation plan, attrition and layoffs, and changed
processes to obtain efficiencies to reduce operating and
maintenance (O&M) costs.  This process resulted in internal
restructuring charges in 1996 as described in Note C to the
financial statements.

                                M-22


<PAGE>

                                                    Monongahela Power Company

REVIEW OF OPERATIONS

Earnings Summary


(Millions of Dollars)                                      Earnings
                                                    1998     1997     1996

Operations....................................    $82.4    $80.5    $76.1

Expenses related to internal restructuring
  activities..................................                      (14.6)

Net Income....................................    $82.4    $80.5    $61.5


The increase in 1998 earnings from operations resulted from
increased kilowatt-hour (kWh) sales to commercial and industrial
customers and from reduced power station O&M spending.  The 1996
restructuring costs resulted from internal restructuring
initiated in 1994 which is described in Note C to the financial
statements and Internal Restructuring on page 1.  The increase in
1997 earnings from operations resulted primarily from reductions
in O&M expenses from the internal restructuring process and
additional actions taken during the year to achieve further O&M
reductions in response to significant decreases in residential
kWh sales caused primarily by mild weather.  Also contributing to
the increase was additional revenues due to a change in
allocation of affiliated transmission services, increased
generating capacity sales to an affiliate, and an interest refund
on a tax-related contract settlement by the Company's 27% owned
subsidiary, Allegheny Generating Company (AGC), recorded in other
income as increased equity in earnings of AGC.

Sales and Revenues

Percentage changes in revenues and kWh sales in 1998 and 1997 by
major retail customer classes were:

                                   1998 vs. 1997           1997 vs. 1996
                                 Revenues      kWh       Revenues      kWh

Residential.................       0.5%       (0.3)%      (3.0)%     (1.8)%
Commercial..................       6.4         5.8        (2.3)      (1.0)
Industrial..................       6.0         5.5        (2.1)       4.0
  Total.....................       4.0%        4.0 %      (2.5)%      1.3 %


The changes in residential kWh sales, which are more weather
sensitive than the other classes, were due primarily to changes
in customer usage because of weather conditions.  The growth in
the number of residential customers was .6% and .8% in 1998 and
1997, respectively.  The weather in 1997 was mild in both the
early and late winter and in the summer, causing the 1.8%
decrease in residential kWh sales.

                               M-23


<PAGE>

                                                   Monongahela Power Company



Commercial kWh sales are also affected by weather, but to a
lesser extent than residential.  The 5.8% increase in 1998
reflects growth in the number of customers and increased usage.
The increases in industrial kWh sales in 1998 and 1997 were
primarily due to increased sales to one of the Company's
customers who switched an additional portion of their load
requirements to the Company in September 1997.

Changes in revenues from retail customers resulted from the
following:

                                                  Changes from Prior Year
(Millions of Dollars)                         1998 vs. 1997   1997 vs. 1996

Fuel clauses...............................        $11.8         $(10.2)
All other..................................          8.7           (3.0)
  Net change in retail revenues............        $20.5         $(13.2)


Revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy
cost adjustment clauses (fuel clauses) which have little effect
on net income because increases and decreases in fuel and
purchased power costs and sales of transmission services and bulk
power are passed on to customers by adjustment of customers'
bills through fuel clauses.

All other is the net effect of kWh sales changes due to changes
in customer usage (primarily weather for residential customers),
growth in the number of customers, and changes in pricing other
than changes in general tariff and fuel clause rates.  The
increase in 1998 all other retail revenues was primarily the
result of increased customer usage and growth in the number of
customers.  The decrease in 1997 all other retail revenues is
primarily the result of mild weather in 1997.

Wholesale and other revenues were as follows:

(Millions of Dollars)                         1998        1997       1996

Wholesale customers......................    $ 5.2       $ 4.9      $ 5.0
Affiliated companies.....................     77.3        83.6       74.9
Street lighting and other................      6.9         7.1        6.6
  Total wholesale and other revenues.....    $89.4       $95.6      $86.5


Wholesale customers are cooperatives and municipalities that own
their own distribution systems and buy all or part of their bulk
power needs from the Company under Federal Energy Regulatory
Commission (FERC) regulation. Competition in the wholesale market
for electricity was initiated by the National Energy Policy Act
of 1992, which permits wholesale generators, utility-owned and
otherwise, and wholesale customers to request from owners of bulk
power transmission facilities a commitment to supply transmission
services.  All of the Company's wholesale customers have signed
contracts to remain as customers until December 1, 2000.

Revenues from affiliated companies represent sales of energy and
intercompany allocations of generating capacity, generation
spinning reserves, and

                              M-24


<PAGE>

                                                    Monongahela Power Company

transmission services pursuant to a power supply agreement among
the Company and the other regulated utility subsidiaries of
Allegheny Energy.  The decrease in such revenues in 1998 resulted
primarily from decreased generating capacity sales ($4.7 million).
 The increase in 1997 resulted primarily from an increase in the
allocation of transmission services revenues and increased generating
capacity sales ($6.5 million).


Bulk power transactions include sales of bulk power and
transmission services to power marketers and other utilities.
Bulk power and transmission services sales for 1998, 1997, and
1996 were as follows:

                                               1998        1997       1996
KWh Transactions (in billions):
  Bulk power...............................      .3          .3         .2
  Transmission services to
    nonaffiliated companies................     1.9         3.0        4.2
      Total................................     2.2         3.3        4.4

Revenues (in millions):
  Bulk power...............................   $ 8.5       $ 7.3      $ 4.8
  Transmission services to
    nonaffiliated companies................    11.3        10.0       12.6
      Total................................   $19.8       $17.3      $17.4


The 1998 increase in revenues from bulk power was due to
increased sales that occurred primarily in the second quarter as
a result of warm weather which increased the demand and price for
energy.  In 1998, revenues from transmission services were
affected by a revenue refund resulting from a reduction in the
Company's standard transmission rate and rates for ancillary
services which were recently approved by the FERC.  A provision
of $1.7 million for these rate reductions was recorded in 1998,
with the revenues to be refunded to customers in the first
quarter of 1999.

Revenues from transmission services to nonaffiliated companies in
1998 increased, despite decreased transmission services activity.
The increase in revenues was due in part to transmission
services' reservation charges paid to the Company by others for
the right to transmit energy.  Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used.  Revenues from transmission services to
nonaffiliated companies in 1997 decreased due to reduced demand,
primarily because of mild weather.

In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level.  These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh.  The costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to the
fuel and energy cost recovery clauses, either positively or
negatively, depends on whether the Company is a net

                                M-25


<PAGE>

                                                    Monongahela Power Company

buyer or seller of electricity during such periods.  The impact
of such price volatility in June and the third quarter of 1998 was
insignificant to the Company because changes are passed through
to customers through operation of fuel clauses.

Operating Expenses

Fuel expenses increased 1.9% in 1998 due primarily to an increase
in kWhs generated.  The 4.1% increase in 1997 was caused by a
2.4% increase in kWh's generated, a 1.4% increase in average fuel
prices, and a .3% increase in the average heat rate of the
generating stations.  The increases in kWh's generated in 1998
and 1997 were primarily the result of increased retail sales and
bulk power sales to power marketers and other utilities.

Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies and purchases from
qualified facilities under the Public Utility Regulatory Policies
Act of 1978 (PURPA), capacity charges paid to AGC, and other
transactions with affiliates made pursuant to a power supply
agreement whereby each company uses the most economical
generation available in the System at any given time, and
consists of the following items:

(Millions of Dollars)                          1998        1997       1996

Nonaffiliated transactions:
  Purchased power:
    From PURPA generation*................    $65.5       $69.8     $ 69.1
    Other.................................     11.6         9.6       11.3
  Power exchanges, net....................      (.2)         .1         .9
Affiliated transactions:
  AGC capacity charges....................     18.4        18.5       20.2
  Energy and spinning reserve charges.....       .3          .3         .1
    Purchased power and exchanges, net....    $95.6       $98.3     $101.6

*PURPA cost (cents per kWh)                     5.1         5.3        5.3


The decrease in purchased power from PURPA generation in 1998 was
due primarily to reduced generation at hydroelectric plants due
to river flow.  The increase in other purchased power in 1998
resulted primarily from increased purchases for sales.  An
increase in price caused by volatility in the spot prices for
electricity at the wholesale level in the second and third
quarters of 1998 also contributed to the increase.  The decrease
in other purchased power in 1997 was a result of decreased demand
due to decreased sales related to mild 1997 weather.

None of the Company's purchased power contracts are capitalized
since there are no minimum payment requirements absent associated
kWh generation and under a regulated environment recovery of the
costs are reasonably assured.

The increase in other operation expenses in 1998 resulted
primarily from increases in salaries and wages and employee
benefits, increased property insurance expense due in part to a
prior period adjustment, and an increase in expense related to
Year 2000 readiness.  Other operation expenses in 1997

                                  M-26


<PAGE>

                                                    Monongahela Power Company

include $1.7 million for increased allowances for uncollectible
accounts.  Nevertheless, other operation expense decreased in
1997 because of a reduction in embedded expenses achieved through
the 1996 internal restructuring process.

The decrease in maintenance expenses in 1998 was due primarily to
a management program to postpone such expenses for the year in
response to limited sales growth in the first quarter due to the
warm winter weather.  The Company is postponing these expenses
primarily by extending the time between maintenance outages.  The
1997 decrease in maintenance expenses resulted from reduced
expenses achieved through internal restructuring efforts and
other cost controls.  Maintenance expenses represent costs
incurred to maintain the power stations, the transmission and
distribution (T&D) system, and general plant, and reflect routine
maintenance of equipment and rights-of-way, as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the
T&D system.

Variations in maintenance expense result primarily from unplanned
events and planned major projects, which vary in timing and
magnitude depending upon the length of time equipment has been in
service without a major overhaul and the amount of work found
necessary when the equipment is dismantled.

Internal restructuring charges in 1996 resulted from internal
restructuring activities, which have been completed.

Depreciation expense in 1998 and 1997 increased $2.0 million and
$1.1 million, respectively, due to increased investment.

Taxes other than income taxes increased $6.0 million in 1998 due
primarily to West Virginia Business and Occupation Taxes
resulting from an adjustment for a prior period and increased
property taxes.  The decrease in 1997 taxes other than income
taxes was because of a decrease in gross receipts taxes due to
lower retail revenues and lower FICA taxes due to the Company's
prior year internal restructuring.

The increases in federal and state income taxes were primarily
due to increased income before income taxes.  Note D to the
financial statements provides a further analysis of income tax
expenses.

The decrease in other income, net, of $2.4 million in 1998 and
the increase in 1997 of $1.7 million was primarily due to a 1997
interest refund on a tax-related contract settlement ($2.2
million, net of taxes) received by the Company's subsidiary, AGC.

The decrease in interest on long-term debt in 1998 of $3.7
million resulted from reduced long-term debt and lower interest
rates.  Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated interest rates.

                              M-27


<PAGE>

                                                    Monongahela Power Company

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements.  The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives.  The availability and cost of external financings
depend upon the financial health of the companies seeking those
funds and market conditions.

Construction expenditures in 1998 were $73 million and, for 1999
and 2000, are estimated at $76 million and $79 million,
respectively.  The 1999 and 2000 estimated expenditures include
$13 million and $20 million, respectively, for construction of
environmental control technology.  It is the Company's goal to
constrain future construction spending to the approximate level
of depreciation currently in rates.  The Company also has
additional capital requirements for debt maturities (see Note J
to the financial statements).

Internal Cash Flow

Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $108 million in 1998,
compared with $65 million in 1997.  Reduced 1997 cash flow was
primarily the result of the payment of internal restructuring and
other liabilities.  Current rate levels and reduced levels of
construction expenditures permitted the Company to finance all of
its construction expenditures in 1998 and nearly all in 1997 with
internal cash flow.  As described under Environmental Issues
starting on page 9, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues.  Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues.

Financing

Short-term debt is used to meet temporary cash needs.  Short-term
debt, including notes payable to affiliates under the money pool,
decreased $9.3 million to $49.0 million in 1998.  At December 31,
1998, the Company had Securities and Exchange Commission (SEC)
authorization to issue up to $106 million of short-term debt.
The Company and its regulated affiliates use an Allegheny Energy
internal money pool as a facility to accommodate intercompany
short-term borrowing needs, to the extent that certain of the
companies have funds available.  The Company anticipates meeting
its 1999 cash needs through internal cash generation, cash on
hand, and short-term borrowings as necessary.

                             M-28


<PAGE>

                                                    Monongahela Power Company


SIGNIFICANT CONTINUING ISSUES

Proposed Merger with DQE

Allegheny Energy believes that DQE's basis for seeking to
terminate the merger (described in Note B to the financial
statements) is without merit.  Accordingly, Allegheny Energy
continues to seek the remaining regulatory approvals from the
Department of Justice and the SEC.  It is not likely either
agency will act on the request unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.

Electric Energy Competition

The electricity supply segment of the electric utility industry
in the United States is in the midst of becoming a competitive
marketplace.  The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems.  Since 1992, the wholesale
electricity market has become increasingly competitive as
companies began to engage in nationwide power trading.  In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. The Company has been an advocate
of federal legislation to create competition in the retail
electricity markets to avoid regional dislocations and ensure
level playing fields.  In the absence of federal legislation,
state-by-state implementation has begun.

The Company has franchised regulated customers in West Virginia
and Ohio.

In West Virginia, the Public Service Commission of West Virginia
(W.Va. PSC) issued an Order in December 1996 initiating a general
investigation regarding the restructuring of the regulated
electric utility industry.  A task force was established to
further investigate restructuring issues.  Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the legislation, and to then submit that plan to the
Legislature for review and possible approval.  The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.

In Ohio, the Public Utilities Commission of Ohio has continued
informal roundtable discussions on issues concerning competition
in the electric utility industry.  The Governor established a
legislative committee from members of both the Senate and House
to further review issues regarding deregulation.  Several bills
on restructuring and deregulation have been introduced in the
Ohio Legislature and are subject to continuing hearings and
negotiations at the committee level.

The status of electric energy competition in Maryland, Virginia,
and Pennsylvania in which affiliates of the Company serve are as
follows.

                             M-29

<PAGE>

                                                   Monongahela Power Company

In Maryland, the Maryland Public Service Commission (Maryland
PSC) in December 1997 issued an Order to implement retail
competition in that state.  The Maryland PSC's Order and its
revised second Order, call for a deregulation process, including
a three-year phase-in beginning July 1, 2000, with recovery of
prudent transition costs after mitigation.  The Maryland PSC
subsequently issued a third Order which clarified certain issues
and questions involved with the earlier Orders.  A court-approved
settlement of appeals of these Orders provides that the Maryland
PSC Orders are not final.  The Company's Maryland affiliate, The
Potomac Edison Company (Potomac Edison), is subject to these
orders and appeals.

In Virginia, a Subcommittee of the Virginia General Assembly
studied electric utility restructuring and made recommendations
to the General Assembly throughout 1998.  The process led to the
introduction of detailed restructuring legislation in both the
House and Senate in the 1999 session.  The legislation would
implement a transition to choice beginning in 2002.  The Senate
passed the bill and referred it to the House.  It is expected
that the bill will be signed into law this year.  The Company's
affiliate, Potomac Edison, is subject to this action.

In Pennsylvania, the Electricity Generation Customer Choice and
Competition Act has created retail access to a competitive
electric energy market.  The Company's Pennsylvania affiliate,
West Penn Power Company (West Penn), is subject to this Act.
Beginning in January 1999, two-thirds of West Penn's customers
were permitted to choose an alternate electricity supplier.
Remaining West Penn customers can do so in January 2000.  As a
result of a Pennsylvania Public Utility Commission (Pennsylvania
PUC) Order and settlement agreement, West Penn determined that
under the provisions of Statement of Financial Accounting
Standards No. 101, "Accounting for the Discontinuation of
Application of FASB Statement No. 71," in 1998 an extraordinary
charge of $466.9 million ($275.4 million after taxes) was
required to reflect a write-off of certain disallowances.  In
addition, charges of $40.3 million ($23.7 million after taxes)
related to West Penn's revenue refund and energy program payments
were also recorded.

Fully meeting challenges in the emerging competitive environment
will be challenging for the Company unless certain outmoded and
anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 of PURPA, are
repealed or significantly revised.  Allegheny Energy continues to
advocate the repeal or reform of PUHCA and PURPA on the grounds
that they are obsolete and anti-competitive, and that PURPA, in
particular, results in utility customers paying above-market
prices for power.

Business Strategy

Generation will continue to be a core part of Allegheny Energy's
business.  Allegheny Energy's goal is to grow generation through
building and buying generating facilities.  The energy delivery
or wires business will also continue to be a core part of
Allegheny Energy's business.  Allegheny Energy plans to expand
the energy delivery business primarily through acquisitions of
other electric distribution properties.

                              M-30


<PAGE>

                                                   Monongahela Power Company


The settlement agreement for the Company's affiliate, West Penn,
in Pennsylvania permitted the transfer of its 3,722 MW of
generating capacity to a new, unregulated company that is
expected to be a wholly owned subsidiary of West Penn.  West Penn
plans to transfer these generating assets at book value. The
unregulated generation will be sold in both the wholesale and
retail competitive marketplace, allowing greater earnings growth
potential, subject to market risk, while allowing Allegheny
Energy to capitalize on its strengths in the generation business.

Allegheny Energy continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.

Environmental Issues

In the normal course of business, the Company is subject to
various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.
The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are being recovered currently from
customers in rates.  The Company estimates that its banked
emission allowances will allow it to comply with Phase II sulfur
dioxide (SO2) limits through 2005.  Studies to evaluate cost-
effective options to comply with Phase II limits beyond 2005,
including those available in connection with the emission
allowance trading market, are continuing.

Title I of the CAAA established an Ozone Transport Commission to
ascertain additional nitrogen oxides (NOx) reductions to allow
the Ozone Transport Region (OTR) to meet the ozone National
Ambient Air Quality Standards (NAAQS). Under terms of a
Memorandum of Understanding (MOU) among the OTR states, the
Company's generating station located in Pennsylvania was required
to reduce NOx emissions by approximately 55% from the 1990
baseline emissions, with a compliance date of May 1999.  Further
reductions of 75% from the 1990 baseline may be required by May
2003 under Phase III of the MOU.  However, this reduction will
most likely be suspended by the proposed NOx State Implementation
Plan (SIP) call rule discussed below.  While the SIP call is
being litigated, the Company is making preliminary plans to
comply by applying NOx reduction facilities to existing units at
various power stations.  If reductions of 75% are required,
installation of post-combustion control technologies would be
very expensive.  Pennsylvania promulgated regulations to
implement Phase II of the MOU in November 1997.

The Ozone Transport Assessment Group issued its final report in
June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu.  The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998.  The EPA's SIP
call rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone

                             M-31


<PAGE>

                                                   Monongahela Power Company


nonattainment in downwind
states.  The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis.  The final SIP call
rule requires that all state-adopted Nox reduction measures must
be incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003.  The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.

In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included).  The petitions claim NOx
emissions from these upwind sources are preventing their
attainment with the ozone standard.  In December 1997, the
petitioning states and the EPA signed a Memorandum of Agreement
to address these petitions in conjunction with the related SIP
call mentioned above.  In October 1998, the EPA proposed approval
of the petitions.  However, the EPA believes implementation of
the NOx SIP call will alleviate the need to grant the petitions.
The EPA intends to issue a final rule by April 1999.

The EPA is required by law to regularly review the NAAQS for
criteria pollutants.  Recent court orders in litigation by the
American Lung Association have expedited these reviews.  The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997.  State attainment
plans to meet the revised standards will not be developed for
several years.  Also, in July 1997, the EPA proposed regional
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas).  If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities.  The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.

The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time.  All are being challenged by rulemaking,
petition, and/or the litigation process.  Implementation dates
are also uncertain at this time, but could be as early as 2003,
which would require substantial capital expenditures in the 1999-
2000 period.  The Company's construction forecast includes the
expenditure of $96 million of capital costs during the 1999-2003
period to comply with the SIP call.

Climate change is alleged to be the result of the atmospheric
accumulation of certain gases collectively referred to as
greenhouse gases (GHG), the most significant of which is carbon
dioxide (CO2).  Human activities, particularly combustion of
fossil fuels, are alleged to be responsible for this accumulation
of GHG.  The Clinton Administration has signed an international
treaty called the Kyoto Protocol, which will require the United
States to reduce emissions of GHG by 7% from 1990 levels in the
2008-2012 time period.  The United States Senate must ratify the
Kyoto Protocol before it enters into force.  The Senate passed a
resolution in 1997 that placed two conditions on

                              M-32


<PAGE>

                                                   Monongahela Power Company


 entering into
any international climate change treaty.  First, any treaty must
include all nations, and, second, any treaty must not cause
serious harm to the Unites States' economy.  The Kyoto Protocol
does not appear to satisfy either of these conditions, and,
therefore, the Clinton Administration has withheld it from
consideration by the Senate.  Because coal combustion in power
plants produces about 33% of the Unites States' CO2 emissions,
implementation of the Kyoto Protocol would raise considerable
uncertainty about the future viability of coal as a fuel source
for new and existing power plants.

The Company previously reported that the EPA had identified the
Company and its regulated affiliates as potentially responsible
parties, along with approximately 175 others, in a Superfund site
subject to cleanup.  A final determination has not been made for
the Company's share of the remediation costs based on the amount
of materials sent to the site.  The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs.  The Company believes that provisions for liability
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.


Independent Transmission System Operator

Allegheny Energy conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of a proposed merger with DQE.  The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998.  Allegheny Energy's membership status
remains conditional upon the outcome of the merger.  Many
industry participants, including customers and regulatory
authorities, believe that an entity independent of the utilities
which own the transmission systems is needed to operate the
systems to ensure nondiscriminatory access to the transmission
systems by all users.  Should these beliefs result in a mandate,
Allegheny Energy may either voluntarily or involuntarily sustain
membership or achieve new membership in some form of Independent
System Operator.

Year 2000 Readiness Disclosure

As the Year 2000 (Y2K) approaches, most organizations, including
the Company, could experience serious problems related to
software and various equipment with embedded chips which may not
properly recognize calendar dates.  To minimize such problems,
the Company and its affiliates in the System are
proceeding with a comprehensive effort to continue operations
without significant problems in 2000 and beyond.  An Executive
Task Force is coordinating the efforts of 24 separate Y2K Teams,
representing all business and support units in the System.

                            M-33


<PAGE>

                                                   Monongahela Power Company


In May 1998, the North American Electric Reliability Council
(NERC), of which the System is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts.  The electric utility industry and the
System have segmented the Y2K problem into the following
components:

-    Computer hardware and software;

-    Embedded chips in various equipment; and

-    Vendors and other organizations on which the System relies
  for critical materials and services.

The industry's and the System's efforts for each of these three
components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.

The NERC has established a goal of having the industry achieve a
state of Y2K readiness for critical systems by June 30, 1999,
and, to monitor progress, requires each utility to prepare and
submit a monthly report showing progress and dated plans.  By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
file contingency plans by that date.  The System's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.

Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, cascading failure of the
entire electrical system.  The System is working with the Edison
Electric Institute, the Electric Power Research Institute, the
NERC, and the East Central Area Reliability Agreement group to
capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning.  The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is clearly much more
work to be done, we have found that North America's electric
power supply and delivery systems are well on their way to being
Y2K ready."

The SEC requires that each company disclose its estimate of the
"most reasonably likely worst case scenario" of a negative Y2K
event.  Since the Company and the industry are working diligently
to avoid any disruption of electric service, the Company does not
believe it or its customers will experience any significant long-
term disruptions of electric service.  It is the Company's
opinion that the "most reasonably likely worst case scenario" is
that there could be isolated problems at various Company
facilities or at the facilities of neighboring utilities that may
have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service.  All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.

                             M-34


<PAGE>

                                                   Monongahela Power Company


The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems.  Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions.  To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.

Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning.  While outside contractors and equipment vendors will
be employed for some of the work, the Company believes it must
rely on System employees for most of the effort because of their
experience with the Company's systems and equipment.  The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $4 to $5 million. Of that amount, about $2
million has been incurred through 1998.

The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act.  Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995.  Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning activities.  There
can be no assurance that actual results will not materially
differ from expectations.

                               M-35


<PAGE>

                                                  The Potomac Edison Company


                    1998 Financial Statements


                                                 The Potomac Edison Company
                                                                           
                                                                           
                                                   Part of Allegheny Energy
                                                                           

                              M-36


<PAGE>

                                                  The Potomac Edison Company


MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995.  These include
statements with respect to deregulation activities and movements
toward competition in states served by The Potomac Edison Company
(the Company), the proposed merger of Allegheny Energy, Inc.
(Allegheny Energy) with DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., and results of
operations.  All such forward-looking information is necessarily
only estimated.  There can be no assurance that actual results
will not materially differ from expectations.  Actual results
have varied materially and unpredictably from past expectations.

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which the Company
operates, including regulatory proceedings affecting rates
charged by the Company; environmental, legislative, and
regulatory changes; future economic conditions; developments
relating to the proposed merger of Allegheny Energy with DQE,
including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.

SIGNIFICANT EVENTS IN 1998, 1997, AND 1996

Merger with DQE

See Page 8 and also Note B to the financial statements for
information about the proposed merger of Allegheny Energy with
DQE.

Maryland Settlement and Deregulation

The Company reached a settlement agreement with various parties
on the Office of People's Counsel's petition for a reduction in
the Company's Maryland rates.  Further information on the
settlement agreement is provided under Sales and Revenues
starting on page 2.

On July 1, 1998, the Company filed testimony in Maryland's
investigation into transition costs, price protection, and
unbundled rates.  See Electric Energy Competition on page 8 for
more information regarding the restructuring in Maryland.

                               M-37


<PAGE>

                                                  The Potomac Edison Company


Internal Restructuring

In 1994, the Allegheny Energy integrated electric utility system
(the System), including the Company, initiated an internal
restructuring process to consolidate and re-engineer their
utility operations to meet the competitive challenges of the
changing electric utility industry.  As a result of this process,
the System reduced employment by about 1,000 employees through a
voluntary separation plan, attrition and layoffs, and changed
processes to obtain efficiencies to reduce operating and
maintenance  (O&M) costs.  This process resulted in internal
restructuring charges in 1996 as described in Note C to the
financial statements.

REVIEW OF OPERATIONS

Earnings Summary

                                                          Earnings
(Millions of Dollars)                              1998     1997     1996

Operations...................................     $101.5   $95.8    $94.7

Expenses related to internal
  restructuring activities...................                        16.5

Net Income...................................     $101.5   $95.8    $78.2


The increase in 1998 earnings from operations resulted from
increased kilowatt-hour (kWh) sales to retail customers and from
reduced power station O&M spending.  The 1996 restructuring costs
resulted from internal restructuring initiated in 1994 which is
described in Note C to the financial statements and Internal
Restructuring on page 1.  The increase in 1997 earnings from
operations resulted primarily from reductions in O&M expenses
from the internal restructuring process and additional actions
taken during the year to achieve further O&M reductions in
response to significant decreases in kWh sales to residential
customers caused primarily by mild weather.  Also contributing to
the increase was additional revenues due to a change in
allocation of affiliated transmission services and an interest
refund on a tax-related contract settlement by the Company's 28%
owned subsidiary, Allegheny Generating Company (AGC), recorded in
other income as increased equity in earnings of AGC.


Sales and Revenues

Percentage changes in revenues and kWh sales in 1998 and 1997 by
major retail customer classes were:
                                    1998 vs. 1997          1997 vs. 1996
                                  Revenues      kWh      Revenues      kWh

Residential...................      3.1%        2.6%      (7.5)%      (6.7)%
Commercial....................      5.9         7.2        1.3         1.9
Industrial....................      4.3         5.9         .7          .5
  Total.......................      4.1%        5.0%      (3.2)%      (1.9)%


The changes in residential kWh sales, which are more weather
sensitive than the other classes, were due primarily to changes
in customer usage because of

                              M-38


<PAGE>

                                                   The Potomac Edison Company


weather conditions.  The growth in
the number of residential customers was 1.9% and 1.8% in 1998 and
1997, respectively.  The weather in 1997 was mild in both the
early and late winter and in the summer, causing the 6.7%
decrease in residential kWh sales.

Commercial kWh sales are also affected by weather, but to a
lesser extent than residential.  The 7.2% increase in 1998
reflects increased usage due to weather and commercial activity
as well as growth in the number of customers. The 1.9% increase
in 1997 reflects growth in the number of customers.

The increases in industrial kWh sales in 1998 and 1997 reflect a
trend of continued economic growth in the service territory.  The
increase in 1998 also reflects increased sales to paper and
printing customers and to the Eastalco aluminum reduction plant.

On August 7, 1998, the Virginia State Corporation Commission
(Virginia SCC) approved an agreement reached between the Company
and the Staff of the Virginia SCC which reduced base rates for
Virginia customers beginning September 1, 1998, by about $2.5
million annually.  The review of rates was required by an annual
information filing in Virginia.

In 1999, revenues will reflect a reduction for a settlement
agreement with various parties on the Maryland Office of People's
Counsel's petition for a reduction in the Company's Maryland
rates.  The agreement, which includes recognition of costs to be
incurred from the Applied Energy Services (AES) Warrior Run
cogeneration project being developed under the Public Utility
Regulatory Policies Act of 1978 (PURPA), was approved by the
Maryland Public Service Commission (Maryland PSC) on October 27,
1998.  Under the terms of that agreement, the Company will
increase its rates about 4% ($13 million) in each of the years
1999, 2000, and 2001 (a $39 million annual effect in 2001). The
increases are designed to recover additional costs of about $131
million over the period 1999-2001 for capacity purchases from the
AES Warrior Run cogeneration project, net of alleged over-
earnings of $52 million for the same period.  The net effect of
these changes over the 1999-2001 time frame results in a pre-tax
income reduction of $12 million in 1999, $18 million in 2000, and
$22 million in 2001.  In addition, the settlement requires that
the Company share, on a 50% customer, 50% shareholder basis,
earnings above a return on equity of 11.4% for 1999-2001.  This
sharing will occur through an annual true-up.
Changes in revenues from retail customers resulted from the
following:

                                                Changes from Prior Year
(Millions of Dollars)                        1998 vs. 1997   1997 vs. 1996

Fuel clauses.............................        $10.9          $ (9.6)
All other................................         15.4           (11.4)
  Net change in retail revenues..........        $26.3          $(21.0)


Revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy
cost adjustment clauses (fuel clauses) which have little effect
on net income because increases and decreases in fuel and
purchased power costs and sales of transmission services and bulk
power are passed on to customers by adjustment of customers'
bills through fuel clauses.

                              M-39


<PAGE>

                                                  The Potomac Edison Company


All other is the net effect of kWh sales changes due to changes
in customer usage (primarily weather for residential customers),
growth in the number of customers, and changes in pricing other
than changes in general tariff and fuel clause rates.  The
increase in 1998 all other retail revenues was primarily the
result of increased customer usage and growth in the number of
customers.  The decrease in 1997 all other retail revenues is
primarily the result of mild weather in 1997.

Wholesale and other revenues were as follows:

(Millions of Dollars)                          1998        1997        1996

Wholesale customers.......................    $23.5       $26.6       $29.1
Affiliated companies......................      9.4         9.7         2.5
Street lighting and other.................      5.5         2.6         3.3
  Total wholesale and other revenues......    $38.4       $38.9       $34.9


Wholesale customers are cooperatives and municipalities that own
their own distribution systems and buy all or part of their bulk
power needs from the Company under Federal Energy Regulatory
Commission (FERC) regulation.  Competition in the wholesale
market for electricity was initiated by the National Energy
Policy Act of 1992, which permits wholesale generators, utility-
owned and otherwise, and wholesale customers to request from
owners of bulk power transmission facilities a commitment to
supply transmission services.  Five-year contracts have been
signed (one in 1997 with an expiration date in 2002 with
estimated annual revenues of $3 million, and four in 1998 with
expiration dates in 2003 with estimated annual revenues of $19
million) with the Company's wholesale customers allowing the
Company to continue as their wholesale supplier.  The decrease in
wholesale revenues in 1998 was primarily due to the mild 1998
winter weather.  The decrease in wholesale revenues in 1997 was
primarily due to the reduced electricity requirements of one
wholesale customer caused by the shut-down in early 1997 of a
large fiber plant on the wholesale customer's system.

Revenues from affiliated companies represent sales of energy and
intercompany allocations of generating capacity, generation
spinning reserves, and transmission services pursuant to a power
supply agreement among the Company and the other regulated
utility subsidiaries of Allegheny Energy.  The increase in such
revenues in 1997 resulted primarily from an increase in the
allocation of transmission services revenues ($5.3 million) to
the Company.

The increases in street lighting and other revenues in 1998 were
primarily due to the recording in 1998 of pole attachment
revenues for 1998 and 1997.

                               M-40


<PAGE>

                                                   The Potomac Edison Company


Bulk power transactions include sales of bulk power and
transmission services to power marketers and other utilities.
Bulk power and transmission services sales for 1998, 1997, and
1996 were as follows:

                                                 1998        1997        1996
KWh Transactions (in billions):
  Bulk power................................       .4          .4          .3
  Transmission services to
    nonaffiliated companies.................      2.5         4.0         5.6
      Total.................................      2.9         4.4         5.9

Revenues (in millions):
  Bulk power................................    $11.7       $10.0       $ 7.6
  Transmission services to
    nonaffiliated companies.................     14.7        13.6        16.9
      Total.................................    $26.4       $23.6       $24.5

The 1998 increase in revenues from bulk power was due to
increased sales that occurred primarily in the second quarter as
a result of warm weather which increased the demand and price for
energy.  In 1998, revenues from transmission services were
affected by a revenue refund resulting from a reduction in the
Company's standard transmission rate and rates for ancillary
services which were recently approved by the FERC.  A provision
of $2.2 million for these rate reductions was recorded in 1998,
with the revenues to be refunded to customers in the first
quarter of 1999.

Revenues from transmission services to nonaffiliated companies in
1998 increased, despite decreased transmission services activity.
The increase in revenues was due in part to transmission
services' reservation charges paid to the Company by others for
the right to transmit energy.  Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used.  Revenues from transmission services to
nonaffiliated companies in 1997 decreased due to reduced demand,
primarily because of mild weather.

In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level.  These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh.  The costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to the
fuel and energy cost recovery clauses, either positively or
negatively, depends on whether the Company is a net buyer or
seller of electricity during such periods.  The impact of such
price volatility in June and the third quarter of 1998 was
insignificant to the Company because changes are passed through
to customers through operation of fuel clauses.

Operating Expenses

Fuel expenses increased 2.1% in each of the years 1998 and 1997
due to increases in kWhs generated.  The increases in kWhs
generated were primarily the result of increased bulk power sales
to power marketers and other utilities and in 1998 also due to
increased sales to retail customers.

                              M-41


<PAGE>

                                                  The Potomac Edison Company


Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies, capacity charges paid to
AGC, and other transactions with affiliates made pursuant to a
power supply agreement whereby each company uses the most
economical generation available in the System at any given time,
and consists of the following items:

(Millions of Dollars)                            1998       1997       1996

Nonaffiliated transactions:
  Purchased power..........................     $ 15.2     $ 13.2    $ 14.8
  Power exchanges, net.....................        (.1)                 1.7
Affiliated transactions:
  AGC capacity charges.....................       23.8       25.5      26.9
  Other affiliated capacity charges........       42.9       50.8      47.7
  Energy and spinning reserve charges......       56.5       50.7      49.9
    Purchased power and exchanges, net.....     $138.3     $140.2    $141.0


The increase in purchased power in 1998 resulted primarily from
increased purchases for sales.  An increase in price caused by
volatility in the spot prices for electricity at the wholesale
level in the second and third quarters of 1998 also contributed
to the increase.  Purchased power in 1997 decreased because of
decreased demand due to decreased sales to retail customers
related to mild 1997 weather.  The increase in affiliated energy
and spinning reserve charges was due to an increase in retail kWh
sales.

The AES Warrior Run PURPA cogeneration project in the Company's
Maryland service territory, scheduled to commence generation in
October 1999, will increase the cost of power purchases $60
million or more annually.  The settlement, described under Sales
and Revenues starting on page 2, is designed to recover all such
costs through 2001.

The increase in other operation expenses in 1998 resulted
primarily from increased expenses related to competition in
Maryland ($1.6 million), an increase in expense related to Year
2000 Readiness, and increases in salaries and wages and employee
benefits.  These expenses were partially offset by a reduction in
expenses related to provisions for uninsured claims.  Other
operation expenses in 1997 include $1.2 million for increased
allowances for uncollectible accounts.  Nevertheless, other
operation expense decreased in 1997 because of a reduction in
embedded expenses achieved through the 1996 internal
restructuring process.

The decrease in maintenance expenses in 1998 was due primarily to
a management program to postpone such expenses for the year in
response to limited sales growth in the first quarter due to the
warm winter weather.  The Company is postponing these expenses
primarily by extending the time between maintenance outages.  The
1997 decrease in maintenance expenses resulted from reduced
expenses achieved through internal restructuring efforts and
other cost controls.  Maintenance expenses represent costs
incurred to maintain the power stations, the transmission and
distribution (T&D) system, and general plant, and reflect routine
maintenance of equipment and rights-of-way, as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the
T&D system.  Variations in maintenance expense result primarily
from unplanned events and planned major projects, which vary in
timing and magnitude depending upon the length of time equipment
has been

                                M-42


<PAGE>

                                                   The Potomac Edison Company


in service without a major overhaul and the amount of
work found necessary when the equipment is dismantled.

Internal restructuring charges in 1996 resulted from internal
restructuring activities, which have been completed.

Depreciation expense increases resulted from increased
investment.

The increase in taxes other than income taxes of $2 million in
1998 was primarily due to an increase in gross receipts taxes
resulting from greater revenues from retail customers and
increased property taxes.  The increase in taxes other than
income taxes of $1.8 million in 1997 was due to increased
property taxes and capital stock and franchise taxes related to
an increase in the assessment of property in Maryland.

The 1998 and 1997 increases in federal and state income taxes
were primarily due to increased income before taxes. Note D to
the financial statements provides a further analysis of income
tax expenses.

The decrease in allowance for other than borrowed funds used
during construction of $1.1 million in 1998 resulted primarily
from adjustments of prior periods.

The decrease in other income, net, of $4.7 million in 1998 and
the increase in 1997 of $2.2 million was primarily due to a 1997
interest refund on a tax-related contract settlement ($2.5
million, net of taxes) received by the Company's subsidiary, AGC.

The decrease in interest on long-term debt in 1998 of $1.6
million resulted from reduced long-term debt and lower interest
rates.  Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated interest rates.

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements.  The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives.  The availability and cost of external financings
depend upon the financial health of the companies seeking those
funds and market conditions.

Construction expenditures in 1998 were $61 million and, for 1999
and 2000, are estimated at $86 million and $98 million,
respectively.  The 1999 and 2000 estimated expenditures include
$17 million and $22 million, respectively, for construction of
environmental control technology.  It is the Company's goal to
constrain future construction spending to the approximate level
of depreciation currently in rates.  The Company also has
additional capital requirements for debt maturities (see Note I
to the financial statements).

                              M-43


<PAGE>

                                                  The Potomac Edison Company


Internal Cash Flow

Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $187 million in 1998,
compared with $87 million in 1997.  The increase in 1998 cash
flows resulted primarily from a reduction in the level of common
stock dividends payable to its Parent, Allegheny Energy, Inc.
Reduced 1997 cash flow was primarily the result of payment of
internal restructuring liabilities.  Current rate levels and
reduced levels of construction expenditures permitted the Company
to finance all of its construction expenditures in 1998 and 1997
with internal cash flow.  As described under Environmental Issues
starting on page 10, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues.  Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues.

Financing

Short-term debt is used to meet temporary cash needs.  The
Company had no short-term debt outstanding at December 31, 1998
or December 31, 1997.  At December 31, 1998, the Company had
Securities and Exchange Commission (SEC) authorization to issue
up to $130 million of short-term debt.  The Company and its
regulated affiliates use an Allegheny Energy internal money pool
as a facility to accommodate intercompany short-term borrowing
needs, to the extent that certain of the companies have funds
available.  The Company anticipates meeting its 1999 cash needs
through internal cash generation, cash on hand, and short-term
borrowings as necessary.

SIGNIFICANT CONTINUING ISSUES

Proposed Merger with DQE

Allegheny Energy believes that DQE's basis for seeking to
terminate the merger (described in Note B to the financial
statements) is without merit.  Accordingly, Allegheny Energy
continues to seek the remaining regulatory approvals from the
Department of Justice and the SEC.  It is not likely either
agency will act on the request unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.

Electric Energy Competition

The electricity supply segment of the electric utility industry
in the United States is in the midst of becoming a competitive
marketplace.  The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems.  Since 1992, the wholesale
electricity market has become increasingly competitive as
companies began to engage in nationwide power trading.  In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. The Company has been an advocate
of federal legislation to create competition in the retail
electricity markets to avoid regional dislocations and ensure
level playing fields.  In the absence of federal legislation,
state-by-state implementation has begun.

                                 M-44


<PAGE>

                                                  The Potomac Edison Company


The Company has franchised regulated customers in Maryland,
Virginia, and West Virginia.

In Maryland, the Maryland PSC in December 1997 issued an Order to
implement retail competition in that state.  The Maryland PSC's
Order and its revised second Order call for a deregulation
process, including a three-year phase-in beginning July 1, 2000,
with recovery of prudent transition costs after mitigation.  On
September 10, 1998, the Maryland PSC issued a third Order which
clarified certain issues and questions involved with the earlier
Orders. A court-approved settlement of appeals of these orders
provides that the Maryland PSC orders are not final.  Roundtable
discussions created by the Orders have been held since April
1998.  The roundtable's final report to the Maryland PSC is due
May 1, 1999, and the Maryland PSC's final Order in connection
with the work of the roundtable is due August 1, 1999.  As
required by the Maryland PSC, the Company, on July 1, 1998, filed
testimony in Maryland's investigation into transition costs,
price protection, and unbundled rates.  The filing requested
recovery of transition costs and a surcharge to recover the cost
of the AES Warrior Run cogeneration project
which is scheduled to commence production on October 1, 1999.
Hearings are scheduled to begin in April 1999.  Several
electricity competition bills have been introduced in the 1999
legislative session, and we continue to support bringing customer
choice to Maryland customers.

In Virginia, a Subcommittee of the Virginia General Assembly
studied electric utility restructuring and made recommendations
to the General Assembly throughout 1998.  The process led to the
introduction of detailed restructuring legislation in both the
House and Senate in the 1999 session.  The legislation would
implement a transition to choice beginning in 2002.  The Senate
passed the bill and referred it to the House.  We expect the bill
to be signed into law this year.

In West Virginia, the Public Service Commission of West Virginia
(W.Va. PSC) issued an Order in December 1996 initiating a general
investigation regarding the restructuring of the regulated
electric utility industry.  A task force was established to
further investigate restructuring issues.  Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the legislation, and to then submit that plan to the
Legislature for review and possible approval.  The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.

The status of electric energy competition in Ohio and
Pennsylvania in which affiliates of the Company serve are as
follows:

In Ohio, the Public Utilities Commission of Ohio has continued
informal roundtable discussions on issues concerning competition
in the electric utility industry.  The Governor established a
legislative committee from members of both the Senate and House
to further review issues regarding deregulation.  Several bills
on restructuring and deregulation have been introduced in the
Ohio Legislature and are subject to continuing hearings and
negotiations at the committee level.  The Company's affiliate,
Monongahela Power Company, is subject to these discussions and
hearings.

                              M-45


<PAGE>

                                                  The Potomac Edison Company


In Pennsylvania, the Electricity Generation Customer Choice and
Competition Act has created retail access to a competitive
electric energy market.  The Company's Pennsylvania affiliate,
West Penn Power Company (West Penn), is subject to this Act.
Beginning in January 1999, two-thirds of West Penn's customers
were permitted to choose an alternate electricity supplier.
Remaining West Penn customers can do so in January 2000.  As a
result of a Pennsylvania Public Utility Commission (Pennsylvania
PUC) Order and settlement agreement, West Penn determined that
under the provisions of Statement of Financial Accounting
Standards No. 101, "Accounting for the Discontinuation of
Application of FASB Statement No. 71," in 1998 an extraordinary
charge of $466.9 million ($275.4 million after taxes) was
required to reflect a write-off of certain disallowances.  In
addition, charges of $40.3 million ($23.7 million after taxes)
related to West Penn's revenue refund and energy program payments
were also recorded.

Fully meeting challenges in the emerging competitive environment
will be challenging for the Company unless certain outmoded and
anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 of PURPA, are
repealed or significantly revised.  Allegheny Energy continues to
advocate the repeal or reform of PUHCA and PURPA on the grounds
that they are obsolete and anti-competitive, and that PURPA, in
particular, results in utility customers paying above-market
prices for power.

Business Strategy

Generation will continue to be a core part of Allegheny Energy's
business.  Allegheny Energy's goal is to grow generation through
building and buying generating facilities.  The energy delivery
or wires business will also continue to be a core part of
Allegheny Energy's business.  Allegheny Energy plans to expand
the energy delivery business primarily through acquisitions of
other electric distribution properties.

The settlement agreement for the Company's affiliate, West Penn,
in Pennsylvania permitted the transfer of its 3,722 MW of
generating capacity to a new, unregulated company that is
expected to be a wholly owned subsidiary of West Penn.  West Penn
plans to transfer these generating assets at book value. The
unregulated generation will be sold in both the wholesale and
retail competitive marketplace, allowing greater earnings growth
potential, subject to market risk, while allowing Allegheny
Energy to capitalize on its strengths in the generation business.

Allegheny Energy continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.

Environmental Issues

In the normal course of business, the Company is subject to
various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.

                              M-46


<PAGE>

                                                  The Potomac Edison Company


The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are being recovered currently from
customers in rates.  The Company estimates that its banked
emission allowances will allow it to comply with Phase II sulfur
dioxide (SO2) limits through 2005.  Studies to evaluate cost-
effective options to comply with Phase II limits beyond 2005,
including those available in connection with the emission
allowance trading market, are continuing.

Title I of the CAAA established an Ozone Transport Commission to
ascertain additional nitrogen oxides (NOx) reductions to allow
the Ozone Transport Region (OTR) to meet the ozone National
Ambient Air Quality Standards (NAAQS). Under terms of a
Memorandum of Understanding (MOU) among the OTR states, the
Company's generating stations located in Maryland and
Pennsylvania were required to reduce NOx emissions by
approximately 55% from the 1990 baseline emissions, with a
compliance date of May 1999.  Further reductions of 75% from the
1990 baseline may be required by May 2003 under Phase III of the
MOU.  However, this reduction will most likely be suspended by
the proposed NOx State Implementation Plan (SIP) call rule
discussed below.  While the SIP call is being litigated, the
Company is making preliminary plans to comply by applying NOx
reduction facilities to existing units at various power stations.
If reductions of 75% are required, installation of post-
combustion control technologies would be very expensive.
Pennsylvania and Maryland promulgated regulations to implement
Phase II of the MOU in November 1997 and May 1998, respectively.

The Ozone Transport Assessment Group issued its final report in
June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu.  The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998.  The EPA's SIP
call rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states.  The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis.  The final SIP call
rule requires that all state-adopted NOx reduction measures must
be incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003.  The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.

In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included).  The petitions claim NOx
emissions from these upwind sources are preventing their
attainment with the ozone standard.  In December 1997, the
petitioning states and the EPA signed a Memorandum of Agreement
to address these petitions in conjunction with the related SIP
call mentioned above.  In October 1998, the EPA proposed approval
of the petitions.  However, the EPA believes implementation of
the NOx SIP call will alleviate the need to grant the petitions.
The EPA intends to issue a final rule by April 1999.

                              M-47


<PAGE>

                                                  The Potomac Edison Company


The EPA is required by law to regularly review the NAAQS for
criteria pollutants.  Recent court orders in litigation by the
American Lung Association have expedited these reviews.  The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997.  State attainment
plans to meet the revised standards will not be developed for
several years.  Also, in July 1997, the EPA proposed regional
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas).  If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities.  The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.

The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time.  All are being challenged by rulemaking,
petition, and/or the litigation process.  Implementation dates
are also uncertain at this time, but could be as early as 2003,
which would require substantial capital expenditures in the 1999-
2000 period.  The Company's construction forecast includes the
expenditure of $103 million of capital costs during the 1999-2003
period to comply with the SIP call.

Climate change is alleged to be the result of the atmospheric
accumulation of certain gases collectively referred to as
greenhouse gases (GHG), the most significant of which is carbon
dioxide (CO2).  Human activities, particularly combustion of
fossil fuels, are alleged to be responsible for this accumulation
of GHG.  The Clinton Administration has signed an international
treaty called the Kyoto Protocol, which will require the United
States to reduce emissions of GHG by 7% from 1990 levels in the
2008-2012 time period.  The United States Senate must ratify the
Kyoto Protocol before it enters into force.  The Senate passed a
resolution in 1997 that placed two conditions on entering into
any international climate change treaty.  First, any treaty must
include all nations, and, second, any treaty must not cause
serious harm to the Unites States' economy.  The Kyoto Protocol
does not appear to satisfy either of these conditions, and,
therefore, the Clinton Administration has withheld it from
consideration by the Senate.  Because coal combustion in power
plants produces about 33% of the Unites States' CO2 emissions,
implementation of the Kyoto Protocol would raise considerable
uncertainty about the future viability of coal as a fuel source
for new and existing power plants.

The Company previously reported that the EPA had identified the
Company and its regulated affiliates as potentially responsible
parties, along with approximately 175 others, in a Superfund site
subject to cleanup.  A final determination has not been made for
the Company's share of the remediation costs based on the amount
of materials sent to the site.  The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs.  The Company believes that provisions for liability
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.

Independent Transmission System Operator

Allegheny Energy conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of

                             M-48


<PAGE>

                                                  The Potomac Edison Company


a proposed merger with DQE.  The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998.  Allegheny Energy's membership status
remains conditional upon the outcome of the merger.  Many
industry participants, including customers and regulatory
authorities, believe that an entity independent of the utilities
which own the transmission systems is needed to operate the
systems to ensure nondiscriminatory access to the transmission
systems by all users.  Should these beliefs result in a mandate,
Allegheny Energy may either voluntarily or involuntarily sustain
or achieve new membership in some form of Independent System
Operator.

Year 2000 Readiness Disclosure

As the Year 2000 (Y2K) approaches, most organizations, including
the Company, could experience serious problems related to
software and various equipment with embedded chips which may not
properly recognize calendar dates.  To minimize such problems,
the Company and its affiliates in the System are proceeding with
a comprehensive effort to continue operations without significant
problems in 2000 and beyond.  An Executive Task Force is
coordinating the efforts of 24 separate Y2K Teams, representing
all business and support units in the System.

In May 1998, the North American Electric Reliability Council
(NERC), of which the System is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts.  The electric utility industry and the
System have segmented the Y2K problem into the following
components:

Computer hardware and software;

Embedded chips in various equipment; and

Vendors and other organizations on which the System relies for
critical materials and services.

The industry's and the System's efforts for each of these three
components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.

The NERC has established a goal of having the industry achieve a
state of Y2K readiness for critical systems by June 30, 1999,
and, to monitor progress, requires each utility to prepare and
submit a monthly report showing progress and dated plans.  By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
file contingency plans by that date.  The System's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.

Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, cascading failure of the
entire electrical system.  The System is working with the Edison
Electric Institute, the Electric Power Research Institute, the
NERC, and the East Central Area Reliability Agreement group to
capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning.  The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is

                              M-49


<PAGE>

                                                  The Potomac Edison Company


clearly much more work to be done, we have found that North
America's electric power supply and delivery systems are well
on their way to being Y2K ready."

The SEC requires that each company disclose its estimate of the
"most reasonably likely worst case scenario" of a negative Y2K
event.  Since the Company and the industry are working diligently
to avoid any disruption of electric service, the Company does not
believe it or its customers will experience any significant long-
term disruptions of electric service.  It is the Company's
opinion that the "most reasonably likely worst case scenario" is
that there could be isolated problems at various Company
facilities or at the facilities of neighboring utilities that may
have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service.  All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.


The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems.  Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions.  To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.

Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning.  While outside contractors and equipment vendors will
be employed for some of the work, the Company believes it must
rely on System employees for most of the effort because of their
experience with the Company's systems and equipment.  The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $4 to $5 million. Of that amount, about $2
million has been incurred through 1998.

The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act.  Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995.  Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning activities.  There
can be no assurance that actual results will not materially
differ from expectations.

                               M-50


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


                    1998 Financial Statements



                                          West Penn Power Company
                                                                 
                                                                 
                                         Part of Allegheny Energy

                               M-51


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995.  These include
statements with respect to deregulation activities and movements
toward competition in Pennsylvania, the proposed merger of
Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa., and
results of operations.  All such forward-looking information is
necessarily only estimated.  There can be no assurance that
actual results will not materially differ from expectations.
Actual results have varied materially and unpredictably from past
expectations.

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which West Penn Power
Company (the Company) operates, including regulatory proceedings
affecting rates charged by the Company; environmental,
legislative, and regulatory changes; future economic conditions;
developments relating to the proposed merger of Allegheny Energy
with DQE, including expenses that may be incurred in litigation;
and other circumstances that could affect anticipated revenues
and costs such as significant volatility in the market price of
wholesale power, unscheduled maintenance or repair requirements,
weather, and compliance with laws and regulations.

SIGNIFICANT EVENTS IN 1998, 1997, AND 1996

Pennsylvania Deregulation

On November 19, 1998, the Pennsylvania Public Utility Commission
(Pennsylvania PUC) approved a settlement agreement between the
Company and intervenors in the Company's restructuring
proceedings related to legislation in Pennsylvania to provide
customer choice of electric suppliers and deregulate electricity
generation.

As a result of the May 29, 1998, Pennsylvania PUC Order and as
revised by the November 19, 1998, settlement agreement, the
Company determined that under the provisions of Statement of
Financial Accounting Standards No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71," an
extraordinary charge of $466.9 million ($275.4 million after
taxes) was required to reflect a write-off of certain
disallowances.  In addition, charges of $40.3 million ($23.7
million after taxes) related to the Company's revenue refund and
energy program payments were also recorded.

Under the terms of the settlement agreement, two-thirds of the
Company's customers were permitted to choose an alternate
generation supplier beginning in January 1999.  All of the
Company's customers can do so beginning in January 2000.  They
can also choose to remain as a customer at the Company's capped
generation rates or to alternate back and forth.  Under the law,
all electric utilities, including the Company, retain the
responsibility of electricity provider of last resort to all
customers in their respective

                               M-52


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


franchise territories who do not choose an alternate supplier.
See Notes B and C to the consolidated financial statements for
details of the settlement agreement and other information about
the deregulation process.

Merger with DQE

See page 9 and also Note D to the consolidated financial
statements for information about the proposed merger of Allegheny
Energy with DQE.

PURPA Power Project Terminations

On August 26, 1997, and December 3, 1997, the Company announced
that it had negotiated agreements to buy out and settle disputes
with developers of proposed power plants (the Milesburg and
Washington Power projects) for $15 million and $48 million,
respectively, reducing costs over the proposed 30- and 33-year
lives of the projects by an estimated $1.4 billion.  The disputed
projects were being developed under the Public Utility Regulatory
Policies Act of 1978 (PURPA) and would have required the Company
to buy 43 megawatts (MW) and 80 MW of capacity and energy,
respectively, over the lives of the projects at prices well above
current market price estimates.  In 1996, the Company and the
developers of a proposed Shannopin PURPA project reached an
agreement to terminate that project at a buyout price of $31
million.  The Shannopin buyout will reduce the Company's costs
approximately $665 million over 30 years by eliminating the need
to buy the uneconomic power.

Internal Restructuring

In 1994, the Allegheny Energy integrated electric utility system
(the System), including the Company, initiated an internal
restructuring process to consolidate and re-engineer their
utility operations to meet the competitive challenges of the
changing electric utility industry.  As a result of this process,
the System reduced employment by about 1,000 employees through a
voluntary separation plan, attrition and layoffs, and changed
processes to obtain efficiencies to reduce operating and
maintenance (O&M) costs.  This process resulted in internal
restructuring charges and an asset write-off in 1996 as described
in Note E to the consolidated financial statements.


REVIEW OF OPERATIONS

Earnings Summary

                                                          Earnings
(Millions of Dollars)                             1998      1997      1996

Consolidated income before
  restructuring activities...................   $ 136.3    $134.7   $119.9

Costs related to restructuring
  activities, net of taxes*..................     (23.7)             (31.4)
Extraordinary charge, net of taxes (Notes B
  and C to consolidated financial
  statements)................................    (275.4) 
Consolidated Net (Loss) Income...............   $(162.8)   $134.7   $ 88.5

*Pennsylvania deregulation settlement costs in 1998 and internal
restructuring  costs in 1996.

                               M-53


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


The increase in 1998 consolidated income before costs related to
Pennsylvania restructuring and settlement activities, resulted
primarily from increased bulk power transactions and from reduced
power station O&M spending.  The 1998 costs from restructuring
activities and the extraordinary charge are related to
Pennsylvania deregulation and the Pennsylvania restructuring
Order.  These costs are described in Notes B and C to the
consolidated financial statements. The 1996 restructuring costs
resulted from internal restructuring initiated in 1994 which is
described in Note E to the consolidated financial statements and
Internal Restructuring on page 2.  The increase in 1997
consolidated income before restructuring activities resulted
primarily from reductions in O&M expenses from the internal
restructuring process and additional actions taken during the
year to achieve further O&M reductions in response to significant
decreases in residential kilowatt-hour (kWh) sales caused
primarily by mild weather.  The reductions from the internal
restructuring process were offset in part by a change in
allocation of affiliated transmission services which resulted in
higher charges to the Company.  Also contributing to the 1997
increase was a $3.6 million (after tax) interest refund on a tax-
related contract settlement by the Company's 45% owned
subsidiary, Allegheny Generating Company (AGC), recorded in other
income as increased equity in earnings of AGC, a gain on a sale
of land by a subsidiary of $2.8 million (after tax), and
decreased depreciation expense.


Sales and Revenues

Total operating revenues for 1998, 1997, and 1996 were as
follows:

(Millions of Dollars)                           1998       1997       1996

Operating revenues:
  Bundled retail sales....................    $  920.1   $  973.6 $  988.9
  Unbundled retail sales..................        14.0        2.5 
  Wholesale and other*....................        75.7       65.5     67.3
  Bulk power and transmission
    services sales........................        68.9       40.6     32.9
      Total operating revenues............    $1,078.7   $1,082.2 $1,089.1

*Excludes street lighting sales which are
 included in bundled retail sales.                $7.3       $7.0     $7.0


Bundled retail sales revenues (full service sales to retail
customers) include a $25.1 million rate refund from 1998
revenues, pursuant to the terms of the Pennsylvania restructuring
settlement agreement.  This refund to customers will be made in
1999.  Excluding this rate decrease, bundled retail sales
revenues decreased $28.4 million in 1998 primarily due to
previously fully bundled customers participating in the
Pennsylvania pilot by buying energy from another supplier of
their choice.  As a result of the Company's nonutility affiliate,
Allegheny Energy Solutions, being permitted to sell to all
Pennsylvania customers participating in the pilot, Allegheny
Energy was able to recover some of the Company's generation sales
lost as a result of customers participating in the Pennsylvania
pilot program.  Retail sales include sales to residential,
commercial, industrial, and street lighting customers.  Bundled
retail sales revenues were affected by the Electricity Generation
Customer Choice and Competition Act (Customer Choice Act) in
Pennsylvania.  As part of the Customer Choice Act, all utilities
in Pennsylvania were required to administer retail access pilot
programs under

                              M-54


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries

which customers, representing 5% of the load of
each rate class, would choose a generation supplier other than
their own local franchise utility.  As a result, 5% of previously
fully bundled customers participated in the Pennsylvania pilot
program and were required to buy energy from another supplier of
their choice.  The pilot program began on November 1, 1997, and
continued through December 31, 1998.  Unbundled retail sales
revenues represent transmission and distribution revenues from
Pennsylvania pilot customers who chose another supplier to
provide their energy needs.

To assure participation in the pilot program, pilot participants
received an energy credit from their local utility and a price
for energy pursuant to an agreement with an alternate supplier.
The credit established by the Pennsylvania PUC was artificially
high to encourage customer shopping, with the result that the
Company incurred a revenue loss of $6.5 million for the pilot.
The Pennsylvania PUC has approved the Company's pilot compliance
filing and thus has indicated its intent to treat the revenue
loss as a regulatory asset.  Wholesale and other revenues include
an accrual of such revenue losses, as well as sales to wholesale
customers (cooperatives and municipalities that own their own
distribution systems and buy all or part of their bulk power
needs from the Company under Federal Energy Regulatory Commission
(FERC) regulation) and non-kWh revenues.  All of the Company's
wholesale customers have signed contracts to remain as customers
through at least November 2001.

Effective May 1, 1997, as a result of the Customer Choice Act,
the Company obtained Pennsylvania PUC authorization to set its
fuel clause to zero and to roll its then-applicable fuel clause
rates into base rates.  Thereafter, the Company assumed the risks
and benefits of changes in fuel and purchased power costs and
sales of transmission services and bulk power.  The decrease in
1997 bundled retail revenues resulted primarily from a decrease
in the fuel component of revenues and a decrease in residential
kWh sales due to mild weather in 1997.

The increase in wholesale and other revenues in 1998 was due
primarily to  deferred net revenue losses.  The Company recorded
a regulatory asset of $6.4 million in 1998 and $.1 million in
1997 to offset revenue losses suffered as a result of the pilot
program.

Bulk power transactions includes sales of bulk power and
transmission services to power marketers and other utilities.
Bulk power and transmission services sales for 1998, 1997, and
1996 were as follows:

                                                1998       1997       1996
KWh Transactions (in billions):
  Bulk power...............................      2.3        1.0        0.4
  Transmission services to
    nonaffiliated companies................      3.0        5.4        7.6
      Total................................      5.3        6.4        8.0

Revenues (in millions):
  Bulk power...............................     49.6       22.2       10.0
  Transmission services to
    nonaffiliated companies................     19.3       18.4       22.9
      Total................................     68.9       40.6       32.9

                                  M-55


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


The 1998 increase in revenues from bulk power was due to
increased sales that occurred primarily in the second quarter as
a result of warm weather which increased the demand and price for
energy.  In 1998, revenues from transmission services were
affected by a revenue refund resulting from a reduction in the
Company's standard transmission rate and rates for ancillary
services which were recently approved by the FERC.  A provision
of $2.9 million for these rate reductions was recorded in 1998,
with the revenues to be refunded to customers in the first
quarter of 1999.

Revenues from transmission services to nonaffiliated companies in
1998 increased, despite decreased transmission services activity.
The increase in revenues was due in part to transmission
services' reservation charges paid to the Company by others for
the right to transmit energy.  Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used.  Revenues from transmission services to
nonaffiliated companies in 1997 decreased due to reduced demand,
primarily because of mild weather.

In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level.  These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh.  The potential exists for such volatility to significantly
affect the Company's operating results.  The effect may be either
positive or negative, depending on whether the Company is a net
buyer or seller of electricity during such periods, and the open
commitments which exist at such times.

Operating Expenses

Fuel expenses in 1998 and 1997 increased 1.6% and 6.2%,
respectively, due primarily to increases in kWhs generated.  The
increases in kWhs generated were primarily the result of
increased bulk power sales to power marketers and other
utilities.

Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies and purchases from
qualified facilities under PURPA, capacity charges paid to AGC,
and other transactions with affiliates made pursuant to a power
supply agreement whereby each company uses the most economical
generation available in the System at any given time, and
consists of the following items:

(Millions of Dollars)                          1998        1997       1996

Nonaffiliated transactions:
  Purchased power:
    From PURPA generation*................    $ 63.5      $ 65.1    $ 63.6
    Other.................................      23.2        18.4      22.3
  Power exchanges, net....................       (.3)         .2        .7
Affiliated transactions:
  AGC capacity charges....................      31.5        32.4      36.3
  Energy and spinning reserve charges.....       3.4         3.9       4.0
    Purchased power and exchanges, net....    $121.3      $120.0    $126.9

*PURPA cost (cents per kWh)                      5.8         6.0       5.8

                                   M-56


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


The increase in other purchased power in 1998 resulted primarily
from increased purchases for sales.  An increase in price caused
by volatility in the spot prices for electricity at the wholesale
level in the second and third quarters of 1998 also contributed
to the increase.  The decrease in other purchased power in 1997
was a result of decreased demand due to decreased sales to retail
customers related to mild 1997 weather.

None of the Company's purchased power contracts are capitalized
since there are no minimum payment requirements absent associated
kWh generation.

PURPA purchased power costs will be reduced $197 million during
the period 1999-2016 related to the Applied Energy Services
Corporation's Beaver Valley nonutility generation contract as a
result of the 1998 extraordinary charge.  See Notes B and C to
the consolidated financial statements for further information.

The increase in other operation expenses in 1998 was due
primarily to increased expenses related to competition and the
Pennsylvania restructuring Order.  See Note B to the consolidated
financial statements for additional information related to
Pennsylvania restructuring.  The increase in other operation
expenses in 1997 was primarily due to increased transmission
services cost allocations from affiliated companies under the
power supply agreement ($10.1 million) and Pennsylvania pilot-
related expenses.  Other operation expense for 1997 also includes
$4.4 million of legal expenses incurred by the Company to defend
itself against an antitrust lawsuit filed by the developers of
the proposed Washington Power PURPA project.  The dispute was
settled in December 1997.  These expenses more than offset the
reduction in embedded expenses achieved through the 1996 internal
restructuring process.

The decrease in maintenance expenses in 1998 was due primarily to
a management program to postpone such expenses for the year in
response to limited sales growth in the first quarter due to the
warm winter weather.  The Company is postponing these expenses
primarily by extending the time between maintenance outages.  The
1997 decrease in maintenance expenses resulted from reduced
expenses achieved through internal restructuring efforts and
other cost controls.  Maintenance expenses represent costs
incurred to maintain the power stations, the transmission and
distribution (T&D) system, and general plant, and reflect routine
maintenance of equipment and rights-of-way, as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the
T&D system.  Variations in maintenance expense result primarily
from unplanned events and planned major projects, which vary in
timing and magnitude depending upon the length of time equipment
has been in service without a major overhaul and the amount of
work found necessary when the equipment is dismantled.

Internal restructuring charges and an asset write-off in 1996
resulted from internal restructuring activities, which have been
completed, and the write-off of previously accumulated costs
related to a proposed transmission line.

Higher depreciation expense in 1998 resulted from increased
investment.  The decrease in depreciation expense in 1997 was the
result of a change in the retirement dates for the Mitchell power
station and the Pleasants power station scrubbers.

                             M-57


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


The decrease in federal and state income taxes in 1998 resulted
primarily from a decrease in income before taxes, primarily
because of costs related to restructuring activities recorded in
1998.  The 1997 increase in federal and state income taxes was
primarily due to increased income in 1997 compared with 1996.
Note F to the consolidated financial statements provides a
further analysis of income tax expenses.

The decrease in allowance for other than borrowed funds used
during construction of $1.5 million in 1998 reflects lower-cost
short-term debt financing.  The allowance for borrowed funds used
during construction component of the formula receives greater
weighting when short-term debt increases.  The decrease also
reflects adjustments of prior periods.  Starting in July 1998, as
a result of the Pennsylvania restructuring, the Company stopped
accruing allowance for funds used during construction and began
accruing capitalized interest for generation construction
projects.  Capitalized interest is reported within allowance for
borrowed funds used during construction.

The decrease in other income, net, of $6.2 million in 1998 and
the increase in 1997 of $4.1 million was primarily due to 1997
increases for an interest refund on a tax-related contract
settlement ($3.6 million, net of taxes) received by the Company's
subsidiary, AGC, and income on the sale of land ($2.8 million,
net of taxes) by the Company's subsidiary, West Virginia Power
and Transmission Company.

The decrease in interest on long-term debt in 1998 of $3.3
million resulted from reduced long-term debt and lower interest
rates.

Other interest expense reflects changes in the levels of short-
term debt maintained by the Company throughout the year, as well
as the associated interest rates.  The decrease in other interest
expense in 1997 resulted primarily from decreased interest due to
reduced overcollections of the fuel cost portion of customer
billings.

The extraordinary charge of $466.9 million ($275.4 million after
taxes) was required to reflect a write-off of certain
disallowances in the Pennsylvania PUC's May and November 1998
Orders as described in Notes B and C to the consolidated
financial statements.

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements.  The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives.  The availability and cost of external financings
depend upon the financial health of the companies seeking those
funds and market conditions.

Construction expenditures in 1998 were $96 million and, for 1999
and 2000, are estimated at $119 million and $106 million,
respectively.  The 1999 and 2000 estimated expenditures include
$33 million and $43 million, respectively, for construction of
environmental control technology.  It is

                                 M-58


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


the Company's goal to constrain future utility construction
spending to the approximate level of depreciation currently
in rates.  The Company also has additional capital requirements
for debt maturities (see Note L to the consolidated financial statements).


Internal Cash Flow

Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $151 million in 1998,
compared with $103 million in 1997.  Reduced 1997 cash flow was
the result of the $48 million buyout of the Washington Power
PURPA project and payment of internal restructuring liabilities.
Current rate levels and reduced levels of construction
expenditures permitted the Company to finance all of its
construction expenditures in 1998 and nearly all in 1997 with
internal cash flow.  As described under Environmental Issues
starting on page 11, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues.  Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues.

Financing

Short-term debt is used to meet temporary cash needs.  Short-term
debt, including notes payable to affiliates under the money pool,
increased $13 million to $65 million in 1998.  At December 31,
1998, the Company had Securities and Exchange Commission (SEC)
authorization to issue up to $182 million of short-term debt.
The Company and its regulated affiliates use an Allegheny Energy
internal money pool as a facility to accommodate intercompany
short-term borrowing needs, to the extent that certain of the
companies have funds available.  The Company anticipates meeting
its 1999 cash needs through internal cash generation, cash on
hand, and short-term borrowings as necessary.  However, the
Company is expected to issue up to $670 million of bonds to
"securitize" transition costs related to its restructuring
settlement described in Note B to the consolidated financial
statements.

SIGNIFICANT CONTINUING ISSUES

Proposed Merger with DQE

Allegheny Energy believes that DQE's basis for seeking to
terminate the merger (described in Note D to the consolidated
financial statements) is without merit.  Accordingly, Allegheny
Energy continues to seek the remaining regulatory approvals from
the Department of Justice and the SEC.  It is not likely either
agency will act on the requests unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.

Electric Energy Competition

The electricity supply segment of the electric utility industry
in the United States is in the midst of becoming a competitive
marketplace.  The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems.  Since 1992, the wholesale
electricity market has become increasingly competitive as
companies began to

                              M-59


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


engage in nationwide power trading.  In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. Allegheny Energy has been an
advocate of federal legislation to create competition in the
retail electricity markets to avoid regional dislocations and
ensure level playing fields.  In the absence of federal
legislation, state-by-state implementation has begun.

The Customer Choice Act in Pennsylvania has created retail access
to a competitive electric energy market.  Pursuant to the
Customer Choice Act, all electric utilities in Pennsylvania were
required in 1998 to establish and administer retail access pilot
programs to 5% of the load of each class of their customers.
Beginning in January 1999, two-thirds of the Company's customers
were permitted to choose an alternate electricity supplier.
Remaining Company customers can do so in January 2000.  See Note
B to the consolidated financial statements for additional
information on the settlement agreement reached with the
Pennsylvania PUC, which included transition costs and the ability
to transfer generating assets to an affiliate at net book value.

One result of the Customer Choice Act is the bifurcation of
electricity supply and electricity delivery into two separate
businesses.  The transmission and distribution (wires) business
remains under the traditional regulated ratemaking, while the
electricity supply business in Pennsylvania is deregulated, and
its pricing will be determined by the marketplace.  The wires
business will have responsibility as the electricity provider of
last resort and will generally obtain its electricity supply from
the market, primarily by competitive bidding.  Provider of last
resort service will continue to be regulated and provided at
capped rates.  The electricity supply business will be free to
sell the Company's generation capacity and energy in the open
wholesale and retail market, subject to codes of conduct and the
restriction that it may not sell at retail, except under certain
conditions, in the Company's service territory through 2003.
Because of these new regulations, the Company reorganized for
1999 into a Delivery Business (wires) and a Supply Business
(marketing capacity and energy).  The Company's Delivery Business
will continue to provide transmission and distribution service
and will bill a Competitive Transition Charge to native load
customers exercising choice.

The status of electric energy competition in Maryland, Virginia,
West Virginia, and Ohio in which affiliates of the Company serve
are as follows.

In Maryland, the Maryland Public Service Commission (Maryland
PSC) in December 1997 issued an Order to implement retail
competition in that state.  The Maryland PSC's Order and its
revised second Order, call for a deregulation process, including
a three-year phase-in beginning July 1, 2000, with recovery of
prudent transition costs after mitigation.  The Maryland PSC
subsequently issued a third Order which clarified certain issues
and questions involved with the earlier Orders.  A court-approved
settlement of appeals of these Orders provides that the Maryland
PSC Orders are not final.  The Company's Maryland affiliate, The
Potomac Edison Company, is subject to these orders and appeals.

In Virginia, a Subcommittee of the Virginia General Assembly
studied electric utility restructuring and made recommendations
to the General Assembly throughout 1998.  The process led to the
introduction of detailed

                              M-60


<PAGE>

                                                   West Penn Power Company
                                                          and Subsidiaries


restructuring legislation in both the
House and Senate in the 1999 session.  The legislation would
implement a transition to choice beginning in 2002.  The Senate
passed the bill and referred it to the House.  It is expected
that the bill will be signed into law this year.  The Company's
affiliate, The Potomac Edison Company, is subject to this action.

In West Virginia, the Public Service Commission of West Virginia
(W.Va. PSC) issued an Order in December 1996 initiating a general
investigation regarding the restructuring of the regulated
electric utility industry.  A task force was established to
further investigate restructuring issues.  Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the legislation, and to then submit that plan to the
Legislature for review and possible approval.  The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.  The Company's affiliates,
Monongahela Power Company and The Potomac Edison Company, are
subject to this restructuring plan.

In Ohio, the Public Utilities Commission of Ohio has continued
informal roundtable discussions on issues concerning competition
in the electric utility industry.  The Governor established a
legislative committee from members of both the Senate and House
to further review issues regarding deregulation.  Several bills
on restructuring and deregulation have been introduced in the
Ohio Legislature and are subject to continuing hearings and
negotiations at the committee level.  The Company's affiliate,
Monongahela Power Company, is subject to these discussions and
hearings.

Fully meeting challenges in the emerging competitive environment
will be challenging for Allegheny Energy unless certain outmoded
and anti-competitive laws, specifically the Public Utility
Holding Company Act of 1935 (PUHCA) and Section 210 of PURPA, are
repealed or significantly revised.  Allegheny Energy continues to
advocate the repeal or reform of PUHCA and PURPA on the grounds
that they are obsolete and anti-competitive, and that PURPA, in
particular, results in utility customers paying above-market
prices for power.

Business Strategy

Generation will continue to be a core part of Allegheny Energy's
business.  Allegheny Energy's goal is to grow generation through
building and buying generating facilities.  The energy delivery
or wires business will also continue to be a core part of
Allegheny Energy's business.  Allegheny Energy plans to expand
the energy delivery business primarily through acquisitions of
other electric distribution properties.

The Company's settlement agreement in Pennsylvania permitted the
transfer of the Company's 3,722 MW of generating capacity to a
new, unregulated, company that is expected to be a wholly owned
subsidiary.  The Company plans to transfer these generating
assets at book value.  The unregulated generation will be sold in
both the wholesale and retail competitive marketplace, allowing
greater earnings growth potential, subject to market risk, while
allowing Allegheny Energy to capitalize on its strengths in the
generation business.

Allegheny Energy continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric

                               M-61


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.

Environmental Issues

In the normal course of business, the Company is subject to
various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.

The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are being recovered currently from
customers in rates.  The Company estimates that its banked
emission allowances will allow it to comply with Phase II sulfur
dioxide (SO2) limits through 2005.  Studies to evaluate cost-
effective options to comply with Phase II limits beyond 2005,
including those available in connection with the emission
allowance trading market, are continuing.

Title I of the CAAA established an Ozone Transport Commission to
ascertain additional nitrogen oxides (NOx) reductions to allow
the Ozone Transport Region (OTR) to meet the ozone National
Ambient Air Quality Standards (NAAQS). Under terms of a
Memorandum of Understanding (MOU) among the OTR states, the
Company's generating station located in Pennsylvania was required
to reduce NOx emissions by approximately 55% from the 1990
baseline emissions, with a compliance date of May 1999.  Further
reductions of 75% from the 1990 baseline may be required by May
2003 under Phase III of the MOU.  However, this reduction will
most likely be suspended by the proposed NOx State Implementation
Plan (SIP) call rule discussed below.  While the SIP call is
being litigated, the Company is making preliminary plans to
comply by applying NOx reduction facilities to existing units at
various power stations.  If reductions of 75% are required,
installation of post-combustion control technologies would be
very expensive.  Pennsylvania promulgated regulations to
implement Phase II of the MOU in November 1997.

The Ozone Transport Assessment Group issued its final report in
June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu.  The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998.  The EPA's SIP
call rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states.  The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis.  The final SIP call
rule requires that all state-adopted Nox reduction measures must
be incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003.  The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.

                             M-62


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries


In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included).  The petitions claim NOx
emissions from these upwind sources are preventing their
attainment with the ozone standard.  In December 1997, the
petitioning states and the EPA signed a Memorandum of Agreement
to address these petitions in conjunction with the related SIP
call mentioned above.  In October 1998, the EPA proposed approval
of the petitions.  However, the EPA believes implementation of
the NOx SIP call will alleviate the need to grant the petitions.
The EPA intends to issue a final rule by April 1999.

The EPA is required by law to regularly review the NAAQS for
criteria pollutants.  Recent court orders in litigation by the
American Lung Association have expedited these reviews.  The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997.  State attainment
plans to meet the revised standards will not be developed for
several years.  Also, in July 1997, the EPA proposed regional
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas).  If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities.  The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.

The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time.  All are being challenged by rulemaking,
petition, and/or the litigation process.  Implementation dates
are also uncertain at this time, but could be as early as 2003,
which would require substantial capital expenditures in the 1999-
2000 period.  The Company's construction forecast includes the
expenditure of $147 million of capital costs during the 1999-2003
period to comply with the SIP call.

Climate change is alleged to be the result of the atmospheric
accumulation of certain gases collectively referred to as
greenhouse gases (GHG), the most significant of which is carbon
dioxide (CO2).  Human activities, particularly combustion of
fossil fuels, are alleged to be responsible for this accumulation
of GHG.  The Clinton Administration has signed an international
treaty called the Kyoto Protocol, which will require the United
States to reduce emissions of GHG by 7% from 1990 levels in the
2008-2012 time period.  The United States Senate must ratify the
Kyoto Protocol before it enters into force.  The Senate passed a
resolution in 1997 that placed two conditions on entering into
any international climate change treaty.  First, any treaty must
include all nations, and, second, any treaty must not cause
serious harm to the Unites States' economy.  The Kyoto Protocol
does not appear to satisfy either of these conditions, and,
therefore, the Clinton Administration has withheld it from
consideration by the Senate.  Because coal combustion in power
plants produces about 33% of the Unites States' CO2 emissions,
implementation of the Kyoto Protocol would raise considerable
uncertainty about the future viability of coal as a fuel source
for new and existing power plants.

The Company previously reported that the EPA had identified the
Company and its regulated affiliates as potentially responsible
parties, along with approximately 175 others, in a Superfund site
subject to cleanup.  A final determination has not been made for
the Company's share of the remediation costs based on the amount
of materials sent to the site.  The Company and its

                              M-63


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


regulated affiliates have also been named as defendants along
with multiple other defendants in pending asbestos cases
involving one or more plaintiffs.  The Company believes that
provisions for liability and insurance recoveries are such that
final resolution of these claims will not have a material effect
on its financial position.

Independent Transmission System Operator

Allegheny Energy conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of a proposed merger with DQE.  The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998.  Allegheny Energy's membership status
remains conditional upon the outcome of the merger.  Many
industry participants, including customers and regulatory
authorities, believe that an entity independent of the utilities
which own the transmission systems is needed to operate the
systems to ensure nondiscriminatory access to the transmission
systems by all users.  Should these beliefs result in a mandate,
Allegheny Energy may either voluntarily or involuntarily sustain
membership or achieve new membership in some form of Independent
System Operator.

Year 2000 Readiness Disclosure

As the Year 2000 (Y2K) approaches, most organizations, including
the Company, could experience serious problems related to
software and various equipment with embedded chips which may not
properly recognize calendar dates.  To minimize such problems,
the Company and its affiliates in the System are proceeding with
a comprehensive effort to continue operations without significant
problems in 2000 and beyond.  An Executive Task Force is
coordinating the efforts of 24 separate Y2K Teams, representing
all business and support units in the System.

In May 1998, the North American Electric Reliability Council
(NERC), of which the System is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts.  The electric utility industry and the
System have segmented the Y2K problem into the following
components:

Computer hardware and software;

Embedded chips in various equipment; and

Vendors and other organizations on which the System relies for
critical materials and services.

The industry's and the System's efforts for each of these three
components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.

The NERC has established a goal of having the industry achieve a
state of Y2K readiness for critical systems by June 30, 1999,
and, to monitor progress, requires each utility to prepare and
submit a monthly report showing progress and dated plans.  By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
file contingency plans by

                               M-64


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


that date.  The System's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.

Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, cascading failure of the
entire electrical system.  The System is working with the Edison
Electric Institute, the Electric Power Research Institute, the
NERC, and the East Central Area Reliability Agreement group to
capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning.  The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is clearly much more
work to be done, we have found that North America's electric
power supply and delivery systems are well on their way to being
Y2K ready."

The SEC requires that each company disclose its estimate of the
"most reasonably likely worst case scenario" of a negative Y2K
event.  Since the Company and the industry are working diligently
to avoid any disruption of electric service, the Company does not
believe it or its customers will experience any significant long-
term disruptions of electric service.  It is the Company's
opinion that the "most reasonably likely worst case scenario" is
that there could be isolated problems at various Company
facilities or at the facilities of neighboring utilities that may
have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service.  All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.

The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems.  Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions.  To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.

Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning.  While outside contractors and equipment vendors will
be employed for some of the work, the Company believes it must
rely on System employees for most of the effort because of their
experience with the Company's systems and equipment.  The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $7 to $10 million. Of that amount, about $4
million has been incurred through 1998.

The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act.  Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995.  Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning

                              M-65


<PAGE>

                                                    West Penn Power Company
                                                           and Subsidiaries

activities.  There can be no assurance that actual results will
not materially differ from expectations.

                                M-66


<PAGE>

                                                Allegheny Generating Company

                    1998 Financial Statements



                                     Allegheny Generating Company
                                                                 
                                                                 
                                         Part of Allegheny Energy


                                 M-67


<PAGE>

                                               Allegheny Generating Company


MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

FACTORS THAT MAY AFFECT FUTURE RESULTS

This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995.  All such forward-
looking information is necessarily only estimated.  There can be
no assurance that actual results will not materially differ from
expectations.  Actual results have varied materially and
unpredictably from past expectations.

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which Allegheny
Generating Company (the Company) operates, including regulatory
proceedings affecting rates charged by the Company;
environmental, legislative, and regulatory changes; future
economic conditions; developments relating to the proposed merger
of Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc.
(DQE), parent company of Duquesne Light Company in Pittsburgh,
Pa.; and other circumstances that could affect anticipated
revenues and costs such as unscheduled maintenance or repair
requirements and compliance with laws and regulations.

SIGNIFICANT EVENTS IN 1998, 1997, AND 1996

See page 3 and also Note B to the financial statements for
information about the proposed merger of Allegheny Energy with
DQE.

REVIEW OF OPERATIONS

As described under Liquidity and Capital Requirements, revenues
are determined under a cost-of-service formula rate schedule.
Revenues are expected to decrease each year due to a normal
continuing reduction in the Company's net investment in the Bath
County station and its connecting transmission facilities upon
which the return on investment is determined.  The net investment
(primarily net plant less deferred income taxes) decreases to the
extent that provisions for depreciation and deferred income taxes
exceed net plant additions.  Revenues for 1998 and 1997 decreased
due to a reduction in net investment and reduced operating
expenses.

The decrease in operating expenses in 1998 and 1997 resulted from
a decrease in federal income taxes due to a decrease in operating
income before taxes, exclusive of other income which is reported
net of taxes combined with a decrease in operation and
maintenance expense.

Effective June 1, 1995, the Federal Energy Regulatory Commission
(FERC) gave approval for the Company to add a prior tax payment
of approximately $12 million to rate base.  In September 1997,
the Company received a tax-related contract settlement of $8.8
million of taxes related to the $12 million added to rate base

                               M-68


<PAGE>

                                               Allegheny Generating Company

in 1995.  The 1997 settlement amount was recorded as a reduction
to plant and was removed from rate base.

The increase in other income, net in 1997 was due to interest on
the refund on the tax-related contract settlement (see above).

The decrease in interest on long-term debt in 1998 and 1997 was
primarily the result of a decrease in the average amount of long-
term debt outstanding.

The increase in other interest expense in 1998 was due to an
increased level of short-term debt maintained by the Company upon
retirement of medium-term debt.

LIQUIDITY AND CAPITAL REQUIREMENTS

The Company's only operating assets are an undivided 40% interest
in the Bath County (Virginia) pumped-storage hydroelectric
station and its connecting transmission facilities.  The Company
has no plans for construction of any other major facilities.

Pursuant to an agreement, Monongahela Power Company, The Potomac
Edison Company, and West Penn Power Company (the Parents), buy
all of the Company's capacity in the station priced under a "cost-
of-service formula" wholesale rate schedule approved by the FERC.
Under this arrangement, the Company recovers in revenues all of
its operation and maintenance expenses, depreciation, taxes, and
a return on its investment.  On December 29, 1998, the FERC
issued an Order accepting a proposed amendment to the Parent's
Power Supply Agreement for the Company effective January 1, 1999.
This amendment sets the generation demand for each Parent
proportional to its ownership in the Company.  Previously, demand
for each Parent fluctuated due to customer usage.

The Company's rates are set by a formula filed with and
previously accepted by the FERC.  The only component which
changes is the return on equity (ROE).  Pursuant to a settlement
agreement filed with and approved by the FERC, the Company's ROE
is set at 11% and will continue at that rate unless any affected
party seeks a change.

As previously reported, the Company has received authority from
the Securities and Exchange Commission (SEC) to pay common
dividends from time to time through December 31, 2001, out of
capital to the extent permitted under applicable corporation law
and any applicable financing agreements which restrict
distributions to shareholders.  Due to the nature of being a
single asset company with declining capital needs, the Company
systematically reduces capitalization each year as its asset
depreciates.  This has resulted in the payment of dividends in
excess of current earnings out of other paid-in capital and the
reduction of retained earnings to zero.  The Company's goal is to
retire debt and pay dividends in amounts necessary to maintain a
common equity position of about 45%, including short-term debt.
The payment of dividends out of capital surplus will not be
detrimental to the financial integrity or working capital of
either the Company or its Parents, nor will it adversely affect
the protections due debt security holders.

                                M-69


<PAGE>

                                               Allegheny Generating Company


An Allegheny Energy internal money pool accommodates intercompany
short-term borrowing needs to the Company to the extent that
Allegheny Energy and the Company's Parents have funds available.
To the extent funds are not available from the money pool, the
Company borrows from external sources.


SIGNIFICANT CONTINUING ISSUES

Proposed Merger with DQE

Allegheny Energy, Inc., (Allegheny Energy) parent of the
Company's parents, believes that DQE's basis for seeking to
terminate the merger (described in Note B to the financial
statements) is without merit.  Accordingly, Allegheny Energy
continues to seek the remaining regulatory approvals from the
Department of Justice and the SEC.  It is not likely either
agency will act on the requests unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.

Year 2000 Readiness Disclosure

The Company and its Parents have spent considerable time and
effort over the past several years on the issue of the Year 2000
(Y2K) software compliance, and the effort is continuing.  Certain
software has already been made year 2000 compliant by upgrades
and replacement, and analysis is continuing on others, in
accordance with a schedule planned to permit the Company and its
Parents to process information in the year 2000 and beyond
without significant problems.  Expenditures for year 2000
compliance are not expected to have a material effect on the
Company's results of operations or financial position.

As described in the second paragraph under Liquidity and Capital
Requirements above, the Company's results of operations are
primarily related to recovery of fixed capital costs under
contract with its Parents and therefore are not affected by the
operation, or non-operation, of the Bath County station and
related transmission facilities.

                                 M-70


<PAGE>

                                  48


ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements



                                              Index

                                            Monon-  Potomac  West
                                     AE     gahela  Edison   Penn    AGC

Report of Independent Accountants    F- 1    F-26    F-41    F-56    F-77

Statement of Income for
  the three years ended
  December 31, 1998                  F- 2    F-27    F-42    F-57    F-78
Statement of Retained Earnings
  for the three years ended
  December 31, 1998                   -      F-27    F-42    F-57    F-78

Statement of Cash Flows for
  the three years ended
  December 31, 1998                  F- 3    F-28    F-43    F-58    F-79

Balance Sheet at December 31,
  1998 and 1997                      F- 4    F-29    F-44    F-59    F-80

Statement of Capitalization at
  December 31, 1998 and 1997         F- 5    F-30    F-45    F-60    F-80

Statement of Common Equity for
  the three years ended
  December 31, 1998                  F- 6     -       -       -       -

Notes to financial statements        F- 7    F-31    F-46    F-61    F-81

Financial Statement Schedules -
  Schedules for the three years
  ended December 31, 1998             49      49      49      49      49

II Valuation and qualifying
  accounts                            S-1     S-2     S-3     S-4      -


<PAGE>

                                                      Allegheny Energy, Inc.


REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors and the Shareholders
of Allegheny Energy, Inc.

     In our opinion, the accompanying consolidated balance sheet,
consolidated  statements of capitalization and of  common  equity
and  the  related consolidated statements of income and  of  cash
flows  present  fairly, in all material respects,  the  financial
position  of  Allegheny  Energy, Inc.  and  its  subsidiaries  at
December  31, 1998 and 1997, and the results of their  operations
and  their  cash flows for each of the three years in the  period
ended  December  31, 1998, in conformity with generally  accepted
accounting  principles.  These  financial  statements   are   the
responsibility of the Company's management; our responsibility is
to  express an opinion on these financial statements based on our
audits. We conducted our audits of these statements in accordance
with generally accepted auditing standards which 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,   assessing  the  accounting  principles   used   and
significant  estimates  made by management,  and  evaluating  the
overall  financial statement presentation. We  believe  that  our
audits  provide  a  reasonable basis for  the  opinion  expressed
above.




PricewaterhouseCoopers LLP


Pittsburgh, Pennsylvania
February 4, 1999

                                F-1


<PAGE>

                                                      Allegheny Energy, Inc.


Consolidated Statement of Income

<TABLE>
<CAPTION>

Year ended December 31                                 1998           1997           1996
(Thousands of Dollars Except Per Share Data)

Operating Revenues:
<S>                                                <C>            <C>            <C>
Utility                                            $  2,329,450   $  2,283,697   $  2,326,902
Nonutility                                              246,986         85,794            747
     Total Operating Revenues                         2,576,436      2,369,491      2,327,649

Operating Expenses:
Operation:
  Fuel                                                  566,453        559,939        513,210
  Purchased power and exchanges, net                    388,758        219,837        184,357
  Deferred power costs, net                              (6,639)       (22,916)        15,621
  Other                                                 337,440        308,991        299,817
Maintenance                                             217,559        230,602        243,314
Internal restructuring charges and asset write-off                                    103,865
Depreciation                                            270,379        265,750        263,246
Taxes other than income taxes                           194,583        186,978        185,373
Federal and state income taxes                          168,396        168,073        127,992
  Total Operating Expenses                            2,136,929      1,917,254      1,936,795
  Operating Income                                      439,507        452,237        390,854

Other Income and Deductions:
Allowance for other than borrowed funds used
  during construction                                     1,553          4,393          3,157
Other income, net                                         8,180         18,016          4,370
  Total Other Income and Deductions                       9,733         22,409          7,527
  Income Before Interest Charges and
   Preferred Dividends                                  449,240        474,646        398,381

Interest Charges and Preferred Dividends:
Interest on long-term debt                              161,057        173,568        166,387
Other interest                                           19,395         14,409         15,398
Allowance for borrowed funds used during construction    (3,471)        (3,907)        (2,731)
Dividends on preferred stock of subsidiaries              9,251          9,280          9,280
  Total Interest Charges and Preferred Dividends        186,232        193,350        188,334

Consolidated Income Before Extraordinary Charge         263,008        281,296        210,047

Extraordinary Charge, Net                              (275,426)

Consolidated Net (Loss) Income                     $    (12,418)  $    281,296   $    210,047

Common Stock Shares Outstanding (Average)           122,436,317    122,208,465    121,141,446

Basic and Diluted Earnings Per Average Share:
  Consolidated income before extraordinary charge        $ 2.15          $2.30          $1.73
  Extraordinary charge, net                              $(2.25)

Consolidated Net (Loss) Income                          $  (.10)         $2.30          $1.73

</TABLE>

See accompanyiong notes to consolidated financial statements.


                                  F-2


<PAGE>

                                                      Allegheny Energy, Inc.



Consolidated Statement of Cash Flows

<TABLE>
<CAPTION>

Year ended December 31                                     1998          1997          1996
(Thousands of Dollars)

<S>                                                  <C>              <C>           <C>
Cash Flows from Operations:
Consolidated net (loss) income                       $  (12,418)      $  281,296    $  210,047
Extraordinary charge, net of taxes                      275,426
Consolidated income before extraordinary charge         263,008          281,296       210,047
Depreciation                                            270,379          265,750       263,246
Deferred investment credit and income taxes, net         20,998           66,362        20,887
Deferred power costs, net                                (6,639)         (22,916)       15,621
Allowance for other than borrowed funds
  used during construction                               (1,553)          (4,393)       (3,157)
Internal restructuring liability                         (5,504)         (50,597)       55,544
PURPA project buyout                                                     (48,000)       
Changes in certain current assets and liabilities:
  Accounts receivable, net                               15,365           (6,052)       19,570
  Materials and supplies                                (12,852)          (1,385)       15,507
  Accounts payable                                       23,118          (17,172)        1,739
  Taxes accrued                                          14,312           (3,653)         (181)
Other, net                                               10,550           19,386        (7,902)

                                                        591,182          478,626       590,921

Cash Flows from Investing:
Utility construction expenditures
  (less allowance for other than borrowed
  funds used during construction)                      (227,809)        (280,255)     (286,297)
Nonutility construction expenditures and investments     (6,205)            (829)     (180,245)
                                                       (234,014)        (281,084)     (466,542)

Cash Flows from Financing:
Sale of common stock                                                      16,706        33,847
Issuance of long-term debt                              211,952                        160,000
Retirement of long-term debt                           (419,780)         (46,892)      (54,143)
Short-term debt, net                                     52,436           49,971       (43,988)
Cash dividends on common stock                         (210,591)        (210,195)     (204,720)
                                                       (365,983)        (190,410)     (109,004)


Net Change in Cash and Temporary Cash Investments        (8,815)           7,132        15,375
Cash and Temporary Cash Investments at January 1         26,374           19,242         3,867

Cash and Temporary Cash Investments at December 31   $   17,559       $   26,374    $   19,242

Supplemental Cash Flow Information
Cash paid during the year for:
  Interest (net of amount capitalized)               $  171,719       $  178,121    $  169,200
  Income taxes                                          145,053          108,519       132,037

</TABLE>

See accompanying notes to consolidated financial statements.

                               F-3

<PAGE>

                                                        Allegheny Energy, Inc.

Consolidated Balance Sheet

As of December 31                        1998                1997
(Thousands of Dollars)


Assets
Property, Plant, and Equipment:
At original cost, including $166,330
  and $229,785 under construction         $ 8,629,733        $  8,451,424
Accumulated depreciation                   (3,395,603)         (3,155,210)
                                            5,234,130           5,296,214
Investments and Other Assets:
Subsidiaries consolidated-excess of cost
  over book equity at acquisition              15,077              15,077
Benefit plans' investments                     87,468              79,474
Nonutility investments                          9,361               4,992
Other                                           1,566               1,559
                                              113,472             101,102
Current Assets:
Cash and temporary cash investments            17,559              26,374
Accounts receivable:
Electric service, net of $18,011 and
  $17,191 uncollectible allowance             276,866             296,082
Other, net                                     16,163              12,312
Materials and supplies-at average cost:
Operating and construction                     99,439              80,836
Fuel                                           57,610              63,361
Prepaid taxes                                  56,658              51,724
Other, including current portion of
  regulatory assets                            30,788              24,005
                                              555,083             554,694

Deferred Charges:
Regulatory assets                             704,506             586,125
Unamortized loss on reacquired debt            48,671              49,550
Other                                          91,931              66,406

                                              845,108             702,081

Total                                     $ 6,747,793        $  6,654,091

Capitalization and Liabilities

Capitalization:
Common stock, other paid-in capital,
  and retained earnings                   $ 2,033,889        $  2,256,898
Preferred stock                               170,086             170,086
Long-term debt and QUIDS                    2,179,288           2,193,153
                                            4,383,263           4,620,137
Current Liabilities:
Short-term debt                               258,837             206,401
Long-term debt due within one year                                185,400
Accounts payable                              153,107             129,989
Taxes accrued:
Federal and state income                       17,442              10,453
Other                                          62,751              55,428
Interest accrued                               35,945              40,000
Deferred income taxes                          18,718
Adverse power purchase commitments             47,173
Other                                         101,239              74,170
                                              695,212             701,841
Deferred Credits and Other Liabilities:
Unamortized investment credit                 125,396             133,316
Deferred income taxes                         842,193           1,031,236
Regulatory liabilities                         80,354              91,178
Adverse power purchase commitments            538,745
Other                                          82,630              76,383
                                            1,669,318           1,332,113
Commitments and Contingencies (Note N)

Total                                     $ 6,747,793        $  6,654,091


See accompanying notes to consolidated financial statements.

                               F-4


<PAGE>

                                                        Allegheny Energy, Inc.


Consolidated Statement of Capitalization

<TABLE>
<CAPTION>
                                                              (Thousands of Dollars)          (Capitalization Ratios)
<S>                                                          <C>            <C>                <C>              <C>
As of December 31                                              1998            1997            1998             1997
Common Stock:
Common stock of Allegheny Energy, Inc.-
$1.25 par value per share, 260,000,000 shares
 authorized, 122,436,317 shares outstanding                 $  153,045    $   153,045
Other paid-in capital                                        1,044,085      1,044,085
Retained earnings                                              836,759      1,059,768
Total                                                        2,033,889      2,256,898          46.4%            48.8%

Preferred Stock of Subsidiaries-cumulative, par value
  $100 per share, authorized 9,975,688 shares:

                           December 31, 1998
                        Shares            Regular Call Price
  Series           Outstanding            Per Share
  3.60%-4.80%          650,861            $102.205 to $110.00      65,086         65,086
  $5.88-$7.73          650,000            $102.85 to $102.86       65,000         65,000
  Auction 3.95%-4.12%  400,000            $100.00                  40,000         40,000
Total (annual dividend
  requirements $9,254)                                            170,086        170,086        3.9%             3.7%

Long-Term Debt and QUIDS of Subsidiaries:

First mortgage bonds:                 December 31, 1998
  Maturity                            Interest Rate-%
  1998-2000                           5 5/8-5 7/8                 140,000        242,000
  2002-2004                           6 3/8-7 7/8                 175,000        175,000
  2006-2007                           7 1/4-8                     120,000        120,000
  2021-2025                           7 5/8-8 7/8                 810,000        925,000
Debentures due 2003-2023              5 5/8-6 7/8                 150,000        150,000
Quarterly Income Debt Securities
  due 2025                            8.00                        155,457        155,457
Secured notes due 2002-2024           4.70-6.875                  368,300        368,300
Unsecured notes due 2002-2012         4.35-5.10                    23,695         24,995
Installment purchase obligations
  due 2003                            4.50                         19,100         19,100
Medium-term debt due 2001-2003        5.56-6.18                   237,025        220,000
Unamortized debt discount and
  premium, net                                                    (19,289)       (21,299)

Total (annual interest
  requirements $154,039)                                        2,179,288      2,378,553

Less current maturities                                                         (185,400)

Total                                                           2,179,288      2,193,153          49.7%            47.5%

Total Capitalization                                           $4,383,263    $ 4,620,137         100.0%           100.0%

</TABLE>

See accompanying notes to consolidated financial statements.

                                F-5


<PAGE>
Consolidated Statement of Common Equity

<TABLE>
<CAPTION>

                                                                       (Thousands of Dollars)
                                                                       Other          Retained       Total
                                          Shares          Common       Paid-In        Earnings       Common
Year ended December 31                    Outstanding     Stock        Capital        (Note G)       Equity

<S>                                       <C>            <C>         <C>            <C>           <C>
Balance at January 1, 1996                120,700,809    $150,876    $  995,701     $  983,340    $2,129,917

Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
  Purchase Plan and Employee Stock
  Ownership and Savings Plan                1,139,518       1,424        32,423                       33,847
Consolidated net income                                                                210,047       210,047

Deduct:

Dividends on common stock of the
Company (cash)                                                                         204,720       204,720

Balance at December 31, 1996              121,840,327    $152,300    $1,028,124     $  988,667    $2,169,091

Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
  Purchase Plan, Employee Stock
  Ownership and Savings Plan,
  and Performance Share Plan                  595,990         745        15,961                      16,706
Consolidated net income                                                                281,296      281,296

Deduct:

Dividends on common stock of the
Company (cash)                                                                         210,195      210,195

Balance at December 31, 1997              122,436,317     $153,045   $1,044,085     $1,059,768   $2,256,898

Deduct:
Consolidated net loss                                                                   12,418       12,418
Dividends on common stock of the
  Company (cash)                                                                       210,591      210,591

Balance at December 31, 1998              122,436,317     $153,045   $1,044,085     $  836,759   $2,033,889

</TABLE>

See accompanying notes to consolidated financial statements.


                                 F-6

<PAGE>

                                                       Allegheny Energy, Inc.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These   notes   are  an  integral  part  of  the  consolidated   financial
statements.)

Note A: Summary of Significant Accounting Policies

       Allegheny  Energy,  Inc.  (the  Company)  is  an  electric   utility
holding  company  that  derives  substantially  all  of  its  income   from
the   electric   utility   operations  of   its   regulated   subsidiaries,
Monongahela   Power  Company  (Monongahela  Power),  The   Potomac   Edison
Company   (Potomac   Edison),   and   West   Penn   Power   Company   (West
Penn).    These    subsidiaries   jointly    own    Allegheny    Generating
Company   (AGC),  which  owns  and  sells  to  its  parents  840  megawatts
(MW)   of   pumped-storage  generating  capacity.  The  markets   for   the
subsidiaries'   regulated  electric  retail  sales  are   in   the   states
of   Pennsylvania,  West  Virginia,  Maryland,  Virginia,  and   Ohio.   In
1998,   revenues   from   the   50  largest  electric   utility   customers
provided   approximately   17%   of  the  consolidated   retail   revenues.
The   Company   also  has  a  wholly  owned  nonutility   subsidiary,   AYP
Capital,   Inc.   (AYP  Capital),  formed  in  1994,  which,   along   with
its    subsidiaries,    is    involved    primarily    in    energy-related
services,   development   of   nonutility   power   generation,   wholesale
and     retail     electricity     sales    to     deregulated     markets,
telecommunications, and other energy-related businesses.

       The   Company  and  its  subsidiaries  are  subject  to   regulation
by   the   Securities  and  Exchange  Commission,  including   the   Public
Utility    Holding   Company   Act   of   1935   (PUHCA).   The   regulated
subsidiaries   are   subject  to  regulation  by   various   state   bodies
having    jurisdiction    and    by   the   Federal    Energy    Regulatory
Commission   (FERC).   See   Note  B  for  significant   changes   in   the
Pennsylvania     regulatory     environment.     Significant     accounting
policies   of   the   Company   and   its   subsidiaries   are   summarized
below.

Consolidation

      The  Company  owns  all  of  the  outstanding  common  stock  of  its
subsidiaries.   The   consolidated   financial   statements   include   the
accounts   of   the   Company   and   all   subsidiary   companies    after
elimination of intercompany transactions.

Use of Estimates

       The   preparation  of  financial  statements  in   conformity   with
generally   accepted   accounting   principles   requires   management   to
make    estimates   that   affect   the   reported   amounts   of   assets,
liabilities,   revenues,   expenses,  and  disclosures   of   contingencies
during   the   reporting   period,  which   in   the   normal   course   of
business are subsequently adjusted to actual results.

Revenues

Revenues,   including   amounts   resulting   from   the   application   of
fuel   and   energy  cost  adjustment  clauses,  are  recognized   in   the
same   period   in  which  the  related  electric  services  are   provided
to   customers   by  recording  an  estimate  for  unbilled  revenues   for
services  provided  from  the  meter  reading  date  to  the  end  of   the
accounting    period.   Revenues   from   nonregulated    activities    are
recorded in the period earned.

                                F-7


<PAGE>

                                                       Allegheny Energy, Inc.




Deferred Power Costs, Net

      The  costs  of  fuel,  purchased  power,  and  certain  other  costs,
and   revenues   from  sales  to  other  utilities  and  power   marketers,
including   transmission   services,   are   deferred   until   they    are
either   recovered   from  or  credited  to  customers   under   fuel   and
energy    cost-recovery    procedures   in   West    Virginia,    Maryland,
Virginia,   and   Ohio.   West   Penn   discontinued   this   practice   in
Pennsylvania, effective May 1, 1997.

Property, Plant, and Equipment

Utility   property,   plant,  and  equipment   are   stated   at   original
cost,   less   contributions   in   aid   of   construction,   except   for
capital   leases,   which   are   recorded   at   present   value.    Costs
include   direct   labor   and   material;   allowance   for   funds   used
during    construction   (AFUDC)   on   utility    property    for    which
construction  work  in  progress  is  not  included  in  rate   base;   and
indirect     costs    such    as    administration,    maintenance,     and
depreciation     of    transportation    and    construction     equipment,
postretirement   benefits,   taxes,   and   other   benefits   related   to
employees engaged in construction.

       The  cost  of  depreciable  utility  property  units  retired,  plus
removal    costs    less    salvage,    are    charged    to    accumulated
depreciation.

Allowance for Funds Used During Construction

       AFUDC,  an  item  that  does  not  represent  current  cash  income,
is    defined   in   applicable   regulatory   systems   of   accounts   as
including   "the   net   cost   for   the   period   of   construction   of
borrowed   funds   used  for  construction  purposes   and   a   reasonable
rate   on  other  funds  when  so  used."  AFUDC  is  recognized   by   the
regulated   subsidiaries  as  a  cost  of  utility  property,  plant,   and
equipment   with   offsetting  credits  to  other   income   and   interest
charges.   Rates   used  by  the  subsidiaries  for  computing   AFUDC   in
1998,    1997,    and    1996   averaged   7.78%,   8.59%,    and    8.41%,
respectively.   AFUDC  is  not  included  in  the  cost   of   construction
by   the  nonutility  business  or  by  the  utility  businesses  when  the
cost   of   financing   the   construction  is  being   recovered   through
rates.

      As  discussed  in  Note  B,  as a result  of  a  Pennsylvania  Order,
West   Penn   has   discontinued   the   application   of   the   Financial
Accounting    Standards    Board's   (FASB)    Statement    of    Financial
Accounting   Standards  (SFAS)  No.  71,  "Accounting   for   the   Effects
of    Certain    Types    of    Regulation,"   for   electric    generation
operations   and   has   adopted  SFAS  No.  101,   "Accounting   for   the
Discontinuation    of    Application   of   FASB   Statement    No.    71."
Starting   in   July   1998,   West  Penn  stopped   accruing   AFUDC   for
generation    construction   projects   and   adopted    SFAS    No.    34,
"Capitalizing   Interest  Costs,"  to  capitalize   interest   during   the
period    of    construction    of   generation   construction    projects.
Capitalized   interest,   recognized  by   West   Penn   as   a   cost   of
property,    plant,    and   equipment   with   offsetting    credits    to
interest   charges,   is   reported  in  the   statement   of   income   as
allowance   for   borrowed   funds   used

                                 F-8


<PAGE>

                                                      Allegheny Energy, Inc.


during construction.  Since adoption   in   July  1998,  rates
used  by  West  Penn  for  capitalizing interest on generation
construction projects averaged 7.45%.


Depreciation and Maintenance

       Provisions   for  depreciation  are  determined   generally   on   a
straight-line    method    based   on   estimated    service    lives    of
depreciable   properties   and   amounted   to   approximately   3.3%    of
average  depreciable  property  in  each  of  the  years  1998  and   1997,
and   3.5%   in   1996.   The   cost   of  maintenance   and   of   certain
replacements    of    property,   plant,   and   equipment    is    charged
principally to operating expenses.

Nonutility Property

       Nonutility   property   is   stated  at   original   cost   and   is
depreciated   by  the  straight-line  method  over  its  estimated   useful
life.

Investments

       The   investment   in  subsidiaries  consolidated   represents   the
excess   of  acquisition  cost  over  book  equity  (goodwill)   prior   to
1966.   Goodwill   is   not  being  amortized  because,   in   management's
opinion, there has been no reduction in its value.

       Benefit   plans'  investments  primarily  represent  the   estimated
cash   surrender   values  of  purchased  life  insurance   on   qualifying
management     employees    under    executive    life    insurance     and
supplemental    executive    retirement   plans.    Payment    of    future
premiums will fully fund these benefits.

Temporary Cash Investments

       For   purposes  of  the  consolidated  statement  of   cash   flows,
temporary   cash   investments   with   original   maturities   of    three
months   or   less,   generally   in  the   form   of   commercial   paper,
certificates     of    deposit,    and    repurchase    agreements,     are
considered to be the equivalent of cash.

Regulatory Assets and Liabilities

       In   accordance  with  SFAS  No.  71,  the  Company's   consolidated
financial   statements  include  certain  assets  and   liabilities   based
on cost-based ratemaking regulation.

Income Taxes

       Financial  accounting  income  before  income  taxes  differs   from
taxable   income   principally  because  certain  income   and   deductions
for   tax   purposes  are  recorded  in  the  financial  income   statement
in   another   period.   For   the  regulated   subsidiaries,   differences
between   income   tax  expense,  computed  on  the  basis   of   financial
accounting   income  and  taxes  payable  based  on  taxable  income,   are
accounted   for   substantially   in   accordance   with   the   accounting
procedures   followed   for  ratemaking  purposes.  Deferred   tax   assets
and   liabilities  represent  the  tax  effect  of  temporary   differences
between   the

                                F-9


<PAGE>


financial   statement  and  tax   basis   of   assets   and
liabilities computed using the most current tax rates.

       Provisions   for  federal  income  tax  were  reduced  in   previous
years   by   investment   credits,   and   amounts   equivalent   to   such
credits   were   charged   to   income  with  concurrent   credits   to   a
deferred   account.   These   balances  are  being   amortized   over   the
estimated service lives of the related properties.

Postretirement Benefits

       The   Company's   subsidiaries  have  a   noncontributory,   defined
benefit    pension    plan    covering   substantially    all    employees,
including  officers.  Benefits  are  based  on  the  employee's  years   of
service   and   compensation.  The  funding   policy   is   to   contribute
annually   at  least  the  minimum  amount  required  under  the   Employee
Retirement  Income  Security  Act  and  not  more  than  can  be   deducted
for federal income tax purposes.

         The     Company's    subsidiaries    also    provide     partially
contributory    medical   and   life   insurance   plans    for    eligible
retirees   and   dependents.   Medical  benefits,   which   make   up   the
largest  component  of  the  plans,  are  based  upon  an  age  and  years-
of-service    vesting   schedule   and   other   plan    provisions.    The
funding  plan  for  these  costs  is  to  contribute  the  maximum   amount
that  can  be  deducted  for  federal  income  tax  purposes.  Funding   of
these    benefits    is    made   primarily   into    Voluntary    Employee
Beneficiary   Association   trust  funds.  Medical   benefits   are   self-
insured.    The   life   insurance   plan   is   paid   through   insurance
premiums.

Capitalized Software Costs

       The   Company  capitalizes  the  cost  of  software  developed   for
internal   use.  These  costs  are  amortized  on  a  straight-line   basis
over a five-year period beginning upon a project's completion.

Comprehensive Income

       SFAS   No.   130,   "Reporting  Comprehensive   Income,"   effective
for    1998,    established    standards   for   reporting    comprehensive
income   and  its  components  (revenues,  expenses,  gains,  and   losses)
in   the   financial   statements.  The   Company   does   not   have   any
elements   of   other   comprehensive  income  to  report   in   accordance
with SFAS No. 130.


Note B: Industry Restructuring

        In    December   1996,   Pennsylvania   enacted   the   Electricity
Generation   Customer   Choice  and  Competition   Act   (Customer   Choice
Act)   to   restructure   the   electric  industry   in   Pennsylvania   to
create   retail   access   to   a  competitive   electric   energy   supply
market.   Approximately   45%  of  the  Company's   retail   revenues   are
from   its   Pennsylvania  subsidiary,  West  Penn.  On  August  1,   1997,
West   Penn   filed   with  the  Pennsylvania  Public  Utility   Commission
(Pennsylvania    PUC)    a    comprehensive    restructuring    plan     to
implement    full   customer   choice   of   electricity    suppliers    as
required  by  the  Customer  Choice  Act.  The  filing

                                 F-10


<PAGE>

                                                      Allegheny Energy, Inc.


included a plan for recovery of transition costs (sometimes
referred   to    as stranded  costs) through  a Competitive
Transition Charge (CTC).

        Transition   costs   are   costs   incurred   under   a   regulated
environment,   which   may   not   be   recoverable   in   a    competitive
market.   The  amount  of  transition  costs  has  been  a  key  issue   in
the    restructuring   proceedings.   Since   the   installed   costs    of
utility  facilities  are  known,  the  key  variable  in  transition   cost
determinations   in   Pennsylvania   was   the   projection    of    market
prices     of    electricity    in    future    periods.    West     Penn's
restructuring   plan   filing   included   its   determination    of    its
transition  costs  based  on  its  projection  of  future  market   prices.
West   Penn's   recoverable  transition  costs   were   limited   to   $1.2
billion by rate caps mandated by the Customer Choice Act.

       On   May   29,   1998,  the  Pennsylvania  PUC   issued   an   Order
authorizing   West  Penn  recovery  of  approximately  $595   million   (or
$525   million   in   the  event  of  the  merger)  in  transition   costs,
with   a   return,  based  on  alternative  projections  of  future  market
prices.  On  June  26,  1998,  the  Pennsylvania  PUC  denied,  except  for
minor   corrections,  a  request  by  West  Penn  for  reconsideration   of
the   May   29  Order.  On  that  same  day,  West  Penn  filed  a   formal
appeal   in  state  court  and  an  action  in  federal  court  challenging
the Pennsylvania PUC's restructuring Order.

      As  a  result  of  the  May  29, 1998, Order,  West  Penn  determined
that   it  was  required  to  discontinue  the  application  of  SFAS   No.
71   for  electric  generation  operations  and  adopt  SFAS  No.  101.  In
doing  so,  West  Penn  also  determined  that,  under  the  provisions  of
SFAS   No.   101,  an  extraordinary  charge  of  $450.6  million   ($265.4
million   after   taxes)   was   required   to   reflect   adverse    power
purchase   commitments  and  deferred  costs  that  are   not   recoverable
from customers under the Pennsylvania PUC's Order.

       While   pursuing   its   litigation,  West  Penn   participated   in
settlement   discussions   with   interested   parties   regarding   issues
related   to   the   restructuring  Order.  A  negotiated  settlement   was
achieved,  and,  on  November  19,  1998,  the  Pennsylvania  PUC   granted
final   approval   to  West  Penn's  restructuring  settlement   agreement.
The settlement agreement includes the following provisions:

-    Agreement   by   the  parties  to  withdraw  all  litigation   related
     to the Pennsylvania deregulation proceedings.

-    Establishment   of   an  average  shopping  credit   of   3.16   cents
     per   kilowatt-hour  in  1999  for  West  Penn  customers   who   shop
     for the generation portion of electricity services.

-    Two-thirds   of   West   Penn's   customers   have   the   option   of
     selecting  a  generation  supplier  on  January  2,  1999,  with   all
     customers able to shop on January 2, 2000.

-    Requires   a  rate  refund  from  1998  revenue  (about  $25  million)
     via  a  2.5%  rate  decrease  throughout  1999,  accomplished  by   an
     equal percentage decrease for each rate class.


                                 F-11


<PAGE>

                                                      Allegheny Energy, Inc.


-    Provides   that   customers   will   have   the   option   of   buying
     electricity    from    West   Penn   at   capped   generation    rates
     through   2008,   and   that  transmission  and   distribution   rates
     are   capped   through  2005,  except  that  the  capped   rates   are
     subject   to   certain  increases  as  provided  for  in  the   Public
     Utility Code.

-    Prohibits     complaints    challenging    West    Penn's    regulated
     transmission and distribution rates through 2005.

-    Provides   about   $15   million  of  West  Penn   funding   for   the
     development   and   use   of  renewable  energy   and   clean   energy
     technologies, energy conservation, energy efficiency, etc.

-    Permits   recovery   of   $670  million  in  transition   costs   plus
     return   over   10   years  beginning  in  January   1999   for   West
     Penn.  In  the  event  that  the  merger  of  Allegheny  Energy,  Inc.
     and    DQE,   Inc.   (DQE),   parent   company   of   Duquesne   Light
     Company   in   Pittsburgh,   Pa.,  is  consummated,   the   transition
     costs   will   be   adjusted   to  $630   million   plus   return   to
     provide a sharing of merger synergy savings with customers.

-    Allows   for  income  recognition  of  transition  cost  recovery   in
     the   earlier   years  of  the  transition  period  to   reflect   the
     Pennsylvania    PUC's    projections    that    electricity     market
     prices are lower in the earlier years.

-    Grants   West   Penn's  application  to  issue  bonds  to   securitize
     up   to   $670  million  (or  $630  million  in  the  event   of   the
     merger)   in   transition   costs  and   to   provide   75%   of   the
     associated savings to customers with 25% to shareholders.

-    Authorizes   the  transfer  of  West  Penn's  generating   assets   to
     a   nonutility   affiliate   at  book  value.   Subject   to   certain
     time-limited   exceptions,  the  nonutility   business   can   compete
     in the unregulated energy market.

-    If   West  Penn  is  forced  to  divest  some  generating  assets   or
     chooses  to  divest  all  of  its  generation  before  2002,  the  CTC
     will  be  adjusted,  either  up  or down,  based  on  the  results  of
     such divestiture.

       As  a  result  of  the  November  19,  1998,  settlement  agreement,
the   extraordinary   charge  was  increased  by   $16.3   million   ($10.0
million   after   taxes)   to   $466.9  million   ($275.4   million   after
taxes),   and   additional   charges  of  $40.3  million   ($23.7   million
after   taxes)  related  to  the  West  Penn  revenue  refund  and   energy
program   payments  were  also  recorded.  See  Note  C    for   additional
details.   Pursuant   to  Pennsylvania  PUC  Orders,  starting   in   1999,
West  Penn  is  unbundling  its  rates  to  reflect  separate  prices   for
the   supply   charge,   the   CTC,  and  transmission   and   distribution
charges.  While  supply  will  be  open  to  competition,  West  Penn  will
continue    to    provide   regulated   transmission    and    distribution
services   to   customers  in  its  service  area  at   Pennsylvania   PUC-
and   FERC-regulated  rates  and  will  be  the  electricity  provider   of
last   resort  for  those  customers  who  decide  not  to  choose  another
electricity supplier.

                               F-12


<PAGE>

                                                      Allegheny Energy, Inc.


       As   stated  above,  West  Penn  made  its  filing  concerning   its
transition   cost   requirements  based  on  its  early   1997   projection
of   market  prices.  The  Pennsylvania  PUC  issued  its  May  29,   1998,
Order   to   West  Penn,  as  well  as  its  1998  orders  to   all   other
Pennsylvania      electric     utilities,     based     on      alternative
projections.  Current  prices,  which  the  Company  believes   are   being
influenced,  among  other  things,  by  price  volatility  in  the   summer
of   1998,   are   equal   to   and  in  some   cases   higher   than   the
projections   adopted   by  the  Pennsylvania  PUC  in   its   deregulation
orders  issued  to  West  Penn  and  other  utilities  in  the  state.   If
the    Pennsylvania    PUC's   projections   are   correct,    West    Penn
believes  that  the  transition  costs  provided  will  be  sufficient   to
permit   it   to  recover  its  embedded  costs,  with  a  return,   during
the   transition   from   regulation   to   deregulation   of   electricity
generation.

       The   West  Penn  settlement  agreement  authorizes  West  Penn   to
create  a  CTC  regulatory  asset  for  specified  CTC  revenues  in   1999
through  2002  to  be  amortized  in  2005  through  2008.  The  regulatory
asset   booking   of  CTC  revenue  acts  to  accelerate   recognition   of
transition   cost   recovery.  In  addition,   the   settlement   agreement
specifies   how   CTC  revenues  will  be  allocated  between   return   on
and    recovery   of   transition   costs.   Amortization   of   regulatory
assets   in   1999   through  2008  under  the  Pennsylvania   PUC-approved
settlement   agreement   results  in  smaller   amortization   expense   in
the   early  years  of  the  transition  period  which  favorably   affects
earnings in those years.

       Also   pursuant   to   the  Customer  Choice   Act,   all   electric
utilities    in    Pennsylvania   were   required    to    establish    and
administer   retail   access   pilot   programs   under   which   customers
representing  5%  of  the  load  of  each  rate  class  would   choose   an
electricity    supplier   other   than   their    own    local    franchise
utility.   The   pilot   programs  began   on   November   1,   1997,   and
continued    through    December   31,   1998.   As    ordered    by    the
Pennsylvania  PUC,  pilot  participants  received  an  energy   credit   to
their   bills   from   their   local  utility   and   paid   an   alternate
supplier    for   energy.   To   assure   participation   in   the    pilot
program,   the   credit   established   by   the   Pennsylvania   PUC   was
artificially   high   (greater   than  West   Penn's   generation   costs),
with   the  result  that  West  Penn  suffered  a  loss  of  $6.5  million.
West   Penn  attempted  to  mitigate  the  loss  by  competing  for   sales
to    pilot    participants   of   other   utilities   as   an    alternate
supplier.    The    Pennsylvania   PUC   approved   West    Penn's    pilot
compliance  filing  and  thus  has  indicated  its  intent  to  treat   the
revenue   losses   as   a   regulatory  asset   subject   to   review   and
potential   rate   recovery.   Because   sales   prices   were   low    and
margins    were   commensurately   thin,   West   Penn   was   unable    to
completely    offset    its    pilot    losses    with    new     revenues.
Accordingly,   West   Penn   deferred  the  net   revenue   losses   as   a
regulatory asset.

Note C: Accounting for the Effects of Price Deregulation

     In 1997, the FASB, through its Emerging Issues Task Force
(EITF), issued EITF No. 97-4, "Deregulation of the Pricing of
Electricity-Issues Related to the Application of FASB Statement
Numbers 71 and 101." In EITF 97-4, the EITF agreed that when a
rate order that contains sufficient detail for the enterprise to
reasonably determine how the transition plan will affect the
separable portion of its business whose pricing is being
deregulated is issued, the entity should cease to apply SFAS No.
71 to that separable portion of its business. West Penn believes
that the Pennsylvania PUC Order dated May 29, 1998, as described
in Note B which begins on page 50, provides

                               F-13

                                                      Allegheny Energy, Inc.

sufficient details
regarding the deregulation of West Penn's electric generation
operations to require discontinuation of the application of SFAS
No. 71 for its electric generation operations. Effective June 30,
1998, West Penn adopted the provisions of SFAS No. 101 for its
electric generation operations. West Penn determined that under
the provisions of SFAS No. 101, an extraordinary charge of $466.9
million ($275.4 million after taxes) was required to reflect a
write-off of certain disallowances in the Pennsylvania PUC's May
29, 1998, Order, as revised by the Pennsylvania PUC-approved
November 19, 1998, settlement agreement. The write-off reflects
adverse power purchase commitments and deferred costs that are
not recoverable from customers under the Pennsylvania PUC's Order
and settlement agreement as follows:

(Millions of Dollars)                               Gross     Net-of-Tax

AES Beaver Valley nonutility generation contract    $197.5    $116.5
AGC pumped storage capacity contract                 165.6      97.7
Other                                                103.8      61.2

Total extraordinary charge                          $466.9    $275.4

       In   1985,   West  Penn  entered  into  a  contract   with   Applied
Energy  Services  (AES)  Corporation  for  the  purchase  of  energy   from
AES's   Beaver  Valley  generating  plant  in  Pennsylvania   pursuant   to
the  requirements  of  the  Public  Utility  Regulatory  Policies  Act   of
1978 (PURPA).

       West   Penn   owns  45%  of  AGC,  which  owns  an   undivided   40%
interest   in   the  2,100-MW  pumped-storage  hydroelectric   station   in
Bath   County,   Va.  West  Penn  buys  AGC's  capacity  in   the   station
priced   under   a  cost  of  service  formula  wholesale   rate   schedule
approved by the FERC.

       Under   both   of   these   contracts,  West   Penn   has   purchase
commitments  at  costs  in  excess  of the  market  value  of  energy  from
the   plants.   Because  of  utility  restructuring  under   the   Customer
Choice   Act,  these  commitments  have  been  determined  to  be   adverse
purchase    commitments   requiring   accrual   as    loss    contingencies
pursuant   to   SFAS   No.   5,   "Accounting   for   Contingencies."   The
extraordinary  charge  before  taxes  for  these  contracts  is   the   net
result   of   such  excess  cost  accruals  (recorded  as   adverse   power
purchase     commitments)     less     estimated     revenue     recoveries
authorized   in   the  Pennsylvania  PUC  Order  (recorded  as   regulatory
assets) as follows:

<TABLE>
<CAPTION>

                                                       AES               AGC
(Millions of Dollars)                                  Beaver Valley     Pumped Storage

<S>                                                    <C>               <C>
Projected costs in excess of market value of energy    $351.5            $234.5
Estimated recovery via a CTC (regulatory asset)         154.0              68.9

Net unrecoverable extraordinary charge                 $197.5            $165.6

</TABLE>

       Various   assumptions  and  estimates  were  made   in   determining
the  extraordinary  charge  to  income  discussed  on  page  52.  The  most
significant   relate   to  future  electricity  prices.   To   the   extent
that    future    electricity   prices   differ    from    the    Company's
estimates,   adjustments  to  the  reserve  for  adverse   power   purchase
commitments may be required.

       The   other  $103.8  million  of  extraordinary  charges  represents
$55.0   million   of   deferred  unrecovered  expenditures   for   previous
PURPA   buyouts,

                                F-14

                                                      Allegheny Energy, Inc.


$13.5  million  for  an  abandoned   generating   plant,
and   $35.3   million   of  other  generation-related  regulatory   assets,
primarily related to SFAS No. 109, "Accounting for Income Taxes."

       The   Consolidated  Balance  Sheet  includes  the   amounts   listed
below for generation assets not subject to SFAS No. 71.

                                                      December     December
(Thousands of Dollars)                                  1998         1997

Property, plant, and equipment at original cost     $1,969,636   $1,951,066
Amounts under construction included above               39,227       51,715
Accumulated depreciation                              (870,777)    (793,166)

       In  addition  to  the  extraordinary  charge  and  as  a  result  of
the   settlement  agreement,  a  fourth  quarter  charge  to  earnings   of
$40.3   million   ($23.7   million   after   taxes)   resulted   from   the
required   West  Penn  refund  throughout  1999  from  1998   revenues   of
about    $25   million   and   a   $15   million   provision   for   energy
programs.

       The   Company's  other  utility  subsidiaries  could  be   subjected
to   retail   electric  supply  competition  in  four  additional   states-
West   Virginia,   Maryland,   Virginia,  and  Ohio.   Additional   charges
of   the   sort  incurred  in  connection  with  Pennsylvania  deregulation
could result from such proceedings.

Note D: Proposed Merger

       On   April  7,  1997,  the  Company  and  DQE,  parent  company   of
Duquesne   Light   Company  in  Pittsburgh,  Pa.,   announced   that   they
had agreed to merge in a tax-free, stock-for-stock transaction.

        At    separate   meetings   held   on   August   7,    1997,    the
shareholders   of   the   Company  and  DQE  approved   the   merger.   The
Company   and   DQE   made   all   necessary  regulatory   filings.   Since
then,   the   Company  and  DQE  received  approval  of  the  merger   from
the   Nuclear  Regulatory  Commission,  the  Pennsylvania  PUC,   and   the
FERC.  The  Pennsylvania  PUC  and  the  FERC  approvals  were  subject  to
conditions   acceptable   to   the  Company.   In   addition,   while   not
required,   the   Maryland  Public  Service  Commission  and   the   Public
Utilities Commission of Ohio have indicated their approval.

       On   October  5,  1998,  DQE  notified  the  Company  that  it   had
unilaterally    decided   to   terminate   the    merger.    The    Company
believes  DQE's  action  was  without  basis  and  was  a  breach  of   the
merger   agreement.  In  response,  the  Company  filed  with  the   United
States  District  Court  for  the  Western  District  of  Pennsylvania   on
October  5,  1998,  a  lawsuit  for  specific  performance  of  the  merger
agreement   or,   alternatively,   damages.   The   Company   also    filed
motions for preliminary injunctive relief against DQE.

      On  October  28,  1998,  the  District  Court  denied  the  Company's
motions   for  preliminary  injunctive  relief.  The  District  Court   did
not  rule  on  the  merits  of  the lawsuit  for  specific  performance  or
damages.   On   October  30,  1998,  the  Company  appealed  the   District
Court's  Order  to  the  United  States Court  of  Appeals  for  the  Third
Circuit.    The    Company   cannot   predict   the   outcome    of    this
litigation.

                               F-15


<PAGE>

                                                      Allegheny Energy, Inc.


      All  of  the  Company's  incremental  costs  of  the  merger  process
($17.6  million  through  December  31,  1998)  are  being  deferred.   The
accumulated   merger   costs  will  be  written   off   by   the   combined
company   when   the   merger  occurs  or  by  the   Company   if   it   is
determined that the merger will not occur.

Note E: Internal Restructuring Charges and Asset Write-Off

       In   1996,   the  Company  and  its  subsidiaries  completed   their
internal   restructuring   activities  initiated   in   1994,   simplifying
the    management    structure   and   streamlining   operations.    During
1996,    restructuring   activities   included   consolidating    operating
divisions, customer services, and other functions.

       In   1996,  the  subsidiaries  recorded  restructuring  charges   of
$93.1   million   ($56.2   million  after  tax)  in   operating   expenses,
including    all    restructuring    charges    associated     with     the
reorganization.   These   charges  reflected   liabilities   and   payments
for     severance,     employee    termination     costs,     and     other
restructuring   costs.   The   current   portion   of   the   restructuring
liability,    reflected    in   other   current   liabilities,    excluding
benefit     plans     curtailment     adjustments     to     postretirement
liabilities    (which   are   primarily   recorded   in   other    deferred
credits), consists of:

(Thousands of Dollars)                           1998          1997

Restructuring liability:
Balance at beginning of period                $    5,504    $  56,101
Less payments and accrual reversals               (5,504)     (50,597)

Balance at end of period                      $    -        $   5,504

       In   1996,   the  utility  subsidiaries  wrote  off  $10.8   million
($6.3   million   after  tax)  of  previously  accumulated  costs   related
to    a    proposed    transmission   line.   In   the   industry's    more
competitive   environment,   it  was  no  longer   reasonable   to   assume
future recovery of these costs in rates.



Note F: Income Taxes

Details of federal and state income tax provisions are:

(Thousands of Dollars)                       1998      1997      1996

Income taxes-current:
  Federal                                    $114,319  $ 87,394  $ 83,456
  State                                        33,385    23,960    26,004

    Total                                     147,704   111,354   109,460

Income taxes-deferred, net of amortization     28,920    74,565    29,129
Income taxes-deferred, extraordinary charge  (191,480)
Amortization of deferred investment credit     (7,922)   (8,203)   (8,242)

    Total income taxes                        (22,778)  177,716   130,347

Income taxes-charged to other income and
  deductions                                     (306)   (9,643)   (2,355)
Income taxes-credited to extraordinary 
  charge                                      191,480 

Income taxes-charged to operating income     $168,396  $168,073  $127,992

                                    F-16


<PAGE>

                                                     Allegheny Energy, Inc.


       The  total  provision  for  income  taxes  is  different  from   the
amount  produced  by  applying  the  federal  income  statutory  tax   rate
of 35% to financial accounting income, as set forth below:

(Thousands of Dollars)                            1998      1997      1996

Income before preferred dividends,
  income taxes, and extraordinary charge        $440,655  $458,649  $347,319

Amount so produced                              $154,229  $160,527  $121,562
Increased (decreased) for:
  Tax deductions for which deferred tax
    was not provided:
    Lower tax depreciation                         6,700    14,200    12,600
    Plant removal costs                           (2,400)   (1,700)   (1,900)
  State income tax, net of federal income
   tax benefit                                    20,200    11,700    14,100
  Amortization of deferred investment credit      (7,922)   (8,203)   (8,242)
  Other, net                                      (2,411)   (8,451)  (10,128)

Total                                           $168,396  $168,073  $127,992


       The   provision  for  income  taxes  for  the  extraordinary  charge
is   different   from   the  amount  produced  by  applying   the   federal
income   statutory  tax  rate  of  35%  to  the  gross   amount,   as   set
forth below:

(Thousands of Dollars)                                           1998

Extraordinary charge before income taxes                         $466,905

Amount so produced                                               $163,417
Increased for state income tax, net of federal
  income tax benefit                                               28,063

 Total                                                           $191,480

Federal income tax returns through 1993 have been examined and
substantially settled through 1991.

                                 F-17


<PAGE>

                                                       Allegheny Energy, Inc.

At December 31, the deferred tax assets and liabilities
consisted of the following:

(Thousands of Dollars)                           1998        1997
Deferred tax assets:
  CTC recovery                               $  154,530
  Unamortized investment tax credit              77,213  $   83,818
  Tax interest capitalized                       35,375      35,954
  Postretirement benefits other than
    pensions                                     31,047      21,986
  Contributions in aid of construction           23,643      22,980
  Unbilled revenue                               13,380      13,657
  Revenue refund                                 10,301
  Deferred power costs, net                       8,736      10,598
  Other                                          47,782      38,578
                                                402,007     227,571
Deferred tax liabilities:
Book vs. tax plant basis differences, net     1,174,453   1,142,035
Other                                            88,465     104,415
                                              1,262,918   1,246,450
Total net deferred tax liabilities              860,911   1,018,879
Portion above included in current
   (liabilities) assets                         (18,718)     12,357

Total long-term net deferred
   tax liabilities                            $ 842,193  $1,031,236

Note G: Dividend Restriction

        Supplemental    indentures   relating   to   certain    outstanding
bonds    of    Monongahela   Power   and   West   Penn   contain   dividend
restrictions   under  the  most  restrictive  of  which   $121,015,000   of
the    Company's   consolidated   retained   earnings   at   December   31,
1998,  is  not  available  for  cash  dividends  on  their  common  stocks,
except  that  a  portion  thereof  may be  paid  as  cash  dividends  where
concurrently   an   equivalent  amount   of   cash   is   received   by   a
subsidiary   as  a  capital  contribution  or  as  the  proceeds   of   the
issue and sale of shares of such subsidiary's common stock.

Note   H:   Pension  Benefits  and  Postretirement  Benefits   Other   Than
Pensions

       Net   periodic   (credit)  cost  for  pension   and   postretirement
benefits   other   than  pensions  (principally  health   care   and   life
insurance)   for   employees   and  covered  dependents,   a   portion   of
which   (about   25%   to   30%)  was  charged   to   plant   construction,
included the following components:

<TABLE>
<CAPTION>

                                                                                  Postretirement Benefits
                                              Pension Benefits                      Other Than Pensions
(Thousands of Dollars)                    1998         1997        1996        1998         1997        1996
Components of net periodic (credit) cost:
<S>                                     <C>          <C>         <C>          <C>         <C>         <C>
Service cost                            $14,316      $12,435     $14,881      $ 2,566     $ 2,619     $ 2,930
Interest cost                            46,743       43,060      41,500       14,346      15,244      14,251
Expected return on plan assets          (61,280)     (57,404)    (54,268)      (6,163)     (4,705)     (3,666)
Amortization of unrecognized transition
 (asset) obligation                      (3,146)      (3,146)     (3,146)       6,433       6,433       7,272
Amortization of prior service cost        2,360        1,441       1,140
Periodic (credit) cost                   (1,007)      (3,614)        107       17,182      19,591      20,787
Reversal of previous deferrals              760          760         760                                1,975
Net periodic (credit) cost              $  (247)     $(2,854)    $   867      $17,182     $19,591     $22,762

</TABLE>

                                   F-18


<PAGE>

                                                      Allegheny Energy, Inc.

       The   discount  rates  and  rates  of  compensation  increases  used
in   determining   the   benefit  obligations  at   September   30,   1998,
1997,   and   1996,  and  the  expected  long-term  rate   of   return   on
assets in each of the years 1998, 1997, and 1996 were as follows:



                              1998   1997  1996      1998   1997  1996
Discount rate                 7.00%  7.25% 7.50%     7.00%  7.25% 7.50%
Expected return on plan
  assets                      9.00%  9.00% 9.00%     8.25%  8.25% 8.25%
Rate of compensation increase 4.00%  4.25% 4.50%     4.00%  4.25% 4.50%

       For   postretirement   benefits  other  than  pensions   measurement
purposes,  a  health  care  cost trend rate  of  6%  for  1999  and  beyond
and   plan  provisions  which  limit  future  medical  and  life  insurance
benefits  were  assumed.  Because  of  the  plan  provisions  which   limit
future   benefits,  the  assumed  health  care  cost  trend  rate   has   a
limited   effect   on   the   amounts  reported.   A   one-percentage-point
change  in  the  assumed  health  care  cost  trend  rate  would  have  the
following effects:

<TABLE>
<CAPTION>


                                                          1-Percentage-Point  1-Percentage-Point
(Thousands of Dollars)                                              Increase            Decrease
<S>                                                              <C>                 <C> <C>
Effect on total of service and interest cost components          $  575              $   (596)
Effect on postretirement benefit obligation                      $5,092              $ (5,054)

</TABLE>

The amounts (prepaid) accrued at December 31,
using a measurement date of September 30, included
the following components:

<TABLE>
<CAPTION>
                                                                              Postretirement Benefits
                                                 Pension Benefits             Other Than Pensions
(Thousands of Dollars)                        1998              1997          1998               1997

Change in benefit obligation:
  <S>                                       <C>              <C>            <C>              <C>
  Benefit obligation at beginning of year   $ 664,695        $ 586,473      $ 202,274        $206,229
  Service cost                                 14,316           12,435          2,566           2,619
  Interest cost                                46,743           43,060         14,346          15,244
  Plan amendments                                 360           18,105
  Actuarial loss (gain)                         8,573           44,029        (14,296)        (15,243)
  Benefits paid                               (41,750)         (39,407)        (8,608)         (6,575)

    Benefit obligation at December 31         692,937          664,695        196,282         202,274
Change in plan assets:
  Fair value of plan assets at
   beginning of year                          786,159          691,063         73,363          55,802
  Actual return on plan assets                 49,091          134,503            965          12,230
  Employer contribution                         7,848                           2,451           5,331
  Benefits paid                               (41,750)         (39,407)        (2,006)

    Fair value of plan assets at December 31  801,348          786,159         74,773          73,363
Plan assets (in excess of) less than
 benefit obligation                          (108,411)        (121,464)       121,509         128,911
Unrecognized transition asset (obligation)      6,298            9,444        (90,060)        (96,493)
Unrecognized net actuarial gain               108,366          129,129         21,453          12,355
Unrecognized prior service cost due to plan
 amendments                                   (22,814)         (24,814)
Fourth quarter contributions and benefit
 payments                                                       		          	  (5,227)         (4,025)
(Prepaid) accrued at December 31           $  (16,561)      $   (7,705)   $    47,675        $ 40,748

</TABLE>

                                 F-19


<PAGE>

                                                       Allegheny Energy, Inc.

Note I: Regulatory Assets and Liabilities

        The    Company's   utility   operations   are   subject   to    the
provisions   of   SFAS   No.  71.  Regulatory  assets  represent   probable
future   revenues  associated  with  deferred  costs  that   are   expected
to   be   recovered   from  customers  through  the   ratemaking   process.
Regulatory   liabilities   represent   probable   future   reductions    in
revenues   associated   with  amounts  that   are   to   be   credited   to
customers   through   the  ratemaking  process.  Regulatory   assets,   net
of   regulatory   liabilities,  reflected  in  the   Consolidated   Balance
Sheet at December 31 relate to:

(Thousands of Dollars)                                    1998       1997
Long-Term Assets (Liabilities), Net:
Income taxes, net                                         $305,415   $417,382
CTC recovery                                               292,718
PURPA project buyout                                                   48,000
Demand-side management                                       8,157     14,204
Pennsylvania pilot deferred revenue                          6,726    
Postretirement benefits                                      6,229      7,053
Storm damage                                                 2,101      3,537
Deferred power costs, net (reported in other
  deferred charges/credits)                                 (2,455)     4,051
Other, net                                                   2,806      4,771

Subtotal                                                   621,697    498,998

Current Assets (Liabilities), Net:
CTC recovery                                                17,372
Income taxes, net                                            1,847      1,847
Deferred power costs, net (reported in other
  current assets/liabilities)                                7,211      2,198

Subtotal                                                    26,430      4,045

Net Regulatory Assets                                     $648,127   $503,043


                                F-20


<PAGE>

                                                       Allegheny Energy, Inc.


         Deregulation/competition    proceedings    in    West    Virginia,
Virginia,   Maryland,  and  Ohio  may  in  the  future   result   in   less
than   full   recovery   of  costs  incurred  to  serve   customers.   This
would   then   require  additional  charges  of  the   type   recorded   in
1998   for   West  Penn  as  discussed  in  Notes  B  and  C  starting   on
pages   50   and   52,  respectively,  in  connection  with  Pennsylvania's
deregulation   proceedings.  Such  charges,  if  any,  are  not   estimable
at this time.

Note J: Fair Value of Financial Instruments

The carrying amounts and estimated fair value of
financial instruments at December 31 were as follows:

<TABLE>
<CAPTION>
                                      1998                                 1997 
                                      Carrying         Fair                Carrying       Fair
(Thousands of Dollars)                Amount           Value               Amount         Value
Assets:

<S>                                   <C>    <C>       <C>   <C>           <C> <C>        <C> <C>
Temporary cash investments            $      882       $     882           $   5,863      $   5,863
Life insurance contracts                  87,468          87,468              79,474         79,474
Liabilities:
Short-term debt                          258,837         258,837             206,401        206,401
Long-term debt and QUIDS               2,198,577       2,307,081           2,399,852      2,517,863
Interest rate swap                         1,528           3,831                              3,244
Option contract for interest rate swap     5,717           5,717

</TABLE>

       The   carrying  amount  of  temporary  cash  investments,  as   well
as   short-term   debt,  approximates  the  fair  value  because   of   the
short   maturity  of  those  instruments.  The  fair  value  of  the   life
insurance   contracts  was  estimated  based  on  cash   surrender   value.
The  fair  value  of  long-term  debt and  QUIDS  was  estimated  based  on
actual  market  prices  or  market  prices  of  similar  issues.  The  fair
value  of  the  swap  and  option  contract  was  estimated  based  on  the
present    value   of   future   cash   flows   associated    with    these
instruments.    The   carrying   amount   of   the   swap   represents    a
liability    associated    with   the   refinancing    transaction    which
occurred    in    January   1998.   The   Company    has    no    financial
instruments held or issued for trading purposes.

Note K: Capitalization

Preferred Stock

        All   of   the   preferred   stock   is   entitled   on   voluntary
liquidation   to   its   then  current  call  price  and   on   involuntary
liquidation   to  $100  a  share.  The  holders  of  West   Penn's   market
auction   preferred   stock  are  entitled   to   dividends   at   a   rate
determined quarterly by an auction process.

Long-Term Debt and QUIDS

       Maturities   for  long-term  debt  in  thousands  of   dollars   for
the   next   five   years   are:   1999,  none;   2000,   $140,000;   2001,
$160,000;  2002,  $63,810;  and  2003,  $254,075.  Substantially   all   of
the   properties  of  the  subsidiaries  are  held  subject  to  the   lien
securing   each   subsidiary's  first  mortgage  bonds.   Some   properties
are   also   subject   to   a  second  lien  securing   certain   pollution
control and solid waste disposal notes.

                                     F-21


<PAGE>

                                                       Allegheny Energy, Inc.

      In  October  1996,  AYP  Energy,  Inc.  (AYP  Energy),  a  subsidiary
of   AYP   Capital,   borrowed  $160  million  for  five   years   from   a
syndicate   of  eight  banks  priced  at  the  London  Interbank   Offering
Rate   (LIBOR)   plus   a   spread.  AYP  Energy  also   entered   into   a
floating-to-fixed     interest    rate    swap     to     hedge     against
fluctuations  in  interest  rates.  The  swap  plus  the  spread   on   the
underlying   financing  fixed  the  interest  rate   to   AYP   Energy   at
6.78%.   In  January  1998,  the  swap  was  refinanced  in  exchange   for
the  counterparty's  right  to  exercise  an  option  to  extend  the  swap
until   2006.   The   new   swap  plus  the  spread   on   the   underlying
financing   lowered   the   interest  rate  to   AYP   Energy   to   6.18%.
During   1998,  the  Company  recorded  a  mark-to-market  loss   of   $2.3
million related to this option.

Note L: Short-Term Debt

       To   provide   interim   financing  and  support   for   outstanding
commercial   paper,   lines   of   credit  have   been   established   with
several   banks.   The   Company  and  its  regulated   subsidiaries   have
fee   arrangements   on   all   of   their   lines   of   credit   and   no
compensating balance requirements.

      At  December  31,  1998,  unused lines  of  credit  with  banks  were
$300   million.  In  addition  to  bank  lines  of  credit,   an   internal
money   pool   accommodates   intercompany  short-term   borrowing   needs,
to   the  extent  that  certain  of  the  regulated  companies  have  funds
available.    Short-term   debt   outstanding    for    1998    and    1997
consisted of:

(Thousands of Dollars)                            1998              1997

Balance and interest rate at end of year:
Commercial paper                             $208,837-5.40%    $166,401-6.14%
Notes payable to banks                         50,000-5.40%      40,000-6.75%

Average amount outstanding and interest
 rate during the year:
Commercial paper                              171,393-5.60%     100,572-5.62%
Notes payable to banks                         44,789-5.62%      13,022-5.60%

Note M: Business Segments

       In   June   1997,  the  FASB  issued  SFAS  No.  131,   "Disclosures
about   Segments   of   an   Enterprise  and   Related   Information,"   to
establish    standards   for   reporting   information   about    operating
segments    in    financial    statements.    The    Company's    principal
business   segments   are   utility   and   nonutility   operations.    The
utility   subsidiaries,   doing  business  as  Allegheny   Power,   include
the   generation,  purchase,  transmission,  distribution,  and   sale   of
electric  energy.  Allegheny  Power  derives  substantially  all   of   its
income   from   operations   of   its  utility  subsidiaries,   Monongahela
Power,    Potomac   Edison,   and   West   Penn.   Nonutility    operations
consists  of  AYP  Capital,  a  wholly  owned  subsidiary,  formed  in   an
effort   to   meet  the  challenges  of  the  new  competitive  environment
in   the   electric   industry.  AYP  Capital  has   three   wholly   owned
subsidiaries,   AYP   Energy,   Allegheny  Communications   Connect,   Inc.
(ACC),   and   Allegheny   Energy   Solutions,   Inc.   (Allegheny   Energy
Solutions).   AYP   Energy  is  a  power  marketer.  ACC   is   an   exempt
telecommunications    company   under   the   PUHCA.    Allegheny    Energy
Solutions    was   formed   to   market   electric   energy    to    retail
customers    in    deregulated   markets.   Because    of    organizational

                                F-22


<PAGE>

                                                      Allegheny Energy, Inc.


efficiencies    available    in   an   alternate    corporate    structure,
Allegheny    Energy   Solutions   no   longer   competes   in   deregulated
markets.  Rather,  that  role  has  been  assumed  by  the  Energy   Supply
Division   of  the  Supply  Business  of  West  Penn,  acting   under   the
name   Allegheny  Energy  Supply.  AYP  Capital,  in  its  own  name,  also
markets  various  services  related  to  the  electric  industry  and   has
investments in two limited energy partnerships.

       Business   segment  information  for  1998,  1997,   and   1996   is
summarized   below.   Transactions  between   affiliates   are   recognized
at     prices     which     approximate    market    value.     Significant
transactions    between    reportable   segments    are    eliminated    to
reconcile   the   segment   information  to   consolidated   amounts.   The
identifiable   assets   information  does  not  reflect   the   elimination
of   intercompany  balances  or  transactions  which  are   eliminated   in
the Company's consolidated financial statements.

<TABLE>
<CAPTION>

(Thousands of Dollars)                            1998         1997         1996
Operating Revenues:
 <S>                                          <C>          <C>          <C>
 Utility                                      $2,330,261   $2,286,175   $2,326,902
 Nonutility                                      246,986       85,794          747
 Eliminations                                       (811)      (2,478)

Federal and State Income Taxes:
 Utility                                         178,929      177,581      129,877
 Nonutility                                      (10,533)      (9,508)      (1,885)

Operating Income:
 Utility                                         449,762      457,267      391,081
 Nonutility                                      (10,255)      (5,030)        (227)

Interest Charges and Preferred Dividends:
 Utility                                         176,073      182,564      186,260
 Nonutility                                       10,159       10,786        2,074

Consolidated Income Before Extraordinary Charge:
 Utility                                         283,323      295,653      212,914
 Nonutility                                      (20,315)     (14,357)      (2,867)

Extraordinary Charge, Net:
 Utility                                         275,426
 Nonutility

Identifiable Assets:
 Utility                                       6,534,375    6,442,512    6,410,789
 Nonutility                                      213,418      211,579      207,721

Depreciation:
 Utility                                         264,609      259,145      263,235
 Nonutility                                        5,770        6,605           11

Capital Expenditures:
 Utility                                         229,362      284,648      289,454
 Nonutility                                        6,205          829      180,245

</TABLE>

      The  1998  utility  extraordinary  charge,  net,  reflects  a  write-
off   of   certain  disallowances  in  the  Pennsylvania  PUC's   May   29,
1998,    restructuring   Order   and   resulting   November    19,    1998,
settlement   agreement   with  regard  to  West  Penn   as   described   in
Notes B and C, starting on pages 50 and 52, respectively.

                                 F-23


<PAGE>

                                                      Allegheny Energy, Inc.

Note N: Commitments and Contingencies

Construction Program

       The   subsidiaries   have  entered  into   commitments   for   their
construction  programs,  for  which  expenditures  are  estimated   to   be
$315   million   for   1999  and  $294  million  for   2000.   Construction
expenditure   levels   in  2001  and  beyond  will   depend   upon,   among
other   things,  the  strategy  eventually  selected  for  complying   with
Phase  II  of  the  Clean  Air  Act  Amendments  of  1990  and  the  extent
to    which    environmental   initiatives   currently   being   considered
become   mandated.   The  Company  estimates  that  its   banked   emission
allowances   will  allow  it  to  comply  with  Phase  II  sulfur   dioxide
(SO2)   limits   through   2005.   Studies   to   evaluate   cost-effective
options  to  comply  with  Phase  II  SO2  limits  beyond  2005,  including
those   available  in  connection  with  the  emission  allowance   trading
market, are continuing.

Market Risk

       The   Company's  utility  subsidiaries  and  AYP  Energy,   one   of
the   Company's  nonutility  subsidiaries,  supply  power   in   the   bulk
power  market.  At  December  31,  1998,  the  marketing  books  for   such
operations    consisted   primarily   of   fixed-priced,   forward-purchase
and/or    sale    contracts   which   require   settlement   by    physical
delivery   of   electricity.   These   transactions   result   in    market
risk,    which   occurs   when   the   market   price   of   a   particular
obligation or entitlement varies from the contract price.

       The   Company   has   a   Corporate  Energy  Risk   Control   Policy
adopted   by   the  Board  of  Directors  and  monitored  by  an   Exposure
Management   Committee   of  senior  management.   This   policy   requires
continuous   monitoring   for   conformity   to   policies   which    limit
value  at  risk  and  market  risk  associated  with  the  credit  standing
of   trading   counterparties.  Such  credit  standing   must   be   within
the   guidelines   established  by  the  Company's  Risk  Control   Policy.
The   Company's  exposure  to  volatility  in  the  price  of   electricity
and   other  energy  commodities  is  maintained  within  approved   policy
limits,    but    has    increased   as   a    result    of    Pennsylvania
restructuring,   which   created   retail   access   to    a    deregulated
electric supply market.

Environmental Matters and Litigation

       The  companies  are  subject  to  various  laws,  regulations,   and
uncertainties   as  to  environmental  matters.  Compliance   may   require
them   to   incur  substantial  additional  costs  to  modify  or   replace
existing   and   proposed  equipment  and  facilities  and  may   adversely
affect the cost of future operations.

       The   Environmental  Protection  Agency  (EPA)  issued   its   final
regional   nitrogen   oxides   (NOx)  State   Implementation   Plan   (SIP)
call   rule  on  September  24,  1998.  The  EPA's  SIP  call  rule   found
that   22   eastern   states   (including   Maryland,   Pennsylvania,   and
West   Virginia)  and  the  District  of  Columbia  are  all   contributing
significantly   to   ozone   nonattainment   in   downwind   states.    The
final   rule   declares   that   this  downwind   nonattainment   will   be
eliminated    (or   sufficiently   mitigated)   if   the   upwind    states
reduce  their  NOx  emissions  by  an

                                 F-24

<PAGE>

                                                       Allegheny Energy, Inc.

amount  that  is  precisely  set  by the   EPA  on a state-by-state  basis.
The  final   SIP   call   rule requires   that   all  state-adopted  NOx
reduction   measures   must   be incorporated   into   SIPs  by September 24,
1999,   and   must   be implemented   by  May  1,  2003.  The  Company's
compliance   with   these requirements   would   require  the installation
of   post-combustion control   technologies  on  most,  if  not  all,  of
its  power   stations at  a  cost  of  approximately  $360  million.  The
Company  continues  to work    with    other   coal-burning   utilities
and    other    affected constituencies   in   coal-producing   states
to   challenge   this   EPA action.

       The   utility   subsidiaries  previously  reported  that   the   EPA
had   identified   them   as   potentially   responsible   parties,   along
with   approximately   175  others,  in  a  Superfund   site   subject   to
cleanup.   A   final   determination   has   not   been   made   for    the
subsidiaries'  share  of  the  remediation  costs  based  on   the   amount
of   materials   sent   to  the  site.  The  regulated  subsidiaries   have
also    been    named   as   defendants   along   with    multiple    other
defendants   in   pending   asbestos   cases   involving   one   or    more
plaintiffs.   The   utility  subsidiaries  believe  that   provisions   for
liabilities    and    insurance   recoveries   are    such    that    final
resolution   of   these  claims  will  not  have  a  material   effect   on
their financial position.

                                   F-25


<PAGE>

                                                   Monongahela Power Company


REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors and the Shareholder
of Monongahela Power Company

In our opinion, the accompanying balance sheet, statement of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Monongahela Power Company (a
subsidiary of Allegheny Energy, Inc.) at December 31, 1998 and
1997, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.  These
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements based on our audits.  We conducted our
audits of these statements in accordance with generally accepted
auditing standards which 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, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation.  We
believe that our audits provide a reasonable basis for the
opinion expressed above.



PricewaterhouseCoopers LLP



Pittsburgh, Pennsylvania
February 4, 1999

                                      F-26


<PAGE>

                                                    Monongahela Power Company

STATEMENT OF INCOME

<TABLE>
<CAPTION>

                                                                          YEAR ENDED DECEMBER 31
(Thousands of Dollars)                                                 1998         1997        1996

Electric Operating Revenues:
  <S>                                                                <C>         <C>         <C>
  Residential.....................................................   $200,896    $199,931    $206,033
  Commercial......................................................    126,464     118,825     121,631
  Industrial......................................................    208,613     196,716     200,970
  Wholesale and other, including affiliates.......................     89,396      95,579      86,474
  Bulk power transactions, net....................................     19,753      17,260      17,363
    Total Operating Revenues......................................    645,122     628,311     632,471

Operating Expenses:
  Operation:
    Fuel..........................................................    143,993     141,340     135,833
    Purchased power and exchanges, net............................     95,617      98,266     101,593
    Deferred power costs, net.....................................     (8,452)    (10,027)     (3,051)
    Other.........................................................     82,637      75,908      76,105
  Maintenance.....................................................     67,033      70,561      74,735
  Internal restructuring charges..................................                             24,299
  Depreciation....................................................     58,610      56,593      55,490
  Taxes other than income taxes...................................     44,742      38,776      40,418
  Federal and state income taxes..................................     49,456      47,519      34,496
    Total Operating Expenses......................................    533,636     518,936     539,918
    Operating Income..............................................    111,486     109,375      92,553

Other Income and Deductions:
  Allowance for other than borrowed funds used during
    construction..................................................        376         570         313
  Other income, net...............................................      6,049       8,498       6,831
    Total Other Income and Deductions.............................      6,425       9,068       7,144
    Income Before Interest Charges................................    117,911     118,443      99,697

Interest Charges:
  Interest on long-term debt......................................     32,363      36,076      36,654
  Other interest..................................................      3,790       2,654       1,950
  Allowance for borrowed funds used during construction...........       (667)       (816)       (359)
    Total Interest Charges........................................     35,486      37,914      38,245
Net Income.........................................................   $82,425    $ 80,529    $ 61,452

STATEMENT OF RETAINED EARNINGS

Balance at January 1..............................................   $243,939    $215,221    $208,761
Add:
  Net income......................................................     82,425      80,529      61,452

                                                                      326,364     295,750     270,213
Deduct:
  Dividends on capital stock:
    Preferred stock...............................................      5,037       5,037       5,037
    Common stock..................................................     48,129      46,774      49,955
      Total Deductions............................................     53,166      51,811      54,992

Balance at December 31............................................   $273,198    $243,939    $215,221

</TABLE>

See accompanying notes to financial statements.

                                      F-27


<PAGE>

                                                    Monongahela Power Company

STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>

                                                                          YEAR ENDED DECEMBER 31
(Thousands of Dollars)                                                 1998        1997        1996

Cash Flows from Operations:
  <S>                                                                <C>         <C>         <C>
  Net income......................................................   $ 82,425    $ 80,529    $ 61,452
  Depreciation....................................................     58,610      56,593      55,490
  Deferred investment credit and income taxes, net................     14,827      18,139       7,739
  Deferred power costs, net.......................................     (8,452)    (10,027)     (3,051)
  Unconsolidated subsidiaries' dividends in excess of earnings....      9,301         988       3,100
  Allowance for other than borrowed funds used during
    construction..................................................       (376)       (570)       (313)
  Internal restructuring liability................................       (236)    (13,761)     13,734
  Changes in certain current assets and liabilities:
    Accounts receivable, net......................................     (8,907)        (80)      4,356
    Materials and supplies........................................     (3,929)      1,878       5,123
    Accounts payable..............................................     15,324     (11,453)     (9,970)
  Other, net......................................................      2,198      (5,100)      8,998

                                                                      160,785     117,136     146,658

Cash Flows from Investing:
  Construction expenditures (less allowance for other than
    borrowed funds used during construction)......................    (72,419)    (77,569)    (72,264)

Cash Flows from Financing:
  Issuance of long-term debt......................................     85,918
  Retirement of long-term debt....................................   (111,690)    (15,500)    (18,500)
  Short-term debt, net............................................     (7,829)     28,590       1,271
  Notes payable to affiliates.....................................     (1,450)     (1,450)
  Dividends on capital stock:
    Preferred stock...............................................     (5,037)     (5,037)     (5,037)
    Common stock..................................................    (48,129)    (46,774)    (49,955)

                                                                      (88,217)    (40,171)    (72,221)


Net Change in Cash and Temporary Cash Investments.................        149        (604)      2,173
Cash and temporary cash investments at January 1..................      1,686       2,290         117
Cash and temporary cash investments at December 31................   $  1,835    $  1,686    $  2,290


Supplemental Cash Flow Information:
  Cash paid during the year for:
    Interest (net of amount capitalized)..........................   $ 33,041    $ 36,776    $ 37,190
    Income taxes..................................................     33,361      28,282      31,064

</TABLE>

See accompanying notes to financial statements.


                                 F-28

<PAGE>

                                                    Monongahela Power Company
BALANCE SHEET

(Thousands of Dollars)
                                                         DECEMBER 31

                                                     1998            1997
ASSETS

Property, Plant, and Equipment:
  At original cost, including $43,657 and
    $55,588 under construction...........         $2,007,876      $1,950,478
  Accumulated depreciation...............           (883,915)       (840,525)

                                                   1,123,961       1,109,953
Investments:
  Allegheny Generating Company--common
   stock at equity.......................             44,624          53,888
  Other..................................                231             268

                                                      44,855          54,156
Current Assets:
  Cash...................................              1,835           1,686
  Accounts receivable:
    Electric service, net of $2,516 and
     $2,176 uncollectible allowance......             68,293          68,143
    Affiliated and other.................             19,674          10,917
  Materials and supplies--at average cost:
    Operating and construction...........             21,942          18,716
    Fuel.................................             16,588          15,885
  Prepaid taxes..........................             19,627          17,287
  Other, including current portion
   of regulatory assets..................              9,652           3,559

                                                     157,611         136,193
Deferred Charges:
  Regulatory assets......................            154,882         164,260
  Unamortized loss on reacquired debt....             17,826          14,338
  Other..................................             19,893          14,354

                                                     192,601         192,952
Total....................................         $1,519,028      $1,493,254


CAPITALIZATION AND LIABILITIES

Capitalization:
  Common stock, other paid-in capital,
   and retained earnings.................         $  570,188      $  540,930
  Preferred stock........................             74,000          74,000
  Long-term debt and QUIDS...............            453,917         455,088

                                                   1,098,105       1,070,018
Current Liabilities:
  Short-term debt........................             49,000          56,829
  Long-term debt due within one year.....                             20,100
  Notes payable to affiliates............                              1,450
  Accounts payable.......................             13,080           5,910
  Accounts payable to affiliates.........             13,958           5,804
  Taxes accrued:
    Federal and state income.............              6,277           5,046
    Other................................             23,192          18,935
  Interest accrued.......................              7,692           7,877
  Other..................................             13,362          13,470

                                                     126,561         135,421
Deferred Credits and Other Liabilities:
  Unamortized investment credit..........             16,155          18,297
  Deferred income taxes..................            242,805         235,291
  Regulatory liabilities.................             15,476          16,973
  Other..................................             19,926          17,254

                                                     294,362         287,815
Commitments and Contingencies (Note L)
 Total...................................         $1,519,028      $1,493,254

See accompanying notes to financial statements

                                     F-29


<PAGE>

                                                    Monongahela Power Company
STATEMENT OF CAPITALIZATION

<TABLE>
<CAPTION>

                                                                                  DECEMBER 31
                                                                     1998      1997         1998      1997
                                                                 (Thousands of Dollars)  (Capitalization Ratios)

Common Stock:
  Common stock--par value $50 per share, authorized
    <S>                                                          <C>            <C>
    8,000,000 shares, outstanding 5,891,000 shares....           $  294,550     $  294,550
  Other paid-in capital...............................                2,441          2,441
  Retained earnings...................................              273,197        243,939
      Total...........................................              570,188        540,930      51.9%     50.6%

</TABLE>

Preferred Stock:
  Cumulative preferred stock--par value $100 per share,
    authorized 1,500,000 shares, outstanding as follows:

<TABLE>
<CAPTION>

                   December 31, 1998
                                Regular
                  Shares      Call Price    Date of
    Series     Outstanding    Per Share      Issue
    <S>           <C>           <C>           <C>                     <C>            <C>
    4.40% ....    90,000        $106.50       1945                    9,000          9,000
    4.80% B...    40,000         105.25       1947                    4,000          4,000
    4.50% C...    60,000         103.50       1950                    6,000          6,000
    $6.28 D...    50,000         102.86       1967                    5,000          5,000
    $7.73 L...   500,000         100.00       1994                   50,000         50,000
      Total (annual dividend requirements $5,037)                    74,000         74,000       6.8       6.9

</TABLE>

Long-Term Debt and QUIDS:

<TABLE>
<CAPTION>

  First mortgage    Date of        Date       Date
  bonds:             Issue      Redeemable    Due
    <S>               <C>          <C>        <C>                    <C>            <C>
    5-5/8% ...        1993         2000       2000                   65,000         65,000
    7-3/8% ...        1992         2002       2002                   25,000         25,000
    7-1/4% ...        1992         2002       2007                   25,000         25,000
    8-5/8% ...        1991         2001       2021                   50,000         50,000
    8-1/2% ...        1992         1998       2022                                  65,000
    8-3/8% ...        1992         2002       2022                   40,000         40,000
    7-5/8% ...        1995         2005       2025                   70,000         70,000

</TABLE>

                                   December 31, 1998
                                     Interest Rate

<TABLE>
<CAPTION>

  <S>                                  <C>                           <C>            <C>
  Quarterly Income Debt Securities
    due 2025......................         8.00%                     40,000         40,000
  Secured notes due 2002-2024.....     4.70%-6.875%                  74,050         74,050
  Unsecured notes due 2002-2012...     4.35%-5.10%                    6,060          6,560
  Installment purchase
    obligations due 2003..........        4.50%                      19,100         19,100
  Medium-term debt due 2003.......     5.56%-5.71%                   43,475
  Unamortized debt discount and premium, net..........               (3,768)        (4,522)
      Total (annual interest requirements $31,498)                  453,917        475,188
  Less current maturities.............................                             (20,100)
      Total...........................................              453,917        455,088      41.3      42.5

Total Capitalization..................................           $1,098,105     $1,070,018     100.0%    100.0%

</TABLE>


See accompanying notes to financial statements.

                               F-30


<PAGE>

                                                    Monongahela Power Company


NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)


NOTE A:  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Monongahela Power Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System).  The Company and its utility affiliates, The
Potomac Edison Company and West Penn Power Company, do business
as Allegheny Power.

The Company is subject to regulation by the Securities and
Exchange Commission (SEC), by various state bodies having
jurisdiction, and by the Federal Energy Regulatory Commission
(FERC).  Significant accounting policies of the Company are
summarized below.

Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.

Revenues
Revenues, including amounts resulting from the application of
fuel and energy cost adjustment clauses, are recognized in the
same period in which the related electric services are provided
to customers by recording an estimate for unbilled revenues for
services provided from the meter reading date to the end of the
accounting period.

Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other utilities and power marketers,
including transmission services, are deferred until they are
either recovered from or credited to customers under fuel and
energy cost-recovery procedures.

Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost,
less contributions in aid of construction, except for capital
leases, which are recorded at present value.  Costs include
direct labor and material; allowance for funds used during
construction (AFUDC) on property for which construction work in
progress is not included in rate base; and indirect costs such as
administration, maintenance, and depreciation of transportation
and construction equipment, postretirement benefits, taxes, and
other benefits related to employees engaged in construction.

The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.

Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used."  AFUDC is recognized as a cost

                               F-31


<PAGE>

                                                   Monongahela Power Company


of property, plant, and equipment with offsetting credits to
other income and interest charges.  Rates used for computing
AFUDC in 1998, 1997, and 1996 were 6.56%, 7.55%, and 7.90%,
respectively.  AFUDC is not included in the cost of construction
when the cost of financing the construction is being recovered
through rates.

Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.1% of
average depreciable property in each of the years 1998, 1997, and
1996.  The cost of maintenance and of certain replacements of
property, plant, and equipment is charged principally to
operating expenses.

Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash
investments with original maturities of three months or less,
generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the
equivalent of cash.

Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities based on cost-based ratemaking regulation.

Income Taxes
The Company joins with its parent and affiliates in filing a
consolidated federal income tax return.  The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.

Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period.  Differences between income tax expense,
computed on the basis of financial accounting income and taxes
payable based on taxable income, are accounted for substantially
in accordance with the accounting procedures followed for
ratemaking purposes.  Deferred tax assets and liabilities
represent the tax effect of temporary differences between the
financial statement and tax basis of assets and liabilities
computed using the most current tax rates.

Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to income with concurrent credits to a deferred
account.  These balances are being amortized over the estimated
service lives of the related properties.

Postretirement Benefits
The Company participates with affiliated companies of Allegheny
Energy, Inc. in a noncontributory, defined benefit pension plan
covering substantially all employees, including officers.
Benefits are based on the employee's years of service and
compensation.  The funding policy is to contribute annually at
least the minimum amount required under the Employee Retirement
Income Security Act and not more than can be deducted for federal
income tax purposes.

                                   F-32


<PAGE>

                                                   Monongahela Power Company

The Company and its affiliates also provide partially
contributory medical and life insurance plans for eligible
retirees and dependents.  Medical benefits, which make up the
largest component of the plans, are based upon an age and years-
of-service vesting schedule and other plan provisions.  The
funding plan for these costs is to contribute the maximum amount
that can be deducted for federal income tax purposes.  Funding of
these benefits is made primarily into Voluntary Employee
Beneficiary Association trust funds.  Medical benefits are self-
insured.  The life insurance plan is paid through insurance
premiums.

Capitalized Software Costs
The Company capitalizes the cost of software developed for
internal use.  These costs are amortized on a straight-line basis
over a five-year period beginning upon a project's completion.

Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," effective for
1998, established standards for reporting comprehensive income
and its components (revenues, expenses, gains, and losses) in
financial statements.  The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.

Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility operations
which includes the generation, purchase, transmission,
distribution, and sale of electricity.

NOTE B:  PROPOSED MERGER

On April 7, 1997, the Company's parent, Allegheny Power System,
Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
announced that they had agreed to merge in a tax-free, stock-for-
stock transaction.

At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger.  Allegheny Energy
and DQE made all necessary regulatory filings.  Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania Public Utility
Commission (Pennsylvania PUC), and the FERC.  The Pennsylvania
PUC and the FERC approvals were subject to conditions acceptable
to Allegheny Energy.  In addition, while not required, the
Maryland Public Service Commission and the Public Utilities
Commission of Ohio have indicated their approval.

On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger.  Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement.  In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.

On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief.  The District Court
did not rule on the merits of the lawsuit for specific
performance or damages.  On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States

                              F-33


<PAGE>

                                                    Monongahela Power Company


Court of Appeals for the Third Circuit.  Allegheny Energy cannot
predict the outcome of this litigation.

All of the Company's incremental costs of the merger process
($4.4 million through December 31, 1998) are being deferred.  The
accumulated merger costs will be written off by the Company when
the merger occurs or if it is determined that the merger will not
occur.

NOTE C:  INTERNAL RESTRUCTURING CHARGES

In 1996, the System, including the Company, completed its
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations.  During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.

In 1996, the Company recorded restructuring charges of $24.3
million ($14.6 million after tax) in operating expenses,
including its share of all restructuring charges associated with
the reorganization.  These charges reflected liabilities and
payments for severance, employee termination costs, and other
restructuring costs.  The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits), consists of:

(Thousands of Dollars)                                    1998       1997

Internal restructuring liability:
  Balance at beginning of period....................     $ 236      $13,997
  Less payments and accrual reversals...............      (236)     (13,761)
Balance at end of period............................     $  -       $   236


As part of the reorganization, the Company and its utility
affiliates in 1996 expanded the intercompany use of each other's
employees to optimize the use of their skills.  In 1997 virtually
all the employees in the System, including all of the Company's
employees, were transferred to Allegheny Power Service
Corporation (APSC) to facilitate the intercompany use of
personnel.  APSC was formed in 1963 pursuant to the Public
Utility Holding Company Act of 1935 to perform certain functions
common to all companies in the System.  APSC bills each company
at its cost (without profit) based on the work performed and
services provided to each company.

                               F-34


<PAGE>

                                                   Monongahela Power Company


NOTE D:  INCOME TAXES

Details of federal and state income tax provisions are:

(Thousands of Dollars)                      1998         1997         1996

Income taxes--current:
  Federal.............................    $26,457      $21,812     $19,412
  State...............................      8,135        7,455       7,317
    Total.............................     34,592       29,267      26,729
Income taxes--deferred, net of
  amortization........................     16,971       20,287       9,883
Amortization of deferred
  investment credit...................     (2,144)      (2,148)     (2,145)
    Total income taxes................     49,419       47,406      34,467
Income taxes--credited to other
  income and deductions...............         37          113          29
Income taxes--charged to operating
  income..............................    $49,456      $47,519     $34,496


The total provision for income taxes is different from the amount
produced by applying the federal income statutory tax rate of 35%
to financial accounting income, as set forth below:

(Thousands of Dollars)                      1998         1997         1996

Income before income taxes............    $131,881     $128,048    $ 95,948
Amount so produced....................    $ 46,158     $ 44,817    $ 33,582
Increased (decreased) for:
  Tax deductions for which deferred
    tax was not provided:
      Lower tax depreciation..........       1,800        5,000       4,300
      Plant removal costs.............      (2,600)      (2,400)     (2,200)
  State income tax, net of federal
    income tax benefit................       4,400        3,600       4,000
  Amortization of deferred
    investment credit.................      (2,144)      (2,148)     (2,145)
  Equity in earnings of subsidiaries..      (2,100)      (3,000)     (2,500)
  Other, net..........................       3,942        1,650        (541)
    Total.............................    $ 49,456     $ 47,519    $ 34,496


Federal income tax returns through 1993 have been examined and
substantially settled through 1991.

                                     F-35


<PAGE>

                                                   Monongahela Power Company


At December 31, the deferred tax assets and liabilities consisted
of the following:

(Thousands of Dollars)                                   1998         1997

Deferred tax assets:
  Unamortized investment tax credit...............    $ 10,779    $ 12,275
  Tax interest capitalized........................       4,269       4,500
  Contributions in aid of construction............       2,810       2,619
  Advances for construction.......................       2,097       2,087
  Internal restructuring..........................       1,810          53
  Deferred power costs, net.......................                   1,266
  Other...........................................      14,358      12,090
                                                        36,123      34,890
Deferred tax liabilities:
  Book vs. tax plant basis differences, net.......     244,432     236,962
  Other...........................................      38,420      33,865
                                                       282,852     270,827
Total net deferred tax liabilities................     246,729     235,937
Portion above included in current liabilities.....      (3,924)       (646)
  Total long-term net deferred tax liabilities....    $242,805    $235,291


NOTE E:  DIVIDEND RESTRICTION

Supplemental indentures relating to certain outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $76,384,000 of the Company's retained
earnings at December 31, 1998, is not available for cash
dividends on common stock, except that a portion thereof may be
paid as cash dividends where concurrently an equivalent amount of
cash is received by the Company as a capital contribution or as
the proceeds of the issue and sale of shares of its common stock.

NOTE F:  ALLEGHENY GENERATING COMPANY

The Company owns 27% of the common stock of Allegheny Generating
Company (AGC), and affiliates of the Company own the remainder.
AGC is reported by the Company in its financial statements using
the equity method of accounting. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.

AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and a
return on its investment under a wholesale rate schedule approved
by the FERC.  AGC's rates are set by a formula filed with and
previously accepted by the FERC.  The only component which
changes is the return on equity (ROE).  Pursuant to a settlement
agreement filed April 4, 1996, with the FERC, AGC's ROE was set
at 11% for 1996 and will continue until the time any affected
party seeks renegotiation of the ROE.

                                 F-36


<PAGE>

                                                   Monongahela Power Company

Following is a summary of financial information for AGC:

                                                         December 31
(Thousands of Dollars)                               1998          1997

Balance sheet information:
  Property, plant, and equipment...............    $618,608    $635,485
  Current assets...............................       5,857      11,876
  Deferred charges.............................      14,993      16,559
    Total assets...............................    $639,458    $663,920

  Total capitalization.........................    $314,105    $348,258
  Current liabilities..........................      75,849      70,540
  Deferred credits.............................     249,504     245,122
    Total capitalization and liabilities.......    $639,458    $663,920


                                                Year Ended December 31
 (Thousands of Dollars)                      1998         1997         1996

Income statement information:
  Electric operating revenues.........    $73,816      $76,458      $83,402
  Operation and maintenance expense...      4,592        4,877        5,165
  Depreciation........................     16,949       17,000       17,160
  Taxes other than income taxes.......      4,662        4,835        4,801
  Federal income taxes................     10,959       11,213       13,297
  Interest charges....................     13,987       15,391       16,193
  Other income, net...................        (86)      (9,126)          (3)
    Net income........................    $22,753      $32,268      $26,789


The Company's share of the equity in earnings was $6.1 million,
$8.7 million, and $7.2 million for 1998, 1997, and 1996,
respectively, and is included in other income, net, on the
Company's Statement of Income.  Dividends received from AGC in
1998 approximated $15 million which reflects an effort to reduce
AGC equity to about 45% of total capitalization and short-term
debt.

NOTE G:  POSTRETIREMENT BENEFITS

As described in Note A, the Company and its affiliates
participate in a pension plan and medical and life insurance
plans for eligible employees and dependents.  The Company is
responsible for its proportional share of the costs (credits) and
the assets or liabilities of the plans.  As described in Note C,
in 1997 the Company transferred all of its employees to APSC.
The Company's share of the costs (credits) of these plans, a
portion of which (about 25% to 35%) was charged to plant
construction, is as follows:

(Thousands of Dollars)                       1998        1997         1996

Pension................................     $ (356)    $(1,754)     $   78
Medical and life insurance.............     $5,421     $ 3,706      $5,461

                                  F-37


<PAGE>

                                                    Monongahela Power Company


NOTE H:  REGULATORY ASSETS AND LIABILITIES

The Company's operations are subject to the provisions of SFAS
No. 71.  Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process.  Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process.  Regulatory assets, net of
regulatory liabilities, reflected in the Balance Sheet at
December 31 relate to:

(Thousands of Dollars)                                 1998         1997

Long-Term Assets (Liabilities), Net:
  Income taxes, net..............................    $130,878   $137,056
  Postretirement benefits........................       4,937      4,937
  Storm damage...................................       1,047      2,211
  Other, net.....................................       2,544      3,083
    Subtotal.....................................     139,406    147,287
Current Assets (Liabilities), Net:
  Income taxes, net (reported in other
    current assets)..............................       1,847      1,847
  Deferred power costs, net......................       6,878       (484)
    Subtotal.....................................       8,725      1,363
      Net Regulatory Assets......................    $148,131   $148,650


Deregulation/competition proceedings in West Virginia and Ohio
may in the future result in less than full recovery of costs
incurred to serve customers. Such deregulation and transition to
a competitive environment could adversely affect the Company's
results of operations, cash flows, and capitalization.  Such
charges, if any, are not estimable at this time.

NOTE I:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:

                                    1998                     1997
                            Carrying       Fair       Carrying       Fair
(Thousands of Dollars)       Amount        Value       Amount        Value

Liabilities:
  Short-term debt.......    $ 49,000     $ 49,000     $ 58,279    $ 58,279
  Long-term debt and
    QUIDS...............     457,685      483,695      479,710     528,155


The carrying amount of short-term debt approximates the fair
value because of the short maturity of those instruments.  The
fair value of long-term debt and QUIDS was estimated based on
actual market prices or market prices of similar issues.  The
Company has no financial instruments held or issued for trading
purposes.

                                F-38


<PAGE>

                                                   Monongahela Power Company


NOTE J:  CAPITALIZATION

Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.

Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are: 1999, none; 2000, $65,000; 2001, none; 2002,
$27,060; and 2003, $62,575. Substantially all of the properties
of the Company are held subject to the lien securing its first
mortgage bonds.  Some properties are also subject to a second
lien securing certain pollution control and solid waste disposal
notes. Certain first mortgage bonds series are not redeemable by
certain refunding until dates established in the respective
supplemental indentures.

NOTE K:  SHORT-TERM DEBT

To provide interim financing and support for outstanding
commercial paper, the System companies have established lines of
credit with several banks.  The Company has SEC authorization for
total short-term borrowings of $106 million, including money pool
borrowings described below.  The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements.  In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available.  Short-term debt outstanding for
1998 and 1997 consisted of:

(Thousands of Dollars)                          1998         1997

Balance and interest rate
  at end of year:
    Commercial Paper...................                   $56,829-6.50%
    Notes Payable to Banks.............    $49,000-5.40%
    Money Pool.........................                     1,450-5.96%
Average amount outstanding and
  interest rate during the year:
    Commercial Paper...................     12,900-5.66%    1,651-5.76%
    Notes Payable to Banks.............     21,793-5.60%    7,307-5.56%
    Money Pool.........................      3,764-5.46%    9,300-5.44%


NOTE L:  COMMITMENTS AND CONTINGENCIES

Construction Program
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $76 million
for 1999 and $79 million for 2000.  Construction expenditure
levels in 2001 and beyond will depend upon, among other things,
the strategy eventually selected for complying with Phase II of
the Clean Air Act Amendments of 1990 and the extent to which
environmental initiatives currently being considered become
mandated.  The Company estimates that its banked emission
allowances will allow it to comply with Phase II sulfur dioxide
(SO2) limits through 2005.  Studies to evaluate cost-effective
options to comply with Phase II SO2 limits beyond 2005, including
those available in connection with the emission allowance trading
market, are continuing.

                               F-39


<PAGE>

                                                   Monongahela Power Company


Market Risk
The Company supplies power in the bulk power market.  At December
31, 1998, the marketing books for such operations consisted
primarily of fixed-priced, forward-purchase and/or sale contracts
which require settlement by physical delivery of electricity.

Allegheny Energy has a Corporate Energy Risk Control Policy
adopted by the Board of Directors and monitored by an Exposure
Management Committee of senior management.  This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of counterparties.  Such credit standing must be within the
guidelines established by Allegheny Energy's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits.

Environmental Matters and Litigation
System companies are subject to various laws, regulations, and
uncertainties as to environmental matters.  Compliance may
require them to incur substantial additional costs to modify or
replace existing and proposed equipment and facilities and may
adversely affect the cost of future operations.

The Environmental Protection Agency (EPA) issued its final
regional nitrogen oxides (NOx) State Implementation Plan (SIP)
call rule on September 24, 1998. The EPA's SIP call rule found
that 22 eastern states (including Maryland, Pennsylvania, and
West Virginia) and the District of Columbia are all contributing
significantly to ozone nonattainment in downwind states.  The
final rule declares that this downwind nonattainment will be
eliminated (or sufficiently mitigated) if the upwind states
reduce their NOx emissions by an amount that is precisely set by
the EPA on a state-by-state basis.  The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003.  The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations
at a cost of approximately $96 million.  The Company continues to
work with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action.

The Company previously reported that the EPA had identified it
and its regulated affiliates as potentially responsible parties,
along with approximately 175 others, in a Superfund site subject
to cleanup.  A final determination has not been made for the
Company's share of the remediation costs based on the amount of
materials sent to the site.  The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs.  The Company believes that provisions for liabilities
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.

                                   F-40


<PAGE>

                                                  The Potomac Edison Company

REPORT OF INDEPENDENT ACCOUNTANTS



To the Board of Directors and the Shareholders
of The Potomac Edison Company


In our opinion, the accompanying balance sheet and statement of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material
respects, the financial position of The Potomac Edison Company (a
subsidiary of Allegheny Energy, Inc.) at December 31, 1998 and
1997, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.  These
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements based on our audits.  We conducted our
audits of these statements in accordance with generally accepted
auditing standards which 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, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation.  We
believe that our audits provide a reasonable basis for the
opinion expressed above.



PricewaterhouseCoopers LLP



Pittsburgh, Pennsylvania
February 4, 1999

                                      F-41


<PAGE>

                                                  The Potomac Edison Company

STATEMENT OF INCOME

<TABLE>
<CAPTION>

                                                                          YEAR ENDED DECEMBER 31
(Thousands of Dollars)                                                 1998        1997        1996

Electric Operating Revenues:
  <S>        <C>                                                     <C>         <C>         <C>
  Residential.....................................................   $309,058    $299,876    $324,120
  Commercial......................................................    156,973     148,287     146,432
  Industrial......................................................    206,638     198,174     196,813
  Wholesale and other, including affiliates.......................     38,426      38,857      34,901
  Bulk power transactions, net....................................     26,399      23,587      24,494
    Total Operating Revenues......................................    737,494     708,781     726,760

Operating Expenses:
  Operation:
    Fuel..........................................................    143,124     140,206     137,310
    Purchased power and exchanges, net............................    138,277     140,183     141,027
    Deferred power costs, net.....................................      1,812      (4,944)      5,040
    Other.........................................................     86,785      83,905      89,756
  Maintenance.....................................................     52,186      56,815      62,248
  Internal restructuring charges..................................    				                     26,094
  Depreciation....................................................     74,344      71,763      71,254
  Taxes other than income taxes...................................     49,567      47,585      45,809
  Federal and state income taxes..................................     52,603      44,496      34,132
    Total Operating Expenses......................................    598,698     580,009     612,670
    Operating Income..............................................    138,796     128,772     114,090

Other Income and Deductions:
  Allowance for other than borrowed funds used
    during construction...........................................        597       1,716       1,409
  Other income, net...............................................      9,297      13,976      11,791
    Total Other Income and Deductions.............................      9,894      15,692      13,200
    Income Before Interest Charges................................    148,690     144,464     127,290

Interest Charges:
  Interest on long-term debt......................................     46,010      47,659      47,982
  Other interest..................................................      2,177       2,164       2,215
  Allowance for borrowed funds used during construction...........       (979)     (1,114)     (1,082)
    Total Interest Charges........................................     47,208      48,709      49,115

Net Income........................................................   $101,482    $ 95,755    $ 78,175






STATEMENT OF RETAINED EARNINGS

Balance at January 1..............................................   $239,391    $227,726    $216,852
Add:
  Net income......................................................    101,482      95,755      78,175

                                                                      340,873     323,481     295,027
Deduct:
  Dividends on capital stock:
    Preferred stock...............................................        818         818         818
    Common stock..................................................     27,533      83,272      66,483
      Total deductions............................................     28,351      84,090      67,301

Balance at December 31............................................   $312,522    $239,391    $227,726

</TABLE>

See accompanying notes to financial statements.

                                      F-42


<PAGE>

                                                   The Potomac Edison Company
STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>

                                                                          YEAR ENDED DECEMBER 31
(Thousands of Dollars)                                                 1998        1997        1996

Cash Flows from Operations:
  <S>                                                               <C>          <C>         <C>
  Net income......................................................  $ 101,482    $ 95,755    $ 78,175
  Depreciation....................................................     74,344      71,763      71,254
  Deferred investment credit and income taxes, net................      8,682       5,984       5,157
  Deferred power costs, net.......................................      1,812      (4,944)      5,040
  Unconsolidated subsidiaries' dividends in excess of earnings....      9,607       1,058       3,211
  Allowance for other than borrowed funds used during
    construction..................................................       (597)     (1,716)     (1,409)
  Internal restructuring liability................................     (1,187)    (13,783)     15,801
  Changes in certain current assets and liabilities:
    Accounts receivable, net......................................      4,472       9,450      (2,016)
    Materials and supplies........................................     (4,462)       (764)      6,768
    Accounts payable..............................................     17,529      (1,994)      4,184
  Other, net......................................................      4,138      10,485      (2,686)
 
                                                                      215,820     171,294     183,479

Cash Flows from Investing:
  Construction expenditures (less allowance for other
    than borrowed funds used during construction).................    (59,928)    (76,582)    (84,847)

Cash Flows from Financing:
  Issuance of long-term debt......................................     33,200
  Retirement of long-term debt....................................    (86,655)       (800)    (18,700)
  Short-term debt, net............................................     (7,497)    (14,140)
  Notes receivable from affiliates................................     (7,850)     (1,450)
  Notes receivable from subsidiary................................    (66,750)
  Dividends on capital stock:
    Preferred stock...............................................       (818)       (818)       (818)
    Common stock..................................................    (27,533)    (83,272)    (66,483)

                                                                      156,406)    (93,837)   (100,141)

Net Change in Cash and Temporary Cash Investments.................       (514)        875      (1,509)
Cash and temporary cash investments at January 1..................      2,319       1,444       2,953
Cash and temporary cash investments at December 31................  $   1,805    $  2,319    $  1,444


Supplemental Cash Flow Information:
  Cash paid during the year for:
    Interest (net of amount capitalized)..........................  $  46,770    $ 47,642    $ 47,580
    Income taxes..................................................     41,132      36,705      37,694

</TABLE>

See accompanying notes to financial statements.

                                 F-43


<PAGE>

                                                  The Potomac Edison Company


BALANCE SHEET


(Thousands of Dollars)

                                                      DECEMBER 31
ASSETS                                           1998            1997

Property, Plant, and Equipment:
  At original cost, including $46,353
   and $55,702 under construction........      $2,249,716      $2,196,262
  Accumulated depreciation...............        (926,840)       (859,076)

                                                1,322,876       1,337,186
Investments and Other Assets:
  Allegheny Generating Company--common
    stock at equity......................          46,277          55,847
  Other..................................             473             529

                                                   46,750          56,376
Current Assets:
  Cash...................................           1,805           2,319
  Accounts receivable:
    Electric service, net of $2,203 and
      $1,683 uncollectible allowance.....          77,170          83,431
    Affiliated and other.................           7,091           5,302
  Notes receivable from affiliate........           9,300           1,450
  Notes receivable from subsidiary.......          66,750
  Materials and supplies--at average cost:
    Operating and construction...........          29,922          23,715
    Fuel.................................          14,098          15,843
  Prepaid taxes..........................          15,727          15,052
  Other..................................           1,092           4,716

                                                  222,955         151,828

Deferred Charges:
  Regulatory assets......................          66,792          80,651
  Unamortized loss on reacquired debt....          19,012          17,094
  Other..................................          23,742          17,512

                                                  109,546         115,257
Total....................................      $1,702,127      $1,660,647


CAPITALIZATION AND LIABILITIES

Capitalization:
  Common stock, other paid-in capital,
    and retained earnings................      $  762,912      $  689,781
  Preferred stock........................          16,378          16,378
  Long-term debt and QUIDS...............         578,817         627,012

                                                1,358,107       1,333,171
Current Liabilities:
  Long-term debt due within one year.....                           1,800
  Accounts payable.......................          35,572          29,125
  Accounts payable to affiliates.........          31,011          19,929
  Deferred income taxes..................          11,311
  Taxes accrued:
    Federal and state income.............           6,430           2,106
    Other................................          18,922          11,461
  Interest accrued.......................           7,193           9,487
  Payrolls accrued.......................                           6,353
  Other..................................           8,770          10,553

                                                  119,209          90,814
Deferred Credits and Other Liabilities:
  Unamortized investment credit..........          19,592          21,470
  Deferred income taxes..................         170,349         178,529
  Regulatory liabilities.................          11,233          12,424
  Other..................................          23,637          24,239

                                                  224,811         236,662
Commitments and Contingencies (Note K)
Total....................................      $1,702,127      $1,660,647

See accompanying notes to financial statements.

                                  F-44


<PAGE>

                                                  The Potomac Edison Company

STATEMENT OF CAPITALIZATION
<TABLE>
<CAPTION>

                                                                                  DECEMBER 31
                                                                  1998        1997          1998     1997
                                                                 (Thousands of Dollars)  (Capitalization Ratios)
Common Stock:
  <S>                                                            <C>         <C>          <C>       <C>
  Common stock--no par value, authorized 23,000,000
    shares, outstanding 22,385,000 shares............         $  447,700  $  447,700
  Other paid-in capital..............................              2,690       2,690
  Retained earnings..................................            312,522     239,391
      Total..........................................            762,912     689,781      56.2%     51.8%

</TABLE>

Preferred Stock:
  Cumulative preferred stock--par value $100 per share,
    authorized 5,378,611 shares, outstanding as follows:

                   December 31, 1998

<TABLE>
<CAPTION>
                                Regular
                  Shares      Call Price    Date of
    Series     Outstanding    Per Share      Issue
    <S>           <C>           <C>           <C>                  <C>         <C>
    3.60% ....    63,784        $103.75       1946                 6,378       6,378
    $5.88 C...   100,000         102.85       1967                10,000      10,000
      Total (annual dividend requirements $818)......             16,378      16,378       1.2       1.2

</TABLE>

Long-Term Debt and QUIDS:

<TABLE>
<CAPTION>

  First mortgage    Date of        Date       Date
  bonds:             Issue      Redeemable    Due
    <S>               <C>          <C>        <C>                 <C>         <C>
    5-7/8% ......     1993         2000       2000                75,000      75,000
    8    % ......     1991         2001       2006                50,000      50,000
    8-7/8% ......     1991         1998       2021                            50,000
    8    % ......     1992         2002       2022                55,000      55,000
    7-3/4% ......     1993         2003       2023                45,000      45,000
    8    % ......     1994         2004       2024                75,000      75,000
    7-5/8% ......     1995         2005       2025                80,000      80,000
    7-3/4% ......     1995         2005       2025                65,000      65,000

</TABLE>

                                   December 31, 1998
                                     Interest Rate

<TABLE>
<CAPTION>

  <S>                                                           <C>         <C>          <C>       <C>
  Quarterly Income Debt Securities
    due 2025..............................  8.00%                 45,457      45,457
  Secured notes due 2007-2024.............  4.70%-6.875%          91,700      91,700
  Unsecured note due 2002.................  4.35%                  3,200       4,000
  Unamortized debt discount...............                        (6,540)     (7,345)
      Total (annual interest requirements
        $42,525)..........................                       578,817     628,812
  Less current maturities.................                                    (1,800)
Total.....................................                       578,817     627,012      42.6      47.0

Total Capitalization......................                    $1,358,107  $1,333,171     100.0%    100.0%

</TABLE>

See accompanying notes to financial statements.


                                 F-45

<PAGE>

                                                   The Potomac Edison Company

NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)


NOTE A:  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Potomac Edison Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System).  The Company and its utility affiliates,
Monongahela Power Company and West Penn Power Company, do
business as Allegheny Power.

The Company is subject to regulation by the Securities and
Exchange Commission (SEC), by various state bodies having
jurisdiction, and by the Federal Energy Regulatory Commission
(FERC).  Significant accounting policies of the Company are
summarized below.

Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.

Revenues
Revenues, including amounts resulting from the application of
fuel and energy cost adjustment clauses, are recognized in the
same period in which the related electric services are provided
to customers by recording an estimate for unbilled revenues for
services provided from the meter reading date to the end of the
accounting period.  Revenues of $65 million from one industrial
customer were 9% of total electric operating revenues in 1998.

Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other utilities and power marketers,
including transmission services, are deferred until they are
either recovered from or credited to customers under fuel and
energy cost-recovery procedures.

Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost,
less contributions in aid of construction.  Costs include direct
labor and material; allowance for funds used during construction
(AFUDC) on property for which construction work in progress is
not included in rate base; and such indirect costs as
administration, maintenance, and depreciation of transportation
and construction equipment, postretirement benefits, taxes, and
other benefits related to employees engaged in construction.

The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.

                              F-46


<PAGE>

                                                  The Potomac Edison Company



Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used."  AFUDC is recognized as a cost of property,
plant, and equipment with offsetting credits to other income and
interest charges.  Rates used for computing AFUDC in 1998, 1997,
and 1996 were 9.83%, 9.75%, and 9.32%, respectively.  AFUDC is
not included in the cost of construction when the cost of
financing the construction is being recovered through rates.
AFUDC is not recorded for construction applicable to the state of
Virginia, where construction work in progress is included in rate
base.

Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.5% of
average depreciable property in each of the years 1998 and 1997,
and 3.6% in 1996.  The cost of maintenance and of certain
replacements of property, plant, and equipment is charged
principally to operating expenses.

Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash
investments with original maturities of three months or less,
generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the
equivalent of cash.

Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities based on cost-based ratemaking regulation.

Income Taxes
The Company joins with its parent and affiliates in filing a
consolidated federal income tax return.  The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.

Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period.  Differences between income tax expense,
computed on the basis of financial accounting income and taxes
payable based on taxable income, are accounted for substantially
in accordance with the accounting procedures followed for
ratemaking purposes.  Deferred tax assets and liabilities
represent the tax effect of temporary differences between the
financial statement and tax basis of assets and liabilities
computed using the most current tax rates.

Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to

                                F-47


<PAGE>

                                                  The Potomac Edison Company

income with concurrent credits to a deferred account.  These
balances are being amortized over the estimated service lives
of the related properties.

Postretirement Benefits
The Company participates with affiliated companies of Allegheny
Energy, Inc. in a noncontributory, defined benefit pension plan
covering substantially all employees, including officers.
Benefits are based on the employee's years of service and
compensation.  The funding policy is to contribute annually at
least the minimum amount required under the Employee Retirement
Income Security Act and not more than can be deducted for federal
income tax purposes.

The Company and its affiliates also provide partially
contributory medical and life insurance plans for eligible
retirees and dependents.  Medical benefits, which make
up the largest component of the plans, are based upon an age and
years-of-service vesting schedule and other plan provisions.  The
funding plan for these costs is to contribute the maximum amount
that can be deducted for federal income tax purposes.  Funding of
these benefits is made primarily into Voluntary Employee
Beneficiary Association trust funds.  Medical benefits are self-
insured.  The life insurance plan is paid through insurance
premiums.

Capitalized Software Costs
The Company capitalizes the cost of software developed for
internal use.  These costs are amortized on a straight-line basis
over a five-year period beginning upon a project's completion.

Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," effective for
1998, established standards for reporting comprehensive income
and its components (revenues, expenses, gains, and losses) in
financial statements.  The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.

Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility operations
which includes the generation, purchase, transmission,
distribution, and sale of electricity.

NOTE B:  PROPOSED MERGER

On April 7, 1997, the Company's parent, Allegheny Power System,
Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
announced that they had agreed to merge in a tax-free, stock-for-
stock transaction.

At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger.  Allegheny Energy
and DQE made all necessary regulatory filings.  Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania Public Utility
Commission (Pennsylvania PUC), and the FERC.  The Pennsylvania
PUC and the FERC approvals were subject to conditions acceptable
to Allegheny Energy.  In addition, while not required, the
Maryland Public

                                F-48


<PAGE>

                                                   The Potomac Edison Company

Service Commission and the Public Utilities Commission of Ohio
have indicated their approval.

On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger.  Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement.  In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.

On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief.  The District Court
did not rule on the merits of the lawsuit for specific
performance or damages.  On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States Court of
Appeals for the Third Circuit.  Allegheny Energy cannot predict
the outcome of this litigation.

All of the Company's incremental costs of the merger process
($5.2 million through December 31, 1998) are being deferred.  The
accumulated merger costs will be written off by the Company when
the merger occurs or if it is determined that the merger will not
occur.

NOTE C:  INTERNAL RESTRUCTURING CHARGES

In 1996, the System, including the Company, completed its
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations.  During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.

In 1996, the Company recorded restructuring charges of $26.1
million ($16.5 million after tax) in operating expenses,
including its share of all restructuring charges associated with
the reorganization.  These charges reflected liabilities and
payments for severance, employee termination costs, and other
restructuring costs.  The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits) consists of:

(Thousands of Dollars)                                    1998         1997

Internal restructuring liability:
  Balance at beginning of period....................     $1,187     $14,970
  Less payments and accrual reversals...............     (1,187)    (13,783)
Balance at end of period............................     $  -       $ 1,187


As part of the reorganization, the Company and its utility
affiliates in 1996 expanded the intercompany use of each other's
employees to optimize the use of their skills.  In 1997 virtually
all the employees in the System, including virtually all of the
Company's employees, were transferred to Allegheny Power Service
Corporation (APSC) to facilitate the intercompany use

                               F-49


<PAGE>

                                                   The Potomac Edison Company


of personnel.  APSC was formed in 1963 pursuant to the Public
Utility Holding Company Act of 1935 to perform certain functions
common to all companies in the System.  APSC bills each company
at its cost (without profit) based on the work performed and
services provided to each company.

NOTE D:  INCOME TAXES

Details of federal and state income tax provisions are:

(Thousands of Dollars)                       1998         1997         1996

Income taxes--current:
  Federal..............................    $40,003      $36,126     $26,651
  State................................      5,569        5,264       4,833
    Total..............................     45,572       41,390      31,484
Income taxes--deferred, net of
  amortization.........................     10,559        8,136       7,351
Amortization of deferred investment
  credit...............................     (1,877)      (2,152)     (2,194)
    Total income taxes.................     54,254       47,374      36,641
Income taxes--charged to other
  income and deductions................     (1,651)      (2,878)     (2,509)
Income taxes--charged to operating
  income...............................    $52,603      $44,496     $34,132


The total provision for income taxes is different from the amount
produced by applying the federal income statutory tax rate of 35%
to financial accounting income, as set forth below:

(Thousands of Dollars)                       1998         1997        1996

Income before income taxes.............    $154,085     $140,251    $112,305
Amount so produced.....................    $ 53,930     $ 49,088    $ 39,307
Increased (decreased) for:
  Tax deductions for which deferred
    tax was not provided:
      Lower tax depreciation...........       2,800        2,900       4,300
      Plant removal costs.............         (800)        (700)     (1,800)
  State income tax, net of federal
    income tax benefit.................       5,100        4,400       1,300
  Amortization of deferred investment
    credit.............................      (1,878)      (2,152)     (2,194)
  Equity in earnings of subsidiaries...      (2,200)      (3,100)     (2,600)
  Other, net...........................      (4,349)      (5,940)     (4,181)
    Total..............................    $ 52,603     $ 44,496    $ 34,132


Federal income tax returns through 1993 have been examined and
substantially settled through 1991.

                                 F-50


<PAGE>

                                                 The Potomac Edison Company



At December 31, the deferred tax assets and liabilities consisted
of the following:

(Thousands of Dollars)                                  1998        1997

Deferred tax assets:
  Contributions in aid of construction............    $ 13,845     $ 13,841
  Tax interest capitalized........................      12,096       12,234
  Unamortized investment tax credit...............      11,442       12,518
  Postretirement benefits other than pensions.....       5,770        3,998
  Unbilled revenue................................       3,492        3,492
  Internal restructuring..........................       2,344        1,239
  Advances for construction.......................         914        1,194
  Other...........................................       3,685        3,436
                                                        53,588       51,952
Deferred tax liabilities:
  Book vs. tax plant basis differences, net.......     218,434      211,837
  Other...........................................      16,814       17,600
                                                       235,248      229,437
Total net deferred tax liabilities................     181,660      177,485
Portion above included in current (liabilities)
  assets..........................................     (11,311)       1,044
    Total long-term net deferred tax liabilities..    $170,349     $178,529


NOTE E:  ALLEGHENY GENERATING COMPANY

The Company owns 28% of the common stock of Allegheny Generating
Company (AGC), and affiliates of the Company own the remainder.
AGC is reported by the Company in its financial statements using
the equity method of accounting. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.

AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and a
return on its investment under a wholesale rate schedule approved
by the FERC.  AGC's rates are set by a formula filed with and
previously accepted by the FERC.  The only component which
changes is the return on equity (ROE).  Pursuant to a settlement
agreement filed April 4, 1996, with the FERC, AGC's ROE was set
at 11% for 1996 and will continue until the time any affected
party seeks renegotiation of the ROE.

                               F-51


<PAGE>

                                                  The Potomac Edison Company


Following is a summary of financial information for AGC:


                                                         December 31
(Thousands of Dollars)                                1998         1997

Balance sheet information:
  Property, plant, and equipment...............     $618,608     $635,485
  Current assets...............................        5,857       11,876
  Deferred charges.............................       14,993       16,559
    Total assets...............................     $639,458     $663,920

  Total capitalization.........................     $314,105     $348,258
  Current liabilities..........................       75,849       70,540
  Deferred credits.............................      249,504      245,122
    Total capitalization and liabilities.......     $639,458     $663,920


                                                 Year Ended December 31
(Thousands of Dollars)                       1998         1997         1996

Income statement information:
  Electric operating revenues.........     $73,816      $76,458       $83,402
  Operation and maintenance expense...       4,592        4,877         5,165
  Depreciation........................      16,949       17,000        17,160
  Taxes other than income taxes.......       4,662        4,835         4,801
  Federal income taxes................      10,959       11,213        13,297
  Interest charges....................      13,987       15,391        16,193
  Other income, net...................         (86)      (9,126)           (3)
    Net income........................     $22,753      $32,268       $26,789


The Company's share of the equity in earnings was $6.4 million,
$9.0 million, and $7.5 million for 1998, 1997, and 1996,
respectively, and is included in other income, net, on the
Company's Statement of Income.  Dividends received from AGC in
1998 approximated $16 million which reflects an effort to reduce
AGC equity to about 45% of total capitalization and short-term
debt.

At December 31, 1998 the Company had an outstanding short-term
loan to AGC of $66.8 million at 4.80% through the Allegheny
Energy money pool.

NOTE F:  POSTRETIREMENT BENEFITS

As described in Note A, the Company and its affiliates
participate in a pension plan and medical and life insurance
plans for eligible employees and dependents.  The Company is
responsible for its proportional share of the costs (credits) and
the assets or liabilities of the plans.  As described in Note C,
in 1997 the Company transferred virtually all of its employees to
APSC.  The Company's share of the costs (credits) of these plans,
a portion of which (about 25% to 35%) was charged to plant
construction, is as follows:

(Thousands of Dollars)                       1998         1997         1996
Pension................................     $ (323)     $(1,745)     $ (201)
Medical and life insurance.............     $4,893      $ 4,007      $5,831

                                F-52


<PAGE>

                                                  The Potomac Edison Company


NOTE G:  REGULATORY ASSETS AND LIABILITIES

The Company's operations are subject to the provisions of SFAS
No. 71. Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process.  Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process.  Regulatory assets, net of
regulatory liabilities, reflected in the Balance Sheet at
December 31 relate to:

(Thousands of Dollars)                                 1998         1997

Long-Term Assets (Liabilities), Net:
  Income taxes, net.............................     $45,847       $52,231
  Demand-side management........................       8,157        14,204
  Postretirement benefits.......................       1,292         1,292
  Deferred power costs (reported in other 
    deferred credits)...........................      (2,455)       (2,949)
  Other, net....................................         263           500
    Subtotal....................................      53,104        65,278
Current Assets (Liabilities), Net:
  Deferred power costs (reported in
    other current assets).......................         333         2,682
      Net Regulatory Assets.....................     $53,437       $67,960


Deregulation/competition proceedings in Maryland, Virginia, and
West Virginia may in the future result in less than full recovery
of costs incurred to serve customers.  Such deregulation and
transition to a competitive environment could adversely affect
the Company's results of operations, cash flows, and
capitalization.  Such charges, if any, are not estimable at this
time.

NOTE H:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:

                                     1998                       1997
                             Carrying       Fair       Carrying       Fair
(Thousands of Dollars)        Amount        Value       Amount        Value

Liabilities:
  Long-term debt and
    QUIDS................    $585,357     $607,726     $636,157     $672,198


The fair value of long-term debt and QUIDS was estimated based on
actual market prices or market prices of similar issues.  The
Company has no financial instruments held or issued for trading
purposes.

                                     F-53


<PAGE>

                                                   The Potomac Edison Company



NOTE I:  CAPITALIZATION

Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.

Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are:  1999, none; 2000, $75,000; 2001, none;
2002, $3,200; and 2003, none.  Substantially all of the
properties of the Company are held subject to the lien securing
its first mortgage bonds.  Some properties are also subject to a
second lien securing certain pollution control and solid waste
disposal notes. Certain first mortgage bond series are not
redeemable by certain refunding until dates established in the
respective supplemental indentures.

NOTE J:  SHORT-TERM DEBT

To provide interim financing and support for outstanding
commercial paper, the System companies have established lines of
credit with several banks.  The Company has SEC authorization for
total short-term borrowings of $130 million, including money pool
borrowings described below.  The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements.  In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available.  Short-term debt outstanding for
1998 and 1997 consisted of:

(Thousands of Dollars)                           1998         1997

Average amount outstanding and
  interest rate during the year:
    Commercial Paper.....................          _         $137-5.63%
    Notes Payable to Banks...............          _         $189-5.37%


NOTE K:  COMMITMENTS AND CONTINGENCIES

Construction Program
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $86 million
for 1999 and $98 million for 2000.  Construction expenditure
levels in 2001 and beyond will depend upon, among other things,
the strategy eventually selected for complying with Phase II of
the Clean Air Act Amendments of 1990 (CAAA) and the extent to
which environmental initiatives currently being considered become
mandated. The Company estimates that its banked emission
allowances will allow it to comply with Phase II sulfur dioxide
(SO2) limits through 2005.  Studies to evaluate cost-effective
options to comply with Phase II SO2 limits beyond 2005, including
those available in connection with the emission allowance trading
market, are continuing.

Market Risk
The Company supplies power in the bulk power market.  At December
31, 1998, the marketing books for such operations consisted
primarily of fixed-priced,

                                 F-54


<PAGE>

                                                  The Potomac Edison Company


forward-purchase and/or sale contracts which require settlement
by physical delivery of electricity.

Allegheny Energy has a Corporate Energy Risk Control Policy
adopted by the Board of Directors and monitored by an Exposure
Management Committee of senior management.  This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of counterparties.  Such credit standing must be within the
guidelines established by Allegheny Energy's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits.

Environmental Matters and Litigation
System companies are subject to various laws, regulations, and
uncertainties as to environmental matters.  Compliance may
require them to incur substantial additional costs to modify or
replace existing and proposed equipment and facilities and may
adversely affect the cost of future operations.

The Environmental Protection Agency (EPA) issued its final
regional nitrogen oxides (NOx) State Implementation Plan (SIP)
call rule on September 24, 1998. The EPA's SIP call rule found
that 22 eastern states (including Maryland, Pennsylvania, and
West Virginia) and the District of Columbia are all contributing
significantly to ozone nonattainment in downwind states.  The
final rule declares that this downwind nonattainment will be
eliminated (or sufficiently mitigated) if the upwind states
reduce their NOx emissions by an amount that is precisely set by
the EPA on a state-by-state basis.  The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003.  The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations
at a cost of approximately $103 million.  The Company continues
to work with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action.

The Company previously reported that the EPA had identified it
and its regulated affiliates as potentially responsible parties,
along with approximately 175 others, in a Superfund site subject
to cleanup.  A final determination has not been made for the
Company's share of the remediation costs based on the amount of
materials sent to the site.  The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs.  The Company believes that provisions for liabilities
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.

                               F-55


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries

REPORT OF INDEPENDENT ACCOUNTANTS


To The Board of Directors and the Shareholder
of West Penn Power Company


In our opinion, the accompanying consolidated balance sheet and
consolidated statement of capitalization and the related
consolidated statements of income, of retained earnings and of
cash flows present fairly, in all material respects, the
financial position of West Penn Power Company (a subsidiary of
Allegheny Energy, Inc.) and its subsidiaries at December 31, 1998
and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting
principles.  These financial statements are the responsibility of
the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits.  We
conducted our audits of these statements in accordance with
generally accepted auditing standards which 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, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation.  We believe that our
audits provide a reasonable basis for the opinion expressed
above.



PricewaterhouseCoopers LLP



Pittsburgh, Pennsylvania
February 4, 1999

                                F-56


<PAGE>

                                                      West Penn Power Company
                                                             and Subsidiaries

CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>

                                                     YEAR ENDED DECEMBER 31
(Thousands of Dollars)
                                               1998          1997          1996

Electric Operating Revenues:
  <S>                                       <C>           <C>           <C>
  Residential............................   $  370,636    $  393,036    $  402,083
  Commercial.............................      217,954       223,347       224,663
  Industrial.............................      338,254       352,730       355,120
  Wholesale and other, including
    affiliates...........................       82,982        72,459        74,328
  Bulk power transactions, net...........       68,901        40,590        32,930
    Total Operating Revenues.............    1,078,727     1,082,162     1,089,124

Operating Expenses:
  Operation:
    Fuel.................................      258,199       254,210       239,337
    Purchased power and exchanges, net...      121,286       120,005       126,908
    Deferred power costs, net............                     (7,944)       13,635
    Other................................      173,029       157,780       151,642
  Maintenance............................       91,724        98,252       104,211
  Internal restructuring charges
    and asset write-off..................                                   53,343
  Depreciation...........................      114,709       113,793       119,066
  Taxes other than income taxes..........       88,722        90,140        90,132
  Federal and state income taxes.........       64,526        73,279        47,455
    Total Operating Expenses.............      912,195       899,515       945,729
    Operating Income.....................      166,532       182,647       143,395

Other Income and Deductions:
  Allowance for other than borrowed
    funds used during construction.......          581         2,107         1,434
  Other income, net......................       11,325        17,562        13,439
    Total Other Income and Deductions....       11,906        19,669        14,873
    Income Before Interest Charges.......      178,438       202,316       158,268

Interest Charges:
  Interest on long-term debt..............      61,727        64,990        64,988
  Other interest..........................       5,913         4,639         6,084
  Allowance for borrowed funds used
    during construction...................      (1,822)       (1,978)       (1,289)
    Total Interest Charges................      65,818        67,651        69,783

Consolidated income before
   extraordinary charge...................     112,620       134,665        88,485
Extraordinary charge, net.................    (275,426)

Consolidated Net (Loss) Income............   $(162,806)   $  134,665    $   88,485


CONSOLIDATED STATEMENT OF RETAINED EARNINGS

Balance at January 1.....................    $ 475,558    $  441,283    $  451,719
Add:
  Consolidated net (loss) income.........     (162,806)      134,665        88,485

                                               312,752       575,948       540,204
Deduct:
  Dividends on capital stock 
    of the Company:
    Preferred stock......................        3,396         3,430         3,423
    Common stock.........................       98,664        96,960        95,498
      Total Deductions...................      102,060       100,390        98,921

Balance at December 31...................    $ 210,692    $  475,558    $  441,283

</TABLE>

See accompanying notes to consolidated financial statements.

                                F-57



<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries

CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>

                                                                           YEAR ENDED DECEMBER 31
(Thousands of Dollars)                                                 1998         1997        1996

Cash Flows from Operations:
  <S>                                                               <C>          <C>         <C>
  Consolidated net (loss) income.........                           $(162,806)   $134,665    $ 88,485
  Extraordinary charge, net of taxes.....                             275,426
  Consolidated income before
     extraordinary charge................                             112,620     134,665      88,485
  Depreciation...........................                             114,709     113,793     119,066
  Deferred investment credit
   and income taxes, net.................                              (1,511)     31,381       2,022
  Deferred power costs, net..............                                          (7,944)     13,635
  Unconsolidated subsidiaries' dividends
    in excess of earnings................                              15,484       1,702       5,191
  Allowance for other than borrowed
   funds used during construction........                                (581)     (2,107)     (1,434)
  Internal restructuring liability.......                              (4,082)    (23,052)     25,879
  PURPA project buyout...................                                         (48,000)
  Changes in certain current assets
    and liabilities:
    Accounts receivable, net.............                               5,866     (12,382)     23,671
    Materials and supplies...............                              (3,851)     (3,421)      8,847
    Accounts payable.....................                              21,953       7,507     (14,809)
  Other, net.............................                              (7,105)     11,532       1,714

                                                                      253,502     203,674     272,267


Cash Flows from Investing:
  Construction expenditures (less allowance
   for other than borrowed funds used during
   construction)..........................                            (95,394)   (125,947)   (129,172)


Cash Flows from Financing:
  Issuance of long-term debt..............                             92,834
  Retirement of long-term debt............                           (161,435)
  Short-term debt, net....................                              3,720      18,659     (36,831)
  Notes payable to affiliates.............                              9,300
  Notes receivable from affiliates........                                          2,900      (2,900)
  Dividends on capital stock:
    Preferred stock.......................                             (3,396)     (3,430)     (3,423)
    Common stock..........................                            (98,664)    (96,960)    (95,498)

                                                                     (157,641)    (78,831)   (138,652)


Net Change in Cash and Temporary
  Cash Investments.......................                                 467      (1,104)      4,443
Cash and Temporary Cash Investments at
  January 1..............................                               4,056       5,160         717
Cash and Temporary Cash Investments
  at December 31.........................                              $4,523    $  4,056    $  5,160


Supplemental Cash Flow Information:
  Cash paid during the year for:
    Interest (net of amount
    capitalized).........................                            $ 62,711    $ 64,594    $ 65,149
    Income taxes.........................                              73,653      43,297      57,126

</TABLE>

See accompanying notes to consolidated financial statements.

                                  F-58


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
                                                      DECEMBER 31
                                                 1998            1997
ASSETS
Property, Plant, and Equipment:
  At original cost, including
  $75,725 and $117,588 under
  construction............................    $3,365,784      $3,293,039
  Accumulated depreciation................    (1,362,413)     (1,254,900)

                                               2,003,371       2,038,139
Investments and Other Assets:
  Allegheny Generating Company--common
    stock at equity .....................         74,374          89,783
  Other..................................            646             721

                                                  75,020          90,504
Current Assets:
  Cash and temporary cash investments....          4,523           4,056
  Accounts receivable:
    Electric service, net of $13,211
      and $13,326 uncollectible
      allowance..........................        119,175         128,348
    Affiliated and other, net............         24,832          21,525
  Materials and supplies--at average cost:
    Operating and construction...........         43,167          34,212
    Fuel.................................         24,363          29,467
  Deferred income taxes..................                         11,959
  Prepaid taxes..........................         14,534          11,738
  Regulatory assets......................         17,372
  Other..................................          2,261           2,252

                                                 250,227         243,557
Deferred Charges:
  Regulatory assets......................        475,776         333,235
  Unamortized loss on reacquired debt....          4,065           9,725
  Other..................................         34,610          31,999

                                                 514,451         374,959
Total....................................     $2,843,069      $2,747,159

CAPITALIZATION AND LIABILITIES
Capitalization:
  Common stock, other paid-in capital,
    and retained earnings................     $  732,161      $  997,027
  Preferred stock........................         79,708          79,708
  Long-term debt and QUIDS...............        837,725         802,319

                                               1,649,594       1,879,054
Current Liabilities:
  Short-term debt........................         55,766          52,046
  Notes payable to affiliate.............          9,300
  Long-term debt due within one year.....                        103,500
  Accounts payable.......................         77,815          73,584
  Accounts payable to affiliates.........         33,859          16,137
  Taxes accrued:
    Federal and state income.............          1,002           1,605
    Other................................         16,711          22,728
  Interest accrued.......................         15,681          15,817
  Refunds payable........................         28,151
  Adverse power purchase commitments.....         47,173
  Other..................................         15,393          28,457

                                                 300,851         313,874
Deferred Credits and Other Liabilities:
  Unamortized investment credit..........         42,630          45,206
  Deferred income taxes..................        260,477         450,390
  Regulatory liabilities.................         28,325          34,326
  Adverse power purchase commitments.....        538,745
  Other..................................         22,447          24,309

                                                 892,624         554,231
Commitments and Contingencies (Note N)
Total....................................     $2,843,069      $2,747,159

See accompanying notes to consolidated financial statements.

                                    F-59


<PAGE>

                                                      West Penn Power Company
                                                             and Subsidiaries


CONSOLIDATED STATEMENT OF CAPITALIZATION

<TABLE>
<CAPTION>

<S>                                                                 <C>            <C>             <C>       <C>
                                                                                        DECEMBER 31
                                                                       1998          1997         1998      1997
                                                                     (Thousands of Dollars)  (Capitalization Ratios)
Common Stock of the Company:
  Common stock--no par value, authorized 28,902,923
    shares, outstanding 24,361,586 shares.............              $  465,994     $  465,994
  Other paid-in capital...............................                  55,475         55,475
  Retained earnings...................................                 210,692        475,558
      Total...........................................                 732,161        997,027      44.4%     53.1%

Preferred Stock of the Company:
  Cumulative preferred stock--par value $100 per share,
    authorized 3,097,077 shares, outstanding as follows:

                     December 31, 1998
                                  Regular
                     Shares     Call Price   Date of
    Series        Outstanding   Per Share     Issue
    4-1/2% ..       297,077       $110.00      1939                     29,708         29,708
    4.20% B..        50,000        102.205     1948                      5,000          5,000
    4.10% C..        50,000        103.50      1949                      5,000          5,000
    Auction
      3.95%-4.12%   400,000        100.00      1992                     40,000         40,000
    Total (annual dividend requirements $3,400)                         79,708         79,708       4.8       4.2

Long-Term Debt and QUIDS:
  First mortgage
  bonds:            Date of        Date       Date
                     Issue      Redeemable    Due
    5-1/2% JJ....     1993         1998       1998                                    102,000
    6-3/8% KK....     1993         2003       2003                      80,000         80,000
    7-7/8% GG....     1991         2001       2004                      70,000         70,000
    7-3/8% HH....     1992         2002       2007                      45,000         45,000
    8-7/8% FF....     1991         2001       2021                     100,000        100,000
    7-7/8% II....     1992         2002       2022                     135,000        135,000
    8-1/8% LL....     1994         2004       2024                      65,000         65,000
    7-3/4% MM....     1995         2005       2025                      30,000         30,000

                                   December 31, 1998
                                     Interest Rate
  Quarterly Income Debt Securities
    due 2025........................      8.00%                         70,000         70,000
  Secured notes due 2003-2024.......  4.70%-6.875%                     202,550        202,550
  Unsecured notes due 2007..........      4.75%                         14,435         14,435
  Medium-term debt due 2002.........  5.56%-5.66%                       33,550
  Unamortized debt discount...........................                  (7,810)        (8,166)
      Total (annual interest requirements $60,440)....                 837,725        905,819
  Less current maturities.............................                               (103,500)
      Total...........................................                 837,725        802,319      50.8      42.7

Total Capitalization..................................              $1,649,594     $1,879,054     100.0%    100.0%

</TABLE>


See accompanying notes to consolidated financial statements.

                                     F-60


<PAGE>

                                                       West Penn Power Company
                                                              and Subsidiaries



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial
statements.)


NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

West Penn Power Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System).  The Company and its utility affiliates,
Monongahela Power Company and The Potomac Edison Company, do
business as Allegheny Power.

The Company is subject to regulation by the Securities and
Exchange Commission (SEC), by various state bodies having
jurisdiction, and by the Federal Energy Regulatory Commission
(FERC).  Significant accounting policies of the Company are
summarized below.

Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries (the companies) after
elimination of intercompany transactions.

Use Of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.

Revenues
Revenues are recognized in the same period in which the related
electric services are provided to customers by recording an
estimate for unbilled revenues for services provided from the
meter reading date to the end of the accounting period.

Deferred Power Costs, Net
Prior to May 1, 1997, the costs of fuel, purchased power, and
certain other costs, and revenues from sales to other companies
and power marketers, including transmission services, were
deferred until they were either recovered from or credited to
customers under fuel and energy cost-recovery procedures.  The
Company discontinued this practice effective May 1, 1997.

Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost,
less contributions in aid of construction, except for capital
leases, which are recorded at present value.  Costs include
direct labor and material; allowance for funds used during
construction (AFUDC) on regulated utility property for which
construction work in progress is not included in rate base;
capitalized interest on generation projects; and indirect costs
such as administration, maintenance, and depreciation of
transportation and construction equipment, postretirement
benefits, taxes, and other benefits related to employees engaged
in construction.

The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.

                                 F-61


<PAGE>

                                                       West Penn Power Company
                                                              and Subsidiaries


Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used."  AFUDC is recognized as a cost of property,
plant, and equipment with offsetting credits to other income and
interest charges.  Rates used for computing AFUDC in 1998, 1997,
and 1996 were 7.17%, 8.30%, and 7.83%, respectively.  AFUDC is
not included in the cost of construction when the cost of
financing the construction is being recovered through rates.

As discussed in Note B, as a result of a Pennsylvania Order, the
Company has discontinued the application of the Financial
Accounting Standards Board's (FASB) Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation," for electric generation
operations and has adopted SFAS No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71."
Starting in July 1998, the Company stopped accruing AFUDC for
generation construction projects and adopted SFAS No. 34,
"Capitalizing Interest Costs," to capitalize interest during the
period of construction of generation construction projects.
Capitalized interest, recognized as a cost of property, plant,
and equipment with offsetting credits to interest charges, is
reported in the consolidated statement of income as allowance for
borrowed funds used during construction. Since adoption in July
1998, rates used for capitalizing interest on generation
construction projects averaged 7.45%.

Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.6%, 3.7%,
and 4.0%, of average depreciable property in 1998, 1997, and
1996, respectively.  The cost of maintenance and of certain
replacements of property, plant, and equipment is charged
principally to operating expenses.

Temporary Cash Investments
For purposes of the consolidated statement of cash flows,
temporary cash investments with original maturities of three
months or less, generally in the form of commercial paper,
certificates of deposit, and repurchase agreements, are
considered to be the equivalent of cash.

Regulatory Assets and Liabilities
In accordance with SFAS No. 71, the Company's consolidated
financial statements include certain assets and liabilities based
on cost-based ratemaking regulation.

Income Taxes
The companies join with their parent and affiliates in filing a
consolidated federal income tax return.  The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.

                                 F-62


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period.  Differences between income tax expense,
computed on the basis of financial accounting income and taxes
payable based on taxable income, are accounted for substantially
in accordance with the accounting procedures followed for
ratemaking purposes.  Deferred tax assets and liabilities
represent the tax effect of temporary differences between the
financial statement and tax basis of assets and liabilities
computed using the most current tax rates.

Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to income with concurrent credits to a deferred
account.  These balances are being amortized over the estimated
service lives of the related properties.

Postretirement Benefits
The Company participates with affiliated companies of Allegheny
Energy, Inc. in a noncontributory, defined benefit pension plan
covering substantially all employees, including officers.
Benefits are based on the employee's years of service and
compensation.  The funding policy is to contribute annually at
least the minimum amount required under the Employee Retirement
Income Security Act and not more than can be deducted for federal
income tax purposes.

The Company and its affiliates also provide partially
contributory medical and life insurance plans for eligible
retirees and dependents.  Medical benefits, which make up the
largest component of the plans, are based upon an age and years-
of-service vesting schedule and other plan provisions.  The
funding plan for these costs is to contribute the maximum amount
that can be deducted for federal income tax purposes.  Funding of
these benefits is made primarily into Voluntary Employee
Beneficiary Association trust funds.  Medical benefits are self-
insured.  The life insurance plan is paid through insurance
premiums.

Capitalized Software Costs
The Company capitalizes the cost of software developed for
internal use.  These costs are amortized on a straight-line basis
over a five-year period beginning upon a project's completion.

Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," effective for
1998, established standards for reporting comprehensive income
and its components (revenues, expenses, gains, and losses) in
financial statements.  The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.

Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility operations
which includes the generation, purchase, transmission,
distribution, and sale of electricity.

                                  F-63


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


NOTE B:  INDUSTRY RESTRUCTURING

In December 1996, Pennsylvania enacted the Electricity Generation
Customer Choice and Competition Act (Customer Choice Act) to
restructure the electric industry in Pennsylvania to create
retail access to a competitive electric energy supply market.  On
August 1, 1997, the Company filed with the Pennsylvania Public
Utility Commission (Pennsylvania PUC) a comprehensive
restructuring plan to implement full customer choice of
electricity suppliers as required by the Customer Choice Act.
The filing included a plan for recovery of transition costs
(sometimes referred to as stranded costs) through a Competitive
Transition Charge (CTC).

Transition costs are costs incurred under a regulated
environment, which may not be recoverable in a competitive
market.  The amount of transition costs has been a key issue in
the restructuring proceedings.  Since the installed costs of
utility facilities are known, the key variable in transition cost
determinations in Pennsylvania was the projection of market
prices of electricity in future periods.  The Company's
restructuring plan filing included its determination of its
transition costs based on its projection of future market prices.
The Company's recoverable transition costs were limited to $1.2
billion by rate caps mandated by the Customer Choice Act.

On May 29, 1998, the Pennsylvania PUC issued an Order authorizing
the Company recovery of approximately $595 million (or $525
million in the event of the merger) in transition costs, with a
return, based on alternative projections of future market prices.
On June 26, 1998, the Pennsylvania PUC denied, except for minor
corrections, a request by the Company for reconsideration of the
May 29 Order.  On that same day, the Company filed a formal
appeal in state court and an action in federal court challenging
the Pennsylvania PUC's restructuring Order.

As a result of this May 29, 1998 Order, the Company determined
that it was required to discontinue the application of SFAS No.
71 for electric generation operations and adopt SFAS No. 101.  In
doing so, the Company also determined that, under the provisions
of SFAS No. 101, an extraordinary charge of $450.6 million
($265.4 million after taxes) was required to reflect adverse
power purchase commitments and deferred costs that are not
recoverable from customers under the Pennsylvania PUC's Order.

While pursuing its litigation, the Company participated in
settlement discussions with interested parties regarding issues
related to the restructuring Order.  A negotiated settlement was
achieved, and, on November 19, 1998, the Pennsylvania PUC granted
final approval to the Company's restructuring settlement
agreement.  The settlement agreement includes the following
provisions:

Agreement by the parties to withdraw all litigation related to
the Pennsylvania deregulation proceedings.

Establishment of an average shopping credit of 3.16 cents per
kilowatt-hour in 1999 for Company customers who shop for the
generation portion of electricity services.

Two-thirds of the Company's customers have the option of
selecting a generation supplier on January 2, 1999, with all
customers able to shop on January 2, 2000.

                                F-64


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


Requires a rate refund from 1998 revenues (about $25 million) via
a 2.5%  rate decrease throughout 1999, accomplished by an equal
percentage decrease for each rate class.

Provides that customers will have the option of buying
electricity from the Company at capped generation rates through
2008, and that transmission and distribution rates are capped
through 2005, except that the capped rates are subject to certain
increases as provided for in the Public Utility Code.

Prohibits complaints challenging the Company's regulated
transmission and distribution rates through 2005.

Provides about $15 million of Company funding for the development
and use of renewable energy and clean energy technologies, energy
conservation, energy efficiency, etc.

Permits recovery of $670 million in transition costs plus return
over 10 years beginning in January 1999 for the Company.  In the
event that the merger of Allegheny Energy, Inc. and DQE, Inc.
(DQE), parent company of Duquesne Light Company in Pittsburgh,
Pa., is consummated, the transition costs will be adjusted to
$630 million plus return to provide a sharing of merger synergy
savings with customers.

Allows for income recognition of transition cost recovery in the
earlier years of the transition period to reflect the
Pennsylvania PUC's projections that electricity market prices are
lower in the earlier years.

Grants the Company's application to issue bonds to securitize up
to $670 million (or $630 million in the event of the merger) in
transition costs and to provide 75% of the associated savings to
customers with 25% to shareholders.

Authorizes the transfer of the Company's generating assets to a
nonutility affiliate at book value.  Subject to certain time-
limited exceptions, the nonutility business can compete in the
unregulated energy market.

If the Company is forced to divest some generating assets or
chooses to divest all of its generation before 2002, the CTC will
be adjusted, either up or down, based on the results of such
divestiture.

As a result of the November 19, 1998, settlement agreement, the
extraordinary charge was increased by $16.3 million ($10.0
million after taxes) to $466.9 million ($275.4 million after
taxes), and additional charges of $40.3 million ($23.7 million
after taxes) related to the Company's revenue refund and energy
program payments were also recorded.  See Note C for additional
details. Pursuant to Pennsylvania PUC orders, starting in 1999,
the Company is unbundling its rates to reflect separate prices
for the supply charge, the CTC, and transmission and distribution
charges.  While supply will be open to competition, the Company
will continue to provide regulated transmission and distribution
services to customers in its service area at Pennsylvania PUC-
and FERC-regulated rates and will be the electricity provider of
last resort for those customers who decide not to choose another
electricity supplier.

                                 F-65


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


As stated above, the Company made its filing concerning its
transition cost requirements based on its early 1997 projection
of market prices.  The  Pennsylvania PUC issued its May 29, 1998
Order to the Company, as well as its 1998 orders to all other
Pennsylvania electric utilities, based on alternative
projections.  Current prices, which the Company believes are
being influenced, among other things, by price volatility in the
summer of 1998, are equal to and in some cases higher than the
projections adopted by the Pennsylvania PUC in its deregulation
orders issued to the Company and other utilities in the state.
If the Pennsylvania PUC's projections are correct, the Company
believes that the transition costs provided will be sufficient to
permit it to recover its embedded costs, with a return, during
the transition from regulation to deregulation of electricity
generation.

The settlement authorizes the Company to create a CTC regulatory
asset for specified CTC revenues in 1999 through 2002 to be
amortized in 2005 through 2008.  The regulatory asset booking of
CTC revenue acts to accelerate recognition of transition cost
recovery. In addition, the settlement agreement specifies how CTC
revenues will be allocated between return on and recovery of
transition costs.  Amortization of regulatory assets in 1999
through 2008 under the Pennsylvania PUC-approved settlement
agreement results in smaller amortization expense in the early
years of the transition period which favorably affects earnings
in those years.

Also pursuant to the Customer Choice Act, all electric utilities
in Pennsylvania were required to establish and administer retail
access pilot programs under which customers representing 5% of
the load of each rate class would choose an electricity supplier
other than their own local franchise utility.  The pilot programs
began on November 1, 1997, and continued through December 31,
1998.  As ordered by the Pennsylvania PUC, pilot participants
received an energy credit to their bills from their local utility
and paid an alternate supplier for energy.  To assure
participation in the pilot program, the credit established by the
Pennsylvania PUC was artificially high (greater than the
Company's generation costs), with the result that the Company
suffered a loss of $6.5 million.  The Company attempted to
mitigate the loss by competing for sales to pilot participants of
other utilities as an alternate supplier.  The Pennsylvania PUC
approved the Company's pilot compliance filing and thus has
indicated its intent to treat the revenue losses as a regulatory
asset subject to review and potential rate recovery.  Because
sales prices were low and margins were commensurately thin, the
Company was unable to completely offset its pilot losses with new
revenues. Accordingly, the Company deferred the net revenue
losses as a regulatory asset.

NOTE C:  ACCOUNTING FOR THE EFFECTS OF PRICE DEREGULATION

In 1997, the FASB, through its Emerging Issues Task Force (EITF),
issued EITF No. 97-4, "Deregulation of the Pricing of Electricity
- Issues Related to the Application of FASB Statement Numbers 71
and 101."  In EITF 97-4, the EITF agreed that when a rate order
that contains sufficient detail for the enterprise to reasonably
determine how the transition plan will affect the separable
portion of its business whose pricing is being deregulated is
issued, the entity should cease to apply SFAS No. 71 to that
separable portion of its business.  The Company believes that the
Pennsylvania PUC Order dated May 29, 1998, as described in Note
B, provides sufficient details regarding the deregulation of the
Company's electric generation operations to require
discontinuation of the application of SFAS No. 71 for its
electric generation

                                 F-66


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


operations.  Effective June 30, 1998, the Company adopted the
provisions of SFAS No. 101 for its electric generation
operations.  The Company determined that under the provisions of
SFAS No. 101, an extraordinary charge of $466.9 million ($275.4
million after taxes) was required to reflect a write-off of
certain disallowances in the Pennsylvania PUC's May 29, 1998
Order, as revised by the Pennsylvania PUC-approved November 19,
1998 settlement agreement.  The
write-off reflects adverse power purchase commitments and
deferred costs that are not recoverable from customers under the
Pennsylvania PUC's Order and settlement agreement as follows:

(Millions  of Dollars)                                  Gross       Net-of-Tax

AES Beaver Valley nonutility generation contract.....  $197.5         $116.5
AGC pumped storage capacity contract.................   165.6           97.7
Other................................................   103.8           61.2
  Total extraordinary charge.........................  $466.9         $275.4


In 1985, the Company entered into a contract with Applied Energy
Services (AES) Corporation for the purchase of energy from AES's
Beaver Valley generating plant in Pennsylvania pursuant to the
requirements of the Public Utility Regulatory Policies Act of
1978 (PURPA).

The Company owns 45% of AGC, which owns an undivided 40% interest
in the 2,100-MW pumped-storage hydroelectric station in Bath
County, Va.  The Company buys AGC's capacity in the station
priced under a cost of service formula wholesale rate schedule
approved by the FERC.

Under both of these contracts, the Company has purchase
commitments at costs in excess of the market value of energy from
the plants.  Because of utility restructuring under the Customer
Choice Act, these commitments have been determined to be adverse
purchase commitments requiring accrual as loss contingencies
pursuant to SFAS No. 5, "Accounting for Contingencies."  The
extraordinary charge before taxes for these contracts is the net
result of such excess cost accruals (recorded as adverse power
purchase commitments) less estimated revenue recoveries
authorized in the Pennsylvania PUC Order (recorded as regulatory
assets) as follows:

                                                     AES               AGC
(Millions  of Dollars)                          Beaver Valley    Pumped Storage

Projected costs in excess of market
  value of energy.............................     $351.5             $234.5
Estimated recovery via a CTC (regulatory
  asset)......................................      154.0               68.9
    Net unrecoverable extraordinary charge....     $197.5             $165.6


Various assumptions and estimates were made in determining the
extraordinary charge to income discussed above.  The most
significant relate to future electricity prices.  To the extent
that future electricity prices differ from the Company's
estimates, adjustments to the reserve for adverse power purchase
commitments may be required.

                                  F-67


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries



The other $103.8 million of extraordinary charges represents
$55.0 million of deferred unrecovered expenditures for previous
PURPA buyouts, $13.5 million for an abandoned generating plant,
and $35.3 million of other generation-related regulatory assets,
primarily related to SFAS No. 109, "Accounting for Income Taxes."

The consolidated balance sheet includes the amounts listed below
for generation assets not subject to SFAS No. 71:
                                                     December        December
(Thousands of Dollars)                                  1998           1997

Property, plant, and equipment at original cost....  $1,969,636     $1,951,066
Amounts under construction included above..........      39,227         51,715
Accumulated depreciation...........................    (870,777)      (793,166)

In addition to the extraordinary charge and as a result of the
settlement agreement, a fourth quarter charge to earnings of
$40.3 million ($23.7 million after taxes) resulted from the
required refund throughout 1999 from 1998 revenues of about $25
million and a $15 million provision for energy programs.

NOTE D:  PROPOSED MERGER

On April 7, 1997, the Company's parent, Allegheny Power System,
Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
announced that they had agreed to merge in a tax-free, stock-for-
stock transaction.

At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger.  Allegheny Energy
and DQE made all necessary regulatory filings.  Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania PUC, and the
FERC.  The Pennsylvania PUC and the FERC approvals were subject
to conditions acceptable to Allegheny Energy.  In addition, while
not required, the Maryland Public Service Commission and the
Public Utilities Commission of Ohio have indicated their
approval.

On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger.  Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement.  In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.

On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief.  The District Court
did not rule on the merits of the lawsuit for specific
performance or damages.  On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States Court of
Appeals for the Third Circuit.  Allegheny Energy cannot predict
the outcome of this litigation.

All of the Company's incremental costs of the merger process
($7.9 million through December 31, 1998) are being deferred.  The
accumulated merger costs will be written off by the Company when
the merger occurs or by the Company if it is determined that the
merger will not occur.

                                 F-68


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


NOTE E:  INTERNAL RESTRUCTURING CHARGES AND ASSET WRITE-OFF

In 1996, the System, including the Company, completed its
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations.  During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.

In 1996, the Company recorded restructuring charges of $42.6
million ($25.1 million after tax) in operating expenses,
including its share of all restructuring charges associated with
the reorganization.  These charges reflected liabilities and
payments for severance, employee termination costs, and other
restructuring costs.  The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits), consists of:

(Thousands of Dollars)                                1998          1997

Internal restructuring liability:
  Balance at beginning of period.................   $ 4,082       $ 27,134
  Less payments and accrual reversals............    (4,082)       (23,052)
Balance at end of period.........................   $   -         $  4,082


In 1996, the Company wrote off $10.8 million ($6.3 million after
tax) of previously accumulated costs related to a proposed
transmission line.  In the industry's more competitive
environment, it was no longer reasonable to assume future
recovery of these costs in rates.

As part of the reorganization, the Company and its utility
affiliates in 1996 expanded the intercompany use of each other's
employees to optimize the use of their skills.  In 1997 virtually
all the employees in the System, including all of the Company's
employees, were transferred to Allegheny Power Service
Corporation (APSC) to facilitate the intercompany use of
personnel.  APSC was formed in 1963 pursuant to the Public
Utility Holding Company Act of 1935 to perform certain functions
common to all companies in the System.  APSC bills each company
at its cost (without profit) based on the work performed and
services provided to each company.

                                   F-69


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries



NOTE F:  INCOME TAXES

Details of federal and state income tax provisions are:

(Thousands of Dollars)                         1998         1997          1996

Income taxes--current:
  Federal..............................    $  47,605     $29,426        $32,778
  State................................       18,415      12,357         12,975
    Total..............................       66,020      41,783         45,753
Income taxes--deferred, net of
  amortization.........................        1,069      33,961          4,602
Income taxes--deferred, extraordinary
  charge...............................     (191,480)
Amortization of deferred investment
  credit...............................       (2,580)     (2,580)        (2,580)
    Total income taxes.................     (126,971)     73,164         47,775
Income taxes--credited (charged)
  to other income and deductions.......           17         115           (320)
Income taxes--credited to
  extraordinary charge.................      191,480
Income taxes--charged to operating
  income...............................    $  64,526     $73,279        $47,455


The total provision for income taxes is different from the amount
produced by applying the federal income statutory tax rate of 35%
to financial accounting income, as set forth below:

(Thousands of Dollars)                       1998         1997          1996

Income before income taxes
  and extraordinary charge.............    $177,146     $207,944      $135,900
Amount so produced.....................    $ 62,001     $ 72,780      $ 47,565
Increased (decreased) for:
  Tax deductions for which deferred
    tax was not provided:
      Lower tax depreciation...........       1,500        5,700         3,300
      Plant removal costs..............       1,000        1,400         2,100
  State income tax, net of federal
    income tax benefit.................      10,000        4,900         8,900
  Amortization of deferred
    investment credit..................      (2,580)      (2,580)       (2,580)
  Equity in earnings of subsidiaries...      (3,900)      (6,300)       (4,600)
  Other, net...........................      (3,495)      (2,621)       (7,230)
    Total..............................    $ 64,526     $ 73,279      $ 47,455


                                         F-70



<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries



The provision for income taxes for the extraordinary charge is
different from the amount produced by applying the federal income
statutory tax rate of 35% to the gross amount, as set forth
below:

(Thousands of Dollars)                                      1998

Extraordinary charge before income taxes...............  $466,905
Amount so produced.....................................  $163,417
Increased for state income tax, net of federal
  income tax benefit...................................    28,063
    Total..............................................  $191,480


Federal income tax returns through 1993 have been examined and
substantially settled through 1991.

At December 31, the deferred tax assets and liabilities consisted
of the following:

(Thousands of Dollars)                                  1998          1997

Deferred tax assets:
  CTC recovery....................................    $154,530
  Unamortized investment tax credit...............      29,674     $ 31,570
  Tax interest capitalized........................      19,010       19,220
  Postretirement benefits other than pensions.....      15,610       12,857
  Revenue refund..................................      10,301
  Unbilled revenue................................       9,068        9,226
  Contributions in aid of construction............       6,988        6,520
  Internal restructuring..........................       2,954        2,709
  Other...........................................      24,724       25,777
                                                       272,859      107,879
Deferred tax liabilities:
  Book vs. tax plant basis differences, net.......     503,605      493,361
  Other...........................................      33,214       52,949
                                                       536,819      546,310
Total net deferred tax liabilities................     263,960      438,431
Portion above included in current (liabilities)
  assets..........................................      (3,483)      11,959
    Total long-term net deferred tax liabilities..    $260,477     $450,390


NOTE G:  DIVIDEND RESTRICTION

Supplemental indentures relating to certain outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $70,576,000 of consolidated retained
earnings at December 31, 1998, is not available for cash
dividends on common stock, except that a portion thereof may be
paid as cash dividends where concurrently an equivalent amount of
cash is received by the Company as a capital contribution or as
the proceeds of the issue and sale of shares of its common stock.


                               F-71


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries




NOTE H:  ALLEGHENY GENERATING COMPANY

The Company owns 45% of the common stock of Allegheny Generating
Company (AGC), and affiliates of the Company own the remainder.
AGC is reported by the Company in its financial statements using
the equity method of accouting. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.

AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and a
return on its investment under a wholesale rate schedule approved
by the FERC.  AGC's rates are set by a formula filed with and
previously accepted by the FERC.  The only component which
changes is the return on equity (ROE).  Pursuant to a settlement
agreement filed April 4, 1996, with the FERC, AGC's ROE was set
at 11% for 1996 and will continue until the time any affected
party seeks renegotiation of the ROE.

Following is a summary of financial information for AGC:


                                                          December 31
(Thousands of Dollars)                                 1998          1997

Balance sheet information:
  Property, plant, and equipment.................    $618,608      $635,485
  Current assets.................................       5,857        11,876
  Deferred charges...............................      14,993        16,559
    Total assets.................................    $639,458      $663,920

  Total capitalization...........................    $314,105      $348,258
  Current liabilities............................      75,849        70,540
  Deferred credits...............................     249,504       245,122
    Total capitalization and liabilities.........    $639,458      $663,920


                                                  Year Ended December 31
 (Thousands of Dollars)                       1998          1997         1996

Income statement information:
  Electric operating revenues..........    $73,816      $76,458        $83,402
  Operation and maintenance expense....      4,592        4,877          5,165
  Depreciation.........................     16,949       17,000         17,160
  Taxes other than income taxes........      4,662        4,835          4,801
  Federal income taxes.................     10,959       11,213         13,297
  Interest charges.....................     13,987       15,391         16,193
  Other income, net....................        (86)      (9,126)            (3)
    Net income.........................    $22,753      $32,268        $26,789


The Company's share of the equity in earnings was $10.2 million,
$14.5 million, and $12.1 million for 1998, 1997, and 1996,
respectively, and is included in other income, net, on the
Company's Consolidated Statement of Income.  Dividends received
from AGC in 1998 approximated $25 million which reflects an
effort to reduce AGC equity to about 45% of total capitalization
and short-term debt.

                                  F-72


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


NOTE I:  POSTRETIREMENT BENEFITS

As described in Note A, the Company and its affiliates
participate in a pension plan and medical and life insurance
plans for eligible employees and dependents.  The Company is
responsible for its proportional share of the costs (credits) and
the assets or liabilities of the plans.  As described in Note E,
in 1997 the Company transferred all of its employees to APSC.
The Company's share of the costs (credits) of these plans, a
portion of which (about 25% to 35%) was charged to plant
construction, is as follows:

(Thousands of Dollars)                       1998         1997          1996

Pension................................     $  919      $(3,037)       $  564
Medical and life insurance.............     $6,708      $ 4,551        $9,039


NOTE  J:  REGULATORY ASSETS AND LIABILITIES

The Company's operations, other than electric generation, are
subject to the provisions of SFAS No. 71.  As discussed in Note
B, as a result of a Pennsylvania Order, the Company has
discontinued the application of SFAS No. 71 and has adopted SFAS
No. 101 for electric generation operations.  Regulatory assets
represent probable future revenues associated with deferred costs
that are expected to be recovered from customers through the
ratemaking process.  Regulatory liabilities represent probable
future reductions in revenues associated with amounts that are to
be credited to customers through the ratemaking process.
Regulatory assets, net of regulatory liabilities, reflected in
the consolidated balance sheet at December 31 relate to:

(Thousands of Dollars)                                1998          1997

Long-Term Assets (Liabilities), Net:
  Income taxes, net............................     $146,952      $247,574
  CTC recovery.................................      292,718  
  PURPA project buyout.........................                     48,000
  Pennsylvania pilot deferred revenue..........        6,727            84
  Deferred power costs, (reported in other
    deferred charges)..........................                      7,000
  Storm damage.................................        1,054         1,326
  Postretirement benefits......................                        823
  Other, net...................................                      1,102
    Subtotal...................................      447,451       305,909
Current Asset:
  CTC recovery.................................       17,372
    Net Regulatory Assets......................     $464,823      $305,909


                                       F-73

<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries



NOTE K:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:

                                    1998                       1997
                            Carrying       Fair       Carrying        Fair
(Thousands of Dollars)       Amount        Value       Amount         Value

Assets:
  Temporary cash
    investments.........    $    882     $    882     $    573      $    573
Liabilities:
  Short-term debt.......      65,066       65,066       52,046        52,046
  Long-term debt
    and QUIDS...........     845,535      902,037      913,985       953,700


The carrying amount of temporary cash investments, as well as
short-term debt, approximates the fair value because of the short
maturity of those instruments.  The fair value of long-term debt
and QUIDS was estimated based on actual market prices or market
prices of similar issues.  The Company has no financial
instruments held or issued for trading purposes.

NOTE L:  CAPITALIZATION

Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.  The holders of the Company's market auction
preferred stock are entitled to dividends at a rate determined by
an auction held the business day preceding each quarterly
dividend payment date.

Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are:  1999-2001, none; 2002, $33,550; and 2003,
$141,500.  Substantially all of the properties of the Company are
held subject to the lien securing its first mortgage bonds.  Some
properties are also subject to a second lien securing certain
pollution control and solid waste disposal notes.  Certain first
mortgage bond series are not redeemable by certain refunding
until dates established in the respective supplemental
indentures.

NOTE M:  SHORT-TERM DEBT

To provide interim financing and support for outstanding
commercial paper, the System companies have established lines of
credit with several banks.  The Company has SEC authorization for
total short-term borrowings of $182 million, including money pool
borrowings described below.  The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements.  In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available.

                                    F-74


<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries


Short-term debt outstanding for 1998 and 1997 consisted of:

(Thousands of Dollars)                         1998               1997

Balance and interest rate
  at end of year:
    Commercial Paper..................    $55,766-5.45%       $12,046-6.50%
    Notes Payable to Banks............                         40,000-6.75%
    Money Pool........................      9,300-4.80%
Average amount outstanding and
  interest rate during the year:
    Commercial Paper..................    $32,824-5.60%      $  3,376-5.73%
    Notes Payable to Banks............     16,885-5.60%         5,526-5.67%
    Money Pool........................     10,942-5.38%        17,628-5.48%


NOTE N:  COMMITMENTS AND CONTINGENCIES

Construction Program
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $119 million
for 1999 and $106 million for 2000.  Construction expenditure
levels in 2001 and beyond will depend upon, among other things,
the strategy eventually selected for complying with Phase II of
the Clean Air Act Amendments of 1990 and the extent to which
environmental initiatives currently being considered become
mandated.  The Company estimates that its banked emission
allowances will allow it to comply with Phase II sulfur dioxide
(SO2) limits through 2005.  Studies to evaluate cost-effective
options to comply with Phase II SO2 limits beyond 2005, including
those available in connection with the emission allowance trading
market, are continuing.

Market Risk
The Company supplies power in the bulk power market.  At December
31, 1998, the marketing books for such operations consisted
primarily of fixed-priced, forward-purchase and/or sale contracts
which require settlement by physical delivery of electricity.

Allegheny Energy has a Corporate Energy Risk Control Policy
adopted by the Board of Directors and monitored by an Exposure
Management Committee of senior management.  This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of counterparties.  Such credit standing must be within the
guidelines established by Allegheny Energy's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits, but has increased as a result of Pennsylvania
restructuring, which created retail access to a deregulated
electric supply market.

Environmental Matters and Litigation
System companies are subject to various laws, regulations, and
uncertainties as to environmental matters.  Compliance may
require them to incur substantial additional costs to modify or
replace existing and proposed equipment and facilities and may
adversely affect the cost of future operations.

                                  F-75

<PAGE>

                                                     West Penn Power Company
                                                            and Subsidiaries



The Environmental Protection Agency (EPA) issued its final
regional nitrogen oxides (NOx) State Implementation Plan (SIP)
call rule on September 24, 1998. The EPA's SIP call rule found
that 22 eastern states (including Maryland, Pennsylvania, and
West Virginia) and the District of Columbia are all contributing
significantly to ozone nonattainment in downwind states.  The
final rule declares that this downwind nonattainment will be
eliminated (or sufficiently mitigated) if the upwind states
reduce their NOx emissions by an amount that is precisely set by
the EPA on a state-by-state basis.  The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003.  The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations
at a cost of approximately $147 million.  The Company continues
to work with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action.

The Company previously reported that the EPA had identified it
and its regulated affiliates as potentially responsible parties,
along with approximately 175 others, in a Superfund site subject
to cleanup.  A final determination has not been made for the
Company's share of the remediation costs based on the amount of
materials sent to the site.  The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs.  The Company believes that provisions for liabilities
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.

                                   F-76


<PAGE>

                                                Allegheny Generating Company
                                                        



REPORT OF INDEPENDENT ACCOUNTANTS


To The Board of Directors and the Shareholders
of Allegheny Generating Company


In our opinion, the accompanying balance sheet and the related
statements of income, of retained earnings and of cash flows
present fairly, in all material respects, the financial position
of Allegheny Generating Company (a subsidiary of Allegheny
Energy, Inc.) at December 31, 1998 and 1997, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 1998, in conformity with generally
accepted accounting principles.  These financial statements are
the responsibility of the Company's management; our
responsibility is to express an opinion on these financial
statements based on our audits.  We conducted our audits of these
statements in accordance with generally accepted auditing
standards which 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, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation.  We
believe that our audits provide a reasonable basis for the
opinion expressed above.



PricewaterhouseCoopers LLP



Pittsburgh, Pennsylvania
February 4, 1999

                                  F-77


<PAGE>

                                                Allegheny Generating Company


STATEMENT OF INCOME

                                                  YEAR ENDED DECEMBER 31
(Thousands of Dollars)                          1998       1997       1996


Electric Operating
Revenues.......................................$73,816    $76,458    $83,402

Operating Expenses:
  Operation and maintenance expense............  4,592      4,877      5,165
  Depreciation................................. 16,949     17,000     17,160
  Taxes other than income taxes................  4,662      4,835      4,801
  Federal income taxes......................... 10,959     11,213     13,297
    Total Operating Expenses................... 37,162     37,925     40,423
    Operating Income........................... 36,654     38,533     42,979

Other Income, net...............................    86      9,126          3
  Income Before Interest Charges................36,740     47,659     42,982

Interest Charges:
  Interest on long-term debt....................10,848     14,431     15,235
  Other interest................................ 3,139        960        958
    Total Interest Charges......................13,987     15,391     16,193

Net Income.....................................$22,753    $32,268    $26,789




STATEMENT OF RETAINED EARNINGS

Balance at January 1...........................$     0    $     0    $ 4,153
Add:
  Net income................................... 22,753     32,268     26,789

                                                22,753     32,268     30,942
Deduct:
  Dividends on common stock.................... 22,753*    32,268*    30,942*

Balance at December 31.........................$     0    $     0    $     0



*Excludes cash dividends paid from other paid-in capital.


See accompanying notes to financial statements.

                                    F-78


<PAGE>

                                                Allegheny Generating Company



STATEMENT OF CASH FLOWS


                                               YEAR ENDED DECEMBER 31
(Thousands of Dollars)                      1998        1997        1996


Cash Flows from Operations:
  Net income...............................$22,753     $32,268     $26,789
  Depreciation............................. 16,949      17,000      17,160
  Tax-related contract settlement..........              8,835
  Deferred investment credit and income
    taxes, net.............................  5,305       6,329      10,898
  Changes in certain current assets and
   liabilities:
    Accounts receivable....................      6       1,331       3,937
    Materials and supplies.................   (261)        260         (43)
    Accounts payable.......................   (340)      5,913         206
  Other, net...............................    578          28      (3,739)

                                            44,990      71,964      55,208

Cash Flows from Investing:
  Construction expenditures................    (69)       (444)       (178)


Cash Flows from Financing:
  Retirement of long-term debt.............(60,000)    (30,592)    (16,943)
  Notes payable to parents................. 66,750
  Cash dividends on common stock...........(57,000)    (35,700)    (37,987)

                                           (50,250)    (66,292)    (54,930)

Net Change in Cash and Temporary
  Cash Investments......................... (5,329)      5,228         100
Cash and Temporary Cash Investments at
  January 1................................  5,359         131          31
Cash and Temporary Cash Investments at
  December 31..............................$    30     $ 5,359     $   131


Supplemental Cash Flow Information
  Cash paid during the year for:
    Interest...............................$14,490     $14,770     $15,703
    Income taxes...........................  4,828      10,313       6,256



See accompanying notes to financial statements.

                                    F-79


<PAGE>

                                                Allegheny Generating Company



BALANCE SHEET

                                                          DECEMBER 31
(Thousands of Dollars)                                 1998         1997

ASSETS

Property, Plant, and Equipment:
  At original cost, including $595 and $906
    under construction......................         $828,806     $828,658
  Accumulated depreciation..................         (210,198)    (193,173)

                                                      618,608      635,485

Current Assets:
  Cash and temporary cash investments.......               30        5,359
  Accounts receivable from Parents..........                             6
  Materials and supplies--at average cost...            2,093        1,832
  Prepaid taxes.............................            3,569        4,442
  Other.....................................              165          237

                                                        5,857       11,876

Deferred Charges:
  Regulatory assets.........................            7,056        7,979
  Unamortized loss on reacquired debt.......            7,768        8,393
  Other.....................................              169          187

                                                       14,993       16,559
Total.......................................         $639,458     $663,920


CAPITALIZATION AND LIABILITIES

Capitalization:
  Common stock - $1.00 par value per share,
    authorized 5,000 shares, outstanding
    1,000 shares. ..........................         $      1     $      1
  Other paid-in capital.....................          165,275      199,522

                                                      165,276      199,523
  Long-term debt............................          148,829      148,735

                                                      314,105      348,258

Current Liabilities:
  Notes payable to parents..................           66,750
  Long-term debt due within one year........                        60,000
  Accounts payable to affiliates............            5,795        6,135
  Interest accrued..........................            3,229        4,404
  Other.....................................               75            1

                                                       75,849       70,540

Deferred Credits:
  Unamortized investment credit.............           47,020       48,342
  Deferred income taxes.....................          177,166      169,325
  Regulatory liabilities....................           25,318       27,455

                                                      249,504      245,122

Total.......................................         $639,458     $663,920



See accompanying notes to financial statements.

                                        F-80


<PAGE>

                                                Allegheny Generating Company


NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)


NOTE A:  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Allegheny Generating Company (the Company) was incorporated in
Virginia in 1981.  Its common stock is owned by Monongahela Power
Company - 27%, The Potomac Edison Company - 28%, and West Penn
Power Company - 45% (the Parents). The Parents are wholly-owned
subsidiaries of Allegheny Energy, Inc. (Allegheny Energy) and are
a part of the Allegheny Energy integrated electric utility
system.  The Company is subject to regulation by the Securities
and Exchange Commission (SEC) and by the Federal Energy
Regulatory Commission (FERC).  Significant accounting policies of
the Company are summarized below.

Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.

Revenues
Revenues are determined under a cost-of-service formula rate
schedule approved by the FERC.  Under this arrangement, the
Company recovers in revenues all of its operation and maintenance
expense, depreciation, taxes, and a return on its investment.
All sales are made to the Company's Parents.

Property, Plant, and Equipment
Property, plant, and equipment are stated at original cost, and
consist of a 40% undivided interest in the Bath County pumped-
storage hydroelectric station and its connecting transmission
facilities.  The cost of depreciable property units retired, plus
removal costs less salvage, are charged to accumulated
depreciation.

Depreciation and Maintenance
Provisions for depreciation are determined on a straight-line
method based on estimated service lives of depreciable properties
and amounted to approximately 2.1% of average depreciable
property in each of the years 1998, 1997, and 1996.  The cost of
maintenance and of certain replacements of property, plant, and
equipment is charged to operating expenses.

Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash
investments with original maturities of three months or less,
generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the
equivalent of cash.

Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities based on cost-based ratemaking regulation.

                                    F-81


<PAGE>

                                                Allegheny Generating Company



Income Taxes
The Company joins with its Parents and affiliates in filing a
consolidated federal income tax return.  The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.

Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period.  Differences between income tax expense
computed on the basis of financial accounting income and taxes
payable based on taxable income are deferred.  Deferred tax
assets and liabilities represent the tax effect of temporary
differences between the financial statement and tax basis of
assets and liabilities computed using the most current tax rates.

Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to income with concurrent credits to a deferred
account.  These balances are being amortized over the estimated
service lives of the related properties.

Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," effective for
1998, established standards for reporting comprehensive income
and its components (revenues, expenses, gains, and losses) in the
financial statements.  The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.

Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company operates as a single business segment selling its
entire capacity to its Parents priced under a cost-of-service
wholesale rate schedule.

NOTE B:  PROPOSED MERGER

On April 7, 1997, Allegheny Power System, Inc. (now renamed
Allegheny Energy, Inc.) and DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., announced that they
had agreed to merge in a tax-free, stock-for-stock transaction.

At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger.  Allegheny Energy
and DQE made all necessary regulatory filings.  Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania Public Utility
Commission (Pennsylvania PUC), and the FERC.  The Pennsylvania
PUC and the FERC approvals were subject to conditions acceptable
to Allegheny Energy.  In addition, while not required, the
Maryland Public Service Commission and the Public Utilities
Commission of Ohio have indicated their approval.

                                  F-82


<PAGE>

                                                Allegheny Generating Company


On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger.  Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement.  In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.

On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief.  The District Court
did not rule on the merits of the lawsuit for specific
performance or damages.  On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States Court of
Appeals for the Third Circuit.  The Company cannot predict the
outcome of this litigation.

NOTE C:  INCOME TAXES

Details of federal income tax provisions are:

(Thousands of Dollars)                      1998         1997         1996

Current income taxes payable..........    $ 5,700      $ 9,799      $ 2,401
Deferred income taxes--
  accelerated depreciation............      6,628        7,652       12,220
Amortization of deferred
  investment credit...................     (1,323)      (1,323)      (1,322)
    Total income taxes................     11,005       16,128       13,299
Income taxes--charged to other
  income..............................        (46)      (4,915)          (2)
Income taxes--charged to operating
  income..............................    $10,959      $11,213      $13,297


In 1998, the total provision for income taxes ($10,959) was less
than the amount produced ($11,799) by applying the federal income
tax statutory rate of 35% to financial accounting income before
income taxes ($33,712), primarily due to amortization of deferred
investment credit ($1,323).

Federal income tax returns through 1993 have been examined and
substantially settled through 1991.

At December 31, the deferred tax liabilities, net consisted of
the following:

(Thousands of Dollars)                                  1998         1997

Deferred tax liabilities, net:
  Unamortized investment tax credit...............   $(25,318)    $(27,455)
  Book vs. tax plant basis differences, net.......    202,484      196,780
    Total long-term net deferred tax liabilities..   $177,166     $169,325

                                      F-83


<PAGE>

                                                Allegheny Generating Company



NOTE D:  REGULATORY ASSETS AND LIABILITIES

The Company's operations are subject to the provisions of SFAS
No. 71.  Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process.  Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process.  Regulatory liabilities, net of
regulatory assets, in thousands of dollars of $18,262 in 1998 and
$19,476 in 1997 relate to income taxes.

NOTE E:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:

                                      1998                      1997
                             Carrying       Fair       Carrying        Fair
(Thousands of Dollars)        Amount        Value       Amount         Value

Liabilities:
  Short-term debt........    $ 66,750     $ 66,750
  Long-term debt:
    Debentures...........     150,000      155,658     $150,000       $144,410
    Medium-term notes....                                60,000         60,000


The carrying amount of short-term debt approximates the fair
value because of the short maturity of those instruments.  The
fair value of debentures and medium-term notes was estimated
based on actual market prices or market prices of similar issues.
The Company has no financial instruments held or issued for
trading purposes.

NOTE F:  CAPITALIZATION

The Company systematically reduces capitalization each year as
its asset depreciates, resulting in the payment of dividends in
excess of current earnings.  The SEC has approved the Company's
request to pay common dividends out of capital.  Common dividends
were paid from retained earnings, reducing the account balance to
zero, and from other paid-in capital as follows:

(Thousands of Dollars)                  1998           1997         1996

Retained earnings..................   $22,753        $32,268       $30,942
Other paid-in capital..............    34,247          3,432         7,045
  Total............................   $57,000        $35,700       $37,987

                                     F-84


<PAGE>

                                                Allegheny Generating Company


NOTE G:  LONG-TERM DEBT

The Company had long-term debt outstanding as follows:

                                        12-31-98
                                        Interest            December 31
(Thousands of Dollars)                    Rate           1998         1997

Debentures due:
  September 1, 2003.................     5.625%        $ 50,000     $ 50,000
  September 1, 2023.................     6.875%         100,000      100,000
Medium-term notes due 1998..........                                  60,000
Unamortized debt discount...........                     (1,171)      (1,265)
    Total...........................                    148,829      208,735
Less current maturities.............                                  60,000
    Total...........................                   $148,829     $148,735


Maturities for long-term debt for the next five years are $50,000
in 2003.

NOTE H:  SHORT-TERM DEBT

To provide interim financing and support for outstanding
commercial paper, the Allegheny Energy companies have established
lines of credit with several banks.  The Company has SEC
authorization for total short-term borrowings of $100 million,
including money pool borrowings described below.  The Company has
fee arrangements on all of its lines of credit and no
compensating balance requirements.  In addition to bank lines of
credit, an Allegheny Energy internal money pool accommodates
intercompany short-term borrowing needs to the Company, to the
extent that Allegheny Energy and the Company's Parents have funds
available.  At December 31, 1998, the Company had borrowings from
the Allegheny Energy money pool of $66.8 million which were
funded by The Potomac Edison Company.  Short-term debt
outstanding for 1998 consisted of:

(Thousands of Dollars)             1998

Balance and interest rate at end of year:
  Money pool..............................                   $66,750-4.80%
Average amount outstanding and interest rate during
  the year:
    Commercial paper..................................         1,725-5.46%
    Notes payable to banks............................           406-5.63%
    Money pool........................................        43,415-5.23%


                                        F-85


<PAGE>


                               S-1
                           SCHEDULE II
                                
         ALLEGHENY ENERGY, INC. AND SUBSIDIARY COMPANIES
                                
                                
                Valuation and Qualifying Accounts
        For Years Ended December 31, 1998, 1997, and 1996


<TABLE>
<CAPTION>

<S>                         <C>              <C>            <C>             <C>                <C>
                             Column A         Column B         Column C         Column D        Column E

                                                      Additions
                            Balance at       Charged to      Charged to                        Balance at
                            beginning         costs and        other                             end of
Description                 of period         expenses       accounts      Deductions            period
                                                               (A)             (B)

Allowance for
uncollectible accounts:

Year Ended 12/31/98         $17,191,310      $15,371,602    $4,953,941      $17,956,716        $19,560,137

Year Ended 12/31/97         $15,052,494      $16,306,082    $3,869,153      $18,036,419        $17,191,310

Year Ended 12/31/96         $13,046,900      $12,970,000    $3,243,945      $14,208,351        $15,052,494

</TABLE>


(A)  Recoveries.
(B)  Uncollectible accounts charged off.


<PAGE>


                               S-2
                           SCHEDULE II
                                
                    MONONGAHELA POWER COMPANY
                                
                Valuation and Qualifying Accounts
        For Years Ended December 31, 1998, 1997, and 1996

         
<TABLE>
<CAPTION>

<S>                          <C>              <C>            <C>             <C>                <C>
                             Column A         Column B         Column C         Column D        Column E

                                                      Additions
                            Balance at       Charged to      Charged to                        Balance at
                            beginning         costs and        other                             end of
Description                 of period         expenses       accounts      Deductions            period
                                                               (A)             (B)

Allowance for
uncollectible accounts:

Year Ended 12/31/98         $ 2,176,006      $ 3,951,000    $ 1,383,021     $ 4,994,278        $ 2,515,749

Year Ended 12/31/97         $ 1,949,219      $ 3,699,997    $ 1,005,246     $ 4.478,456        $ 2,176,006

Year Ended 12/31/96         $ 2,266,808      $ 1,970,000    $   666,816     $ 2,954,405        $ 1,949.219

</TABLE>

(A)  Recoveries.
(B)  Uncollectible accounts charged off.


<PAGE>

                               S-3
                           SCHEDULE II
                                
                     POTOMAC EDISON COMPANY
                                
                Valuation and Qualifying Accounts
        For Years Ended December 31, 1998, 1997, and 1996


<TABLE>
<CAPTION>

<S>                         <C>              <C>            <C>             <C>                <C>
                             Column A         Column B         Column C         Column D        Column E

                                                      Additions
                            Balance at       Charged to      Charged to                        Balance at
                            beginning         costs and        other                             end of
Description                 of period         expenses       accounts      Deductions            period
                                                               (A)             (B)


Allowance for
uncollectible accounts:

Year Ended 12/31/98         $ 1,683,485      $ 3,731,000    $ 1,456,097     $ 4,667,910        $ 2,202,672

Year Ended 12/31/97         $ 1,579,503      $ 3,700,000    $ 1,312,074     $ 4,908,092        $ 1,683,485

Year Ended 12/31/96         $ 1,344,077      $ 2,514,000    $   957,372     $ 3,235,946        $ 1,579,503

</TABLE>


(A)  Recoveries.
(B)  Uncollectible accounts charged off.


<PAGE>

                               S-4
                           SCHEDULE II
                                
        WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
                                
                Valuation and Qualifying Accounts
        For Years Ended December 31, 1998, 1997, and 1996


<TABLE>
<CAPTION>

<S>                         <C>              <C>            <C>             <C>                <C>
                             Column A         Column B         Column C         Column D        Column E

                                                      Additions
                            Balance at       Charged to      Charged to                        Balance at
                            beginning         costs and        other                             end of
Description                 of period         expenses       accounts      Deductions            period
                                                               (A)             (B)


Allowance for
uncollectible accounts:

Year Ended 12/31/98         $13,325,739      $ 7,613,934    $ 2,114,823     $ 8,294,528        $14,759,968

Year Ended 12/31/97         $11,523,772      $ 8,900,005    $ 1,551,833     $ 8,649,871        $13,325,739

Year Ended 12/31/96         $ 9,436,015      $ 8,486,000    $ 1,619,757      $ 8,018,000       $11,523,772

</TABLE>


(A)  Recoveries.
(B)  Uncollectible accounts charged off.


<PAGE>

                                  49


Supplementary Data
Quarterly Financial Data (Unaudited)
(Dollar Amounts in Thousands Except for Per Share Data)
                  Electric
                  Operating    Operating     Net        Earnings
                  Revenues      Income      Income*     Per Share*
Quarter ended

AE
March 1998        $645 472     $124,707    $ 78 237     $ .64
June 1998          627 650      100 065      53 891       .44
September 1998     726 607      128 604      82 736       .68
December 1998      576 707       86 131      48 144       .39

March 1997         614 980      124 094      77 591       .64
June 1997          542 750       95 473      51 683       .42
September 1997     595 125      110 635      74 808       .61
December 1997      616 636      122 035      77 214       .63

Monongahela
March 1998         158 272       27 358      19 427
June 1998          153 774       24 087      16 611
September 1998     177 364       31 887      25 244
December 1998      155 712       28 154      21 143

March 1997         162 803       30 480      22 556
June 1997          144 078       23 701      16 174
September 1997     158 240       28 493      23 457
December 1997      163 190       26 701      18 342

Potomac Edison
March 1998         191 698       37 622      27 922
June 1998          177 519       30 036      20 504
September 1998     190 533       36 680      27 299
December 1998      177 744       34 458      25 757

March 1997         192 228       37 062      27 723
June 1997          164 867       26 894      18 376
September 1997     175 464       30 388      25 296
December 1997      176 222       34 428      24 360

West Penn
March 1998         280 703       52 619      39 001
June 1998          263 023       40 627      26 308
September 1998     288 272       56 248      42 835
December 1998      246 729       17 038       4 476

March 1997         282 530       47 271      36 901
June 1997          252 731       35 661      21 963
September 1997     266 746       43 865      34 333
December 1997      280 155       55 850      41 468

AGC
March 1998          18 604        9 450       5 937
June 1998           19 126        9 258       5 961
September 1998      18 303        9 297       5 625
December 1998       17 783        8 649       5 230

March 1997          20 216       10 328       6 368
June 1997           20 408       10 311       6 395
September 1997      19 664       10 230      15 396
December 1997       16 170        7 664       4 109

  *For AE and West Penn - 1998 results exclude the effect of
  extraordinary charges in June 1998 ($265,446, net of taxes, or
  $2.17 per share) and December 1998 ($9,980, net of taxes, or $.08
  per share).


<PAGE>

                                      50



                REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors and the Shareholders of
Allegheny Energy, Inc.


         In   our  opinion,  the  consolidated  financial  statements
listed  in  the  accompanying index present fairly, in  all  material
respects,  the  financial  position of  Allegheny  Energy,  Inc.  and
its  subsidiaries  at  December 31, 1998 and 1997,  and  the  results
of  their  operations  and their cash flows for  each  of  the  three
years  in  the  period ended December 31, 1998,  in  conformity  with
generally    accepted   accounting   principles.    These   financial
statements  are  the  responsibility  of  the  Company's  management;
our  responsibility  is  to  express an opinion  on  these  financial
statements  based on our audits.  We conducted our  audits  of  these
statements   in   accordance   with   generally   accepted   auditing
standards  which  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, assessing  the  accounting
principles  used  and significant estimates made by  management,  and
evaluating   the   overall  financial  statement  presentation.    We
believe   that  our  audits  provide  a  reasonable  basis  for   the
opinion expressed above.





PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
February 4, 1999


<PAGE>

                                  51



                REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors of
Monongahela Power Company


        In  our  opinion,  the  financial statements  listed  in  the
accompanying  index  present fairly, in all  material  respects,  the
financial  position  of Monongahela Power Company  (a  subsidiary  of
Allegheny  Energy,  Inc.) at December 31,  1998  and  1997,  and  the
results  of  its  operations  and its cash  flows  for  each  of  the
three  years  in  the period ended December 31, 1998,  in  conformity
with  generally  accepted  accounting  principles.   These  financial
statements  are  the  responsibility  of  the  Company's  management;
our  responsibility  is  to  express an opinion  on  these  financial
statements  based on our audits.  We conducted our  audits  of  these
statements   in   accordance   with   generally   accepted   auditing
standards  which  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, assessing  the  accounting
principles  used  and significant estimates made by  management,  and
evaluating   the   overall  financial  statement  presentation.    We
believe   that  our  audits  provide  a  reasonable  basis  for   the
opinion expressed above.






PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
February 4, 1999


<PAGE>

                                 52


                REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors of
The Potomac Edison Company


        In  our  opinion,  the  financial statements  listed  in  the
accompanying  index  present fairly, in all  material  respects,  the
financial  position of The Potomac Edison Company  (a  subsidiary  of
Allegheny  Energy,  Inc.) at December 31,  1998  and  1997,  and  the
results  of  its  operations  and its cash  flows  for  each  of  the
three  years  in  the period ended December 31, 1998,  in  conformity
with  generally  accepted  accounting  principles.   These  financial
statements  are  the  responsibility  of  the  Company's  management;
our  responsibility  is  to  express an opinion  on  these  financial
statements  based on our audits.  We conducted our  audits  of  these
statements   in   accordance   with   generally   accepted   auditing
standards  which  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, assessing  the  accounting
principles  used  and significant estimates made by  management,  and
evaluating   the   overall  financial  statement  presentation.    We
believe   that  our  audits  provide  a  reasonable  basis  for   the
opinion expressed above.





PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
February 4, 1999


<PAGE>

                                 53



                REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors of
West Penn Power Company


         In   our  opinion,  the  consolidated  financial  statements
listed  in  the  accompanying index present fairly, in  all  material
respects,  the  financial  position of West  Penn  Power  Company  (a
subsidiary  of  Allegheny  Energy,  Inc.  and  its  subsidiaries)  at
December  31,  1998  and   1997,  and  the  results of their operations 
and  their  cash  flows for each of the three years in the period ended
December 31, 1998, in conformity with  generally  accepted accounting
principles.  These financial statements  are  the  responsibility  of
the Company's management; our responsibility is to express an opinion
on  these financial statements  based  on  our audits.   We conducted
our audits of these statements in accordance with  generally accepted
auditing  standards  which  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, assessing  the  accounting
principles  used  and significant estimates made by  management,  and
evaluating   the   overall  financial  statement  presentation.    We
believe   that  our  audits  provide  a  reasonable  basis  for   the
opinion expressed above.





PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
February 4, 1999


<PAGE>

                                54



                REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors of
Allegheny Generating Company


        In  our  opinion,  the  financial statements  listed  in  the
accompanying  index  present fairly, in all  material  respects,  the
financial  position  of  Allegheny Generating Company  (a  subsidiary
of  Allegheny  Energy, Inc.) at December 31, 1998 and 1997,  and  the
results  of  its  operations  and its cash  flows  for  each  of  the
three  years  in  the period ended December 31, 1998,  in  conformity
with  generally  accepted  accounting  principles.   These  financial
statements  are  the  responsibility  of  the  Company's  management;
our  responsibility  is  to  express an opinion  on  these  financial
statements  based on our audits.  We conducted our  audits  of  these
statements   in   accordance   with   generally   accepted   auditing
standards  which  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, assessing  the  accounting
principles  used  and significant estimates made by  management,  and
evaluating   the   overall  financial  statement  presentation.    We
believe   that  our  audits  provide  a  reasonable  basis  for   the
opinion expressed above.




PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania
February 4, 1999


<PAGE>

                                  55



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

   For AE and its subsidiaries, none.

                          PART III


ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

   AE,  Monongahela,  Potomac Edison, West Penn, and  AGC.  Reference
is  made  to the Executive Officers of the Registrants in Part  I  of
this  report.   The  names, ages as of December  31,  1998,  and  the
business  experience  during the past five  years  of  the  directors
of the System companies are set forth below:

                Business Experience during     Director since date shown of
    Name           the Past Five Years        Age   AE   MP   PE   WP  AGC

Eleanor Baum         See below  (a)           58   1988 1988 1988 1988
William L. Bennett   See below  (b)           49   1991 1991 1991 1991
Thomas K. Henderson  Company employee (1)     58                       1996
Wendell F. Holland   See below  (c)           46   1994 1994 1994 1994
Kenneth M. Jones     Company employee (1)     61                       1991
Phillip E. Lint      See below  (d)           69   1989 1989 1989 1989
Frank A. Metz, Jr.   See below  (e)           64   1984 1984 1984 1984
Michael P. Morrell   Company employee (1)     50        1996 1996 1996 1996
Alan J. Noia         Company employee (1)     51   1994 1994 1987 1994 1994
Jay S. Pifer         Company employee (1)     61        1995 1995 1992
Steven H. Rice       See below  (f)           55   1986 1986 1986 1986
Gunnar E. Sarsten    See below  (g)           61   1992 1992 1992 1992
Peter J. Skrgic      Company employee (1)     57        1990 1990 1990 1989


(1)  See Executive Officers of the Registrants in Part I of this
     report for further details.

      (a) Eleanor Baum.  Dean of The Albert Nerken School  of
          Engineering   of   The  Cooper   Union   for   the
          Advancement  of  Science  and  Art.   Director  of
          Avnet, Inc. and United States Trust Company, Chair
          of  the Engineering Workforce Commission, a fellow
          of  the  Institute  of Electrical  and  Electronic
          Engineers,  Chairman of Board  of  Governors,  New
          York Academy of Sciences.  Formerly, President  of
          Accreditation Board for Engineering and Technology
          and  President,  American Society  of  Engineering
          Education.
      
      (b) William L. Bennett.  Vice-Chairman and Director  of
          HealthPlan  Services Corporation, and Director  of
          Sylvan,  Inc.  Formerly,  Chairman,  Director  and
          Chief  Executive Officer of Noel Group,  Inc.  and
          Director of Belding Heminway Company, Inc.
      
      (c) Wendell   F.  Holland.   Vice  President,  American
          International Water Services Company and  Director
          of Bryn Mawr Trust Company.  Formerly, Of Counsel,
          Law  Firm  of Reed, Smith, Shaw & McClay, Partner,
          Law  Firm  of LeBoeuf, Lamb, Greene & MacRae,  and
          Commissioner  of the Pennsylvania  Public  Utility
          Commission.
      
      (d) Phillip  E.  Lint.   Retired.   Formerly,  Partner,
          Price Waterhouse.
      
      (e) Frank  A.  Metz, Jr.  Retired.  Director of Norrell
          Corporation  and  Solutia, Inc.  Formerly,  Senior
          Vice President, Finance and Planning, and Director
          of International Business Machines Corporation and
          Director of Monsanto Company.
      
      (f) Steven  H.  Rice.  President,  LaJolla  Bank,  FSB,
          Northeast Region and Director, LaJolla Bank,  FSB.
          Formerly,   Chief  Executive  Officer   and   Vice
          Chairman of the Board of Stamford Federal  Savings
          Bank,  bank  consultant,  President  and  Director
          of The Seamen's Bank for Savings, and Director  of
          Royal Group, Inc.


<PAGE>

                                 56


      (g) Gunnar  E.  Sarsten.  Chairman and Chief  Executive
          Officer of MK International.  Formerly, President  and
          Chief    Operating   Officer   of   Morrison   Knudsen
          Corporation, President and Chief Executive Officer  of
          United  Engineers  & Constructors International,  Inc.
          (now  Raytheon Engineers & Constructors),  and  Deputy
          Chairman  of  the Third District Federal Reserve  Bank
          in Philadelphia.



ITEM 11.   EXECUTIVE COMPENSATION

         During   1998,  and  for  1997  and  1996,  the   annual
compensation paid by AE, Monongahela, Potomac Edison,  West  Penn
and AGC directly or indirectly for services in all capacities  to
such  companies to their Chief Executive Officer and each of  the
four most highly paid executive officers of the System whose cash
compensation exceeded $100,000 was as follows:


                 Summary Compensation Tables (a)
    AE(b), Monongahela(c), Potomac Edison(c), West Penn(c) and AGC(c)
                       Annual Compensation

                                                                        All
Name                                                                    Other
and                                                       Long-Term     Compen-
Principal                                 Annual          Performance   sation
Position(d)               Year  Salary($) Incentive($)(e) Plan($)(f)    ($)(g)

Alan J. Noia,             1998  525,000   180,500         286,655      184,788 
Chief Executive Officer   1997  460,000   253,000         250,657      124,495
                          1996  360,000   253,750         131,071       92,769

Peter J. Skrgic,          1998  280,008   123,000         204,753       50,757
Senior Vice President     1997  265,000   155,400         150,394       91,409
Supply                    1996  245,000   176,300          96,119       24,830

Michael P. Morrell (h)    1998  255,000   117,000         114,870       28,599
Senior Vice President &   1997  240,000    95,200            (h)        26,068
Chief Financial Officer   1996  183,336    72,500            (h)          (h)

Jay S. Pifer,             1998  250,008    66,500         131,042       41,542
Senior Vice President     1997  240,000    95,200         150,394       67,810
Delivery                  1996  230,000   112,000          87,381       30,949

Richard J. Gagliardi      1998  200,016    60,400         114,662       25,345
Vice President            1997  190,000    75,600         100,263       25,340
Administration            1996  175,000   100,800          52,429       17,898
     
        
     
     (a)  The  individuals appearing in this  chart  perform
          policy-making   functions   for   each   of    the
          Registrants.  The compensation shown  is  for  all
          services   in  all  capacities  to  AE   and   its
          subsidiaries.  All salaries and bonuses  of  these
          executives are paid by APSC.
     
     (b)  AE has no paid employees.
     
     (c)  Monongahela,  Potomac Edison, West Penn,  and  AGC
          have no paid employees.
     
     (d)  See  Executive Officers of the Registrants for all
          positions held.


<PAGE>

                                      57

     
     (e)  Incentive awards are based upon performance in the
          year  in which the figure appears but are paid  in
          the following year.  The incentive award plan will
          be continued for 1999.
     
     (f)  In  1994,  the Board of Directors of  the  Company
          implemented a Performance Share Plan (the  "Plan")
          for   senior  officers  of  the  Company  and  its
          subsidiaries   which   was   approved    by    the
          shareholders  of AE at the annual meeting  in  May
          1994.  The  first Plan cycle began on  January  1,
          1994  and  ended on December 31, 1996.   A  second
          cycle  began  on  January 1,  1995  and  ended  on
          December  31,  1997.  The figure  shown  for  1996
          represents the dollar value paid in 1997  to  each
          of  the  named executive officers who participated
          in  Cycle I.  The figure shown for 1997 represents
          the dollar value paid in 1998 to each of the named
          executive  officers who participated in Cycle  II.
          A  third cycle began on January 1, 1996 and  ended
          on  December 31, 1998.  The figure shown for  1998
          represents the dollar value paid in 1999  to  each
          of  the named executives who participated in Cycle
          III.  A fourth cycle began on January 1, 1997  and
          will end on December 31, 1999.  In 1998, the Board
          of  Directors  of AE implemented a  new  Long-Term
          Incentive   Plan,  which  was  approved   by   the
          shareholders of AE at the AE annual meeting in May
          1998.  A fifth cycle (the first three-year performance
          period of this Plan) began on January 1, 1998  and
          will  end  on December 31, 2000.  After completion
          of  each cycle, AE stock, stock options (for Cycle
          V),  cash,  or  a  combination  may  be  paid   if
          performance criteria have been met.
     
     (g)  The  figures  in this column include  the  present
          value  of the executives' cash value at retirement
          attributable to the current year's premium payment
          for  both the Executive Life Insurance and Secured
          Benefit  Plans  (based upon  the  premium,  future
          valued  to  retirement, using the policy  internal
          rate  of  return  minus the corporation's  premium
          payment),  as  well as the premium  paid  for  the
          basic  group life insurance program plan  and  the
          contribution for the Employee Stock Ownership  and
          Savings  Plan  (ESOSP)  established  as   a   non-
          contributory stock ownership plan for all eligible
          employees  effective January 1, 1976, and  amended
          in 1984 to include a savings program.
     
          Effective  January 1, 1992, the basic  group  life
          insurance provided employees was reduced from  two
          times  salary during employment, which reduced  to
          one  times  salary after five years in retirement,
          to  a  new  plan which provides one  times  salary
          until  retirement  and  $25,000  thereafter.  Some
          executive  officers  and  other  senior   managers
          remain under the prior plan.  In order to pay  for
          this  insurance for these executives, during  1992
          insurance  was purchased on the lives of  each  of
          them,  except Mr. Morrell, who is not  covered  by
          this  plan.  Effective January 1, 1993,  Allegheny
          started  to  provide funds to pay for  the  future
          benefits  due


<PAGE>

                                      58


          under  the supplemental  retirement
          plan   (Secured  Benefit  Plan).   To   do   this,
          Allegheny  purchased, during 1993, life  insurance
          on  the  lives  of  the covered  executives.   The
          premium  costs of both policies plus a factor  for
          the use of the money are returned to Allegheny  at
          the earlier of (a) death of the insured or (b) the
          later  of age 65 or 10 years from the date of  the
          policy's inception.  Under the ESOSP for 1998, all
          eligible  employees may elect to have from  2%  to
          10%  of their compensation contributed to the Plan
          as  pre-tax contributions and an additional 1%  to
          6%  as  post-tax contributions.  Employees  direct
          the investment of these contributions into one  or
          more  of  nine available funds.  Fifty percent  of
          the pre-tax contributions up to 6% of compensation
          are  matched  with common stock of AE.   Effective
          January   1  1997,  the  maximum  amount  of   any
          employee's compensation that may be used in  these
          computations is $160,000.  Employees' interests in
          the   ESOSP   vest  immediately.   Their   pre-tax
          contributions may be withdrawn only  upon  meeting
          certain  financial hardship requirements  or  upon
          termination of employment.  For 1998,  the  figure
          shown   includes  amounts  representing  (a)   the
          aggregate  of life insurance premiums  and  dollar
          value  of the benefit to the executive officer  of
          the  remainder of the premium paid  on  the  Group
          Life  Insurance  program and  the  Executive  Life
          Insurance and Secured Benefit Plans, and (b) ESOSP
          contributions, respectively, as follows:  Mr. Noia
          $179,988  and  $4,800;  Mr.  Skrgic  $45,957   and
          $4,800; Mr. Morrell $25,399 and $3,200; Mr.  Pifer
          $36,742 and $4,800; and Mr. Gagliardi $20,545  and
          $4,800.
     
     (h)  Michael  P.  Morrell joined Allegheny  on  May  1,
          1996, and did not receive a payment from the Long-
          Term Performance Plan for the first or second Plan
          cycles.  His Cycle III payout is prorated for  the
          period May 1, 1996 - December 31, 1998.


         ALLEGHENY ENERGY, INC. LONG-TERM INCENTIVE PLAN
          SHARES AWARDED IN LAST FISCAL YEAR (CYCLE V)
                                

Estimated Future Payout

<TABLE>
<CAPTION>

                            Number of   Performance     Threshold    Target      Maximum
                              Shares   Period Until     Number of   Number of   Number of
Name                                      Payout         Shares      Shares      Shares


<S>                           <C>       <C>              <C>          <C>         <C>
Alan J. Noia
Chief Executive Officer       8,077     1998-2000        4,846        8,077       16,154

Peter J. Skrgic
Senior Vice President         4,308     1998-2000        2,585        4,308        8,615

Michael P. Morrell
Senior Vice President         3,077     1998-2000        1,846        3,077        6,154

Jay S. Pifer
Senior Vice President         2,923     1998-2000        1,754        2,923        5,846

Richard J. Gagliardi
Vice President                2,462     1998-2000        1,477        2,462        4,923

</TABLE>


<PAGE>

                                           59


       The  named  executives were awarded the  above  number  of
performance  shares  for the 1998-2000 period.   Such  number  of
shares are only targets.  As described below, no payouts will  be
made unless certain criteria are met.  Each executive's 1998-2000
target   long-term  incentive  opportunity  was  converted   into
performance shares equal to an equivalent number of shares of  AE
common  stock  based on the price of such stock on  December  31,
1997.   At  the  end of this three-year performance  period,  the
performance  shares attributed to the calculated  award  will  be
valued based on the price of AE common stock on December 31, 2000
and  will  reflect dividends that would have been  paid  on  such
stock during the performance period as if they were reinvested on
the date paid.  If an executive retires, dies or otherwise leaves
the  employment  of Allegheny prior to the end of the  three-year
period,  the  executive may still receive an award based  on  the
number of months worked during the period.  The final value of an
executive's  account, if any, will be paid to  the  executive  in
early 2001.

       The actual payout of an executive's award may range from 0
to  200% of the target amount, before dividend reinvestment.  The
Management Review of Director Affairs Committee of the  Board and
Directors  may  decide to convert the value of  such  performance
shares to stock options at that time or deliver cash or shares of
common  stock.  The payout is based upon stockholder  performance
versus  the peer group.  The stockholder rating is then  compared
to  a  pre-established percentile ranking chart to determine  the
payout percentage of target.  A ranking below 30% results in a 0%
payout.   The  minimum payout begins at the  30%  ranking,  which
results  in  a payout of 60% of target, ranging up to a payout of
200% if there is a 90% or higher ranking.

                         Retirement Plan


     The Company maintains a Retirement Plan covering substantially
all employees.  The Retirement Plan is a noncontributory, trusteed
pension plan designed to meet the requirements of Section 401(a) of
the Internal Revenue Code of 1986, as amended (the Code).  Each
covered employee is eligible for retirement at normal retirement
date (age 65), with early retirement permitted.  In addition,
executive officers and other senior managers participate in a
supplemental executive retirement plan (Secured Benefit Plan).

     Pursuant to the Secured Benefit Plan, senior executives of
Allegheny companies who retire at age 60 or over with 40 or more
years of service are entitled to a supplemental retirement benefit
in an amount that, together with the benefits under the basic plan
and from other employment, will equal 60% of the executive's highest
average monthly earnings for any 36 consecutive months.  The
earnings include 50% of the actual annual incentive award paid
beginning February 1, 1996 and 100% beginning February 1, 1999.  The
supplemental benefit is reduced for less than 40 years service and
for retirement age from 60 to 55.  It is included in the amounts
shown where applicable.  To provide funds to pay such benefits,
beginning January 1, 1993, the Company purchased insurance on the
lives of the participants in the Secured Benefit Plan.  If the
assumptions made as to mortality experience, policy dividends, and
other factors are realized, the Company will recover all premium
payments, plus a factor for the use of the Company's money.  The
portion of the premiums for this insurance required to be deemed
"compensation" by the Securities and Exchange Commission is included
in the "All Other Compensation" column on page 56 of this Form 10-K.
All exectuive officers are participants in the Secured Benefit Plan.
It also provides for use of Average Compensation in excess of Code
maximums.


<PAGE>

                                     60

     The following table shows estimated maximum annual benefits
payable following retirement (assuming payments on a normal life
annuity basis and not including any survivor benefit) to an employee
in specified remuneration and years of credited service
classifications.  These amounts are based on an estimated Average
Compensation (defined as average total earnings during the highest-
paid 36 consecutive calendar months or, if smaller, the member's
highest rate of pay as of any July 1st), retirement at age 65 and
without consideration of any effect of various options which may be
elected prior to retirement.  The benefits listed in the Pension
Plan Table are not subject to any deduction for Social Security or
any other offset amounts.


                            PENSION PLAN TABLE

<TABLE>
<CAPTION>

                                              Years of Credited Service
Average Compensation(a)  15 Years  20 Years   25 Years   30 Years    35 Years   40 Years

<S>                      <C>       <C>        <C>        <C>         <C>        <C>
$  200,000               $ 60,000  $ 80,000   $100,000   $110,000    $115,000   $120,000
   250,000                 75,000   100,000    125,000    137,500     143,750    150,000
   300,000                 90,000   120,000    150,000    165,000     172,500    180,000
   350,000                105,000   140,000    175,000    192,500     201,250    210,000
   400,000                120,000   160,000    200,000    220,000     230,000    240,000
   450,000                135,000   180,000    225,000    247.500     258,750    270,000
   500,000                150,000   200,000    250,000    275,000     287,500    300,000
   550,000                165,000   220,000    275,000    302,500     316,250    330,000
   600,000                180,000   240,000    300,000    330,000     345,000    360,000
   650,000                195,000   260,000    325,000    357,500     373,750    390,000
   700,000                210,000   280,000    350,000    385,000     402,500    420,000
   750,000                225,000   300,000    375,000    412,500     431,250    450,000
   800,000                240,000   320,000    400,000    440,000     460,000    480,000

</TABLE>

(a)  The earnings of Messrs. Noia, Skrgic, Pifer, Morrell and  Gagliardi
     covered by the plan correspond substantially to such amounts shown
     for them in the summary compensation table.  As of December 31,
     1998, they had accrued 29, 34, 34, 2-1/2 and 20 years of credited
     service, respectively, under the Retirement Plan.  Pursuant to an
     agreement with Mr. Morrell, at the end of ten years of employment
     with the Company, Mr. Morrell will be credited with an additional
     eight years of service.


                                     
                        Change In Control Contracts

      AE  has  entered  into Change in Control contracts with  the  named  and
certain other Allegheny executive officers (Agreements).  Each Agreement  sets
forth (i) the severance benefits that will be provided to the employee in  the
event  the employee is terminated subsequent to a Change in Control of AE  (as
defined in the Agreements), and (ii) the employee's obligation to continue his
or  her  employment after the occurrence of certain circumstances  that  could
lead  to a Change in Control.  The Agreements provide generally that if  there
is  a  Change  in Control, unless employment is terminated by  AE  for  Cause,
Disability  or Retirement or by the employee for Good Reason (each as  defined
in the Agreements), severance benefits payable to the employee will consist of
a  cash  payment  equal to 2.99 times the employee's base  annual  salary  and
target short-term incentive together with AE maintaining existing benefits for
the  employee and the employee's dependents for a period of three years.  Each
Agreement expires on December 31, 2001, but is automatically extended for  one
year  periods  thereafter  unless  either AE  or  the  employee  gives  notice
otherwise.   Notwithstanding the delivery of such notice, the Agreements  will
continue in effect for thirty-six months after a Change in Control.

                         Compensation of Directors

      In  1998,  AE  directors who were not officers or  employees  of  System
companies  received  for  all  services to System  companies  (a)  $16,000  in
retainer  fees, (b) $800 for each committee


<PAGE>

                                    61


meeting attended, except Executive Committee  meetings, for which fees are
$200, (c) $250 for each Board  meeting of  each  company attended, and (d)
200 shares of AE common stock pursuant  to the  Restricted Stock Plan for
Outside Directors.  Under an unfunded  deferred compensation plan, a director
may elect to defer receipt of all or part of his or  her  director's  fees
for succeeding calendar years  to  be  payable  with accumulated  interest
when the director ceases to be such,  in  equal  annual installments, or,
upon authorization by the Board of Directors, in a lump sum.  In addition to
the fees mentioned above, the Chairperson of each of the Audit, Finance,
Management Review and Director Affairs, New Business, and  Strategic
Affairs Committees receives a further fee of $4,000 per year.

      In  addition, a Deferred Stock Unit Plan for Outside Directors  provides
for  a  lump  sum payment (payable at the director's election in one  or  more
installments, including interest thereon equivalent to the dividend yield)  to
directors  calculated by reference to AE's common stock.  Directors who  serve
at  least five years on the Board and leave at or after age 65, or upon  death
or  disability,  or  as  otherwise directed by the  Board  will  receive  such
payments.  Each year, AE credits each Outside Director's account with 275 
deferred stock units.


<PAGE>

                                         62


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
          AND MANAGEMENT

     The table below shows the number of shares of AE common
stock  that  are beneficially owned, directly or indirectly,
by   each  director  and  named  executive  officer  of  AE,
Monongahela, Potomac Edison, West Penn, and AGC and  by  all
directors and executive officers of each such company  as  a
group as of December 31, 1998.  To the best of the knowledge
of  AE, there is no person who is a beneficial owner of more
than  5%  of the voting securities of AE other than the  one
shareholder shown in the chart below.

                         Executive       Shares of
                         Officer or          APS          Percent
Name                     Director of     Common Stock     of Class

Eleanor Baum           AE,MP,PE,WP          2,800*    .02% or less
William L. Bennett     AE,MP,PE,WP          3,570*          "
Richard J. Gagliardi   AE                  10,541           "
Thomas K. Henderson    AE,MP,PE,WP,AGC      5,761           "
Wendell F. Holland     AE,MP,PE,WP          1,057*          "
Kenneth M. Jones       AE,AGC              11,541           "
Phillip E. Lint        AE,MP,PE,WP          1,517*          "
Frank A. Metz, Jr.     AE,MP,PE,WP          3,355*          "
Michael P. Morrell     AE,MP,PE,WP,AGC        252           "
Alan J. Noia           AE,MP,PE,WP,AGC     27,947             "
Jay S. Pifer           AE,MP,PE,WP         14,547           "
Steven H. Rice         AE,MP,PE,WP          3,640*          "
Gunnar E. Sarsten      AE,MP,PE,WP          6,800*          "
Peter J. Skrgic        AE,MP,PE,WP,AGC     16,101           "

Sanford C. Bernstein & Co., Inc.         7,948,382      6.49%
767 Fifth Avenue
New York, NY 10153

All directors and executive officers
of AE as a group (18 persons)              122,459     Less than .10%

All directors and executive officers
of MP as a group (18 persons)              115,334         "

All directors and executive officers
of PE as a group (18 persons)              115,334         "

All directors and executive officers
of WP as a group (19 persons)              121,352         .10%

All directors and executive officers
of AGC as a group (8 persons)               74,378         .06%



*Excludes the outside directors' accounts in the Deferred Stock Unit
 Plan  which, at March 1, 1999, were valued at the number of  shares
 shown:  Baum 3,463; Bennett 1,720; Holland 1,578; Lint 5,084;  Metz
 3,732; Rice 2,270; and Sarsten 3,159.


<PAGE>

                                 63


All of the shares of common stock of Monongahela (5,891,000), Potomac
Edison  (22,385,000), and West Penn (24,361,586) are owned  by  AE.
All  of  the  common  stock  of AGC is owned  by  Monongahela  (270
shares), Potomac Edison (280 shares), and West Penn (450 shares).

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.


                          PART IV

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


(a)(1)(2) The  financial statements and financial  statement
          schedules  filed as part of this  Report  are  set
          forth  under ITEM 8. and reference is made to  the
          index on page 48.

(b)       No  companies filed reports on Form 8-K during the
          quarter ended December 31, 1998.

(c)       Exhibits for AE, Monongahela, Potomac Edison, West
          Penn,  and  AGC  are listed in the  Exhibit  Index
          beginning on page E-1 and are incorporated  herein
          by reference.


<PAGE>

                                  

                               64

                           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.

                              ALLEGHENY ENERGY, INC.


                              By:  /s/ Alan J. Noia
                                  (Alan J. Noia) Chairman,
President
                                   and Chief Executive Officer
Date:  March 4, 1999



        Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.

<TABLE>
<CAPTION>

              Signature                  Title                           Date

      <S>                                <C>                             <C>
  (i) Principal Executive Officer:

      /s/ Alan J. Noia                   Chairman, President, Chief
      (Alan J. Noia                      Executive Officer and Director  3/4/99

 (ii) Principal Financial Officer:

      /s/ Michael P. Morrell             Senior Vice President,
      (Michael P. Morrell)               Finance                         3/4/99

(iii) Principal Accounting Officer:

      /s/ Thomas J.                      Vice President and
      (Thomas J. Kloc)                   Controller                      3/4/99



 (iv) A Majority of the Directors:

      *Eleanor Baum             *Frank A. Metz, Jr.
      *William L. Bennett       *Alan J. Noia
      *Wendell F. Holland       *Steven H. Rice
      *Phillip E. Lint          *Gunnar E. Sarsten

*By:  /s/ Thomas K. Henderson                                            3/4/99
      (Thomas K. Henderson)

</TABLE>

<PAGE>

                               65

                           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.  The signature of the undersigned
company  shall  be deemed to relate only to  matters  having
reference to such company and any subsidiaries thereof.

                                MONONGAHELA POWER COMPANY

                                By:  /s/ Jay S. Pifer
                                     (Jay S. Pifer) President
                                     and Director
Date:  March 4, 1999

      Pursuant to the requirements of the Securities Exchange Act
of  1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.  The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

<TABLE>
<CAPTION>

              Signature                  Title                           Date


      <S>                                <C>                             <C>
  (i) Principal Executive Officer

      /s/ Alan J. Noia                   Chairman of the Board, Chief     
      (Alan J. Noia)                     Executive Officer and Director  3/4/99

 (ii) Principal Financial Officer:

      /s/ Michael P. Morrell
      (Michael P. Morrell)               Vice President, Finance         3/4/99

(iii) Principal Accounting Officer:

      /s/ Thomas J. Kloc
      (Thomas J. Kloc)                   Controller                      3/4/99

 (iv) A Majority of the Directors:

      *Eleanor Baum             *Alan J. Noia
      *William L. Bennett       *Jay S. Pifer
      *Wendell F. Holland       *Steven H. Rice
      *Phillip E. Lint          *Gunnar E. Sarsten
      *Frank A. Metz, Jr.       *Peter J. Skrgic
      *Michael P. Morrell

*By:  /s/ Thomas K. Henderson
      (Thomas K. Henderson)                                              3/4/99

</TABLE>


<PAGE>

                               66

                           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.  The signature of the undersigned
company  shall  be deemed to relate only to  matters  having
reference to such company and any subsidiaries thereof.

                                THE POTOMAC EDISON COMPANY

                                By:  /s/ Jay S. Pifer
                                     (Jay S. Pifer) President
                                     and Director
Date:  March 4, 1999

      Pursuant to the requirements of the Securities Exchange Act
of  1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.  The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

<TABLE>
<CAPTION>


              Signature                  Title                           Date


      <S>                                <C>                             <C>
  (i) Principal Executive Officer

      /s/ Alan J. Noia                   Chairman of the Board, Chief
      (Alan J. Noia)                     Executive Officer and Director  3/4/99

 (ii) Principal Financial Officer:

      /s/ Michael P. Morrell
      (Michael P. Morrell)               Vice President, Finance         3/4/99

(iii) Principal Accounting Officer:

      /s/ Thomas J. Kloc
      (Thomas J. Kloc)                   Controller                      3/4/99

 (iv) A Majority of the Directors:

      *Eleanor Baum             *Alan J. Noia
      *William L. Bennett       *Jay S. Pifer
      *Wendell F. Holland       *Steven H. Rice
      *Phillip E. Lint          *Gunnar E. Sarsten
      *Frank A. Metz, Jr.       *Peter J. Skrgic
      *Michael P. Morrell

*By:  /s/ Thomas K. Henderson
      (Thomas K. Henderson)                                              3/4/99

</TABLE>


<PAGE>

                               67

                           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.  The signature of the undersigned
company  shall  be deemed to relate only to  matters  having
reference to such company and any subsidiaries thereof.

                                WEST PENN POWER COMPANY

                                By:  /s/ Jay S. Pifer
                                     (Jay S. Pifer) President
                                     and Director
Date:  March 4, 1999

      Pursuant to the requirements of the Securities Exchange Act
of  1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.  The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

<TABLE>
<CAPTION>


      Signature                          Title                           Date


      <S>                                <C>                             <C>
  (i) Principal Executive Officer

      /s/ Alan J. Noia                   Chairman of the Board, Chief
      (Alan J. Noia)                     Executive Officer and Director  3/4/99

 (ii) Principal Financial Officer:

      /s/ Michael P. Morrell 
      (Michael P. Morrell)               Vice President, Finance         3/4/99

(iii) Principal Accounting Officer:

      /s/ Thomas J. Kloc
      (Thomas J. Kloc)                   Controller                      3/4/99

 (iv) A Majority of the Directors:

      *Eleanor Baum             *Alan J. Noia
      *William L. Bennett       *Jay S. Pifer
      *Wendell F. Holland       *Steven H. Rice
      *Phillip E. Lint          *Gunnar E. Sarsten
      *Frank A. Metz, Jr.       *Peter J. Skrgic
      *Michael P. Morrell

*By:  /s/ Thomas K. Henderson        
      (Thomas K. Henderson)                                              3/4/99

</TABLE>

<PAGE>

                               68


                           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.  The signature of the undersigned
company  shall  be deemed to relate only to  matters  having
reference to such company and any subsidiaries thereof.

                                ALLEGHENY GENERATING COMPANY

                                By:  /s/ Alan J. Noia
                                     (Alan J. Noia)
                                     Chief Executive Officer
Date:  March 4, 1999

      Pursuant to the requirements of the Securities Exchange Act
of  1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.  The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.

<TABLE>
<CAPTION>


      Signature                          Title                           Date


      <S>                                <C>                             <C>

  (i) Principal Executive Officer

      /s/ Alan J. Noia                  Chairman of the Board, Chief
      (Alan J. Noia)                    Executive Officer and President  3/4/99

 (ii) Principal Financial Officer:

      /s/ Michael P. Morrell
      (Michael P. Morrell)              Vice President, Finance          3/4/99

(iii) Principal Accounting Officer:

      /s/ Thomas J. Kloc
      (Thomas J. Kloc)                  Controller                       3/4/99

 (iv) A Majority of the Directors:

      *Thomas K. Henderson
      *Thomas J. Kloc
      *Michael P. Morrell
      *Alan J. Noia
      *Peter J. Skrgic

*By:  /s/ Thomas K. Henderson
      (Thomas K. Henderson)                                              3/4/99


</TABLE>


<PAGE>

                               69


               CONSENT OF INDEPENDENT ACCOUNTANTS
  
  
  
  
  We  hereby consent to the incorporation by reference in
  the  Prospectus  constituting part of  Allegheny  Power
  System Inc.'s (now Allegheny Energy, Inc.) Registration
  Statements  on  Form S-3 (Nos. 33-36716  and  33-57027)
  relating   to  the  Dividend  Reinvestment  and   Stock
  Purchase  Plan  of  Allegheny  Energy,  Inc.;  in   the
  Prospectus constituting part of Allegheny Power System,
  Inc.'s   (now   Allegheny  Energy,  Inc.)  Registration
  Statement  on Form S-3 (No. 33-49791) relating  to  the
  common  stock  shelf registration;  in  the  Prospectus
  constituting   part  of  Monongahela  Power   Company's
  Registration Statements on Form S-3 (Nos. 333-31493, 33-
  51301,   33-56262  and  33-59131);  in  the  Prospectus
  constituting  part  of  The  Potomac  Edison  Company's
  Registration Statements on Form S-3 (Nos. 333-33413, 33-
  51305 and 33-59493); and in the Prospectus constituting
  part   of   West   Penn  Power  Company's  Registration
  Statements  on Form S-3 (Nos. 333-34511, 33-51303,  33-
  56997, 33-52862, 33-56260 and 33-59133); of our reports
  dated February 4, 1999 included in ITEM 8 of this  Form
  10-K.   We  also consent to the references to us  under
  the heading "Experts" in such Prospectuses.
  
  
  
  PricewaterhouseCoopers, LLP
  
  Pittsburgh, Pennsylvania
  March 29, 1999


<PAGE>

                               70

                        POWER OF ATTORNEY
  
  
             KNOW  ALL  MEN  BY THESE PRESENTS  THAT  the
  undersigned  directors  of Allegheny  Energy,  Inc.,  a
  Maryland  corporation, Monongahela  Power  Company,  an
  Ohio   corporation,  The  Potomac  Edison  Company,   a
  Maryland and Virginia corporation, and West Penn  Power
  Company,   a   Pennsylvania  corporation,   do   hereby
  constitute  and appoint THOMAS K. HENDERSON and  EILEEN
  M.  BECK,  and each of them, a true and lawful attorney
  in  his  or her name, place and stead, in any  and  all
  capacities,  to sign his or her name to Annual  Reports
  on Form 10-K for the year ended December 31, 1998 under
  the Securities Exchange Act of 1934, as amended, and to
  any and all amendments, of said Companies, and to cause
  the  same to be filed with the SEC, granting unto  said
  attorneys and each of them full power and authority  to
  do  and  perform any act and thing necessary and proper
  to be done in the premises, as fully and to all intents
  and  purposes as the undersigned could do if personally
  present,  and  the  undersigned  hereby  ratifies   and
  confirms  all that said attorneys or any  one  of  them
  shall lawfully do or cause to be done by virtue hereof.
  
  
  Dated:  March 4, 1999
  
  
  /s/ Eleanor Baum           /s/ Frank A. Metz,   Jr.
  (Eleanor Baum)             (Frank A. Metz, Jr.)
  
  /s/ William L. Bennett     /s/ Alan J.   Noia
  (William L. Bennett)       (Alan J. Noia)
  
  /s/ Wendell F. Holland     /s/ Steven H.   Rice
  (Wendell F. Holland)       (Steven H. Rice)
  
  /s/ Phillip E. Lint        /s/ Gunnar E.   Sarsten
  (Phillip E. Lint)          (Gunnar E. Sarsten)


<PAGE>

                               71
  
                        POWER OF ATTORNEY
  
  
             KNOW  ALL  MEN  BY THESE PRESENTS  THAT  the
  undersigned directors of Monongahela Power Company,  an
  Ohio   corporation,  The  Potomac  Edison  Company,   a
  Maryland and Virginia corporation, and West Penn  Power
  Company,   a   Pennsylvania  corporation,   do   hereby
  constitute  and appoint THOMAS K. HENDERSON and  EILEEN
  M.  BECK,  and each of them, a true and lawful attorney
  in   his  name,  place  and  stead,  in  any  and   all
  capacities,  to  sign his or her  name  to  the  Annual
  Report  on  Form 10-K for the year ended  December  31,
  1998  under  the Securities Exchange Act  of  1934,  as
  amended,  and  to  any  and  all  amendments,  of  said
  Company,  and  to cause the same to be filed  with  the
  SEC, granting unto said attorneys and each of them full
  power and authority to do and perform any act and thing
  necessary  and  proper to be done in the  premises,  as
  fully   and  to  all  intents  and  purposes   as   the
  undersigned  could do if personally  present,  and  the
  undersigned  hereby ratify and confirm  all  that  said
  attorneys or any one of them shall lawfully do or cause
  to be done by virtue hereof.
  
  
  Dated:  March 4, 1999
  
  
                         /s/ Michael P. Morrell
                         (Michael P. Morrell)
          
                         /s/ Jay S. Pifer
                         (Jay S. Pifer)
          
                         /s/ Peter J. Skrgic
                         (Peter J. Skrgic)


<PAGE>

                                72
  
                        POWER OF ATTORNEY
  
  
  
             KNOW  ALL  MEN  BY THESE PRESENTS  THAT  the
  undersigned directors of Allegheny Generating  Company,
  a   Virginia  corporation,  do  hereby  constitute  and
  appoint  THOMAS K. HENDERSON and EILEEN  M.  BECK,  and
  each  of them, a true and lawful attorney in his  name,
  place and stead, in any and all capacities, to sign his
  or  her name to the Annual Report on Form 10-K for  the
  year  ended  December  31, 1998  under  the  Securities
  Exchange  Act of 1934, as amended, and to any  and  all
  amendments, of said Company, and to cause the  same  to
  be filed with the SEC, granting unto said attorneys and
  each of them full power and authority to do and perform
  any  act  and thing necessary and proper to be done  in
  the  premises, as fully and to all intents and purposes
  as  the undersigned could do if personally present, and
  the undersigned hereby ratify and confirm all that said
  attorneys or any one of them shall lawfully do or cause
  to be done by virtue hereof.
  
  
  Dated:  March 4, 1999
  
  
                         /s/ Thomas K. Henderson
                         (Thomas K. Henderson)
          
                         /s/ Thomas J. Kloc
                         (Thomas J. Kloc)
          
                         /s/ Michael P. Morrell
                         (Michael P. Morrell)
          
                         /s/ Alan J. Noia
                         (Alan J. Noia)
          
                         /s/ Peter J. Skrgic
                         (Peter J. Skrgic)
          


<PAGE>


  
                               E-1

                         EXHIBIT INDEX
                         (Rule 601(a))

Allegheny Energy, Inc.
                                             Incorporation
        Documents                            by Reference

3.1  Charter of the Company,            Form 10-K of the Company
     as amended, September 16, 1997     (1-267), December 31, 1997,
                                        exh. 3.1


3.2  By-laws of the Company,            Form 10-Q of the Company
     as amended May 14, 1998            (1-267), June 30, 1998,
                                        exh. 3.2

4    Subsidiaries' Indentures
     described below

10.1 Directors' Deferred                Form 10-K of the Company
       Compensation Plan                (1-267), December 31, 1994,
                                        exh. 10.1

10.2 Executive Compensation Plan        Form 10-K of the Company
                                        (1-267), December 31, 1996
                                        exh. 10.2

10.3 Allegheny Power System Incentive   Form 10-K of the Company
     Compensation Plan                  (1-267), December 31, 1996
                                        exh. 10.3

10.4 Allegheny Power System             Form 10-K of the Company
       Supplemental Executive           (1-267), December 31, 1996
       Retirement Plan                  exh. 10.4

10.5 Executive Life Insurance           Form 10-K of the Company
       Program and Collateral           (1-267), December 31, 1994,
       Assignment Agreement             exh. 10.5

10.6 Secured Benefit Plan               Form 10-K of the Company
       and Collateral Assignment        (1-267), December 31, 1994,
       Agreement                        exh. 10.6

10.7 Restricted Stock Plan
       for Outside Directors


10.8 Deferred Stock Unit Plan           Form 10-K of the Company
       for Outside Directors            (1-267), December 31, 1997,
                                        exh. 10.8


<PAGE>

                          E-1 (cont'd.)
                                
                          EXHIBIT INDEX
                          (Rule 601(a))
                                

Allegheny Energy, Inc.
                                             Incorporation
        Documents                            by Reference

10.9 Allegheny Power System             Form 10-K of the Company
     Performance Share Plan             (1-267), December 31, 1994,
                                        exh. 10.9

10.10 Form of Change in Control
      Contract With Certain
      Executive Officers Under
      Age 55


10.11 Form of Change in Control
      Contract With Certain
      Executive Officers Over
      Age 55


10.12 Allegheny Energy, Inc.          Form S-8 of the Company
      1998 Long-Term Incentive Plan   (1-267), October 14, 1998,
                                      exh. 4.1

11   Statement re computation of
     per share earnings:  Clearly
     determinable from the financial
     statements contained in Item 8.

21   Subsidiaries of AE:

     Name of Company                      State of Organization

     Allegheny Generating Company (a)            Virginia
     Allegheny Power Service Corporation         Maryland
     AYP Capital, Inc.                           Delaware
     Monongahela Power Company                   Ohio
     The Potomac Edison Company                  Maryland and Virginia
     West Penn Power Company                     Pennsylvania

     (a)   Owned directly by Monongahela,
         Potomac Edison, and West Penn.

23   Consent of Independent Accountants   See page 69 herein.

24   Powers of Attorney                   See page 70 herein.

27   Financial Data Schedule


<PAGE>


                               E-2

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

Monongahela Power Company
                                             Incorporation
        Documents                            by Reference

3.1  Charter of the Company,                 Form 10-Q of the Company
     as amended                              (1-5164), September 1995,
                                             exh. (a)(3)(i)

3.2  Code of Regulations,                    Form 10-Q of the Company
     as amended                              (1-5164), September 1995,
                                             exh. (a)(3)(ii)

4    Indenture, dated as of                  S 2-5819, exh. 7(f)
     August 1, 1945, and                     S 2-8782, exh. 7(f)(1)
     certain Supplemental                    S 2-8881, exh. 7(b)
     Indentures of the                       S 2-9355, exh. 4(h)(1)
     Company defining rights                 S 2-9979, exh. 4(h)(1)
     of security holders.*                   S 2-10548, exh. 4(b)
                                             S 2-14763, exh. 2(b)(i)
                                             S 2-24404, exh. 2(c);
                                             S 2-26806, exh. 4(d);
                                             Forms 8-K of the Company
                                             (1-268-2) dated November 21,
                                             1991, July 15, 1992,
                                             September 1, 1992, April 29,
                                             1993 and May 23, 1995


*    There are omitted the Supplemental Indentures which do no more
     than subject property to the lien of the above Indentures since
     they are not considered constituent instruments defining the
     rights of the holders of the securities.  The Company agrees to
     furnish the Commission on its request with copies of such
     Supplemental Indentures.

10.1 Form of Change in Control
     Contract With Certain
     Executive Officers Under
     Age 55


10.2 Form of Change in Control
     Contract With Certain
     Executive Officers Over
     Age 55


<PAGE>



                          E-2 (cont'd.)

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

Monongahela Power Company
                                             Incorporation
        Documents                            by Reference

12   Computation of ratio of earnings
     to fixed charges

21   Subsidiaries:  Monongahela Power
     Company has a 27% equity ownership
     in Allegheny Generating Company,
     incorporated in Virginia; and a 25%
     equity ownership in Allegheny
     Pittsburgh Coal Company, incorporated
     in Pennsylvania.

23   Consent of Independent Accountants      See page 69 herein.

24   Powers of Attorney                      See pages 70-71 herein.

27   Financial Data Schedule


<PAGE>


                               E-3

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

The Potomac Edison Company

                                        Incorporation
           Documents                    by Reference

3.1  Charter of the Company,            Form 10-Q of the Company
     as amended                         (1-3376-2), September 1995,
                                        exh. (a)(3)(i)

3.2  By-laws of the Company,            Form 10-Q of the Company
     as amended                         (1-3376-2), September 1995,
                                        exh. (a)(3)(ii)

4    Indenture, dated as of             S 2-5473, exh. 7(b); Form
     October 1, 1944, and               S-3, 33-51305, exh. 4(d)
     certain Supplemental               Forms 8-K of the Company
     Indentures of the                  (1-3376-2) dated December 11,
     Company defining rights            1991, December 15, 1992,
     of security holders*               February 17, 1993, March 30,
                                        1993, June 22, 1994, May 12,
                                        1995 and May 17, 1995

*    There are omitted the Supplemental Indentures which do no more
     than subject property to the lien of the above Indentures since
     they are not considered constituent instruments defining the
     rights of the holders of the securities.  The Company agrees to
     furnish the Commission on its request with copies of such
     Supplemental Indentures.

10.1 Form of Change in Control
     Contract With Certain
     Executive Officers Under
     Age 55


10.2 Form of Change in Control
     Contract With Certain
     Executive Officers Over
     Age 55


12   Computation of ratio of earnings
     to fixed charges


<PAGE>



                          E-3 (cont'd.)

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

The Potomac Edison Company

                                             Incorporation
           Documents                         by Reference
21   Subsidiaries:  The Potomac Edison
     Company has a 28% equity ownership in
     Allegheny Generating Company, incorporated
     in Virginia and a 25% equity ownership in
     Allegheny Pittsburgh Coal Company,
     incorporated in Pennsylvania.

23   Consent of Independent                  See page 69 herein.
     Accountants

24   Powers of Attorney                      See pages 70-71 herein.

27   Financial Data Schedule


<PAGE>


                               E-4

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

West Penn Power Company


                                        Incorporation
     Documents                          by Reference

3.1  Charter of the Company,            Form 10-Q of the Company
     as amended                         (1-255-2), September 1995,
                                        exh. (a)(3)(i)

3.2  By-laws of the Company,            Form 10-Q of the Company
     as amended                         (1-255-2), September 1995,
                                        exh. (a)(3)(ii)

4    Indenture, dated as of             S-3, 33-51303, exh. 4(d)
     March 1, 1916, and certain         S 2-1835, exh. B(1), B(6)
     Supplemental Indentures of         S 2-4099, exh. B(6), B(7)
     the Company defining rights        S 2-4322, exh. B(5)
     of security holders.*              S 2-5362, exh. B(2), B(5)
                                        S 2-7422, exh. 7(c), 7(i)
                                        S 2-7840, exh. 7(d), 7(k)
                                        S 2-8782, exh. 7(e) (1)
                                        S 2-9477, exh. 4(c), 4(d)
                                        S 2-10802, exh. 4(b), 4(c)
                                        S 2-13400, exh. 2(c), 2(d)
                                        Form 10-Q of the Company
                                        (1-255-2), June 1980, exh. D
                                        Forms 8-K of the Company
                                        (1-255-2) dated February
                                        1991, December 1991, August
                                        13, 1992, September 15, 1992,
                                        June 9, 1993, August 2,
                                        1994 and May 19, 1995

*    There are omitted the Supplemental Indentures which do no more
     than subject property to the lien of the above Indentures since
     they are not considered constituent instruments defining the
     rights of the holders of the securities.  The Company agrees to
     furnish the Commission on its request with copies of such
     Supplemental Indentures.

10.1 Form of Employment Contract
     with Certain Executive Officers
     Under Age 55


<PAGE>


                          E-4 (cont'd.)

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

West Penn Power Company

                                        Incorporation
     Documents                          by Reference

10.2 Form of Employment Contract
     with Certain Executive Officers
     Over Age 55

12   Computation of ratio of earnings
     to fixed charges

21   Subsidiaries:  West Penn Power Company
     has   a 45% equity ownership in Allegheny
     Generating Company, incorporated in
     Virginia; a 50% equity ownership in
     Allegheny Pittsburgh Coal Company,
     incorporated in Pennsylvania; and a 100%
     equity ownership in West Virginia Power
     and Transmission Company, incorporated
     in West Virginia, which owns a 100%
     equity ownership in West Penn West
     Virginia Water Power Company,
     incorporated in Pennsylvania.

23   Consent of Independent                  See page 69 herein.
     Accountants

24   Powers of Attorney                      See pages 70-71 herein.

27   Financial Data Schedule


<PAGE>

                                 E-5

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

Allegheny Generating Company
                                                  Incorporation
           Documents                              by Reference

3.1(a)     Charter of the Company,
           as amended*

3.1(b)     Certificate of Amendment to
           Charter, effective July 14, 1989**

3.2     By-laws of the Company, as amended,       Form 10-K of the Company
        effective December 23, 1996.              (0-14688), December 31, 1996

4       Indenture, dated as of December 1,
        1986, and Supplemental Indenture,
        dated as of December 15, 1988, of the
        Company defining rights of security
        holders.***

10.1    APS Power Agreement-Bath County
        Pumped Storage Project, as amended,
        dated as of August 14, 1981, among
        Monongahela Power Company, West
        Penn Power Company, and The Potomac
        Edison Company and Allegheny
        Generating Company.****

10.2    Amendment No. 8, effective date
        January 1, 1999, to the APS Power
        Agreement - Bath County Pumped
        Storage Project.

10.3    Operating Agreement, dated as of
        June 17, 1981, among Virginia
        Electric and Power Company, Allegheny
        Generating Company, Monongahela Power
        Company, West Penn Power Company and
        The Potomac Edison Company.****

10.4    Equity Agreement, dated June 17,
        1981, between and among Allegheny
        Generating Company, Monongahela Power
        Company, West Penn Power Company and
        The Potomac Edison Company.****


<PAGE>



                          E-5 (cont'd.)

                          EXHIBIT INDEX
                          (Rule 601(a))
                                

Allegheny Generating Company

                                                 Incorporation
           Documents                             by Reference

10.5    United States of America Before The
        Federal Energy Regulatory Commission,
        Allegheny Generating Company, Docket
        No. ER84-504-000, Settlement Agreement
        effective October 1, 1985.****

12      Computation of ratio of earnings
        to fixed charges

23      Consent of Independent
        Accountants                               See page 69 herein.

24      Powers of Attorney                        See page 72
herein.

27      Financial Data Schedule

__________

*    Incorporated by reference to the designated exhibit to AGC's registration
     statement on Form 10, File No. 0-14688.

**   Incorporated by reference to Form 10-Q of the Company (0-14688)
     for June 1989, exh. (a).

***  Incorporated by reference to Forms 8-K of the Company (0-14688)
     for December 1986, exh. 4(A), and December 1988, exh. 4.1.

**** Incorporated by reference to Form 10-Q of the Company (0-14688)
     for June 1989, exh. (a).