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 (Fee Required)   
  
                                 For the fiscal year ended December 31, 1995

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

  1-267                    ALLEGHENY POWER SYSTEM, INC.          13-5531602
                           (A Maryland Corporation)
                           12 East 49th Street
                           New York, New York  10017
                           Telephone (212) 752-2121

  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 (412) 837-3000

  0-14688                  ALLEGHENY GENERATING COMPANY          13-3079675
                           (A Virginia Corporation)
                           12 East 49th Street
                           New York, New York  10017
                           Telephone (212) 752-2121

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 Power System, 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 Company     Cumulative Preferred
                              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
                                February 1, 1996              February 1, 1996  


Allegheny Power System, Inc.       $3,621,024,270                 120,700,809
                                                              ($1.25 par value)


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

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


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


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

                    
(a)   All such common stock is held by Allegheny Power System, 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 
                    Competition                                            3
                    Restructuring                                          5
                    Sales                                                  7
                    Electric Facilities                                   12
                    Allegheny Power Map                                   16
                    Research and Development                              18
                    Capital Requirements and Financing                    19
                    Fuel Supply                                           23
                    Rate Matters                                          24
                    Environmental Matters                                 26
                    Air Standards                                         27 
                    Water Standards                                       29 
                    Hazardous and Solid Wastes                            31 
                    Emerging Environmental Issues                         31 
                    Regulation                                            32

     ITEM 2.        Properties                                            37

     ITEM 3.        Legal Proceedings                                     37 

     ITEM 4.        Submission of Matters to a Vote of Security
                       Holders                                            43

                    Executive Officers of the Registrants                 44 


PART II:


     ITEM 5.        Market for the Registrants' Common Equity
                       and Related Stockholder Matters                    46


     ITEM 6.        Selected Financial Data                               47 


     ITEM 7.        Management's Discussion and Analysis of Financial          
                       Condition and Results of Operations                48 

       
     ITEM 8.        Financial Statements and Supplementary Data           49 


     ITEM 9.        Changes in and Disagreements with Accountants on      56 
                       Accounting and Financial Disclosure               
<PAGE>


                                     CONTENTS (Cont'd)
                                                                         Page

PART III:


     ITEM 10.       Directors and Executive Officers of the              
                       Registrants                                        56


     ITEM 11.       Executive Compensation                                57 


     ITEM 12.       Security Ownership of Certain Beneficial Owners    
                       and Management                                     68


     ITEM 13.       Certain Relationships and Related Transactions        69 



PART IV:


     ITEM 14.       Exhibits, Financial Statement Schedules, and     
                      Reports on Form 8-K                                 69
<PAGE>

                                     1

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY POWER SYSTEM, 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 Power System, Inc. (APS), incorporated in Maryland in 1925,
is an electric utility holding company which owns directly and indirectly
various regulated subsidiaries (collectively, Allegheny Power), and a
nonutility subsidiary, AYP Capital, Inc. (AYP Capital).  APS derives
substantially all of its income from the electric utility operations of its
direct and indirect subsidiaries, Monongahela Power Company (Monongahela), The
Potomac Edison Company (Potomac Edison), West Penn Power Company (West Penn),
and Allegheny Generating Company (AGC) (collectively, the Subsidiaries).  The
properties of the 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 (Operating
Subsidiaries).  APS has no employees.  Its officers are employed by Allegheny
Power Service Corporation (APSC), a wholly owned subsidiary of APS.  On
December 31, 1995, Allegheny Power had 5,905 employees.

         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 347,600 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.  On
December 31, 1995, Monongahela had 1,921 employees.  Its 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 368,800
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.  On December 31, 1995, Potomac Edison had 1,097
employees.  Its 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.  West Penn serves about 660,000
customers in a service area of about 9,900 square miles with a population of
about 1,399,000.  The 10 largest communities served have populations ranging
from 11,200 to 38,900.  On December 31, 1995, West Penn had 1,981 employees. 
Its 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 two municipal electric distribution systems in its service area,
which purchase their power requirements from West Penn, and five rural
electric cooperative associations, located partly within the area, which
purchase virtually all of their power through a pool supplied by West Penn and
other nonaffiliated utilities.

         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).

         APSC, incorporated in Maryland in 1963, is a wholly owned subsidiary of
APS which provides various technical, engineering, accounting, administrative,
purchasing, computing, managerial, operational, and legal services to the
Subsidiaries and AYP Capital at cost.  On December 31, 1995, APSC had 906
employees.

         AYP Capital, incorporated in Delaware in 1994, is a wholly owned
nonutility subsidiary of APS.  AYP Capital was formed in an effort to meet the
challenges of the new competitive environment in the industry.  AYP Capital
has no employees.  However, as of February 1, 1996, 10 APSC employees are
dedicated to AYP Capital activities on a full-time basis.  Other APSC
employees provide services to AYP Capital as required.  AYP Capital reimburses
APSC for the use of its employees.  APS' total investment in AYP Capital was
$1.8 million as of December 31, 1995.  APS is currently committed to invest up
to an additional $10 million in AYP Capital to fund AYP Capital's investment
in two limited partnerships.  AYP Capital has agreed to purchase a 50%
interest (276 MW) in a generating unit for approximately $170 million.  AYP
Capital has also formed a limited liability company (APS Cogenex) with EUA
Cogenex, a nonutility subsidiary of Eastern Utilities Associates.  (See ITEM
1. COMPETITION, for a further description of AYP Capital's activities.)

         Allegheny Power has in the past and may in the future experience some
of the more significant problems common to electric utilities in general. 
These include increases in operating and other expenses, difficulties in
obtaining adequate and timely rate relief, restrictions on construction and
operation of facilities due to regulatory requirements and environmental and
health considerations, including the requirements of the Clean Air Act
<PAGE>
                                  3  

Amendments of 1990 (CAAA), which among other things, require a substantial
annual reduction in emissions of sulfur dioxides (SO[2]) and nitrogen oxides
(NO[x]).

         Additional concerns include proposals to restructure and to deregulate
portions of the industry and to increase competition. (See ITEM 1.
COMPETITION.)  Further concerns of the industry include possible restrictions
on carbon dioxide emissions, uncertainties in demand due to economic
conditions, energy conservation, market competition, weather, and
interruptions in fuel supply because of weather.  (See ITEM 1. CAPITAL
REQUIREMENTS AND FINANCING, RATE MATTERS, and ENVIRONMENTAL MATTERS for
information concerning the effect on the Subsidiaries of the CAAA.)


                                                 COMPETITION

         Competitive forces within the electric utility industry continued to
increase in 1995 due to a variety of influences including legislative and
regulatory proceedings.  Difficult questions including stranded investment
recovery, responsibility for service and service reliability, the obligation
to serve, recovery of environmental and other social costs, tax implications,
and the effect of competition on all classes of customers are being debated. 
Large industrial users of electricity remain the principal nongovernmental
advocates of increased competition, including retail wheeling.  In response to
the competitive environment that has evolved following the passage of the
National Energy Policy Act of 1992 (EPACT), Allegheny Power has developed, and
is continuing to develop, a number of strategies to retain and continue to
serve its existing customers and to expand its customer base.

         In 1995, Allegheny Power began to restructure its operations in an
effort to control costs by making more efficient use of resources and
streamlining processes.  Although certain initiatives have been completed, the
process is continuing. (See ITEM 1. RESTRUCTURING for a description of the
Allegheny Power reorganization efforts.)  In addition, Allegheny Power
established and staffed in 1995 a Major Accounts Program to enhance the
working relationship between Allegheny Power and its largest customers.  In-
depth knowledge from the Major Accounts Program is already providing
opportunities for potential business ventures and is enhancing Allegheny
Power's reputation as an efficient, low cost provider of energy services.

         Various states in the Allegheny Power service area have initiated
investigations concerning competition, but, except for Maryland, definitive
conclusions have not been reached. (See ITEM 1. REGULATION for a discussion of
the competitive investigations in Maryland, Ohio, Pennsylvania, and Virginia.)

         To help meet the challenges of the new competitive environment and the
new opportunities presented in EPACT, AYP Capital was formed in 1994.  Its
purpose is to pursue and develop new opportunities in unregulated markets to
strengthen the long-term competitiveness and profitability of APS.  During
1995, AYP Capital funded several investments.  They include EnviroTech
Investment Fund I, L.P. (EnviroTech), a limited partnership formed to invest
in emerging electrotechnologies that promote the efficient use of electricity
<PAGE>
                                  4

and improve the environment.  AYP Capital has committed to invest up to $5
million in EnviroTech.  AYP Capital has also invested 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 has committed to invest up to $5 million in FONDELEC.  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. 
AYP Capital offers engineering consulting services and project management for
transmission and distribution facilities.  AYP Capital has also invested in
APS Cogenex, a limited liability company formed jointly with EUA Cogenex, a
nonutility subsidiary of Eastern Utilities Associates.  APS Cogenex provides
energy services to improve the energy efficiency of consumer facilities in the
five states in which Allegheny Power provides electric service, plus the
District of Columbia.  AYP Capital intends to provide financing to consumers
that undertake capital improvements necessary to achieve energy efficiency.

         AYP Capital is moving into the wholesale unregulated power generation
market with its agreement to purchase Duquesne Light Company's (Duquesne) 50%
interest in Unit No. 1 of the Fort Martin Power Station for about $170
million.  AYP Capital intends to utilize its share of the unit as an exempt
wholesale generator and sell the output at market price.  Obtaining the
necessary regulatory approvals will likely take several months.  AYP Capital
expects a closing in 1996.  AYP Capital is also pursuing other opportunities.

         In addition, management continues to explore methods of marketing and
pricing its core services - electric energy and the transmission thereof - in
new and competitive ways, such as bulk sales of each type of service to
nonaffiliates, incentive pricing to traditional utility customers, and
repackaging of services in nontraditional ways.  It is also attempting to
reduce costs, particularly capital expenditures, to position Allegheny Power
in a more competitive mode.

         Fully meeting challenges in the emerging competitive environment will
be difficult 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 Power is a member of the PURPA Reform Group, an ad hoc group
of utilities seeking repeal or reform of PURPA on the grounds that it is
obsolete, anticompetitive and it results in utility customers paying above-
market prices for power.  This Group supports legislation which has been
introduced in both houses of Congress to repeal or reform PURPA. (See ITEM 3.
LEGAL PROCEEDINGS for information concerning PURPA-related litigation.)

         Allegheny Power, along with the other registered electric public
utility holding companies under PUHCA, advocates repeal of PUHCA.  PUHCA
prevents or significantly disadvantages regulated holding companies from
<PAGE>
                                  5

diversifying into utility-related or nonutility businesses within or outside
their service territories, except under limited circumstances.  Exempt
companies as well as other competitors, on the other hand, can diversify into
other types of businesses with generally no greater limitations than any other
domestic company.  Legislation has been introduced in Congress to repeal PUHCA
and grant utility oversight responsibility to the Federal Energy Regulatory
Commission (FERC). The Securities and Exchange Commission (SEC) has also
recommended repeal of PUHCA.  If the problems with PUHCA are not resolved
through legislation, restructuring of Allegheny Power to reduce or eliminate
the effect of PUHCA is an alternative.


                                                RESTRUCTURING

         In the late 1960's and early 1970's, Allegheny Power was one of the
first public utility holding company systems to establish a service company, 
APSC, to increase efficiencies and savings through centralization.  APSC was
organized into two groups - Bulk Power Supply (BPS) and Central Services. 
That structure served Allegheny Power and its customers well and is one of the
reasons that its electric rates are among the lowest in the region.

         The competitive environment emerging in the electric utility industry,
however, is requiring Allegheny Power to restructure many of its functions to
strengthen its competitive position and improve its cost structure.

         The restructuring process is initiated by core teams consisting of
selected employees chosen to evaluate existing processes and recommend
changes.  The core teams receive guidance from review groups, senior
management, and consultants.  Recommendations are implemented following
acceptance by senior management and, in some cases, the Board of Directors.

         BPS has been reengineered from its functional groups - Planning,
Engineering, Construction, and Operating - to Generation, Transmission, and
Planning and Compliance Business Units.  Reengineering of the Transmission and
Planning and Compliance Business Units has been completed, and process
redesign and restructuring now under way in the power stations will complete
the reengineering of the Generation Business Unit.

         The Business Unit concept adopted in BPS and planned for other parts of
Allegheny Power is designed to improve Allegheny Power's ability to compete
and to respond to customers.  The Business Unit organization is structured to
make extensive use of teams including individuals from other Business Units or
from other areas of Allegheny Power.

         The Generation Business Unit will be responsible for ensuring that
adequate generation is available to serve the native load customers of
Allegheny Power by employing Allegheny Power generating facilities and third-
party generation obtained through its marketing efforts.  Its primary
responsibilities include ensuring the cost-effective operation and maintenance
of Allegheny Power's generating units and providing the most economic mix of
generation by available Allegheny Power generating units and off-system
purchases and sales.
<PAGE>
                                  6

         The Transmission Business Unit will be responsible for ensuring that
adequate high voltage network facilities are available and on line to convey
power produced from the power production operations run by, or procured by,
the Generation Business Unit to serve native load and to engage in wholesale
transmission sales to nonaffiliates.  It will also engage in marketing efforts
for sales of bundled and unbundled transmission services to nonaffiliates and
will be responsible for accommodating requests for transmission service
submitted by nonaffiliates who qualify as customers for that service under
federal regulations.  Finally, the Transmission Business Unit will be
responsible for maintaining the optimal economic balance on a real time basis
between native customer load and the output of the generation resources
supplied by the Generation Business Unit.

         The Planning and Compliance Business Unit will provide strategic
resource planning and engineering analysis of alternate transmission and
generation resource options, environmental and regulatory issues management,
environmental compliance oversight, research and development, and emerging
technology development for Allegheny Power.  Much of the work of this Business
Unit will be accomplished through multi-functional, cross-organizational teams
yielding a more balanced, multiple perspective solution to strategic problems.

         Reorganization in the Operating Subsidiaries began early in 1995 and
has resulted in a single management team.  There are now 18 operating
divisions compared with 23 at the beginning of 1995, and functions such as
engineering, construction, construction services, as well as marketing
functions have been consolidated.  An effort is currently under way to
redesign all the processes in the Operating Subsidiaries.

         In 1995, the Engineering and Construction Departments (E&C) of the
Operating Subsidiaries completed a partial reorganization in conjunction with
the restructuring of BPS.  Some functions in E&C were transferred to the new
Business Units, while functions in BPS involving land management,
communications, standards, and nonnetwork planning were transferred to E&C. 
The Construction Services Division of E&C consolidated its General Stores
function into two locations and developed a Material Transportation System to
serve all locations of the Operating Subsidiaries.  Repair and testing of
electrical equipment were consolidated.  The balance of E&C is undergoing
reengineering as part of the core team evaluation of the Operating
Subsidiaries.

         Corporate Services, including Accounting, Finance, Information
Services, Human Resources, and Legal, as well as other support functions, are
being reengineered along with other functions in the internal supply chain for
materials and services.  The Corporate Services and supply chain restructuring
will help to eliminate internal barriers to meeting external competition.  As
part of the restructuring, Allegheny Power consolidated two data processing
centers, which resulted in the closing of one center.

         As of January 1, 1996, APS and APSC began using the common name,
"Allegheny Power."   The Operating Subsidiaries will also begin using the
"Allegheny Power" name by September 1996, to reflect Allegheny Power's unified
<PAGE>
                                  7

mission and one-company concept.  For legal purposes, APS and the Subsidiaries
will retain their formal names.

         By late 1996, the corporate headquarters of Allegheny Power will move
from New York City to Washington County, Maryland.  The move will situate
Allegheny Power's headquarters in the service territory of the Operating
Subsidiaries.

         It is currently anticipated that all of the reengineering now under way
will be completed by the end of 1996, although Allegheny Power will continue
to identify ways to increase efficiencies.

         Downsizing was not a specific goal of Allegheny Power's reorganization
and reengineering efforts, but as a consequence of process redesign and
elimination of duplicate positions, approximately 200 employees have been
placed in a staffing force thus far.  Employees in the staffing force on
January 1, 1996 were offered a separation package.  Employees who did not
elect to accept the separation package and who are not placed in a regular
employment position will be laid-off at the end of 12 months.

         In addition, it is currently estimated that about 130 fewer employees
will be required in the power station work force by the end of 1997.  Employee
reductions are also likely to result from reengineering in the Operating
Subsidiaries and support functions.


                                                    SALES

         In 1995, consolidated kilowatt-hour (kWh) sales to the Operating
Subsidiaries' retail customers increased 3.9% from those of 1994 as a result
of increases of 3.0%, 4.7%, and 4.2% in residential, commercial, and
industrial sales, respectively.  The increased kWh sales in 1995 reflect both
growth in number of customers and higher use.  Consolidated revenues from
residential, commercial, and industrial sales increased 7.3%, 7.5%, and 5.8%,
respectively, primarily because of rate increases (See ITEM 1. RATE MATTERS)
and increased kWh sales.

         Consolidated kWh sales to and revenues from nonaffiliates under
buy/resale agreements increased 36.3% and 16.1%, respectively, due primarily
to increased sales of power purchased from nonaffiliated utilities and power
brokers, and transmitted through our system to others.  Consolidated sales
under the Standard Transmission Service Tariff increased from 0.5 billion kWh
to 1.5 billion kWh and revenues increased from $3.2 million to $5.6 million.

         Allegheny Power's all-time peak load of 7,500 MW, which was higher than
that forecast, occurred on February 5, 1996.  The peak load in 1995 and 1994
was 7,280 MW and 7,153 MW, respectively.  The average System load (yearly net
power supply divided by number of hours in the year) was 4,969 MW and 4,776 MW
in 1995 and 1994, respectively.  More information concerning sales may be
found in the statistical sections.  (See also ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)
<PAGE>
                                  8 

         Consolidated electric operating revenues for 1995 were derived as
follows: Pennsylvania, 44.6%; West Virginia, 28.3%; Maryland, 20.6%; Virginia,
5.0%; Ohio, 1.5% (residential, 35.0%; commercial, 18.7%; industrial, 29.1%;
nonaffiliated utilities, 14.5%; and other, 2.7%).  The following percentages
of such revenues were derived from these industries: iron and steel, 6.2%;
fabricated products, 3.4%; chemicals, 3.3%; aluminum and other nonferrous
metals, 3.1%; coal mines, 3.0%; cement, 1.7%; and all other industries, 8.4%. 
Revenues from each of 19 industrial customers exceeded $5 million, including
one coal customer of both Monongahela and West Penn providing total revenues
exceeding $23 million, three steel customers providing revenues exceeding $31
million each, and one aluminum customer providing revenues exceeding $67
million.                                              

         During 1995, Monongahela's kWh sales to retail customers increased 4.5%
as a result of increases of 5.0%, 6.5%, and 3.5% in residential, commercial,
and industrial sales, respectively.  Revenues from residential, commercial and
industrial customers increased 9.5%, 7.1%, and 5.1%, respectively, and
revenues from kWh sales to affiliated and nonaffiliated utilities increased
3.9%.  Monongahela's all-time peak load of 1,825 MW occurred on August 17,
1995. 

         Monongahela's electric operating revenues were derived as follows: West
Virginia, 94.6% and Ohio, 5.4% (residential, 28.9%; commercial, 17.2%;
industrial, 29.4%; nonaffiliated utilities, 12.6%; and other, 11.9%). 
Revenues from each of five industrial customers exceeded $11 million,
including one steel customer providing revenues exceeding $31 million and one
coal customer providing revenues exceeding $20 million.

         During 1995, Potomac Edison's kWh sales to retail customers increased 
3.3% as a result of increases of 3.9%, 3.6%, and 2.7% in residential,
commercial, and industrial sales, respectively. Revenues from such customers
increased 7.0%, 6.7%, and 3.0%, respectively, and revenues from kWh sales to
affiliated and nonaffiliated utilities increased 17.1%.  Potomac Edison's all-
time peak load of 2,595 MW occurred on January 19, 1994.                

         Potomac Edison's electric operating revenues were derived as follows:
Maryland, 66.9%; West Virginia 16.9% and Virginia, 16.2%; (residential, 38.7%;
commercial, 17.7%; industrial, 24.5%; nonaffiliated utilities, 15.4%; and
other, 3.7%).  Revenues from one industrial customer, the Eastalco aluminum
reduction plant near Frederick, Maryland, amounted to $67.4 million (8.2% 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 $20.3 million in 1995.  This agreement may be cancelled before the year
2000 upon 90 days notice of a governmental decision resulting in a material
modification of the agreement.

         During 1995, West Penn's kWh sales to retail customers increased 4.0%
as a result of increases of 1.4%, 4.4% and 5.8% in residential, commercial,
and industrial sales, respectively.  Revenues from residential, commercial,
and industrial customers increased 6.5%, 8.2%, and 7.9%, respectively, and
revenues from kWh sales to affiliated and nonaffiliated utilities increased 
<PAGE>
                                  9

17.6%.  West Penn's all-time peak load of 3,242 MW occurred on February 5,
1996.

         West Penn's electric operating revenues were derived as follows:
Pennsylvania, 100% (residential, 32.7%; commercial, 18.3%; industrial, 29.1%;
nonaffiliated utilities, 13.7%; and other, 6.2%).  Revenues from each of four
industrial customers exceeded $11 million, including two steel customers
providing revenues exceeding $36 million each.

         On average, the Operating Subsidiaries are the lowest or among the
lowest cost suppliers of electricity in their respective states with fixed
costs being very low and incremental costs being about average.  Therefore,
the Operating Subsidiaries' delivered power prices should compete favorably
with those of potential alternate suppliers who use cost-based pricing. 
However, the Operating Subsidiaries face increased competition from utilities
with excess generation that may be willing to sell at prices only slightly in
excess of variable costs.  At the same time, the Operating Subsidiaries are
experiencing higher costs due to compliance with the CAAA and purchases from
PURPA projects.  (See page 12 for a discussion of PURPA projects, and ITEM 3.
LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings
concerning PURPA capacity.) 

         In 1995, the Operating Subsidiaries provided approximately 15.4 billion
kWh of energy to nonaffiliated companies, of which 0.78 billion kWh were
generated by the Subsidiaries and the rest were transmitted from electric
systems located primarily to the west.  These sales included a long-term
transaction under which the Operating Subsidiaries purchased 450 MW of firm
capacity and its associated energy from Ohio Edison Company for resale to
Potomac Electric Power Company, both nonaffiliates.  The transaction began in
mid-1987 and will continue through 2005, unless terminated earlier.

         Sales to nonaffiliated companies vary with the needs of those companies
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.  Although
increases occurred in both sales of power purchased from and transmission
services with nonaffiliates in 1995, sales of power generated by Allegheny
Power decreased relative to 1994 primarily because of stagnant demand,
increased Operating Subsidiaries' native load, and increased number of and
willingness of other suppliers to make sales at lower prices.  Further
decreases in sales by Allegheny Power of power generated from rate-based
assets to nonaffiliates are expected in 1996 and beyond.  For 1995,
substantially all of the benefits of power and transmission service sales to
nonaffiliates were passed on to retail customers and as a result have little
effect on net income.

         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 during each December, January, and
February, at least through February 1998.  Thereafter, specific amounts of
annual diversity exchanges beyond those currently established are to be
<PAGE>
                                  10

mutually determined no less than 34 months prior to each year for which an
exchange is to take place.  Negotiations are currently under way to reach an
agreement on an amount of diversity exchange beyond February 1998.  The total
number of megawatt-hours (MWh) to be delivered by each utility to the other
over the term of the arrangement is expected to be the same.

         Pursuant to an exchange arrangement with Duquesne which will continue
through February 1999 and may be extended beyond that date, the Operating
Subsidiaries supply 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 supplies the Operating Subsidiaries with up to
100 MW, generally during each December, January, and February.  The total
number of MWh to be delivered by each utility to the other over the term of
the arrangement is expected to be the same.

         West Penn supplies power to the Borough of Tarentum (Tarentum) using in
part distribution facilities leased from Tarentum under a 30-year lease
agreement terminating in 1996.  In June 1993, Tarentum, which in that year
provided a load of 6.5 MW and revenues of $1.8 million, notified West Penn of
its intention to exercise its option to end the lease agreement and re-enter
the retail electric business.  The termination of the lease agreement and
resulting transfer and sale by West Penn of electric facilities installed by
West Penn will result in Tarentum becoming a municipal customer which will
purchase electricity on a wholesale basis from West Penn or another supplier. 
Tarentum has agreed to purchase wholesale electricity from West Penn until at
least March 16, 1999.  West Penn's sale of electric facilities and
discontinuance of its electric service to customers in Tarentum will require
Pennsylvania Public Utility Commission (Pennsylvania PUC) approval.

         EPACT permits wholesale generators, utility-owned and otherwise, and
wholesale consumers to request from owners of bulk power transmission
facilities a commitment to supply transmission services.  In 1995, the FERC
continued to develop new policies and procedures to implement EPACT and
requested comments on the following: a Notice of Proposed Rulemaking on open
access nondiscriminatory transmission services (Mega-NOPR), a Supplemental
Notice of Proposed Rulemaking on recovery of stranded costs, a Request for
Comments and subsequent Notice of Proposed Rulemaking on Real-Time Information
Networks and Standards of Conduct, and an Inquiry concerning alternative power
pooling arrangements.  Of particular significance to public utilities, on
March 29, 1995, the FERC issued the Mega-NOPR with the stated intent of
stimulating wholesale (sale for resale) competition among electric utilities
and nonregulated electricity generators.  The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power without undue discrimination,
as long as sufficient transmission capacity is available to provide service
without impairing reliability.  To meet the objective of providing
nondiscriminatory or comparable wholesale transmission services, the Mega-
NOPR, if adopted as proposed, requires that utilities functionally unbundle. 
Accordingly, the proposed rule if adopted will require separation of public
utility systems' operations and marketing functions and will require that
wholesale transmission services purchased by the transmission owner must be
taken under its filed open access tariffs.  In addition, the Mega-NOPR
<PAGE>
                                  11

proposes pro forma open access tariffs containing the terms and conditions for
these transmission services.  The Mega-NOPR also states that electric
utilities would be able to collect stranded costs (costs of facilities made
uneconomic by wholesale transmission access) and that it is up to the states
to decide if retail wheeling should be adopted and, if so, to address retail
stranded costs.  FERC has received public input to the Mega-NOPR and is
currently reviewing that information before issuing a final rule.  (See ITEM
1. REGULATION for a further discussion of the Mega-NOPR.)

         In response to both the Mega-NOPR and the continuing evolution of the
wholesale power and transmission service markets, Allegheny Power implemented
reorganization of its existing wholesale marketing function into separate
transmission and generation marketing functions.  (See ITEM 1. RESTRUCTURING
for further discussion of the restructuring of Bulk Power Supply.)  Through
rulings issued in various cases, the FERC has expanded the definition of
nondiscriminatory service to require a utility to provide transmission service
comparable to the service it provides itself.  (See ITEM 3. LEGAL PROCEEDINGS
for a discussion of the FERC proceeding wherein Duquesne has requested firm
transmission service over Allegheny Power's transmission facilities.)

         Through 1995, the Operating Subsidiaries provided wholesale
transmission services under their FERC-approved Standard Transmission Service
Tariff.  The tariff stipulated that such service was subordinate in priority
to native load and reliability requirements of interconnected systems to avoid
adverse effects on regional and Operating Subsidiaries' reliability. 
Transmission services requiring special arrangements or long-term commitments
were provided through specially negotiated, mutually acceptable bilateral
agreements that were consistent with and accommodated the Standard
Transmission Service Tariff.  Effective in 1996 and consistent with the
intentions of the FERC under the Mega-NOPR, Allegheny Power submitted a filing
to FERC of a set of two new transmission service tariffs which qualify as open
access filings pursuant to the Mega-NOPR.  As of December 6, 1995, the FERC
accepted for filing a Network Transmission Service Tariff and a Point-to-Point
Transmission Service Tariff under which the Operating Subsidiaries will sell
comparable open access transmission services to eligible wholesale customers. 
Customers may choose from a range of services that extend from broad use of
the transmission network on a firm basis for the life of a customer facility
to a fully interruptible energy only service that is available for a one-hour
term.  The tariffs were accepted subject to modification pending the outcome
of the Final Rule in the Mega-NOPR proceeding.  The FERC acceptance for filing
set the tariffs for hearing during the summer of 1996; in the interim, the
Operating Subsidiaries may sell transmission services under the tariffs,
subject to refund.  With this filing, the need for and applicability of the
Standard Transmission Service Tariff was eliminated for new service
transactions.  Substantially all of the revenues from transmission service
sales now arise from transactions with customers located outside the service
territory of the Operating Subsidiaries and are passed through to retail
customers.  As a result, they presently have little effect on net income.  In
addition, the Operating Subsidiaries have a Standard Generation Service Rate
Schedule tariff on file with and accepted by the FERC under which the
Operating Subsidiaries make available bundled, nonfirm generation services
with associated System transmission services to any customer who executes an
<PAGE>
                                  12

agreement under such tariff.  Revenues from this tariff are also passed
through to retail customers.

         In conjunction with the Mega-NOPR, on December 16, 1995, the FERC
issued a notice of proposed rulemaking on Real-Time Information Networks and
Standards of Conduct to ensure the separation of service directed by the
functional unbundling of wholesale services required by the Mega-NOPR and to
assure that all buyers and sellers of transmission services will have equal
and timely access to the information needed to transact business.  Allegheny
Power commented on this proposed rulemaking.

         Under PURPA, certain municipalities and private developers have
installed, are installing or are proposing to install hydroelectric and other
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.  Allegheny Power's
total generating capacity includes 299 MW of on-line PURPA capacity.  Payments
for PURPA capacity and energy in 1995 totaled approximately $129 million at an
average cost to Allegheny Power of 5.5 cents/kWh, as compared to Allegheny
Power's own generating cost of about 3 cents/kWh. Allegheny Power projects an
additional 180 MW (Warrior Run) of PURPA capacity to come on-line in 1999.  It
is expected that the Warrior Run project will result in increased costs for
Potomac Edison's customers.  Eighty MW (Burgettstown) of PURPA capacity has
been removed from Allegheny Power's projections due to a PURPA project that
expired when the project failed to meet its financing closing deadline.  (See
ITEM 3. LEGAL PROCEEDINGS for a description of the Washington Power lawsuit
filed by the Burgettstown developer against West Penn and APS concerning this
project.)  Lapsed purchase agreements totaling 203 MW (Burgettstown,
Shannopin, and Milesburg) and other PURPA related complaints totaling 470 MW
(MidAtlantic and South River) are the subject of ongoing litigation and are
not included in Allegheny Power's current planning strategy.  (See ITEM 3.
LEGAL PROCEEDINGS concerning an agreement to resovle the Shannopin lawsuit and
for a description of litigation and regulatory proceedings in Pennsylvania and
West Virginia.)


                                               ELECTRIC FACILITIES

       The following table shows Allegheny Power's December 31, 1995, generating
capacity, based on the maximum monthly normal seasonal operating capacity of
each unit.  Allegheny Power's capacity totaled 8,070 MW, of which 7,090 MW (88%)
are coal-fired, 840 MW (10%) are pumped-storage, 82 MW (1%) are oil-fired, and
58 MW (1%) are hydroelectric.  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 Allegheny Power's steam stations shown on the
following page, based on generating capacity at December 31, 1995, was about
<PAGE>
                                  13 

25.6 years.  In 1995, their average heat rate was 9,970 Btu's/kWh, and their
availability factor was 82.3%.
<PAGE>
<TABLE>
<CAPTION>
                                  14

                                            Allegheny Power Stations
                                           Maximum Generating Capacity
                                                 (Megawatts) (a)     
                                                                                                       Dates When
                                                Station        Monon-        Potomac        West       Service
Station                            Units         Total         gahela        Edison         Penn       Commenced (b)
Coal-fired (steam):
        <S>                           <C>        <C>          <C>            <C>           <C>           <C>
        Albright                       3           292          216             76                       1952-4       
        Armstrong                      2           352                                       352         1958-9        
        Fort Martin                    2           831          249            304           278         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           114                         114                       1947-58
        Willow Island                  2           243          243                                      1949-60
Oil-Fired (steam):(a)
        Mitchell                       1             82                                       82         1948
Pumped-Storage                          
and Hydro:                                                                                           
        Bath County                    6           840          227(c)        235(c)     378(c)   1985
        Lake Lynn(d)                   4            52                                        52         1926
        Potomac
         Edison(d)                   21              6                          6                        Various
Total Allegheny Power
Capacity                             54          8,070        2,326         2,072          3,672
</TABLE>
<TABLE>
<CAPTION>
                                                       Nonutility Generation
                                                    Maximum Generating Capacity
                                                           (Megawatts)(e)      
                                                                                                       Contract
                                                 Project       Monon-       Potomac         West       Commencement
Project                                           Total        gahela       Edison          Penn       Date        

Coal-fired:
  <S>                                              <C>         <C>          <C>            <C>           <C>
  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
  Nonutility Capacity                               299          161             0(f)        138

Total Maximum Allegheny Power
Generating Capacity (a)                          8,369         2,487        2,072          3,810
</TABLE>
<PAGE>
                                  15

(a)  Excludes 207 MW of West Penn oil-fired capacity at Springdale Power 
     Station and 77 MW of the total MW at Mitchell Power Station, which were 
     placed on cold reserve status as of June 1, 1983.  Current plans call for 
     the reactivation of these units in about five years.  On December 31, 
     1994, 82 MW of the total MW at Mitchell Power Station were reactivated.

(b)  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.

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

(d)  The FERC issued a new license with a 30-year term for Lake Lynn on 
     December 27, 1994.  Certain terms of said license are being appealed 
     but do not affect its validity.  Potomac Edison's license for 
     hydroelectric facilities Dam #4 and Dam #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.

(e)  Nonutility generating capacity available through state utility commission 
     approved arrangements pursuant to PURPA.

(f)  The Warrior Run project of 180 MW has completed its financial closing, 
     is under construction, and is planned to begin providing capacity and 
     energy to Potomac Edison in 1999.
<PAGE>

                                   16

                                             ALLEGHENY POWER 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 Pennsylvania,
Ohio, West Virginia, Maryland and 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 capcity from 138kV to 765kV.
Additionally, interconnections with other utilities are displayed.
<PAGE>

                                   17

The following table sets forth the existing miles of tower and pole 
transmission and distribution lines and the number of substations of the 
Subsidiaries as of December 31, 1995:
<TABLE>
<CAPTION>
                                       Above Ground Transmission and
                                     Distribution Lines (a) and Substations

                                                                  Portion of Total                      Transmission and
                                                                    Representing                          Distribution
                                                Total          500-Kilovolt (kV) Lines                   Substations(b) 

            <S>                               <C>                           <C>                                   <C>
            Monongahela                       19,912                        281                                   229 
            Potomac Edison                    17,413                        202                                   205
            West Penn                         21,940                        273                                   532
            AGC(c)                                85                         85                                     1
            Total                             59,350                        841                                   967
</TABLE>
    
            (a)      Allegheny Power has a total of 5,831 miles of underground 
                     distribution lines.

            (b)      The substations have an aggregate transformer capacity of 
                     39,207,919 kilovoltamperes.

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


       Allegheny Power has 11 extra-high-voltage (345 kV and above) (EHV) and 29
lower-voltage interconnections with neighboring utility systems.  The
interregional EHV transmission system, including System facilities,
historically has operated near reliability limits because of frequent periods
of heavy power flows, predominantly in a west-to-east direction.  In 1994 and
early 1995, use of the transmission system in aggregate declined and the west-
to-east power flows decreased to more comfortable levels.  However, in the
later months of 1995, west-to-east transfers began to increase, although not
to the critical levels commonly seen earlier in the decade.  If transfers and
customer load continue to increase, along with coincident parallel flows,
interregional EHV transmission facilities, including Allegheny Power
facilities, will again operate nearer to reliability limits, at which time
restrictions on transfers may become necessary.

          Under certain provisions of EPACT, wholesale generators and wholesale
customers may seek from owners of bulk power transmission facilities a
commitment to supply transmission services. (See discussion under ITEM 1.
SALES and REGULATION.)  Such demand on Allegheny Power's transmission
facilities may add to heavy power flows on Allegheny Power's facilities.

       The Operating Subsidiaries have, to date, provided managed contractual
access to Allegheny Power's transmission facilities via the provisions of
their Standard Transmission Service Tariff, or the terms and conditions of
bilateral contracts.  As described earlier, for new agreements starting in
1996, managed access will also be governed by the provisions of the Allegheny
Power open access tariffs recently accepted provisionally by FERC.
<PAGE>
                                  18

                                          RESEARCH AND DEVELOPMENT
  
       The Operating Subsidiaries spent $9.0 million, $7.7 million, and $4.6
million in 1995, 1994, and 1993, respectively, for research programs.  Of
these amounts, $6.2 million, $5.9 million, and $3.2 million were for Electric
Power Research Institute (EPRI) dues in 1995, 1994, and 1993, respectively. 
EPRI is an industry-sponsored research and development institution.  The
Operating Subsidiaries plan to spend approximately $8.5 million for research
in 1996, with EPRI dues representing $5.5 million of that total.

       Independent research conducted by the Operating Subsidiaries concentrated
on environmental protection (CAAA and permit mandates), generating unit
performance, future generating technologies, delivery systems, and customer-
related research.  Clean power technology focused on power quality and load
management devices and techniques for customer and delivery equipment.

       Research is also being directed to help address major issues facing
Allegheny Power including electric and magnetic field (EMF) assessment of
employee exposure within the work environment, waste disposal and discharges,
greenhouse gases, client-server information system prospects, Internet,
renewable resources, fuel cells, new combustion turbines and cogeneration
technologies.  In addition, there is continuing evaluation of technical
proposals from outside sources and monitoring of developments in industry-
related literature, law, litigation, and standards.

       As Allegheny Power continues in its effort to comply with the NOx control
requirements of the CAAA, it has entered into a 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 in the Ozone Transport Region (See
page 28).  With reference to alleged global climate change, a Participation
Accord was entered into on behalf of the Operating Subsidiaries with the
Department of Energy (DOE) to participate in the DOE's Climate Challenge
Program.  

       Electric vehicle (EV) research included participation in the Ford Ecostar
Demonstration Program, EV America and the Electric Transportation Coalition,
as well as the development of appropriate wiring and building code standards
to accommodate electric vehicles.

       Research is being directed into communication systems to develop and
demonstrate a high speed advanced power line communication system utilizing
existing utility wires to service information needs of the Operating
Subsidiaries' customers.

       Allegheny Power, in cooperation with the Pennsylvania Department of
Environmental Protection and the West Virginia Division of Environmental
Protection, continued to investigate the feasibility and cost-effectiveness of
injecting fly ash from Allegheny Power's power stations into abandoned
underground mine sites in Pennsylvania and West Virginia to reduce acid mine
<PAGE>
                                  19

drainage and mine surface subsidence.  The project cost is anticipated to be
shared with EPRI as part of a Tailored Collaboration Agreement with EPRI.

       An additional collaborative effort in which Allegheny Power participated
through West Penn in 1995 was the Pennsylvania Electric Energy Research
Council (PEERC).  PEERC was formed in 1987 as a partnership of Pennsylvania
based electric utilities to promote technological advancements related to the
electric utility industry.

       The Operating Subsidiaries also made research grants to regional colleges
and universities to encourage the development of technical resources related
to current and future utility problems.


                                     CAPITAL REQUIREMENTS AND FINANCING

          Construction expenditures by the Subsidiaries in 1995 amounted to
$318.9 million and for 1996 and 1997 are expected to aggregate $278.6 million
and $305.2 million, respectively.  In 1995, these expenditures included $36.4
million for compliance with the CAAA.  The 1996 and 1997 estimated
expenditures include $6.7 million and $19.7 million, respectively, to cover
the costs of compliance with the CAAA.  Expenditures to cover the costs of
compliance with the CAAA were much more significant in prior years and may be
again in future years if required for Phase II compliance.
<PAGE>
<TABLE>
<CAPTION>
                                  20

                                            Construction Expenditures


                                                              1995           1996            1997
                                                                     Millions of Dollars
                                                             (Actual)      (Estimated)
Monongahela
<S>                                                         <C>            <C>             <C>
Generation Business Unit                                    $  22.1        $  29.6         $  37.7
Transmission Business Unit                                     19.3            3.4             4.6    
Distribution Unit                                              34.1           32.5            32.5
  Total*                                                    $  75.5        $  65.5         $  74.8

Potomac Edison
Generation Business Unit                                    $  26.0        $  26.1         $  24.8
Transmission Business Unit                                     19.2           16.0            32.7
Distribution Unit                                              47.0           45.4            45.6
  Total*                                                    $  92.2        $  87.5         $ 103.1    

West Penn
Generation Business Unit                                    $  83.6        $  51.9         $  65.6
Transmission Business Unit                                     14.6           22.5            11.3
Distribution Unit                                              48.6           48.1            47.8
Other                                                           2.3            2.6             1.6
  Total*                                                    $ 149.1        $ 125.1         $ 126.3

AGC
Generation Business Unit                                    $   2.1        $    .5         $   1.0

Total Construction Expenditures                             $ 318.9        $ 278.6         $ 305.2
</TABLE>
                  

*    Includes allowance for funds used during construction (AFUDC) for 1995, 
     1996 and 1997 of: Monongahela $1.4, $1.0 and $2.0; Potomac Edison $1.8, 
     $1.9 and $2.5; and West Penn $5.0, $3.0 and $2.9.


          These construction expenditures include major capital projects at
existing generating stations, upgrading distribution lines and substations,
and the strengthening of the transmission and subtransmission systems.  The
Harrison scrubber project was completed on schedule and the scrubbers were
declared available for service on November 16, 1994.  The final cost is
expected to be $555 million, which is approximately 24% below the original
budget.  Primary factors that contributed to the reduced cost were: a)
favorable rulings of state commissions allowing the inclusion of carrying
costs of construction in rates in lieu of AFUDC; b) the absence of any major
construction problems; and c) financing, material and equipment costs lower
than expected.

          On a collective basis for the Operating Subsidiaries, total
expenditures for 1995, 1996, and 1997 include $76 million, $48 million, and
$71 million, respectively, for construction of environmental control
technology.  Outages for construction, CAAA compliance work and other
<PAGE>
                                  21

environmental work is, and will continue to be coordinated with planned
outages.

          Allegheny Power continues to study ways to reduce or meet future
increases in customer demand, including aggressive 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 Power generating facilities, reducing internal
electrical use and transmission and distribution losses, and, where feasible
and economical, acquisition of reliable, long-term capacity from other
electric systems and from nonutility developers.

          The Operating Subsidiaries are implementing demand-side management
activities.  Potomac Edison and West Penn are engaged in state commission
supported or ordered evaluations of demand-side management programs. (See ITEM
1. REGULATION for a further discussion of these programs.)

          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 of 1.56% and 1.57%,
respectively, in the period 1996-2006.  After considering the reactivation of
West Penn capacity in  cold reserve (see page 15), peak diversity exchange
arrangements described in ITEM 1. SALES above, demand-side management and
conservation programs, and contracted PURPA capacity, it is anticipated that
new Allegheny Power generating capacity will not be required until the year
2000 or beyond.  If future customer demand materially exceeds that forecast,
anticipated supply-side resources do not become available, demand-side
management efforts do not succeed, or in the event of extremely adverse
weather conditions, the Operating Subsidiaries may be unable at times to meet
all of their customers' requirements for electric service.

          In connection with their construction and demand-side management
programs, the Operating Subsidiaries must make estimates of the availability
and cost of capital as well as the future demands of their 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.  As a result, future plans of the Operating
Subsidiaries are subject to continuing review and substantial change.

          The Subsidiaries have financed their construction programs through
internally generated funds, first mortgage bond, debenture, medium-term note,
subordinated debt, and preferred stock issues, pollution control and solid
waste disposal notes, installment loans, long-term lease arrangements, equity
investments by APS (or, in the case of AGC, by the Operating Subsidiaries),
and, where necessary, interim short-term debt.  The future ability of the
Subsidiaries to finance their construction programs by these means depends on
many factors, including creditworthiness, rate levels sufficient to provide
internally generated funds and adequate revenues to produce a satisfactory
return on the common equity portion of the Subsidiaries' capital structures
<PAGE>
                                 22

and to support their issuance of senior and other securities.  The
creditworthiness of the Operating Subsidiaries in the future may be affected
by increased concern of rating agencies that purchased power contracts are a
risk factor deserving consideration.  APS obtains most of the funds for equity
investments in the Operating Subsidiaries through the issuance and sale of its
common stock publicly and through its Dividend Reinvestment and Stock Purchase
Plan and its Employee Stock Ownership and Savings Plan.

          AYP Capital has agreed to purchase Duquesne's 50% ownership interest
(276 MW) in Fort Martin Unit No. 1 for approximately $170 million.  Various
financing alternatives for this acquisition are being considered.

          In 1995, the Operating Subsidiaries refunded an aggregate of $493.4
million of securities.  The securities issued for the refunding had interest
rates ranging from 6.05% to 8.00%.  Preferred stock issues totaling $155.5
million were refunded with Quarterly Income Debt Securities (QUIDS).  QUIDS
are subordinated debt instruments which permit deferral of interest payments
under certain circumstances for up to 20 consecutive quarters.

          In May 1995, the Operating Subsidiaries issued $245 million of first
mortgage bonds having interest rates between 7-5/8% and 7-3/4% to refund like
securities having interest rates from 8-7/8% to 9-5/8%.  Monongahela sold $70
million of 7-5/8% 30-year first mortgage bonds to refund a $70 million 8-7/8%
issue due in 2019.  Potomac Edison sold $65 million of 7-3/4% 30-year first
mortgage bonds to refund a $65 million 9-1/4% issue due in 2019 and $80
million of 7-5/8% 30-year first mortgage bonds to refund an $80 million 9-5/8%
issue due in 2020.  West Penn sold $30 million of 7-3/4% 30-year first
mortgage bonds to refund a $30 million 9% issue due in 2019.

          In June 1995, the Operating Subsidiaries issued $92.9 million of tax-
exempt bonds having interest rates from 6.05% to 6.15% to refund like
securities having interest rates from 6.95% to 9-3/8%.  Monongahela sold $25
million of 6.15% 20-year tax-exempt bonds to refund a $25 million 7-3/4%
issue.  Potomac Edison sold $21 million of 6.15% 20-year tax-exempt bonds to
refund a $21 million 7.3% issue.  West Penn sold $31.5 million of 6.15% 20-
year tax-exempt bonds to refund a $20 million 7% issue and an $11.5 million
6.95% issue.  West Penn also sold $15.4 million of 6.05% 19-year tax-exempt
bonds to refund a $15.4 million 9-3/8% issue.

          In June 1995, the Operating Subsidiaries issued QUIDS to refund an
aggregate of $155.5 million of preferred stock.  Monongahela sold $40 million
of 8% 30-year QUIDS to refund $40 million of preferred stock with rates
between 7.36% and 8.8%.  Potomac Edison sold $45.5 million of 8% 30-year QUIDS
to refund $45.5 million of preferred stock with rates between 7% and 8.32%. 
West Penn sold $70 million of 8% 30-year QUIDS to refund $70 million of
preferred stock with rates between 7% and 8.2%.

          In 1995, APS sold 1,407,855 shares of its common stock for $34.6
million through its Dividend Reinvestment and Stock Purchase Plan and its
Employee Stock Ownership and Savings Plan.
<PAGE>
                                  23

          During 1995, 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 4.75%, 4.71%, 4.249% and 4.292%.  The rate set at auction on January 12,
1996, was 4.185%.

          At December 31, 1995, short-term debt was outstanding in the following
amounts:  APS $78.7 million, Monongahela $29.9 million, Potomac Edison $21.6
million, and West Penn $70.2 million, respectively.  At December 31, 1995, AGC
had $30.6 million of commercial paper outstanding.

          The Subsidiaries' ratios of earnings to fixed charges for the year
ended December 31, 1995, were as follows:  Monongahela, 3.68; Potomac Edison,
3.27; West Penn, 3.58; and AGC, 3.22.

          Allegheny Power's consolidated capitalization ratios as of December
31, 1995, were: common equity, 46.6%; preferred stock, 3.7%; and long-term
debt, 49.7%, including QUIDS (3.3%).  Allegheny Power's long-term objective is
to maintain the common equity portion above 45%.

          During 1996, the Operating Subsidiaries currently anticipate meeting
their capital requirements through a combination of internally generated
funds, cash on hand, and short-term borrowing as necessary.  APS plans to
continue selling common stock through its Dividend Reinvestment and Stock
Purchase Plan and Employee Stock Ownership and Savings Plan.


                                                 FUEL SUPPLY

          Allegheny Power-operated stations burned approximately 15.9 million
tons of coal in 1995.  Of that amount, 88% was either cleaned (5.2 million
tons) or used in stations equipped with scrubbers (8.8 million tons).  The use
of desulfurization equipment and the cleaning and blending of coal make
burning local higher-sulfur coal practical.  In 1995 about 97% of the coal
received at Allegheny Power-operated stations came from mines in West
Virginia, Pennsylvania, Maryland, and Ohio.  The Operating Subsidiaries do 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, subject to price change, are in effect and
will provide for approximately 11 million tons of coal in 1996.  The Operating
Subsidiaries will depend on short-term arrangements and spot purchases for
their remaining requirements.  Through the year 1999, the total coal
requirements of present Allegheny Power-operated stations are expected to be
met with coal acquired under existing contracts or from known suppliers.

          For each of the years 1991 through 1994, the average cost per ton of
coal burned was $36.74, $36.31, $36.19 and $35.88, respectively.  For the year
1995, the cost per ton decreased to $32.68.

          Long-term arrangements, subject to price change, are in effect and
will provide for the lime requirements of scrubbers at Allegheny Power's
scrubbed stations.
<PAGE>
                                  24

          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 fly ash and bottom ash
for beneficial uses and thereby reduce landfill requirements.  (See also ITEM
1. RESEARCH AND DEVELOPMENT.)  In 1995, the Operating Subsidiaries received
approximately $459,000 for the sale of 206,609 tons of fly ash and 31,014 tons
of bottom ash for various uses including cement replacement, mine grouting,
oil well grouting, soil extenders and anti-skid material.

          The Operating Subsidiaries own coal reserves estimated to contain
about 125 million tons of high-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

          Rate case decisions were issued for Monongahela, Potomac Edison and
AGC in 1995.

                                              Monongahela Power

          As previously reported, on January 18, 1994, Monongahela filed an
application with the Public Service Commission of West Virginia (West Virginia
PSC) for a base rate increase designed to produce $61.3 million in additional
annual revenues which included recovery of the remaining carrying charges on
investment, depreciation, and all operating costs required to comply with
Phase I of the CAAA, and other increasing levels of expense.  On November 9,
1994 the West Virginia PSC affirmed the recommended decision of the
Administrative Law Judge (ALJ) which provided for a rate increase of $23.5
million and a 10.85% return on equity (ROE) effective November 16, 1994.  This
amount was in addition to $6.9 million of CAAA recovery granted effective July
1, 1994, in the Expanded Net Energy Cost (ENEC) recovery proceeding which had
been included in Monongahela's $61.3 million request.  The West Virginia PSC
invited all parties to file petitions for reconsideration which resulted in a
second order issued on March 17, 1995.  The March 17, 1995 order deferred some
of CAAA issues to the 1995 ENEC proceeding.  The net result of both the March
17, 1995 base rate order and the ENEC order decreased the previously allowed
increase to base rates adopted in the November 9, 1994 order by $1.1 million
to $22.4 million and maintained the ROE of 10.85%.  The ENEC order permits
Monongahela to apply for review of its post-1994 scrubber operation and
maintenance expense levels and CAAA investment during the 1996 ENEC
proceeding.  Monongahela filed a Petition for Appeal with the West Virginia
Supreme Court of Appeals challenging the March 17 order.  The court declined
to hear the appeal.

          On January 31, 1995, Monongahela filed an application with The Public
Utilities Commission of Ohio (Ohio PUC) for a base rate increase designed to
produce $7.0 million in additional annual revenues which included recovery of
carrying charges on investment, depreciation, and all operating costs required
to comply with Phase I of the CAAA, and other increasing levels of expense. 
<PAGE>
                                  25

On October 20, 1995, a stipulation was submitted by all of the parties to the
Ohio PUC.  The Ohio PUC approved the stipulation on November 9, 1995 providing
for an annual revenue increase of $6.0 million effective November 9, 1995.


                                               Potomac Edison

          On January 14, 1994, Potomac Edison filed an application with the West
Virginia PSC for a base rate increase of $12.2 million which included recovery
of the remaining carrying charges on investment, depreciation, and all
operating costs required to comply with Phase I of the CAAA, and other
increasing levels of expense.  On November 9, 1994, the West Virginia PSC
affirmed the recommended decision of the ALJ providing for a rate increase of
$1.5 million and an ROE of 10.85% effective November 11, 1994.  This increase
was in addition to $1.9 million of CAAA recovery granted effective July 1,
1994, which had been included in Potomac Edison's original request for $12.2
million.  The West Virginia PSC invited all parties to file petitions for
reconsideration which resulted in a second order issued on March 17, 1995. 
This order deferred some of the CAAA issues to the 1995 ENEC proceeding.  The
net result of both the March 17, 1995 base rate order and the ENEC order
reduced the original $1.5 million increase in base rates adopted in the
November 9, 1994 order by $1.1 million to $.4 million.  The ROE was maintained
at 10.85%. The order permits Potomac Edison to apply for review of its post-
1994 scrubber operation and maintenance expense levels and CAAA  investment
during the 1996 ENEC proceeding.  Potomac Edison filed a Petition for Appeal
with the West Virginia Supreme Court of Appeals challenging the March 17
order.  The court declined to hear the appeal.

          On June 25, 1995, Potomac Edison implemented two FERC-approved
settlement agreements covering wholesale rates in effect for its municipal,
co-op, and borderline agreement customers subject to the jurisdiction of the
FERC.  Each agreement included recovery of the remaining carrying charges on
investment, depreciation, as well as all operating costs required to comply
with Phase I of the CAAA, and other increasing levels of expense.  The first
agreement, with all but one of Potomac Edison's FERC customers, provides for a
three-year term of service with an increase in annual revenues of $2.12
million. During this period, a moratorium on further rate changes, except for
changes based on fuel costs, taxes, and environmental statutes or regulations,
is in effect.  This agreement also allows Potomac Edison to seek legitimate
and verifiable stranded costs from any customer who terminates service under
the tariff.  The second agreement, with the one remaining Potomac Edison FERC
customer not included under the first agreement, provides for service until
January 1, 1997, (approximately eighteen months) with an increase in annual
rates of $.15 million.  A moratorium on rate increases is also in effect for
this time period.  However, this agreement contains no provision for recovery
of stranded costs from the customer should service be terminated.


                                                     AGC

          AGC's rates are set by a formula filed with and previously accepted by
FERC.  The only component which changes is the ROE.  In December 1991, AGC
<PAGE>
                                  26

filed for a continuation of the existing ROE of 11.53% and other interested
parties filed to reduce the ROE to 10%.  Hearings were held and a
recommendation was issued by an ALJ on December 21, 1993, for an ROE of
10.83%.  Exceptions to this recommendation were filed by all parties for
consideration by the FERC.  On January 28, 1994, a complaint was filed jointly
by several parties with the FERC against AGC claiming that both the existing
ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and
unreasonable.  A recommendation was issued by an ALJ on December 22, 1994, to
dismiss the joint complaint.  A settlement agreement for both cases was filed
with FERC on January 12, 1995, which would reduce AGC's ROE from 11.53% to
11.13% for the period from March 1, 1992 through December 31, 1994, and
increase AGC's ROE to 11.2% for the period from January 1, 1995 through
December 31, 1995.  This settlement was approved by FERC on March 23, 1995. 
Refunds were made by AGC of any revenues collected between March 1, 1992 and
March 23, 1995 in excess of these levels.  A second settlement has been
negotiated to address AGC's ROE after 1995.  On December 21, 1995, AGC
submitted the new settlement to the FERC and action is pending.  The
interested parties representing less than 2% of AGC's eventual revenues have
filed exceptions to the settlement.  Under the terms of the settlement, AGC's
ROE for 1996 would be 11%.  For 1997 and 1998 the ROE would be set by a
formula based upon the yields of 10-year constant maturity U.S. Treasury
securities.  However, the change in ROE from the previous year's value cannot
exceed 50 basis points.

          Through a filing completed on October 31, 1994, AGC sought FERC
approval to add a prior tax payment of approximately $12 million to rate base
which would produce about $1.4 million in additional annual revenues.  The
FERC accepted AGC's filing and ordered the increase to become effective June
1, 1995.


                                            ENVIRONMENTAL MATTERS

          The operations of the Subsidiaries 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.

          Meeting known environmental standards is estimated to cost the
Subsidiaries about $199 million in capital expenditures over the next three
years.  Additional legislation or regulatory control requirements, if enacted,
may require modifying, supplementing, or replacing equipment at existing
stations at substantial additional cost. 


                                                Air Standards

          Allegheny Power currently meets applicable standards as to
particulates and opacity at the 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 fuel operations, are experienced and are accommodated by the
regulatory process.
<PAGE>
                                  27

          On July 17, 1995, the West Virginia Division of Environmental
Protection (WVDEP), Office of Air Quality (OAQ), issued a Notice of Violation
(NOV) regarding the accidental release of particulate matter that occurred on
June 17, 1995, at the Pleasants Power Station.  Allegheny Power responded on
August 11, 1995, and stated that the accidental release of particulate matter
was not due to a failure of any of the pollution control equipment, but was a
side effect of testing a further reduction of the sulfur dioxide (SO[2])
emissions from the power station.  Subsequently, on November 16, 1995, the
WVDEP issued a Cease and Desist Order pertaining to the release.  In order to
minimize the risk of future releases, the station intends to increase the
frequency of scheduled stack washing.  Also, a consultant has been retained to
determine whether any operational or equipment changes can be implemented to
reduce the risk of releases in the future.

          Allegheny Power meets current emission standards as to SO[2] 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, require an annual reduction in total
utility emissions within the United States of 10 million tons of SO[2] and two
million tons of nitrogen oxides (NO[x]) from 1980 emission levels, to be
completed in two phases, Phase I and Phase II.  Five coal-fired Allegheny
Power plants are affected in Phase I and the remaining plants and units
reactivated in the future will be affected in Phase II.  Installation of
scrubbers at the Harrison Power Station was the strategy undertaken by
Allegheny Power to meet the required SO[2] emission reductions for Phase I
(1995-1999).  Continuing studies will determine the compliance strategy for
Phase II (2000 and beyond).  Studies to evaluate cost effective options to
comply with Phase II SO[2] limits, including those which may be available from
the use of Allegheny Power's banked emission allowances and from the emission
allowance trading market, are continuing.  It is expected that burner
modifications at possibly all Allegheny Power stations will satisfy the NO[x]
emission reduction requirements for the acid rain (Title IV) provisions of the
CAAA.  Additional post-combustion controls may be mandated in Maryland and
Pennsylvania 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 SO[2] emission allowances.  An allowance is defined as an
authorization to emit one ton of SO[2] into the atmosphere.  Subject to
regulatory limitations, allowances (including bonus and extension allowances)
may be sold or banked for future use or sale.  Allegheny Power 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 of approximately 356,000 per year
during the Phase I years.  Ownership of these allowances permits Allegheny
Power to operate in compliance with Phase I, as well as to postpone a decision
on its compliance strategy for Phase II.  As part of its compliance strategy,
Allegheny Power 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.
<PAGE>
                                  28  

          In a case brought by the electric utility industry which disputed the
EPA's inclusion of overfire air equipment as well as low NO[x] burners in its
definition of "low NO[x] burner technology," the District of Columbia Circuit
Court of Appeals on November 29, 1994 vacated and remanded to the EPA the
Title IV NO[x] rule. As a result, the January 1, 1995, Phase I NO[x]
compliance deadline under Title IV is no longer applicable.  On April 13,
1995, the EPA published the revised NO[x] regulation which redefined low NO[x]
burner technology as "burners only" and changed the Phase I compliance date
from January 1, 1995, to January 1, 1996.

          Pursuant to an option in the CAAA and in order to avoid the potential
for more stringent NO[x] limits in Phase II, Allegheny Power chose to treat
seven Phase II Group 1 boilers (tangential- and wall-fired) as Phase I
affected units (Substitution Units) as of January 1, 1995.  Additionally, the
four Phase II, Group 2 boilers (top- and cyclone-fired) were also made
Substitution Units for 1995.  The status of all Substitution Units will be
evaluated on an annual basis to ascertain the financial benefits.  As a result
of being Phase I affected, these Substitution Units will also be required to
comply with the Phase I SO[2] limits for each year that they are accorded
substitution status by Allegheny Power.  Phase I NO[x] and SO[2] compliance
for these units should not require additional capital or operating
expenditures.

          Title I of the CAAA established an ozone transport region (OTR)
consisting of the District of Columbia, the northern part of Virginia and 11
northeast states including Maryland and Pennsylvania.  On October 11, 1995,
Pennsylvania petitioned the EPA to remove western Pennsylvania from the OTR. 
The EPA has not acted on the request.  Sources within the OTR will be required
to reduce NO[x] 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 NO[x] burners) at all Pennsylvania and Maryland stations
has been completed.  This is essentially compatible with Title IV NO[x]
reduction requirements.

          The Ozone Transport Commission (OTC), formed by the states in the OTR
and Washington, DC, has determined that Allegheny Power will be required to
make additional NO[x] reductions beyond RACT in order for the ozone transport
region to meet the ozone NAAQS.  Under terms of a Memorandum of Understanding
(MOU) among the OTR states, Allegheny Power's power stations located in
Maryland and Pennsylvania will be required to reduce NO[x] emissions by 55%
from the 1990 baseline emissions, with a compliance date of May 1999.  Further
reductions of 75% from the 1990 baseline will be required by May 2003, unless
the results of modeling studies due to be completed by 1998, indicate
otherwise.  If Allegheny Power has to make reductions of 75%, it could be very
expensive and would depend upon further technological advances.  Both Maryland
and Pennsylvania must promulgate regulations to implement the terms of the
MOU.

          During 1995, the Environmental Council of States (ECOS) and the EPA
established the Ozone Transport Assessment Group (OTAG) to develop
recommendations for the regional control of NO[x] and Volatile Organic
Compounds (VOC's) in 31 states east of and bordering the west bank of the
<PAGE>
                                  29 

Mississippi River plus Texas.  OTAG appears to be similar to the OTC in
purpose and organization.  OTAG could lead to additional NO[x] controls on
certain Allegheny Power generating facilities in West Virginia.  There is no
assurance that NO[x] control for non-OTR states will be limited to RACT.  What
occurs in the non-OTR states could also affect whether Allegheny Power
generating facilities in Maryland and Pennsylvania would need post-RACT
controls.  OTAG plans to issue recommendations by the end of 1996.

          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 status of Monongahela's Rivesville Station with
ambient standards for SO[2].  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 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 over $13 million with the expectation that EPA's reclassification
of Armstrong County to "attainment status" under NAAQS for SO[2] 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.


                                               Water Standards

          Under the National Pollutant Discharge Elimination System (NPDES),
permits for all of Allegheny Power's stations and disposal sites are in place. 
However, NPDES permit renewals for several West Virginia disposal sites
contain what Allegheny Power believes are overly stringent discharge
limitations.  The WVDEP has temporarily stayed the stringent permit
limitations while Allegheny Power continues to work with WVDEP and EPA in
order to scientifically justify less stringent limits.  Where this is not
possible, installation of wastewater treatment facilities may become
necessary.  The cost of such facilities, if required, cannot be predicted at
this time.

          The stormwater permitting program required under the 1987 Amendments
to the Clean Water Act required implementation in two phases.  In Phase I, the
EPA and state agencies implemented stormwater runoff regulations for
controlling discharges from industrial and municipal sources as well as
construction sites.  Stormwater discharges have been identified and included
in NPDES permit renewals, but controls have not yet been required.  Since the
<PAGE>
                                  30

current round of permit renewals began in 1993, monitoring requirements have
been imposed, with pollution reduction plans and additional control of some
discharges anticipated.

          In April 1995, EPA promulgated the Phase II stormwater rule which
establishes a two-tiered application process for discharges composed entirely
of stormwater.  Under the rule, sources determined to be significant
contributors to water quality problems will be required to apply for a
discharge permit within 180 days of receiving notice.  The remaining sources
are required to apply for permits within six years of the rule's effective
date or August 2, 2001 under yet-to-be proposed application requirements.

          Pursuant to the National Groundwater Protection Strategy, West
Virginia adopted a Groundwater Protection Act in 1991.  This law establishes a
statewide antidegradation policy which could require Allegheny Power to
undertake reconstruction of existing landfills and surface impoundments as
well as groundwater remediation, and may affect herbicide use for right-of-way
maintenance in West Virginia.  Groundwater protection standards were approved
and implemented in 1993 (based on EPA drinking water criteria) which
established compliance limits.  Pursuant to the groundwater protection
standards variance provision, on October 26, 1994, Allegheny Power jointly
filed with American Electric Power Company, Inc. (AEP) and Virginia Power, a
Notice of Intent (NOI) to request class or source variances from the
groundwater standards for steam electric operating facilities in West
Virginia.  Additionally, each of the companies filed individual NOIs. 
Technical and socio-economic justification to support the variance requests
are being developed and the costs shared through EPRI by all participants,
including Allegheny Power.  While the justification for the variance requests
is being developed, Allegheny Power is protected from any enforcement action. 
Because variance requests must ultimately be approved by the West Virginia
legislature, it is not possible to predict the outcome.

          The Pennsylvania Department of Environmental Protection (PADEP)
developed a Groundwater Quality Protection Strategy which established a goal
of nondegradation of groundwater quality.  However, the strategy recognizes
that there are technical and economic limitations to immediately achieving the
goal and further recognizes that some groundwaters need greater protection
than others.  PADEP is beginning to implement the strategy by promulgating
changes to the existing rules that heretofore did not consider the
nondegradation goal.  The full extent of the impact of the strategy on
Allegheny Power cannot be predicted.


                                         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, 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.
<PAGE>
                                  31

          Allegheny Power 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 operating in compliance with their permits.

          Significant costs were incurred during 1995 for expansion of existing
coal combustion by-product disposal sites due to requirements for installation
of liners on new sites and assessment of groundwater impacts through routine
groundwater monitoring and specific hydrogeological studies.  Existing sites
may not meet the current regulatory criteria and groundwater remediation may
be required at some of Allegheny Power's facilities.  Allegheny Power
continues to work with regulatory agencies to resolve outstanding issues. 
Additional and substantial costs may be incurred by the Operating Subsidiaries
if remediation of existing sites is necessary.

          Allegheny Power 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.

          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 in central Pennsylvania.  (See ITEM 3.
LEGAL PROCEEDINGS for a description of this superfund case.)


                                        Emerging Environmental Issues

          Title III of the CAAA requires EPA to conduct studies of toxic air
pollutants from electric utility plants to determine if emission controls are
necessary.  EPA's reports are expected to be submitted to Congress in early
1996.  If air toxic emission controls are recommended by EPA, final
regulations are not likely to be promulgated prior to the year 2000.  The
impact of Title III on Allegheny Power is unknown at this time.

          Reauthorization of the Clean Water Act, CERCLA and the RCRA are
currently pending.  When reauthorization does occur, it is anticipated that
EPA will likely continue to regulate coal combustion by-product wastes and
their leachates as nonhazardous.

          Pursuant to RCRA, EPA began reviewing the electric utility industry's
disposal practices of pyrites and pyritic material in 1995.  Concerns over the
production of low pH waters from pyrites may cause reclassification of ash or
flue-gas desulfurization by-product disposal areas containing pyrites to that
<PAGE>
                                  32

of special handling waste, or even possibly hazardous waste.  Any change in
classification would result in substantially increased costs for either
retrofitting existing disposal sites or designing new disposal sites.  A final
determination is scheduled for 1998.

          An additional issue which could impact Allegheny Power and which is
undergoing intense study, is the health effect, if any, of electric and
magnetic fields.  The financial impact of this issue on Allegheny Power, if
any, cannot be assessed at this time.

          In connection with President Clinton's Climate Change Action Plan
concerning greenhouse gases, Allegheny Power expressed by letter to DOE in
August 1993, its willingness to work with the DOE on implementing voluntary,
cost-effective courses of action that reduce or avoid emission of greenhouse
gases.  Such courses of action must take into account the unique circumstances
of each participating company, such as growth requirements, fuel mix and other
circumstances.  Furthermore, they must be consistent with Allegheny Power's
integrated resource planning process and must not have an adverse effect on
its competitive position in terms of costs and rates, or be unacceptable to
its regulators.  Some 63 other electric utility systems submitted similar
letters.

          On April 27, 1994, the DOE and the Edison Electric Institute, on
behalf of member utilities, signed the Climate Challenge Program Memorandum of
Understanding which established the principles DOE and utilities will operate
under to reduce or avoid emission of greenhouse gases.  A company-specific
agreement was entered into on behalf of the Operating Subsidiaries and DOE in
February 1995.

          The EPA is required by law to regularly review the National Ambient
Air Quality Standards for criteria pollutants.  Recent court orders due to
litigation by the American Lung Association have expedited these reviews.  The
EPA is currently reviewing the standards for ozone, SO[2], NO[x], and
particulate matter.  The impact on Allegheny Power of any revision to these
standards is unknown at this time.


                                                 REGULATION

          Allegheny Power and AYP Capital are subject to the broad jurisdiction
of the SEC under PUHCA.  APS, as a Maryland corporation, is also subject to
the jurisdiction of the Maryland PSC as to certain of its activities.  The
Subsidiaries are regulated as to substantially all of their operations by
regulatory commissions in the states in which they operate and also by the
DOE.  The Subsidiaries and AYP Capital are regulated by the FERC.  In
addition, they are subject to numerous other city, county, 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.  A
bill has been introduced in Congress to repeal PUHCA. However, Allegheny Power
<PAGE>
                                   33

cannot predict what changes, if any, will be made to PUHCA as a result of
these activities.

          On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking on
open access nondiscriminatory transmission service which came to be known as
the "Mega-NOPR" due to its size and scope.  If adopted by the FERC, the Mega-
NOPR will lead to a fundamental restructuring of the business of transmitting
wholesale electric power and could potentially influence the future of retail
electric sales as well.  The FERC's stated objective was to ensure development
of a competitive market for wholesale power buyers and sellers while
preventing anti-competitive or discriminatory transmission practices.  The
Mega-NOPR requires all public or investor-owned utilities that own
transmission systems and are under FERC's jurisdiction to file
nondiscriminatory, open access transmission tariffs available to all wholesale
buyers and sellers of electricity and apply these open access tariffs to their
own wholesale purchases and sales of electricity.  The Mega-NOPR also permits
such utilities to recover stranded costs that may result from restructuring of
the wholesale electric industry.  In a separate notice, FERC proposed the
development of a standardized, real-time electronic information network to
provide all potential users of a utility's transmission system equal access to
information regarding transmission capability and pricing.  Allegheny Power
has numerous concerns regarding the Mega-NOPR, including the issue of stranded
costs, reliability of service and the development of a real-time electronic
information network.

          The requirements of the Mega-NOPR, if adopted by FERC, would force
utilities to functionally unbundle their transmission and generation assets to
operate independently of one another, in order to promote nondiscriminatory
behavior.  In response to the Mega-NOPR and in conjunction with Allegheny
Power's reengineering of its Bulk Power Supply functions, Allegheny Power has
established separate business units to operate and manage its generation and
transmission assets.  (See ITEM 1. REORGANIZATION for further discussion of
the formation of business units.)  Allegheny Power cannot predict when FERC
will issue final regulations, nor the specifics thereof, regarding
nondiscriminatory open access transmission services and related issues.

          Allegheny Power founded and continues to participate in, along with
other utilities, an organization (General Agreement on Parallel Paths) whose
primary purpose is to develop a mutually acceptable method of resolving the
inequities imposed on transmission network owners by parallel power flows.

          Section 111 of EPACT requires state utility commissions to institute
proceedings to investigate and determine the feasibility of adopting proposed
federal standards regarding three regulatory policy issues related to
integrated resource planning, rate recovery methods for investments in demand-
side management programs, and rates to encourage investments in cost-effective
energy efficiency improvements to generation, transmission and distribution
facilities.  In 1994, Maryland, Pennsylvania, Virginia, and West Virginia
initiated investigations to determine whether to adopt the federal standards,
while Ohio summarily issued a final order.  Allegheny Power submitted comments
in all proceedings.  Maryland, Ohio, Virginia and West Virginia have issued
final orders.  All four states declined to adopt the federal standards,
<PAGE>
                                  34

concluding that existing state regulations adequately address the issues.  The
outcome in Pennsylvania cannot be predicted.                 

          On December 30, 1995, the Pennsylvania PUC issued its regulations
regarding future competitive bidding for purchase of capacity and energy.  The
regulations specify the rules an electric utility must follow to competitively
bid the long-term purchase of capacity and energy.

          In November 1993, while awaiting the new competitive bidding
regulations, West Penn filed a petition with the Pennsylvania PUC requesting
an order that, pending the adoption of new state regulations requiring
competitive bidding for PURPA, any proceedings or orders regarding purchase by
West Penn of capacity from a qualifying facility under PURPA shall be based on
competitive bidding.  On June 3, 1994, the Pennsylvania PUC granted the West
Penn petition.  However, the Pennsylvania PUC reserved judgment on the
applicability of the competitive bidding process to the South River project
and provided that the question would be addressed in the South River complaint
proceeding.  By March 1995, all appeals to the June 1994 order were withdrawn
and the order became final.

          On October 8, 1993, the West Virginia PSC issued proposed regulations
concerning bidding procedures for capacity additions for electric utilities
and invited comment by December 7, 1993.  A number of interested parties,
including Monongahela and Potomac Edison, filed comments.  In May 1994, the
West Virginia PSC held hearings on the proposed regulations.  The West
Virginia PSC has yet to issue an Order.

          On December 17, 1992, the Ohio PUC issued proposed rules concerning
competitive bidding for supply-side resources, transmission access for winning
bidders, and incentives for the recovery of the cost of purchased power.  The
Ohio PUC invited comments and a number of interested parties, including
Monongahela, submitted comments.  The Ohio PUC has taken no further action
following the filing of comments.

          As part of its investigation into market competition and regulatory
policies, the Maryland PSC has declared that all new capacity needs in the
state will be subject to competitive bidding unless a utility can demonstrate
why a particular capacity need should not be bid.

          Virginia has not mandated compulsory competitive bidding for capacity
additions.
  
          On September 20, 1994, the Maryland PSC instituted a proceeding for
the purpose of examining regulatory and competitive issues affecting electric
service in Maryland.  On November 1, 1994, the Maryland PSC staff described
the issues on which they requested comment by the utilities and interested
persons.  Potomac Edison submitted comments.  After legislative hearings were
held and comments were filed, the Maryland PSC issued an order.  In its order
dated August 18, 1995 the Commission found that while competition in the
electric wholesale market should be encouraged, retail competition is not in
the public interest at this time.  The Commission also announced in its order
that in the future it would be flexible and allow utilities to implement
<PAGE>
                                   35

special rates and contracts including cost-based economic development rates as
appropriate.

          By order dated September 18, 1995, the Virginia State Corporation
Commission began an investigation reviewing Commission policy regarding
restructuring of and competition in the electric utility industry. The
Commission staff has been directed to investigate and file a report on
competitive issues by March 29, 1996. Comments by utilities and other
interested persons on the staff report are due by May 31.

          The Ohio PUC has initiated informal roundtable discussions on issues
concerning competition in the electric utility industry and promoting
increased competitive options for Ohio businesses.  These discussions are
being undertaken pursuant to an Ohio Energy Strategy issued in April 1994. 
The Ohio PUC is pursuing an incremental approach to competition by holding
roundtable meetings.  As a first step, the meetings have resulted in a set of
guidelines on interruptible rates which are now pending before the Ohio PUC.

          The Pennsylvania PUC instituted an investigation into electric power
competition on May 10, 1994, requesting responses from interested persons on
several broad areas of inquiry, such as retail wheeling, treatment of stranded
investments, consumer protection and utility financial health.  Comments and
reply comments have been filed.  The Pennsylvania PUC staff issued a report
advising against instituting retail wheeling at this time.  Thereafter, the
Pennsylvania PUC held hearings in December 1995, January 1996, and February
1996.  The Pennsylvania PUC has set a target of April 1996 to issue a final
report to the Governor and the Pennsylvania Legislature.

          In August 1994, the Pennsylvania PUC instituted a proposed rulemaking
relating to Pennsylvania PUC review of siting and construction of electric
transmission lines.  In connection with the proposed rulemaking, the
Pennsylvania PUC propounded a list of questions, including questions regarding
electric and magnetic fields.  In December 1994, West Penn filed responses to
the questions.  West Penn cannot predict the outcome of this proposed
rulemaking.

          In October 1995, the Staff of the Maryland PSC issued draft
regulations concerning the construction of generating stations and overhead
transmission lines by nonutility generators (NUGS), applications covering
modifications of electric generating stations by utilities and by NUGs, and
changes to current regulations relating to whether certificates of public
convenience and necessity must be obtained prior to modifying existing
overhead transmission lines.  Potomac Edison commented on the proposed changes
in November 1995, and cannot predict what, if any, modifications might be made
to current regulations.

          In October 1990, the Pennsylvania PUC ordered Pennsylvania's major
electric utilities, including West Penn, to file programs for demand-side
management designed to reduce customer demand for electricity and to reduce
the need for additional generating capacity.  The Pennsylvania PUC also
instituted a proceeding to formalize incentive ratemaking treatment for
successful demand-side management activities.  On December 13, 1993, the
<PAGE>
                                  36

Pennsylvania PUC entered an order allowing Pennsylvania utilities to recover
the costs of demand-side management activities, to recover revenues lost as a
result of the activities, and to recover a performance incentive for
successful activities.  A group of industrial customers appealed the order to
the Pennsylvania Commonwealth Court.  On January 9, 1995, the Court held that
utilities could recover demand-side management expenditures, but held that the
Pennsylvania PUC had incorrectly allowed recovery of lost revenues and
performance incentives.  The Pennsylvania PUC has appealed the case to the
Pennsylvania Supreme Court.

          During 1995, Potomac Edison continued its participation in the
Collaborative Process for demand-side management in Maryland. Potomac Edison's
two programs, the Commercial and Industrial Lighting Rebate Program and the
Power Saver/Comfort Home Program for new residential construction continued. 
Through December 31, 1995, Potomac Edison had approved applications for $15.2
million in rebates related to the commercial lighting program and $2.6 million
in rebates related to the residential new construction program. The peak
demand reductions from these two programs through the end of 1995 should
reduce future generation requirements by about 18.4 and 3.3 MW respectively.
Program costs (including rebates) which are being amortized over a seven-year
period, lost revenues, and a performance based shared savings incentive
(shareholder bonus) are being recovered through an Energy Conservation
Surcharge.  Potomac Edison filed a request to change the method used to
allocate demand-side management costs to customers as part of the surcharge. 
The requested change was denied by a Hearing Examiner but has been appealed to
the full Commission. Potomac Edison is awaiting the Commission's decision on
this allocation issue.

          West Penn implemented a two-year Low Income Payment and Usage
Reduction Pilot Program in 1994.  This program will assist up to 2,000 low
income customers.  The program allows a customer to enter into a payment
agreement with West Penn which results in a reduced monthly payment based on
income.  The difference between the amount of the actual bill and the
customer's payment is paid by Federal Assistance Grants and West Penn.  The
program is administered by the Dollar Energy Fund, a nonprofit, charitable
organization.

          West Penn also implemented a Customer Assistance and Referral
Evaluation Service Program in 1994 for customers with special needs.  West
Penn representatives work with customers who are experiencing temporary
hardship in an attempt to solve their problems and maximize their ability to
pay their bills.  West Penn representatives utilize a variety of internal and
external resources to address the needs of such customers.

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 properties are also subject to a second lien securing certain
solid waste disposal and pollution control notes.  The indenture under which
<PAGE>
                                   37

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, 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 POWER MAP.)


ITEM 3.    LEGAL PROCEEDINGS

          On September 16, 1994, Duquesne Light Company (Duquesne) initiated a
proceeding before the FERC by filing a request for an order requiring the
Operating Subsidiaries to provide 300 MW of transmission service at parity
with native load customers from interconnection points with Allegheny Power to
Allegheny Power's points of interconnection with the Pennsylvania-New Jersey-
Maryland Interconnection.  On May 16, 1995, the FERC issued a preliminary
order directing the Operating Subsidiaries to provide 300 MW of transmission
service as requested by Duquesne.  The order established further procedures
for the development of rates, terms, and conditions of service by the parties. 
The parties have completed the procedural schedule and await a final order
from the FERC.  On October 6, 1995, the Operating Subsidiaries filed open
access tariffs under which they intend to provide comparable wholesale
transmission services to all potential customers, including Duquesne. 
Consequently, on October 23, 1995, the Operating Subsidiaries filed a motion
asking FERC to suspend further proceedings in the Duquesne docket and to
consolidate it with the open access docket.  The FERC has chosen not to
consolidate the proceedings for the present time.

          In 1979, National Steel Corporation (National Steel) filed suit
against APS and certain Subsidiaries in the Circuit Court of Hancock County,
West Virginia, 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 APS 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.  APS and the Subsidiaries
believe the motion is without merit; however, they cannot predict the outcome
of this case.

          In 1987, West Penn entered into separate Electric Energy Purchase
Agreements (EEPAs) with developers of three PURPA projects:  Milesburg (43
MW), Burgettstown  (80 MW), and Shannopin (80 MW).  The EEPAs provided for the
purchase of each project's power over 30 years or more at rates generally
approximating West Penn's estimated avoided cost at the time the EEPAs were
<PAGE>
                                   38

negotiated.  Each EEPA was subject to prior Pennsylvania PUC approval.  In
1987 and 1988, West Penn filed a separate petition with the Pennsylvania PUC
for approval of each EEPA.  Thereafter the Pennsylvania PUC issued orders that
significantly modified the EEPAs.  Since that time, all three EEPAs as
modified have been, in varying degrees, the subject of complex and continuing
regulatory and judicial proceedings.  On various dates in 1994, West Penn and
its two largest industrial customers, Armco Advanced Materials Company and
Allegheny Ludlum Corporation, filed joint petitions with the U.S. Supreme
Court for writs of certiorari (Cert) in the Milesburg, Burgettstown, and
Shannopin cases.  On October 11, 1994, the U.S. Supreme Court denied these
requests for appeal.

          After denial of Cert, the Pennsylvania PUC, acting upon a pending
petition of Shannopin, entered an order calculating capacity costs to be paid
to the project.  West Penn and its two largest industrial customers appealed
this order to the Pennsylvania Commonwealth Court.  On July 20, 1995, the
Pennsylvania Commonwealth Court reversed part of the PUC order by reducing the
maximum avoided capacity cost rate to be paid to the project from 8.0151 cents
per kWh to 5.5933 cents per kWh.  On October 23, 1995, West Penn filed a
Petition for Allowance of Appeal with the Pennsylvania Supreme Court.  A cross
petition for Allowance of Appeal was subsequently filed by Shannopin.  These
appeals are pending.

          West Penn and the developers of the Shannopin project reached an
agreement on January 25, 1996, which provides that West Penn will buy out the
Shannopin EEPA and terminate the project and all pending litigation associated
with the Shannopin project.  The agreement provides for a buy out price of $31
million.  The buy out agreement is subject to Pennsylvania PUC approval of
West Penn's full pass through of the buy out price to West Penn's customers
through the energy cost rate by no later than March 31, 1999.  Once the
Pennsylvania PUC order is final and no longer subject to appeal, both parties
will withdraw their pending Pennsylvania Supreme Court appeals.  Because the
buy out agreement is conditioned on full pass through of the buy out price to
customers, it will not have a material effect on West Penn's net income. 
However, the buy out will significantly aid West Penn's customers by
eliminating a requirement to purchase unneeded, above market cost power for 30
years.  The agreement was filed with the Pennsylvania PUC on February 13,
1996, along with a request for expedited approval.

          On February 27, 1995, the Milesburg developers filed with the
Pennsylvania PUC a Petition for Recalculation of capacity cost to be paid to
the project in accordance with the July 1990 order of the Commonwealth Court. 
These matters have since been stayed at the request of Milesburg and West Penn
for the purpose of pursuing settlement discussions.

          The Pennsylvania PUC orders relating to recalculated rates and
adjusted milestone dates for Burgettstown became final and no longer subject
to appeal as of November 8, 1994.

          In November 1994, West Penn filed a complaint with the Pennsylvania
PUC regarding Burgettstown, Shannopin, and Milesburg, requesting the
Pennsylvania PUC to rescind its orders regarding these projects because they
<PAGE>
                                   39 

were not in accord with PURPA and were no longer in the public interest.  On
December 16, 1994, the Pennsylvania PUC dismissed the complaint.  West Penn
appealed the order to the Pennsylvania Commonwealth Court.  By order entered
May 25, 1995, the Pennsylvania Commonwealth Court affirmed the Pennsylvania
PUC order.

          In November 1994, Washington Power (I), Inc. and Air Products and
Chemicals, Inc., trading as Washington Power Company, L.P. (Washington Power),
the developer of Burgettstown, filed a complaint against West Penn in the
Court of Common Pleas of Washington County, Pennsylvania.  The complaint
requested equitable relief in the form of specific performance, declaratory
and injunctive relief, and also sought monetary damages for breach of contract
and for tortious interference with Burgettstown's contractual relations with
others.  The Court set April 3, 1995 as the trial date for the specific
performance remedy only.  The trial was cancelled at the request of Washington
Power.  On May 5, 1995, at the request of Washington Power, the Court entered
an order discontinuing the case without prejudice.

          On March 10, 1995, West Penn filed a petition for issuance of a
declaratory order with FERC.  This petition sought a declaration that the
orders of the Pennsylvania PUC requiring West Penn to purchase capacity from
Burgettstown at rates and pursuant to the terms in the Pennsylvania PUC Orders
violated PURPA and FERC's PURPA regulations and thus West Penn had no
obligation to purchase capacity from Burgettstown.  On May 8, 1995, FERC
denied the petition.

          The Burgettstown EEPA automatically terminated in accordance with its
terms, as the financing closing had not occurred by May 8, 1995, as required
by the Pennsylvania PUC orders.  Burgettstown did not request an extension.

          On May 2, 1995,  Washington Power filed a complaint against West Penn,
APS and APSC in the United States District Court for the Western District of
Pennsylvania asserting claims of treble damages for monopolization and
attempts to monopolize in violation of the federal antitrust laws, unfair
competition, breach of contract, intentional interference with contract and
interference with prospective business relations.  West Penn, APS and APSC
cannot predict the outcome of this litigation.

          In October 1993, South River Power Partners, L.P. (South River) filed
a complaint against West Penn with the Pennsylvania PUC.  The complaint seeks
to require West Penn to purchase 240 MW of power from a proposed coal-fired
PURPA project to be built in Fayette County, Pennsylvania.  West Penn is
opposing this complaint as the power is not needed and the price proposed by
South River is in excess of avoided cost.  The Pennsylvania Consumer Advocate,
the Small Business Advocate, the Pennsylvania PUC Trial Staff and various
industrial customers intervened in opposition to the complaint.  On August 2,
1995, these proceedings, with the exception of discovery, were stayed due to
South River's appeal to the Commonwealth Court of an order of the Pennsylvania
PUC requiring South River to bear the cost associated with providing notice of
the proceedings to West Penn's customers.  West Penn cannot predict the
outcome of this proceeding.
<PAGE>
                                   40

          Two previously reported complaints had been filed with the West
Virginia PSC by developers of PURPA cogeneration projects in Marshall County,
West Virginia (MidAtlantic) and Barbour County, West Virginia, seeking to
require Monongahela and Potomac Edison to purchase capacity from the projects.

          Following a meeting in February, 1994, and an exchange of
correspondence in the spring and summer of 1994, no further contact was had
with the developers of the Barbour County project until, following a request
by the PSC for a status report, Barbour County reported it was ready to go
forward and discuss substantial modifications to the project.  Potomac Edison
and Monongahela responded on May 8, 1995, recommending the West Virginia PSC
require evidence that a new project would be a qualifying facility (QF) under
PURPA, that Barbour County provide a plan for resolving its QF status, and
that any meeting with Staff be open to representatives of all parties.  By
Order dated June 15, 1995, the West Virginia PSC dismissed the Barbour County
complaint on the basis that the project was undefined and contrary to the
public interest.

          The developers of the MidAtlantic project contacted Potomac Edison and
Monongahela in September 1994 proposing a new, two-phased gas turbine
facility.  Following an exchange of letters, on January 10, 1995 MidAtlantic
filed with the West Virginia PSC a Motion to Compel Potomac Edison to enter
into an agreement, alleging bad faith negotiations.  Potomac Edison and
Monongahela filed a response on January 30, 1995, denying bad faith and noting
numerous problems with MidAtlantic's new proposed project, including its plan
to have West Virginia customers pay 100% of costs of the first phase, contrary
to an order entered by the West Virginia PSC on March 5, 1993.  On March 20,
1995 the West Virginia PSC issued an order rejecting MidAtlantic's plan to
charge 100% of its Phase I project to West Virginia customers; directing
MidAtlantic to obtain from FERC a resolution of its QF status; and requiring
MidAtlantic to advise the West Virginia PSC within 30 days if it intended to
pursue its complaint.

          MidAtlantic filed a response to the West Virginia PSC order on April
19, 1995, together with a motion for extension of time to respond to the
question whether it would continue with the project, citing withdrawal of its
financial partner (Babcock and Wilcox) from the project.  Following a grant of
an extension of time, on June 26, 1995, MidAtlantic filed a letter informing
the West Virginia PSC that it would not pursue its project further, blaming
APS for its inability to obtain a financial partner.  The West Virginia PSC
dismissed the MidAtlantic complaint by order dated June 29, 1995.

          On September 7, 1995, MidAtlantic sued Monongahela, Potomac Edison,
and APS in state court in Marshall County, West Virginia for failure to comply
with PURPA regulations in refusing to purchase capacity and energy from the
proposed project; interference with MidAtlantic's contract with Babcock and
Wilcox; causing and/or aiding Babcock and Wilcox in breaching a fiduciary
duty; defamation; and undermining PURPA in an anti-competitive civil
conspiracy with Babcock and Wilcox.  The MidAtlantic suit was also filed
against Babcock and Wilcox for breach of contract, breach of fiduciary duty,
and conspiring with Allegheny Power to undermine PURPA.  MidAtlantic seeks
compensatory and punitive damages.   Monongahela, Potomac Edison and APS filed
<PAGE>
                                  41

an answer on October 24, 1995, and Babcock and Wilcox filed an answer,
counterclaim and motion for summary judgment, alleging that MidAtlantic had
released Babcock and Wilcox from all obligations arising from their
development agreement.  The court heard oral argument on the summary judgment
motion on January 19, 1996.  Monongahela, Potomac Edison and APS cannot
predict the outcome of this litigation.

          On August 24, 1995, American Bituminous Power Partners, L.P. (ABPP),
owner and operator of the Grant Town project, an operating 80 MW waste coal
PURPA project located in Marion County, West Virginia (see page 14), filed a
Petition to Reopen and for Emergency Interim Relief with the West Virginia PSC
against Monongahela.  ABPP seeks modifications to the EEPA that will result in
an unspecified increase in the cap of the Tracking Account and a retroactive
restoration of the price for project energy to 1.9 cents/kWh.  The West
Virginia PSC issued an order on November 29, 1995, which set a schedule for
briefing of issues.  In its brief, ABPP advised for the first time that the
modifications it is seeking are only for interim relief and that if such
relief is granted, it intends to petition the West Virginia PSC to further
amend the EEPA to permanently increase the avoided energy cost.  On December
20, 1995, ABPP requested additional briefing to clarify the relief sought.  On
January 5, 1996, the West Virginia PSC granted ABPP's request and set a
schedule for additional briefs which concluded on January 26, 1996. 
Monongahela cannot predict the outcome of this proceeding.

          As previously reported, effective March 1, 1989, West Virginia enacted
a new method for calculating the Business and Occupation Tax 
(B & O Tax) on electricity generated in that state, which disproportionately
increased the B & O Tax on shipments of electricity to other states.  In 1989,
West Penn, the Pennsylvania Consumer Advocate, and several West Penn
industrial customers filed a joint complaint in the Circuit Court of Kanawha
County, West Virginia seeking to have the B & O Tax declared illegal and
unconstitutional on the grounds that it violates the Interstate Commerce
Clause and the Equal Protection Clause of the federal Constitution and certain
provisions of federal law that bar the states from imposing or assessing taxes
on the generation or transmission of electricity that discriminate against
out-of-state entities.  In 1991, West Penn amended the complaint to include a
1990 increase in the rate of the B & O Tax.  The trial was held in July 1993,
and briefs were filed.  Effective June 1, 1995, West Virginia enacted a new
method of calculating the B & O Tax, assessing the tax on a capacity rather
than a generation basis and effective January 31, 1996, included a lower rate
for generating units with flue-gas desulfurization systems (scrubbers).  As a
result of these changes, this litigation ended.

          As of March 8, 1996, Monongahela has been named as a defendant
along with multiple other defendants in a total of 5,564 pending asbestos
cases involving one or more plaintiffs.  Potomac Edison and West Penn have
been named as defendants along with multiple other defendants in a total of
2,749 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-
<PAGE>
                                 42

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.  Because there are multiple defendants, the Operating Subsidiaries
believe their relative percentage of potential liability is a small percentage
of the total amount of the damages sought.  A total of 94 cases have been
previously settled and/or dismissed as 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 June 10, 1994, Allegheny Power filed a declaratory judgment action
in the Superior Court of New Jersey 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.  On January 27, 1995, the
Court granted the CGL insurers' motion which dismissed the complaint, without
prejudice, on procedural grounds.  On the same day, Allegheny Power
recommenced action in the Court of Common Pleas of Westmoreland County,
Pennsylvania where it is currently pending.  To date, two insurers have
settled.  However, the final outcome of this proceeding cannot be predicted.

          On December 13, 1995, APSC, Monongahela, and Potomac Edison filed a
civil complaint in the Court of Common Pleas of Westmoreland County,
Pennsylvania against Industrial Risk Insurers (IRI) seeking damages in excess
of $5 million for breach of an insurance contract covering physical damage to
property at Unit No. 1 of Fort Martin Power Station.  IRI previously denied
coverage under an all risk insurance policy in effect at the time of the
property damage.  The outcome of the litigation or the amount of damages, if
any, that may be recovered 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 875 other PRPs involved.  A Remedial
Investigation/Feasibility Study (RI/FS) prepared by the EPA indicates remedial
alternatives which range as high as $113 million, to be shared by all
responsible parties.  A PRP Group has been formed and has submitted an
addendum to the RI/FS which proposes a substantially less expensive cleanup
remedy.  The EPA has not yet selected which remedial alternatives it will use,
<PAGE>
                                  43 

nor has it issued a Proposed Plan and Record of Decision.  The Operating
Subsidiaries cannot predict the outcome of this proceeding.

          After protracted litigation concerning the Operating Subsidiaries'
application for a license to build a 1,000-MW energy-storage facility near
Davis, West Virginia, 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 decision
has been appealed and  negotiations are ongoing to settle this matter.  The
Operating Subsidiaries cannot predict the outcome of this proceeding.


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


       APS, Monongahela, West Penn and AGC did not submit any matters to a vote
of shareholders during the fourth quarter of 1995.
          
       The holder of all the outstanding common stock of Potomac Edison
consented in writing on October 23, 1995, to the amendment of the Charter of the
Corporation to reclassify shares that had been purchased pursuant to a mandatory
sinking fund.
<PAGE>
<TABLE>
<CAPTION>
                                 44

                                          Executive Officers of the Registrants 

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

                                                         Position (a) and Period of Service                            

<S>                     <C>      <C>           <C>               <C>            <C>             <C>              <C>    
Name                    Age      APS           APSC              MP             PE              WP               AGC
Charles S. Ault         57                                                                      V.P.
                                                                                                (1990-    )

Thomas A. Barlow(b)     61                                       V.P.
                                                                 (1987-95)

Eileen M. Beck          54  Secretary      Secretary       Secretary      Secretary       Secretary        Secretary
                            (1988-  )      (1988-  )       (1995-  )      (1996-  )       (1996-  )        (1982-  )
                            Asst. Treas.   Asst. Treas.    Asst. Treas.   Previously,     Previously,
                            (1979-  )      (1979-  )       (1981-  )      Asst. Sec.      Asst. Sec.
                                                           Previously,    (1988-95)       (1988-95)
                                                           Asst. Sec.
                                                           (1988-94)      

Klaus Bergman           64  CEO            CEO             Chrm., CEO     Chrm., CEO      Chrm., CEO       Dir. (1982- )
                            & Dir.         & Dir.          & Dir.         & Dir.          & Dir.           Pres. & CEO
                            (1985-  )      (1985-  )       (1985-  )      (1985-  )       (1985-  )        (1985-   )
                            Chairman       Chairman
                            (1994-  )      (1994-  )
                            Previously,    Previously,
                            Pres.           Pres.
                            (1985-94)      (1985-94)

Marvin W. Bomar         55                                 V.P.
                                                           (9/95-  )

Charles V. Burkley(c)   64                                                                Controller
                                                                                          (1984-12/95)

Nancy L. Campbell       56  V.P.            V.P.           Treasurer      Treasurer       Treasurer        Treas. & 
                            (1994-  )      (1993-  )       (1995-  )      (1996-  )       (1996-  )        Asst. Sec.
                            Treas.          Treas.                        & Asst. Sec.                     (1988-  )
                            (1988-  )       (1988-  )                     (1988-  )
                                                                          Previously,
                                                                          Asst. Treas.
                                                                          (1988-95)
Richard J. Gagliardi    45  V.P.           V.P.            Asst. Sec.                                      Asst. Treas.
                            (1991-  )      (1990-  )       (1990-  )                                       (1982-   )

Stanley I. Garnett (d)  52  Senior         Senior          Dir.           Dir.            Dir.             Dir. & V.P.
                            V.P. - Fin.    V.P. - Fin.     (1990-95)      (1990-95)       (1990-95)        (1990-95)
                            (9/94-95)      (9/94-95)                                      V.P.            
                            & Asst. Sec.   & Asst. Sec.                                   (1985-95)   
                            (1982-95)      (1982-95)
                            Previously,    Previously,
                            V.P. - Fin.    V.P. - Fin.
                            (1990-9/94)    (1990-9/94)

Nancy H. Gormley(e)     63  V.P.           V.P. - Legal    V.P.                           Asst. Sec.
                            (1991-95)      & Regulatory    (1992-95)                      & Asst. Treas.
                                           (1990-95)                                      (1990-95)
</TABLE>



(a)  All officers and directors are elected annually.
(b)  Retired effective September 1, 1995.
(c)  Retired effective December 1, 1995.
(d)  Resigned effective December 1, 1995.
(e)  Retired effective January 1, 1996.
<PAGE>
<TABLE>
<CAPTION>
                                 45

                                                         Position (a) and Period of Service                                

<S>                     <C>      <C>           <C>               <C>            <C>         <C>             <C> 
Name                    Age      APS           APSC              MP             PE          WP              AGC

Thomas K. Henderson     55                 V.P. Legal      V.P.           V.P.            V.P. 
                                           (1996-  )       (1995-  )      (1995-  )       (1985-  )
                                           Previously,
                                           Asst. V.P.
                                           (9/95-12/95)

Kenneth M. Jones        58  V.P. &         V.P.                                                            Dir. & V.P.
                            Controller     (1991-  )                                                       (1991-  )
                            (1991-  )      Controller
                                           (1976-5/95)

Thomas J. Kloc          43                 Controller      Controller     Controller      Controller       Controller
                                           (5/95-   )      (1996-  )      (1988-  )       (12/95-  )       (1988-   )


James D. Latimer        57                                 V.P.           V.P.            V.P.
                                                           (12/95-  )     (12/95-  )      (12/95-  )
                                                                          Previously,
                                                                          Executive V.P.                   
                                                                          (6/94-12/95)
                                                                          V.P.
                                                                          (1988-6/94)

Kenneth D. Mowl         56                 Asst. Sec. &    Asst. Treas.                   Asst. Sec. &
                                            Asst. Treas.    (1996-  )                     Asst. Treas.
                                           (1996-  )                                      (1996-  )
                                                                                          Previously,
                                                                                          Sec. & Treas.
                                                                                          (1986-95)

Richard E. Myers(b)     59                                 Controller
                                                           (1980-95)

Alan J. Noia            48  Pres., COO     Pres., COO      Dir.           Dir.            Dir.             Dir. & V.P.
                            & Dir.         & Dir.          (9/94-  )      (1990-  )       (9/94-  )        (9/94-  )
                            (9/94-  )      (9/94-  )                      Previously,
                                                                          Pres.
                                                                          (1990-94)

Jay S. Pifer            58  Senior V.P.    Senior V.P.     Pres. & Dir.   Pres. & Dir.    Pres.
                            (1996-  )      (1995-  )       (1995-  )      (1995-  )       (1990-  )
                                                                                          & Dir.    
                                                                                          (1992-  )  

Richard A. Roschli      61                                                V.P.
                                                                          (6/94-  )
                                                                          Previously,
                                                                          Asst. V.P.
                                                                          (5/94-6/94);
                                                                          Div. Mgr.
                                                                          (1988-5/94)     

Peter J. Skrgic         54  Senior V.P.    Senior V.P.     Dir.           Dir. & V.P.     Dir.             Dir. & V.P.
                            (9/94-  )      (9/94-  )       (1990-   )     (1990-   )      (1990-   )       (1989-  )
                            Previously,    Previously,
                            V.P.           V.P.          
                            (1989-94)      (1989-94)

Robert R. Winter        52                                 V.P.           V.P.            V.P.
                                                           (1987-   )     (1995-  )       (9/95-  )
                                                                                                           
Dale F. Zimmerman(b)    62                                 Asst. Sec. &   Sec. & Treas.
                                                           Asst. Treas.   (1990 -1995)
                                                           (1995)
</TABLE>




(a)  All officers and directors are elected annually.
(b)  Retired effective January 1, 1996.
<PAGE>
                                   46

                                                  PART II 


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


          APS.

          AYP is the trading symbol of the common stock of APS 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, 1995,
there were 63,290 holders of record of APS' common stock.

          The tables below show the dividends paid and the high and low sale
prices of the common stock for the periods indicated:
<TABLE>
<CAPTION>
                                  1995                                              1994                   
               Dividend          High             Low             Dividend         High           Low
<S>            <C>               <C>              <C>             <C>              <C>            <C>
1st Quarter    41 cents          $24-3/8          $21-1/2         41 cents         $26-1/2        $22-3/8
2nd Quarter    41 cents          $25-1/8          $22-3/4         41 cents         $24            $20-1/8
3rd Quarter    41 cents          $26              $22-7/8         41 cents         $22-3/4        $19-3/4
4th Quarter    42 cents          $29-1/4          $25-1/2         41 cents         $22            $19-3/4
</TABLE>

        The high and low prices through February 1, 1996 were $30-1/2 and $28. 
The last reported sale on that date was at $30.
          
        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 APS.


        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>
                                  47

ITEM 6.    SELECTED FINANCIAL DATA

                                                                  Page No.
          
          APS                                                        48
          Monongahela                                                51
          Potomac Edison                                             53
          West Penn                                                  55
          AGC                                                        57
<PAGE>
<TABLE>
<CAPTION>
                                  48

APS
Consolidated Statistics
Year ended December 31
                              1995        1994       1993        1992       1991        1990        1985
Summary of Operations
(Millions of Dollars)
<S>                         <C>         <C>        <C>         <C>        <C>         <C>         <C>
Operating revenues          $2,647.8    $2,451.7   $2,331.5    $2,306.7   $2,282.2    $2,301.9    $1,833.4
Operation expense            1,373.8     1,284.9    1,208.4     1,252.0    1,252.2     1,338.6     1,049.0
Maintenance                    256.6       241.9      231.2       210.9      204.2       182.0       148.8
Depreciation                   256.3       223.9      210.4       197.8      189.7       180.9       125.0
Taxes other than income        184.8       183.1      178.8       174.6      167.5       152.5       105.9
Taxes on income                154.2       129.7      128.1       115.4      119.1       106.4       119.3
Allowance for funds used 
  during construction           (8.2)      (19.6)     (21.5)      (17.5)      (7.9)       (7.2)      (46.5)
Interest charges and 
  preferred dividends          196.8       184.2      180.3       171.3      165.0       161.1       159.5
Other income and 
  deductions                    (6.2)        3.8                   (1.3)      (1.6)       (3.8)       (6.0)
Consolidated income before  
  cumulative effect  
  of accounting change      $  239.7    $  219.8   $  215.8    $  203.5   $  194.0    $  191.4    $  178.4
Cumulative effect of 
  accounting change,
  net[a]                                    43.4
Consolidated
  net income                $  239.7    $  263.2   $  215.8    $  203.5   $  194.0    $  191.4    $  178.4
Common Stock Data[b] 
 Shares outstanding
 (Thousands)                 120,701     119,293    117,664     113,899    108,451     106,984     100,513
 Average shares
  outstanding
 (Thousands)                 119,864     118,272    114,937     111,226    107,548     106,102      99,437
Earnings per average share:
  Consolidated income 
    before cumulative 
    effect of accounting 
    change                     $2.00       $1.86      $1.88       $1.83      $1.80       $1.80       $1.79
Cumulative effect of 
  accounting change[a]                       .37
Consolidated net income        $2.00       $2.23      $1.88       $1.83      $1.80       $1.80       $1.79
Dividends paid per share       $1.65       $1.64      $1.63       $1.605     $1.585      $1.58       $1.35
Dividend payout ratio[c]       82.5%       88.3%      86.9%       88.3%      87.8%       87.6%       75.2%
Stockholders                  63,280      66,818     63,396      63,918     62,095      63,201      81,680
Market price range per share:
  High                        29 1/4      26 1/2    28 7/16      24 3/8     23 1/4     21 1/16     17 3/16
  Low                         21 1/2      19 3/4    23 7/16      20 3/4    17 7/16     17          14 1/16
Book value
  per share                   $17.65      $17.26     $16.62      $16.05     $15.54      $15.26      $12.87
Return on average 
  common equity[c]             11.35%      10.96%     11.40%      11.45%     11.59%      11.78%     14.10%
<PAGE>
                                 49
Capitalization Data
(Millions of Dollars)
  Common stock              $2,129.9    $2,059.3   $1,955.8    $1,827.8   $1,685.6    $1,632.3    $1,293.1
  Preferred stock:
    Not subject to 
      mandatory 
      redemption               170.1       300.1      250.1       250.1      235.1       235.1       240.1
Subject to 
  mandatory 
  redemption                                25.2        26.4       28.0        29.3       30.6        79.0
Long-term debt 
  and QUIDS                  2,273.2     2,178.5    2,008.1     1,951.6    1,747.6     1,642.2     1,600.7
Total capitalization        $4,573.2    $4,563.1   $4,240.4    $4,057.5   $3,697.6    $3,540.2    $3,212.9
Capitalization ratios:
  Common stock                  46.6%       45.1%      46.1%       45.0%      45.6%       46.1%       40.2%
  Preferred stock:
    Not subject to 
     mandatory
     redemption                  3.7         6.6        5.9         6.2        6.3         6.6         7.5
    Subject to 
     mandatory 
     redemption                               .6         .6          .7         .8          .9         2.5
    Long-term debt 
     and QUIDS                  49.7        47.7       47.4        48.1       47.3        46.4        49.8
Total Assets
(Millions of Dollars)       $6,447.3    $6,362.2   $5,949.2    $5,039.3   $4,855.0    $4,561.3    $4,059.3
Property Data 
(Millions of Dollars)
Gross property              $7,812.7    $7,586.8   $7,176.9    $6,679.9   $6,255.7    $5,986.2    $4,916.8
Accumulated 
  depreciation              (2,700.1)   (2,529.4)  (2,388.8)   (2,240.0)  (2,093.7)   (1,946.1)   (1,275.6)
Net property                $5,112.6    $5,057.4   $4,788.1    $4,439.9   $4,162.0    $4,040.1    $3,641.2
Gross additions 
  during year               $  319.1    $  508.3   $  574.0    $  487.6   $  337.7    $  321.8    $  520.4
Ratio of provisions 
  for depreciation to
  depreciable property         3.50%       3.32%      3.37%       3.31%      3.28%       3.27%       3.17%
Revenues 
(Millions of Dollars)
  Residential               $  927.0    $  863.7   $  818.4    $  734.9   $  708.3    $  649.5    $  513.3
  Commercial                   493.7       459.3      430.2       391.9      375.4       343.0       267.5
  Industrial                   770.2       728.0      673.4       637.7      600.2       571.5       504.9
  Nonaffiliated utilities      385.0       331.6      346.7       465.5      525.0       679.9       501.0
  Other                         71.9        69.1       62.8        76.7       73.3        58.0        46.7
  Total revenues            $2,647.8    $2,451.7   $2,331.5    $2,306.7   $2,282.2    $2,301.9    $1,833.4
<PAGE>
                                   50
Sales-GWh
  Residential                 13,003      12,630     12,514      11,746     11,755      11,264       9,309
  Commercial                   7,963       7,607      7,440       7,071      7,003       6,670       5,396
  Industrial                  18,457      17,708     16,967      16,910     16,430      16,511      14,927
  Nonaffiliated utilities     13,517       9,915     12,388      17,753     18,211      21,796      16,914
  Other                        1,304       1,275      1,240       1,186      1,146       1,101         964
    Total sales               54,244      49,135     50,549      54,666     54,545      57,342      47,510
Output-GWh 
  Steam generation            39,174      38,959     38,247      40,373     42,307      41,933      39,000
  Hydro and pumped-
    storage generation         1,234       1,390      1,233       1,204      1,654       1,426         214
  Pumped-storage 
    input                     (1,390)     (1,564)    (1,385)     (1,340)    (1,907)     (1,568)        (65)
  Purchased power and 
    exchanges, net            18,031      12,965     15,245      17,279     15,321      17,924      11,171
  Losses and system uses      (2,805)     (2,615)    (2,791)     (2,850)    (2,830)     (2,373)     (2,810)
    Total sales as above      54,244      49,135     50,549      54,666     54,545      57,342      47,510
Energy Supply
  Generating capability-MW
    System-owned               8,070       8,070      7,991       7,991      7,992       7,991       7,938
    Nonutility contracts[d]      299         299        292         212        162         160            
  Maximum hour peak-MW         7,280       7,153      6,678       6,530      6,238       6,070       6,035
  Load factor                  68.3%       66.8%      70.0%       69.3%      71.7%       71.3%       63.3%
  Heat rate-Btu's per kWh      9,970       9,927     10,020       9,910      9,956       9,944      10,016
  Fuel costs-cents 
    per million Btu's         130.20      141.50     142.12      141.93     143.19      140.97      154.21
Customers 
(Thousands)
  Residential               1,204.4     1,189.7    1,176.6     1,161.5    1,146.6     1,133.4     1,053.3
  Commercial                  146.0       143.0      140.1       137.4      134.7       132.2       115.9
  Industrial                   24.6        24.2       23.8        23.6       23.1        22.8        20.8
  Other                         1.3         1.3        1.2         1.2        1.3         1.3         1.1
    Total customers         1,376.3     1,358.2    1,341.7     1,323.7    1,305.7     1,289.7     1,191.1
Average Annual Use-kWh per customer
  Residential-APS            10,865      10,682     10,715      10,181     10,316      10,011       8,868
  Residential-National        9,451e      9,378e     9,394       8,949      9,280       9,056       8,487
  All retail service-APS     28,908      28,205     27,800      27,259     27,205      26,996      25,060
Average Rate-cents per kWh
  Residential-APS             7.13        6.84       6.54        6.26       6.03        5.77        5.51
  Residential-National        8.84e       8.83e      8.73        8.63       8.46        8.17        7.79
  All retail service-APS      5.58        5.43       5.23        4.96       4.80        4.56        4.36
</TABLE>

[a]  To record unbilled revenues, net of income taxes.
[b]  Reflects a two-for-one common stock split effective November 4, 1993.
[c]  Excludes the cumulative effect of the accounting change in 1994.
[d]  Capability available through contractual arrangements with nonutility
     generators.
[e]  Preliminary.
<PAGE>
<TABLE>
<CAPTION>
                                  51

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

                                            1995        1994        1993        1992        1991        1990
Electric operating revenues:
  <S>                                     <C>         <C>         <C>         <C>         <C>         <C>
  Residential..........................   $209,065    $190,861    $185,141    $169,589    $163,757    $151,658
  Commercial...........................    124,457     116,201     110,762     102,709      97,849      90,095
  Industrial...........................    212,427     202,181     187,669     186,442     177,688     169,654
  Nonaffiliated utilities..............     90,916      79,701      86,032     119,628     140,029     177,573
  Other, including affiliates..........     85,617      91,186      72,240      53,595      45,803      41,348
    Total..............................    722,482     680,130     641,844     631,963     625,126     630,328

Operation expense......................    413,858     394,438     364,027     372,002     364,968     379,663
Maintenance............................     74,418      69,389      67,770      62,909      64,035      57,768
Depreciation...........................     57,864      57,952      56,056      53,865      51,903      50,433
Taxes other than income................     38,551      40,404      34,076      33,207      35,378      34,310
Taxes on income........................     41,834      30,712      33,612      27,919      31,173      31,005
Allowance for funds used
  during construction..................     (1,393)     (2,946)     (5,780)     (3,908)     (1,341)     (1,559)
Interest charges.......................     39,872      38,156      37,588      36,013      33,494      33,264
Other income, net......................     (9,235)     (7,911)     (7,203)     (8,388)     (8,573)     (9,505)

Income before cumulative effect
  of accounting change.................     66,713      59,936      61,698      58,344      54,089      54,949
Cumulative effect of accounting
  change, net (a)......................                  7,945                                                
Net income.............................   $ 66,713    $ 67,881    $ 61,698    $ 58,344    $ 54,089    $ 54,949

Return on average common equity (b)....      11.92%      10.66%      11.83%      11.96%      11.43%      11.84%
</TABLE>

(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
<PAGE>
<TABLE>
<CAPTION>
                                  52
Monongahela

FINANCIAL AND OPERATING STATISTICS
Year ended December 31

                                             1995         1994         1993         1992         1991         1990

PROPERTY, PLANT, AND EQUIPMENT
  (Thousands of Dollars):
    <S>                                   <C>          <C>          <C>          <C>          <C>          <C>
    Gross..............................   $1,821,613   $1,763,533   $1,684,322   $1,567,252   $1,458,643   $1,389,906
    Accumulated depreciation...........     (747,013)    (701,271)    (664,947)    (628,595)    (590,311)    (550,104)
      Net..............................   $1,074,600   $1,062,262   $1,019,375   $  938,657   $  868,332   $  839,802

GROSS ADDITIONS TO PROPERTY      
  (Thousands of Dollars)...............   $   75,458   $  103,975   $  140,748   $  126,422   $   84,515   $   74,575

TOTAL ASSETS (Thousands of Dollars).      $1,480,591   $1,476,483   $1,407,453   $1,166,410   $1,091,287   $1,054,497

CAPITALIZATION:
  Amount (Thousands of Dollars):
    Common stock.......................   $  505,752   $  495,693   $  483,030   $  475,628   $  428,855   $  425,016
    Preferred stock....................       74,000      114,000       64,000       64,000       69,000       69,000
    Long-term debt and QUIDS...........      489,995      470,131      460,129      444,506      372,618      367,871
      Total                               $1,069,747   $1,079,824   $1,007,159   $  984,134   $  870,473   $  861,887

  Ratios:
    Common stock.......................         47.3%        45.9%        48.0%        48.3%        49.3%        49.3%
    Preferred stock....................          6.9         10.6          6.3          6.5          7.9          8.0
    Long-term debt and QUIDS...........         45.8         43.5         45.7         45.2         42.8         42.7
      Total                                    100.0%       100.0%       100.0%       100.0%       100.0%       100.0%
GENERATING CAPABILITY-- kW
    Company-owned......................    2,326,300    2,326,300    2,325,300    2,325,300    2,325,300    2,325,300
    Nonutility contracts*..............      161,000      161,000      159,000       79,000       29,000       27,000
KILOWATT-HOURS IN THOUSANDS: 
  Sales:
    Residential........................    2,807,135    2,674,664    2,689,830    2,527,247    2,581,628    2,430,539
    Commercial.........................    1,967,473    1,846,791    1,825,127    1,742,469    1,744,881    1,656,961
    Industrial.........................    5,114,126    4,942,388    4,656,921    4,872,126    4,905,715    4,868,551
    Nonaffiliated utilities............    3,182,827    2,383,531    3,082,715    4,578,187    4,877,930    5,634,908
    Other, including affiliates........    1,734,537    1,925,450    1,565,561      824,393      584,677      590,920
      Total sales......................   14,806,098   13,772,824   13,820,154   14,544,422   14,694,831   15,181,879
  Output:
    Steam generation...................   10,620,003   10,743,934   10,194,794   10,593,059   11,512,714   11,247,964
    Pumped-storage generation..........      257,284      290,586      263,329      260,155      375,500      306,470
    Pumped-storage input...............     (330,915)    (373,116)    (337,737)    (332,989)    (475,898)    (389,467)
    Purchased power and exchanges, net.    4,981,345    3,784,421    4,381,916    4,705,418    3,969,954    4,618,564
    Losses and system uses.............     (721,619)    (673,001)    (682,148)    (681,221)    (687,439)    (601,652)
      Total sales as above.............   14,806,098   13,772,824   13,820,154   14,544,422   14,694,831   15,181,879

CUSTOMERS:
  Residential..........................      303,568      300,465      297,865      294,595      291,578      288,990
  Commercial...........................       35,793       35,268       34,626       34,005       33,484       33,107
  Industrial...........................        8,085        8,029        8,014        8,005        7,994        7,946
  Other................................          170          171          170          172          172          170
    Total customers....................      347,616      343,933      340,675      336,777      333,228      330,213
                                                           
RESIDENTIAL SERVICE:
  Average use-
    kWh per customer...................        9,306        8,957        9,093        8,636        8,905        8,457
  Average revenue-
    dollars per customer...............       693.11       639.16       625.87       579.51       564.87       527.70
  Average rate-
    cents per kWh......................         7.45         7.14         6.88         6.71         6.34         6.24
</TABLE>

*Capability available through contractual arrangements with nonutility
 generators.
<PAGE>
<TABLE>
<CAPTION>
                                  53

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

                                            1995        1994        1993        1992        1991        1990
Electric operating revenues:
  <S>                                     <C>         <C>         <C>         <C>         <C>         <C>
  Residential..........................   $316,714    $296,090    $274,358    $243,413    $227,851    $213,165          
  Commercial...........................    145,096     135,937     124,667     111,506     104,642      97,902
  Industrial...........................    200,890     195,089     175,902     157,304     147,654     148,632
  Nonaffiliated utilities..............    125,890     107,027     108,132     141,120     161,720     210,710
  Other, including affiliates..........     30,429      25,222      29,526      34,544      32,210      27,135
    Total..............................    819,019     759,365     712,585     687,887     674,077     697,544

Operation expense......................    487,833     448,527     413,145     414,939     423,489     460,546
Maintenance............................     62,147      58,624      64,376      53,141      49,766      45,035
Depreciation...........................     68,826      59,989      56,449      53,446      50,578      47,547
Taxes other than income................     47,629      46,740      46,813      45,791      43,937      38,527
Taxes on income........................     36,936      33,163      30,086      28,422      24,194      25,132
Allowance for funds used
  during construction..................     (1,752)     (5,874)     (7,134)     (5,368)     (3,366)     (2,908)
Interest charges.......................     51,179      46,456      43,802      39,392      36,831      33,049
Other income, net......................    (12,044)    (10,243)     (8,419)     (9,352)     (9,593)    (10,964)

Income before cumulative effect
  of accounting change.................     78,265      81,983      73,467      67,476      58,241      61,580
Cumulative effect of accounting
  change, net (a)......................                 16,471                                                
Net income.............................   $ 78,265    $ 98,454    $ 73,467    $ 67,476    $ 58,241    $ 61,580

Return on average common equity (b)....      11.34%      11.86%      11.63%      11.85%      11.04%      12.31%
</TABLE>

(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
<PAGE>
<TABLE>
<CAPTION>
                                  54 
Potomac Edison

FINANCIAL AND OPERATING STATISTICS
Year Ended December 31


                                             1995         1994          1993         1992         1991       1990

PROPERTY, PLANT, AND EQUIPMENT
  (Thousands of Dollars)
    <S>                                      <C>          <C>          <C>          <C>          <C>        <C>
    Gross..................................  $2,050,835   $1,978,396   $1,857,961   $1,698,711   $1,557,695 $1,454,250  
   Accumulated depreciation...............     (729,653)    (673,853)    (632,269)    (591,378)    (546,867)  (504,168)
      Net..................................  $1,321,182   $1,304,543   $1,225,692   $1,107,333   $1,010,828 $  950,082

GROSS ADDITIONS TO PROPERTY      
  (Thousands of Dollars)...................  $   92,240   $  142,826   $  179,433   $  153,485   $  116,589 $  116,627
TOTAL ASSETS (Thousands of Dollars)........  $1,654,444   $1,629,535   $1,519,763   $1,355,385   $1,256,712 $1,140,623

CAPITALIZATION:
  Amount (Thousands of Dollars):
    Common stock...........................  $  667,242   $  658,146   $  626,467   $  567,826   $  480,931 $  453,761
    Preferred stock:               
      Not subject to mandatory redemption..      16,378       36,378       36,378       36,378       56,378     56,378
      Subject to mandatory redemption......                   25,200       26,400       28,005       29,280     30,555
    Long-term debt and QUIDS...............     628,854      604,749      517,910      511,801      453,584    399,518
      Total                                  $1,312,474   $1,324,473   $1,207,155   $1,144,010   $1,020,173 $  940,212

  Ratios:
    Common stock...........................        50.8%        49.7%        51.9%        49.6%        47.1%      48.3%
    Preferred stock:               
      Not subject to mandatory redemption..         1.3          2.7          3.0          3.2          5.5        6.0
      Subject to mandatory redemption......                      1.9          2.2          2.5          2.9        3.2
    Long-term debt and QUIDS...............        47.9         45.7         42.9         44.7         44.5       42.5
      Total                                       100.0%       100.0%       100.0%       100.0%       100.0%     100.0%

GENERATING CAPABILITY--kW                      2,072,292    2,072,292    2,076,592    2,076,592    2,077,192  2,076,292
            
KILOWATT-HOURS (Thousands)
  Sales:
    Residential............................   4,377,416    4,214,997    4,144,958    3,822,387    3,753,884  3,561,824
    Commercial.............................   2,213,052    2,136,081    2,091,930    1,954,025    1,912,848  1,818,789
    Industrial.............................   5,485,220    5,339,737    5,194,909    4,979,219    4,881,835  4,928,433
    Nonaffiliated utilities................   4,420,313    3,194,580    3,860,791    5,394,006    5,649,050  6,818,528
    Other, including affiliates............     656,539      653,614      649,636      616,711      615,604    593,548
      Total sales..........................  17,152,540   15,539,009   15,942,224   16,766,348   16,813,221 17,721,122
  Output:
    Steam generation.......................  10,410,118   10,464,607   10,103,411   10,713,987   11,192,300 11,094,016
    Hydro and pumped-storage generation....     395,315      426,550      368,834      351,035      502,302    430,500
    Pumped-storage input...................    (452,151)    (506,213)    (433,885)    (407,393)    (593,879)  (489,243)
    Purchased power and exchanges, net.....   7,565,505    5,896,492    6,691,792    6,937,037    6,517,575  7,387,314
    Losses and system uses.................    (766,247)    (742,427)    (787,928)    (828,318)    (805,077)  (701,465)
      Total sales as above.................  17,152,540   15,539,009   15,942,224   16,766,348   16,813,221 17,721,122

CUSTOMERS
  Residential..............................     321,813      315,309      309,096      302,559      295,564    289,695
  Commercial...............................      41,759       40,927       40,173       39,236       38,522     37,708
  Industrial...............................       4,733        4,595        4,509        4,435        4,283      4,132
  Other....................................         543          524          510          510          501        471
    Total customers........................     368,848      361,355      354,288      346,740      338,870    332,006

RESIDENTIAL SERVICE:
  Average use-
    kWh per customer.......................      13,729       13,506       13,562       12,766       12,822     12,463
  Average revenue-
    dollars per customer...................      993.35       948.76       897.70       812.96       778.25     745.90
  Average rate-
    cents per kWh..........................        7.24         7.02         6.62         6.37         6.07       5.98
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                    55

West Penn
SUMMARY OF OPERATIONS            
Year Ended December 31
(Thousands of Dollars)

                                                1995         1994         1993         1992         1991         1990
Electric operating revenues:

  <S>                                        <C>          <C>          <C>          <C>          <C>          <C>
  Residential..........................      $  401,186   $  376,776   $  358,900   $  321,871   $  316,685   $  284,691    
  Commercial...........................         224,144      207,165      194,773      177,697      172,924      154,999
  Industrial...........................         356,937      330,739      309,847      293,910      274,896      253,184
  Nonaffiliated utilities..............         168,215      144,829      152,541      204,743      223,225      291,636
  Other, including affiliates..........          75,859       68,733       68,916       78,620       83,073       74,342
    Total..............................       1,226,341    1,128,242    1,084,977    1,076,841    1,070,803    1,058,852

Operation expense......................         675,953      647,963      625,269      647,989      649,422      684,508
Maintenance............................         118,162      111,841       96,706       93,067       87,717       77,516
Depreciation...........................         112,334       88,935       80,872       73,469       70,334       66,122
Taxes other than income................          89,694       87,224       89,249       87,300       80,630       72,114
Taxes on income........................          61,745       50,385       51,529       44,078       47,846       33,867
Allowance for funds used
  during construction..................          (5,041)     (10,777)      (8,566)      (8,276)      (3,224)      (2,729)
Interest charges.......................          67,902       60,274       60,585       55,592       51,977       49,268
Asset write-off, net...................                        5,179
Other income, net......................         (12,287)     (13,797)     (12,728)     (14,534)     (15,077)     (15,067)

Consolidated income before cumulative 
  effect of accounting change..........         117,879      101,015      102,061       98,156      101,178       93,253
Cumulative effect of accounting
  change, net (a)......................                       19,031                                                    
Consolidated net income................      $  117,879   $  120,046   $  102,061   $   98,156   $  101,178   $   93,253

Return on average common equity (b)....           11.46%        9.94%       11.49%       11.53%       12.66%       12.07%
</TABLE>

(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
<PAGE>
<TABLE>
<CAPTION>
                                 56

West Penn 

FINANCIAL AND OPERATING STATISTICS
Year Ended December 31
                                      
                                                1995         1994         1993         1992         1991         1990

PROPERTY, PLANT, AND EQUIPMENT
    (Thousands of Dollars)
    <S>                                      <C>          <C>          <C>          <C>          <C>          <C>
    Gross..................................  $3,097,522   $3,013,777   $2,803,811   $2,581,641   $2,409,005   $2,312,425    
    Accumulated depreciation...............  (1,063,399)  (1,009,565)    (962,623)    (904,906)    (857,999)    (809,674)
      Net..................................  $2,034,123   $2,004,212   $1,841,188   $1,676,735   $1,551,006   $1,502,751

GROSS ADDITIONS TO PROPERTY      
  (Thousands of Dollars)...................  $  149,122   $  260,366   $  251,017   $  204,409   $  134,443   $  128,762
TOTAL ASSETS (Thousands of Dollars)........  $2,771,164   $2,731,858   $2,544,763   $2,083,127   $2,006,309   $1,842,766

CAPITALIZATION:
  Amount (Thousands of Dollars)
    Common stock...........................  $  973,188   $  955,482   $  893,969   $  782,341   $  774,707   $  723,567
    Preferred stock........................      79,708      149,708      149,708      149,708      109,708      109,708
    Long-term debt and QUIDS...............     904,669      836,426      782,369      759,005      621,906      563,378
      Total                                  $1,957,565   $1,941,616   $1,826,046   $1,691,054   $1,506,321   $1,396,653

  Ratios:
    Common stock...........................        49.7%        49.2%        49.0%        46.3%        51.4%        51.8%
    Preferred stock........................         4.1          7.7          8.2          8.8          7.3          7.9
    Long-term debt and QUIDS...............        46.2         43.1         42.8         44.9         41.3         40.3
      Total                                       100.0%       100.0%       100.0%       100.0%       100.0%       100.0%

GENERATING CAPABILITY-- kW:
    Company-owned..........................   3,671,408    3,671,408    3,589,408    3,589,408    3,589,408    3,589,408
    Nonutility contracts (*)...............     138,000      138,000      133,000      133,000      133,000      133,000

KILOWATT-HOURS (THOUSANDS): 
  Sales:
    Residential............................   5,818,838    5,740,028    5,679,746    5,396,533    5,419,150    5,271,390
    Commercial.............................   3,782,250    3,624,117    3,522,566    3,374,355    3,345,255    3,194,141
    Industrial.............................   7,857,689    7,426,267    7,114,765    7,058,895    6,643,238    6,713,824
    Nonaffiliated utilities................   5,913,320    4,337,106    5,444,798    7,780,654    7,683,817    9,342,543
    Other, including affiliates............   1,621,745    1,530,853    1,821,189    2,247,844    2,485,366    2,426,414
      Total sales..........................  24,993,842   22,658,371   23,583,064   25,858,281   25,576,826   26,948,312
  Output:
    Steam generation.......................  18,143,822   17,750,267   17,949,335   19,066,445   19,602,129   19,590,731
    Hydro and pumped-storage generation....     581,353      673,195      600,497      592,895      775,798      688,517
    Pumped-storage input...................    (606,953)    (684,715)    (613,290)    (599,729)    (836,700)    (689,186)
    Purchased power and exchanges, net.....   8,192,623    6,119,757    6,967,752    8,139,496    7,373,185    8,428,158
    Losses and system uses.................  (1,317,003)  (1,200,133)  (1,321,230)  (1,340,826)  (1,337,586)  (1,069,908)
      Total sales as above.................  24,993,842   22,658,371   23,583,064   25,858,281   25,576,826   26,948,312

CUSTOMERS:
  Residential..............................     578,983      573,963      569,601      564,300      559,444      554,716
  Commercial...............................      68,500       66,842       65,337       64,212       62,674       61,396
  Industrial...............................      11,801       11,563       11,218       11,138       10,826       10,687
  Other....................................         598          586          576          569          692          680
    Total customers........................     659,882      652,954      646,732      640,219      633,636      627,479

RESIDENTIAL SERVICE:
  Average use-
    kWh per customer.......................      10,096       10,041       10,025        9,608        9,733        9,550
  Average revenue-
    dollars per customer...................      696.06       659.07       633.48       573.07       568.76       515.75
  Average rate-
    cents per kWh..........................        6.89         6.56         6.32         5.96         5.84         5.40
</TABLE>

(*) Capability available through contractual arrangements with nonutility 
    generators.
<PAGE>
<TABLE>
<CAPTION>
                                  57
AGC
STATISTICS
Year Ended December 31
SUMMARY OF OPERATIONS            
(Thousands of Dollars)

                                            1995        1994        1993        1992        1991    1990

<S>                                       <C>         <C>         <C>         <C>         <C>         <C>
Electric operating revenues............   $ 86,970    $ 91,022    $ 90,606    $ 96,147    $100,505    $104,482

Operation and maintenance expense......      5,740       6,695       6,609       6,094       6,774       5,974  
Depreciation...........................     17,018      16,852      16,899      16,827      16,778      16,756
Taxes other than income taxes..........      5,091       5,223       5,347       5,236       4,563       4,712
Federal income taxes...................     13,552      14,737      13,262      14,702      15,455      16,458
Interest charges.......................     18,361      17,809      21,635      22,585      24,030      26,883
Other income, net......................        (16)        (11)       (328)        (21)        (24)        (17)
  Net Income...........................   $ 27,224    $ 29,717    $ 27,182    $ 30,724    $ 32,929    $ 33,716

Return on average common equity........      12.46%      13.14%      11.72%      12.79%      13.09%      12.78%

PROPERTY, PLANT, AND EQUIPMENT
  (Thousands of Dollars):
    Gross..............................   $836,894*   $824,714    $824,904    $825,493    $822,332    $821,424
    Accumulated depreciation...........   (159,037)   (143,965)   (128,375)   (114,684)    (97,915)    (81,514)
      Net..............................   $677,857    $680,749    $696,529    $710,809    $724,417    $739,910

GROSS ADDITIONS TO PROPERTY      
  (Thousands of Dollars)...............   $ 14,165*   $  1,065    $  2,729    $  3,251    $  1,391    $  1,214

TOTAL ASSETS (Thousands of Dollars)....   $710,287    $714,236    $735,929    $727,820    $742,223    $757,084

CAPITALIZATION at Dec. 31:
  Amount (Thousands of Dollars):
    Common stock.......................   $214,153    $222,729    $228,512    $235,530    $244,593    $254,664
    Long-term debt.....................    249,709     267,165     277,196     287,139     299,502     311,461
      Total                               $463,862    $489,894    $505,708    $522,669    $544,095    $566,125

  Ratios:
    Common stock.......................       46.2%       45.5%       45.2%       45.1%       45.0%       45.0%
    Long-term debt.....................       53.8        54.5        54.8        54.9        55.0        55.0
      Total                                  100.0%      100.0%      100.0%      100.0%      100.0%      100.0%
        
KILOWATT-HOURS (THOUSANDS):
  Pumping energy supplied by parents...  1,390,019   1,564,044   1,384,912   1,340,111   1,906,477   1,567,896
  Pumped-storage generation............  1,081,112   1,218,446   1,079,985   1,047,015   1,504,310   1,233,782
</TABLE>

*Reflects a balance sheet reclassification of $12 million from deferred 
 charges to plant for a prior tax payment.
<PAGE>
                                 58

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


                                                  Page No.
                              
            APS                                      59 
            Monongahela                              68
            Potomac Edison                           77
            West Penn                                87
            AGC                                      95
<PAGE>
                                 59

APS
Management Discussion & Analysis of Financial Condition 
and Results of Operations
Review of Utility Operations
Earnings

  Earnings in 1995 increased to $240 million ($2.00 per share) compared with
$220 million ($1.86 per share) in 1994, excluding in 1994 the cumulative
effect of an accounting change to record unbilled revenues. The increase
resulted primarily from additional retail revenues due to increased kilowatt--
hour (kWh) sales and previously reported rate increases. These revenue
increases were offset in part by restructuring charges and inventory write-offs
in 1995 of $14.1 million after tax ($.12 per share) and higher expenses.
Earnings in 1994 included a charge of $5.3 million after tax ($.05 per share)
related to asset write-offs. Consolidated net income in 1993 was $216 million
($1.88 per share). Consolidated net income in 1994 also reflects higher retail
revenues from increased kWh sales and rate increases, offset in part by higher
expenses.

  Restructuring activities in 1995 were initiated by the System in response to
the competitive environment emerging in the electric utility industry. The
subsidiaries are restructuring many of their functions to strengthen their
competitive position and improve their cost structure. During 1995, reenginee-
ring of the Bulk Power Supply department was substantially completed and
process redesign is expected to be substantially completed in 1996 for the
remainder of the System. Downsizing was not a specific goal of the restructur-
ing efforts but, as a consequence of process redesign and elimination of
duplicate positions, approximately 200 employees have been placed in a
staffing force pending reassignment or layoff. In addition, about 130 fewer
employees will be required in the power station work force by the end of 1997,
and employee reductions are also likely to result from reengineering in other
areas. The charges recorded in 1995 in connection with restructuring activi-
ties reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs. These costs will be recovered
through future cost savings. 

Sales and Revenues

  KWh sales to and revenues from residential, commercial, and industrial
customers are shown on page 50. Such kWh sales increased 3.9% and 2.8% in 1995
and 1994, respectively. The increases in revenues from sales to residential,
commercial, and industrial customers resulted from the following:
  
                              Changes from Prior Year

(Millions of Dollars)                1995        1994
Increased kWh sales                $ 56.2      $ 23.6
Rate changes:
  Pennsylvania                       50.2        22.7
  Maryland                           17.7        11.9
  West Virginia                      19.3         9.7
  Virginia                           (1.8)        8.5
  Ohio                                 .5
                                     85.9        52.8
Fuel and energy cost                     
adjustment clauses*                  (2.8)       48.3
Other                                  .6         4.3
                                   $139.9      $129.0

*  Changes in revenues from fuel and energy cost adjustment clauses have little
effect on consolidated net income.  
<PAGE>
                                  60

   The increase in kWh sales in 1995 was largely attributable to industrial and
commercial sales. Industrial sales increased 4.2% and 4.4% in 1995 and 1994,
respectively. The 4.7% increase in commercial sales in 1995 and the 2.2%
increase in 1994 reflect growth in the number of customers and in 1995 also
reflects increased customer usage. These increases continue to reflect a trend
of economic growth in the service territory. In 1995 the subsidiaries
implemented a new Major Accounts Program which focuses on enhancing the
working relationships with the System's largest customers. The goal of the
program is to assure, through superior service, that Allegheny Power remains
the energy supplier for these major customers. 

   Residential kWh sales increased 3% in 1995 and .9% in 1994. The rate of
growth in the number of residential customers has remained constant at 1.2%
annually in 1995, 1994, and 1993. However, the impact of weather on customer
usage continues to produce fluctuations in residential sales. In 1995,
decreased sales due to mild weather in the first and second quarters were more
than offset by extremely hot summer weather and cooler than normal winter
weather in November and December as compared to 1994. The 1994 residential use
was down slightly from 1993 levels reflecting a decrease in both heating and
cooling degree days.

   Rate case decisions in all jurisdictions, representing revenue increases in
excess of $125 million on an annual basis, have been obtained, most of them
effective in late 1994. These included recovery of the remaining carrying
charges on investment, depreciation, and all operating costs required to
comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other
increasing levels of expenses. Additional base rate increases are not expected
to be necessary for the next several years. However, future purchased power
expenses related to a qualified facility under the Public Utility Regulatory
Policies Act of 1978 (PURPA), to be completed in late 1999, may make it
necessary to increase rates at that time. 

   KWh sales to and revenues from nonaffiliated utilities are comprised of the
following items:
<TABLE>
<CAPTION>
                                                             1995             1994             1993
KWh sales (Billions):
 <S>                                                       <C>              <C>              <C>
  From subsidiaries' generation                                .5              1.1              1.2
  From purchased power                                       13.0              8.8             11.2
                                                             13.5              9.9             12.4
Revenues (Millions):
  From subsidiaries' generation                            $ 13.0           $ 29.0           $ 28.5
  From sales of purchased power                             372.0            302.6            318.2
                                                           $385.0           $331.6           $346.7
</TABLE>

  Sales from subsidiaries' generation in 1995 decreased because of growth in
kWh sales to retail customers, which reduced the amount available for sale,
and because of continuing price competition. The generation tax imposed in
West Virginia, which in prior years was a significant factor affecting the
subsidiaries' ability to compete in the market for sales to nonaffiliated
utilities, was favorably amended effective in June 1995 to change the basis of
the tax from generation to generating capacity. Sales of purchased power vary
depending on the availability of other utilities' generating equipment, demand
for energy, and price competition. In the future, some of these transactions
may be made under new transmission tariffs described below. About 95% of the
aggregate benefits from sales to nonaffiliated utilities are passed on to
retail customers and have little effect on consolidated net income. 
<PAGE>
                                  61

  The increase in other revenues in 1995 and 1994 resulted primarily from
increased revenues from wholesale customers (cooperatives and municipalities
who own their own distribution systems and who buy all or part of their bulk
power needs from the subsidiaries under regulation by the Federal Energy
Regulatory Commission). Under the National Energy Policy Act of 1992, these
customers obtained the ability to choose the bulk power supplier of their
choice by the requirement that transmission-owning utilities must provide
transmission service. In 1995, rate cases for wholesale customers were
completed with the result that such customers, with revenues representing
about 97% of the $46 million in annual wholesale revenues, agreed to negotiat-
ed rate increases and signed contracts to remain as System customers for
periods ranging from three to seven years. One customer representing the
remaining 3% of annual revenues selected an 18-month contract at higher rates.
In the event that this customer selects another supplier, the subsidiaries
would retain transmission revenues with the result that any reduction in
consolidated net income would not be significant. 

  Other revenues in 1995 also reflect an increase in standard transmission
service revenues. See page 66 under Competition in Core Business for informa-
tion about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the Federal
Energy Regulatory Commission (FERC) in 1995. Effective in 1996, pursuant to
the intentions of the Mega-NOPR, the subsidiaries eliminated their Standard
Transmission Service tariff for new service transactions, and began using two
new transmission service tariffs which qualify as required open access tariffs
- a Network tariff and a Point-to-Point tariff. The FERC accepted the filing
of the new tariffs subject to hearings in the summer of 1996 and modification
pending final Mega-NOPR rules. The subsidiaries are using the new tariffs in
the interim, subject to refund. In addition, the subsidiaries have a Standard
Generation Service tariff accepted by the FERC under which the subsidiaries
make available bundled, nonfirm generation services with associated transmis-
sion services. Substantially all of the benefits of these sales of transmis-
sion and generation services to customers outside the service territory are
passed through to retail customers and, as a result, have little effect on
consolidated net income. While this procedure will continue to apply to
similar sales under the new tariffs, the subsidiaries may petition to revise
the procedure in the future.

Operating Expenses

  The 7% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers. Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the consolidated financial statements, with the result that
changes in fuel expenses have little effect on consolidated net income.

 "Purchased power and exchanges, net" represents power purchases from and
exchanges with other utilities and purchases from qualified facilities under
PURPA, and is comprised of the following items:
<TABLE>
<CAPTION>

(Millions of Dollars)                                          1995            1994            1993
Purchased power:
  <S>                                                        <C>             <C>             <C>
  For resale to other utilities                              $332.9          $267.1          $280.9
  From PURPA generation                                       129.3           134.0           105.2
  Other                                                        48.8            40.4            33.8
      Total power purchased                                   511.0           441.5           419.9
Power exchanges, net                                            (.3)           ( .6)           (2.5) 
                                                             $510.7          $440.9          $417.4
</TABLE>

  The amount of power purchased from other utilities for use by subsidiaries
and for resale to other utilities depends upon the availability of subsidiar-
ies' generating equipment, transmission capacity, and fuel, and their cost of
<PAGE>
                                 62

generation and the cost of operations of other utilities from which such
purchases are made. The primary reason for the fluctuations in purchases for
resale to other utilities is described under Sales and Revenues above. The
decrease in purchases from PURPA generation in 1995 was due primarily to a
contractual reduction in the energy rate effective in June 1995 for the Grant
Town PURPA project. American Bituminous Power Partners, L.P., the developer of
the Grant Town project, has filed an emergency petition with the Public
Service Commission of West Virginia for interim relief to have its former
energy rate reinstated. Monongahela Power has filed objections to this
petition. The increase in purchases from PURPA generation in 1994 reflects
generation from the Grant Town PURPA project beginning in late 1993. As
reported under Sales and Revenues, an agreement has been reached with a
proposed facility to commence purchasing generation in 1999. This project and
others may significantly increase the costs of power purchases passed on to
customers. None of the subsidiaries' purchased power contracts is capitalized
since there are no minimum payment requirements absent associated kWh
generation. Other purchased power continued to increase in 1995 because of
increased sales to retail customers and the availability of more economic
energy. The cost of power purchased for use by the subsidiaries, including
power from PURPA generation, is mostly recovered from customers currently
through the regular fuel and energy cost recovery procedures followed by the
subsidiaries' regulatory commissions, and is primarily subject to deferred
power cost procedures with the result that changes in such costs have little
effect on consolidated net income.

  In January 1996, West Penn and the developers of a proposed Shannopin PURPA
project reached agreement to terminate the project and all pending litigation,
at a buy out price of $31 million. The agreement is subject to Pennsylvania
Public Utility Commission (PUC) approval of recovery of the buy out price by
West Penn by no later than March 31, 1999. The agreement was filed with the
PUC in February 1996 along with a request for expedited approval.

  The increase in other operation expense in 1995 resulted primarily from
restructuring charges which are described in Note B to the consolidated
financial statements on page 112. Additional restructuring charges will be
incurred in 1996 as the subsidiaries complete their reengineering process.
Other operation expense in 1996 and thereafter is expected to reflect the
benefits of savings related to the restructuring activities. The 1994 increase
in other operation expense resulted primarily from a decision to increase the
allowances for uncollectible accounts ($9 million), increases in salaries and
wages ($5 million) and employee benefit costs, primarily pension expense ($6
million) and other postretirement benefits ($3 million), and provisions for
environmental liabilities ($3 million). Allowances for uncollectible accounts
were increased in 1994 due to an increase in aged outstanding receivables
caused primarily by Pennsylvania rate regulations which make it difficult if
not impossible to curtail service to non-paying customers. It is expected that
the allowance for these uncollectible accounts will be increased in the future
because of increasing accounts receivables in arrears. The increase in pension
expense occurred because the subsidiaries in 1994 discontinued the practice of
deferring pension expense in Pennsylvania and West Virginia to reflect rate
case decisions in those states. Pension expense in 1994 also includes a charge
of $3.1 million for write-off of prior deferrals in West Virginia because
recovery of those deferrals was denied.

  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. The
subsidiaries are also experiencing, and expect to continue to experience,
increased expenditures due to the aging of their power stations. 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. Maintenance expense in 1995
includes a charge of about $7 million for inventory write-offs described in
<PAGE>
                                  63 

Note B to the consolidated financial statements on page 112 and $3 million due
to maintenance expense for the Harrison scrubbers which went into service in
late 1994. Maintenance expense for the scrubbers is expected to increase since
the warranty period has expired. 

  Depreciation expense increases resulted primarily from additions to electric
plant. The subsidiaries began depreciating the Harrison scrubbers in mid-Nove-
mber 1994, amounting to $32 million annually. Future depreciation expense
increases for utility operations are expected to be less than historical
increases because of reduced levels of proposed capital expenditures.
 
  The increase in taxes other than income in 1995 and 1994 was due primarily
to increases in gross receipts taxes resulting from higher revenues from
retail customers. In 1995 this increase was offset in part by a decrease in
West Virginia Business and Occupation (B&O) taxes resulting from an amendment
in the B&O tax law effective June 1995, which changed the basis for this tax
from generation to generating capacity. 

  The net increase of $24 million in federal and state income taxes in 1995
resulted primarily from an increase in income before taxes ($16 million) and
an increase in reversals of prior year depreciation benefits for which
deferred taxes were not then provided ($6 million). The net increase in 1994
of $2 million resulted primarily from an increase in income before taxes. Note
C to the consolidated financial statements provides a further analysis of
income tax expenses.

  The combined decreases in allowances for funds used during construction in
1995 and 1994 of $11 million and $2 million, respectively, reflect decreases
in construction expenditures upon substantial completion of the compliance
program for Phase I of the CAAA. The increase in other income, net, of $5
million in 1995 was due primarily to income from demand-side management
programs. During 1995, Potomac Edison continued its participation in the
collaborative process for demand-side management in Maryland. Program costs,
including lost revenues and rebates, are deferred as a regulatory asset and
are being recovered through an energy conservation surcharge over a seven-year
period. The balance in the regulatory asset for this program is $16 million as
of December 31, 1995. Other income, net, in 1994 reflects the write-off of
$5.3 million net of income taxes of previously accumulated costs related to
future facilities which are no longer considered meaningful in the industry's
more competitive environment.

  In 1995 interest on long-term debt increased $14 million due primarily to
the new security issues in 1994 and the timing of the refinancing of $245
million of first mortgage bonds and $93 million of pollution control revenue
notes in 1995. Dividends on preferred stock decreased $5 million in 1995 due
primarily to the redemption of preferred stock issues refinanced with $155.5
million of Quarterly Income Debt Securities. Other interest expense reflects
changes in the levels of short-term debt maintained by the companies through-
out the year, as well as the associated interest rates.

Environmental and Other Issues

  In the normal course of business, the subsidiaries are subject to various
contingencies and uncertainties relating to their operations and construction
programs, including cost recovery in the regulatory process, laws, regulations
and uncertainties related to environmental matters, and legal actions.

  Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements. The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide and two million tons of nitrogen oxides (NOx) 
from 1980 emission levels, to be completed in two phases, Phase I and Phase 
II. Five coal-fired System plants are affected in Phase I and the remaining 
plants and units reactivated in the future will be affected in Phase II. 
Installation of scrubbers at the Harrison Power Station was the strategy 
undertaken to meet the required SO[2] emission reductions for Phase I 
(1995-1999). Continuing
<PAGE>
                                  64

studies will determine the compliance strategy for Phase II (2000 and beyond).
Studies to evaluate cost effective options to comply with Phase II SO[2]
limits, including those which may be available from the use of the subsidiaries'
banked emission allowances and from the emission allowance trading market,
are continuing. It is expected that burner modifications at possibly all
stations will satisfy the NOx emission reduction requirements for the acid
rain (Title IV) provisions of the CAAA. Additional post-combustion controls
may be mandated in Maryland and Pennsylvania for ozone nonattainment (Title I)
reasons. Continuous emission monitoring equipment has been installed on all
Phase I and Phase II units. 

  The subsidiaries previously reported that the Environmental Protection
Agency had identified them and approximately 875 others as potentially
responsible parties in a Superfund site subject to cleanup. The subsidiaries
have also been named as defendants along with multiple other defendants in
pending asbestos cases involving one or more plaintiffs. The 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.

  In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective
in 1996. SFAS No. 121 establishes standards for the impairment of long-lived
assets and certain identifiable intangibles and requires companies to
recognize an impairment loss if the expected future undiscounted cash flows
are less than the carrying amount of an asset. The Company and its subsidiar-
ies do not believe at this time that adoption of this standard will have a
materially adverse effect on their financial position. 

Financial Condition and Requirements
Liquidity and Capital Requirements

  To meet the System companies' need for cash 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 internal-
ly 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 financing depend upon
the financial health of the companies seeking those funds. 

  Construction expenditures of the regulated subsidiaries in 1995 were $319
million and for 1996 and 1997 are estimated at $279 million and $305 million,
respectively. In 1995, these expenditures included $36 million for compliance
with the CAAA. The 1996 and 1997 estimated expenditures include $7 million and
$20 million, respectively, for additional CAAA compliance costs. The Harrison
scrubbers, which were constructed for compliance with Phase I of the CAAA,
were completed on schedule in late 1994 and the final cost was approximately
24% below the original budget. Expenditures in the future to cover the costs
of compliance with Phase II of the CAAA may be significant. Based on current
forecasts and considering the reactivation of capacity in cold reserve, peak
diversity exchange arrangements, demand-side management and conservation
programs, and contracted PURPA capacity, it is not anticipated that the
regulated subsidiaries will require new generating capacity until the year
2000 or beyond. The regulated subsidiaries also have additional capital
requirements for debt maturities (see Note H to the consolidated financial
statements). The Company will have additional capital requirements in the
future related to nonutility investments of AYP Capital which are described
under Nonutility Business on page 67. 
<PAGE>
                                 65
Internal Cash Flows

  Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $281 million in 1995 compared with $246 million in
1994. Because of the new rate case authorizations effective in late 1994 and
1995 and reduced levels of capital expenditures, the regulated subsidiaries
were able to finance approximately 88% of their capital expenditure program
through internal cash generation in 1995, as compared to 48% in 1994. This
ratio is expected to continue to increase over the next several years for
utility investments. See page 67 for a description of future nonutility
investments. Dividends paid on common stock in 1995 increased to $1.65 per
share compared with $1.64 in 1994. However, the dividend payout ratio
decreased from 88%, excluding the cumulative effect of the accounting change
in 1994, to 83% in 1995. 

  As capital-intensive electric utilities, the regulated subsidiaries are
affected by the rate of inflation. The inflation rate over the past several
years has been relatively low and has not materially affected their financial
position. However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years.

  Fuel inventory provided a source of cash in 1995 ($12 million), primarily
related to lower fuel prices attained through renegotiations of fuel contracts
effective in January 1995 and the ability to use lower-cost, high-sulfur coal
at the Harrison Power Station because of the new scrubbers. In 1994, fuel
inventory represented a use of cash ($13 million) as it returned to a higher
level after selective mine shutdowns during contract renegotiations in 1993.
The decrease in operating and construction inventory in 1995 resulted from the
write-off of obsolete and slow-moving inventory. In connection with ongoing
restructuring activities and consolidation of facilities, the subsidiaries are
reevaluating inventory management objectives to take advantage of centralized
storerooms serving several facilities and to improve turnover ratios.

Financings 

  During 1995, the Company issued 1,407,855 shares of common stock under its
Dividend Reinvestment and Stock Purchase Plan (DRISP), and Employee Stock
Ownership and Savings Plan (ESOSP) for $35.0 million. The subsidiaries
refinanced $338 million of debt securities with new debt securities having
lower interest rates and refinanced preferred stock issues totaling $155.5
million with Quarterly Income Debt Securities (QUIDS). Under certain circum-
stances the interest payments on QUIDS may be deferred for a period of up to
20 consecutive quarters. Debt redemption costs of refinancings are amortized
over the life of the associated new securities. Due to the significant number
of refinancings which have occurred over the past four years, this balance is
now $57 million. Reduced future interest expense will more than offset these
expenses. Preferred stock redemption costs of $5.5 million were charged
directly to retained earnings.

  Short-term debt is used to meet temporary cash needs until the timing is
considered appropriate to issue long-term securities. Short-term debt
increased $74 million to $200 million in 1995. At December 31, 1995, unused
lines of credit with banks were $173 million. In addition, a multi-year credit
program established in 1994 provides the subsidiaries with the ability to
borrow on a standby revolving credit basis up to $300 million. After the
initial three-year term, the program agreement provides that the maturity date
may be extended in one-year increments. There were no borrowings under this
facility in 1995. During 1996, the subsidiaries anticipate meeting their
capital requirements through a combination of internally generated funds, cash
on hand, and short-term borrowing as necessary. The Company plans to continue
DRISP/ESOSP common stock sales. The subsidiaries anticipate that they will be
able to meet their future cash needs through internal cash generation and
external financings, as they have in the past. See page 67 for information on
financing requirements for proposed nonutility investments.
<PAGE>
                                 66

Changes in the Electric Utility Industry

  Competitive forces within the electric utility industry continued to
increase in 1995. As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory. Electric utilities must also compete with suppliers
of other forms of energy. Growing competitive challenges due to legislative,
economic, and technological changes, and Allegheny Power's ability to meet
these challenges, have been a major focal point in 1995.

Competition in Core Business

  Competition in the wholesale market for electricity was enhanced by the
National Energy Policy Act of 1992 (EPACT), which permits wholesale genera-
tors, utility-owned and otherwise, and wholesale customers to request from
owners of bulk power transmission facilities a commitment to supply transmis-
sion services. EPACT is the first legislative action to permit wholesale
customers within a utility's franchised service territory to seek alternative
providers of energy. 

  The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995 which
intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators. The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power. The Mega-NOPR provides that
electric utilities would be able to recover stranded costs (costs of facili-
ties made uneconomic by wholesale transmission access). The FERC has not yet
issued a final rulemaking on these issues.

  State regulators in Ohio, Pennsylvania, and Virginia are in various stages
of proceedings to evaluate the feasibility of retail competition. The Maryland
commission has completed its investigation and issued an order which found
that while competition in the electric wholesale market should be encouraged,
retail competition is not in the public interest at this time. The regulated
subsidiaries have filed responses in these proceedings which emphasize the
need to move cautiously toward retail competition in order to protect the
reliability of service to retail customers, and to insure that utilities
without excess generating capacity, like the regulated subsidiaries, are not
placed at a competitive disadvantage by permitting utilities with excess
capacity to dump energy at low marginal cost while keeping their own customers
captive through high stranded investment fees. Attempts at variations of
retail wheeling have been authorized in some states, and various municipali-
ties around the country that are not wholesale customers are exploring ways to
become wholesale customers to obtain the ability to choose their electric
supplier. In 1995, the Department of Defense proposed that it be granted
competitive procurement rights for defense facilities.

Efforts to Maintain and Improve Competitive Position

  The emerging competitive environment in generation and wholesale markets and
the increasing possibility of retail competition have created greater planning
uncertainty and risks for the Company. In response, the Company is continuing
to develop a number of strategies to retain its existing customers and to
expand its retail and wholesale customer base, including:

    1.  Restructuring its operations to maintain its relatively low-cost status
        by controlling costs and operating more efficiently 

    2. Implementing new marketing strategies

    3. Increasing customer and energy services

    4. Avoiding future rate increases

    5. Expanding core business into nonutility activities (see below)
<PAGE>
                                   67
  
    The Company believes it is taking necessary actions to position itself to
meet current and future competitive challenges.

Nonutility Business

  To help meet the challenges of the competitive environment in the electric
utility industry, Allegheny Power is broadening its operations into nonutility
businesses. In 1994, AYP Capital was formed to pursue opportunities in
unregulated markets in order to strengthen the long-term competitiveness and
profitability of the Company. AYP Capital's primary objectives are to develop
new energy-related services businesses and to pursue wholesale unregulated
power generation. The most significant project is an agreement with Duquesne
Light Company to purchase for about $170 million its 50% interest (276
megawatts) in Unit No. 1 of the Fort Martin Power Station. The rest of the
station is owned by the Company's regulated subsidiaries. AYP Capital intends
to operate its share of the unit as an exempt wholesale generator and sell the
output at market rates. After necessary approvals, AYP Capital expects a
closing by late 1996. Various financing alternatives for this acquisition are
being considered. Upon commencement of operations, AYP Capital will incur
depreciation expense and other operating expenses related to Fort Martin. 

  AYP Capital has also committed to invest up to $10 million in two limited
partnerships. AYP Capital has also invested in APS Cogenex, a joint venture
limited liability company which provides services to improve the energy
efficiency of consumer facilities in the five states in which Allegheny Power
provides electric service plus the District of Columbia. AYP Capital intends
to provide financing to consumers that undertake capital improvements
necessary to achieve energy efficiency. AYP Capital will continue to evaluate
investment opportunities with potentially significant additional capital
investments in the future. AYP Capital's total investments as of December 31,
1995, were $1.1 million. 

  Although nonutility investments offer the potential for earning returns in
excess of regulated investments, they generally involve a higher degree of
risk. AYP Capital intends to manage these risks by diversifying its invest-
ments and by investing where there is an appropriate balance of risk and
reward. 

  The ability of AYP Capital to engage and compete in nonutility businesses
will be impeded unless the Public Utility Holding Company Act of 1935 (PUHCA)
is repealed or revised. PUHCA prevents or significantly disadvantages the
Company and other non-exempt holding companies from diversifying into
utility-related or nonutility businesses, a disadvantage not imposed on exempt
holding companies and other competitors. The Company has been active in
seeking repeal or reform of this law.
<PAGE>
                                 68

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

REVIEW OF OPERATIONS

Net Income

Net income in 1995 increased to $66.7 million compared with $59.9 million in
1994, excluding in 1994 the cumulative effect of an accounting change to
record unbilled revenues.  The increase resulted primarily from additional
retail revenues due to increased kilowatt-hour (kWh) sales and previously
reported rate increases.  These revenue increases were offset in part by
restructuring charges and inventory write-offs in 1995 of $3.3 million after
tax and higher expenses.  Net income in 1993 was $61.7 million.  The decrease
in 1994 resulted primarily from higher expenses, including taxes, pension
expense, and depreciation.

           Restructuring activities in 1995 were initiated by the System in
response to the competitive environment emerging in the electric utility
industry.  The System, including the Company, is restructuring many of its
functions to strengthen its competitive position and improve its cost
structure.  During 1995, reengineering of the Bulk Power Supply department in
the affiliated Allegheny Power Service Corporation was substantially completed
and process redesign is expected to be substantially completed in 1996 for the
remainder of the System.  Downsizing was not a specific goal of the restruc-
turing efforts, but as a consequence of process redesign and elimination of
duplicate positions, approximately 200 System employees have been placed in a
staffing force pending reassignment or layoff.  In addition, about 130 fewer
System employees will be required in the power station work force by the end
of 1997, and employee reductions are also likely to result from reengineering
in other areas.  The charges recorded in 1995 in connection with restructuring
activities reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs.  It is expected that these
costs will be recovered through future cost savings.

Sales and Revenues

         KWh sales to and revenues from residential, commercial, and industrial
customers are shown on pages 51 and 52.  Such kWh sales increased 4.5% and
3.2% in 1995 and 1994, respectively.  The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the following:
                                                           Changes
                                                       from Prior Year  
                                                       1995        1994
                                                    (Millions of Dollars)
Increased kWh sales..............................     $21.6       $ 3.8
Rate increases:
  West Virginia..................................      17.1         7.9
  Ohio...........................................        .5            
                                                       17.6         7.9
Fuel and energy cost adjustment clauses*.........      (3.1)       13.0
Other............................................        .6         1.0
                                                      $36.7       $25.7

*Changes in revenues from fuel and energy cost adjustment clauses have little
effect on net income.
<PAGE>
                                  69
 
           The increase in kWh sales in 1995 was largely attributable to
commercial and industrial sales.  Industrial sales increased 3.5% and 6.1% in
1995 and 1994, respectively.  The 6.5% increase in commercial sales in 1995
and the 1.2% increase in 1994 reflect growth in the number of customers and in
1995 also increased customer usage.  These increases continue to reflect a
trend of economic growth in the service territory.  In 1995, the Company
implemented a new Major Accounts Program which focuses on enhancing the
working relationships with its largest customers.  The goal of the program is
to assure, through superior service, that the Company remains the energy
supplier for these major customers.  

           Residential kWh sales increased 5.0% in 1995 and decreased .6% in
1994.  The rate of growth in the number of residential customers has remained
constant at 1% annually in 1995, 1994, and 1993.  However, the impact of
weather on customer usage continues to produce fluctuations in residential
sales.  In 1995, decreased sales due to mild weather in the first and second
quarters were more than offset by extremely hot summer weather and cooler than
normal winter weather in November and December as compared to 1994.  The 1994
residential use was down slightly from 1993 levels reflecting a decrease in
both heating and cooling degree days. 

           Rate case decisions in all jurisdictions, representing revenue
increases in excess of $35 million on an annual basis, have been obtained.
About $29 million became effective in 1994 and $6 million in Ohio became
effective on November 9, 1995.  These included recovery of the remaining
carrying charges on investment, depreciation, and all operating costs required
to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and
other increasing levels of expenses.  Additional base rate increases are not
expected to be necessary for the next several years. 

           KWh sales to and revenues from nonaffiliated utilities are comprised
of the following items:
                                            
                                            1995        1994        1993 
KWh sales (Billions):
  From Company generation.................     .1          .3          .3
  From purchased power....................    3.1         2.1         2.8
                                              3.2         2.4         3.1
Revenues (Millions):
  From Company generation.................  $ 2.7       $ 7.7       $ 8.4
  From sales of purchased
    power.................................   88.2        72.0        77.6
                                            $90.9       $79.7       $86.0


         Sales to nonaffiliated companies from the Company's generation in 1995
decreased because of growth in kWh sales to retail customers which reduced the
amount available for sale and because of continuing price competition.  The
generation tax imposed in West Virginia, which in prior years was a signifi-
cant factor affecting the Company's ability to compete in the market for sales
to nonaffiliated companies, was favorably amended effective in June 1995 to
change the basis of the tax from generation to generating capacity.  Sales of
purchased power vary depending on the availability of other companies'
<PAGE>
                                  70

generating equipment, demand for energy, and price competition.  In the
future, some of these transactions may be made under new transmission tariffs
described below.  About 90% of the aggregate benefits from sales to nonaffili-
ated companies and to affiliates included in other revenues described below,
are passed on to retail customers and have little effect on net income.


           The decrease in other revenues in 1995 resulted primarily from a
decrease in sales of energy and spinning reserve to affiliated companies,
offset in part by increased revenues from wholesale customers (cooperatives
and municipalities who own their own distribution systems and who buy all or
part of their bulk power needs from the Company under regulation by the
Federal Energy Regulatory Commission).  Under the National Energy Policy Act
of 1992, these customers obtained the ability to choose the bulk power
supplier of their choice by the requirement that transmission-owning utilities
must provide transmission service.  In 1994, a rate case for wholesale
customers was completed with the result that such customers, representing
about $4.5 million in annual wholesale revenues, agreed to negotiated rate
increases and signed contracts to remain as the Company's customers for five
years.  The increase in 1994 resulted from continued increases in sales of
capacity, energy, and spinning reserve to affiliated companies because of
additional capacity and energy available from qualified facilities under the
Public Utility Regulatory Policies Act of 1978 (PURPA).  

           Other revenues in 1995 also reflect an increase in standard transmis-
sion service revenues.  See page 76 under Competition in Core Business for
information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the
Federal Energy Regulatory Commission (FERC) in 1995.  Effective in 1996,
pursuant to the intentions of the Mega-NOPR, the Company eliminated its
Standard Transmission  Service tariff for new service transactions, and began
using two new transmission service tariffs which qualify as required open
access tariffs - a Network tariff and a Point-to-Point tariff.  The FERC
accepted the filing of the new tariffs subject to hearings in the summer of
1996 and modification pending final Mega-NOPR rules.  The Company is using the
new tariffs in the interim, subject to refund.  In addition, the Company has a
Standard Generation Service tariff accepted by the FERC under which the
Company makes available bundled, nonfirm generation services with associated
transmission services.  About 90% of the benefits of these sales of transmis-
sion and generation services to customers outside the service territory are
passed through to retail customers and as a result have little effect on net
income.  While this procedure will continue to apply to similar sales under
the new tariffs, the Company may petition to revise the procedure in the
future.

Operating Expenses

           The 9% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers.  Fuel expenses increased
4% in 1994 due primarily to an increase in kWh generated.  Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the financial statements, with the result that changes in fuel
expenses have little effect on net income.
<PAGE>
                                  71

           "Purchased power and exchanges, net" represents power purchases from
and exchanges with nonaffiliated utilities and purchases from qualified 
facilities under PURPA, capacity charges paid to Allegheny Generating 
Company (AGC), an affiliate partially owned by the Company, 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 is comprised of the following items:

                                            1995        1994        1993 
                                                (Millions of Dollars)
Nonaffiliated transactions:
  Purchased power:                        
    For resale to other companies........  $ 79.1      $ 63.7      $ 68.6
    From PURPA generation................    64.6        68.3        55.7
    Other................................    11.6         9.4         8.1
  Power exchanges, net...................      .1         (.2)        (.6)
Affiliated transactions:
  AGC capacity charges...................    20.6        20.1        23.3
  Energy and spinning
    reserve charges......................      .4          .5          .5
                                           $176.4      $161.8      $155.6


           The amount of power purchased from nonaffiliated companies for use by
the Company and for resale to nonaffiliated companies depends upon the
availability of the Company's generating equipment, transmission capacity, and
fuel, and its cost of generation and the cost of operations of nonaffiliated
companies from which such purchases are made.  The primary
reason for the fluctuations in purchases for resale to nonaffiliated companies
is described under Sales and Revenues above.  The decrease in purchases from
PURPA generation in 1995 was due primarily to a contractual reduction in the
energy rate effective in June 1995 for the Grant Town PURPA project.  American
Bituminous Power Partners, L.P., the developer of the Grant Town project, has
filed an emergency petition with the Public Service Commission of West
Virginia for interim relief to have its former energy rate reinstated.  The
Company has filed objections to this petition.  The increase in purchases from
PURPA generation in 1994 reflects generation from the Grant Town PURPA project
beginning in late 1993.  None of the Company's purchased power contracts is
capitalized since there are no minimum payment requirements absent associated
kWh generation.  Other purchased power continued to increase in 1995 because
of increased sales to retail customers and the availability of more economic
energy.  The cost of power and capacity purchased for use by the Company,
including power from PURPA generation and affiliated transactions, is mostly
recovered from customers currently through the regular fuel and energy cost
recovery procedures followed by the Company's regulatory commissions and is
primarily subject to deferred power cost procedures with the result that
changes in such costs have little effect on net income.  

           The increase in other operation expense in 1995 resulted primarily
from restructuring charges which are described in Note B to financial
statements on page 125.  Additional restructuring charges will be incurred in
1996 as the Company and its affiliates complete their reengineering process. 
Other operation expense in 1996 and thereafter is expected to reflect the
benefits of savings related to the restructuring activities.  The 1994
increase in other operation expense resulted primarily from increases in
pension expense ($4 million), allowance for uncollectible accounts ($1
million), and salaries and wages ($1 million).  The increase in pension
<PAGE>
                                  72
expense occurred because the Company in 1994 discontinued the practice of
deferring pension expense in West Virginia to reflect a rate case decision in
that state, and wrote off $2.5 million of prior deferrals in West Virginia
because recovery of those deferrals was denied.

           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. 
The Company is also experiencing, and expects to continue to experience,
increased expenditures due to the aging of its power stations.  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.  Maintenance expense in 1995
includes a charge of about $1.4 million for inventory write-offs described in
Note B to the financial statements on page 125.  Maintenance expense for the
Harrison scrubbers which went into service in late 1994 is expected to
increase since the warranty period has expired. 
  
           The depreciation expense decrease in 1995 was the net result of a
decrease in depreciation rates in West Virginia concurrent with the West
Virginia base rate case effective in November 1994, offset by additions to
electric plant.  The Company began depreciating the Harrison scrubbers in mid-
November 1994 amounting to approximately $8 million annually.  A further
reduction of about $4 million annually, effective in January 1996, will result
in depreciation rates for the Company which are comparable to those of other
electric utilities, particularly those providing service in West Virginia.

         The decrease in taxes other than income in 1995 was primarily due to a
decrease in West Virginia Business and Occupation Taxes (B&O) resulting from
an amendment in the B&O tax law effective June 1995, which changed the basis
for this tax from generation to generating capacity.  The 1994 increase in
taxes other than income was primarily due to an increase in B&O taxes
resulting from prior period adjustments recorded in 1993. 

           The net increase of $11 million in federal and state income taxes in
1995 resulted from an increase in income before taxes ($7 million) and changes
in the provisions for prior years ($4 million). The net decrease in 1994 of $3
million resulted primarily from a decrease in income before taxes.  Note C to
the financial statements provides a further analysis of income tax expenses.

           The combined decreases in allowances for borrowed and other than
borrowed funds used during construction (AFUDC) in 1995 and 1994 of $2 million
and $3 million, respectively, reflect decreases in construction expenditures
upon substantial completion of the compliance program for Phase I of the CAAA.
The increase in other income, net, of $1 million in 1995 reflects an increase
in the deferral of carrying charges on CAAA expenditures in Ohio until the
base rate increase became effective in November 1995, proceeds from the sale
of timber, and interest income on a tax refund.  The changes in other income,
<PAGE>
                                  73

net, in 1994 resulted primarily from the Company's share of earnings of AGC
(see Note E to the financial statements).  

         In 1995, interest on long-term debt increased $2 million due primarily
to the new security issues in 1994 and the timing of the refinancing of $70
million of first mortgage bonds and $25 million of pollution control revenue
notes in 1995.  The increase also reflects interest on $40 million of
Quarterly Income Debt Securities issued in 1995 to refund preferred stock
issues.  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.

Environmental and Other Issues

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

           Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements.  The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides 
(NOx) from 1980 emission levels, to be completed in two phases, Phase I and 
Phase II.  Four coal-fired Company 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 to meet the required SO[2]
emission reductions for Phase I (1995-1999).  Continuing studies will
determine the compliance strategy for Phase II (2000 and beyond).  Studies to
evaluate cost effective options to comply with Phase II SO[2] limits,
including those which may be available from the use of the Company's banked
emission allowances and from the emission allowance trading market, are
continuing.  It is expected that burner modifications at possibly all stations
will satisfy the NOx emission reduction requirements for the acid rain (Title
IV) provisions of the CAAA.  Additional post-combustion controls may be
mandated in Pennsylvania (where the Company has ownership in a station) for
ozone nonattainment (Title I) reasons.  Continuous emission monitoring
equipment has been installed on all Phase I and Phase II units.

           The Company previously reported that the Environmental Protection
Agency had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup.  The Company has also been named as a defendant along with multiple
other affiliated and nonaffiliated 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.  
           
           In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," effective in 1996.  SFAS No. 121 establishes standards for the
impairment of long-lived assets and certain identifiable intangibles and
<PAGE>
                                  74

requires companies to recognize an impairment loss if the expected future
undiscounted cash flows are less than the carrying amount of an asset.  The
Company does not believe at this time that adoption of this standard will have
a materially adverse effect on its financial position.  


FINANCIAL CONDITION AND REQUIREMENTS
            
Liquidity and Capital Requirements

           To meet the Company's need for cash 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 financing depend upon
the financial health of the companies seeking those funds.

           Construction expenditures in 1995 were $75 million and for 1996 and
1997 are estimated at $66 million and $75 million, respectively.  In 1995,
these expenditures included $8 million for compliance with the CAAA.  The 1996
and 1997 estimated expenditures include $2 million and $7 million, respective-
ly, for additional CAAA compliance costs.  The Harrison scrubbers, which were
constructed for compliance with Phase I of the CAAA, were completed on
schedule in late 1994 and the final cost was approximately 24% below the
original budget.  Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant.  Based on current forecasts and
considering peak diversity exchange arrangements, demand-side management and
conservation programs, a power supply agreement with affiliates, and contract-
ed PURPA capacity, it is not anticipated that the Company will require new
generating capacity until the year 2000 or beyond.  The Company also has
additional capital requirements for debt maturities (see Note I to the
financial statements).

Internal Cash Flows

           Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $93 million in 1995 compared with $67 million in
1994.  Because of the new rate case authorizations effective in late 1994 and
1995 and reduced levels of capital expenditures, the Company was able to
finance 100% of its capital expenditure program through internal cash
generation in 1995, as compared to 64% in 1994.  This ratio is expected to
remain close to 100% over the next several years.  

           As a capital-intensive electric utility, the Company is affected by
the rate of inflation.  The inflation rate over the past several years has
been relatively low and has not materially affected the Company's financial
position.  However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years. 
<PAGE>
                                  75
 
           Fuel inventory provided a source of cash in 1995 ($3 million),
primarily related to lower fuel prices attained through renegotiations of fuel
contracts effective in January 1995 and the ability to use lower-cost, high-
sulfur coal at the Harrison Power Station because of the new scrubbers.  In
1994, fuel inventory represented a use of cash ($4 million) as it returned to
a higher level after selective mine shutdowns during contract renegotiations
in 1993.  The decrease in operating and construction inventory in 1995
resulted from the write-off of obsolete and slow-moving inventory.  In
connection with ongoing restructuring activities and consolidation of
facilities, the Company is reevaluating inventory management objectives to
take advantage of centralized storerooms serving several facilities and to
improve turnover ratios.

Financings

           During 1995, the Company refinanced $95 million of debt securities
with new debt securities having lower interest rates and refinanced preferred
stock issues totaling $40 million with Quarterly Income Debt Securities
(QUIDS).  Under certain circumstances the interest payments on QUIDS may be
deferred for a period of up to 20 consecutive quarters.  Debt redemption costs
of refinancings are amortized over the life of the associated new securities. 
Due to the significant number of refinancings which have occurred over the
past four years, this balance is now $16 million.   Reduced future interest
expense will more than offset these expenses.  Preferred stock redemption
costs of $1.4 million were charged directly to retained earnings.

           Short-term debt is used to meet temporary cash needs until the timing
is considered appropriate to issue long-term securities. Short-term debt,
including notes payable to affiliates under the money pool, decreased $7
million to $30 million in 1995.  At December 31, 1995, the Company had SEC
authorization to issue up to $100 million of short-term debt.  The Company and
its affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of the
companies have funds available.  In addition, a multi-year credit program
established in 1994 provides the Company with the ability to borrow on a
standby revolving credit basis up to $81 million.  After the initial three-
year term, the program agreement provides that the maturity date may be
extended in one-year increments.  There were no borrowings under this facility
in 1995.  During 1996, the Company anticipates meeting its capital require-
ments through a combination of internally generated funds, cash on hand, and
short-term borrowing as necessary.  The Company anticipates that it will be
able to meet its future cash needs through internal cash generation and
external financings, as it has in the past.  

 
CHANGES IN THE ELECTRIC UTILITY INDUSTRY

           Competitive forces within the electric utility industry continued to
increase in 1995.  As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory.  Electric utilities must also compete with suppliers
of other forms of energy.  Growing competitive challenges due to legislative,
economic, and technological changes, and the ability to meet these challenges,
have been a major focal point in 1995.
<PAGE>
                                  76
 
Competition in Core Business

           Competition in the wholesale market for electricity was enhanced by
the National Energy Policy Act of 1992 (EPACT), 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.  EPACT was the first legislative action to permit
wholesale customers within a utility's franchised service territory to seek
alternative providers of energy.

           The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995
which intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators.  The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power.  The Mega-NOPR provides that
electric utilities will be able to recover stranded costs (costs of facilities
made uneconomic by wholesale transmission access).  The FERC has not yet
issued a final rulemaking on these issues.

           The Public Utilities Commission of Ohio has initiated proceedings to
evaluate the feasibility of retail competition.  The Company has filed a
response in this proceeding which emphasizes the need to move cautiously
towards retail competition in order to protect the reliability of service to
retail customers, and to insure that utilities without excess generating
capacity, like the Company, are not placed at a competitive disadvantage by
permitting utilities with excess capacity to dump energy at low marginal cost
while keeping its own customers captive through high stranded investment fees. 
Attempts at variations of retail wheeling have been authorized in some states,
and various municipalities around the country that are not wholesale customers
are exploring ways to become wholesale customers to obtain the ability to
choose their electric supplier.  In 1995, the Department of Defense proposed
that it be granted competitive procurement rights for defense facilities.

Efforts to Maintain and Improve Competitive Position

           The emerging competitive environment in generation and wholesale
markets and the increasing possibility of retail competition have created
greater planning uncertainty and risks for the Company.  In response, the
Company is continuing to develop a number of strategies to retain its existing
customers and to expand its retail and wholesale customer base, including:

        1.  Restructuring its operations to maintain its relatively low-cost    
            status by controlling costs and operating more efficiently

        2.  Implementing new marketing strategies

        3.  Increasing customer and energy services

        4.  Avoiding future rate increases


         The Company believes it is taking necessary actions to position itself
to meet current and future competitive challenges.
<PAGE>
                                  77

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

REVIEW OF OPERATIONS

Net Income

           Net income was $78.3 million in 1995 compared with $82.0 million in
1994, excluding in 1994 the cumulative effect of an accounting change to
record unbilled revenues.  The decrease resulted primarily from restructuring
charges and inventory write-offs in 1995 of $4.3 million after tax and higher
expenses offset in part by increased kilowatt-hour (kWh) sales and previously
reported rate increases.  Net income in 1993 was $73.5 million.  The increase
in 1994 resulted from an increase in kWh sales and revenue increases, offset
in part by higher expenses.

           Restructuring activities in 1995 were initiated by the System in
response to the competitive environment emerging in the electric utility
industry.  The System, including the Company, is restructuring many of its
functions to strengthen its competitive position and improve its cost
structure.  During 1995, reengineering of the Bulk Power Supply department in
the affiliated Allegheny Power Service Corporation was substantially completed
and process redesign is expected to be substantially completed in 1996 for the
remainder of the System.  Downsizing was not a specific goal of the restruc-
turing efforts, but as a consequence of process redesign and elimination of
duplicate positions, approximately 200 System employees have been placed in a
staffing force pending reassignment or layoff.  In addition, about 130 fewer
System employees will be required in the power station work force by the end
of 1997, and employee reductions are also likely to result from reengineering
in other areas.  The charges recorded in 1995 in connection with restructuring
activities reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs.  It is expected that these
costs will be recovered through future cost savings.
<PAGE> 
                                  78
          
Sales and Revenues

         KWh sales to and revenues from residential, commercial, and industrial
customers are shown on pages 53 and 54.  Such kWh sales increased 3.3% and
2.3% in 1995 and 1994, respectively.  The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the following:
                                                          Changes 
                                                      from Prior Year  
                                                      1995        1994
                                                   (Millions of Dollars)
Increased kWh sales..............................    $17.3       $10.3
Rate changes:
  Maryland.......................................     17.7        11.9
  Virginia.......................................     (1.8)        8.5
  West Virginia..................................      2.2         1.9
                                                      18.1        22.3
Fuel and energy cost
  adjustment clauses*............................      3.2        18.6
Other............................................     (3.0)        1.0
                                                     $35.6       $52.2

*Changes in revenues from fuel and energy cost adjustment clauses have little
 effect on net income.

           The increase in kWh sales in 1995 was in part attributable to
industrial and commercial sales.  Industrial sales increased 2.7% and 2.8% in
1995 and 1994, respectively.  The 3.6% increase in commercial sales in 1995
and the 2.1% increase in 1994 reflect growth in the number of customers and in
1995 also increased customer usage.  These increases continue to reflect a
trend of economic growth in the service territory.  In 1995 the Company
implemented a new Major Accounts Program which focuses on enhancing the
working relationships with its largest customers.  The goal of the program is
to assure, through superior service, that the Company remains the energy
supplier for these major customers.

           Residential kWh sales increased 3.9% in 1995 and 1.7% in 1994.  The
rate of growth in the number of residential customers has remained constant at
about 2.1% annually in 1995, 1994, and 1993.  However, the impact of weather
on customer usage continues to produce fluctuations in residential sales.  In
1995, decreased sales due to mild weather in the first and second quarters
were more than offset by extremely hot summer weather and cooler than normal
winter weather in November and December as compared to 1994.  The 1994
residential use was down slightly from 1993 levels reflecting a decrease in
both heating and cooling degree days. 

           Rate case decisions in all jurisdictions, representing revenue
increases in excess of $35 million on an annual basis, have been obtained,
most of them in late 1994.  These included recovery of the remaining carrying
charges on investment, depreciation, and all operating costs required to
comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other
<PAGE>
                                  79

increasing levels of expenses.  Additional base rate increases are not
expected to be necessary for the next several years.
However, future purchased power expenses related to a qualified facility under
the Public Utility Regulatory Policies Act of 1978 (PURPA), to be completed in
late 1999, may make it necessary to increase rates at that time.
           
           KWh sales to and revenues from nonaffiliated utilities are comprised
of the following items:
                                            
                                           1995         1994        1993 
KWh sales (Billions):
  From Company generation...............      .2           .3          .4
  From purchased power..................     4.2          2.9         3.5
                                             4.4          3.2         3.9
Revenues (Millions):
  From Company generation...............  $  4.6       $  8.9      $  8.6
  From sales of purchased
    power...............................   121.3         98.1        99.5
                                          $125.9       $107.0      $108.1


         Sales to nonaffiliated companies from the Company's generation in 1995
decreased because of growth in kWh sales to retail customers which reduced the
amount available for sale and because of continuing price competition.  The
generation tax imposed in West Virginia, which in prior years was a signifi-
cant factor affecting the Company's ability to compete in the market for sales
to nonaffiliated companies, was favorably amended effective in June 1995 to
change the basis of the tax from generation to generating capacity.  Sales of
purchased power vary depending on the availability of other companies'
generating equipment, demand for energy, and price competition.  In the
future, some of these transactions may be made under new transmission tariffs
described below.  About 95% of the aggregate benefits from sales to nonaffili-
ated companies are passed on to retail customers and have little effect on net
income.  
                                                      
           The increase in other revenues in 1995 resulted primarily from
provisions recorded for rate refunds in 1994 and increased revenues from
wholesale customers (cooperatives and municipalities who own their own
distribution systems and who buy all or part of their bulk power needs from
the Company under regulation by the Federal Energy Regulatory Commission). 
Under the National Energy Policy Act of 1992, these customers obtained the
ability to choose the bulk power supplier of their choice by the requirement
that transmission-owning utilities must provide transmission service.  In June
1995, rate cases for wholesale customers were completed with the result that
such customers, with revenues representing about 94% of the $23.4 million in
annual wholesale revenues, agreed to negotiated rate increases of about $2.1
million, and signed three-year contracts to remain as Company customers. One
customer representing the remaining 6% of annual revenues selected an 18-month
contract at higher rates.  In the event that this customer was to select
another supplier, the Company would retain transmission revenues with the
result that any reduction in net income would not be significant.   The
decrease in other revenues in 1994 resulted from provisions for rate refunds
recorded in 1994 for the 1993 and 1994 Virginia base rate increase requests,
collected from customers subject to refund.  The refunds were completed in
1995.
<PAGE>
                                  80

           Other revenues in 1995 also reflect an increase in standard transmis-
sion service revenues.  See page 85 under Competition in Core Business for
information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the
Federal Energy Regulatory Commission (FERC) in 1995.  Effective in 1996,
pursuant to the intentions of the Mega-NOPR, the Company eliminated its
Standard Transmission Service tariff for new service transactions, and began
using two new transmission service tariffs which qualify as required open
access tariffs - a Network tariff and Point-to- Point tariff.  The FERC
accepted the filing of the new tariffs subject to hearings in the summer of
1996 and modification pending final Mega-NOPR rules.  The Company is using the
new tariffs in the interim, subject to refund.  In addition, the Company has a
Standard Generation Service tariff accepted by the FERC under which the
Company makes available bundled, nonfirm generation services with associated
transmission services.  About 95% of the benefits of these sales of transmis-
sion and generation services to customers outside the service territory are
passed through to retail customers and as a result have little effect on net
income.  While this procedure will continue to apply to similar sales under
the new tariffs, the Company may petition to revise the procedure in the
future.

Operating Expenses

           The 7% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers.  Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the financial statements, with the result that changes in fuel
expenses have little effect on net income.

           "Purchased power and exchanges, net" represents power purchases from
and exchanges with nonaffiliated utilities, capacity charges paid to Allegheny
Generating Company (AGC), an affiliate partially owned by the Company, 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 is comprised of the following items:



                                            1995        1994        1993 
                                                (Millions of Dollars)
Nonaffiliated transactions:
  Purchased power:                        
    For resale to other companies........  $108.5      $ 86.5      $ 87.9
    Other................................    15.4        12.7        10.5
  Power exchanges, net...................     (.2)        (.2)        (.8)
Affiliated transactions:
  AGC capacity charges...................    28.1        29.4        28.0
  Other affiliated capacity charges......    45.6        37.6        28.4
  Energy and spinning
    reserve charges......................    48.2        51.1        51.1
                                           $245.6      $217.1      $205.1


           The amount of power purchased from nonaffiliated companies for use by
the Company and for resale to nonaffiliated companies depends upon the
availability of the Company's generating equipment, transmission capacity, and
fuel, and its cost of generation and the cost of operations of nonaffiliated
<PAGE>
                                  81 

companies from which such purchases are made.  The primary reason for the
fluctuations in purchases for resale to nonaffiliated companies is described
under Sales and Revenues above.  Other purchased power continued to increase
in 1995 because of increased sales to retail customers and the availability of
more economic energy.  The increase in affiliated capacity in 1995 and 1994
was due to growth of kWh sales to retail customers.  The cost of power
purchased from nonaffiliates for use by the Company, AGC capacity charges in
West Virginia, and affiliated energy and spinning reserve charges are mostly
recovered from customers currently through the regular fuel and energy cost
recovery procedures followed by the Company's regulatory commissions and is
primarily subject to deferred power cost procedures with the result that
changes in such costs have little effect on net income.

           While the Company does not currently purchase generation from
qualified facilities under PURPA, it will be required to do so in 1999 because
of a PURPA facility which is then scheduled to commence operations.  This
project may significantly increase the cost of power purchases passed on to
customers.

           The increase in other operation expense in 1995 resulted primarily
from restructuring charges which are described in Note B to the financial
statements on page 140.  Additional restructuring charges will be incurred in
1996 as the Company and its affiliates complete their reengineering process. 
Other operation expense in 1996 and thereafter is expected to reflect the
benefits of savings related to the restructuring activities.  The 1994
increase in other operation expense resulted primarily from demand-side
management program costs ($1 million) and cogeneration project expenses ($1
million), both of which are being recovered from customers, provisions for
environmental liabilities ($1 million), and increases in affiliated company
charges for transmission service ($2 million), salaries and wages ($1
million), and employee benefit costs ($1 million), primarily pension expense
and other postretirement benefits.  The increase in pension expense occurred
because the Company in 1994 discontinued the practice of deferring pension
expense in West Virginia to reflect a rate case decision in that state, and
wrote off $.9 million of prior deferrals in Virginia and West Virginia because
recovery of those deferrals was denied.

           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. 
The Company is also experiencing, and expects to continue to experience,
increased expenditures due to the aging of its power stations.  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.  Maintenance expense in 1995
includes a charge of about $2 million for inventory write-offs described in
Note B to the financial statements on page 140.  Maintenance expense for the 
Harrison scrubbers which went into service in late 1994 is expected to 
increase since the warranty period has expired.
<PAGE>
                                   82

           Depreciation expense increases resulted primarily from additions to
electric plant.  The Company began depreciating the Harrison scrubbers in mid-
November 1994 amounting to approximately $10 million annually.  Future
depreciation expense increases for utility operations are expected to be less
than historical increases because of reduced levels of proposed capital
expenditures.  

           The net increase of $4 million in federal and state income taxes in
1995 resulted primarily from an increase in reversals of prior year deprecia-
tion benefits for which deferred taxes were not then provided.  The net
increase of $3 million in federal and state income taxes in 1994 resulted
primarily from an increase in income before taxes.  Note C to the financial
statements provides a further analysis of income tax expenses.
           
           The combined decreases in allowances for borrowed and other than
borrowed funds used during construction (AFUDC) in 1995 and 1994 of $4 million
and $1 million, respectively, reflect decreases in construction expenditures
upon substantial completion of the compliance program for Phase I of the CAAA. 
The increase in other income, net, of $2 million in 1995 was due primarily to
income from demand-side management programs.  During 1995, the Company
continued its participation in the collaborative process for demand-side
management in Maryland.  Program costs, including lost revenues and rebates,
are deferred as a regulatory asset and are being recovered through an energy
conservation surcharge over a seven-year period.  The balance in the regulato-
ry asset for this program is $16 million as of December 31, 1995.  The
increase in other income, net, in 1994 resulted primarily from the Company's
share of earnings of AGC (see Note E to the financial statements) and income
from demand-side management programs.  

           In 1995 interest on long-term debt increased $4 million due primarily
to the new security issues in 1994 and the timing of the refinancing of $145
million of first mortgage bonds and $21 million of pollution control revenue
notes in 1995.  The increase also reflects interest on $45.5 million of
Quarterly Income Debt Securities issued in 1995 to refund preferred stock
issues.  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.

Environmental and Other Issues

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

           Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements.  The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides 
(NOx) from 1980 emission levels, to be completed in two phases, Phase I and 
Phase II.  Three coal-fired Company 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 to meet the required SO[2]
emission reductions for Phase I (1995-1999).  Continuing studies will
<PAGE>
                                 83

determine the compliance strategy for Phase II (2000 and beyond).  Studies to
evaluate cost effective options to comply with Phase II SO[2] limits,
including those which may be available from the use of the Company's banked
emission allowances and from the emission allowance trading market, are
continuing.  It is expected that burner modifications at possibly all stations
will satisfy the NOx emission reduction requirements for the acid rain (Title
IV) provisions of the CAAA.  Additional post-combustion controls may be
mandated in Maryland and Pennsylvania (where the Company has ownership in a
station) for ozone nonattainment (Title I) reasons.  Continuous emission
monitoring equipment has been installed on all Phase I and Phase II units.

           The Company previously reported that the Environmental Protection
Agency had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup.  The Company has also been named as a defendant along with multiple
other affiliated and nonaffiliated 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.

           In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996.  SFAS No. 121 establishes standards for the impairment
of long-lived assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future undiscounted
cash flows are less than the carrying amount of an asset.  The Company does
not believe at this time that adoption of this standard will have a materially
adverse effect on its financial position.  


FINANCIAL CONDITION AND REQUIREMENTS

Liquidity and Capital Requirements

           To meet the Company's need for cash 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 financing depend upon
the financial health of the companies seeking those funds.

           Construction expenditures in 1995 were $92 million and for 1996 and
1997 are estimated at $87 million and $103 million, respectively.  In 1995,
these expenditures included $9 million for compliance with the CAAA.  The 1996
and 1997 estimated expenditures include $1 million and $2 million, respective-
ly, for additional CAAA compliance costs.  The Harrison scrubbers, which were
<PAGE>
                                  84

constructed for compliance with Phase I of the CAAA, were completed on
schedule in late 1994 and the final cost was approximately 24% below the
original budget.  Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant.  Based on current forecasts and
considering peak diversity exchange arrangements, demand-side management and
conservation programs, a power supply agreement with affiliates, and contract-
ed PURPA capacity, it is not anticipated that the Company will require new
generating capacity until the year 2000 or beyond.  The Company also has
additional capital requirements for debt maturities (See Note I to the
financial statements).

Internal Cash Flows

           Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $85 million in 1995 compared with $67 million in
1994.  Because of the new rate case authorizations effective in late 1994 and
1995 and reduced levels of capital expenditures, the Company was able to
finance approximately 92% of its capital expenditure program through internal
cash generation in 1995, as compared to 47% in 1994.  This ratio is expected
to continue to increase over the next several years.  

           As a capital-intensive electric utility, the Company is affected by
the rate of inflation.  The inflation rate over the past several years has
been relatively low and has not materially affected the Company's financial
position.  However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years. 

           Fuel inventory provided a source of cash in 1995 ($3 million),
primarily related to lower fuel prices attained through renegotiations of fuel
contracts effective in January 1995 and the ability to use lower-cost, high-
sulfur coal at the Harrison Power Station because of the new scrubbers.  In
1994, fuel inventory represented a use of cash ($4 million) as it returned to
a higher level after selective mine shutdowns during contract renegotiations
in 1993.  The decrease in operating and construction inventory in 1995
resulted from the write-off of obsolete and slow-moving inventory.  In
connection with ongoing restructuring activities and consolidation of
facilities, the Company is reevaluating inventory management objectives to
take advantage of centralized storerooms serving several facilities and to
improve turnover ratios.

Financings

           During 1995, the Company refinanced $166 million of debt securities
with new debt securities having lower interest rates and refinanced preferred
stock issues totaling $45.5 million with Quarterly Income Debt Securities
(QUIDS).  Under certain circumstances the interest payments on QUIDS may be
deferred for a period of up to 20 consecutive quarters.  Debt redemption costs
of refinancings are amortized over the life of the associated new securities. 
Due to the significant number of refinancings which have occurred over the 
past four years, this balance is now $19 million.  Reduced future interest 
expense will more than offset these expenses. Preferred stock redemption costs 
of $2.0 million were charged directly to retained earnings.
<PAGE>
                                  85

           Short-term debt is used to meet temporary cash needs until the timing
is considered appropriate to issue long-term securities.  Short-term debt
increased to $22 million in 1995.  At December 31, 1995, the Company had SEC
authorization to issue up to $115 million of short-term debt.  The Company and
its affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of the
companies have funds available.  In addition, a multi-year credit program
established in 1994 provides the Company with the ability to borrow on a
standby revolving credit basis up to $84 million.  After the initial three-
year term, the program agreement provides that the maturity date may be
extended in one-year increments.  There were no borrowings under this facility
in 1995.  During 1996, the Company anticipates meeting its capital require-
ments through a combination of internally generated funds, cash on hand, and
short-term borrowing as necessary.  The Company anticipates that it will be
able to meet its future cash needs through internal cash generation and
external financings, as it has in the past.

 
CHANGES IN THE ELECTRIC UTILITY INDUSTRY

           Competitive forces within the electric utility industry continued to
increase in 1995.  As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory.  Electric utilities must also compete with suppliers
of other forms of energy.  Growing competitive challenges due to legislative,
economic, and technological changes, and the ability to meet these challenges,
have been a major focal point in 1995.

Competition in Core Business

           Competition in the wholesale market for electricity was enhanced by
the National Energy Policy Act of 1992 (EPACT), 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.  EPACT was the first legislative action to permit
wholesale customers within a utility's franchised service territory to seek
alternative providers of energy.

           The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995
which intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators.  The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power.  The Mega-NOPR provides that
electric utilities will be able to recover stranded costs (costs of facilities
made uneconomic by wholesale transmission access).  The FERC has not yet
issued a final rulemaking on these issues.  

           The Virginia commission is conducting proceedings to evaluate the
feasibility of retail competition.  The Maryland commission has completed its
investigation and issued an order which found that while competition in the
electric wholesale market should be encouraged, retail competition is
not in the public interest at this time.  The Company has filed responses in
these proceedings which emphasize the need to move cautiously toward retail
competition in order to protect the reliability of service to retail custom-
ers, and to insure that utilities without excess generating capacity, like the
<PAGE>
                                  86 

Company, are not placed at a competitive disadvantage by permitting utilities
with excess capacity to dump energy at low marginal cost while keeping its own
customers captive through high stranded investment fees.  Attempts at
variations of retail wheeling have been authorized in some states, and various
municipalities around the country that are not wholesale customers are
exploring ways to become wholesale customers to obtain the ability to choose
their electric supplier.  In 1995, the Department of Defense proposed that it
be granted competitive procurement rights for defense facilities.

Efforts to Maintain and Improve Competitive Position

           The emerging competitive environment in generation and wholesale
markets and the increasing possibility of retail competition have created
greater planning uncertainty and risks for the Company.  In response, the
Company is continuing to develop a number of strategies to retain its existing
customers and to expand its retail and wholesale customer base, including:

        1.  Restructuring its operations to maintain its relatively low-cost   
            status by controlling costs and operating more efficiently

        2.  Implementing new marketing strategies

        3.  Increasing customer and energy services

        4.  Avoiding future rate increases


         The Company believes it is taking necessary actions to position itself
to meet current and future competitive challenges.
<PAGE>
                                 87

West Penn
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
     
REVIEW OF OPERATIONS

Consolidated Net Income

           Consolidated net income in 1995 increased to $117.9 million compared
with $101.0 in 1994, excluding in 1994 the cumulative effect of an accounting
change to record unbilled revenues.  The increase resulted primarily from
additional retail revenues due to increased kilowatt-hour (kWh) sales and
previously reported rate increases.  These revenue increases were offset in
part by restructuring charges and inventory write-offs in 1995 of $6.5 million
after tax and higher expenses.  Earnings in 1994 included a charge of $5.2
million after tax related to asset write-offs.  Consolidated net income in
1993 was $102.1 million.  Consolidated net income in 1994 reflects higher
retail revenues from increased kWh sales and rate increases, offset in part by
higher expenses.

           Restructuring activities in 1995 were initiated by the System in
response to the competitive environment emerging in the electric utility
industry.  The System, including the Company, is restructuring many of its
functions to strengthen its competitive position and improve its cost
structure.  During 1995, reengineering of the Bulk Power Supply department in
the affiliated Allegheny Power Service Corporation was substantially completed
and process redesign is expected to be substantially completed in 1996 for the
remainder of the System.  Downsizing was not a specific goal of the restruc-
turing efforts, but as a consequence of process redesign and elimination of
duplicate positions, approximately 200 System employees have been placed in a
staffing force pending reassignment or layoff.  In addition, about 130 fewer
System employees will be required in the power station work force by the end
of 1997, and employee reductions are also likely to result from reengineering
in other areas.  The charges recorded in 1995 in connection with restructuring
activities reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs.  It is expected that these
costs will be recovered through future cost savings.

Sales and Revenues

         KWh sales to and revenues from residential, commercial, and industrial
customers are shown on pages 55 and 56.  Such kWh sales increased 4.0% and
2.9% in 1995 and 1994, respectively.  The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the following:
                                                          Changes  
                                                      from Prior Year  
                                                      1995        1994
                                                   (Millions of Dollars)

Increased kWh sales..............................    $17.3       $ 9.4
Rate increases...................................     50.2        22.7
Fuel and energy cost adjustment clauses*.........     (2.9)       16.8
Other............................................      3.0         2.3
                                                     $67.6       $51.2

*Changes in revenues from fuel and energy cost adjustment clauses have little
effect on consolidated net income.
<PAGE>
                                  88

           The increase in kWh sales in 1995 was largely attributable to
industrial and commercial sales.  Industrial sales increased 5.8% and 4.4% in
1995 and 1994, respectively.  The 4.4% increase in commercial sales in 1995
and  the 2.9% increase in 1994 reflect growth in the number of customers and
increased customer usage.  These increases continue to reflect a trend of
economic growth in the service territory.  In 1995 the Company implemented a
new Major Accounts Program which focuses on enhancing the working relation-
ships with its largest customers.  The goal of the program is to assure,
through superior service, that the Company remains the energy supplier for
these major customers.  

           Residential kWh sales increased 1.4% in 1995 and 1.1% in 1994 due to
growth in number of customers and higher usage.  The rate of growth in the
number of residential customers has remained constant at just under 1%
annually in 1995, 1994, and 1993.  However, the impact of weather on customer
usage continues to produce fluctuations in residential sales.  In 1995,
decreased sales due to mild weather in the first and second quarters were more
than offset by extremely hot summer weather and cooler than normal winter
weather in November and December as compared to 1994.  Residential usage
increased in 1994 despite a decrease in both heating and cooling degree days.  
 

           Rate case decisions, representing revenue increases in excess of $57
million on an annual basis, have been obtained effective in late 1994.  These
included recovery of the remaining carrying charges on investment, deprecia-
tion, and all operating costs required to comply with Phase I of the Clean Air
Act Amendments of 1990 (CAAA), and other increasing levels of expenses. 
Additional base rate increases are not expected to be necessary for the next
several years.

           KWh sales to and revenues from nonaffiliated utilities are comprised
of the following items:
                                            
                                            1995        1994        1993 
KWh sales (Billions):
  From Company generation.................     .2          .5          .4
  From purchased power....................    5.7         3.8         5.0
                                              5.9         4.3         5.4
Revenues (Millions):
  From Company generation................. $  5.7      $ 12.3      $ 11.5
  From sales of purchased power...........  162.5       132.5       141.0
                                           $168.2      $144.8      $152.5


         Sales to nonaffiliated companies from the Company's generation in 1995
decreased because of growth in kWh sales to retail customers which reduced the
amount available for sale and because of continuing price competition.  The
generation tax imposed in West Virginia, which in prior years was a signifi-
cant factor affecting the Company's ability to compete in the market for sales
to nonaffiliated companies, was favorably amended effective in June 1995 to
change the basis of the tax from generation to generating capacity.  Sales of
purchased power vary depending on the availability of other companies'
generating equipment, demand for energy, and price competition.  In the
<PAGE>
                                  89 

future, some of these transactions may be made under new transmission tariffs
described below.  Most of the aggregate benefits from sales to nonaffiliated
companies and sales of energy and spinning reserve to affiliates included in
other revenues described below, are passed on to retail customers and have
little effect on consolidated net income.

           The increase in other revenues in 1995 resulted primarily from an
increase in sales of capacity, energy, and spinning reserve to other affiliat-
ed companies.  About $18 million of other revenues in 1995 were derived from
wholesale customers (cooperatives and municipalities who own their own
distribution systems and who buy all or part of their bulk power needs from
the Company under regulation by the Federal Energy Regulatory Commission). 
Under the National Energy Policy Act of 1992, these customers obtained the
ability to choose the bulk power supplier of their choice by the requirement
that transmission-owning utilities must provide transmission service.  In
1994, a rate case for wholesale customers was completed with the result that
such customers agreed to negotiated rate increases and signed seven-year
contracts to remain as Company customers. 

           Other revenues in 1995 also reflect an increase in standard transmis-
sion service revenues.  See page 94 under Competition in Core Business for
information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the
Federal Energy Regulatory Commission (FERC) in 1995.  Effective in 1996,
pursuant to the intentions of the Mega-NOPR, the Company eliminated its
Standard Transmission Service tariff for new service transactions, and began
using two new transmission service tariffs which qualify as required open
access tariffs - a Network tariff and a Point-to-Point tariff.  The FERC
accepted the filing of the new tariffs subject to hearings in the summer of
1996 and modification pending final Mega-NOPR rules.  The Company is using the
new tariffs in the interim, subject to refund.  In addition, the Company has a
Standard Generation Service tariff accepted by the FERC under which the
Company makes available bundled, nonfirm generation services with associated
transmission services.  Most of the benefits of these sales of transmission
and generation services to customers outside the service territory are passed
through to retail customers and as a result have little effect on consolidated
net income.  While this procedure will continue to apply to similar sales
under the new tariffs, the Company may petition to revise the procedure in the
future.                                    

Operating Expenses

           The 6% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers.  Fuel expenses decreased
2% in 1994 due primarily to a decrease in kWh generated. Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the consolidated financial statements, with the result that
changes in fuel expenses have little effect on consolidated net income.

           "Purchased power and exchanges, net" represents power purchases from
and exchanges with nonaffiliated companies and purchases from qualified
facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA),
capacity charges paid to Allegheny Generating Company (AGC), an affiliate
partially owned by the Company, and other transactions with affiliates made
<PAGE>
                                  90

pursuant to a power supply agreement whereby each company uses the most
economical generation available in the System at any given time, and is
comprised of the following items:

                                            1995        1994        1993 
                                                (Millions of Dollars)
Nonaffiliated transactions:
  Purchased power:                        
    For resale to other companies........  $145.4      $116.9      $124.5
    From PURPA generation................    64.7        65.7        49.6
    Other................................    21.6        18.3        15.2
  Power exchanges, net...................     (.1)        (.2)       (1.2)
Affiliated transactions:
  AGC capacity charges...................    37.8        37.2        42.3
  Energy and spinning
    reserve charges......................     4.6         8.6         4.7
  Other affiliated capacity charges......      .7          .7          .7
                                           $274.7      $247.2      $235.8


           The amount of power purchased from nonaffiliated companies for use by
the Company and for resale to nonaffiliated companies depends upon the
availability of the Company's generating equipment, transmission capacity, and
fuel, and its cost of generation and the cost of operations of nonaffiliated
companies from which such purchases are made.  The primary
reason for the fluctuations in purchases for resale to nonaffiliated companies
is described under Sales and Revenues above.  The reduced level of purchases
from PURPA generation in 1993 was due to a planned generating outage at one
PURPA project.  None of the Company's purchased power contracts is capitalized
since there are no minimum payment requirements absent associated kWh
generation.  Other purchased power continued to increase in 1995 because of
increased sales to retail customers and the availability of more economic
energy.  The cost of power purchased for use by the Company, including power
from PURPA generation and affiliated transactions, is mostly recovered from
customers currently through the regular fuel and energy cost recovery
procedures followed by the Pennsylvania Public Utility Commission (PUC), and
is primarily subject to deferred power cost procedures with the result that
changes in such costs have little effect on consolidated net income.  

           In January 1996, the Company and the developers of a proposed
Shannopin PURPA project reached agreement to terminate the project and all
pending litigation, at a buy out price of $31 million.  The agreement is
subject to PUC approval of recovery of the buy out price by the Company by no
later than March 31, 1999.  The agreement was filed with the PUC in February
1996 along with a request for expedited approval.  

           The increase in other operation expense in 1995 resulted primarily
from restructuring charges which are described in Note B to the consolidated
financial statements on page 157.  Additional restructuring charges will be
incurred in 1996 as the Company and its affiliates complete their reengineeri-
ng process.  Other operation expense in 1996 and thereafter is expected to
reflect the benefits of savings related to the restructuring activities.  The
1994 increase in other operation expense resulted primarily from a decision to
increase the allowances for uncollectible accounts ($8 million), increases in
salaries and wages ($2 million) and employee benefit costs, primarily pension
expense ($1 million) and other postretirement benefits ($2 million), and
<PAGE>
                                  91

provisions for environmental liabilities ($1 million).  Allowances for
uncollectible accounts were increased in 1994 due to an increase in aged
outstanding receivables caused primarily by Pennsylvania rate regulations
which make it difficult if not impossible to curtail service to non-paying
customers.  It is expected that the allowance for these uncollectible accounts
will be increased in the future because of increasing accounts receivable in
arrears.  The increase in pension expense occurred because the Company in 1994
discontinued the practice of deferring pension expense to reflect a rate case
decision. 
 
           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. 
The Company is also experiencing, and expects to continue to experience,
increased expenditures due to the aging of its power stations.
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.  Maintenance
expense in 1995 includes a charge of about $4   million for inventory write-
offs described in Note B to the consolidated financial statements on page 157. 
Maintenance expense for the Harrison scrubbers which went into service in late
1994 is expected to increase since the warranty period has expired.

           Depreciation expense increases resulted primarily from additions to
electric plant and from a change in depreciation rates.  The Company began
depreciating the Harrison scrubbers in mid-November 1994 amounting to
approximately $14 million annually.  Future depreciation expense increases are
expected to be less than historical increases because of reduced levels of
proposed capital expenditures.  

           The increase in taxes other than income in 1995 was due primarily to
an increase in gross receipts taxes resulting from higher revenues from retail
customers.  Taxes other than income decreased $2 million in 1994 primarily due
to a decrease in West Virginia Business and Occupation taxes (B&O taxes) ($3
million), offset in part by an increase in gross receipts taxes ($2 million).

           The net increase of $11 million in federal and state income taxes in
1995 resulted primarily from an increase in income before taxes.  The net
decrease in 1994 of $1 million resulted primarily from plant removal cost tax
deductions for which deferred taxes were not provided.  Note C to the
consolidated financial statements provides a further analysis of income tax
expenses.

           The combined decrease in allowances for borrowed and other than
borrowed funds used during construction (AFUDC) in 1995 of $6 million reflects
decreases in construction expenditures upon substantial completion of the
compliance program for Phase I of the CAAA.  The increase of $2 million in
AFUDC in 1994 reflects increased construction expenditures, including those
associated with the CAAA, net of CAAA amounts included in rate base and
earning a cash return.  Other income, net, in 1994 reflects the write-off of
$5.2 million net of income taxes of previously accumulated costs related to
<PAGE>
                                  92 

future facilities which are no longer considered meaningful in the industry's
more competitive environment.  

         In 1995, interest on long-term debt increased $6 million due primarily
to the new security issues in 1994 and the timing of the refinancing of $30
million of first mortgage bonds and $47 million of pollution control revenue
notes in 1995.  The increase also reflects interest on $70 million of
Quarterly Income Debt Securities issued in 1995 to refund preferred stock
issues.  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.

Environmental and Other Issues

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

           Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements.  The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides 
(NO[x]) from 1980 emission levels, to be completed in two phases, Phase I and 
Phase II.  Four coal-fired Company plants are affected in Phase I and the 
remaining plants and units reactivated in the future will be affected in Phase 
II. Installation of scrubbers at the Harrison Power Station was the strategy
undertaken to meet the required SO[2]  emission reductions for Phase I (1995-
1999).  Continuing studies will determine the compliance strategy for Phase II
(2000 and beyond).  Studies to evaluate cost effective options to comply with
Phase II SO[2] limits, including those which may be available from the use of
the Company's banked emission allowances and from the emission allowance
trading market, are continuing.  It is expected that burner modifications at
possibly all stations will satisfy the NO[x] emission reduction requirements
for the acid rain (Title IV) provisions of the CAAA.  Additional post-
combustion controls may be mandated in Pennsylvania for ozone nonattainment
(Title I) reasons.  Continuous emission monitoring equipment has been
installed on all Phase I and Phase II units.

           The Company previously reported that the Environmental Protection
Agency had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup.  The Company has also been named as a defendant along with multiple
other affiliated and nonaffiliated 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.

           In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996.  SFAS No. 121 establishes standards for the impairment
of long-lived assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future undiscounted
<PAGE>
                                  93

cash flows are less than the carrying amount of an asset.  The Company does 
not believe at this time that adoption of this standard will have a materially 
adverse effect on its financial position.


FINANCIAL CONDITION AND REQUIREMENTS

Liquidity and Capital Requirements

           To meet the Company's need for cash 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 financing depend upon
the financial health of the companies seeking those funds.

           Construction expenditures in 1995 were $149 million and for 1996 and
1997 are estimated at $125 million and $126 million, respectively.  In 1995,
these expenditures included $19 million for compliance with the CAAA.  The
1996 and 1997 estimated expenditures include $4 million and $10 million,
respectively, for additional CAAA compliance costs.  The Harrison scrubbers,
which were constructed for compliance with Phase I of the CAAA, were completed
on schedule in late 1994 and the final cost was approximately 24% below the
original budget.  Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant.  Based on current forecasts and
considering the reactivation of capacity in cold reserve, peak diversity
exchange arrangements, demand-side management and conservation programs, a
power supply agreement with affiliates, and contracted PURPA capacity, it is
not anticipated that the Company will require new generating capacity until
the year 2000 or beyond.  The Company also has additional capital requirements
for debt maturities (See Note I to the consolidated financial statements).  

Internal Cash Flows

           Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $110 million in 1995 compared with $109 million in
1994.  Because of the new rate case authorizations effective in late 1994 and
reduced levels of capital expenditures, the Company was able to finance
approximately 74% of its capital expenditure program through internal cash
generation in 1995, as compared to 42% in 1994.  This ratio is expected to
continue to increase over the next several years. 

           As a capital-intensive electric utility, the Company is affected by
the rate of inflation.  The inflation rate over the past several years has
been relatively low and has not materially affected the Company's financial
position.  However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years.

           Fuel inventory provided a source of cash in 1995 ($6 million),
primarily related to lower fuel prices attained through renegotiations of fuel
<PAGE>
                                  94
 
contracts effective in January 1995 and the ability to use lower-cost, high-
sulfur coal at the Harrison Power Station because of the new scrubbers.  In
1994, fuel inventory represented a use of cash ($5 million)  as it returned to
a higher level after selective mine shutdowns during contract renegotiations
in 1993.  The decrease in operating and construction inventory in 1995
resulted from the write-off of obsolete and slow-moving inventory.  In
connection with ongoing restructuring activities and consolidation of
facilities, the Company is reevaluating inventory management objectives to
take advantage of centralized storerooms serving several facilities and to
improve turnover ratios.

Financings

           During 1995, the Company refinanced $77 million of debt securities
with new debt securities having lower interest rates and refinanced preferred
stock issues totaling $70 million with Quarterly Income Debt Securities
(QUIDS).  Under certain circumstances the interest payments on QUIDS may be
deferred for a period of up to 20 consecutive quarters.  Debt redemption costs
of refinancings are amortized over the life of the associated new securities. 
Due to the significant number of refinancings which have occurred over the
past four years, this balance is now $12   million.  Reduced future interest
expense will more than offset these expenses.  Preferred stock redemption
costs of $2.2 million were charged directly to retained earnings.

           Short-term debt is used to meet temporary cash needs until the timing
is considered appropriate to issue long-term securities.  Short-term debt
increased to $70 million in 1995.  At December 31, 1995, the Company had SEC
authorization to issue up to $170 million of short-term debt.  The Company and
its affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of the
companies have funds available.  In addition, a multi-year credit program
established in 1994 provides the Company with the ability to borrow on a
standby revolving credit basis up to $135 million.  After the initial three-
year term, the program agreement provides that the maturity date may be
extended in one-year increments.  There were no borrowings under this facility
in 1995.      During 1996, the Company anticipates meeting its capital require-
ments through a combination of internally generated funds, cash on hand, and
short-term borrowings as necessary.  The Company anticipates that it will be
able to meet its future cash needs through internal cash generation and
external financings, as it has in the past.


CHANGES IN THE ELECTRIC UTILITY INDUSTRY

           Competitive forces within the electric utility industry continued to
increase in 1995.  As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory.  Electric utilities must also compete with suppliers
of other forms of energy.  Growing competitive challenges due to legislative,
economic, and technological changes, and the ability to meet these challenges,
have been a major focal point in 1995.
<PAGE>
                                  94
Competition in Core Business

           Competition in the wholesale market for electricity was enhanced by
the National Energy Policy Act of 1992 (EPACT), 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.  EPACT was the first legislative action to permit
wholesale customers within a utility's franchised service territory to seek
alternative providers of energy.

           The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995
which intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators.  The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power.  The Mega-NOPR provides that
electric utilities will be able to recover stranded costs (costs of facilities
made uneconomic by wholesale transmission access).  The FERC has not yet
issued a final rulemaking on these issues.

           The Pennsylvania PUC has begun an investigation into electric power
competition.  The PUC staff issued a report advising against instituting
retail wheeling at this time.  The Company has filed a response to this
investigation which emphasizes the need to move cautiously toward retail
competition in order to protect the reliability of service to retail custom-
ers, and to insure that utilities without excess generating capacity, like the
Company, are not placed at a competitive disadvantage by permitting utilities
with excess capacity to dump energy at low marginal cost while keeping their
own customers captive through high stranded investment fees.  Attempts at
variations of retail wheeling have been authorized in some states, and various
municipalities around the country that are not wholesale customers are
exploring ways to become wholesale customers to obtain the ability to choose
their electric supplier.  In 1995, the Department of Defense proposed that it
be granted competitive procurement rights for defense facilities.

Efforts to Maintain and Improve Competitive Position

           The emerging competitive environment in generation and wholesale
markets and the increasing possibility of retail competition have created
greater planning uncertainty and risks for the Company.  In response, the
Company is continuing to develop a number of strategies to retain its existing
customers and to expand its retail and wholesale customer base, including:

         1.  Restructuring its operations to maintain its relatively low-cost
             status by controlling costs and operating more efficiently 

         2.  Implementing new marketing strategies

         3.  Increasing customer and energy services

         4.  Avoiding future rate increases


         The Company believes it is taking necessary actions to position itself
to meet current and future competitive challenges.
<PAGE>
                                  95

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

Results of Operations

           As described under Liquidity and Capital Requirements, revenues are
determined under a cost of service formula rate schedule.  Therefore, if all
other factors remain equal, 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 1995 decreased due to a reduction in net investment and reduced operating
expenses which are described below.  Revenues for 1994 increased primarily
because of the return on equity settlement which resulted in an adjustment of
prior period provisions for rate refunds.

         The decrease in operating expenses in 1995 resulted from a decrease in
federal income taxes due to a decrease in income before taxes ($1.2 million)
combined with a decrease in operation and maintenance expense ($1.0 million). 
The increase in operating expenses in 1994 resulted primarily from an increase
in federal income taxes due to an increase in income before taxes ($1.5
million).

           The decrease in interest on long-term debt in 1994 was the combined
result of a decrease in the average amount of, and interest rates on, long-
term debt outstanding.  The increase in other interest in 1995 was due to cash
needs for refunds mandated in rate case proceedings (see Liquidity and Capital
Requirements), and the increase in 1994 was due to amortization of the premium
paid to refund debentures in 1993.

           In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996.  SFAS No. 121 establishes standards for the impairment
of long-lived assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future undiscounted
cash flows are less than the carrying amount of an asset.  The Company does
not believe at this time that adoption of this standard will have a materially
adverse effect on its financial position.

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, 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, deprecia-
tion, taxes, and a return on its investment.
<PAGE>
                                 96

           Through February 29, 1992, the Company's return on equity (ROE) was
adjusted annually pursuant to a settlement agreement approved by the FERC.  In
December 1991, the Company filed for a continuation of the existing ROE of
11.53% and other parties (the Consumer Advocate Division of the Public Service
Commission of West Virginia, Maryland People's Counsel, and Pennsylvania
Office of Consumer Advocate, collectively referred to as the joint consumer
advocates or JCA) filed to reduce the ROE to 10%.  Hearings were completed in
June 1992, and a recommendation was issued by an Administrative Law Judge
(ALJ) on December 21, 1993, for an ROE of 10.83%, which the JCA argued should
be further adjusted to reflect changes in capital market conditions since the
hearings.  Exceptions to this recommendation were filed by all parties for
consideration by the FERC.  On January 28, 1994, the JCA filed a joint
complaint with the FERC against the Company claiming that both the existing
ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and
unreasonable.  This new complaint requested an ROE of 8.53% with rates subject
to refund beginning April 1, 1994.  Hearings were completed in November 1994
and a recommendation was issued by an ALJ on December 22, 1994, dismissing the
JCA's complaint.  A settlement agreement for both cases was filed with the
FERC on January 12, 1995, which would reduce the Company's ROE from 11.53% to
11.13% for the period from March 1, 1992 through December 31, 1994, and
increase the Company's ROE to 11.2% for the period from January 1, 1995
through December 31, 1995.  This settlement was approved by the FERC on March
23, 1995.  Refunds were made by the Company of any revenues collected between
March 1, 1992 and March 23, 1995 in excess of these levels.  A second
settlement has been negotiated to address the Company's ROE after 1995.  On
December 21, 1995, the Company submitted the new settlement to the FERC and
action is pending.  Interested parties representing less than 2% of the
Company's eventual revenues have filed exceptions to the settlement.  Under
the terms of the settlement, the Company's ROE for 1996 would be 11%.  For
1997 and 1998 the ROE would be set by a formula based upon the yields of 10-
year constant maturity U.S. Treasury securities.  However, the change in ROE
from the previous year's value cannot exceed 50 basis points.

           Through a filing completed on October 31, 1994, the Company sought
FERC approval to add a prior tax payment of approximately $12 million to rate
base which will produce about $1.4 million in additional annual revenues.  The
FERC accepted the Company's filing and ordered the increase to become
effective June 1, 1995.

           An internal money pool accommodates intercompany short-term borrowing
needs to the extent that certain of the Company's affiliates have funds
available.
<PAGE>
<TABLE>
<CAPTION>
                                  97

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
                                                                   Index
                                                                                                         
                                                    Monon-          Potomac         West    
                                          APS       gahela          Edison          Penn       AGC

<S>                                       <C>        <C>             <C>            <C>        <C>
Report of Independent Accountants          98         99             100            101        102

Statement of Income for                   103        119             134            152        167
  the three years ended
  December 31, 1995                       

Statement of Retained Earnings             -         119             134            152        167
  for the three years ended
  December 31, 1995

Statement of Cash Flows for               105        120             135            153        168
  the three years ended
  December 31, 1995

Balance Sheet at December 31,             106        121             136            153        169
  1995 and 1994  
                                                                   
Statement of Capitalization at            107        122             137            154         -
  December 31, 1995 and 1994
                                          
Statement of Common Equity for            109         -               -              -          -
  the three years ended
  December 31, 1995               
                                  
Notes to financial statements             110        123             138            155        170
                                                                   
Financial Statement Schedules -                            

  Schedules - for the three years
    ended December 31, 1995

II  Valuation and qualifying
       accounts                                   S-1          S-2             S-3    S-4     -
</TABLE>

All other schedules are omitted because they are not applicable or the 
required information is shown in the Financial Statements or Notes thereto.
<PAGE>
                                  98 

                        REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors of
Allegheny Power System, Inc.


     In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Allegheny Power System, Inc. and its subsidiaries at December 31,
1995 and 1994, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1995, 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 audit provides a reasonable basis for the opinion expressed above.

     As discussed in Note A to the consolidated financial statements, the
Company changed its method of accounting for revenue recognition in 1994.


                                         PRICE WATERHOUSE LLP
                                         PRICE WATERHOUSE LLP

New York, New York
February 1, 1996
<PAGE>
                                  99

                        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 Power System, Inc.) at
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, 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.

     As discussed in Note A to the financial statements, the Company
changed its method of accounting for revenue recognition in 1994.


                                         PRICE WATERHOUSE LLP
                                         PRICE WATERHOUSE LLP

New York, New York
February 1, 1996
<PAGE>
                                 100

                        REPORT OF INDEPENDENT ACCOUNTANTS


The 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 Power System, Inc.) at
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, 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.

     As discussed in Note A to the financial statements, the Company
changed its method of accounting for revenue recognition in 1994.


                                         PRICE WATERHOUSE LLP  
                                         PRICE WATERHOUSE LLP

New York, New York
February 1, 1996
<PAGE>
                                  101

                         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 Power System,
Inc.) at December 31, 1995 and 1994, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 1995,
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.

     As discussed in Note A to the consolidated financial statements, the 
Company changed its method of accounting for revenue recognition in 1994.


                                         PRICE WATERHOUSE LLP
                                         PRICE WATERHOUSE LLP

New York, New York
February 1, 1996
<PAGE>
                                  102

                         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 (an Allegheny Power System, Inc. affiliate) at
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, 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.

 
                                         PRICE WATERHOUSE LLP
                                         PRICE WATERHOUSE LLP

New York, New York
February 1, 1996
<PAGE
<TABLE>
<CAPTION>
                                   103
APS
Consolidated Statement of Income
Year ended December 31                                               
(Thousands of Dollars Except for Per Share Data)                 1995            1994          1993
Electric Operating Revenues:
  <S>                                                      <C>             <C>            <C>
  Residential                                              $  926,966      $  863,725     $ 818,400
  Commercial                                                  493,696         459,303       430,202
  Industrial                                                  770,251         728,009       673,418
  Nonaffiliated utilities                                     385,023         331,557       346,705
  Other                                                        71,872          69,090        62,801
    Total Operating Revenues                                2,647,808       2,451,684     2,331,526
Operating Expenses:
  Operation:
    Fuel                                                      508,533         547,241       544,659
<PAGE>
                                   104  
    Purchased power and exchanges, net                        510,700         440,880       417,449
    Deferred power costs, net (Note A)                         47,796          11,805       (11,462)
    Other (Note B)                                            306,795         285,010       257,732
  Maintenance (Note B)                                        256,623         241,913       231,163
  Depreciation                                                256,316         223,883       210,428
  Taxes other than income taxes                               184,729         183,060       178,788
  Federal and state income taxes (Note C)                     154,203         129,751       128,130
    Total Operating Expenses                                2,225,695       2,063,543     1,956,887
    Operating Income                                          422,113         388,141       374,639
Other Income and Deductions:
  Allowance for other than borrowed funds used 
    during construction (Note A)                                4,473          11,966        12,499
  Other income (expense), net (Note B)                          6,224          (3,828)           (6)
    Total Other Income and Deductions                          10,697           8,138        12,493
    Income Before Interest Charges and 
       Preferred Dividends                                    432,810         396,279       387,132
Interest Charges and Preferred Dividends:
  Interest on long-term debt                                  167,199         153,668       157,449
  Other interest                                               14,417          10,394         5,812
  Allowance for borrowed funds used during 
    construction (Note A)                                      (3,713)         (7,630)       (8,983)
  Dividends on preferred stock of subsidiaries                 15,215          20,096        17,098
    Total Interest Charges and Preferred Dividends            193,118         176,528       171,376
Consolidated Income Before Cumulative Effect 
  of Accounting Change                                        239,692         219,751       215,756
Cumulative Effect of Accounting Change, net (Note A)                           43,446
Consolidated Net Income                                    $  239,692     $   263,197    $  215,756
Common Stock Shares Outstanding 
  (average) (Note H)                                      119,863,753     118,272,373   114,937,032
Earnings Per Average Share (Note H):
  Consolidated income before cumulative 
    effect of accounting change                                 $2.00           $1.86         $1.88
  Cumulative effect of accounting change, net (Note A)                            .37
  Consolidated net income                                       $2.00           $2.23         $1.88
See accompanying notes to consolidated financial statements.
<PAGE>
                                   105
  
Consolidated Statement of Cash Flows
Year ended December 31
(Thousands of Dollars)                                           1995            1994          1993
Cash Flows from Operations:
  Consolidated net income                                    $239,692        $263,197      $215,756
  Depreciation                                                256,316         223,883       210,428
  Deferred investment credit and income taxes, net             27,019          25,684        (2,388)
  Deferred power costs, net                                    47,796          11,805       (11,462)
  Allowance for other than borrowed funds used 
    during construction                                        (4,473)        (11,966)      (12,499)
  Cumulative effect of accounting change before 
    income taxes (Note A)                                                     (72,333)
  Changes in certain current assets and liabilities:
    Accounts receivable, net, excluding cumulative 
       effect of accounting change (Note A)                   (63,370)          9,666       (15,393)
    Materials and supplies                                     20,358         (20,519)       53,614
    Accounts payable                                          (45,387)          3,119          (305)
    Taxes accrued                                               3,060          (5,792)        3,619
    Interest accrued                                           (2,326)          3,452        (2,164)
  Other, net                                                     (250)          9,957        18,087
                                                              478,435         440,153       457,293
Cash Flows from Investing:
  Construction expenditures                                  (319,050)       (508,254)     (573,970)
  Nonutility investments                                       (1,076)               
  Allowance for other than borrowed funds used 
    during construction                                         4,473          11,966        12,499
                                                             (315,653)       (496,288)     (561,471)
Cash Flows from Financing:
  Sale of common stock                                         34,514          34,709        99,875
  Sale of preferred stock                                                      49,635              
  Retirement of preferred stock                              (162,171)         (1,190)       (1,611)
  Issuance of long-term debt and QUIDS                        482,856         197,098       691,343
  Retirement of long-term debt                               (392,715)        (26,000)     (632,000)
  Short-term debt, net                                         73,600          (3,818)      119,431
  Cash dividends on common stock                             (197,764)       (193,951)     (187,475)
                                                             (161,680)         56,483        89,563
Net Change in Cash and Temporary Cash 
  Investments (Note G)                                          1,102             348       (14,615)
  Cash and Temporary Cash Investments at January 1              2,765           2,417        17,032
  Cash and Temporary Cash Investments at December 31         $  3,867        $  2,765      $  2,417
Supplemental Cash Flow Information
  Cash paid during the year for:
    Interest (net of amount capitalized)                     $178,239        $148,016      $153,455
    Income taxes                                              126,386         122,343       124,979
See accompanying notes to consolidated financial statements.
<PAGE>
                               106

APS
Consolidated Balance Sheet
As of December 31
(Thousands of Dollars)                                                         1995            1994
Assets
  Property, Plant, and Equipment:
    At original cost, including $147,467,000 
       and $215,756,000 under construction                               $7,812,670      $7,586,780
    Accumulated depreciation                                             (2,700,077)     (2,529,354)
                                                                          5,112,593       5,057,426

  Investments and Other Assets:
    Subsidiaries consolidated-excess of cost over book 
       equity at acquisition (Note A)                                        15,077          15,077
    Benefit plans' investments (Note A)                                      47,545          35,584
    Other                                                                     2,981           1,950
                                                                             65,603          52,611
  Current Assets:
    Cash and temporary cash investments (Note G)                              3,867           2,765
    Accounts receivable:
       Electric service, net of $13,047,000 and $11,353,000 
          uncollectible allowance (Note A)                                  305,988         250,367
       Other                                                                 15,924           8,175
    Materials and supplies-at average cost:
       Operating and construction                                            86,421          94,478
       Fuel                                                                  71,898          84,199
    Prepaid taxes                                                            45,404          43,880
    Deferred income taxes                                                    28,655          10,916
    Other                                                                    13,164          12,814
                                                                            571,321         507,594
  Deferred Charges:
    Regulatory assets (Note C)                                              602,360         643,791
    Unamortized loss on reacquired debt                                      57,255          40,991
    Other                                                                    38,183          59,812
                                                                            697,798         744,594
  Total                                                                  $6,447,315      $6,362,225
Capitalization and Liabilities
  Capitalization:
    Common stock, other paid-in capital, and retained 
       earnings (Notes D and H)                                          $2,129,917      $2,059,304
    Preferred stock (Note H)                                                170,086         325,286
    Long-term debt and QUIDS (Note H)                                     2,273,226       2,178,472
                                                                          4,573,229       4,563,062
  Current Liabilities:
    Short-term debt (Note I)                                                200,418         126,818
    Long-term debt and preferred stock due within one year (Note H)          43,575          29,200
    Accounts payable                                                        145,422         190,809
    Taxes accrued:
       Federal and state income                                              15,599          13,873
       Other                                                                 54,116          52,782
    Interest accrued                                                         39,752          42,078
    Deferred power costs (Note A)                                            26,735
    Other                                                                    70,912          62,073
                                                                            596,529         517,633
  Deferred Credits and Other Liabilities:
    Unamortized investment credit                                           149,759         158,018
    Deferred income taxes                                                   985,804         972,113
    Regulatory liabilities (Note C)                                          97,970         105,076
    Other                                                                    44,024          46,323
                                                                          1,277,557       1,281,530
  Commitments and Contingencies (Note J)
  Total                                                                  $6,447,315      $6,362,225
See accompanying notes to consolidated financial statements.
<PAGE>
                                  107
</TABLE>

<TABLE>
<CAPTION>
APS
Consolidated Statement of Capitalization
As of December 31
                                                             (Thousands of Dollars)  (Capitalization Ratios)
                                                              1995          1994          1995          1994
Common Stock: 
Common stock of Allegheny Power System, Inc. -
  $1.25 par value per share, 
  260,000,000 shares authorized, 
  outstanding 120,700,809 and 
  <S>                                                          <C>           <C>                <C>           <C>
  119,292,954 shares (Note H)                                  $  150,876    $  149,116
Other paid-in capital                                             995,701       963,269
Retained earnings (Note D)                                        983,340       946,919
    Total                                                       2,129,917     2,059,304         46.6%         45.1%
Preferred Stock of Subsidiaries-cumulative, par value 
  $100 per share, authorized 9,975,688 shares (Note H):
Not subject to mandatory redemption:
                          December 31, 1995
                    Share  Regular Call Price
Series              Oustanding              Per Share
3.60% - 4.80%          650,861            $103.75 to $110.00       65,086        65,086
$5.88 - $7.73          650,000            $102.85 to $102.86       65,000       115,000
$7.92 - $8.80                                                                    80,000

Auction
4.25%      - 4.75%     400,000                $100.00                     40,000        40,000              
  Total  (annual dividend requirements $9,323,269)                       170,086       300,086      3.7%      6.6%
Subject to mandatory redemption:                                                
  $7.16                                                                               26,400
  Total                                                                               26,400
  Less current sinking fund requirement                                               (1,200)
  Total                                                                               25,200            0.6%
Long-Term Debt and QUIDS of Subsidiaries (Note H):
First mortgage bonds:         December 31, 1995
  Maturity                    Interest Rate-%                                               
  1995 - 2000                 5 1/2 - 6 1/2                              293,000     320,000
  2002 - 2004                 6 3/8 - 7 7/8                              175,000     175,000
  2006 - 2007                 7 1/4 - 8                                  120,000     120,000
  2019 - 2020                                                                        245,000
  2021 - 2025                 7 5/8 - 8 7/8                              925,000     680,000
<PAGE>
                                  108

Debentures 
  due 2003 - 2023             5 5/8 - 6 7/8                              150,000     150,000
Quarterly Income Debt 
  Securities due 2025         8.00                                       155,457            
Secured notes 
  due 1998 - 2024             4.95 - 6.875                               368,300     368,300
Unsecured notes 
  due 1996 - 2012             6.10 - 6.40                                 27,495      27,495
Installment purchase 
  obligations due 1998        6.875                                       19,100      19,100
Commercial paper              5.82                                        30,561      41,736
Medium-term notes 
  due 1995 - 1998             5.75 - 7.93                                 76,975      77,975
Unamortized debt 
  discount and 
  premium, net                                                           (24,087)    (18,134)               
    Total  
       (annual interest requirements $167,534,964)                     2,316,801   2,206,472
  Less current maturities                                                (43,575)    (28,000)
Total                                                                  2,273,226   2,178,472        49.7%    47.7%
Total Capitalization                                                  $4,573,229  $4,563,062       100.0%   100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
                                  109
<TABLE>
<CAPTION>
APS
Consolidated Statement of Common Equity
Year Ended December 31
                                                               (Thousands of Dollars)
                                          Shares                       Other        Retained           Total
                                     Outstanding        Common       Paid-In        Earnings          Common
                                        (Note H)         Stock       Capital        (Note D)          Equity
<S>                                  <C>              <C>           <C>             <C>           <C>
Balance at January 1, 1993           113,898,736      $142,373      $836,038        $849,398      $1,827,809
Add:
Sale of common stock, 
  net of expenses:
  Public offerings                     2,400,000         3,000        61,057                          64,057
  Dividend Reinvestment 
    and Stock
    Purchase Plan and 
       Employee Stock
    Ownership and Savings Plan         1,364,846         1,706        34,402                          36,108
Consolidated net income                                                              215,756         215,756
Deduct:
Dividends on common stock of the
  Company (cash)                                                                     187,475         187,475
Expenses related to common 
  stock split                                                            290                             290
Expenses related to subsidiary
  companies' preferred 
  stock transactions                                                     144               6             150
Balance at December 31, 1993         117,663,582      $147,079      $931,063        $877,673      $1,955,815
Add:
Sale of common stock, 
  net of expenses:
  Dividend Reinvestment 
    and Stock
    Purchase Plan and 
       Employee Stock
    Ownership and Savings Plan         1,629,372         2,037        32,988                          35,025
Consolidated net income                                                              263,197         263,197
Deduct:
Dividends on common stock of 
  the Company (cash)                                                                 193,951         193,951
Expenses related to 1993 
  public offerings                                                        79                              79
Expenses related to common 
  stock split                                                            237                             237
Expenses related to subsidiary
  companies' preferred stock 
  transactions                                                           466                             466
Balance at December 31, 1994         119,292,954      $149,116      $963,269        $946,919      $2,059,304
Add:
Sale of common stock, 
  net of expenses:
  Dividend Reinvestment 
  and Stock
  Purchase Plan and 
  Employee Stock
  Ownership and Savings Plan           1,407,855         1,760        32,754                          34,514
Consolidated net income                                                              239,692         239,692
Deduct:
Dividends on common stock of 
  the Company (cash)                                                                 197,764         197,764
Expenses related to subsidiary
  companies' preferred 
  stock transactions                                                     322           5,507           5,829
Balance at December 31, 1995         120,700,809      $150,876      $995,701        $983,340      $2,129,917
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
                                 110

APS
Notes to Consolidated Financial Statements
(These notes are an integral part of the consolidated financial statements.)

Note A: Summary of Significant Accounting Policies

  Allegheny Power System, 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, The Potomac
Edison Company, and West Penn Power Company. The principal markets for the
System's electric sales are in the states of Pennsylvania, West Virginia,
Maryland, Virginia, and Ohio. In 1995, revenues from 50 of its largest electric
utility customers provided approximately 20% of the System's retail revenues.
The Company also has a wholly-owned nonutility subsidiary, AYP Capital, Inc.,
formed in 1994, which is involved primarily in energy-related services,
development of wholesale unregulated power generation, and other energy-related
businesses.    

  The Company and its subsidiaries are subject to regulation by the Securities
and Exchange Commission (SEC), including the Public Utility Holding Company Act
of 1935. The regulated subsidiaries are subject to regulation by various state
bodies having jurisdiction and by the Federal Energy Regulatory Commission
(FERC). 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:

  Beginning in 1994, 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. In 1993, revenues were recorded for 
billings rendered to customers, except for a portion of unbilled revenues in 
West Virginia. 

Deferred Power Costs, Net:

  The costs of fuel, purchased power, and certain other costs, and revenues from
sales to other utilities, 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 are stated at original cost, less contributions
in aid of construction, except for capital leases which are recorded at present
value. Cost includes 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, and pensions,
taxes, and other fringe benefits related to employees engaged in construction.

  The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE>
                                  111
 
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 property, plant, and equipment with
offsetting credits to other income and interest charges. Rates used by the
subsidiaries for computing AFUDC in 1995, 1994, and 1993 averaged 8.73%, 9.00%,
and 9.37%, respectively. AFUDC is not included in the cost of such 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 3.5% of average depreciable property in 1995, 3.3% in 1994, and
3.4% in 1993. The cost of maintenance and of certain replacements of property,
plant, and equipment is charged principally to operating expenses.

Investments:

  The investment in subsidiaries consolidated represents the excess of acquisi-
tion 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 represent the estimated cash surrender values of
purchased life insurance on the Board of Directors and qualifying management
employees under a Directors' pension plan, and an executive life insurance plan
and a supplemental executive retirement plan. Payment of future premiums will
fully fund these benefits.

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. 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
utilizing 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 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 subsidiaries also provide partially contributory medical and life 
insurance plans for eligible retirees and dependents. Medical benefits, which
comprise 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 an amount equal to the annual cost, but not 
more than can be deducted for federal income tax purposes. Funding of these
benefits is made primarily into Voluntary Employee Beneficiary Association 
(VEBA) trust funds in amounts up to that which can be deducted for federal 
<PAGE>
                                 112

income tax purposes. Medical benefits are self-insured; the life insurance plan
is paid through insurance premiums.

Accounting Changes:

  Effective January 1, 1994, the regulated subsidiaries changed their revenue
recognition method to include the accrual of estimated unbilled revenues for
electric services. This change results in a better matching of revenues and
expenses, and is consistent with predominant utility industry practice.
Previously, in accordance with rate making procedures followed in West Virginia,
Monongahela Power Company had recorded a portion of revenues for service 
rendered but unbilled at year-end. The cumulative effect of this accounting
change for years prior to 1994, which is shown separately in the consolidated
statement of income for 1994, resulted in a benefit of $43.4 million (after
related income taxes of $28.9 million), or $.37 per share of common stock. The
effect of the change on 1994 consolidated income before the cumulative effect of
accounting change, as well as 1993 consolidated net income, is not material.

  In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in
1996. The Company does not believe at this time that the adoption of this
standard will have a materially adverse effect on its financial position.

Note B: Restructuring Charges and Asset Write-Offs

  The System is undergoing a reorganization and reengineering process (restruc-
turing) to simplify its management structure and to increase efficiency. As a
consequence of this process, approximately 200 employees, primarily in the Bulk
Power Supply department, have been placed in a staffing force. In January 1996,
these employees were offered an option to resign immediately under a Voluntary
Separation Program (VSP) or to remain employed subject to involuntary separation
(layoff) after one year, if during that year they have not found 
other employment within the System. 

  In 1995, the regulated subsidiaries recorded restructuring charges of $16.0
million ($9.6 million after tax) in other operation expense, for the estimated
liabilities related primarily to staffing force employees' involuntary
separation costs. Further separation costs for these employees will be recorded
in 1996 depending upon those employees who elect early separation under the VSP,
which provides enhanced separation benefits. Additional restructuring costs may
be required as the restructuring process is completed for other departments. 

  In connection with changes in inventory management objectives, the regulated
subsidiaries in 1995 also recorded $7.4 million ($4.5 million after tax)
primarily in maintenance expense for the write-off of obsolete and slow-moving
materials.

  In 1994, the regulated subsidiaries wrote off $9.2 million ($5.3 million after
tax) in other income (expense), net, of previously accumulated costs related to
a potential future power plant site and 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 C: Income Taxes
Details of federal and state income tax provisions are:
<TABLE>
<CAPTION>

(Thousands of Dollars)                                                  1995        1994       1993
Income taxes-current:
  <S>                                                               <C>         <C>        <C>
  Federal                                                           $112,482    $114,263   $110,815
  State                                                               17,375      15,633     20,732
    Total                                                            129,857     129,896    131,547
<PAGE>
                                 113

Income taxes-deferred, net of amortization                            35,279      33,994      6,034
Amortization of deferred investment credit                            (8,260)     (8,310)    (8,422)
Total income taxes                                                   156,876     155,580    129,159
Income taxes-credited (charged) to other 
  income and deductions                                               (2,673)      3,058     (1,029)
Income taxes-charged to accounting change   
  (including state income taxes)                                                 (28,887)
Income taxes-charged to operating income                            $154,203    $129,751   $128,130
</TABLE>

  The total provision for income taxes is different than the amount produced 
by applying the federal income statutory tax rate to financial accounting 
income, as set forth below:

<TABLE>
<CAPTION>
(Thousands of Dollars)                                                  1995       1994        1993
Financial accounting income before cumulative effect of   
  <S>                                                               <C>        <C>         <C>
  accounting change, preferred dividends, and income taxes          $409,110   $369,598    $360,984
Amount so produced                                                  $143,200   $129,400    $126,300
Increased (decreased) for:
  Tax deductions for which deferred tax was not provided:
  Lower tax depreciation                                              13,500      8,000       8,800
  Plant removal costs                                                 (3,500)    (5,600)     (6,000)
  State income tax, net of federal income tax benefit                 16,300     11,600      15,000
  Amortization of deferred investment credit                          (8,260)    (8,310)     (8,422)
  Other, net                                                          (7,037)    (5,339)     (7,548)
  Total                                                             $154,203   $129,751    $128,130
</TABLE>

  Federal income tax returns through 1991 have been examined and
substantially settled.

  At December 31, the deferred tax assets and liabilities were comprised of 
the following:

<TABLE>
<CAPTION>
(Thousands of Dollars)                                                           1995          1994
Deferred tax assets:
  <S>                                                                      <C>           <C> 
  Unamortized investment tax credit                                        $   92,715    $   99,821
  Unbilled revenue                                                             12,187        13,043
  Tax interest capitalized                                                     35,029        33,773
  Contributions in aid of construction                                         21,111        18,742
  Postretirement benefits other than pensions                                   8,671         4,719
  Deferred power costs, net                                                     7,483              
  State tax loss carryback/carryforward                                           532         8,256
  Other                                                                        43,142        36,208
                                                                              220,870       214,562
Deferred tax liabilities:
  Book vs. tax plant basis differences, net                                 1,108,948     1,123,763
  Other                                                                        69,071        51,996
                                                                            1,178,019     1,175,759
Total net deferred tax liabilities                                            957,149       961,197
Add portion above included in current assets                                   28,655        10,916
Total long-term net deferred tax liabilities                               $  985,804    $  972,113
</TABLE>
<PAGE>
                                114
  
  It is expected that regulatory commissions will allow recovery of the deferred
tax liabilities in future years as they are paid, and accordingly, the regulated
subsidiaries have recorded regulatory assets of $559 million and $605 million as
of December 31, 1995 and 1994, respectively. Regulatory liabilities of $98
million and $105 million as of December 31, 1995 and 1994, respectively, have
been recorded in order to reflect the subsidiaries' obligation to pass such tax
benefits on to their customers as the benefits are realized in cash in future
years.


Note D: Dividend Restriction

  Supplemental indentures relating to most outstanding bonds of the regulated 
subsidiaries contain dividend restrictions under the most restrictive of which 
$209,729,000 of consolidated retained earnings at December 31, 1995, 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 E: Pension Benefits

  Net pension costs, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:

<TABLE>
<CAPTION>
(Thousands of Dollars)                                                  1995       1994        1993
<S>                                                                <C>          <C>         <C>
Service cost-benefits earned                                       $  13,695    $14,940     $13,361
Interest cost on projected benefit obligation                         39,901     38,630      37,387
Actual return on plan assets                                        (107,972)       (61)    (89,680)
Net amortization and deferral                                         56,451    (48,983)     43,653
Pension cost                                                           2,075      4,526       4,721
Regulatory reversal (deferral)                                           760      6,681      (1,509)
Net pension cost                                                   $   2,835    $11,207     $ 3,212
</TABLE>
   
  The benefits earned to date and funded status at December 31 using a
measurement date of September 30 were as follows:

<TABLE>
<CAPTION>
(Thousands of Dollars)                                                              1995       1994
Actuarial present value of accumulated benefit obligation earned 
  <S>                                                                           <C>        <C>
  to date (including vested benefit of $432,922,000 and $403,610,000)           $462,733   $429,998
Funded status:
  Actuarial present value of projected benefit obligation                       $568,479   $529,411
  Plan assets at market value, primarily common stocks and fixed     
    income securities                                                            666,740    573,122
  Plan assets in excess of projected benefit obligation                          (98,261)   (43,711)
  Add:
    Unrecognized cumulative net gain from past experience different from 
      that assumed                                                                94,809     52,078
    Unamortized transition asset, being amortized over 14 years beginning
      January 1, 1987                                                             15,736     18,882
  Less unrecognized prior service cost due to plan amendments                      9,510     10,650
  Pension cost liability at September 30                                           2,774     16,599
  Fourth quarter contributions                                                                7,800
Pension liability at December 31                                                $  2,774   $  8,799
</TABLE>
<PAGE>
                                  115 

  In determining the actuarial present value of the projected benefit obligation
at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%,
and 7.25%, and the rates of increase in future compensation levels were 4.5%,
4.75%, and 4.75%, respectively. The expected long-term rate of return on assets
was 9% in each of the years 1995, 1994, and 1993.

Note F: Postretirement Benefits Other Than Pensions
  The cost of postretirement benefits other than pensions (principally health 
care and life insurance) for employees and covered dependents in 1995 and 
1994, a portion of which (about 25% to 30%) was charged to plant 
construction, included the following components:

<TABLE>
<CAPTION>

  (Thousands of Dollars)                                                          1995         1994
  <S>                                                                           <C>         <C>
  Service cost-benefits earned                                                  $ 2,919     $ 3,058
  Interest cost on accumulated postretirement benefit obligation                 14,736      13,732
  Actual (return) loss on plan assets                                            (6,378)        135
  Amortization of unrecognized transition obligation                              7,272       7,300
  Other net amortization and deferral                                             5,163         206
  Postretirement cost                                                            23,712      24,431
  Regulatory reversal (deferral)                                                    492      (3,908)
  Net postretirement cost                                                       $24,204     $20,523
</TABLE>

   The benefits earned to date and funded status at December 31 using a 
measurement date of September 30 were as follows:

<TABLE>
<CAPTION>
(Thousands of Dollars)                                                             1995        1994
Accumulated postretirement benefit obligation:
  <S>                                                                          <C>         <C>
  Retirees                                                                     $115,965    $118,518
  Fully eligible employees                                                       25,994      24,791
  Other employees                                                                53,883      52,914
    Total obligation                                                            195,842     196,223
Plan assets at market value, in common stocks, fixed income securities, 
  and short-term investments                                                     39,875      19,791
Accumulated postretirement benefit obligation in excess
   of plan assets                                                               155,967     176,432
Less:
  Unrecognized cumulative net loss from past experience different 
    from that assumed                                                            19,529      34,190
  Unrecognized transition obligation, being amortized over 20 years
    beginning January 1, 1993                                                   123,628     130,900
Postretirement benefit liability at September 30                                 12,810      11,342
Fourth quarter contributions and benefit payments                                 9,313       5,826
Postretirement benefit liability at December 31                                $  3,497    $  5,516
</TABLE>
<PAGE>
                                  116
 
    In determining the APBO at September 30, 1995, 1994, and 1993, the discount
rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future
compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995 expected
long-term rate of return on assets was 8.25% net of tax. For measurement
purposes, a health care trend rate of 8% for 1996, declining 1% each year
thereafter to 6.5% in the year 1998 and beyond, and plan provisions which limit
future medical and life insurance benefits, were assumed. Increasing the assumed
health care trend rate by 1% in each year would increase the APBO at 
December 31, 1995, by $12.8 million and the aggregate of the service 
and interest cost components of net periodic postretirement benefit 
cost for 1995 by $1.3 million. 

Note G: Fair Value of Financial Instruments

   The carrying amounts and estimated fair value of
financial instruments at December 31 were as follows: 

<TABLE>
<CAPTION>
                                                                 1995                   1994
                                                        Carrying        Fair    Carrying       Fair
(Thousands of Dollars)                                    Amount       Value      Amount      Value
Assets:
   <S>                                                <C>         <C>           <C>      <C>
   Temporary cash investments                         $      425  $      425    $     73 $       73
   Life insurance contracts                               47,545      47,545      35,584     33,884
Liabilities:
   Short-term debt                                       200,418     200,418     126,818    126,818
   Long-term debt and QUIDS                            2,340,888   2,409,080   2,224,606  2,114,871
</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 long-term debt and QUIDS was estimated based on actual market
prices or market prices of similar issues. The fair value of the life insurance
contracts in Note A was estimated based on cash surrender value. The Company 
does not have any financial instruments held or issued for trading purposes.

  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.

Note H: Capitalization
Common Stock:

  In November 1993, the common shareholders approved a two-for-one split of the
Company's common stock effective November 4, 1993. The stock split reduced the
par value of the common stock from $2.50 per share to $1.25 per share and
increased the number of authorized shares of common stock from 130,000,000 to
260,000,000. The number of common stock shares outstanding and per share
information for all periods reflect the two-for-one split.

Preferred Stock:

  In 1995, the regulated subsidiaries refunded $130 million of preferred stock
with dividend rates between 7% and 8.8%, with the proceeds from the issuance of
Quarterly Income Debt Securities (QUIDS) described below. 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 Power
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.
<PAGE>
                                 117
Long-Term Debt and QUIDS:

  Maturities for long-term debt for the next five years are: 1996, $43,575,000;
1997, $26,900,000; 1998, $185,400,000; 1999, $34,861,000; and 2000, 
$145,300,000. 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. 

  In 1995, the regulated subsidiaries issued $155.5 million of 8% 30-year QUIDS
to refund preferred stock. Under certain circumstances the interest payments may
be deferred for a period of up to 20 consecutive quarters. 

  Commercial paper borrowings issuable by Allegheny Generating Company are 
backed by a revolving credit agreement with a group of seven banks which 
provides for loans of up to $50 million at any one time outstanding through 
1999. Each bank has the option to discontinue its loans after 1999 upon three
years' prior written notice. Without such notice, the loans are automatically
extended for one year. However, to the extent that funds are available from the
Company and its regulated subsidiaries, Allegheny Generating Company borrowings
are made through an internal money pool as described in Note I.

Note I: 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, 1995, unused lines of
credit with banks were $173,350,000. In addition to bank lines of credit, an
internal money pool accommodates intercompany short-term borrowing needs, to 
the extent that certain of the companies have funds available. In January 1994,
a multi-year credit program was established which provides that the regulated
subsidiaries may borrow up to $300 million on a standby revolving credit basis.
Short-term debt outstanding for 1995 and 1994 consisted
of:

<TABLE>
<CAPTION>
(Thousands of Dollars)                                                  1995                   1994
Balance at end of year:
  <S>                                                       <C>                    <C>      
  Commercial Paper                                          $148,768 - 5.97%       $103,968 - 6.06%
  Notes Payable to Banks                                      51,650 - 5.96%         22,850 - 5.92%
Average amount outstanding during the year:
  Commercial Paper                                            97,689 - 6.08%         67,290 - 4.25%
  Notes Payable to Banks                                      21,134 - 6.00%         33,273 - 4.17%
</TABLE>

Note J: Commitments and Contingencies
Construction Program:

  The regulated subsidiaries have entered into commitments for their 
construction programs, for which expenditures are estimated to be $279 
million for 1996 and $305 million for 1997. Through 1999, annual 
construction expenditures are not expected to significantly exceed 1996 
estimated levels. Construction expenditure levels in 2000 and beyond will 
depend upon future generation requirements, as well as the strategy eventually 
selected for complying with Phase II of the Clean Air Act Amendments of 1990.

Nonutility Investments:

  AYP Capital, Inc. has entered into an agreement with Duquesne Light Company,
subject to regulatory approvals, to purchase its 50% interest in Unit No. 1 of
the Fort Martin Power Station for approximately $170 million. AYP Capital 
intends to operate the unit as an exempt wholesale generator and sell the output
at market rates. Necessary regulatory approvals will likely take several months,
and AYP Capital expects a closing by late 1996.
<PAGE>
                                 118
                                
  AYP Capital has committed to invest up to $10 million in two limited partner-
ships formed to invest in emerging electrotechnologies that promote the
efficient use of electricity and improve the environment, and to invest in and
develop electric energy opportunities in Latin America. As of December 31, 1995,
AYP Capital's investments totaled $1.1 million.

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 affect adversely the lead time, size, and siting of future
generating stations, increase the complexity and cost of pollution control
equipment, and otherwise add to the cost of future operations. In the normal
course of business, the companies become involved in various legal proceedings.
The companies do not believe that the ultimate outcome of these proceedings 
will have a material effect on their financial position.

  The regulated subsidiaries previously reported that the Environmental Protec-
tion Agency (EPA) had identified them and approximately 875 others as potential-
ly responsible parties in a Superfund site subject to cleanup. The regulated
subsidiaries have also been named as defendants along with multiple other
defendants in pending asbestos cases involving one or more plaintiffs. 
The 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.
<PAGE>
<TABLE>
<CAPTION>
                                 119
Monongahela
STATEMENT OF INCOME 
                                                                          YEAR ENDED DECEMBER 31
                                                                       1995        1994        1993
                                                                          (Thousands of Dollars)

Electric Operating Revenues:  
  <S>                                                                <C>         <C>         <C>
  Residential.....................................................   $209,065    $190,861    $185,141
  Commercial......................................................    124,457     116,201     110,762
  Industrial......................................................    212,427     202,181     187,669           
  Nonaffiliated utilities.........................................     90,916      79,701      86,032
  Other, including affiliates.....................................     85,617      91,186      72,240
    Total Operating Revenues......................................    722,482     680,130     641,844

Operating Expenses:
  Operation:
    Fuel..........................................................    136,695     150,088     144,408
    Purchased power and exchanges, net............................    176,380     161,839     155,602  
    Deferred power costs, net (Note A)............................     19,647       7,604      (2,489)
    Other (Note B)................................................     81,136      74,907      66,506 
  Maintenance (Note B)............................................     74,418      69,389      67,770
  Depreciation....................................................     57,864      57,952      56,056
  Taxes other than income taxes...................................     38,551      40,404      34,076
  Federal and state income taxes (Note C).........................     41,834      30,712      33,612
    Total Operating Expenses......................................    626,525     592,895     555,541
    Operating Income..............................................     95,957      87,235      86,303

Other Income and Deductions:
  Allowance for other than borrowed funds used
    during construction (Note A)..................................        446       1,566       3,092
  Other income, net...............................................      9,235       7,911       7,203
    Total Other Income and Deductions.............................      9,681       9,477      10,295
    Income Before Interest Charges................................    105,638      96,712      96,598

Interest Charges:
  Interest on long-term debt......................................     37,244      35,187      35,555
  Other interest..................................................      2,628       2,969       2,033
  Allowance for borrowed funds used during
    construction (Note A).........................................       (947)     (1,380)     (2,688)
    Total Interest Charges........................................     38,925      36,776      34,900

Income Before Cumulative Effect of
  Accounting Change...............................................     66,713      59,936      61,698

Cumulative Effect of Accounting Change,
  net (Note A)....................................................                  7,945            

Net Income........................................................   $ 66,713    $ 67,881    $ 61,698

Monongahela
STATEMENT OF RETAINED EARNINGS

Balance at January 1..............................................   $198,626    $185,486    $178,084
Add:
  Net income......................................................     66,713      67,881      61,698
                                                                      265,339     253,367     239,782

Deduct:
  Dividends on capital stock:
    Preferred stock...............................................      6,555       7,260       4,458
    Common stock..................................................     48,660      47,481      49,838
  Charge on redemption of preferred stock.........................      1,363                        
      Total Deductions............................................     56,578      54,741      54,296

Balance at December 31 (Note D)...................................   $208,761    $198,626    $185,486

See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                  120

Monongahela
STATEMENT OF CASH FLOWS 
                                                                          YEAR ENDED DECEMBER 31
                                                                       1995        1994        1993
                                                                          (Thousands of Dollars)

Cash Flows from Operations:   
  <S>                                                                <C>         <C>         <C>
  Net income......................................................   $ 66,713    $ 67,881    $ 61,698
  Depreciation....................................................     57,864      57,952      56,056
  Deferred investment credit and income taxes, net................      3,519       3,350       6,352
  Deferred power costs, net.......................................     19,647       7,604      (2,489)
  Unconsolidated subsidiaries' dividends in excess of earnings....      2,403       1,647       1,971
  Allowance for other than borrowed funds used
    during construction...........................................       (446)     (1,566)     (3,092)
  Cumulative effect of accounting change before
    income taxes (Note A).........................................                (13,279)
  Changes in certain current assets and liabilities:
    Accounts receivable, net, excluding cumulative effect
      of accounting change (Note A)...............................    (11,222)      4,756      (8,412)
    Materials and supplies........................................      6,639      (5,944)     12,917
    Accounts payable..............................................     (3,373)     (2,044)        129
    Taxes accrued.................................................      8,506        (950)     (5,674)
    Interest accrued..............................................     (2,350)        286         290
  Other, net......................................................        586       1,731       3,296
                                                                      148,486     121,424     123,042


Cash Flows from Investing:
  Construction expenditures.......................................    (75,458)   (103,975)   (140,748)
  Allowance for other than borrowed
    funds used during construction................................        446       1,566       3,092
                                                                      (75,012)   (102,409)   (137,656)


Cash Flows from Financing:
  Sale of preferred stock.........................................                 49,635
  Retirement of preferred stock...................................    (41,406)    
  Issuance of long-term debt and QUIDS............................    132,137       9,718      82,331
  Retirement of long-term debt....................................    (99,403)                (68,471)
  Short-term debt, net............................................     (6,702)    (26,530)     63,100
  Notes payable to affiliates.....................................     (2,900)      2,900      (8,030)
  Dividends on capital stock:
    Preferred stock...............................................     (6,555)     (7,260)     (4,458)
    Common stock..................................................    (48,660)    (47,481)    (49,838)
                                                                      (73,489)    (19,018)     14,634


Net Change in Cash and
  Temporary Cash Investments (Note H).............................        (15)         (3)         20
Cash and Temporary Cash Investments at January 1..................        132         135         115
Cash and Temporary Cash Investments at December 31................   $    117    $    132    $    135


Supplemental Cash Flow Information
  Cash paid during the year for:
    Interest (net of amount capitalized)..........................   $ 42,394    $ 35,347    $ 33,941
    Income taxes..................................................     30,696      29,939      30,982


See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                 121

Monongahela 
BALANCE SHEET                                                                 
                                                                                   DECEMBER 31
ASSETS                                                                        1995            1994
                                                                             (Thousands of Dollars)
Property, Plant, and Equipment:
  At original cost, including $29,443,000 and
    <S>                                                                    <C>             <C>
    $35,856,000 under construction......................................   $1,821,613      $1,763,533
  Accumulated depreciation..............................................     (747,013)       (701,271)
                                                                            1,074,600       1,062,262
Investments:
  Allegheny Generating Company--common stock
    at equity (Note E)..................................................       57,821          60,137
  Other.................................................................          422             509
                                                                               58,243          60,646
Current Assets:
  Cash..................................................................          117             132
  Accounts receivable:
    Electric service, net of $2,267,000 and 
      $1,912,000 uncollectible allowance (Note A).......................       71,759          62,631
    Affiliated and other................................................       11,577           9,483
  Materials and supplies--at average cost:
    Operating and construction..........................................       21,297          24,563
    Fuel................................................................       20,305          23,678
  Prepaid taxes.........................................................       17,778          17,599
  Deferred income taxes.................................................        7,972           1,094
  Other.................................................................        4,857           6,086
                                                                              155,662         145,266
Deferred Charges:
  Regulatory assets (Note C)............................................      164,900         186,109
  Unamortized loss on reacquired debt...................................       16,174          11,500
  Other.................................................................       11,012          10,700
                                                                              192,086         208,309
Total...................................................................   $1,480,591      $1,476,483

CAPITALIZATION AND LIABILITIES
Capitalization:
  Common stock, other paid-in capital, and retained
    earnings (Notes D and I)............................................   $  505,752      $  495,693
  Preferred stock (Note I)..............................................       74,000         114,000
  Long-term debt and QUIDS (Note I).....................................      489,995         470,131
                                                                            1,069,747       1,079,824
Current Liabilities:
  Short-term debt (Note J)..............................................       29,868          36,570
  Long-term debt due within one year (Note I)...........................       18,500
  Notes payable to affiliates (Note J)..................................                        2,900
  Accounts payable......................................................       24,582          31,871
  Accounts payable to affiliates........................................        9,937           6,021
  Taxes accrued:
    Federal and state income............................................        8,068             118
    Other...............................................................       20,749          20,193
  Deferred power costs (Note A).........................................       14,202
  Interest accrued......................................................        8,577          10,927
  Other.................................................................       16,196          16,455
                                                                              150,679         125,055
Deferred Credits and Other Liabilities:
  Unamortized investment credit.........................................       22,590          24,734
  Deferred income taxes.................................................      206,616         216,264
  Regulatory liabilities (Note C).......................................       20,183          19,974
  Other.................................................................       10,776          10,632
                                                                              260,165         271,604
Commitments and Contingencies (Note K)                                                           
Total...................................................................   $1,480,591      $1,476,483


See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                 122

Monongahela 
STATEMENT OF CAPITALIZATION 
As of December 31
                                                                 (Thousands of Dollars) (Capitalization Ratios)
                                                                     1995          1994          1995    1994
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 (Note I)......................                    2,441          2,517
  Retained earnings (Note D)..........................                  208,761        198,626
      Total...........................................                  505,752        495,693    47.3%  45.9%

Preferred Stock 
  Cumulative preferred stock--par value $100 per share,
    authorized 1,500,000 shares, outstanding as follows
    (Note I):

                   December 31, 1995    
                                Regular
                  Shares      Call Price    Date of
    Series     Outstanding    Per Share      Issue 
    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
    $7.36 E...                                1968                                       5,000
    $8.80 G...                                1971                                       5,000
    $7.92 H...                                1972                                       5,000
    $7.92 I...                                1973                                      10,000
    $8.60 J...                                1976                                      15,000
    $7.73 L...   500,000         100.00       1994                       50,000         50,000
      Total (annual dividend requirements $5,037,000)                    74,000        114,000      6.9   10.6

Long-Term Debt and QUIDS (Note I):
  First mortgage    Date of        Date       Date
  bonds:             Issue      Redeemable    Due 
    5-1/2% ...        1966         1996       1996                       18,000         18,000
    6-1/2% ...        1967         1996       1997                       15,000         15,000
    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
    8-7/8% ...        1989                                                              70,000
    8-5/8% ...        1991         2001       2021                       50,000         50,000
    8-1/2% ...        1992         1997       2022                       65,000         65,000
    8-3/8% ...        1992         2002       2022                       40,000         40,000
    7-5/8% ...        1995         2005       2025                       70,000      

                                   December 31, 1995
                                   Interest Rate - %  
  Quarterly Income Debt Securities
    due 2025......................     8.00                              40,000
  Secured notes due 1998-2024.....     5.95-6.875                       74,050         74,050
  Unsecured notes due 1996-2012...     6.30-6.40                         7,560          7,560
  Installment purchase
    obligations due 1998..........       6.875                           19,100         19,100
  Unamortized debt discount and premium, net..........                   (5,215)        (3,579)
      Total (annual interest requirements $37,475,131)                  508,495        470,131
  Less current maturities.............................                  (18,500)
      Total...........................................                  489,995        470,131     45.8   43.5

Total Capitalization..................................               $1,069,747     $1,079,824    100.0% 100.0%


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                 123
Monongahela       
NOTES TO FINANCIAL STATEMENTS
(These notes re an integral part of the financial statements)

Note A - Summary of Significant
Accounting Policies:

  The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and 
is a part of the Allegheny Power integrated electric utility system (the 
System).

  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.  This procedure has been utilized 
for a number of years in West Virginia, as required by the Public
Service Commission of West Virginia, and was adopted for all revenues 
beginning in 1994.

DEFERRED POWER COSTS, NET:
  The costs of fuel, purchased power, and certain other costs, and revenues 
from sales to other companies, 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 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.  Cost includes 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, and pensions,taxes, and other fringe benefits related 
to employees engaged in construction.

  The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE>
                                  124

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
1995, 1994, and 1993 were 7.29%, 8.16%, and 8.69%, respectively.  AFUDC 
is not included in the cost of such 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 3.4%, 3.6%, and 3.8% of average depreciable property 
in 1995, 1994, and 1993, respectively.  The cost of maintenance and of 
certain replacements of property, plant, and equipment is charged 
principally to operating expenses.

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 utilizing 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 in the System 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 also provides partially contributory medical and life insurance 
plans for eligible retirees and dependents.  Medical benefits, which 
comprise 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 an amount equal to the annual cost, 
<PAGE>
                                 125

but not more than can be deducted for federal income tax purposes.
Funding of these benefits is made primarily into Voluntary Employee 
Beneficiary Association (VEBA) trust funds in amounts up to that which can be 
deducted for federal income tax purposes.  Medical benefits are self-
insured; the life insurance plan is paid through insurance premiums.

ACCOUNTING CHANGES:
  Effective January 1, 1994, the Company changed its revenue recognition 
method to include the accrual of estimated unbilled revenues for 
electric services.  This change results in a better matching of revenues and
expenses, and is consistent with predominant utility industry practice and 
the practice used in West Virginia for a number of years.  The cumulative 
effect of this accounting change for the years prior to the adoption of
this practice, including West Virginia, is shown separately in the statement
of income for 1994, and resulted in a benefit of $7.9 million (after
related income taxes of $5.4 million). The effect of the change on 1994
income before the cumulative effect of accounting change, as well as 1993 net 
income, is not material.

  In March 1995, the Financial Accounting Standards Board issued Statement of 
Financial Accounting Standards (SFAS) No. 121, "Accounting for the 
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996.  The Company does not believe at this time that the 
adoption of this standard will have a materially adverse 
effect on its financial position.

Note B - Restructuring Charges and Asset Write-Offs:

  The System is undergoing a reorganization and reengineering process 
(restructuring) to simplify its management structure and to increase 
efficiency.  As a consequence of this process, approximately 200 employees, 
primarily in the System's Bulk Power Supply department, have been placed in a 
staffing force.  In January 1996, these employees were offered an option 
to resign immediately under a Voluntary Separation Program (VSP) or to remain
employed subject to involuntary separation (layoff) after one year, if during
that year they have not found other employment within the System.

  In 1995, the Company recorded restructuring charges of $4.1 million 
($2.5 million after tax) in other operation expense, for its share of the 
estimated liabilities related primarily to staffing force employees' 
involuntary separation costs. Further separation costs for these
employees will be recorded in 1996 depending upon those employees who elect
early separation under the VSP, which provides enhanced separation 
benefits.  Additional restructuring costs may be required as the
restructuring process is completed for other departments.

  In connection with changes in inventory management objectives, the Company 
in 1995 also recorded $1.4 million ($.8 million after tax) primarily in 
maintenance expense for the write-off of obsolete and slow-moving materials.
<PAGE>

                                 126
Note C - Income Taxes:
<TABLE>
<CAPTION>

  Details of federal and state income tax provisions are:

                                          1995         1994         1993
                                              (Thousands of Dollars)
Income taxes--current:
  <S>                                   <C>          <C>          <C>
  Federal.............................  $30,236      $27,793      $25,618
  State...............................    8,707        4,841        1,692
    Total.............................   38,943       32,634       27,310
Income taxes--deferred, net of
  amortization........................    5,664        5,499        8,517
Amortization of deferred
  investment credit...................   (2,145)      (2,149)      (2,165)
    Total income taxes................   42,462       35,984       33,662
Income taxes--credited (charged)
  to other income and deductions......     (628)          63          (50)
Income taxes--charged to accounting
  change (including state income
  taxes)..............................                (5,335)            
Income taxes--charged to operating
  income..............................  $41,834       $30,712      $33,612
</TABLE>

  The total provision for income taxes is different than the amount produced 
by applying the federal income statutory tax rate to financial 
accounting income, as set forth below:

<TABLE>
<CAPTION>
                                          1995         1994         1993
                                              (Thousands of Dollars)
Financial accounting income before
  cumulative effect of accounting
  <S>                                   <C>          <C>          <C>
  change and income taxes.............  $108,547     $90,648      $95,310
Amount so produced....................  $ 38,000     $31,700      $33,400
Increased (decreased) for:
  Tax deductions for which deferred
    tax was not provided:
      Lower tax depreciation..........     4,300       5,400        5,700
      Plant removal costs.............    (1,500)     (2,100)      (3,000)
  State income tax, net of federal
    income tax benefit................     4,800       3,500        3,800
  Amortization of deferred
    investment credit.................    (2,145)     (2,149)      (2,165)
  Equity in earnings of
    subsidiaries......................    (2,500)     (2,800)      (2,500)
  Adjustments of provisions
    for prior years...................     2,431      (1,900)         400
  Other, net..........................    (1,552)       (939)      (2,023)
      Total...........................  $ 41,834     $30,712      $33,612
</TABLE>

  Federal income tax returns through 1991 have been examined and substantially 
  settled.
<PAGE>
                                   127
<TABLE>
<CAPTION>
  At December 31, the deferred tax assets and liabilities were comprised of 
the following:

                                                    1995           1994
                                                  (Thousands of Dollars)
Deferred tax assets:
  <S>                                             <C>            <C>
  Unamortized investment tax credit............   $ 15,133       $ 16,604
  Tax interest capitalized.....................      4,759          4,907
  Deferred power costs.........................      7,483
  Contributions in aid of construction.........      2,488          2,223
  Advances for construction....................      1,939          1,771
  Other........................................     12,046         10,747
                                                    43,848         36,252
Deferred tax liabilities:
  Book vs. tax plant basis differences, net....    209,527        228,997
  Other........................................     32,964         22,425
                                                   242,491        251,422
Total net deferred tax liabilities.............    198,643        215,170
Add portion above included in               
  current assets...............................      7,973          1,094
Total long-term net deferred                
  tax liabilities..............................   $206,616       $216,264
</TABLE>

  It is expected that regulatory commissions will allow recovery of the 
deferred tax liabilities in future years as they are paid, and accordingly, 
the Company has recorded regulatory assets of $152 million and $174 million
as of December 31, 1995 and 1994, respectively.  Regulatory liabilities of 
$20 million as of December 31, 1995 and 1994, respectively, have been 
recorded in order to reflect the Company's obligation to pass such tax
benefits on to its customers as the benefits are realized in cash in future 
years.

Note D - Dividend Restriction:

  Supplemental indentures relating to most outstanding bonds of the Company 
contain dividend restrictions under the most restrictive of which 
$76,384,000 of retained earnings at December 31, 1995, 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 E - 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 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 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.
<PAGE>
                                 128

The only component which changes is the return on equity (ROE).  In December 
1991, AGC filed for a continuation of the existing ROE of 11.53% and other 
interested parties filed to reduce the ROE to 10%.  A recommendation
was issued by an Administrative Law Judge on December 22, 1994, to dismiss the 
joint complaint.  A settlement agreement for both cases was filed 
with the FERC on January 12, 1995, which would reduce AGC's ROE from 11.53%
to 11.13% for the period from March 1, 1992, through December 31, 1994, and 
increase AGC's ROE to 11.2% for the period from January 1, 1995, through 
December 31, 1995.  This settlement was approved by the FERC on March 23,
1995.  Refunds were made by AGC of any revenues collected between March 1, 
1992 and March 23, 1995 in excess of these levels.  A second settlement 
has been negotiated to address AGC's ROE after 1995.  On December 21, 1995,
AGC submitted the new settlement to the FERC.  Interested parties representing
less than 2% of AGC's eventual revenues have filed exceptions to the 
settlement.  Under the terms of the settlement, AGC's ROE for 1996 would
be 11%, and set by formula in 1997 and 1998 based primarily on changes in 
interest rates.

  Following is a summary of financial information for AGC: 

                                                        December 31    
                                                    1995           1994
                                                  (Thousands of Dollars)
Balance sheet information:
  Property, plant, and equipment...............   $677,857       $680,749
  Current assets...............................      7,586          5,991
  Deferred charges.............................     24,844         27,496
    Total assets...............................   $710,287       $714,236

  Total capitalization.........................   $463,862       $489,894
  Current liabilities..........................     11,892          6,484
  Deferred credits.............................    234,533        217,858
    Total capitalization and liabilities.......   $710,287       $714,236

<TABLE>
<CAPTION>
                                                 Year Ended December 31
                                            1995        1994         1993
                                                (Thousands of Dollars)
Income statement information:
  <S>                                   <C>          <C>          <C>
  Electric operating revenues.........  $86,970      $91,022      $90,606
  Operation and maintenance
    expense...........................    5,740        6,695        6,609
  Depreciation........................   17,018       16,852       16,899
  Taxes other than income taxes.......    5,091        5,223        5,347
  Federal income taxes................   13,552       14,737       13,262
  Interest charges....................   18,361       17,809       21,635
  Other income, net...................      (16)         (11)        (328)
    Net income........................  $27,224      $29,717      $27,182
</TABLE>

  The Company's share of the equity in earnings above was $7.4 million, $8.0 
million, and $7.3 million for 1995, 1994, and 1993, respectively, and is 
included in other income, net, on the Statement of Income.
<PAGE>
                                 129

Note F - Pension Benefits:

  The Company's share of net pension costs under the System's pension plan, a
portion of which (about 25% to 30%) was charged to plant construction, 
included the following components:

                                          1995         1994         1993
                                              (Thousands of Dollars)

Service cost - benefits earned........  $ 3,340      $ 3,677      $ 3,198
Interest cost on projected
  benefit obligation..................    9,375        9,045        8,577
Actual (return) loss on           
  plan assets.........................  (27,269)          87      (22,606)
Net amortization and deferral.........   15,183      (11,563)      12,048
Pension cost..........................      629        1,246        1,217
Regulatory reversal (deferral)........                 3,718       (1,179)
Net pension cost......................  $   629      $ 4,964      $    38


  The benefits earned to date and funded status of the Company's share of the 
System plan at December 31 using a measurement date of September 30 
were as follows:

                                                    1995           1994
                                                  (Thousands of Dollars)
Actuarial present value of accumulated
  benefit obligation earned to date
  (including vested benefit of 
  $100,006,000 and $92,823,000)................   $107,672       $ 99,605
Funded status:
  Actuarial present value of projected
    benefit obligation.........................   $133,485       $123,935
  Plan assets at market value, primarily
    common stocks and fixed income securities..    156,554        134,166
  Plan assets in excess of projected
    benefit obligation.........................    (23,069)       (10,231)
  Add:
    Unrecognized cumulative net gain from 
      past experience different from
      that assumed.............................     24,151         13,969
    Unamortized transition asset, being
      amortized over 14 years beginning
      January 1, 1987..........................      3,242          3,988
  Less unrecognized prior service
    cost due to plan amendments................      2,195          2,471
  Pension cost liability at September 30.......      2,129          5,255
  Fourth quarter contributions.................                     1,829
  Pension liability at December 31.............   $  2,129       $  3,426


  The foregoing includes the Company's portion of amounts applicable to 
employees at power stations which are owned jointly with affiliates.

  In determining the actuarial present value of the projected benefit
obligation at September 30, 1995, 1994, and 1993, the discount rates used
were 7.5%, 7.75%, and 7.25%, and the rates of increase in future 
<PAGE>
                                  130

compensation levels were 4.5%, 4.75%, and 4.75%, respectively.  The expected 
long-term rate of return on assets was 9% in each of the years 1995, 1994,
and 1993.

Note G - Postretirement Benefits Other
Than Pensions:

  The cost of postretirement benefits other than pensions (principally health 
care and life insurance) for employees and covered dependents in 1995 
and 1994, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:

                                                     1995          1994
                                                   (Thousands of Dollars)

Service cost - benefits earned..................   $   741       $   764
Interest cost on accumulated
  postretirement benefit obligation.............     3,939         3,655
Actual (return) loss on plan assets.............    (1,702)           38
Amortization of unrecognized
  transition obligation.........................     1,783         1,783
Other net amortization and deferral.............     1,376            50
Postretirement cost.............................     6,137         6,290
Regulatory reversal (deferral)..................       345        (3,450)
Net postretirement cost.........................   $ 6,482       $ 2,840


  The benefits earned to date and funded status of the Company's share of the 
System plan at December 31 using a measurement date of September 30
were as follows:
                                                     1995          1994
                                                   (Thousands of Dollars)

Accumulated postretirement benefit obligation
  (APBO):
    Retirees....................................   $32,249       $33,528
    Fully eligible employees....................     5,221         4,947
    Other employees.............................    14,177        14,458
      Total obligation..........................    51,647        52,933
Plan assets at market value, in common stocks,
  fixed income securities, and short-term
  investments...................................    10,515         5,338
Accumulated postretirement benefit
  obligation in excess of plan assets...........    41,132        47,595
Less:
  Unrecognized cumulative net loss from past
    experience different from that assumed......     7,559        12,752
  Unrecognized transition obligation,
    being amortized over 20 years
    beginning January 1, 1993...................    30,378        32,368
Postretirement benefit liability
  at September 30...............................     3,195         2,475
Fourth quarter contributions
  and benefit payments..........................     2,046         1,437
Postretirement benefit liability
  at December 31................................   $ 1,149       $ 1,038
<PAGE>
                                  131

In determining the APBO at September 30, 1995, 1994, and 1993, the discount 
rates used were 7.5%, 7.75%, and 7.25% and the rates of increase in future 
compensation levels were 4.5%, 4.75%, and 4.75%, respectively.  The 1995
expected long-term rate of return on assets was 8.25% net of tax.  
For measurement purposes, a health care trend rate of 8% for 1996, declining 
1% each year thereafter to 6.5% in the year 1998 and beyond, and plan 
provisions which limit future medical and life insurance benefits, were 
assumed.  Increasing the assumed health care trend rate by 1% in each year 
would increase the APBO at December 31, 1995, by $3.4 million and the 
aggregate of the service and interest cost components of net periodic 
postretirement benefit cost for 1995 by $.3 million.

Note H - Fair Value of Financial Instruments:

  The carrying amounts and estimated fair value of financial instruments at 
December 31 were as follows:

                                  1995                      1994       
                         Carrying       Fair       Carrying       Fair
                          Amount        Value       Amount        Value
                                     (Thousands of Dollars)

Liabilities:
  Short-term debt.....   $ 29,868     $ 29,868     $ 36,570     $ 36,570
  Long-term debt and
    QUIDS.............    513,710      540,387      473,710      458,714


  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 does not have any financial instruments 
held or issued for trading purposes.

  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.

Note I - Capitalization:

COMMON STOCK AND OTHER PAID-IN CAPITAL:
  Other paid-in capital decreased $76,000 in 1995 as a result of preferred
stock transactions and $477,000 in 1994 as a result of underwriting fees 
and commissions associated with the Company's sale of $50 million of
preferred stock.  

PREFERRED STOCK:
  In 1995, the Company refunded $40 million of preferred stock with dividend 
rates between 7.36% and 8.80%, with the proceeds from the issuance of 
Quarterly Income Debt Securities (QUIDS) described below.  In May 1994, the
Company issued 500,000 shares of Series L, $7.73 cumulative preferred stock 
with par value of $100 per share. This Series is not redeemable prior 
to August 1, 2004.  All of the preferred stock is entitled on voluntary
liquidation to its then current call price and on involuntary liquidation to 
$100 a share.
<PAGE>
                                   132

LONG-TERM DEBT AND QUIDS:
  Maturities for long-term debt for the next five years are:  1996, 
$18,500,000; 1997, $15,500,000; 1998, $20,100,000; 1999, $1,000,000; 
and 2000, $66,000,000.  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.

  In 1995, the Company sold $70 million of 7-5/8% 30-year first mortgage 
bonds to refund a $70 million 8-7/8% issue due in 2019.  The Company also 
issued $25 million of 6.15% 20-year tax-exempt notes to refund a $25
million 7-3/4% issue.

  In 1995, the Company issued $40 million of 8% 30-year QUIDS to refund 
preferred stock.  QUIDS may not be redeemed until the year 2000.  Under certain 
circumstances the interest payments may be deferred for a period
of up to 20 consecutive quarters.

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 $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 internal money pool 
accommodates intercompany short-term borrowing needs, to the extent that 
certain of the companies have funds available.  In January 1994, the 
Company and its affiliates jointly established an aggregate $300 million 
multi-year credit program which provides that the Company may borrow up to 
$81 million on a standby revolving credit basis.  Short-term debt 
outstanding for 1995 and 1994 consisted of:

                                              1995               1994
                                              (Thousands of Dollars)
Balance at end of year:
    Commercial Paper..................   $22,368-6.09%      $24,970-6.21%
    Notes Payable to Banks............     7,500-6.00%       11,600-6.43%
    Money Pool........................                        2,900-5.49%
Average amount outstanding
  during the year:
    Commercial Paper..................     8,699-5.96%        8,751-3.58%
    Notes Payable to Banks............     7,153-5.99%       15,283-3.89%
    Money Pool........................     3,116-5.85%       11,363-4.51%


Note K - Commitments and Contingencies:

CONSTRUCTION PROGRAM:
  The Company has entered into commitments for its construction program, 
for which expenditures are estimated to be $66 million for 1996 and 
$75 million for 1997.  Through 1999, annual construction expenditures are 
not expected to significantly exceed 1996 estimated levels.  Construction 
expenditure levels in 2000 and beyond will depend upon future generation
requirements, as well as the strategy eventually selected for complying with 
Phase II of the Clean Air Act Amendments of 1990.
<PAGE>
                                 133
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 affect adversely the lead time, size, and siting of 
future generating stations, increase the complexity and cost of pollution 
control equipment, and otherwise add to the cost of future operations.
In the normal course of business, the Company becomes 
involved in various legal proceedings.  The Company does not believe that 
the ultimate outcome of these proceedings will have a material 
effect on its financial position.

  The Company previously reported that the Environmental Protection Agency 
had identified it and its affiliates and approximately 875 others as 
potentially responsible parties in a Superfund site subject to cleanup.  The
Company has also been named as a defendant 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 their financial position.

  The Company is guarantor as to 27% of a $50 million revolving credit 
agreement of AGC, which in 1995 was used by AGC solely as support for its 
indebtedness for commercial paper outstanding.
<PAGE>
                                  134             
<TABLE>
<CAPTION>
Potomac Edison 
STATEMENT OF INCOME 
                                                                          YEAR ENDED DECEMBER 31
                                                                       1995        1994        1993
                                                                          (Thousands of Dollars)

Electric Operating Revenues:  
  <S>                                                                <C>         <C>         <C>
  Residential.....................................................   $316,714    $296,090    $274,358
  Commercial......................................................    145,096     135,937     124,667
  Industrial......................................................    200,890     195,089     175,902           
  Nonaffiliated utilities.........................................    125,890     107,027     108,132
  Other, including affiliates.....................................     30,429      25,222      29,526
    Total Operating Revenues......................................    819,019     759,365     712,585

Operating Expenses:
  Operation:
    Fuel..........................................................    134,459     145,045     143,587
    Purchased power and exchanges, net............................    245,630     217,137     205,073  
    Deferred power costs, net (Note A)............................     13,056       1,321      (9,953)
    Other (Note B)................................................     94,688      85,024      74,438 
  Maintenance (Note B)............................................     62,147      58,624      64,376
  Depreciation....................................................     68,826      59,989      56,449
  Taxes other than income taxes...................................     47,629      46,740      46,813
  Federal and state income taxes (Note C).........................     36,936      33,163      30,086
    Total Operating Expenses......................................    703,371     647,043     610,869
    Operating Income..............................................    115,648     112,322     101,716

Other Income and Deductions:
  Allowance for other than borrowed funds used
    during construction (Note A)..................................      1,054       3,671       4,329
  Other income, net...............................................     12,044      10,243       8,419
    Total Other Income and Deductions.............................     13,098      13,914      12,748
    Income Before Interest Charges................................    128,746     126,236     114,464

Interest Charges:
  Interest on long-term debt......................................     49,113      44,706      42,695
  Other interest..................................................      2,066       1,750       1,107
  Allowance for borrowed funds used during
    construction (Note A).........................................       (698)     (2,203)     (2,805)
    Total Interest Charges........................................     50,481      44,253      40,997

Income Before Cumulative Effect of
  Accounting Change...............................................     78,265      81,983      73,467

Cumulative Effect of Accounting Change,
  net (Note A)....................................................                 16,471            

Net Income........................................................   $ 78,265    $ 98,454    $ 73,467

                                                                                                      
Potomac Edison
STATEMENT OF RETAINED EARNINGS

Balance at January 1..............................................   $207,722    $176,053    $167,412
Add:
  Net income......................................................     78,265      98,454      73,467
                                                                      285,987     274,507     240,879
Deduct:
  Dividends on capital stock:
    Preferred stock...............................................      2,455       4,331       4,434
    Common stock..................................................     64,693      62,454      60,386
  Charges on redemption of preferred stock........................      1,987                       6
      Total Deductions............................................     69,135      66,785      64,826

Balance at December 31 (Note D)...................................   $216,852    $207,722    $176,053


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                 135          
<TABLE>
<CAPTION>
Potomac Edison 
STATEMENT OF CASH FLOWS 
                                                                          YEAR ENDED DECEMBER 31
                                                                       1995        1994        1993
                                                                          (Thousands of Dollars)

Cash Flows from Operations:   
  <S>                                                                <C>         <C>         <C>
  Net income......................................................   $ 78,265    $ 98,454    $ 73,467
  Depreciation....................................................     68,826      59,989      56,449
  Deferred investment credit and income taxes, net................     14,279      12,688      (3,119)
  Deferred power costs, net.......................................     13,056       1,321      (9,953)
  Unconsolidated subsidiaries' dividends in excess of earnings....      2,489       1,704       2,042
  Allowance for other than borrowed funds used
    during construction...........................................     (1,054)     (3,671)     (4,329)
  Cumulative effect of accounting change before
    income taxes (Note A).........................................                (26,163)
  Changes in certain current assets and liabilities:
    Accounts receivable, net, excluding cumulative effect
      of accounting change (Note A)...............................    (25,050)      6,004      (7,640)
    Materials and supplies........................................      4,554      (5,367)     13,971
    Accounts payable..............................................        885      (9,981)      2,762
    Taxes accrued.................................................        457      (1,083)        240 
    Interest accrued..............................................        443         563       1,664
  Other, net......................................................     (4,971)       (198)     14,006
                                                                      152,179     134,260     139,560

Cash Flows from Investing:
  Construction expenditures.......................................    (92,240)   (142,826)   (179,433)
  Allowance for other than borrowed
    funds used during construction................................      1,054       3,671       4,329
                                                                      (91,186)   (139,155)   (175,104)

Cash Flows from Financing:
  Sale of common stock............................................                             50,000
  Retirement of preferred stock...................................    (48,396)     (1,190)     (1,611)
  Issuance of long-term debt and QUIDS............................    207,019      86,877     142,171
  Retirement of long-term debt....................................   (175,248)    (16,000)   (123,888)
  Short-term debt, net............................................     21,637
  Notes receivable from affiliates................................      1,900       2,700      33,400 
  Dividends on capital stock:
    Preferred stock...............................................     (2,455)     (4,331)     (4,434)
    Common stock..................................................    (64,693)    (62,454)    (60,386)
                                                                      (60,236)      5,602      35,252

Net Change in Cash and
  Temporary Cash Investments (Note H).............................        757         707        (292)
Cash and Temporary Cash Investments at January 1..................      2,196       1,489       1,781
Cash and Temporary Cash Investments at December 31................   $  2,953    $  2,196    $  1,489


Supplemental Cash Flow Information
  Cash paid during the year for:
    Interest (net of amount capitalized)..........................   $ 49,399    $ 42,680    $ 37,427
    Income taxes..................................................     25,679      30,771      30,378


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                  136
<TABLE>
<CAPTION>
Potomac Edison

BALANCE SHEET                                                                 
                                                                                   DECEMBER 31
ASSETS                                                                        1995            1994
                                                                             (Thousands of Dollars)
Property, Plant, and Equipment:                                                 
  At original cost, including $49,987,000 and
    <S>                                                                   <C>             <C>
    $76,365,000 under construction......................................   $2,050,835      $1,978,396
  Accumulated depreciation..............................................     (729,653)       (673,853)
                                                                            1,321,182       1,304,543
Investments:
  Allegheny Generating Company--common stock
    at equity (Note E)..................................................       59,963          62,364
  Other.................................................................          868             938
                                                                               60,831          63,302

Current Assets:
  Cash..................................................................        2,953           2,196
  Accounts receivable:
    Electric service, net of $1,344,000 and $1,177,000
      uncollectible allowance (Note A)..................................       93,250          68,714
    Affiliated and other................................................        2,917           2,403
  Notes receivable from affiliates (Note J).............................                        1,900
  Materials and supplies--at average cost:
    Operating and construction..........................................       26,414          27,800
    Fuel................................................................       19,148          22,316
  Prepaid taxes.........................................................       13,748          13,168
  Other.................................................................        3,158           5,000
                                                                              161,588         143,497

Deferred Charges:
  Regulatory assets (Note C)............................................       80,693          88,758
  Unamortized loss on reacquired debt...................................       18,926           8,344
  Other.................................................................       11,224          21,091
                                                                              110,843         118,193
Total...................................................................   $1,654,444      $1,629,535


CAPITALIZATION AND LIABILITIES
Capitalization:
  Common stock, other paid-in capital, and retained
    earnings (Notes D and I)............................................   $  667,242      $  658,146
  Preferred stock (Note I)..............................................       16,378          61,578
  Long-term debt and QUIDS (Note I).....................................      628,854         604,749
                                                                            1,312,474       1,324,473

Current Liabilities:
  Short-term debt (Note J)..............................................       21,637
  Long-term debt and preferred stock
    due within one year (Note I)........................................       18,700           1,200
  Accounts payable......................................................       28,931          37,126
  Accounts payable to affiliates........................................       19,565          10,485
  Taxes accrued:
    Federal and state income............................................        3,293           3,565
    Other...............................................................       12,603          11,874
  Interest accrued......................................................        9,638           9,195
  Customer deposits.....................................................        6,540           6,228
  Other.................................................................        8,545          11,171
                                                                              129,452          90,844
Deferred Credits and Other Liabilities:
  Unamortized investment credit.........................................       25,816          28,041
  Deferred income taxes.................................................      155,432         149,299
  Regulatory liabilities (Note C).......................................       15,255          16,957
  Other.................................................................       16,015          19,921
                                                                              212,518         214,218
Commitments and Contingencies (Note K)                                                          
Total...................................................................   $1,654,444      $1,629,535

See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                 137
<TABLE>
<CAPTION>
The Potomac Edison Company

STATEMENT OF CAPITALIZATION 
                                                                                         DECEMBER 31        
                                                                         1995          1994         1995      1994
                                                                       (Thousands of Dollars)  (Capitalization Ratios)
Common Stock:
  Common stock--no par value, authorized 23,000,000
    shares, outstanding 22,385,000 shares (issued 2,500,000     
    <S>                                                               <C>           <C>             <C>       <C>
    shares in 1993) (Note I)......................................    $  447,700    $  447,700                          
  Other paid-in capital (Note I)..................................         2,690         2,724
  Retained earnings (Note D)......................................       216,852       207,722
      Total.......................................................       667,242       658,146      50.8%     49.7%

Preferred Stock:
  Cumulative preferred stock--par value $100 per share,
    authorized 5,378,611 shares, outstanding as follows
    (Note I):
    Not subject to mandatory redemption:

                   December 31, 1995    
                                Regular
                  Shares      Call Price    Date of
    Series     Outstanding    Per Share      Issue 
    3.60% ....    63,784        $103.75       1946                         6,378         6,378
    $5.88 C...   100,000         102.85       1967                        10,000        10,000
    $7.00 D...                                1968                                       5,000
    $8.32 F...                                1971                                       5,000
    $8.00 G...                                1972                                      10,000
      Total (annual dividend requirements $817,622)...............        16,378        36,378       1.3       2.7

    Subject to mandatory redemption:
    $7.16 J...                                1986                                      26,400
      Total.......................................................                      26,400
    Less current sinking fund requirement.........................                      (1,200)
                                                                                        25,200                 1.9
Long-Term Debt and QUIDS (Note I):
  First mortgage    Date of        Date       Date
  bonds:             Issue      Redeemable    Due 
    5-7/8% ......     1966         1996       1996                        18,000        18,000
    5-7/8% ......     1993         2000       2000                        75,000        75,000
    8    % ......     1991         2001       2006                        50,000        50,000
    9-1/4% ......     1989                                                              65,000
    9-5/8% ......     1990                                                              80,000
    8-7/8% ......     1991         2001       2021                        50,000        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
    7-3/4% ......     1995         2005       2025                        65,000

                                   December 31, 1995
                                   Interest Rate - % 
  Quarterly Income Debt Securities
    due 2025........................      8.00                            45,457
  Secured notes due 1998-2024.......  5.95-6.875                          91,700        91,700
  Unsecured note due 1996-2002......      6.30                             5,500         5,500
  Unamortized debt discount and premium, net......................        (8,103)       (5,451)
      Total (annual interest requirements $48,707,458)............       647,554       604,749
  Less current maturities.........................................       (18,700)                                       
    Total.........................................................       628,854       604,749      47.9       45.7

Total Capitalization..............................................    $1,312,474    $1,324,473     100.0%     100.0%


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                   138

Potomac Edison       


NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)

Note A - Summary of Significant
Accounting Policies:

  The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and
is a part of the Allegheny Power integrated electric utility system (the
System).

  The Company is subject to regulation by the Securities and Exchange Commis-
sion (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:
  Beginning in 1994, revenues, including amounts resulting from the applica-
tion 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.  In 1993, revenues
were recorded for billings rendered to customers.  Revenues of $67.4 million
from one industrial customer, Eastalco Aluminum Company, were 8% of total
electric operating revenues in 1995.

DEFERRED POWER COSTS, NET:
  The costs of fuel, purchased power, and certain other costs, and revenues
from sales to other companies, 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 affiliates
in the System, are stated at original cost, less contributions in aid of
construction.  Cost includes 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 administra-
tion, maintenance, and depreciation of transportation and construction
equipment, and pensions, taxes, and other fringe benefits related to employees
engaged in construction.

  The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE>
                                139

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 1995, 1994, and 1993 were
9.71%, 9.73%, and 9.97%, respectively.  AFUDC is not included
in the cost of such 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 3.6%, 3.4%, and 3.6% of average depreciable property in 1995,
1994, and 1993, respectively.  The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.

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 substan-
tially 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 utilizing the most current tax rates.

  Provisions for federal income tax were reduced in previous years by invest-
ment 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 in the System 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.
<PAGE>
                                 140

  The Company also provides partially contributory medical and life insurance
plans for eligible retirees and dependents.  Medical benefits, which comprise
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 an amount equal to the annual cost, but not more than can be
deducted for federal income tax purposes.  Funding of these benefits is made
primarily into Voluntary Employee Beneficiary Association (VEBA) trust funds
in amounts up to that which can be deducted for federal income tax purposes. 
Medical benefits are self-insured; the life insurance plan is paid through
insurance premiums.

ACCOUNTING CHANGES:
  Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for electric
services.  This change results in a better matching of revenues and expenses,
and is consistent with predominant utility industry practice.  The cumulative
effect of this accounting change for years prior to 1994, which is shown
separately in the statement of income for 1994, resulted in a benefit of $16.5
million (after related income taxes of $9.7 million).  The effect of the
change on 1994 income before the cumulative effect of accounting change, as
well as 1993 net income, is not material.

  In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective
in 1996.  The Company does not believe at this time that the adoption of this
standard will have a materially adverse effect on its financial position.

Note B - Restructuring Charges and Asset Write-Offs:

  The System is undergoing a reorganization and reengineering process (re-
structuring) to simplify its management structure and to increase efficiency. 
As a consequence of this process, approximately 200 employees, primarily in
the System's Bulk Power Supply department, have been placed in a staffing
force.  In January 1996, these employees were offered an option to resign
immediately under a Voluntary Separation Program (VSP) or to remain employed
subject to involuntary separation (layoff) after one year, if during that year
they have not found other employment within the System.

  In 1995, the Company recorded restructuring charges of $4.6 million 
($2.9 million after tax) in other operation
expense, for its share of the estimated liabilities related primarily to
staffing force employees' involuntary separation costs.  Further separation
costs for these employees will be recorded in 1996 depending upon those
employees who elect early separation under the VSP, which provides enhanced
separation benefits.  Additional restructuring costs may be required as the
restructuring process is completed for other departments.

  In connection with changes in inventory management objectives, the Company
in 1995 also recorded $2.2 million ($1.4 million after tax) primarily in
maintenance expense for the write-off of obsolete and slow-moving materials.
<PAGE>
                                 141

Note C - Income Taxes:

  Details of federal and state income tax provisions are:

                                          1995         1994         1993
                                              (Thousands of Dollars)
Income taxes--current:
  Federal.............................  $25,949      $34,193      $29,758
  State...............................     (640)      (2,849)       3,991
    Total.............................   25,309       31,344       33,749
Income taxes--deferred, net of
  amortization........................   16,504       14,955         (770)
Amortization of deferred
  investment credit...................   (2,225)      (2,267)      (2,349)
    Total income taxes................   39,588       44,032       30,630
Income taxes--charged to other
  income and deductions...............   (2,652)      (1,176)        (544)
Income taxes--charged to
  accounting change (including
  state income taxes).................                (9,693)            
Income taxes--charged to
  operating income....................  $36,936      $33,163      $30,086


  The total provision for income taxes is different than the amount produced
by applying the federal income statutory tax rate to financial accounting
income, as set forth below:

                                          1995         1994         1993
                                              (Thousands of Dollars)
Financial accounting income before
  cumulative effect of accounting
  change and income taxes............   $115,201     $115,146     $103,553
Amount so produced...................   $ 40,300     $ 40,300     $ 36,200
Increased (decreased) for:
  Tax deductions for which deferred
    tax was not provided:
      Lower tax depreciation.........      4,200          100        2,300
      Plant removal costs............     (1,200)      (1,700)      (2,100)
  State income tax, net of federal
    income tax benefit...............      2,200        1,300        1,600
  Amortization of deferred
    investment credit................     (2,225)      (2,267)      (2,349)
  Equity in earnings of
    subsidiaries.....................     (2,600)      (2,900)      (2,600)
  Other, net.........................     (3,739)      (1,670)      (2,965)
      Total..........................   $ 36,936     $ 33,163     $ 30,086


  Federal income tax returns through 1991 have been examined and substantially
settled.
<PAGE>
                                  142

  At December 31, the deferred tax assets and liabilities were comprised of
the following:

                                                    1995           1994
                                                  (Thousands of Dollars)
Deferred tax assets:
  Unamortized investment tax credit............   $ 15,084       $ 16,497
  Unbilled revenue.............................      3,492          3,504
  Tax interest capitalized.....................     11,221         12,701
  Contributions in aid of construction.........     12,614         11,653
  State tax loss carryback/carryforward........         24          2,721
  Advances for construction....................      1,573          1,338
  Other........................................      5,619          5,800
                                                    49,627         54,214
Deferred tax liabilities:
  Book vs. tax plant basis differences, net....    189,618        192,862
  Other........................................     15,803         13,367
                                                   205,421        206,229
Total net deferred tax liabilities.............    155,794        152,015
Less portion above included in
  current liabilities..........................        362          2,716
Total long-term net deferred
  tax liabilities..............................   $155,432       $149,299


  It is expected that regulatory commissions will allow recovery of the
deferred tax liabilities in future years as they are paid, and accordingly,
the Company has recorded regulatory assets of $61 million and $76 million as
of December 31, 1995 and 1994, respectively.  Regulatory liabilities of $15
million and $17 million as of December 31, 1995 and 1994, respectively, have
been recorded in order to reflect the Company's obligation to pass such tax
benefits on to its customers as the benefits are realized in cash in future
years.

Note D - Dividend Restriction:

  Supplemental indentures relating to most outstanding bonds of the Company
contain dividend restrictions under the most restrictive of which $94,355,000
of retained earnings at December 31, 1995, 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 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 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 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
<PAGE>
                                143
 
a formula filed with and previously accepted by the FERC.  The only component
which changes is the return on equity (ROE).  In December 1991, AGC filed for
a continuation of the existing ROE of 11.53% and other interested parties
filed to reduce the ROE to 10%.  A recommendation was issued by an Administra-
tive Law Judge on December 22, 1994, to dismiss the joint complaint.  A
settlement agreement for both cases was filed with the FERC on January 12,
1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from
March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for
the period from January 1, 1995, through December 31, 1995.  This settlement
was approved by the FERC on March 23, 1995.  Refunds were made by AGC of any
revenues collected between March 1, 1992 and March 23, 1995 in excess of these
levels.  A second settlement has been negotiated to address AGC's ROE after
1995.  On December 21, 1995, AGC submitted the new settlement to the FERC. 
Interested parties representing less than 2% of AGC's eventual revenues have
filed exceptions to the settlement.  Under the terms of the settlement, AGC's
ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily
on changes in interest rates.

  Following is a summary of financial information for AGC: 

                                                        December 31    
                                                    1995           1994
                                                  (Thousands of Dollars)
Balance sheet information:
  Property, plant, and equipment...............   $677,857       $680,749
  Current assets...............................      7,586          5,991
  Deferred charges.............................     24,844         27,496
    Total assets...............................   $710,287       $714,236

  Total capitalization.........................   $463,862       $489,894
  Current liabilities..........................     11,892          6,484
  Deferred credits.............................    234,533        217,858
    Total capitalization and liabilities.......   $710,287       $714,236


                                              Year Ended December 31           
                                            1995        1994         1993
                                              (Thousands of Dollars)
Income statement information:
  Electric operating revenues.........  $86,970      $91,022      $90,606
  Operation and maintenance
    expense...........................    5,740        6,695        6,609
  Depreciation........................   17,018       16,852       16,899
  Taxes other than
    income taxes......................    5,091        5,223        5,347
  Federal income taxes................   13,552       14,737       13,262
  Interest charges....................   18,361       17,809       21,635
  Other income, net...................      (16)         (11)        (328)
  Net income..........................  $27,224      $29,717      $27,182


  The Company's share of the equity in earnings above was $7.6 million, $8.3
million, and $7.6 million for 1995, 1994, and 1993, respectively, and is
included in other income, net, on the Statement of Income.
<PAGE>
                                 144
Note F - Pension Benefits:

  The Company's share of net pension costs under the System's pension plan, a
portion of which (about 30% to 35%) was charged to plant construction,
included the following components:

                                          1995         1994         1993
                                              (Thousands of Dollars)

Service cost--benefits earned.........  $ 3,286      $ 3,555      $ 3,225
Interest cost on projected
  benefit obligation..................   10,161        9,867        9,612
Actual (return) loss on
  plan assets.........................  (25,718)         304      (22,481)
Net amortization and deferral.........   12,631      (12,808)      10,669
Pension cost..........................      360          918        1,025
Regulatory reversal...................                 1,194          537 
Net pension cost......................  $   360      $ 2,112      $ 1,562


  The benefits earned to date and funded status of the Company's share of the
System plan at December 31 using a measurement date of September 30 were as
follows:

                                                    1995           1994
                                                  (Thousands of Dollars)
Actuarial present value of accumulated
  benefit obligation earned to date
  (including vested benefit of 
  $111,538,000 and $103,546,000)...............   $119,383       $110,577
Funded status:
  Actuarial present value of projected
    benefit obligation.........................   $144,800       $135,060
  Plan assets at market value, primarily
    common stocks and fixed income securities..    169,830        146,211
  Plan assets in excess of projected
    benefit obligation.........................    (25,030)       (11,151)
  Add:
    Unrecognized cumulative net gain from
      past experience different from
      that assumed.............................     23,839         13,165
    Unamortized transition asset, being
      amortized over 14 years beginning
      January 1, 1987..........................      3,435          4,183
  Less unrecognized prior service
    cost due to plan amendments................      2,450          2,732
  Pension cost liability at September 30.......       (206)         3,465
  Fourth quarter contributions.................                     1,989
  Pension (prepayment) liability 
    at December 31.............................   $   (206)      $  1,476


  The foregoing includes the Company's portion of amounts applicable to
employees at power stations which are owned jointly with affiliates.
<PAGE>
                                 145 
   
  In determining the actuarial present value of the projected benefit obliga-
tion at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%,
7.75%, and 7.25%, and the rates of increase in future compensation levels were
4.5%, 4.75%, and 4.75%, respectively.  The expected long-term rate of return
on assets was 9% in each of the years 1995, 1994, and 1993.

Note G - Postretirement Benefits Other
Than Pensions:

  The cost of postretirement benefits other than pensions (principally health
care and life insurance) for employees and covered dependents in 1995 and
1994, a portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
                                                
                                                  1995          1994
                                                   (Thousands of Dollars)

Service cost - benefits earned..................   $  683         $  696
Interest cost on accumulated
  postretirement benefit obligation.............    4,476          4,047
Actual loss (return) on plan assets.............   (1,938)            47
Amortization of unrecognized
  transition obligation.........................    2,011          1,976
Other net amortization and deferral.............    1,570             53
Postretirement cost.............................    6,802          6,819
Regulatory reversal (deferral)..................       11           (457)
Net postretirement cost.........................   $6,813         $6,362
<PAGE>
                               148

  The benefits earned to date and funded status of the Company's share of the
System plan at December 31 using a measurement date of September 30 were as
follows:

                                                    1995          1994
                                                   (Thousands of Dollars)

Accumulated postretirement benefit obligation
  (APBO):
    Retirees....................................   $35,852       $36,927
    Fully eligible employees....................     8,699         8,152
    Other employees.............................    13,805        14,035
      Total obligation..........................    58,356        59,114
Plan assets at market value, in common stocks,
  fixed income securities, and short-term
  investments...................................    11,882         5,962
Accumulated postretirement benefit
  obligation in excess of plan assets...........    46,474        53,152
Less:
  Unrecognized cumulative net loss from past
    experience different from that assumed......     8,578        14,223
  Unrecognized transition obligation,
    being amortized over 20 years
    beginning January 1, 1993...................    34,125        35,928
Postretirement benefit liability
  at September 30...............................     3,771         3,001
Fourth quarter contributions
  and benefit payments..........................     2,221         1,634
Postretirement benefit liability
  at December 31................................   $ 1,550       $ 1,367


In determining the APBO at September 30, 1995, 1994, and 1993, the discount 
rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future 
compensation levels were 4.5%, 4.75%, and 4.75%, respectively.  The 1995 
expected long-term rate of return on assets was 8.25% net of tax.  
For measurement purposes, a health care trend rate of 8% for 1996, declining 
1% each year thereafter to 6.5% in the year 1998 and beyond, 
and plan provisions which limit future medical and life insurance benefits, 
were assumed.  Increasing the assumed health care trend rate by 1% in each 
year would increase the APBO at December 31, 1995, by $3.8 million and the 
aggregate of the service and interest cost components of net periodic 
postretirement benefit cost for 1995 by $.4 million.
<PAGE>
                                149

Note H - Fair Value of Financial Instruments:

  The carrying amounts and estimated fair value of financial instruments at
December 31 were as follows:

                                    1995                      1994       
                           Carrying       Fair       Carrying       Fair
                            Amount        Value       Amount        Value
                                       (Thousands of Dollars)
Liabilities:
  Mandatorily         
    redeemable
    preferred stock....   $   -        $   -         $ 26,400     $ 25,542
  Short-term debt......     21,637       21,637
  Long-term debt and
    QUIDS..............    655,657      689,003       610,200      594,519

  The fair value of mandatorily redeemable preferred stock was estimated based
on quoted market prices.  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 does not have any financial
instruments held or issued for trading purposes.

  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.

Note I - Capitalization:

COMMON STOCK AND OTHER PAID-IN CAPITAL:
  In October 1993, the Company issued and sold 2,500,000 shares of common
stock to its parent at $20 per share.  Other paid-in capital decreased $34,000
in 1995 and increased $10,000 in 1994 as a result of preferred stock transac-
tions.

PREFERRED STOCK:
  In 1995, the Company refunded $45.5 million of preferred stock with dividend
rates between 7% and 8.32%, with the proceeds from the issuance of Quarterly
Income Debt Securities (QUIDS) described below.  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 for the next five years are:  1996, $18,700,
000; 1997, $800,000; 1998, $1,800,000; 1999, $1,800,000; and 2000, $76,800,000. 
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.
<PAGE>
                                150

  In 1995, the Company sold $65 million of 7-3/4% 30-year first mortgage bonds
to refund a $65 million 9-1/4% issue due in 2019 and $80 million of 7-5/8% 30-
year first mortgage bonds to refund an $80 million 9-5/8% issue due in 2020. 
The Company also issued $21 million of 6.15% 20-year tax-exempt notes to
refund a $21 million 7.3% issue.

  In 1995, the Company issued $45.5 million of 8% 30-year QUIDS to refund
preferred stock.  QUIDS may not be redeemed until the year 2000.  Under
certain circumstances the interest payments may be deferred for a period of up
to 20 consecutive quarters.

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 $115 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 internal money pool accommodates intercompany short-term borrowing needs,
to the extent that certain of the companies have funds available.  In January
1994, the Company and its affiliates jointly established an aggregate $300
million multi-year credit program which provides that the Company may borrow
up to $84 million on a standby revolving credit basis.  Short-term debt
outstanding for 1995 and 1994 consisted of:

                                              1995               1994
                                              (Thousands of Dollars)
Balance at end of year:
  Commercial Paper....................    $21,637-6.10%
Average amount outstanding
  during the year:
  Commercial Paper..................      $   499-5.94%      $1,021-3.96%
  Notes Payable to Banks............          995-6.04%       2,499-3.96%
  Money Pool........................          179-5.96%          87-4.10%


Note K - Commitments and Contingencies:

CONSTRUCTION PROGRAM:
  The Company has entered into commitments for its construction program, for
which expenditures are estimated to be $87 million for 1996 and 
$103 million for 1997.  Through 1999, annual construction expenditures are not
expected to significantly exceed 1996 estimated levels.  Construction
expenditure levels in 2000 and beyond will depend upon future generation
requirements, as well as the strategy eventually selected for complying with
Phase II of the Clean Air Act Amendments of 1990.

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 affect adversely the lead time, size, and siting of future
generating stations, increase the complexity and cost of pollution control
equipment, and otherwise add to the cost of future operations.  In the normal
course of business, the Company becomes involved in various legal proceedings. 
<PAGE>
                                 151

The Company does not believe that the ultimate outcome of these proceedings
will have a material effect on its financial position.

  The Company previously reported that the Environmental Protection Agency had
identified it and its affiliates and approximately 875 others as potentially
responsible parties in a Superfund site subject to cleanup.  The Company has
also been named as a defendant 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.

  The Company is guarantor as to 28% of a $50 million revolving credit
agreement of AGC, which in 1995 was used by AGC solely as support for its
indebtedness for commercial paper outstanding.
<PAGE>
                                152
<TABLE>
<CAPTION>
West Penn 
CONSOLIDATED STATEMENT
OF INCOME 
                                                                             YEAR ENDED DECEMBER 31
                                                                          1995        1994        1993
                                                                             (Thousands of Dollars)
Electric Operating Revenues:  
  <S>                                                                <C>           <C>           <C>
  Residential.....................................................   $  401,186    $  376,776    $  358,900  

  Commercial......................................................      224,144       207,165       194,773
  Industrial......................................................      356,937       330,739       309,847  
  Nonaffiliated utilities.........................................      168,215       144,829       152,541
  Other, including affiliates.....................................       75,859        68,733        68,916
    Total Operating Revenues......................................    1,226,341     1,128,242     1,084,977

Operating Expenses:
  Operation:
    Fuel..........................................................      237,376       252,108       256,664
    Purchased power and exchanges, net............................      274,705       247,194       235,772 

    Deferred power costs, net (Note A)............................       15,091         2,880           979 
    Other (Note B)................................................      148,781       145,781       131,854 
  Maintenance (Note B)............................................      118,162       111,841        96,706
  Depreciation....................................................      112,334        88,935        80,872
  Taxes other than income taxes...................................       89,694        87,224        89,249
  Federal and state income taxes (Note C).........................       61,745        50,385        51,529
    Total Operating Expenses......................................    1,057,888       986,348       943,625
    Operating Income..............................................      168,453       141,894       141,352

Other Income and Deductions:
  Allowance for other than borrowed funds used
    during construction (Note A)..................................        2,974         6,729         5,077
  Other income, net (Note B)......................................       12,287         8,618        12,728
    Total Other Income and Deductions.............................       15,261        15,347        17,805
    Income Before Interest Charges................................      183,714       157,241       159,157

Interest Charges:
  Interest on long-term debt......................................       64,571        58,102        58,857
  Other interest..................................................        3,331         2,172         1,728
  Allowance for borrowed funds used during
    construction (Note A).........................................       (2,067)       (4,048)       (3,489)
    Total Interest Charges........................................       65,835        56,226        57,096

Consolidated Income Before Cumulative 
  Effect of Accounting Change.....................................      117,879       101,015       102,061

Cumulative Effect of Accounting Change,
  net (Note A)....................................................                     19,031              

Consolidated Net Income...........................................   $  117,879    $  120,046    $  102,061

                                                                                                             
 
West Penn
CONSOLIDATED STATEMENT 
OF RETAINED EARNINGS

Balance at January 1..............................................   $  433,801    $  412,288    $  400,515
Add:
  Consolidated net income.........................................      117,879       120,046       102,061
                                                                        551,680       532,334       502,576
Deduct:
  Dividends on capital stock of the Company:
    Preferred stock...............................................        6,204         8,504         8,206
    Common stock..................................................       91,600        90,029        82,082  
    Charge on redemption of preferred stock.......................        2,157                   
         
      Total Deductions............................................       99,961        98,533        90,288

Balance at December 31 (Note D)...................................   $  451,719    $  433,801    $  412,288


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
                                153

<TABLE>
<CAPTION>
West Penn 

CONSOLIDATED STATEMENT OF CASH FLOWS 
                                                                          YEAR ENDED DECEMBER 31
                                                                       1995        1994        1993
                                                                          (Thousands of Dollars)

Cash Flows from Operations:   
  <S>                                                                <C>         <C>         <C>
  Consolidated net income.........................................   $117,879    $120,046    $102,061
  Depreciation....................................................    112,334      88,935      80,872
  Deferred investment credit and income taxes, net................      2,364         699     (10,115)
  Deferred power costs, net.......................................     15,091       2,880         979 
  Unconsolidated subsidiaries' dividends in excess of earnings....      4,034       2,773       3,311
  Allowance for other than borrowed funds used
    during construction...........................................     (2,974)     (6,729)     (5,077)
  Cumulative effect of accounting change before
    income taxes (Note A).........................................                (32,891)
  Changes in certain current assets and liabilities:
    Accounts receivable, net, excluding cumulative effect
      of accounting change (Note A)...............................    (30,280)     18,951      (5,947)
    Materials and supplies........................................      9,022      (9,205)     26,889
    Accounts payable..............................................    (15,041)       (675)      3,196
    Taxes accrued.................................................     (5,577)     (4,502)      9,198 
    Interest accrued..............................................       (585)      2,620      (5,146)
  Other, net......................................................      1,396      25,019       8,878
                                                                      207,663     207,921     209,099


Cash Flows from Investing:
  Construction expenditures.......................................   (149,122)   (260,366)   (251,017)
  Allowance for other than borrowed
    funds used during construction................................      2,974       6,729       5,077
                                                                     (146,148)   (253,637)   (245,940)


Cash Flows from Financing:
  Sale of common stock............................................                 40,000     100,000
  Retirement of preferred stock...................................    (72,369)     
  Issuance of long-term debt and QUIDS............................    143,700      80,129     268,766
  Retirement of long-term debt....................................   (105,888)               (251,414)
  Short-term debt, net............................................     70,218      
  Notes receivable from affiliates................................      1,000      23,900      (4,000)
  Dividends on capital stock:
    Preferred stock...............................................     (6,204)     (8,504)     (8,206)
    Common stock..................................................    (91,600)    (90,029)    (82,082)
                                                                      (61,143)     45,496      23,064

Net Change in Cash and
  Temporary Cash Investments (Note H).............................        372        (220)    (13,777)
Cash and Temporary Cash Investments at January 1..................        345         565      14,342
Cash and Temporary Cash Investments at December 31................   $    717    $    345    $    565


Supplemental Cash Flow Information
  Cash paid during the year for:
    Interest (net of amount capitalized)..........................   $ 64,374    $ 51,745    $ 61,329
    Income taxes..................................................     64,330      54,958      55,111


See accompanying notes to consolidated financial statements.
</TABLE>

<TABLE>
<CAPTION>
West Penn 
CONSOLIDATED BALANCE SHEET                                                                 
                                                                                    DECEMBER 31
ASSETS                                                                         1995            1994
                                                                              (Thousands of Dollars)
Property, Plant, and Equipment:
  At original cost, including $67,626,000 and
    <C>                                                                     <C>             <C>
    $103,514,000 under construction.....................................    $3,097,522      $3,013,777       

  Accumulated depreciation..............................................    (1,063,399)     (1,009,565)
                                                                             2,034,123       2,004,212
Investments and Other Assets:
  Allegheny Generating Company--common stock
    at equity (Note E)..................................................        96,369         100,228
  Other.................................................................         1,239           1,474
                                                                                97,608         101,702
Current Assets:
  Cash and temporary cash investments (Note H)..........................           717             345
  Accounts receivable:
    Electric service, net of $9,436,000 and $8,267,000
      uncollectible allowance (Note A)..................................       140,979         119,020
    Affiliated and other................................................        20,183          11,862
  Notes receivable from affiliates (Note J).............................                         1,000
  Materials and supplies--at average cost:
    Operating and construction..........................................        36,660          39,922
    Fuel................................................................        32,445          38,205
  Deferred income taxes.................................................        21,024          12,538
  Prepaid and other.....................................................        17,744          12,525
                                                                               269,752         235,417

Deferred Charges:
  Regulatory assets (Note C)............................................       342,150         364,473
  Unamortized loss on reacquired debt...................................        12,256          10,494
  Other.................................................................        15,275          15,560
                                                                               369,681         390,527
Total...................................................................    $2,771,164      $2,731,858


CAPITALIZATION AND LIABILITIES
Capitalization:
  Common stock, other paid-in capital, and retained
    earnings (Notes D and I)............................................    $  973,188      $  955,482
  Preferred stock (Note I)..............................................        79,708         149,708
  Long-term debt and QUIDS (Note I).....................................       904,669         836,426
                                                                             1,957,565       1,941,616

Current Liabilities:
  Short-term debt (Note J)..............................................        70,218
  Long-term debt due within one year (Note I)...........................                        27,000
  Accounts payable......................................................        86,935         107,792
  Accounts payable to affiliates........................................        12,293           6,477
  Taxes accrued:
    Federal and state income............................................         4,128           9,217
    Other...............................................................        20,149          20,637
  Interest accrued......................................................        15,890          16,475
  Deferred power costs (Note A).........................................        12,399
  Other.................................................................        20,377          24,028
                                                                               242,389         211,626
Deferred Credits and Other Liabilities:
  Unamortized investment credit.........................................        50,366          52,946
  Deferred income taxes.................................................       469,559         471,515
  Regulatory liabilities (Note C).......................................        35,077          39,881
  Other.................................................................        16,208          14,274
                                                                               571,210         578,616

Commitments and Contingencies (Note K)                                                                
Total...................................................................    $2,771,164      $2,731,858


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
                                154
<TABLE>
<CAPTION>
West Penn Power Company and Subsidiaries
CONSOLIDATED STATEMENT OF CAPITALIZATION 
                                                                                          DECEMBER 31       

                                                                       1995          1994         1995       1994
                                                                       (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 (issued
    <C>                                                               <C>           <C>           <C>         <C>                 
    2,000,000 shares in 1994) (Note I)................                $  465,994    $  465,994               
  Other paid-in capital (Note I)......................                    55,475        55,687
  Retained earnings (Note D)..........................                   451,719       433,801
  Total..........................................................        973,188       955,482    49.7%       49.2%

Preferred Stock of the Company:
  Cumulative preferred stock--par value $100 per share,
    authorized 3,097,077 shares, outstanding as follows
    (Note I):

                   December 31, 1995    
                                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
    $7.00 D...                                1967                                      10,000
    $7.12 E...                                1968                                      10,000
    $8.08 G...                                1971                                      10,000
    $7.60 H...                                1972                                      10,000
    $7.64 I...                                1973                                      10,000
    $8.20 J...                                1976                                      20,000
    Auction
      4.25%-
        4.75%.   400 000         100.00       1992                        40,000        40,000
      Total (annual dividend requirements $3,468,647)                     79,708       149,708       4.1   7.7

Long-Term Debt and QUIDS (Note I):
  First mortgage
  bonds:            Date of        Date       Date
                     Issue      Redeemable    Due 
    4-7/8% U.....     1965                                                              27,000
    5-1/2% JJ....     1993         1998       1998                       102,000       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
    9    % EE....     1989                                                              30,000
    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

                                   December 31, 1995
                                     Interest Rate - % 
  Quarterly Income Debt Securities
    due 2025........................      8.00                            70,000
  Secured notes due 1998-2024.......  4.95-6.75                          202,550       202,550    
  Unsecured notes due 2000-2007.....      6.10                            14,435        14,435
  Unamortized debt discount and premium, net..........                    (9,316)       (7,559)
      Total (annual interest requirements $64,988,743)                   904,669       863,426
  Less current maturities.............................                                 (27,000)
                                                                         904,669       836,426     46.2    43.1

Total Capitalization..................................                $1,957,565    $1,941,616    100.0%  100.0%


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
                                 155
  
West Penn 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial statements.)

Note A - Summary of Significant
Accounting Policies:

       The Company is a wholly-owned subsidiary of Allegheny Power System, Inc.
and is a part of the Allegheny Power integrated electric utility system (the
System).

         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).


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:
         Beginning in 1994, 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.  In 1993, revenues
were recorded for billings rendered to customers.  

DEFERRED POWER COSTS, NET:
         The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other companies, 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
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.  Cost includes 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 administra-
tion, maintenance, and depreciation of transportation and construction
equipment, and pensions, taxes, and other fringe benefits related to employees
engaged in construction.
<PAGE>
                                156
  
         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 of property, plant, and equipment with offsetting credits to other
income and interest charges.  Rates used for computing AFUDC in 1995, 1994,
and 1993 were 8.90%, 8.88%, and 9.40%, respectively.  AFUDC is not included
in the cost of such 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 3.9%, 3.5%, and 3.4% of average depreciable property in 1995,
1994, and 1993, respectively.  The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.

INCOME TAXES:
         The companies join with the parent and affiliates in filing a consoli-
dated 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 substan-
tially 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 utilizing 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 in the System 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 also provides partially contributory medical and life
insurance plans for eligible retirees and dependents.  Medical benefits, which
<PAGE>
                               157

comprise 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 an amount equal to the annual cost, but not more
than can be deducted for federal income tax purposes.  Funding of these
benefits is made primarily into Voluntary Employee Beneficiary Association
(VEBA) trust funds in amounts up to that which can be deducted for federal
income tax purposes.  Medical benefits are self-insured; the life insurance
plan is paid through insurance premiums.

ACCOUNTING CHANGES:
         Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for electric
services.  This change results in a better matching of revenues and expenses,
and is consistent with predominant utility industry practice.  The cumulative
effect of this accounting change for years prior to 1994, which is shown
separately in the consolidated statement of income for 1994, resulted in a
benefit of $19.0 million (after related income taxes of $13.9 million).  The
effect of the change on 1994 consolidated income before the cumulative effect
of accounting change, as well as 1993 consolidated net income, is not
material.

       In March 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
effective in 1996.  The Company does not believe at this time that the
adoption of this standard will have a materially adverse effect on its
financial position.

Note B  - Restructuring Charges and Asset Write-Offs:

         The System is undergoing a reorganization and reengineering process
(restructuring) to simplify its management structure and to increase efficien-
cy.  As a consequence of this process, approximately 200 employees, primarily
in the System's Bulk Power Supply department, have been placed in a staffing
force.  In January 1996, these employees were offered an option to resign
immediately under a Voluntary Separation Program (VSP) or to remain employed
subject to involuntary separation (layoff) after one year, if during that year
they have not found other employment within the System.

         In 1995 the Company recorded restructuring charges of $7.3 million 
($4.3 million after tax) in other operation expense, for its share of the
estimated liabilities related primarily to staffing force employees' involun-
tary separation costs.  Further separation costs for these employees will be
recorded in 1996 depending upon those employees who elect early separation
under the VSP, which provides enhanced separation benefits. Additional 
restructuring costs may be required as the restructuring process is completed 
for other departments.

         In connection with changes in inventory management objectives, the
Company in 1995 also recorded $3.8 million ($2.3 million after tax) primarily
in maintenance expense for the write-off of obsolete and slow-moving materi-
als.  

         In 1994, the Company wrote off $8.9 million ($5.2 million after tax) in
other income (expense), net, of previously accumulated costs related to a
potential future power plant site and a proposed transmission line.  In 
<PAGE>
                                158

the industry's more competitive environment, it was no longer reasonable to
assume future recovery of these costs in rates.


Note C - Income Taxes:

         Details of federal and state income tax provisions are:

                                          1995         1994         1993
                                              (Thousands of Dollars)
Income taxes--current:
  Federal.............................  $49,928      $46,964      $47,089
  State...............................    9,344       13,282       14,983
    Total.............................   59,272       60,246       62,072
Income taxes--deferred,
  net of amortization.................    4,944        3,277       (7,522)
Amortization of deferred
  investment credit...................   (2,580)      (2,578)      (2,592)
    Total income taxes................   61,636       60,945       51,958
Income taxes--credited (charged)
  to other income and deductions......      109        3,300         (429)
Income taxes--charged to
  accounting change (including
  state income taxes).................               (13,860)            
Income taxes--charged to
  operating income....................  $61,745      $50,385      $51,529


         The total provision for income taxes is different than the amount
produced by applying the federal income statutory tax rate to financial
accounting income, as set forth below:

                                          1995         1994         1993
                                              (Thousands of Dollars)
Financial accounting income before
  cumulative effect of accounting
  change and income taxes............   $179,624     $151,400     $153,590
Amount so produced...................   $ 62,900     $ 53,000     $ 53,800
Increased (decreased) for:
  Tax deductions for which deferred
    tax was not provided:
      Lower tax depreciation.........      4,300        2,000          100
      Plant removal costs............       (900)      (1,700)        (900)
  State income tax, net of federal
    income tax benefit...............      9,300        6,400        9,600
  Amortization of deferred
    investment credit................     (2,580)      (2,578)      (2,592)
  Equity in earnings of            
    subsidiaries.....................     (4,300)      (4,600)      (4,300)
  Other, net.........................     (6,975)      (2,137)      (4,179)
      Total..........................   $ 61,745     $ 50,385     $ 51,529


         Federal income tax returns through 1991 have been examined and substan-
tially settled.
<PAGE>
                                  159

         At December 31, the deferred tax assets and liabilities were comprised
of the following:

                                                    1995           1994
                                                  (Thousands of Dollars)
Deferred tax assets:
  Unamortized investment tax credit............   $ 35,043       $ 38,560
  Unbilled revenue.............................      8,594          9,539
  Tax interest capitalized.....................     19,049         16,165
  State tax loss carryback/carryforward........        508          5,535
  Postretirement benefits other than pensions..      7,324          3,952
  Contributions in aid of construction.........      6,009          4,866
  Other........................................     21,499         14,953
                                                    98,026         93,570
Deferred tax liabilities:
  Book vs. tax plant basis differences, net....    526,257        536,343
  Other........................................     20,304         16,204
                                                   546,561        552,547
Total net deferred tax liabilities.............    448,535        458,977
Add portion above included   
  in current assets............................     21,024         12,538
Total long-term net deferred
  tax liabilities..............................   $469,559       $471,515


         It is expected that regulatory commissions will allow recovery of the
deferred tax liabilities in future years as they are paid, and accordingly,
the Company has recorded regulatory assets of $332 million and $351 million as
of December 31, 1995 and 1994, respectively.  Regulatory liabilities of $36
million and $39 million as of December 31, 1995 and 1994, respectively, have
been recorded in order to reflect the Company's obligation to pass such tax
benefits on to its customers as the benefits are realized in cash in future
years.

Note D - Dividend Restriction:

         Supplemental indentures relating to most outstanding bonds of the
Company contain dividend restrictions under the most restrictive of which 
$70,576,000 of consolidated retained earnings at December 31, 1995, 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 E - 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 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 Power Company, a nonaffiliated utility.
<PAGE>
                                 160

           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).  In December 1991, AGC filed for
a continuation of the existing ROE of 11.53% and other interested parties
filed to reduce the ROE to 10%.   A recommendation was issued by an Adminis-
trative Law Judge on December 22, 1994, to dismiss the joint complaint.  A
settlement agreement for both cases was filed with the FERC on January 12,
1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from
March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for
the period from January 1, 1995, through December 31, 1995.  This settlement
was approved by the FERC on March 23, 1995.  Refunds were made by AGC of any
revenues collected between March 1, 1992 and March 23, 1995 in excess of these
levels.  A second settlement has been negotiated to address AGC's ROE after
1995.  On December 21, 1995, AGC submitted the new settlement to the FERC. 
Interested parties representing less than 2% of AGC's eventual revenues have
filed exceptions to the settlement.  Under the terms of the settlement, AGC's
ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily
on changes in interest rates.
    
   Following is a summary of financial information for AGC: 

                                                        December 31    
                                                    1995           1994
                                                  (Thousands of Dollars)
Balance sheet information:
  Property, plant, and equipment...............   $677,857       $680,749
  Current assets...............................      7,586          5,991
  Deferred charges.............................     24,844         27,496
    Total assets...............................   $710,287       $714,236

  Total capitalization.........................   $463,862       $489,894
  Current liabilities..........................     11,892          6,484
  Deferred credits.............................    234,533        217,858
    Total capitalization and liabilities.......   $710,287       $714,236
<PAGE>
                                 161


                                              Year Ended December 31    
                                         1995         1994         1993
                                              (Thousands of Dollars)
Income statement information:
  Electric operating revenues.........  $86,970      $91,022      $90,606
  Operation and maintenance
    expense...........................    5,740        6,695        6,609
  Depreciation........................   17,018       16,852       16,899
  Taxes other than
    income taxes......................    5,091        5,223        5,347
  Federal income taxes................   13,552       14,737       13,262
  Interest charges....................   18,361       17,809       21,635
  Other income, net...................      (16)         (11)        (328)
  Net income..........................  $27,224      $29,717      $27,182


         The Company's share of the equity in earnings above was $12.3 million,
$13.4 million, and $12.2 million for 1995, 1994, and 1993, respectively, and
is included in other income, net, on the Consolidated Statement of Income.

Note F - Pension Benefits:

         The Company's share of net pension costs under the System's pension
plan, a portion of which (about 25% to 30%) was charged to plant construction,
included the following components:

                                          1995         1994         1993
                                              (Thousands of Dollars)

Service cost - benefits earned........  $ 4,655      $ 5,124      $ 4,606
Interest cost on projected
  benefit obligation..................   14,412       14,051       13,773
Actual (return) loss on
  plan assets.........................  (32,610)         358      (31,224)
Net amortization and deferral.........   14,000      (18,210)      14,262
Pension cost..........................      457        1,323        1,417
Regulatory reversal (deferral)........      760         -          (1,309)
Net pension cost......................  $ 1,217      $ 1,323      $   108


         Regulatory deferrals amounting to $3,039,000 will be amortized to
operating expenses over the four-year period 1995 through 1998 in accordance
with authorized rate recovery.  An additional $833,000 regulatory deferral was
charged to plant construction in 1994.

         The benefits earned to date and funded status of the Company's share of
the System plan at December 31 using a measurement date of September 30 were
as follows:
<PAGE>
                                 162
                                                    1995           1994
                                                  (Thousands of Dollars)
Actuarial present value of accumulated
  benefit obligation earned to date
  (including vested benefit of
  $155,921,000 and $150,168,000)...............   $165,162       $158,578
Funded status:
  Actuarial present value of projected
    benefit obligation.........................   $199,683       $191,787
  Plan assets at market value, primarily
    common stocks and fixed income securities..    234,200        207,623
  Plan assets in excess of projected
    benefit obligation.........................    (34,517)       (15,836)
  Add:
    Unrecognized cumulative net gain from
      past experience different from
      that assumed.............................     29,164         15,103
    Unamortized transition asset, being
      amortized over 14 years beginning
      January 1, 1987..........................      7,178          8,427
  Less unrecognized prior service
    cost due to plan amendments................      4,467          4,999
  Pension cost liability at September 30.......     (2,642)         2,695
  Fourth quarter contributions.................                     2,843
  Pension prepayment at December 31............   $ (2,642)      $   (148)


         The foregoing includes the Company's portion of amounts applicable to
employees at power stations which are owned jointly with affiliates.

         In determining the actuarial present value of the projected benefit
obligation at September 30, 1995, 1994, and 1993, the discount rates used were
7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation
levels were 4.5%, 4.75%, and 4.75%, respectively.  The expected long-term rate
of return on assets was 9% in each of the years 1995, 1994, and 1993.

Note G - Postretirement Benefits Other
Than Pensions:

         The cost of postretirement benefits other than pensions (principally
health care and life insurance) for employees and covered dependents in 1995
and 1994, a portion of which (about 25% to 30%) was charged to plant construc-
tion, included the following components:
<PAGE>
                                 163

                                                     1995          1994
                                                   (Thousands of Dollars)

Service cost - benefits earned..................   $ 1,055       $ 1,154
Interest cost on accumulated
  postretirement benefit obligation.............     4,595         4,461
Actual (return) loss on plan assets.............    (1,990)           31
Amortization of unrecognized
  transition obligation.........................     2,830         2,817
Other net amortization and deferral.............     1,610            83
Postretirement cost.............................     8,100         8,546
Regulatory reversal.............................       137          -    
Net postretirement cost.........................   $ 8,237       $ 8,546


         The benefits earned to date and funded status of the Company's share of
the System plan at December 31 using a measurement date of September 30 were
as follows:

                                                     1995          1994
                                                   (Thousands of Dollars)

Accumulated postretirement benefit obligation
  (APBO):
    Retirees....................................   $36,041       $35,895
    Fully eligible employees....................     7,802         8,290
    Other employees.............................    17,608        17,013
      Total obligation..........................    61,451        61,198
Plan assets at market value in common stocks,
  fixed income securities, and short-term
  investments...................................    12,512         6,173
Accumulated postretirement benefit
  obligation in excess of plan assets...........    48,939        55,025
Less:
  Unrecognized cumulative net gain from
    past experience different from
    that assumed................................    (3,292)         (543)
  Unrecognized transition obligation,
    being amortized over 20 years
    beginning January 1, 1993...................    48,099        50,929
Postretirement benefit liability
  at September 30...............................     4,132         4,639
Fourth quarter contributions
  and benefit payments..........................     3,649         2,113
Postretirement benefit liability
  at December 31................................   $   483       $ 2,526
<PAGE>
                                 164

         In determining the APBO at September 30, 1995, 1994, and 1993, the
discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in
future compensation levels were 4.5%, 4.75%, and 4.75%, respectively.  The
1995 expected long-term rate of return on assets was 8.25% net of tax.  For
measurement purposes, a health care trend rate of 8% for 1996, declining 1%
each year thereafter to 6.5% in the year 1998 and beyond, and plan provisions
which limit future medical and life insurance benefits, were assumed. 
Increasing the assumed health care trend rate by 1% in each year would
increase the APBO at December 31, 1995, by $4.0 million and the aggregate of
the service and interest cost components of net periodic postretirement
benefit cost for 1995 by $.4 million.  

Note H - Fair Value of Financial Instruments:

         The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:

                                    1995                      1994       
                           Carrying       Fair       Carrying       Fair
                            Amount        Value       Amount        Value
                                       (Thousands of Dollars)
Assets:     
  Temporary cash      
    investments........   $    425     $    425      $     73     $     73
Liabilities:
  Short-term debt......     70,218       70,218          -             -
  Long-term debt 
  and QUIDS............    913,985      955,336       870,985      826,003


       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 does
not have any financial instruments held or issued for trading purposes.

       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.

Note I - Capitalization:

COMMON STOCK AND OTHER PAID-IN CAPITAL:
         The Company issued and sold common stock to its parent, at $20 per
share, 2,000,000 shares in October 1994 and 5,000,000 shares in 1993.  Other
paid-in capital decreased $212,000 in 1995 as a result of preferred stock
transactions and decreased $145,000 in 1993 due to underwriting fees and
commissions and miscellaneous expenses associated with the Company's sale of
$40 million of preferred stock in 1992.
<PAGE>
                                 165

PREFERRED STOCK:
         In 1995, the Company refunded $70 million of preferred stock with
dividend rates between 7% and 8.2%, with the proceeds from the issuance of
Quarterly Income Debt Securities (QUIDS) described below.  All of the
preferred stock is entitled on voluntary liquidation to its then current call
price and on involuntary liquidation to $100 per 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 for the next five years are:  1996 and
1997, none; 1998, $103,500,000; 1999, $1,500,000; and 2000, $2,500,000. 
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.

         In 1995, the Company sold $30 million of 7-3/4% 30-year first mortgage
bonds to refund a $30 million 9% issue due in 2019.  The Company also issued
$31.5 million of 6.15% 20-year tax-exempt notes to refund a $20 million 7%
issue and an $11.5 million 6.95% issue and issued $15.4 million of 6.05% 19-
year tax-exempt notes to refund a $15.4 million 9-3/8% issue.

         In 1995, the Company issued $70 million of 8% 30-year QUIDS to refund
preferred stock.  QUIDS may not be redeemed until the year 2000.  Under
certain circumstances the interest payments may be deferred for a period of up
to 20 consecutive quarters.

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
$170 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 internal money pool accommodates intercompany short-term borrowing needs,
to the extent that certain of the companies have funds available.  In January
1994, the Company and its affiliates jointly established an aggregate $300
million multi-year credit program which provides that the Company may borrow
up to $135 million on a standby revolving credit basis.  Short-term debt
outstanding for 1995 and 1994 consisted of:

                                              1995               1994
                                              (Thousands of Dollars)
Balance at end of year:
    Commercial Paper..................    $36,318-6.09%
    Notes Payable to Banks............     33,900-5.90%
Average amount outstanding during 
  the year:
    Commercial Paper..................    $ 5,692-6.00%       $2,216-4.38%
    Notes Payable to Banks............      5,342-5.96%        2,379-4.37%
    Money Pool........................        592-5.79%          521-4.24%
<PAGE>
                                166
Note K - Commitments and Contingencies:

CONSTRUCTION PROGRAM:
         The Company has entered into commitments for its construction program,
for which expenditures are estimated to be $125 million for 1996 and 
$126 million for 1997.  Through 1999, annual construction expenditures are not
expected to significantly exceed 1996 estimated levels.  Construction
expenditure levels in 2000 and beyond will depend upon future generation 
requirements, as well as the strategy eventually selected for complying with
Phase II of the Clean Air Act Amendments of 1990.

ENVIRONMENTAL MATTERS AND LITIGATION:
         System companies are subject to various laws, regulations, and uncer-
tainties 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 affect adversely the lead time, size, and
siting of future generating stations, increase the complexity and cost of
pollution control equipment, and otherwise add to the cost of future opera-
tions.     In the normal course of business, the Company becomes involved in
various legal proceedings.  The Company does not believe that the ultimate
outcome of these proceedings will have a material effect on its financial
position.

       The Company previously reported that the Environmental Protection Agency
had identified it and its affiliates and approximately 875 others as poten-
tially responsible parties in a Superfund site subject to cleanup.  The
Company has also been named as a defendant along with multiple other defen-
dants 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.

         The Company is guarantor as to 45% of a $50 million revolving credit
agreement of AGC, which in 1995 was used by AGC solely as support for its
indebtedness for commercial paper outstanding.
<PAGE>
                                 167
<TABLE>
<CAPTION>
AGC
STATEMENT OF INCOME 
                                                                         YEAR ENDED DECEMBER 31
                                                                       1995       1994       1993
                                                                         (Thousands of Dollars)

<S>                                                                  <C>        <C>        <C>
Electric Operating Revenues.......................................   $86,970    $91,022    $90,606

Operating Expenses:
  Operation and maintenance expense...............................     5,740      6,695      6,609
  Depreciation....................................................    17,018     16,852     16,899 
  Taxes other than income taxes...................................     5,091      5,223      5,347 
  Federal income taxes (Note B)...................................    13,552     14,737     13,262
    Total Operating Expenses......................................    41,401     43,507     42,117
    Operating Income..............................................    45,569     47,515     48,489

Other Income and Deductions.......................................        16         11        328
  Income Before Interest Charges..................................    45,585     47,526     48,817

Interest Charges:
  Interest on long-term debt......................................    16,859     16,863     21,185
  Other interest..................................................     1,502        946        450
    Total Interest Charges........................................    18,361     17,809     21,635

Net Income........................................................   $27,224    $29,717    $27,182


            
STATEMENT OF RETAINED EARNINGS

Balance at January 1..............................................   $12,729    $18,512    $25,530
Add:
  Net income......................................................    27,224     29,717     27,182
                                                                      39,953     48,229     52,712
Deduct:
  Dividends on common stock.......................................    35,800     35,500     34,200

Balance at December 31............................................   $ 4,153    $12,729    $18,512


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                 168
<TABLE>
<CAPTION>
AGC

STATEMENT OF CASH FLOWS 
                                                                          YEAR ENDED DECEMBER 31
                                                                        1995       1994        1993
                                                                          (Thousands of Dollars)

Cash Flows from Operations:   
  <S>                                                                <C>         <C>         <C>
  Net income......................................................   $ 27,224    $ 29,717    $ 27,182
  Depreciation....................................................     17,018      16,852      16,899   
  Deferred investment credit and income taxes, net................      6,508       9,567       5,321      
  Changes in certain current assets and liabilities:
    Accounts receivable...........................................     (3,758)      7,099      (6,118)
    Materials and supplies........................................        144          (2)       (163)
    Accounts payable..............................................        (32)         37           6
    Taxes accrued.................................................         80        (216)       (153)
    Interest accrued..............................................        251        (200)        632
  Other, net......................................................      2,703      (7,133)      4,851
                                                                       50,138      55,721      48,457

Cash Flows from Investing:
  Construction expenditures.......................................     (2,177)     (1,065)     (2,739)


Cash Flows from Financing:
  Issuance of long-term debt......................................                            198,075
  Retirement of long-term debt....................................    (12,175)    (19,126)   (209,598)
  Cash dividends on common stock..................................    (35,800)    (35,500)    (34,200)
                                                                      (47,975)    (54,626)    (45,723)

Net Change in Cash................................................        (14)         30          (5)
Cash at January 1.................................................         45          15          20
Cash at December 31...............................................   $     31    $     45    $     15


Supplemental Cash Flow Information
  Cash paid during the year for:
    Interest......................................................   $ 17,165    $ 17,078    $ 21,109
    Income taxes..................................................      5,274       7,137       8,220


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                 169
<TABLE>
<CAPTION>
AGC

BALANCE SHEET                                                                 
                                                                                 DECEMBER 31
ASSETS                                                                       1995          1994
                                                                           (Thousands of Dollars)
Property, Plant, and Equipment: 
  At original cost, including $412,000 and
    <S>                                                                   <C>           <C>
    $21,000 under construction......................................      $ 836,894     $ 824,714
  Accumulated depreciation..........................................       (159,037)     (143,965)
                                                                            677,857       680,749


Current Assets:
  Cash..............................................................             31            45 
  Accounts receivable from parents..................................          5,274         1,516
  Materials and supplies--at average cost...........................          2,049         2,193
  Other.............................................................            232         2,237
                                                                              7,586         5,991

Deferred Charges:
  Regulatory assets (Note B)........................................         14,617         4,449
  Unamortized loss on reacquired debt...............................          9,900        10,653
  Other.............................................................            327        12,394
                                                                             24,844        27,496
Total...............................................................      $ 710,287     $ 714,236



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.............................................        209,999       209,999
  Retained earnings.................................................          4,153        12,729
                                                                            214,153       222,729
  Long-term debt (Note D)...........................................        249,709       267,165
                                                                            463,862       489,894

Current Liabilities:
  Long-term debt due within one year (Note D).......................          6,375         1,000
  Accounts payable..................................................             16            48
  Interest accrued..................................................          5,151         4,900
  Taxes accrued.....................................................            113            33
  Other.............................................................            237           503
                                                                             11,892         6,484     

Deferred Credits:
  Unamortized investment credit.....................................         50,987        52,297
  Deferred income taxes.............................................        156,091       137,297
  Regulatory liabilities (Note B)...................................         27,455        28,264
                                                                            234,533       217,858
                                                                                
Total...............................................................      $ 710,287     $ 714,236


See accompanying notes to financial statements.
</TABLE>
<PAGE>
                                 170
AGC


NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)


Note A - Summary of Significant
Accounting Policies:

         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 Power System, Inc. and are a part of the Allegheny
Power integrated electric utility system.  The Company is subject to regula-
tion 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.

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 1995,
1994, and 1993.  The cost of maintenance and of certain replacements of
property, plant, and equipment is charged to operating expenses.

INCOME TAXES:
         The Company joins with its parents and affiliates in filing a consoli-
dated 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 utilizing the most current tax rates.
<PAGE>
                                 171

         Prior to 1987, provisions for federal income tax were reduced 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.

ACCOUNTING CHANGE:

       In March 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
effective in 1996.  The Company does not believe at this time that the
adoption of this standard will have a materially adverse effect on its
financial position.

Note B - Income Taxes:

         Details of federal income tax provisions are:

                                          1995         1994         1993
                                              (Thousands of Dollars)

Current income taxes payable..........  $ 7,053      $ 5,176      $ 8,112
Deferred income taxes- 
  accelerated depreciation............    7,818       10,883        6,637 
Amortization of deferred
  investment credit...................   (1,310)      (1,316)      (1,316)
    Total income taxes................   13,561       14,743       13,433
Income taxes--charged to     
  other income........................       (9)          (6)        (171)
Income taxes--charged to
  operating income....................  $13,552      $14,737      $13,262


         In 1995, the total provision for income taxes ($13,552,000) was less
than the amount produced by applying the federal income tax statutory rate to
financial accounting income before income taxes ($14,272,000), due primarily
to amortization of deferred investment credit ($1,310,000).

         Federal income tax returns through 1991 have been examined and substan-
tially settled.

         At December 31, the deferred tax assets and liabilities were comprised
of the following:

                                                    1995           1994
                                                  (Thousands of Dollars)
Deferred tax assets:
  Unamortized investment tax credit............   $ 27,455       $ 28,160
  Other........................................                       104
                                                    27,455         28,264
Deferred tax liabilities:
  Book vs. tax plant basis differences, net....    183,546        165,561
Total net deferred tax liabilities.............   $156,091       $137,297
<PAGE>
                                  172

         It is expected the FERC will allow recovery of the deferred tax
liabilities in future years as they are paid, and accordingly, the Company has
recorded regulatory assets of $14.6 million and $4.4 million as of 
December 31, 1995 and 1994, respectively.  Regulatory liabilities of 
$27.5 million and $28.3 million as of December 31, 1995 and 1994, respective-
ly, have been recorded in order to reflect the Company's obligation to pass
such tax benefits on to its customers as the benefits are realized in cash in
future years.

Note C - Fair Value of Financial Instruments:

         The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:

                                    1995                      1994       
                           Carrying       Fair       Carrying       Fair
                            Amount        Value       Amount        Value
                                       (Thousands of Dollars)
Liabilities:
  Long-term debt:
    Debentures.........    $150,000     $146,279     $150,000     $120,195
    Medium term notes..      76,975       78,075       77,975       73,704
    Commercial paper...      30,561       30,561       41,736       41,736
 
         The carrying amount of debentures and medium-term notes was based on
actual market prices or market prices of similar issues.  The carrying amount
of commercial paper approximates the fair value because of the short maturity
of those instruments.  The Company does not have any financial instruments
held or issued for trading purposes.

Note D - Long-Term Debt:

         The Company had long-term debt outstanding as follows:

                                      Interest          December 31      
                                      Rate - %       1995         1994
                                                  (Thousands of Dollars)
Debentures due:
  September 1, 2003...............      5.625      $ 50,000     $ 50,000
  September 1, 2023...............      6.875       100,000      100,000
Commercial paper..................      5.82 (1)     30,561       41,736
Medium term notes due 1995-1998...      6.36 (1)     76,975       77,975
Unamortized debt discount.........                   (1,452)      (1,546)
    Total.........................                  256,084      268,165
Less current maturities...........                    6,375        1,000
    Total.........................                 $249,709     $267,165

(1) Weighted average interest rate at December 31, 1995.
<PAGE>
                                 173

       The Company has a revolving credit agreement with a group of seven banks
which provides for loans of up to $50 million at any one time outstanding
through 1999.  Each bank has the option to discontinue its loans after 1999
upon three years' prior written notice.  Without such notice, the loans are
automatically extended for one year.  Amounts borrowed are guaranteed by the
Parents in proportion to their equity interest.  Interest rates are determined
at the time of each borrowing.  The revolving credit agreement serves as
support for the Company's commercial paper.  In addition to bank lines of
credit, an internal money pool accommodates intercompany short-term borrowing
needs, to the extent that certain of the Company's affiliates have funds
available.

         Maturities for long-term debt for the next five years are:  1996,
$6,375,000; 1997, $10,600,000; 1998, $60,000,000; 1999, $30,561,000; and 2000,
none.
<PAGE>
<TABLE>
<CAPTION>


                                                          S-1              SCHEDULE II


                                 ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES

                                           Valuation and Qualifying Accounts
                                   For Years Ended December 31, 1995, 1994, and 1993


           Col. A                   Col. B                 Col. C                   Col. D          Col. 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:


<S>                               <C>             <C>              <C>              <C>             <C> 
Year ended December 31, 1995      $11 352 674     $ 9 206 000      $ 3 130 418      $10 642 192     $13 046 900


Year ended December 31, 1994      $ 3 418 261     $14 714 000      $ 3 060 544      $ 9 840 131     $11 352 674
   

Year ended December 31, 1993      $ 3 364 104     $ 5 732 000      $ 2 546 341      $ 8 224 184     $ 3 418 261




(A)  Recoveries.
(B)  Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                          S-2              SCHEDULE II



                                               MONONGAHELA POWER COMPANY

                                           Valuation and Qualifying Accounts
                                   For Years Ended December 31, 1995, 1994, and 1993


           Col. A                   Col. B                 Col. C                   Col. D          Col. 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:


<S>                               <C>             <C>              <C>              <C>             <C>
Year ended December 31, 1995      $ 1 910 605     $ 2 266 000      $   700 288      $ 2 610 085     $ 2 266 808


Year ended December 31, 1994      $ 1 084 037     $ 2 240 000      $   667 910      $ 2 081 342     $ 1 910 605


Year ended December 31, 1993      $ 1 056 010     $ 1 210 000      $   604 387      $ 1 786 360     $ 1 084 037




(A)  Recoveries.
(B)  Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                          S-3              SCHEDULE II



                                              THE POTOMAC EDISON COMPANY

                                           Valuation and Qualifying Accounts
                                   For Years Ended December 31, 1995, 1994, and 1993


           Col. A                   Col. B                 Col. C                   Col. D          Col. 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:


<S>                               <C>             <C>              <C>              <C>             <C>
Year ended December 31, 1995      $ 1 175 437     $ 1 630 000      $   983 776      $ 2 445 136     $ 1 344 077


Year ended December 31, 1994      $ 1 207 979     $ 1 624 000      $ 1 007 652      $ 2 664 194     $ 1 175 437


Year ended December 31, 1993      $ 1 178 009     $ 1 412 000      $   790 089      $ 2 172 119     $ 1 207 979




(A)  Recoveries.
(B)  Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                          S-4              SCHEDULE II



                                   WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES

                                           Valuation and Qualifying Accounts
                                   For Years Ended December 31, 1995, 1994, and 1993


           Col. A                   Col. B                 Col. C                   Col. D          Col. 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:


<S>                               <C>             <C>              <C>              <C>             <C>
Year ended December 31, 1995      $ 8 266 632     $ 5 310 000      $ 1 446 354      $ 5 586 971     $ 9 436 015


Year ended December 31, 1994      $ 1 126 244     $10 850 000      $ 1 384 982      $ 5 094 594     $ 8 266 632
 

Year ended December 31, 1993      $ 1 130 085     $ 3 110 000      $ 1 151 865      $ 4 265 706     $ 1 126 244




(A)  Recoveries.
(B)  Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

Supplementary Data
Quarterly Financial Data (Unaudited)
(Thousands of Dollars)
                                                                                   Earnings Per
                     Electric                   Income Before                      Share Before
                     Operating    Operating   Cumulative Effect of     Net     Cumulative Effect of   Earnings
Quarter ended        Revenues      Income      Accounting Change     Income     Accounting Change     Per Share
APS
<S>                 <C>           <C>              <C>              <C>              <C>               <C>
March 1995          $699 988      $122 239         $ 76 129         $ 76 129         $ .64             $ .64
June 1995            603 091        89 613           42 693           42 693           .36               .36
September 1995       672 077       102 735           58 236           58 236           .49               .49
December 1995        672 652       107 526           62 634           62 634           .52               .52

March 1994           697 299       115 118           75 865          119 311           .65              1.02
June 1994            561 217        79 717           39 367           39 367           .33               .33
September 1994       591 123        90 855           49 807           49 807           .42               .42
December 1994        602 045       102 451           54 712           54 712           .46               .46

Monongahela
March 1995           187 702        26 676           19 470           19 470
June 1995            167 727        20 048           12 886           12 886
September 1995       186 616        24 161           16 979           16 979
December 1995        180 437        25 072           17 378           17 378

March 1994           187 909        24 294           17 580           25 525
June 1994            157 940        16 855           10 222           10 222
September 1994       165 932        20 613           13 523           13 523
December 1994        168 349        25 473           18 611           18 611

Potomac Edison
March 1995           218 348        34 983           26 439           26 439
June 1995            181 406        21 457           12 089           12 089
September 1995       205 049        26 770           16 727           16 727
December 1995        214 216        32 438           23 010           23 010

March 1994           223 648        37 350           30 607           47 078
June 1994            171 047        20 934           13 060           13 060
September 1994       179 114        23 109           15 028           15 028
December 1994        185 556        30 929           23 288           23 288

West Penn
March 1995           325 791        49 891           37 412           37 412
June 1995            282 088        36 781           24 613           24 613
September 1995       309 285        40 892           28 634           28 634
December 1995        309 177        40 889           27 220           27 220

March 1994           321 051        42 139           32 665           51 696
June 1994            263 946        30 877           22 006           22 006
September 1994       274 161        35 578           26 745           26 745
December 1994        269 084        33 300           19 599           19 599

AGC
March 1995            22 096        11 554            6 569            6 569
June 1995             22 061        11 516            7 093            7 093
September 1995        21 573        11 344            6 964            6 964
December 1995         21 240        11 155            6 598            6 598

March 1994            22 431        11 509            7 085            7 085
June 1994             21 869        11 253            6 771            6 771
September 1994        22 337        11 551            7 087            7 087
December 1994         24 385        13 202            8 774            8 774
</TABLE>
<PAGE>
                                 174

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

          For APS and the Subsidiaries, none.
                                                  PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

         APS, 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, and the business experience during the past five years of the
directors of the System companies are set forth below:
<TABLE>
<CAPTION>
                         Business Experience during                Director since date shown of
         Name               the Past Five Years            Age      APS      MP      PE       WP      AGC 
<S>                      <C>                               <C>     <C>     <C>      <C>     <C>
Eleanor Baum             See below  (a)                    55      1988    1988     1988    1988 
William L. Bennett       See below  (b)                    46      1991    1991     1991    1991             
Klaus Bergman            System employee  (1)              64      1985    1985     1985    1979      1982
Stanley I. Garnett,II*   System employee  (1)              52              1990     1990    1990      1990
Wendell F. Holland       See below  (c)                    43      1994    1994     1994    1994    
Kenneth M. Jones         System employee  (1)              58                                         1991
Phillip E. Lint          See below  (d)                    66      1989    1989     1989    1989
Edward H. Malone         See below  (e)                    71      1985    1985     1985    1985
Frank A. Metz, Jr.       See below  (f)                    61      1984    1984     1984    1984
Alan J. Noia             System employee  (1)              48      1994    1994     1987    1994      1994
Jay S. Pifer             System employee  (1)              58              1995     1995    1992
Steven H. Rice           See below  (g)                    52      1986    1986     1986    1986
Gunnar E. Sarsten        See below  (h)                    58      1992    1992     1992    1992
Peter L. Shea            See below  (i)                    63      1993    1993     1993    1993
Peter J. Skrgic          System employee  (1)              54              1990     1990    1990      1989
</TABLE>

(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. 
         Commissioner of the Engineering Manpower Commission, a fellow of the 
         Institute of Electrical and Electronic Engineers, member of Board of 
         Governors, New York Academy of Sciences and President, American 
         Society of Engineering Education.

(b)      William L. Bennett.  Chairman, HealthPlan Services Corporation, a 
         leading managed health care services company.  Formerly, Chairman and 
         Chief Executive Officer of Noel Group, Inc.  Director of
         Belding Heminway Company, Inc., Global Natural Resources Inc., 
         Noel Group, Inc. and Sylvan, Inc.

(c)      Wendell F. Holland.  Of Counsel, Law Firm of Reed, Smith, Shaw & 
         McClay.  Formerly, 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)      Edward H. Malone.  Retired.  Formerly, Vice President of General 
         Electric Company and Chairman, eneral Electric Investment
         Corporation. Director of Fidelity Group of Mutual Funds, General Re
         Corporation, and Mattel, Inc.

(f)      Frank A. Metz, Jr.  Retired.  Formerly, Senior Vice President, 
         Finance and Planning, and Director, International Business Machines 
         Corporation.  Director of Monsanto Company and Norrell Corporation.

(g)      Steven H. Rice.  Bank consultant and attorney-at-law.  Director and 
         Vice Chairman of the Board of Stamford Federal Savings Bank.  
         Formerly, President and Director of The Seamen's Bank for Savings
         and Director of Royal Group, Inc. 

(h)      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, Inc.), and Deputy Chairman of the Third 
         District Federal Reserve Bank in Philadelphia.

(i)      Peter L. Shea.  Managing director of Hydrocarbon Energy, Inc., a 
         privately owned oil and gas development drilling and production 
         company and an Individual General Partner of Panther Partners,
         L.P., a closed-end, non-diversified management company.  Member and 
         Manager of Temblor Petroleum Company L.L.C., a privately owned oil 
         and gas exploration and production company operating
         exclusively in California.

*  Stanley I. Garnett, II resigned effective December 1, 1995.
<PAGE>
                                 175
<TABLE>
<CAPTION>

ITEM ll.   EXECUTIVE COMPENSATION
         During 1995, and for 1994 and 1993, the annual compensation paid by the System companies, APS, APSC,
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)
                               APS(b), Monongahela, Potomac Edison, West Penn and AGC(c)
                                                  Annual Compensation
                                                                                            Other        All 
Name                                                                                        Annual       Other
and                                                                                         Compen-     Compen-
Principal                                                                                   sation      sation
Position(d)                             Year               Salary($)       Bonus($)(e)      ($)(f)      ($)(g)(h)
<S>                                     <C>                 <C>             <C>              <C>         <C>
Klaus Bergman,                          1995                515,000         187,500                      63,677
Chief Executive                         1994                485,004         120,000                      91,458
Officer                                 1993                460,008          90,000                      46,889

Alan J. Noia,                           1995                305,000         120,000                      48,983
President and                           1994                236,336          57,000                      47,867
Chief Operating Officer                 1993                212,500          37,000                      20,107

Peter J. Skrgic,                        1995                238,000          73,800                      37,830
Senior Vice President                   1994                213,336          50,000                      57,253
                                        1993                185,004          38,000           (i)        18,678

Jay S. Pifer,                           1995                220,000          72,600                      34,098
President of each                       1994                189,996          39,000                      50,630
Operating Subsidiary                    1993                175,500          25,000                      18,093

Nancy H. Gormley,                       1995                187,500          42,000                      51,776(k)
Vice President (j)                      1994                175,008          37,000                      22,478
                                        1993                162,504          28,000                      15,446
                  
(a)       In 1995, Allegheny Power put into effect a unified management structure in which executive management
          positions were consolidated.  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 APS, APSC and
          the Subsidiaries.  All salaries and bonuses of these executives are paid by APSC.

(b)       APS has no paid employees.

(c)       AGC has no paid employees.

(d)       See Executive Officers of the Registrants for all positions held.

(e)       Incentive awards are based upon performance in the year in which the figure appears but are paid in the
          first quarter of the following year.  The incentive award plan will be continued for 1996.

(f)       Amounts constituting less than 10% of the total annual salary and bonus are not disclosed.  All officers
          did receive miscellaneous other items amounting to less than 10% of total annual salary and bonus.

(g)       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 5 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.  Effective January 1, 1993,
          APS started to provide funds to pay for the future benefits due under the supplemental retirement plan
          (Secured Benefit Plan) as described in note (a) on p.176.  To do this, APS purchased, during 1993, life
          insurance on the lives of the covered executives.  The premium costs of both the 1992 and 1993 policies
          plus a factor for the use of the money are returned to APS 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.  The figures in this column
          include the present value of the executives' cash value at retirement attributable to the current year's
          premium payment (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 401(k) plan.  For 1995, 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) 401(k) contributions as follows:  Mr. Bergman 
          $59,177 and $4,500; Mr. Noia $44,483 and $4,500; Mr. Skrgic $33,855 and $3,975; Mr. Pifer $29,598 and
          $4,500; and Ms. Gormley $24,199 and $4,500, respectively.

(h)       In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance
          Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual
          meeting in May 1994.  The first Plan cycle began on January 1, 1994 and will end on December 31, 1996.  A
          second cycle began January 1, 1995 and will end on December 31, 1997.  A third cycle began January 1, 1996
          and will end on December 31, 1998.  After completion of all cycles, performance share awards or cash may
          be granted if performance criteria have been met.  Since the Plan cycles are not completed, no awards have
          been granted and the amount which any named executive officer will receive has not yet been determined.

(i)       Although less than 10% of total annual salary and bonus, Mr. Skrgic received a $15,000 housing allowance
          in 1993.

(j)       Retired effective January 1, 1996.

(k)       Included in this amount is $23,077 representing accrued vacation for which she was paid.
</TABLE>
<PAGE>
                                176
<TABLE>
<CAPTION>
                                   DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE (a)
                               APS(b), Monongahela, Potomac Edison, West Penn and AGC(c)

                                                                              Estimated
          Name and Capacitites                                             Annual Benefits
            In Which Served                                                on Retirement (d)

          <S>                                                                 <C>
          Klaus Bergman,                                                      $242,212
          Chairman of the Board and
          Chief Executive Officer (e)(f)(g)

          Alan J. Noia, President                                              183,002
          and Chief Operating Officer (e)(g)

          Peter J. Skrgic,                                                     142,805
          Senior Vice President (e)(g)

          Jay S. Pifer,                                                        129,063
          President of each of 
          the Operating Subsidiaries (e)(g)

          Nancy H. Gormley,                                                     72,335
          Vice President (e)(h)
                    
(a)       In 1995, Allegheny Power put into effect a unified management structure in which executive management
          positions were consolidated.  The individuals appearing in this chart perform policy-making functions for
          each of the Registrants.

(b)       APS has no paid employees.

(c)       AGC has no paid employees.

(d)       Assumes present insured benefit plan and salary continue and retirement at age 65 with single life
          annuity.  Under plan provisions, the annual rate of benefits payable at the normal retirement age of 65
          are computed by adding (i) 1% of final average pay up to covered compensation times years of service up to
          35 years, plus (ii) 1.5% of final average pay in excess of covered compensation times years of service up
          to 35 years, plus (iii) 1.3% of final average pay times years of service in excess of 35 years.  Covered
          compensation is the average of the maximum taxable Social Security wage bases during the 35 years
          preceding the member's retirement.  The final average pay benefit is based on the member's average total
          earnings during the highest-paid 60 consecutive calendar months or, if smaller, the member's highest rate
          of pay as of any July 1st.  Effective July 1, 1994 the maximum amount of any employee's compensation that
          may be used in these computations was decreased to $150,000.  Benefits for employees retiring between 55
          and 62 differ from the foregoing. 

          Pursuant to a supplemental plan (Secured Benefit Plan), senior executives of Allegheny Power System
          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 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.  In order to provide funds to pay such
          benefits, effective January 1, 1993 the Company purchased insurance on the lives of the plan participants. 
          The Secured Benefit Plan has been designed that 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 amount of the premiums for this insurance required to be deemed
          "compensation" by the SEC is described and included in the "All Other Compensation" column on page    . 
          All executive officers are participants in the Secured Benefit Plan.  This does not include benefits from
          an 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.  Under the ESOSP for 1995, all eligible employees may elect to have from 2% to 7% 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 available funds. 
          Each System company matches 50% of the pre-tax contributions up to 6% of compensation with common stock of
          Allegheny Power System, Inc.  Effective January 1, 1994 the maximum amount of any employee's compensation
          that may be used in these computations was decreased to $150,000.  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.

(e)       See Executive Officers of the Registrants for all positions held.

(f)       Mr. Bergman is retiring effective June 1, 1996 as Chief Executive Officer.

(g)       The total estimated annual benefits on retirement payable to Messrs. Bergman, Noia, Pifer, and Skrgic 
          for services in all capacities to APS, APSC and the Subsidiaries is set forth in the table.

(h)       Ms. Gormley retired effective January 1, 1996.  The actual amount she is receiving for services in all
          capacities to APS, APSC and the Subsidiaries is set forth in the table.
</TABLE>
<PAGE>
                                  177
                                                 Employment Contracts

          In February 1995, APS entered into employment contracts with certain 
Allegheny Power 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 APS (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 APS 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 annualized 
compensation and APS will maintain existing benefits for the employee and the
employee's dependents for a period of three years.  Each Agreement initially 
expires on December 31, 1997 but will be automatically extended for one year 
periods thereafter unless either APS or the employee gives notice otherwise. 
Notwithstanding the delivery of such notice, the Agreements will continue in 
effect for twenty-four months after a Change in Control.


                                 Compensation of Directors

          In 1995, APS 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 meeting attend-
ed, except Executive Committee meetings, for which fees are $200, and
(c) $250 for each Board meeting of each company attended.  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.

          Effective January 1, 1995, in addition to the fees mentioned
above, the Chairperson of each of the Audit, Finance, Management
Review, and New Business Committees will receive a further fee of
$4,000 per year, and the retainer fee paid outside directors will be
increased by 200 shares of APS common stock pursuant to the Restricted
Stock Plan for Outside Directors which was adopted effective January
1, 1995.  Also adopted effective January 1, 1995 was a Directors'
Retirement Plan which will provide an annual pension equal to the
retainer fee paid to the outside director at the time of his or her
retirement, provided the director has at least five (5) years of
service and, except under special circumstances described in the Plan,
serves until age 65.
<PAGE>
                                178
<TABLE>
<CAPTION>

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
              MANAGEMENT

        The table below shows the number of shares of APS common stock that are
beneficially owned, directly or indirectly, by each director and named executive
officer of APS, 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, 1995.  To
the best of the knowledge of APS, there is no person who is a beneficial owner of
more than 5% of the voting securities of APS.

                                        Executive                   Shares of
                                        Officer or                     APS                      Percent
Name                                    Director of                Common Stock                 of Class

<S>                                     <C>                           <C>                   <C>
Eleanor Baum                            APS,MP,PE,WP                   2,200                  Less than .01%
William L. Bennett                      APS,MP,PE,WP                   2,749                        "
Klaus Bergman                           APS,MP,PE,WP,AGC              11,390                        "
Stanley I. Garnett, II*                 APS,MP,PE,WP,AGC               4,911                        "
Nancy H. Gormley**                      APS, MP                        6,185                        "
Wendell F. Holland                      APS,MP,PE,WP                     350                        "
Phillip E. Lint                         APS,MP,PE,WP                     810                        "
Edward H. Malone                        APS,MP,PE,WP                   1,668                        "
Frank A. Metz, Jr.                      APS,MP,PE,WP                   2,275                        "
Alan J. Noia                            APS,MP,PE,WP,AGC              12,436                        "
Jay S. Pifer                            APS,MP,PE,WP                   8,595                        "
Steven H. Rice                          APS,MP,PE,WP                   2,512                        "
Gunnar E. Sarsten                       APS,MP,PE,WP                   6,200                        "
Peter L. Shea                           APS,MP,PE,WP                   1,800                        "
Peter J. Skrgic                         APS,MP,PE,WP,AGC               6,198                        "

All directors and executive officers
of APS as a group (19 persons)                                        85,994                  Less than .075% 

All directors and executive officers                                 110,839                        "
of MP as a group (24 persons)                                               

All directors and executive officers                                  98,461                        "
of PE as a group (22 persons)                                               

All directors and executive officers
of WP as a group (23 persons)                                         98,629                        "

All directors and executive officers
of AGC as a group (9 persons)                                         54,235                        "

                                    
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 APS.  All of the common stock of AGC is owned by Monongahela (270 shares), Potomac Edison
(280 shares), and West Penn (450 shares).

*        Mr. Garnett resigned effective December 1, 1995.
**       Ms. Gormley retired effective January 1, 1996.
</TABLE>
<PAGE>
                                 178

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
     
         In connection with the relocation of the New York office, Allegheny
Power made available to each employee involved in the relocation an interest-
free loan of up to 95% of the appraised equity in the employee's current
residence for the purchase of a new residence.  The loans must be repaid to
Allegheny Power upon actual relocation.  In addition, interest paid by an
employee on a new mortgage will be reimbursed by Allegheny Power until the
actual date of relocation.  On October 10, 1995, Allegheny Power made an
interest-free loan in the amount of $215,000 to Richard J. Gagliardi, a Vice
President of APS.  On December 7, 1995, Allegheny Power made an interest-free
loan in the amount of $75,000 to Thomas K. Henderson, a Vice President of
Monongahela, Potomac Edison and West Penn.  On January 5, 1996, Allegheny
Power made an interest-free loan in the amount of $61,000 to Peter J. Skrgic,
a Senior Vice President of APS and a Vice President of Potomac Edison and AGC. 
Appropriate monthly interest payments as described above also have been and
will be paid.


                                                   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 97.

(b)  No reports on Form 8-K were filed by System companies during the quarter
ended December 31, 1995.

(c)  Exhibits for APS, 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>
                                  179
                                            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 POWER SYSTEM, INC.


                                              By:   KLAUS BERGMAN              
                                                   (Klaus Bergman
                                                   Chief Executive Officer)
Date:  February 1, 1996

         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.

                    Signature                     Title                 Date  

(i)       Principal Executive Officer:
                                           Chairman of the Board,       2/1/96
              KLAUS BERGMAN                Chief Executive Officer,
             (Klaus Bergman)               and Director


(ii)      Principal Financial Officer:

              ALAN J. NOIA                 Chief Operating Officer      2/1/96
             (Alan J. Noia)                and Director


(iii) Principal Accounting Officer:

              KENNETH M. JONES             Vice President               2/1/96
             (Kenneth M. Jones)            and Controller                     

(iv)      A Majority of the Directors:

         *Eleanor Baum                                     *Frank A. Metz, Jr.
         *William L. Bennett                               *Steven H. Rice
         *Klaus Bergman                                    *Alan J. Noia
         *Wendell F. Holland                               *Gunnar E. Sarsten
         *Phillip E. Lint                                  *Peter L. Shea
         *Edward H. Malone

*By:        THOMAS K. HENDERSON                                         2/1/96
           (Thomas K. Henderson)
<PAGE>
                                  180
                                            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:  JAY S. PIFER              
                                                  (Jay S. Pifer, President)

Date:  February 1, 1996                   

         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.

                    Signature                  Title                     Date  
(i)       Principal Executive Officer:
                                            Chairman of the Board,      2/1/96
                KLAUS BERGMAN               Chief Executive Officer,     
               (Klaus Bergman)              and Director

(ii)      Principal Financial Officer:

                NANCY L. CAMPBELL           Treasurer                   2/1/96 
               (Nancy L. Campbell)                                           

(iii) Principal Accounting Officer:

                THOMAS J. KLOC              Controller                  2/1/96 
               (Thomas J. Kloc)

(iv)      A Majority of the Directors:

          *Eleanor Baum                                    *Alan J. Noia
          *William L. Bennett                              *Jay S. Pifer
          *Klaus Bergman                                   *Steven H. Rice
          *Wendell F. Holland                              *Gunnar E. Sarsten  
          *Phillip E. Lint                                 *Peter L. Shea
          *Edward H. Malone                                *Peter J. Skrgic
          *Frank A. Metz, Jr.

*By:        THOMAS K. HENDERSON                                         2/1/96
           (Thomas K. Henderson)
<PAGE>
                                 181


                                                      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: JAY S. PIFER                  
                                              (Jay S. Pifer, President)  
Date:  February 1, 1996

         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.

                    Signature                    Title                   Date  
(i)       Principal Executive Officer:
                                          Chairman of the Board,        2/1/96
                KLAUS BERGMAN             Chief Executive Officer,    
               (Klaus Bergman)            and Director


(ii)      Principal Financial Officer:

                NANCY L. CAMPBELL         Treasurer                     2/1/96
               (Nancy L. Campbell)

(iii) Principal Accounting Officer:

                THOMAS J. KLOC            Controller                    2/1/96
               (Thomas J. Kloc)

(iv)      A Majority of the Directors:

          *Eleanor Baum                                    *Alan J. Noia      
          *William L. Bennett                              *Jay S. Pifer
          *Klaus Bergman                                   *Steven H. Rice
          *Wendell F. Holland                              *Gunnar E. Sarsten   
          *Phillip E. Lint                                 *Peter L. Shea
          *Edward H. Malone                                *Peter J. Skrgic
          *Frank A. Metz, Jr.

*By:       THOMAS K. HENDERSON                                          2/1/96
          (Thomas K. Henderson)
<PAGE>
                                   182
                                           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: JAY S. PIFER            
                                                  (Jay S. Pifer, President)
Date:  February 1, 1996

         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.

                    Signature                    Title                   Date  
(i)       Principal Executive Officer:
                                           Chairman of the Board,       2/1/96
               KLAUS BERGMAN               Chief Executive Officer,
              (Klaus Bergman)              and Director

(ii)      Principal Financial Officer:

               NANCY L. CAMPBELL           Treasurer                    2/1/96
              (Nancy L. Campbell)

(iii) Principal Accounting Officer:

               THOMAS J. KLOC              Controller                   2/1/96
              (Thomas J. Kloc)

(iv)      A Majority of the Directors:

          *Eleanor Baum                                    *Alan J. Noia
          *William L. Bennett                              *Jay S. Pifer
          *Klaus Bergman                                   *Steven H. Rice      
          *Wendell F. Holland                              *Gunnar E. Sarsten  
          *Phillip E. Lint                                 *Peter L. Shea
          *Edward H. Malone                                *Peter J. Skrgic
          *Frank A. Metz, Jr.
         
*By:          THOMAS K. HENDERSON                                       2/1/96
             (Thomas K. Henderson)
<PAGE>

                                  183
                                            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: KLAUS BERGMAN               
                                                 (Klaus Bergman, President
                                                  and Chief Executive
                                                  Officer)
Date:  February 1, 1996                     

         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.

                    Signature                     Title                 Date  
(i)       Principal Executive Officer: 

               KLAUS BERGMAN                   President,               2/1/96 
              (Klaus Bergman)                  Chief Executive Officer,
                                               and Director 

(ii)      Principal Financial Officer:

               NANCY L. CAMPBELL               Treasurer and            2/1/96
              (Nancy L. Campbell               Assistant Secretary

(iii) Principal Accounting Officer:

               THOMAS J. KLOC                  Controller               2/1/96
              (Thomas J. Kloc)

(iv)      A Majority of the Directors:

              *Klaus Bergman
              *Kenneth M. Jones
              *Alan J. Noia
              *Peter J. Skrgic


*By:         THOMAS K. HENDERSON                                        2/1/96
            (Thomas K. Henderson)
<PAGE>
                                 184

                                     CONSENT OF INDEPENDENT ACCOUNTANTS 


            We hereby consent to the incorporation by reference in the Prospec-
tus constituting part of Allegheny Power System, Inc.'s Registration Statement
on Form S-3 (Nos. 33-36716 and 33-57027) relating to the Dividend Reinvestment
and Stock Purchase Plan of Allegheny Power System, Inc.; in the Prospectus
constituting part of Allegheny Power System, Inc.'s 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. 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. 33-51305 and 33-59493); and in the Prospectus 
constituting part of West Penn Power Company's Registration Statements on 
Form S-3 (Nos. 33-51303, 33-56997, 33-52862, 33-56260 and 33-59133); of our
reports dated February 1, 1996 included in ITEM 8 of this Form 10-K.  We also
consent to the references to us under the heading "Experts" in such Prospec-
tuses.


                                                   PRICE WATERHOUSE LLP
                                                   PRICE WATERHOUSE LLP


New York, New York
March 12, 1996
<PAGE>
                                 185
                                              POWER OF ATTORNEY


         KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of
Allegheny Power System, 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, 1995 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 under-
signed 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:  February 1, 1996

           ELEANOR BAUM                           FRANK A. METZ, JR.
          (Eleanor Baum)                         (Frank A. Metz, Jr.)
 
           WILLIAM L. BENNETT                     ALAN J. NOIA
          (William L. Bennett)                   (Alan J. Noia)
  
           KLAUS BERGMAN                          STEVEN H. RICE
          (Klaus Bergman)                        (Steven H. Rice)

           WENDELL F. HOLLAND                     GUNNAR E. SARSTEN  
          (Wendell F. Holland)                   (Gunnar E. Sarsten)

           PHILLIP E. LINT                        PETER L. SHEA
          (Phillip E. Lint)                      (Peter L. Shea)

           EDWARD H. MALONE
          (Edward H. Malone)
<PAGE>
                                  186
                                              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, 1995 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:  February 1, 1996                        



                                                       JAY S. PIFER
                                                      (Jay S. Pifer)

                                                       PETER J. SKRGIC
                                                      (Peter J. Skrgic)
<PAGE>

                                187

                                              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, 1995 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:  February 1, 1996



                                                    KLAUS BERGMAN
                                                   (Klaus Bergman)

                                                    KENNETH M. JONES
                                                   (Kenneth M. Jones)

                                                    ALAN J. NOIA
                                                   (Alan J. Noia) 

                                                    PETER J. SKRGIC
                                                   (Peter J. Skrgic)
<PAGE>
<TABLE>
<CAPTION>
                                                     E-1

                                                EXHIBIT INDEX
                                                (Rule 601(a))

Allegheny Power System, Inc.
                                                                 Incorporation
              Documents                                          by Reference 

<S>           <C>                                              <C>
3.1           Charter of the Company,                          Form 10-Q of the Company 
              as amended                                       (1-267), September 1993,
                                                               exh. (a)(3)

3.2           By-laws of the Company,                          Form 10-Q of the Company
              as amended November 2, 1995                      (1-267), September 1995,
                                                               exh. (a)(3)(ii)

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, 1994,
                                                               exh. 10.2

10.3          Allegheny Power System Incentive                 Form 10-K of the Company
                Compensation Plan                              (1-267), December 31, 1994,
                                                               exh. 10.3

10.4          Allegheny Power System                           Form 10-K of the Company
                Supplemental Executive                         (1-267), December 31, 1994,
                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                            Form 10-K of the Company
                for Outside Directors                          (1-267), December 31, 1994,
                                                               exh. 10.7

10.8          Retirement Plan                                  Form 10-K of the Company
                for Outside Directors                          (1-267), December 31, 1994,
                                                               exh. 10.8
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                E-1 (Cont'd)

                                                EXHIBIT INDEX
                                                (Rule 601(a))

Allegheny Power System, Inc.
                                                                 Incorporation
              Documents                                          by Reference 

<S>           <C>                                              <C>
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                        Form 8-K of the Company (1-267),
                Employment Contract                            dated February 15, 1995,
                                                               exh. 10.1

11            Statement re computation of per share earnings:
                Clearly determinable from the financial statements
                contained in Item 8.

21            Subsidiaries of APS:

         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 184 herein.

24            Powers of Attorney                                           See pages 185-187 herein.

27            Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                     E-2
Monongahela Power Company
                                                                 Incorporation
              Documents                                          by Reference 
<S>      <C>                                               <C>  
3.1      Charter of the Company,                           Form 10-Q of the Company
         as amended                                        (15164), 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, June 4, 1992, 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       Employment Contract                               Form 8-K of the Company
         of Jay S. Pifer                                   (1-5164) dated February 15,                     
1995, exh. 10.1

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 Pennsyl-
         vania.

23       Consent of Independent Accountants                                See page 184 herein.

24       Powers of Attorney                                                See pages 185-187 herein.

27       Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                                          EXHIBIT 12

                        COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

                                      For Year Ended December 31, 1995

                                        (Dollar Amounts in Thousands)



                                                                   Monongahela Power Company

Earnings:
         <S>                                                               <C>
         Net Income                                                        $ 66,713
         Fixed charges (see below)                                           40,679
         Income taxes                                                        42,460

         Total earnings                                                    $149,852


Fixed Charges:
         Interest on long-term debt                                        $ 37,244
         Other interest                                                       2,628
         Estimated interest                                        
           component of rentals                                                 807

         Total fixed charges                                               $ 40,679


Ratio of Earnings to              
  Fixed Charges                                                                3.68
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                     E-3

The Potomac Edison Company

                                                      Incorporation
                         Documents                    by Reference 

<S>      <C>                                      <C> 
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 August 21, 
         Company defining rights                  1991, December 11, 1991
         of security holders*                     December 15, 1992,   
                                                  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       Employment Contract                      Form 8-K of the Company
           of Jay S. Pifer                        (1-3376-2) dated February
                                                  15, 1995, exh. 10.1

12       Computation of ratio of earnings
         to fixed charges 

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 184 herein.
         Accountants

24       Powers of Attorney                                        See pages 185-187 herein.

27       Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                                EXHIBIT 12

                  COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

                                   For Year Ended December 31, 1995

                                     (Dollar Amounts in Thousands)



                                                                   The Potomac Edison Company

Earnings:
         <S>                                                               <C>
         Net Income                                                        $ 78,265
         Fixed charges (see below)                                           51,982
         Income taxes                                                        39,591

         Total earnings                                                    $169,838


Fixed Charges:
         Interest on long-term debt                                        $ 49,113
         Other interest                                                       2,066
         Estimated interest                                        
           component of rentals                                                 803

         Total fixed charges                                               $ 51,982


Ratio of Earnings to              
  Fixed Charges                                                                3.27
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                     E-4
West Penn Power Company
                                                           Incorporation
                         Documents                         by Reference 
<S>      <C>                                               <C>  
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,
                                                           1993, September 15, 1992, June 
                                                           9, 1993, 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       Employment Contract                               Form 8-K of the Company
           of Jay S. Pifer                                 (1-255-2) dated February 15,
                                                           1995, exh. 10.1
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 184 herein.
         Accountants

24       Powers of Attorney                                See pages 185-187 herein.

27       Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                                                      EXHIBIT 12

                             COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

                                           For Year Ended December 31, 1995

                                             (Dollar Amounts in Thousands)



                                                                   West Penn Power Company

Earnings:
         <S>                                                               <C>
         Net Income                                                        $117,879
         Fixed charges (see below)                                           69,520
         Income taxes                                                        61,636

         Total earnings                                                    $249,035


Fixed Charges:
         Interest on long-term debt                                        $ 64,571
         Other interest                                                       3,331
         Estimated interest                                        
           component of rentals                                               1,618

         Total fixed charges                                               $ 69,520


Ratio of Earnings to              
  Fixed Charges                                                                3.58
</TABLE>
<PAGE>

                                                          E-5

Allegheny Generating Company

                         Documents

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***

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             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.*****

10.3             Equity Agreement, dated June 17, 1981, between and among 
                 Allegheny Generating Company, Monongahela Power Company, 
                 West Penn Power Company and The Potomac Edison Company.*****

10.4             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                  See page 184 herein.
                 Accountants

24               Powers of Attorney                 See pages 185-187 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).

***      Form 10-Q of the Company (0-14688), September 1995, exh. (a)(3)(ii).

****     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).
<PAGE>
<TABLE>
<CAPTION>
                                                                                      EXHIBIT 12

                             COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

                                           For Year Ended December 31, 1995

                                             (Dollar Amounts in Thousands)



                                                           Allegheny Generating Company

Earnings:
         <S>                                                               <C>
         Net Income                                                        $ 27,224
         Fixed charges (see below)                                           18,361
         Income taxes                                                        13,561

         Total earnings                                                    $ 59,146


Fixed Charges:
         Interest on long-term debt                                        $ 16,859
         Other interest                                                       1,502
         Estimated interest                                                       
           component of rentals                                                --- 

         Total fixed charges                                               $ 18,361


Ratio of Earnings to              
  Fixed Charges                                                                3.22
</TABLE>