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<SEC-DOCUMENT>0000003673-00-000027.txt : 20000411
<SEC-HEADER>0000003673-00-000027.hdr.sgml : 20000411
ACCESSION NUMBER: 0000003673-00-000027
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 4
CONFORMED PERIOD OF REPORT: 19991231
FILED AS OF DATE: 20000329

FILER:

COMPANY DATA:
COMPANY CONFORMED NAME: ALLEGHENY ENERGY INC
CENTRAL INDEX KEY: 0000003673
STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911]
IRS NUMBER: 135531602
STATE OF INCORPORATION: MD
FISCAL YEAR END: 1231

FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-00267
FILM NUMBER: 583465

BUSINESS ADDRESS:
STREET 1: 10435 DOWNSVILLE PIKE
CITY: HAGERSTOWN
STATE: MD
ZIP: 21740-1766
BUSINESS PHONE: 3017903400

MAIL ADDRESS:
STREET 1: 10435 DOWNSVILLE PIKE
CITY: HAGERSTOWN
STATE: MD
ZIP: 21740-1766

FORMER COMPANY:
FORMER CONFORMED NAME: ALLEGHENY POWER SYSTEM INC
DATE OF NAME CHANGE: 19920703

FORMER COMPANY:
FORMER CONFORMED NAME: WEST PENN ELECTRIC CO
DATE OF NAME CHANGE: 19660908
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<TEXT>

<PAGE>

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

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999

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

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

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

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

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

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

Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
and (2) have been subject to such filing requirements for the
past 90 days. Yes X No

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

<PAGE>

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

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

Allegheny Energy, Common Stock, New York Stock Exchange
Inc. $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 8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A New York Stock Exchange

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

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

Allegheny Generating
Company Common Stock
$1.00 par value None

<PAGE>

Aggregate market value Number of shares
of voting stock (common stock) of common stock
held by nonaffiliates of of the registrants
the registrants at outstanding at
March 2, 2000 March 2, 2000

Allegheny Energy, Inc. $2,816,126,084 110,436,317
($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 Energy, Inc., the
parent company.

(b) All such common stock is held by its parents, Monongahela Power Company,
The Potomac Edison Company, and Allegheny Energy Supply Company, LLC.

<PAGE>

CONTENTS

PART I: Page

ITEM 1. Business 1
Factors That May Affect Future Results 4
Electric Energy Competition 4
Activities at the Federal Level 5
Activities at the State Level 5
Allegheny's Competitive Steps 8
Telecommunications 9
Proposed Merger with DQE, Inc. 10
Sales 11
Regulated Sales 11
Unregulated Sales 13
Regulatory Framework Affecting Power Sales 13
Electric Facilities 15
Allegheny Map 19
Research and Development 21
Capital Requirements and Financing 21
Financing Programs 24
Fuel Supply 26
Rate Matters 27
Environmental Matters 31
Air Standards 31
Water Standards 35
Hazardous and Solid Wastes 36
Toxic Release Inventory (TRI) 36
Global Climate Change 37
Regulation 38

ITEM 2. Properties 39

ITEM 3. Legal Proceedings 39

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 Shareholder Matters 46

ITEM 6. Selected Financial Data 47

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

ITEM 7A. Quantitative and Qualitative Disclosure About
Market Risk 48

<PAGE>

CONTENTS (Cont'd)
Page
PART III:

ITEM 8. Financial Statements and Supplementary Data 49

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

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 65

ITEM 13. Certain Relationships and Related Transactions 66

PART IV:

ITEM 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 66

<PAGE>

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

PART I

ITEM 1. BUSINESS

Allegheny Energy, Inc. (AE), incorporated in Maryland in
1925, is a diversified utility holding company which owns
directly and indirectly various regulated and non-regulated
subsidiaries (collectively and generically, Allegheny). In 1999,
AE derived substantially all of its income from the electric
utility operations of its direct and indirect regulated and
unregulated subsidiaries Monongahela Power Company (Monongahela),
The Potomac Edison Company (Potomac Edison), West Penn Power
Company (West Penn--both regulated and unregulated in 1999),
Allegheny Generating Company (AGC), Allegheny Energy Supply
Company, LLC (Allegheny Energy Supply) and Allegheny Ventures,
Inc. (Allegheny Ventures) (collectively, Monongahela, Potomac
Edison and the regulated activities of West Penn will be referred
to as the Operating Subsidiaries). The properties of the
Operating Subsidiaries, AGC and Allegheny Energy Supply are
located in Maryland, Ohio, Pennsylvania, Virginia, and West
Virginia; are interconnected; and are located along transmission
facilities owned in whole or part by the Operating Subsidiaries
(System), which are interconnected with all neighboring utility
systems. In 1999, the three regulated electric utility operating
subsidiaries were Monongahela, Potomac Edison, and the regulated
activities of West Penn. The Operating Subsidiaries are doing
business under the trade name Allegheny Power. Allegheny Energy
Supply is an unregulated generating subsidiary of AE. Allegheny
Ventures is an unregulated subsidiary of AE that develops and
operates telecommunications businesses and energy-related
businesses.

In December 1999, for approximately $95 million, Monongahela
acquired the assets of West Virginia Power from UtiliCorp United,
Inc. and entered into a 20-year option agreement with UtiliCorp's
subsidiary, Aquila Energy, for gas supply to Monongahela and
Allegheny Energy Supply. West Virginia Power has approximately
26,000 electric customers in southern West Virginia and 24,000
gas customers in southern and central West Virginia. No electric
generation facilities or gas production facilities were part of
the transaction. All regulatory approvals were secured and this
transaction closed on December 31, 1999. These gas and electric
distribution properties will be operated under the trade name
Allegheny Power beginning around May 1,2000, for electric, and
around October 1, 2000, for gas. Allegheny Ventures acquired the
heating, air conditioning and ventilating repair and installation
business of Utilicorp in West Virginia as part of that
transaction.

On December 20, 1999, AE announced Monongahela's plan to
acquire Mountaineer Gas Company, a natural gas distribution
company serving approximately 200,000 retail natural gas
customers in West Virginia. Mountaineer Gas Company is owned by
Eastern Systems Corporation, a subsidiary

<PAGE>

of Energy Corporation
of America. The acquisition also includes the acquisition of
Mountaineer Gas Company's unregulated subsidiary, Mountaineer Gas
Services, which operates natural gas producing properties, gas
gathering facilities, and intra-state transmission pipelines.
Approval from the West Virginia Public Service Commission, the
Securities and Exchange Commission and the Department of Justice
are required. The transaction is expected to close during the
third quarter of 2000.

Monongahela, incorporated in Ohio in 1924, operates its
electric distribution system in northern West Virginia and an
adjacent portion of Ohio. It also owns generating capacity in
Pennsylvania. With the acquisition of the assets of West
Virginia Power, Monongahela will now serve about 385,000
customers in a service area of about 13,000 square miles with a
population of about 815,000. The seven largest communities
served have populations ranging from 10,900 to 33,900. This
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, in 1999 they purchased 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 398,600 customers in a service area
of about 7,300 square miles with a population of about 782,000.
On July 1, 2000, the Maryland jurisdictional retail customers of
Potomac Edison will be afforded the same generation service
supplier choice opportunities as described for West Penn below.
The ability to choose is the result of state legislation and
regulatory proceedings described in ITEM 1. ELECTRIC ENERGY
COMPETITION. The six largest communities served have populations
ranging from 11,900 to 40,100. Potomac Edison's service area's
principal industries produce aluminum, cement, fabricated
products, rubber products, sand, stone, and gravel. There are
four municipal electric distribution systems in its service area,
all of which purchased power from Potomac Edison in 1999, and six
rural electric cooperatives, one of which purchased power from
Potomac Edison in 1999.

West Penn, incorporated in Pennsylvania in 1916, is an
electricity delivery company in southwestern and north and south-
central Pennsylvania. In December 1996, Pennsylvania enacted the
Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) to restructure the electric industry in
Pennsylvania to create retail access to a competitive electric
energy generation market. During 1999, approximately 226,000
customers, one-third of West Penn's retail load, were not
eligible for customer choice. As of January 2, 2000, all of West
Penn's retail load was able to choose their electric generation
supplier. See ITEM 1. ELECTRIC ENERGY COMPETITION and ITEM 1.
RATE MATTERS for a discussion of the status of competition in
Pennsylvania. As a consequence of the Customer Choice Act,
effective January 1, 1999, West Penn reorganized into a delivery
business unit providing transmission and distribution to
customers in West Penn's service territory, and a supply business
unit supplying unregulated retail generation in

<PAGE>

Pennsylvania
(excluding by temporary regulatory proscription those with
locations wholly inside West Penn's service area) and other
states in the region implementing customer choice, and wholesale
generation anywhere. In November 1999, the supply business unit
became part of a separate, unregulated electricity supply
subsidiary of AE, known as Allegheny Energy Supply. In November
1999, West Penn transferred its generation assets to Allegheny
Energy Supply. West Penn's service area contains about 9,900
square miles with a population of about 1,399,000. The 10
largest communities served by West Penn have populations ranging
from 11,200 to 38,900. West Penn's service area has navigable
waterways and substantial deposits of bituminous coal, limestone,
and other natural resources. Its service area's principal
industries produce steel, coal, fabricated products, and glass.

Allegheny Energy Supply, incorporated in Delaware in 1999,
owns and operates generating capacity in southwestern
Pennsylvania and West Virginia. In November 1999, West Penn
transferred its generating assets, including its ownership
interest in AGC, to Allegheny Energy Supply. AYP Energy also
transferred its unregulated generation asset to Allegheny Energy
Supply. Until January 2, 2000, West Penn continued to supply
electricity to one-third of its retail load that was not able to
choose its generating supplier. Allegheny Energy Supply leased
back to West Penn an amount of generating assets sufficient for
West Penn to satisfy that load. Allegheny Energy Supply sells
retail electric energy throughout Pennsylvania (excluding by
temporary regulatory proscription those customers with locations
wholly inside West Penn's service area) and in other states
throughout the region that have customer choice, and wholesale
electric energy anywhere.

AGC, organized in 1981 under the laws of Virginia, is
jointly owned as follows: Monongahela, 27%; Potomac Edison, 28%;
and Allegheny Energy Supply, 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).

Allegheny Ventures, incorporated in Delaware in 1994, is a
wholly owned non-regulated subsidiary of AE. Allegheny Ventures
has three wholly owned subsidiaries--AYP Energy, Inc. (AYP
Energy), Allegheny Communications Connect, Inc. (ACC), and
Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions),
all Delaware corporations. Allegheny Ventures is also part owner
of APS Cogenex, a limited liability company formed with EUA
Cogenex. APS Cogenex ceased its marketing activities in 1996 and
is concluding existing projects. AYP Energy transferred its
interest in Unit No. 1 of the Ft. Martin Generating Station to
Allegheny Energy Supply in 1999. (See ITEM 1. ELECTRIC ENERGY
COMPETITION and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Significant
Events in 1999, 1998, and 1997 for a further description of
Allegheny Ventures and its subsidiaries' activities.)

<PAGE>

AE, Allegheny Energy Supply, the Operating Subsidiaries,
AGC, and Allegheny Ventures and its subsidiaries have no
employees. Their officers are employed by Allegheny Energy
Service Corporation (AESC, formerly Allegheny Power Service
Corporation), a wholly owned subsidiary of AE, incorporated in
Maryland in 1963. AESC's employees provide all necessary
services to AE, Allegheny Energy Supply, the Operating
Subsidiaries, AGC, and Allegheny Ventures and its subsidiaries.
Those companies reimburse AESC for services provided by AESC's
employees. On December 31, 1999, AESC had approximately 4,923
employees.

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including ongoing state and federal activities; developments in
the legislative, regulatory, and competitive environments in
which Allegheny operates, including regulatory proceedings
affecting rates charged by AE's subsidiaries; environmental,
legislative, and regulatory changes; future economic conditions;
earnings retention and dividend payout policies; Allegheny's
ability to compete in unregulated energy markets; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power and fuel for electric generation, unscheduled maintenance
or repair requirements, weather, and compliance with laws and
regulations.

ELECTRIC ENERGY COMPETITION

The electricity supply segment of the electric utility
industry in the United States is becoming increasingly
competitive. The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems. Since 1992, the wholesale
electricity market has become more competitive. In addition, an
increasing number of states have taken active steps toward
allowing retail customers the right to choose their electricity
supplier. Allegheny has been an advocate of federal legislation
to create competition in the retail electricity markets to avoid
regional dislocations and ensure level playing fields.

<PAGE>

In the absence of federal legislation, state-by-state
implementation has begun. All of the states the Operating
Subsidiaries serve are at various stages of implementation of
programs allowing customers to choose their electric generation
service supplier. Pennsylvania is farthest along with a
competitive retail program fully in place. Maryland is scheduled
to afford retail choice to nearly all residents in July, 2000.
Virginia and Ohio passed legislation in 1999 to implement some
level of retail choice by 2002 and 2001, respectively. In March,
2000, the West Virginia Legislature approved a plan to implement
customer choice, with implementation delayed pending future
legislative enactment of certain tax changes.

Activities at the Federal Level

Allegheny continues to seek enactment of federal legislation
to bring choice to all retail electric customers, deregulate the
generation and sale of electricity on a national level, and
create a more liquid, free market for electric power. Fully
meeting challenges in the emerging competitive environment will
be difficult for Allegheny unless certain outmoded and anti-
competitive laws, specifically the Public Utility Holding Company
Act of 1935 (PUHCA) and Section 210 of the Public Utility
Regulatory Policies Act of 1978 (PURPA) regarding mandatory power
purchase provisions, are repealed or significantly revised.
Allegheny continues to advocate the repeal of PUHCA and PURPA on
the grounds that they are obsolete and anti-competitive, and that
PURPA results in utility customers paying above-market prices for
power. In the U.S. Congress, a series of hearings on the
competition issue in both the House and Senate were completed in
1999. Also, the House Energy & Power Subcommittee forwarded to
the full Commerce Committee a comprehensive competition bill.
Among the most important actions, the Subcommittee rejected
attempts to add market power and environmental restrictions to
the legislation, approved an amendment preventing federal law
from overriding state plans, deleted reciprocity language that
would have harmed Allegheny's ability to compete, adopted an
amendment promoting incentive pricing for transmission, and
clarified provisions relating to regional transmission
organizations and speeding up the merger process. Full Committee
action on this legislation could occur in 2000. Significant
hurdles remain in both houses of Congress, however. While it is
too early to tell whether initial momentum on the issue will
result in legislation in the current Congress, the competition
issue received more attention in 1999 than ever before.

Activities at the State Level

Maryland

On April 8, 1999, Maryland Governor Glendening signed
legislation that will bring competition to Maryland's electric
supply market. The Maryland Public Service Commission is in the
process of implementing the new law. Final Electric
Restructuring Roundtable reports were filed with the Commission
on May 3, 1999. Legislative style hearings were held on the
Roundtable reports. All roundtable report decisions have been
issued by the Commission. Certain outstanding technical issues
were referred to the Technical Implementation Working Group and
are currently under review by the Commission.

<PAGE>

In Potomac Edison's Maryland restructuring case, the staff
of the Maryland Public Service Commission (Maryland PSC) advised
the Commission that a consensus settlement agreement had been
reached with no protest by any of the parties participating in
the negotiations.. On December 23, 1999, the Commission issued
an Order approving the settlement, and on March 15, 2000 issued a
Supplemental Order elaborating on the basis for finding that the
settlement agreement approved in the December 23, 1999 Order is
consistent with Maryland's restructuring legislation and is in
the public interest. (See ITEM 1. RATE MATTERS for a discussion
of the settlement agreement, which included a decision that full
recovery of the Warrior Run purchase power costs was due Potomac
Edison and that generation assets could be transferred to an
affiliate at book value.) Potomac Edison filed an application on
December 15, 1999 to transfer its Maryland generation assets at
book value to an affiliate in accordance with Section 7-508 of
the Electric Customer Choice and Competition Act of 1999. The
Commission approved settlement provides that all of Potomac
Edison's retail customers will have generation supply choice
effective July 1, 2000 and that Potomac Edison may transfer its
Maryland jurisdictional generation in a manner similar to that
described for West Penn in Pennsylvania. Potomac Edison will
become an energy delivery company. It retains a supplier of last
resort obligation that it will satisfy from the market, including
Allegheny Energy Supply. Allegheny Energy Supply will acquire
the soon-to-be deregulated generation assets from Potomac Edison,
and will market the deregulated generation to the retail and
wholesale markets, with the restriction that it may not market to
retail customers within Potomac Edison's Maryland territory for
various time frames, some of which terminate in 2003.

Ohio

On June 22, 1999, the Ohio General Assembly passed
legislation to restructure Ohio's electric utility industry.
Governor Taft signed the legislation into law. All of the
state's customers will be able to choose their electricity
supplier starting January 1, 2001, beginning a five-year
transition to market rates. Pursuant to the legislation, the
Ohio Public Utilities Commission issued its Electric Transition
Rules and Consumer Education Plan on November 30, 1999. In
compliance with those rules, Monongahela filed its transition
plan on January 3, 2000. The Public Utilities Commission must
act on the plan within 275 days, but no later than October 31,
2000. In January 2000, the Commission issued for comments
Proposed Rules on Electric Service and Safety Standards,
Certification of Providers, Minimum Competitive Retail Electric
Service Standards, Market Monitoring, Consumer Education,
Alternative Dispute Resolution, and Long-Term Forecast Reporting.
The Commission also established workshops to address customer
enrollment and switching, billing and collections,
supplier/utility coordination, and data exchange.

<PAGE>

Pennsylvania

The Customer Choice Act in Pennsylvania provides for
customer choice of electric supplier and deregulation of
generation in a competitive electric supply market. As of January
2, 2000, all electricity customers in Pennsylvania have the right
to choose their electric suppliers. Two-thirds of all retail
customers had a choice throughout 1999, the first year of retail
choice following a pilot program. Over 100 electric suppliers
have been licensed to sell to retail customers in Pennsylvania.
One result of the Customer Choice Act was the bifurcation of West
Penn's electricity supply and electricity delivery functions into
two separate businesses. The transmission and distribution
business remains under the traditional regulated ratemaking. The
electric supply business operates in the deregulated marketplace.
The delivery business in Pennsylvania has responsibility as the
electricity provider of last resort (for those customers of West
Penn who choose not to select an alternate supplier or whose
alternate supplier does not deliver) and will generally obtain
necessary electric supply for this function from the market,
including Allegheny Energy Supply. The electric supply business
now under Allegheny Energy Supply is free to sell the deregulated
generation, previously owned by West Penn and now owned by
Allegheny Energy Supply, in the wholesale and retail markets,
subject to codes of conduct, and subject to the restriction that
it may not, except under certain conditions, sell at retail in
West Penn's service territory through the year 2003.

Virginia

The Virginia Electric Utility Restructuring Act (the "Act")
was enacted in March 1999, and provides for a transition to
customer choice of electric suppliers for Virginia customers
beginning January 1, 2002, with all Virginia customers to have
choice by January 1, 2004. The Act generally provides for rate
caps from January 1, 2001 to July 1, 2007, with recovery of
stranded costs and transition costs during the rate cap period
through capped rates and a wires charge mechanism. Supply of
electric energy is generally deregulated effective January 1,
2002, except as provided in the Act. The Act requires functional
separation of generation, retail transmission, and distribution
by January 1, 2002. The Act requires the joining or establishing
of a regional transmission entity by January 1, 2002 to which
management and control of the transmission system shall be
transferred. The Act established a Legislative Transition Task
Force to serve through July 1, 2005 generally to monitor the
implementation of electric customer choice and to report annually
to the Governor and General Assembly, making recommendations as
appropriate for legislative or administrative consideration.

The Virginia State Corporation Commission (Virginia SCC)
instituted a proceeding on May 26, 1999, to investigate regional
transmission entities pursuant to Virginia Electric Utility
Restructuring Act. Potomac Edison filed comments. The
proceeding is ongoing.

By Order dated December 3, 1998, the Virginia SCC
established a proceeding to adopt interim rules to govern issues
common to both the natural

<PAGE>

gas and electricity restructuring
retail access pilot programs ordered in other cases, specifically
the issues of certification, code of conduct, and standards of
conduct governing relationships among entities participating in
pilot programs. The Task Force created in connection with this
proceeding issued its final report to the Commission in March
1999. Following hearings in May 1999, a Hearing Examiner issued
a report adopting many of the Task Force recommendations but with
some modifications. New regulations were issued for comment, and
the proceeding is ongoing.

In December 1999, the Virginia SCC commenced a proceeding to
adopt regulations governing a net energy metering program to
begin no later than July 1, 2000, pursuant to the Virginia
Electric Restructuring Act. The proceeding is ongoing.

West Virginia

On December 20, 1999, the West Virginia Commission (WV
Commission) issued an order accepting and modifying the
Stipulated Plan for Restructuring that was filed on December 13,
1999, by various parties, including Monongahela. The order was in
response to the legislation (WV Code Sec. 24-2-18) enacted in
1998 directing the Commission to solicit public input and
determine if public interest would best be served by opening the
electric supply to market competition. In January, 2000 a
revised plan was adopted by the WV Commission and submitted to
the Legislature. The Legislature approved the plan in March,
2000 with implementation delayed pending future legislative
enactment of tax changes to preserve state and local tax
revenues. The WV Commission is conducting further proceedings
during 2000 in connection with the implementation of this plan.
See also the discussion of the West Virginia plan under Item 1.
RATE MATTERS.

Allegheny's Competitive Steps

Over the past several years Allegheny has taken steps to
better position itself to participate in the new competitive
markets. Its most recent effort to position itself competitively
was the creation of Allegheny Energy Supply, an energy supply and
marketing company, which began operations on November 18, 1999.
Allegheny Energy Supply owns the generation previously owned by
West Penn and by AYP Energy, Inc. In 2000, it is expected that
Allegheny Energy Supply will add the Maryland and West Virginia
jurisdictional generation currently owned by Potomac Edison and
will add newly developed generation assets created or purchased.
As additional states move to competition, Allegheny intends to
transfer all newly deregulated generating assets to Allegheny
Energy Supply. During 1999, Allegheny Energy Unit No. 1 and Unit
No. 2, LLC, a subsidiary of AE, installed two 44 MW combustion
turbines. These facilities will be transferred to Allegheny
Energy Supply in mid-to-late-2000. During 2000, Allegheny Energy
Supply will also install five additional combustion turbines
totaling 220 MW. Also, Allegheny Energy Supply is building a 540
MW combined-cycle generating plant scheduled for completion in
2003. The competitive supply operations were profitable in 1999.

In 1996, Allegheny Ventures (then operating as AYP Capital)
formed two nonutility subsidiaries: AYP Energy and Allegheny
Communications Connect.

<PAGE>

In addition, in 1997 Allegheny Ventures
formed Allegheny Energy Solutions. In 1996, AYP Energy purchased
a 50% interest (276 MW) in Unit No. 1 of the Ft. Martin power
station. Until the second quarter of 1999, AYP Energy was
actively marketing the output of that Unit. In 1999, the
interest in the Ft. Martin unit was transferred to Allegheny
Energy Supply.

Merchant plants and power marketing in the deregulated
wholesale or retail markets are essentially participants in a
commodity market, which create certain risk exposures. The risks
to which Allegheny Energy Supply is exposed include underlying
price volatility, credit risk, and variation in cash flows, among
others. To manage these risks, Allegheny has risk management
policies and procedures, consistent with industry practice and
its goals. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS--EARNINGS SUMMARY.)

During 1999, Allegheny Ventures made investments in
funds that were established in 1995. They include an investment
in EnviroTech Investment Fund I, L.P. (EnviroTech), a limited
partnership formed to invest in emerging electrotechnologies that
promote the efficient use of electricity and improve the
environment. Allegheny Ventures committed to invest up to $5
million in EnviroTech over 10 years, beginning in 1995.
Allegheny Ventures also participates in the Latin American Energy
and Electricity Fund I, L.P. (FONDELEC), a limited partnership
formed to invest in and develop electric energy opportunities in
Latin America. Allegheny Ventures committed to invest up to $5
million in FONDELEC over eight years, beginning in 1995. Through
FONDELEC, Allegheny Ventures has invested in electric
distribution companies in Peru, Brazil and Argentina. Both
EnviroTech and FONDELEC may offer Allegheny Ventures
opportunities to identify investments in which Allegheny Ventures
may coinvest in excess of its capital commitment in each limited
partnership. Allegheny Ventures is also involved in managing the
unused real estate holdings of the Operating Subsidiaries and in
marketing distributed generation.

Telecommunications

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

During 1999, ACC expanded its fiber optic network by 350
miles, giving ACC a total of approximately 600 route miles. In
2000, ACC expects to expand its network by about 1000 additional
route miles, in part through a partnership with Adelphia Business
Solutions.

ACC also continues to expand its fiber infrastructure by
interconnecting with other fiber optic providers, such as AEP
Communications LLC, First Energy Telecom Corp. and GPU Telecom
Services, Inc.

<PAGE>

ACC recently acquired approximately 10 percent of Genosys
Technology Management, Inc., a network operation center service
provider. This new alliance will allow ACC to move into emerging
markets such as e-commerce and the internet.

PROPOSED MERGER WITH DQE, INC.

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

In a letter to AE dated October 5, 1998, DQE stated that it
had decided to unilaterally terminate the merger. In response,
on October 5, 1998, AE filed a lawsuit in the United States
District Court for the Western District of Pennsylvania against
DQE for specific performance of the Merger Agreement or, in the
alternative, for damages. On December 3, 1999, after a non-jury
trial, the District Court found that defendant DQE did not breach
the April 5, 1997 Agreement and Plan of Merger. Accordingly, the
District Court found in favor of DQE and against AE on all claims
and all requests for injunctive relief. It granted judgment in
favor of defendant DQE and against plaintiff AE.

On December 14, 1999, AE filed a Motion of Appeal from the
District Court's judgment to the Third Circuit Court of Appeals.
AE's Motion for Expedited Treatment of the Appeal was granted.
Argument on AE's Motion was held before the Court of Appeals on
March 9, 2000. AE cannot predict the outcome of this appeal.

<PAGE>

SALES

Regulated Sales

In 1999, consolidated regulated kilowatt-hour (kWh) sales
delivered to regular customers (retail and wholesale power)
increased 2.8% from those of 1998 as a result of increases of
4.8%, 3.8% and .9% in residential, commercial and industrial
sales, respectively. Consolidated regulated revenues from
residential sales increased 5.6%, while commercial and industrial
sales decreased .2% and 4.4%, respectively. (See ITEM 1. RATE
MATTERS and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)

Allegheny's all-time peak Control Area Load was 7,788 MW on
July 6, 1999.(Control Area Load refers to the electricity sales
to customers within the Allegheny Power delivery territory
without regard to electric generation supplier. The Control Area
Load includes Regulated Load.) The peak Regulated Load in 1999
was 7,394 MW on July 6, 1999. (Regulated Load refers to the
electricity sales to customers of Allegheny Power (the Operating
Subsidiaries) who have not selected an alternate generation
supplier. It does not include sales by Allegheny Energy Supply to
nonaffiliated customers within the Allegheny Power service
territory.)

Consolidated regulated electric operating revenues for 1999
were derived as follows: Pennsylvania, 41.5%; West Virginia,
29.6%; Maryland, 19.8%; Virginia, 6.3%; and Ohio, 2.8%
(residential, 40.9%; commercial, 22.0%; industrial, 31.7%; bulk
power transactions, 3.1%; and other, 2.3%).

During 1999, Monongahela's kWh sales to retail customers
increased 3.8%. Residential, commercial, and industrial sales
increased 4.6%, 2.2% and 4.1%, respectively. Revenues from
residential, commercial, and industrial customers increased 4.9%,
2.8%, and 4.4%, respectively, primarily due to increased customer
usage because of weather conditions, primarily colder winter
weather in 1999, growth in number of customers, and an increase
in the fuel and energy cost component of revenues. Revenues from
bulk power transactions and sales to affiliates increased 6.4%.
Monongahela's revenues represented 25.8% of Allegheny's total
regulated sales revenues to regular customers. Monongahela's all-
time peak load of 1,899 MW occurred on July 6, 1999.

Monongahela's electric operating revenues were derived as
follows: West Virginia, 90.5%, and Ohio, 9.5% (residential,
31.3%; commercial, 19.3%; industrial, 32.3%; bulk power
transactions, 2.8%; and other, 14.3%).

During 1999, Potomac Edison's kWh sales to retail customers
increased 2.6%. Residential and commercial sales increased 5.5%
and 6.8%, respectively, while industrial sales decreased 1.4%.
Revenues from residential, commercial, and industrial customers
increased 6.9%, 7.3%, and 2.7%, respectively, primarily due to
increased customer usage because of weather conditions, primarily
colder winter weather in 1999, growth in the number of customers,
and to a lesser extent an increase in the fuel and energy cost
component of revenues. Revenues from bulk power transactions and
sales to affiliates increased .3%. Potomac Edison's revenues
represented

<PAGE>

32.7% of Allegheny's total regulated sales revenues
to regular customers. Potomac Edison's all-time peak load of
2,614 MW occurred on January 17, 1997. The peak load in 1999 was
2,604 MW on July 6, 1999.

Potomac Edison's electric operating revenues were derived as
follows: Maryland, 61.2%; West Virginia 19.9%, and Virginia,
18.9%; (residential, 43.9%; commercial, 22.4%; industrial, 28.2%;
bulk power transactions, 3.3%; and other, 2.2%). Revenues from
one industrial customer, the Eastalco aluminum reduction plant
near Frederick, Maryland, amounted to $62.7 million (8.3% of
total electric operating revenues). Minimum annual charges to
Eastalco under an electric service agreement which continues
through April 1, 2003, with automatic extensions thereafter
unless terminated on notice by either party, were $15.9 million
in 1999.

During 1999, West Penn's regulated kWh sales and deliveries
to retail customers decreased 4.6%. Residential sales and
deliveries increased 4.3% while commercial and industrial sales
and deliveries decreased 3.0% and 12.3%, respectively. Regulated
revenues from residential customers increased 5.0%, while regulated
revenues from commercial and industrial customers decreased 7.4%
and 14.1%, respectively. The increase in regulated residential
revenues was due primarily to colder winter weather which led to
increased kWh sales. Despite the ability to shop for another
energy supplier, few of the residential customers elected to
choose another energy supplier. The decreases in regulated
revenues for commercial and industrial customers was due
primarily to Pennsylvania deregulation, which gave two-thirds of
West Penn's regulated customers the ability to choose another
energy supplier. Regulated revenues from bulk power transactions
and sales to affiliates decreased 45.8%. West Penn's regulated
revenues represented 41.5% of Allegheny's total regulated sales
to regular customers. West Penn's all-time peak Control Area Load
of 3,328 MW occurred on July 6, 1999. The peak Regulated Load in
1999 was 3,038 MW on January 5, 1999.

West Penn's regulated electric operating revenues were
derived as follows: Pennsylvania, 100% (residential, 39.8%;
commercial, 20.6%; industrial, 29.7%; bulk power transactions,
2.9%; and other, 7.0%).

In 1999, the Operating Subsidiaries provided approximately
0.6 billion kWh of energy to nonaffiliated companies and
marketers from generation facilities operated by the Operating
Subsidiaries. Revenues from those sales of generation from the
Operating Subsidiaries were approximately $22.5 million.

The Operating Subsidiaries transmitted approximately 8.5
billion kWh to others located outside their service territories
under various forms of transmission service agreements. Revenues
from those sales were about $48.5 million.

Sales of generation and transmission services to others vary
with the needs of those customers for capacity and/or economic
replacement power; the availability of generating facilities and
excess power, fuel, and regional transmission facilities; and the
availability and price of competitive sources of power. Revenues
from sales of power generated by the Operating Subsidiaries
decreased in 1999 relative to 1998 due to decreased sales to

<PAGE>

brokers and power marketers due to the two-thirds of West Penn's
freed up generation being marketed as part of unregulated
operations. As a result, the regulated operations have less
generation available for sale. Regulated revenues from sales of
transmission services to others by the Operating Subsidiaries
increased in 1999 relative to 1998 due to increased megawatthours
transmitted. Substantially all of the benefits of power
and transmission services sales to nonaffiliates by the Operating
Subsidiaries, except West Penn, were passed on to retail
customers and, as a result, had little effect on Monongahela
Power's and Potomac Edison's net income. Effective May 1, 1997,
West Penn no longer passes these benefits on to retail customers,
and effective July 1, 2000, Potomac Edison will also no longer
pass these benefits to its Maryland customers.

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

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

Unregulated Sales

Unregulated sales revenues, in total, were $887.4 million,
of which approximately $352.7 million were the result of energy
sales to affiliates. Excluding the effect of affiliated sales,
unregulated revenues represented 19% of Allegheny's total
operating revenues in 1999.

Regulatory Framework Affecting Power Sales

The Energy Policy Act of 1992 (EPACT) initiated the
restructuring of the electric utility industry by permitting
competition in the wholesale generation market. In order to
facilitate the efficient use of generation facilities, on April
24, 1996, the FERC issued Orders 888 and 889. On March 4, 1997,
the FERC issued Orders 888A and 889A reaffirming and clarifying
the legal and policy determinations as originally adopted in the
previous orders. The FERC also issued Orders 888B and 889B on
November 25, 1997 in which the Commission presented explanations
and minor revisions to specific sections of the orders.

The FERC orders require all transmission providers to offer
service to entities selling generation services in a manner that
is comparable to their own use of the transmission system. The
orders required each transmission provider to file standardized
open access transmission service tariffs;

<PAGE>

therefore, the
Operating Subsidiaries have on file a pro forma open access
tariff under which they sell transmission services to all
eligible customers. The Operating Subsidiaries, AYP Energy and
Allegheny Energy Supply also arrange for transmission services
for their own sales pursuant to the rates, terms, and conditions
of the open access tariff. The tariff was accepted for filing by
the FERC on November 25, 1998. The Commission's order specified
a December 6, 1995, effective date and required refunds to be
paid on the time value of money based upon the difference between
the originally filed rates and those authorized by the
Commission. The Operating Subsidiaries issued the required
refunds in 1999.

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

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

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

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

<PAGE>

effective August 15, 1999. Allegheny
Energy Supply started serving customers under that tariff on
November 19, 1999.

During 1999, consideration of independent transmission
organizations grew to include a number of possibilities for
resolution of the issue. In adopting its Order No. 2000 on
December 20, 1999, the FERC defined requirements for transmission
facility owners to participate in some form of regional
transmission organization (RTO). FERC stated in that order that
transmission owners are expected to join regional transmission
organizations on a voluntary basis. All public utilities that
own, operate, or control interstate transmission are to file by
October 15, 2000, a proposal for an RTO or a description of
efforts made to participate in one, the reasons for not
participating, any obstacles to participation, and any plans for
further work toward participation. RTOs will be operational by
December 15, 2001. Additionally, the state jurisdictions within
which Allegheny operates have, to varying degrees, begun their
transition to a competitive marketplace. In these deliberations,
transmission has been identified as a key to electricity market
efficiency. Allegheny has actively participated in this debate
and continues to evaluate available options to provide its
customers with the most reliable, cost-effective service while
maintaining a focus on the financial interests of its
shareholders.

Under PURPA, certain municipalities, businesses and private
developers have installed generating facilities at various
locations in or near the Operating Subsidiaries' service areas.
They sell electric capacity and energy to the Operating
Subsidiaries at rates consistent with PURPA and ordered by
appropriate state commissions. As a result of PURPA, the
Operating Subsidiaries are committed to purchasing 299 MW of on-
line PURPA capacity. Payments for PURPA capacity and energy in
1999 totaled approximately $115.2 million, at an average cost to
the Operating Subsidiaries of 4.8 cents/kWh, as compared to the
Operating Subsidiaries' cost of 2.9 cents/kWh. An additional
180 MW of PURPA capacity (Warrior Run) became commercially
available in February 2000. As a result of a restructuring
settlement in Maryland, Warrior Run costs will be recovered from
customers by a surcharge over the life of the purchase contract.
The Warrior Run output will be offered into the wholesale market,
beginning July 1, 2000, and customers will receive a credit
through the surcharge for the net revenue received from such
sales.

ELECTRIC FACILITIES

The following table shows Allegheny's December 31, 1999,
operational generating capacity based on the maximum operating
capacity of each unit. The Operating Subsidiaries' owned
capacity totaled 4,451 MW, of which 3,983 MW (90%) are coal-
fired, 462 MW (10%) are pumped-storage, and 6 MW 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.

<PAGE>

Allegheny Energy Supply's owned capacity totaled 4,054 MW of
which 3,492 MW (86%) are coal-fired, 132 MW (3%) are oil-fired,
378 MW (9%) are pumped-storage, and 52 MW (1%) are hydroelectric.

Allegheny Energy Unit No. 1 and Unit No. 2, LLC owns 88 MW
of gas-fired capacity. It sells its output to Allegheny Energy
Supply, and the transfer of ownership of these units to Allegheny
Energy Supply is expected in mid-to-late-2000.

<PAGE>

Allegheny Stations
Maximum Generating Capacity (Megawatts) (a)

<TABLE>
<CAPTION>
Regulated Unregulated
Dates When
Station Monon- Potomac West AE AEUnit Service
Station Units Total gahela Edison Penn Supply Nos. 1& 2 Commenced (c)
<S> <C> <C> <C> <C> <C> <C>
Coal-fired (steam):
Albright 3 292 216 76 1952-4
Armstrong 2 356 356 1958-9
Fort Martin 2 1,113 250 306 557 1967-8
Harrison 3 1,950 488 639 823 1972-4
Hatfield's Ferry 3 1,710 470 342 898 1969-71
Mitchell 1 288 288 1963
Pleasants 2 1,266 316 380 570 1979-80
Rivesville 2 142 142 1944-51
R. Paul Smith 2 115 115 1947-58
Willow Island 2 243 243 1949-60
Gas-fired
AE Nos. 1 & 2 2 88 88 1999
Oil-fired (steam): (a)
Mitchell 2 132 132 1948-49
Pumped-storage and Hydro:
Bath County 6 840 227(d) 235(d) 378(d) 1985
Lake Lynn(e) 4 52 52 1926
Potomac Edison (e) 21 6 6 __ __ Various
Total Allegheny-owned
Capacity 57 8,593 2,352 2,099 0 4,054 88

PURPA Generation
Maximum Generating Capacity (Megawatts) (f)

Contract
Project Monon- Potomac West AE AE Unit Commencement
Project Total gahela Edison Penn Supply Nos.1 & 2 Date
Coal-fired: (steam)
AES Beaver Valley 125 125 1987
Grant Town 80 80 1993
West Virginia University 50 50 1992

Hydro:
Allegheny Lock and Dam 5 6 6 1988
Allegheny Lock and Dam 6 7 7 1989
Hannibal Lock and Dam 31 31 ___ ___ 1988
Total Other Capacity 299 161 0(g) 138 _____
Total Allegheny-owned and
PURPA Committed Generating
Capacity (a) 8,892 2,513 2,099 138 4,054 88

</TABLE>

<PAGE>

(a) Winter rating. On December 31, 1994, 82 MW, and on
July 1, 1998, 50 MW of the total MW at Mitchell Power Station
were reactivated.

(b) Allegheny Energy Unit No. 1 and Unit No. 2, LLC owns
100% of Units No. 1 and No. 2, recently constructed at
Springdale, PA. Output from these units is sold to Allegheny
Energy Supply, and transfer of ownership of these units to
Allegheny Energy Supply is expected in mid-to-late-2000.

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

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

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

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

(g) The 180-MW Warrior Run project commenced commercial
operation on February 10, 2000. Potomac Edison, as required
under the terms of a Maryland settlement, will offer the full
output of the Warrior Run project to the market beginning July 1,
2000.

<PAGE

ALLEGHENY MAP

The Allegheny Map (Map), which has been filed with the
Commission on Form SE, provides a broad illustration of the names
and approximate locations of Allegheny's major generation and
transmission facilities, both existing and under construction, in
a five state region which includes portions of Maryland, Ohio,
Pennsylvania, Virginia, and West Virginia. Additionally, Extra
High Voltage substations are displayed. By use of shading, the
map also provides a general representation of the service areas
of Monongahela (both gas and electric) (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, Allegheny
Energy Unit No. 1 and Unit No. 2 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 voltage from 138 kV to 765 kV.
Additionally, interconnections with other utilities are
displayed.

<PAGE>

The following table sets forth the existing miles of tower and
pole transmission and distribution lines and the number of
substations of the Operating Subsidiaries and AGC as of
December 31, 1999:

Miles of Above-Ground Transmission and
Distribution Lines (a) and Number of Substations

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

Monongahela 21,035 283 331
Potomac Edison 18,135 202 276
West Penn 24,102 273 709
AGC(b) 85 85 1
Total 63,357 843 1,317

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

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

The Operating Subsidiaries' transmission network has 12 extra-high-
voltage (EHV - 345kV and above) and 31 lower-voltage interconnections
with neighboring utility systems. The interregional EHV transmission
system, which includes the Operating Subsidiaries' network, continued in
1999 to operate near reliability limits during periods of heavy power
flows that in the past have had a predominantly west-to-east orientation.
In early 1997, NERC undertook the development of a national transmission
security process. The Operating Subsidiaries serve as one of 22 regional
Security Coordinators. This security process includes a Transmission
Loading Relief (TLR) procedure that identifies actual flow path
consequences of all power transactions, and can be used to reduce loading
on the congested facilities. The new security process has provided a
better exchange of operation planning information. It also has allowed
more accurate evaluation of the transmission system and conditions in the
Midwest that occasionally caused the predominant west-to-east power flow
pattern across the Operating Subsidiaries' network to reverse. The TLR
procedure has been effective in addressing congestion caused by parallel
path flows. Careful use of TLR, mainly by others, has resulted in fewer
constraints on the Operating Subsidiaries' transmission facilities. If
TLR had not been available, many of those transmission congestion events
would have required action in the form of transmission service curtailments.

Wholesale generators and other wholesale customers may
now seek from owners of bulk power transmission facilities a
commitment to supply transmission services. (See discussion
under ITEM 1. SALES. Regulatory Framework Affecting Power
Sales) Such demand on the Operating Subsidiaries'
transmission facilities may add to heavy power flows on the
Operating Subsidiaries' facilities and may eventually require
construction of additional transmission facilities.

The Operating Subsidiaries have, since the early 1980s,
provided managed contractual access to their transmission
facilities under various

<PAGE>

tariffs. For new agreements starting in
1996, managed access is also governed by the provisions of the
Operating Subsidiaries' Open Access Transmission Tariff mandated
by and filed with the FERC.

RESEARCH AND DEVELOPMENT

The Operating Subsidiaries spent $7.8 million, $7.9 million,
and $7.4 million, in 1999, 1998 and 1997, respectively, for
research programs. Of these amounts, $5.6 million, $5.5 million
and $5.7 million were for Electric Power Research Institute
(EPRI) dues in 1999, 1998 and 1997 respectively. EPRI is an
industry-sponsored research and development institution. The
Operating Subsidiaries plan to spend approximately $7.1 million
for research in 2000, with EPRI dues representing $4.9 million of
that total.

In addition to EPRI support, in-house research conducted by
Allegheny concentrated on technology based issues that are
important developments for each of Allegheny's businesses. These
technology drivers include products and services for
environmental control, generating unit performance, future
generation technologies, use of coal combustion by-products,
transmission system performance, customer-related research, clean
power technology which includes both power quality technology and
distributed generation technology for customers, delivery systems
equipment and sustainable energy technologies.

Research is also being directed to help address major issues
for Allegheny and the entire electric industry. These include
electric and magnetic field (EMF) assessment of employee exposure
within the work environment, Global Warming from Greenhouse Gas
emissions, waste disposal and discharges to land, water and air
resources, renewable resources, fuel cells, new combustion
turbines, cogeneration technologies, transmission loading
mitigation using Flexible AC Transmission System (FACTS) devices
and new product development ventures.

CAPITAL REQUIREMENTS AND FINANCING

Construction expenditures by the Operating Subsidiaries
and AGC in 1999 amounted to $266.1 million. Construction
expenditures for 2000 and 2001 are expected to aggregate
$213.0 million and $190.0 million, respectively. Construction
expenditures by Allegheny Ventures and Allegheny Energy
Supply, wholly owned nonutility (unregulated) subsidiaries of
AE, in 1999 amounted to $141.4 million and for 2000 and 2001
are expected to aggregate $205.9 million, and $240.9 million.
The 2000 and 2001 estimated regulated expenditures include
$40.0 million and $72.0 million, respectively, to cover the
costs of compliance with the CAAA. Expenditures to cover the
costs of compliance with the CAAA and other environmental
requirements have been and are likely to continue to be
significant. Additionally, new environmental initiatives (See
ITEM 1. ENVIRONMENTAL MATTERS) may substantially increase
Allegheny's construction requirements as early as 2000.

Allegheny Energy Supply is purchasing additional
combustion turbines that will add 200 MW in 2000. Also,
Allegheny Energy Supply is building a 540-MW combined-cycle
generating plant at the Springdale Borough site at a

<PAGE>

cost of
$235 million. The new facility will include two gas-fired
combustion turbines and a steam turbine. All are expected to
be operational and providing power for sale into competitive
markets in 2003.

On October 27, 1998, the EPA finalized rules for reducing
ground level ozone. The EPA is requiring 22 states and the
District of Columbia to submit revisions to their state
implementation plans (SIPs) that address the regional
transport of ozone The intent of the EPA NOx SIP call rule is
to reduce NOx emissions from power plants, on average, to 0.15
pounds of NOx per million BTU (MBTU). As part of the SIP
submittal process, all of the states served by Allegheny are
required to develop regulations to obtain these NOx
reductions. Although Allegheny has joined with other parties
to contest the EPA's actions in court, it is also formulating
plans to comply by making modifications to existing generating
units. The cost to comply will be about $370 million of
capital investments, to be spent during the 1999-2003 period.
Of this amount, about $12 million was spent in 1999. Under
the EPA's plan, Allegheny would be required to reduce
emissions to the 0.15 pounds per MBTU requirement by May 2003.
On March 3, 2000 the DC Circuit Court of Appeals issued a
decision in support of the EPA's NOx SIP call rule. However,
an appeal of that decision is likely.

<PAGE>

Construction Expenditures

1999 2000 2001
Millions of Dollars
(Actual) (Estimated)
Monongahela
Generation $ 28.9 $ 33.6 $ 31.8
Transmission & Distribution 53.5 41.4 40.6
Total* $ 82.4 $ 75.0 $ 72.4

Potomac Edison
Generation $ 36.7 $ 36.6 $ 16.3
Transmission & Distribution 55.0 51.4 55.7
Total* $ 91.7 $ 88.0 $ 72.0

West Penn
Generation $ 16.3 $ 0.0 $ 0.0
Transmission & Distribution 69.9 46.7 43.3
Total* $ 86.2 $ 46.7 $ 43.3

AGC & AESC $ 5.8 $ 3.3 $ 2.3

Total Construction Expenditures,
Regulated $ 266.1 $ 213.0 $ 190.0

West Penn, Unregulated Energy
Supply Division 28.0 0.0 0.0

Other* $ 113.4 $ 205.9 $ 240.9

Total Construction Expenditures
Unregulated $ 141.4 $ 205.9 $ 240.9

Total Construction Expenditures $ 407.5**$ 418.9 $ 430.9

*Includes allowance for funds used during construction
(AFUDC), or capitalized interest in the case of the
generation business of West Penn and Allegheny Energy
Supply, for 1999, 2000, and 2001 of: Monongahela $1.8,
$0.9, and $1.2; Potomac Edison $2.0, $1.0, and $1.3; West
Penn $2.9, $0.3, and $0.4; and Allegheny Energy Supply
$0.2, 5.6, and 6.0.

**Excludes $5.9 million of capital investments made by Allegheny
Ventures.

<PAGE>

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

Expenditures for 1999, 2000, and 2001 include $79.2 million,
$114.5 million, and $135.7 million, respectively, for
construction of environmental control technology. Outages for
construction, CAAA compliance, and other environmental work is,
and will continue to be, coordinated with other planned outages,
where possible.

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

Current forecasts, which assume normal weather conditions,
project average annual winter and summer peak load growth rates
for the regulated load of Allegheny of 0.47% and 0.4%,
respectively, in the period 2000-2010. Equivalent Control Area
growth rates are 1.3% and 1.5%, respectively. Competition for
existing loads could have a substantial effect on those
projections. It is anticipated that existing resources,
purchased power arrangements, reactivation of existing capacity,
the construction or lease of new generating facilities and/or the
acquisition of capacity will be sufficient for Allegheny's future
needs.

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

Financing Programs

In April 1999, Monongahela, Potomac Edison and West Penn
issued $7.7 million, $9.3 million, and $13.8 million,
respectively, of 30-year Pollution Control Revenue Notes to
Pleasants County, West Virginia. Pleasants County, in turn,
issued $30.8 million of 30-year Pollution Control Revenue Bonds
at 5-1/2% interest due April 1, 2029.

<PAGE>

In June 1999, West Penn issued an $84 million Unsecured
Medium-Term Note at 6.375%, due June 1, 2004. In December 1999,
Monongahela issued a $110 million Unsecured Medium-Term Note at
7.36% interest, due January 15, 2010.

In July 1999, West Penn redeemed $39.708 million of
Cumulative Preferred Stock and $40 million of Market Auction
Preferred Stock. In September 1999, Potomac Edison redeemed
$16.378 million of Cumulative Preferred Stock. These actions
were taken to permit the removal of charter restrictions on the
issuance of unsecured debt. West Penn thereafter amended its
charter in its entirety to remove unsecured debt restrictions and
to modernize its charter. Potomac Edison will amend its charter
in its entirety in 2000 to also remove unsecured debt
restrictions and to modernize its charter.

West Penn issued $600 million of transition bonds in
November 1999, in accordance with its restructuring settlement in
Pennsylvania. The transition bonds were issued in four tranches
with an average yield of 6.887%. The proceeds were used
primarily to retire all of West Penn's first mortgage bonds
either through open market purchases or a par call. Following
this retirement, West Penn cancelled its First Mortgage Bond
Indenture dated March 1, 1916. The transition bonds were issued
by a special purpose subsidiary and are non-recourse to West
Penn. The transition bonds do not affect the general credit of
West Penn since the transition bonds are secured by the
collection of Intangible Transition Property (ITP) as authorized
by the Pennsylvania Customer Choice Act. The transition bonds
issued by a subsidiary of West Penn have received a AAA
equivalent credit rating, separate from the other debt of West
Penn.

On October 1, 1999, AYP Energy made a prepayment to a
Credit Agreement between AYP Energy, Inc. and Mellon Bank, N.A.
and the Lending Parties thereto, reducing the amount of a term
loan, a debt obligation, from $160 million to $130 million. On
December 7, 1999, this reduced debt obligation was assumed by
Allegheny Energy Supply when the related assets were transferred
to Allegheny Energy Supply.

During 2000, Monongahela, Potomac Edison, West Penn and
Allegheny Energy Supply anticipate meeting their capital
requirements through a combination of internally generated funds,
cash on hand, issuance of debt, and short-term borrowing as
necessary.

In the future AE will retain more earnings than its historic
norm to fund the costs of sustaining increased income growth.

The Operating Subsidiaries and AGC have financed their
construction programs through internally generated funds, first
mortgage bonds, debentures, medium-term notes, subordinated debt
and preferred stock issues, pollution control and solid waste
disposal notes, installment loans, long-term lease arrangements,
equity investments by AE (or, in the case of AGC, by its parent
companies, and, where necessary, interim short-term debt). Their
future ability to finance their construction programs by these
means depends on many factors, including effects of competition
and creditworthiness, and adequate revenues to produce
satisfactory internally generated funds and

<PAGE>

return on the common
equity portion of the Operating Subsidiaries' capital structures
and to support their issuance of senior and other securities. AE
obtained funds for equity investments in its subsidiaries through
retained earnings and the issuance and sale of its common stock
publicly. Allegheny Energy Supply has financed its construction
program through internally generated funds, equity investments
and loans from AE.

Beginning in the third quarter of 1997, AE began buying
shares in the open market for its Dividend Reinvestment and Stock
Purchase Plan and its Employee Stock Ownership and Savings Plan,
and in 1998 AE began buying shares in the open market for the
Performance Share Plan. In addition, in 1999, AE repurchased a
total of 12 million shares of its common stock in the open market
at a cost of $398.4 million. The 12 million shares are being
held as treasury stock.

At December 31, 1999, system companies had short-term debt
of $641.1 million outstanding and short-term investments of $44.8
million for a net short-term borrowing of $596.3 million. The
borrowing positions of the individual companies were: AE $641.1
million, AGC $52.2 million, Monongahela $28.7 million, and
Allegheny Energy Supply $21.2 million. At December 31, 1999,
Potomac Edison had $31.4 million invested and West Penn had $13.4
million invested.

The Operating Subsidiaries' and AGC's ratios of earnings to
fixed charges for the year ended December 31, 1999, were as
follows: Monongahela, 4.69; Potomac Edison, 4.05; West Penn,
3.86; and AGC, 3.37.

Allegheny's consolidated capitalization ratios as of
December 31, 1999, were: common equity, 42.1%; preferred stock,
1.9%; and long-term debt, 56.0%, including Quarterly Income Debt
Securities 3.9%.

FUEL SUPPLY

Allegheny stations burned approximately 17.7 million tons of
coal in 1999. Of that amount, 52% was used in stations equipped
with scrubbers (9.3 million tons). The use of desulfurization
equipment and the cleaning and blending of coal make burning
local higher-sulfur coal practical. In 1999, almost 100% of the
coal received at Allegheny-operated stations came from mines in
West Virginia, Pennsylvania, Maryland, and Ohio. Allegheny does
not mine or clean any coal. All raw, clean, or washed coal is
purchased from various suppliers as necessary to meet station
requirements.

Long-term arrangements (term of 12 months or greater) are in
effect to provide for approximately 15.9 million tons of coal in
2000. The Operating Subsidiaries and Allegheny Energy Supply
will depend on short-term arrangements and spot purchases for
their remaining requirements. Through the year 2005, the total
coal requirements of present Allegheny-operated stations are
expected to be met with coal acquired under existing contracts or
from known suppliers.

For each of the years 1995 through 1998, the average cost
per ton of coal burned was $32.68, $32.25, $32.66, and $32.26,
respectively. For the year 1999, the cost per ton decreased to
$30.18.

<PAGE>

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

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

RATE MATTERS

Customer Choice

All of the states the Operating Subsidiaries serve are at
various stages of implementation of programs that allow customers
to choose their electric supplier.

Pennsylvania is furthest along with a retail customer-choice
program in place. West Penn is currently implementing a
settlement agreement (approved by the PA PUC on November 19,
1998) to create competition for electricity supply in
Pennsylvania. In January 1999, 66% of each customer class was
eligible to choose their electric supplier. In January 2000, all
electric customers became eligible to participate in Customer
Choice. The settlement agreement provided for a rate refund from
1998 revenue (about $25 million) via a 2.5% rate decrease
throughout 1999, capped rate provisions and authorization to
issue bonds to securitize up to $670 million in transition costs.
On November 16, 1999, a special purpose subsidiary of West Penn
completed the sale of $600 million in transition bonds. After
deducting issuing costs and other recoverable costs, the bond
proceeds recovered approximately $597 million of West Penn's $670
million of authorized transition costs. The other transition
costs either were already collected in 1999, or will be recovered
over a period extending through 2008. The agreement also allowed
the transfer of West Penn's generation assets at book value to an
unregulated generating company, Allegheny Energy Supply Company,
LLC, which transfer occurred on November 18, 1999.

Potomac Edison filed a settlement agreement (covering its
stranded cost quantification mechanism, price protection
mechanism, and unbundled rates) with the Maryland PSC on
September 23, 1999. On December 23, 1999, the Maryland PSC
issued an order approving the settlement agreement which includes
the following provisions: The ability for nearly all Maryland
customers to have the option of choosing an electric generation
supplier starting July 1, 2000; authorization to transfer
generating assets to a non-regulated corporate entity at book
value on July 1, 2000; a reduction in base rates of 7 percent for
residential customers from 2002 through 2008 ($10.4 million each
year, totaling $72.8 million); a reduction in base rates of one-
half of one percent for the majority of commercial and industrial
customers from 2002 through 2008 ($1.5 million each year,
totaling $10.5 million); a cap on generation rates for
residential customers from 2002 through 2008; a cap on non-
residential generation rates from 2002 through 2004; a cap on
transmission and distribution rates for all customers from 2002
through 2004;

<PAGE>

recovery of all purchased power costs incurred as a
result of Potomac Edison's contract to buy generation from the
AES Warrior Run PURPA project; and the establishment of a fund
for the development and use of energy-efficient technologies.

In June and July 1999, Monongahela and other interested
parties filed testimony on issues identified by the West Virginia
PSC related to its investigation into electric industry
restructuring. Following hearings in August 1999, the West
Virginia PSC issued an order directing parties to meet in an
effort to develop a consensus plan for electric restructuring in
West Virginia. A Plan for Restructuring was filed on December
13, 1999 by various parties, including Monongahela. On December
20, 1999, the West Virginia PSC issued an order proposing a plan
for restructuring, similar to the plan submitted to the West
Virginia PSC. The Commission held hearings on the plan in
January 2000 to receive input as to whether the plan should be
submitted to the Legislature for consideration in the 2000
Legislative session. On January 28, 2000, the West Virginia PSC
issued an order approving a revised plan, filed by the parties
that filed the December plan, as well as additional parties. The
revised plan was submitted to the West Virginia Legislature and
was approved, with implementation delayed until certain tax
changes are enacted b the Legislature relating to preservation of
state and local tax revenue and adoption of an implementing
resolution by the Legislature.. Components of the plan include a
10-year transition to customer choice, beginning after January 1,
2001 upon enactment of the tax changes and adoption of the
implementing resolution. The approved plan would deregulate the
generation component and includes provisions for unbundled rates,
rate caps in the earlier years with transition to market rates by
year eleven, establishment of a Rate Stabilization Deferral
Account for residential and small commercial customers, three
percent rate reduction for large commercial and industrial
customers, establishment of default service providers, and
protections for low-income customers. The approved plan also
allows Potomac Edison to transfer its West Virginia
jurisdictional assets to an affiliate at book value on or after
July 1, 2000. The 2000 session of the Legislature adjourned on
March 11, 2000 without consideration of the tax matters
referenced above.

On July 6, 1999, legislation deregulating the electric
utility industry in Ohio was signed by the governor. The law
permits all Ohio customers to begin shopping for electricity
generation starting January 1, 2001. As required, Monongahela
filed its transition plan with the Public Utilities Commission of
Ohio on January 3, 2000, describing the operational changes
necessary to comply with the new law and seeking $21.3 million in
transition costs. The Commission is required to rule on the
plans by October 31, 2000.

The Virginia Electric Utility Restructuring Act was signed
on March 25, 1999, effective July 1, 1999. Potomac Edison does
not plan to conduct a pilot in Virginia due to the experience
gained in Pennsylvania. Potomac Edison will begin offering
Customer Choice to Virginia customers (except those with special
contracts) in 2002.

<PAGE>

Fuel Cost Adjustments

Currently, the states of Maryland, Virginia, West Virginia,
and Ohio use fuel clause procedures to recognize changes in fuel
and other energy costs in rates. In Pennsylvania, the risks
associated with fuel and other generation-related expenses have
been transferred to Allegheny Energy Supply. As other
jurisdictions move to competition and assets are moved to
Allegheny Energy Supply, all generation-related expenses will
also be borne by Allegheny Energy Supply. The procedures in
Maryland, Virginia, West Virginia and Ohio currently use an
expedited proceeding which permits energy costs to be adjusted on
a more timely basis than other costs. Differences between
revenues received for energy costs and actual energy costs are
deferred until the next proceeding when energy rates are adjusted
to return or recover previous overrecoveries or underrecoveries,
respectively. This procedure minimizes the effect on net income
associated with changes in energy costs. Under the terms of the
Potomac Edison settlement agreement approved by the Maryland PSC
on December 23, 1999, the use of a fuel clause will cease for
Potomac Edison's Maryland jurisdiction effective July 1, 2000.
As the remaining states implement Customer Choice, Allegheny
expects that these fuel clause procedures will no longer be in
effect, since the fuel rate will be rolled into the non-regulated
generation rate. Consequently, as is currently the case in
Pennsylvania, risks associated with fuel, other energy costs and
all other generation-related expenses will be borne by Allegheny
Energy Supply.

On February 26, 1999, the West Virginia PSC issued an order
establishing cases for Potomac Edison and Monongahela for review
of fuel costs for the purpose of establishing a fuel increment in
rates to be effective July 1, 1999 through June 30, 2000. In
June 1999, the WV PSC approved a joint stipulation and agreement
between Potomac Edison and Monongahela and the intervenors.
Under the agreement, the parties are to negotiate further in an
effort to more closely align Potomac Edison and Monongahela West
Virginia rate schedules and to petition to reopen this case if
they are successful. The parties have agreed to continue
negotiations until March 15, 2000 in an attempt to submit
proposed rates to the Commission.

On November 8, 1999, Potomac Edison filed with the Maryland
PSC a request to decrease the fuel portion of Maryland customers'
bills by about $6.4 million annually. The requested decrease is
primarily due to greater efficiencies, lower fuel costs, and
increased nonaffiliated generation and transmission sales. The
proposed rates became effective, subject to refund, with the
billing month of December 1999. A hearing was held on December
21, 1999. On February 18, 2000, the hearing examiner issued his
proposed order which approves the fuel rate decrease. This order
will become final on March 21, 2000 unless appealed by any party
or modified by the Maryland PSC.

Fuel proceedings before the Ohio PUC require a mid-term
filing, financial audit, management performance audit, and an
annual filing. The Ohio PUC issued an order setting a new fuel
rate, representing a 6% decrease for Monongahela from the
previous rate, for the six-month period beginning August 1, 1999.
On January 20, 2000, the Ohio PUC issued an order setting a

<PAGE>

new fuel rate, representing a 12.2% decrease for Monongahela from
the previous rate, for the six-month period beginning February 1,
2000.

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

Base Rate Adjustments

Potomac Edison and the Virginia Commission Staff entered
into discussions which resulted in a settlement agreement of
Potomac Edison's Annual Informational Filing (AIF) which the
Virginia SCC approved May 21, 1999. Effective June 1, 1999,
Potomac Edison reduced base rates by $3.0 million annually. The
return on equity (ROE) range was maintained at 11-12% with the
computed ROE, after adjustments, of 11.18%.

Effective with bills rendered on or after January 7, 2000,
there will be an increase in the Maryland base rates. This
increase is a result of the phase-in of the rate increase of $13
million approved by the Maryland PSC on October 27, 1998 and an
increase of $880,000 due to a state tax law reform passed in 1999
to facilitate the transition to Customer Choice. A settlement
agreement, which includes recognition and dollar-for-dollar
recovery of costs to be incurred from the Warrior Run PURPA
project, was filed with the Maryland PSC on July 30, 1998, and
approved by that Commission on October 27, 1998. Rates to each
customer class were approved by the Maryland PSC on December 22,
1998. Under the terms of the agreement, Potomac Edison will
increase its rates about 4% ($13 million) in each of the years
1999, 2000, and 2001 (a $79 million total revenue increase
during 1999 through 2001). The increases are designed to recover
additional costs of about $131 million, over the period 1999-
2001, for capacity purchases from the Warrior Run project net of
alleged overearnings of $52 million for the same period. The
agreement also requires that Potomac Edison share 50% of earnings
above an 11.4% return on equity with customers for 1999 and 2000.
Any sharing of earnings required for 1999 will be reflected as a
credit on customers' bills starting in May 2000.

Other Rate Matters

On September 24, 1999, Monongahela and UtiliCorp United,
Inc., through its divisions, West Virginia Power and West
Virginia Power Gas Service, jointly petitioned for the West
Virginia PSC's permission for Monongahela to buy the assets of WV
Power and WV Power Gas Service for approximately $95 million.
The transaction includes a 20-year gas supply agreement.
Consumers will benefit from a six-year freeze of natural gas base
rates and a three-year freeze on electric rates, with a reduction
in electric rates in 2003 to rates now offered by Monongahela.
The purchase was approved by the West Virginia PSC, FERC,
Department of Justice/Federal Trade Commission, Federal
Communications Commission, Iowa Public Service Commission, and
the Securities and Exchange Commission. Monongahela assumed
ownership of these assets on December 31, 1999.

<PAGE>

On December 20, 1999, Monongahela announced its plan to
acquire Mountaineer Gas Company, a natural gas sales,
transportation, and distribution company serving southern West
Virginia and the northern and eastern panhandles of West
Virginia. The acquisition also includes the assets of its
subsidiary, Mountaineer Gas Services, which operates natural gas-
producing properties, gas-gathering facilities, and intrastate
transmission pipelines. The completion of this $323 million
purchase is conditioned upon, among other things, the approvals
of the West Virginia PSC and the Securities and Exchange
Commission. The regulatory procedures are anticipated to be
completed in approximately six months.

ENVIRONMENTAL MATTERS

The operations of the Allegheny-owned facilities, including
generating stations, are subject to regulation as to air and
water quality, hazardous and solid waste disposal, and other
environmental matters by various federal, state, and local
authorities. The generating units now owned by Allegheny Energy
Supply are subject to the same environmental regulations as other
units owned by the Operating Subsidiaries.

Meeting known environmental standards is estimated to cost
the Operating Subsidiaries and Allegheny Energy Supply about $358
million in construction expenditures over the next three years.
Additional legislation or regulatory control requirements have
been proposed and, if enacted, will require modifying,
supplementing, or replacing equipment at existing stations at
substantial additional cost.

Air Standards

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

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

The CAAA, among other things, requires an annual reduction
in total utility emissions within the United States of 10 million
tons of SO2 and two million tons of NOx from 1980 emission
levels, to be completed in two phases, Phase I and Phase II.
Five coal-fired Allegheny plants were affected in Phase I, and
the remaining plants are affected in Phase II. Installation of
scrubbers at the Harrison Power Station was the strategy
undertaken by Allegheny to meet the required SO2 emission
reductions for Phase I (1995-1999). Allegheny estimates that its
banked emission allowances will allow it to comply with Phase II
SO2 limits through 2005. Studies to evaluate cost-effective
options to comply with Phase II SO2 limits beyond 2005, including
those available in connection with the emission allowance trading
market, are continuing. It is expected that burner modifications
at most of the

<PAGE>

Allegheny-operated stations will satisfy the NOx
emission reduction requirements for the acid rain (Title IV)
provisions of the CAAA. Additional NOx reductions, which will
require some Selective Catalytic Reduction (SCR) or post-
combustion control technologies, are being mandated in Maryland,
Pennsylvania, and West Virginia for ozone nonattainment (Title I)
reasons. Continuous emission monitoring equipment has been
installed on all Phase I and Phase II units.

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

Pursuant to an option in the CAAA, Allegheny chose to treat
seven Phase II boilers as Phase-I-affected units (Substitution
Units) for calendar year 1999. The status of all substitution
units is evaluated on an annual basis to ascertain the financial
benefits of retaining these units as Phase I-affected units. As
a result of being Phase I-affected, these Substitution Units are
required to comply with the Phase I SO2 limits for each year that
they are accorded substitution status by Allegheny.

Title I of the CAAA established an Ozone Transport Region
(OTR) consisting of the District of Columbia, the northern part
of Virginia, and 11 northeastern states including Maryland and
Pennsylvania. Sources within the OTR will be required to reduce
NOx emissions, a precursor of ozone, to a level conducive to
attainment of the one-hour ozone National Ambient Air Quality
Standard (NAAQS). The installation of Reasonably Available
Control Technology (RACT) (overfire air equipment and/or low NOx
burners) at all Pennsylvania and Maryland stations has been
completed. The installation of RACT satisfies both Title I and
Title IV NOx reduction requirements.

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

<PAGE>

However, the MOU Phase III NOx reductions will most likely be
superseded by the EPA's NOx SIP call as discussed below.
Pennsylvania promulgated regulations to implement Phase II of the
MOU in November 1997. Maryland promulgated regulations to
implement Phase II of the MOU in May 1998. However, as a result
of litigation, the Maryland regulation was revised to postpone
compliance to May 2000.

During 1995, the Environmental Council of States and the
U.S. Environmental Protection Agency (EPA) established the Ozone
Transport Assessment Group (OTAG) to develop recommendations for
the regional control of NOx and Volatile Organic Compounds in 37
states east of and bordering the west bank of the Mississippi
River plus Texas. OTAG issued its final report in June 1997 that
recommended EPA consider a range of utility NOx controls between
existing Clean Air Act (Title IV) controls and the less stringent
of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu.
According to OTAG recommendations, the states would have the
opportunity to conduct additional local and subregional modeling
in order to develop and propose appropriate levels and timing of
controls. The EPA initiated the regulatory process to adopt the
OTAG recommendations with a SIP call issued October 1998. The EPA
NOx SIP call requires the equivalent of a uniform 0.15 lb/mmBtu
emission rate throughout a 22-state region, including Maryland,
Pennsylvania, and West Virginia, without the benefit of the OTAG
recommended additional subregional modeling evaluation.
Implementation of controls will be required by summer 2003.
States were required to develop and submit implementing
regulations to the EPA by September 1999. The EPA's NOx SIP call
regulation has been under litigation, but on March 3, 2000 the DC
Circuit Court of Appeals issued a decision that upheld the
regulation. However, an appeal of that decision is likely to be
filed in April 2000 by the State and industry litigants.
Allegheny's compliance with such stringent regulations will
require the installation of expensive post-combustion control
technologies on most of its power stations, with a total capital
cost of approximately $370 million. Of that amount, $12 million
was spent in 1999.

In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included). The petitions claim NOx
emissions from these upwind sources are preventing their
attainment of the ozone standard. In December 1997, the
petitioning states and EPA signed a Memorandum of Agreement to
address these petitions in conjunction with the OTAG-related SIP
call mentioned above. In May 1999, the EPA issued a technical
approval of the petitions and in December 1999 granted final
approval of four of the petitions. The Section 126 petition
rulemaking is also under litigation. Allegheny's compliance plan
for the Section 126 petition rulemaking would be the same as the
NOx SIP call compliance plan discussed above.

The EPA is required by law to regularly review the NAAQS for
criteria pollutants. Previous court orders in litigation by the
American Lung Association have expedited these reviews. The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were
promulgated by the EPA in July 1997. However, the revised
standards were legally challenged and in May 1999 the DC Circuit
Court of Appeals remanded the revised standards back to EPA for
further consideration.

<PAGE>

Also, in May 1999, EPA promulgated final
regional haze regulations to improve visibility in Class I
federal areas (national parks and wilderness areas). The EPA
regional haze regulation is also under litigation. If eventually
upheld in court, subsequent state regulations could require
additional reduction of SO2 and/or NOx emissions from Allegheny
facilities. The effect on Allegheny of revision to any of these
standards or regulations is unknown at this time, but could be
substantial.

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

In 1989, the West Virginia Air Pollution Control Commission
approved the construction of a third-party cogeneration facility
in the vicinity of Rivesville, West Virginia. Emissions impact
modeling for that facility raised concerns about the compliance
of Monongahela's Rivesville Station with ambient standards for
SO2. Pursuant to a consent order, Monongahela agreed to collect
on-site meteorological data and conduct additional dispersion
modeling in order to demonstrate compliance. The modeling study
and a compliance strategy recommending construction of a new
"good engineering practices" (GEP) stack were submitted to the
West Virginia Department of Environmental Protection (WVDEP) in
June 1993. Costs associated with the GEP stack are approximately
$25 million. Monongahela is awaiting action by the WVDEP.

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

In March 1998, the EPA released its Utility Air Toxics
Report to Congress. The report itself does not recommend
regulatory controls. However, the EPA is expected to make a
recommendation on regulatory controls by December 2000. The EPA
has identified mercury emissions as requiring further research
and monitoring because of the potential concern for public
health. While it appears that EPA wants to control utility
mercury emissions, it currently lacks the technical
justification. In late November 1998, the EPA issued a mercury
data collection request that required utilities to sample and
analyze coal shipments for mercury and chlorine throughout 1999.
In addition, some plants, not any Allegheny plants, were required
to conduct stack testing to determine the effectiveness of
existing particulate and SO2 control equipment in the reduction
of mercury emissions.

<PAGE>

Water Standards

Under the National Pollutant Discharge Elimination System
(NPDES), permits for all of Allegheny's stations and disposal
sites are in place and all facilities are compliant with all
permit terms, conditions and effluent limitations. However as
permits are renewed more stringent permit limitations are being
applied. Thus far Allegheny has successfully developed and
scientifically justified, to the satisfaction of the regulatory
agencies, alternate site-specific water quality criteria and thus
avoided incurring the costs of advanced wastewater treatment.

However, there is significant activity at the Federal level
on Clean Water Act (CWA) issues. There are pending rulemakings,
for example regarding the Total Maximum Daily Load (TMDL)
program, water quality standards, antidegradation review, human
health and aquatic life water quality criteria, and mixing zones.
In addition, EPA is developing new policies concerning protection
of endangered species under the CWA and imposition of new CWA
requirements to address sediment contamination. The outcome of
these rulemakings will fundamentally change the traditional water
quality management program from a chemical specific control of
point sources to comprehensive and integrated watershed
management. This regulatory shift will result in more
restrictions on facility discharges as well as nonpoint source
runoff resulting from land use practices such as agriculture and
forestry and will ultimately address water quality impairment
caused by atmospheric deposition.

Over the past several years TMDLs have become a significant
issue because of successful legal challenges to EPA's treatment
of TMDLs under the CWA in various states. Resulting consent
orders in West Virginia and Pennsylvania require development and
implementation of waste loads for point sources and load
allocations for nonpoint sources on numerous waterbodies not
currently meeting water quality standards within a relatively
short time frame (twelve years). Because of the scientific
complexity of the issue, paucity of water quality data, the
resource limitations of the state agencies as well as political
considerations, it is likely that resulting TMDLs will require a
disproportionate reduction in point source versus nonpoint source
discharges. The direct result of the TMDLs will be further
reductions in the amount of pollutants permitted to be discharged
by Allegheny-owned power stations located on water quality
impaired rivers. Indirectly, TMDL's can adversely affect
Allegheny by prohibiting new or increased discharges and
curtailing the wastewater discharges of its industrial customers.
The full implications of the developing TMDL program will not be
known until EPA finalizes the proposed rule and TMDLs are
developed and implemented in specific watersheds.

In anticipation of the potentially adverse impact of the
TMDL program, Allegheny is proactively working with a number of
watershed TMDL stakeholder groups to ensure development of sound
and equitable TMDLs.

<PAGE>

Hazardous and Solid Wastes

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

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

In addition to using coal combustion by-products (CCB's) in
various power plant applications such as scrubber by-product
stabilization at Harrison and Mitchell Power Stations, the
Operating Subsidiaries continue to expand their efforts to market
CCB's for beneficial applications and thereby reduce landfill
requirements. In 1999, the Operating Subsidiaries received
approximately $990,000 from the external sale and utilization of
approximately 410,000 tons of fly ash, 187,000 tons of bottom ash
and 25,000 tons of boiler slag. These CCB's were beneficially
used in applications such as cement replacement, anti-skid
materials, grit blasting material, mine subsidence, structural
fills, and grouting of mines and oil wells.

The Operating Subsidiaries are near completion on the
construction of a processing plant which will convert the flue
gas desulfurization by-product from the Pleasants Power Station
into a commercial grade synthetic gypsum material to be used in
the manufacture of wallboard. The processing plant, which has
produced gypsum on a trial basis, is in commercial production as
of the end of February of 2000 and is expected to supply a
minimum of 600,000 tons per year of gypsum to a wallboard
manufacturing facility. This process will significantly reduce
the amount of by-product going to an impoundment.

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

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

Toxic Release Inventory (TRI)

On Earth Day 1997, President Clinton announced the expansion
of Right-to-Know Toxics Release Inventory (TRI) reporting to
include electric utilities, limited to facilities that combust
coal and/or oil for the purpose

<PAGE>

of generating power for
distribution in commerce. The purpose of TRI is to provide site-
specific information on chemical releases to the air, land, and
water. On June 4, 1999, AE joined with other members of the
Edison Electric Institute in reporting power station releases to
the public. Packets of information about power station releases
were provided to media in Allegheny's service area and posted on
the AE web site. The first TRI report was filed with the
Environmental Protection Agency prior to the July 1, 1999
deadline date, reporting 18 million pounds of total releases for
calendar year 1998.

Global Climate Change

Many uncertainties remain in the global climate change
debate, including the relative contributions of human activities
and natural processes, the extremely high potential costs of
extensive mitigation efforts, and the significant economic and
social disruptions which may result from a large-scale reduction
in the use of fossil fuels. Allegheny is responding
appropriately and will continue to explore cost-effective
opportunities to improve efficiency and performance. The
scientific debate is continuing, however the Clinton
Administration has signed an international treaty called the
Kyoto Protocol, which will require the U.S. to reduce emissions
of GHG by 7% from 1990 levels in the 2008-2012 time period. With
normal economic growth this requirement could mean as much as a
40% reduction of GHG by 2012. The U.S. Senate must ratify the
Kyoto Protocol before it enters into force, as must other nations
subject to the treaty's provisions. The Senate passed a
resolution in 1997 (S.R. 98) by a vote of 95-0 that placed two
conditions on entering into any international climate change
treaty. First, any treaty must include all nations, and, second,
any treaty must not cause serious harm to the U.S. economy. The
Kyoto Protocol does not appear to satisfy either of these
conditions and, therefore, the Clinton Administration has
withheld it from consideration by the Senate. The U.S. electric
utility industry generates about one third of the GHG emitted,
with other Industries, Transportation and Agriculture the rest,
or two thirds. Implementation of the Kyoto Protocol would raise
considerable uncertainty about the future viability of fossil
fuels as an energy source for new and existing power plants.

If and when the need for reducing greenhouse gas emissions
has been identified and scientifically supported, Allegheny
believes that a global solution involving all nations will be
needed and must give credit for actions taken. Precipitous and
urgent action under strict limits and timetables will result in
severe economic dislocation and is not warranted based on the
ongoing scientific debate. Appropriate results can be achieved
domestically by continuing to build upon Allegheny's corporate
awareness and the notable progress of existing voluntary
programs.

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

<PAGE>

our business and in other areas, such as forestry, international
projects, and emissions trading.

The Operating Subsidiaries maintain an active climate-
related research program and are responsive to the greenhouse gas
guidelines suggested in the national Energy Policy Act of 1992.
As a result, the Operating Subsidiaries have voluntarily reduced
their total annual emissions of GHG by about 1,650,000 tons, as
described in the latest filing with the Department of Energy.

The Operating Subsidiaries support EPRI whose climate
research is funded at around $7 to $10 million per year and
Edison Electric Institute's Climate Challenge Initiative funded
at $100,000 per-year; and have committed to invest $3.11 million
in an electrotechnology and renewable energy venture capital
fund.

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

West Penn, as part of its restructuring settlement approved
by the Pennsylvania PUC, agreed to support five important climate
related initiatives: 1) Renewable Energy Development, 2)
Sustainable Energy Fund ($11,425,721 paid on December 31, 1998),
3) Renewable Energy Pilot Program ($300,000 each year), 4) Energy
Cooperative Association of Pennsylvania (contribution of $4
million) and 5) Universal Service and Energy Conservation Program
($8.082 million per year).

In response to environmental issues over the past 30 years,
the Operating Subsidiaries spent over $1.6 billion in capital
expenditures and approximately $200 million annually in
operations and maintenance. Allegheny is committed to
environmental stewardship and the research needed to provide
answers to difficult compliance problems. These actions will
mitigate the impact of the Operating Subsidiaries' operations on
the environment and ameliorate any alleged climate change
impacts.

REGULATION

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

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

<PAGE>

In 1999, the Operating Subsidiaries continued to take part
in and fund various programs to assist low-income customers,
customers with special needs, and/or customers experiencing
temporary financial hardship.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

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

<PAGE>

conclusions of law were submitted by the parties. On
December 3, 1999 the District Court found that defendant DQE did
not breach the April 5, 1997 Agreement and Plan of Merger.
Accordingly, the District Court found in favor of DQE and against
AE on all claims and all requests for injunctive relief. It
granted judgment in favor of defendant DQE and against plaintiff
AE.

On September 7, 1995, MidAtlantic Energy (MidAtlantic) sued
Monongahela, Potomac Edison, and AE in state court in Marshall
County, W.Va., alleging failure to comply with PURPA regulations
in refusing to purchase capacity and energy from a proposed PURPA
project and interference with MidAtlantic's contract with the
Babcock and Wilcox Company (B and W), among other things. This
suit followed an unsuccessful complaint proceeding by MidAtlantic
requesting the West Virginia PSC to order Monongahela and Potomac
Edison to purchase capacity and energy from the project. The
MidAtlantic suit also named B and W as a defendant. MidAtlantic
sought compensatory and punitive damages. Monongahela, Potomac
Edison, and AE filed an answer and B and W filed an answer and
counterclaim. Trial was scheduled for June 7, 1999 but the case
settled on the first day of trial. The case was dismissed, with
prejudice, on July 9, 1999.

On August 13, 1996, American Bituminous Partners, L.P.,
(AmBit), filed a request for arbitration alleging that the energy
rate payable under its purchase power contract with Monongahela
had been improperly calculated. The arbitration proceeding was
bifurcated into a liability phase and, if necessary, a damages
phase. A hearing in the liability phase of the arbitration
proceeding has been completed and briefed. On February 18, 1998,
the arbitration panel made a determination in the liability
phase. They determined that certain lime handling costs should
have been a component of the energy rate and therefore were
improperly accounted for in 1995 and 1996. Ambit and Monongahela
have entered into a Settlement Agreement, subject to the approval
of the Public Service Commission for the State of West Virginia,
resolving all disputes presented in, or which could have been
presented in, the arbitration. Monongahela will petition the
Public Service Commission for the State of West Virginia for
approval of the Settlement Agreement. Monongahela cannot predict
the outcome of this proceeding.

On December 17, 1999, AES/Beaver Valley, Inc., (AES/BV)
filed a demand for arbitration with the American Arbitration
Association. AES/BV requested a declaratory judgment that the
Electric Energy Purchase Agreement (EEPA) approved by the PaPUC
in 1986 continues to govern the transaction between West Penn and
AES/BV for the sale of up to 125 MWH per hour of power as set
forth in the EEPA, even if AES/BV's proposed improvements to the
plant to comply with the more rigorous NOx standards result in an
increase in the amount of energy the plant produces annually.
AES/BV also requested an award of its attorneys fees and costs.
On February 23, 2000, AES/BV filed an additional claim against
West Penn for $2 million. West Penn cannot predict the outcome
of this proceeding.

<PAGE>

As of January 14, 2000, Monongahela has been named as a
defendant along with multiple other defendants in a total of
7,932 pending asbestos cases involving one or more plaintiffs.
Potomac Edison and West Penn have been named as defendants along
with multiple other defendants in approximately one-half of those
cases. Because these cases are filed in a "shotgun" format
wherein 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 may be estimated that
about one-third of the total number of cases filed actually
involve claims against any or all of the Operating Subsidiaries.
All complaints allege that the plaintiffs sustained unspecified
injuries resulting from claimed exposure to asbestos in various
generating plants and other industrial facilities operated by the
various defendants, although all plaintiffs do not claim exposure
at facilities operated by all defendants. With very few
exceptions, plaintiffs claiming exposure at stations operated by
the Operating Subsidiaries were employed by third-party
contractors, not the Operating Subsidiaries. Three plaintiffs
are known to be either present or former employees of
Monongahela. Each plaintiff generally seeks compensatory and
punitive damages against all defendants in amounts of up to $1
million and $3 million, respectively; in those cases which
include a spousal claim for loss of consortium, damages are
generally sought against all defendants in an amount of up to an
additional $1 million. A total of 878 cases have been previously
settled and/or dismissed against Monongahela for an amount
substantially less than the anticipated cost of defense. While
the Operating Subsidiaries believe that all of the cases are
without merit, they cannot predict the outcome nor are they able
to determine whether additional cases will be filed.

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

On March 4, 1994, the Operating Subsidiaries received notice
that the EPA had identified them as potentially responsible
parties (PRPs) under the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended, with respect
to the Jack's Creek/Sitkin Smelting Superfund Site (Site). There
are approximately 175 other PRPs involved. A Remedial
Investigation/Feasibility Study (RI/FS) prepared by the EPA
originally indicated remedial alternatives which ranged as high
as $113 million, to be shared by all responsible parties. A PRP
Group consisting of approximately 40 members, and to which the
Operating Subsidiaries belong, has been formed and has submitted
an addendum to the RI/FS which proposes a substantially less
expensive cleanup remedy. In 1999, the PRP Group entered into a
consent order with the EPA to remediate the site. A final
determination has not been made for the Operating Subsidiaries'
share of the remediation costs. However, at this time it is
estimated that the effect on the Operating Subsidiaries will not
be material.

<PAGE>

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

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

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

The Attorney General of the State of New York and the
Attorney General of the State of Connecticut, in letters dated
September 15, 1999, and November 3, 1999, respectively, notified
Allegheny of their intent to commence civil actions against
Allegheny and/or its subsidiaries alleging violations at the Fort
Martin Power Station under the federal Clean Air Act, which
requires power plants that make major modifications to comply
with the same emission standards applicable to new power plants.
Similar actions may be commenced by other governmental
authorities in the future. Fort Martin is located in West
Virginia and is now jointly owned by Allegheny Energy Supply,
Monongahela Power, and Potomac Edison. Both Attorneys General
stated their intent to seek injunctive relief and penalties. In
addition, the Attorney General of the State of New York indicated
that he may assert claims under the state common law of public
nuisance seeking to recover, among other things, compensation for
alleged environmental damage caused in New York by the operation
of the Fort Martin Power Station. At this time, Allegheny and
its subsidiaries are not able to determine what effect, if any,
these actions may have on them.

<PAGE>

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

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

<PAGE>

Executive Officers of the Registrants

The names of the executive officers of each company, their ages
as of December 31, 1999, the positions they hold, or held during
1999, and their business experience during the past five years
appears below:

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

Charles S. Ault(b) 61 V.P.
(1990-7/99)

Paul M. Barbas(c) 43 V.P.
(7-99- )

Eileen M. Beck 58 Secretary Secretary Secretary Secretary Secretary
(1988- ) (1995- ) (1996- ) (1996- ) (1982- )
Previously Previously, Previously Previously
Asst. Treas. Asst. Treas. Asst. Sec. Asst. Sec.
(1979-95) (1981-95) (1988-95) (1988-95)
Asst. Sec.
(1988-94)

Regis F. Binder(d) 47 V.P. & Treas. Treas. Treas. Treas. Treas.
(12/98- ) (12/98- ) (12/98- ) (12/98- ) (2/99- )

Richard J. Gagliardi 49 V.P. Asst. Sec. Asst.
(1991- ) (1990-96) Treas.
(1982-96)

James R. Haney(e) 43 V.P. V.P. V.P.
(1998- ) (1998- ) (1998- )

Thomas K. Henderson 59 V.P. V.P. V.P. V.P. Dir.& V.P.
(1997- ) (1995- ) (1995- ) (1985- ) (1996- )

Kenneth M. Jones 62 V.P. Dir.& V.P.
(1991- ) (1991-2/99)
Previously,
Controller
(1991-1998)

Thomas J. Kloc 47 V.P. & Controller Controller Controller Dir.& V.P.
Controller (1996- ) (1988- ) (1995- ) (2/99- )
(1998- ) Controller
(1988- )
____________________________________________________________________________________________________

</TABLE>

(a) All officers and directors are elected annually.
(b) Mr. Ault retired effective July 1, 1999.
(c) Prior to his appointment as Vice President of AE, Mr. Barbas
was President, GE Capital Rental Services (3/97-2/99);
President, GE Capital Computer Rental Services (10/93-3/97);
and National Operations Manager, GE Rental/Lease (3/93-
10/93).
(d) Prior to his appointment as Vice President and Treasurer of
AE and Treasurer of MP, PE, WPP and AGC, Mr. Binder was
Executive Director, Regulation and Rates for APSC
(1997-1998); General Manager, Industrial Marketing for APSC
(1996-1997); Director, Rates for APSC (1995-1996); and
Assisant Director Rates for APSC (1993-1995).
(e) Prior to his appointment as Vice President Customer
Operations, Mr. Haney was Executive Director, Operating
Business Unit (8/98-10/98); Director, Operations Services
(5/96-8/98); Director, Transmission Projects (12/95-5/96);
Manager, Construction (AESC) (2/95-12/95); and Division
Manager, Monongahela (12/90-2/95).

<PAGE>

Executive Officers of the Registrants, cont'd.

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

James D. Latimer 61 V.P. V.P. V.P.
(1995- ) (1995- ) (1995- )
Previously,
Executive V.P.
(1994-95)
V.P.
1988-94)

Ronald A. Magnuson(f) 42 V.P. V.P. V.P.
(7/99- ) (7/99- ) (7/99- )

Michael P. Morrell(g) 51 Sr. V.P. Dir & V.P. Dir.& V.P. Dir. & V.P. Dir.& V.P.
(1996- ) (1996- ) (1996- ) (1996- ) (1996- )

Alan J. Noia 52 Chairman Chairman Chairman Chairman Chairman,
& CEO & CEO & CEO & CEO Pres.& CEO
(1996- ) (1996- ) (1996- ) (1996- ) (1996- )
Pres.& Dir. Dir. Dir. Dir. Dir.& V.P.
(1994- ) (1994- ) (1990- ) (1994- ) (1994-96)
Previously, Previously,
COO Pres.
(1994-96) (1990-94)

Jay S. Pifer 62 Sr. V.P. Pres.& Dir. Pres.& Dir. Pres.
(1996- ) (1995- ) (1995- ) (1990- )
& Dir.
(1992- )

Victoria V. Schaff(h) 55 V.P.
(1997- )

Peter J. Skrgic 58 Sr. V.P. V.P. V.P.& Dir. V.P. V.P.& Dir.
(1994- ) (1996- ) (1990- ) (1996- ) (1989- )
Previously, & Dir. & Dir.
V.P. (1990- ) (1990- )
(1989-94)

Robert R. Winter 56 V.P. V.P. V.P.
(1987- ) (1995- ) (1995- )

</TABLE>

(f) Prior to his appointment as Vice President of MP, PE and
WPP, Mr. Magnuson was Executive Director, Customer Affairs
(4/99-7/99); Executive Director, Human Resources (10/98-
4/99); and Director Human Resources (1/95-10/98).
(g) Prior to his appointment as Senior Vice President of AE and
Vice President of MP, PE, WPP and AGC, Mr. Morrell was V.P.
- Regulatory and Public Affairs, Jersey Central Power &
Light Company (JCP&L) (8/94-4/96); and V.P. - Materials
Services and Regulatory Affairs, JCP&L (1/93-8/94).
(h) Prior to her appointment as Vice President of AE, Ms. Schaff
was a Vice President of AESC (1/96-1/97) and a Federal
Affairs Representative with the Union Electric Company (4/88-
12/95).

<PAGE>

PART II

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

AYE is the trading symbol of the common stock of AE on the
New York, Chicago, and Pacific Stock Exchanges. The stock is also
traded on the Amsterdam (Netherlands) and other stock exchanges.
As of December 31, 1999, there were 44,873 holders of record of
AE's common stock.

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

1999 1998
Dividend High Low Dividend High Low
<S> <C> <C> <C> <C> <C> <C>
1st Quarter 43 cents $34-1/2 $28-11/16 43 cents $33-9/16 $30-1/8
2nd Quarter 43 cents $35-3/16 $29-1/2 43 cents $34 $27-5/16
3rd Quarter 43 cents $34-7/8 $31 43 cents $31-15/16 $26-5/8
4th Quarter 43 cents $33-1/8 $26-3/16 43 cents $34-15/16 $29-1/2

</TABLE>

The high and low prices through March 2, 2000 were $29-9/16
and $25-3/16. The last reported sale on that date was at $25-
1/2.

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

AGC. The information required by this Item is not
applicable as all the common stock of AGC is held by Monongahela,
Potomac Edison, and Allegheny Energy Supply Company, LLC.

<PAGE>

ITEM 6. SELECTED FINANCIAL DATA

Page No.

AE D-1

Monongahela D-7

Potomac Edison D-10

West Penn D-14

AGC D-17

<PAGE>

Allegheny Energy, Inc.

CONDENSED FINANCIAL STATEMENTS

Monongahela The Potomac West Penn Allegheny Energy Allegheny
Power Edison Power Company Supply Energy, Inc. and
Year ended December 31, 1999 Company Company and Subsidiaries Company, LLC Subsidiaries
- -----------------------------------------------------------------------------------------------------------
(Thousands of dollars)

BALANCE SHEETS
Assets
Property, plant, and equipment:
<S> <C> <C> <C> <C> <C> <C>
At original cost* $2,173,603 $2,322,104 $1,597,484 $2,060,040 $ 8,839,719
Accumulated depreciation (958,867) (998,710) (506,416) (940,672) (3,632,568)
- -----------------------------------------------------------------------------------------------------------
1,214,736 1,323,394 1,091,068 1,119,368 5,207,151
Excess of cost over
net assets acquired 26,325 42,584
Cash and temporary cash investments 3,826 34,509 19,288 1,668 65,984
Other current assets 228,393 173,171 272,600 245,802 643,326
Regulatory assets 145,176 46,121 467,982 663,847
Other 75,262 61,656 13,827 83,325 229,549
- ---------------------------------------------------------------------------------------------------------
Total $1,693,718 $1,638,851 $1,864,765 $1,450,163 $ 6,852,441
- ---------------------------------------------------------------------------------------------------------
$ 46,138 $ 53,354 $ 45,450 $ 86,147 $ 231,763
*Includes construction work in progress

Capitalization and liabilities
Common stock, other paid-in capital,
retained earnings, less
treasury stock (at cost) $ 578,951 $ 700,422 $ 79,658 $ 512,699 $ 1,695,325
Preferred stock 74,000 74,000
Long-term debt and QUIDS 503,741 510,344 966,026 356,239 2,254,463
Short-term debt 28,650 21,200 641,095
Other current liabilities 216,353 208,327 259,635 224,158 667,440
Unamortized investment credit 14,007 17,720 21,847 18,199 116,971
Deferred income taxes 248,987 159,351 211,369 128,639 920,943
Regulatory liabilities 13,961 25,319 15,126 78,743
Adverse power purchase commitments 303,935 185,626 303,935
Other 15,068 17,368 7,169 3,403 99,526
- ---------------------------------------------------------------------------------------------------------
Total $1,693,718 $1,638,851 $1,864,765 $1,450,163 $ 6,852,441
- ---------------------------------------------------------------------------------------------------------

Statements of income
Operating revenues $ 673,335 $ 753,257 $1,354,203 $ 140,874 $ 2,808,441
Operating expenses 554,298 617,535 1,160,434 130,408 2,333,794
- ---------------------------------------------------------------------------------------------------------
Operating income 119,037 135,722 193,769 10,466 474,647
Other income and deductions 7,178 8,518 9,654 1,159 3,445
- ---------------------------------------------------------------------------------------------------------
Income before interest charges,
preferred dividends,
preferred redemption premiums,
and extraordinary charge, net 126,215 144,240 203,423 11,625 478,092
Interest charges, preferred dividends,
and preferred redemption premiums 38,925 44,728 70,680 2,093 192,703
- ---------------------------------------------------------------------------------------------------------
Balance for common stock
before extraordinary charge, net 87,290 99,512 132,743 9,532 285,389
Extraordinary charge, net (16,949) (10,018) (26,968)
- ---------------------------------------------------------------------------------------------------------
Balance for common stock $ 87,290 $ 82,563 $ 122,725 $ 9,532 $ 258,421
- ---------------------------------------------------------------------------------------------------------

</TABLE>

Note: Allegheny Energy Supply Company, LLC, started operations on November 18,
1999.

D-1

<PAGE>

Allegheny Energy, Inc.

CONSOLIDATED STATISTICS

Year ended December 31 1999 1998 1997 1996 1995 1994 1989
- -------------------------------------------------------------------------------------------------------------
Summary of operations (Millions of dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $2,808.4 $2,576.4 $2,369.5 $2,327.6 $2,315.2 $2,184.6 $1,790.6
- -------------------------------------------------------------------------------------------------------------

Operation expense 1,498.1 1,286.0 1,065.9 1,013.0 1,024.9 1,017.8 867.0
Maintenance 223.5 217.5 230.6 243.3 249.5 241.9 185.5
Restructuring charges and asset write-offs 103.9 23.4 9.2
Depreciation 257.5 270.4 265.7 263.2 256.3 223.9 172.3
Taxes other than income 190.3 194.6 187.0 185.4 184.7 183.1 139.5
Taxes on income 164.4 168.4 168.1 128.0 154.2 125.9 89.0
Allowance for funds
used during construction (6.9) (5.0) (8.3) (5.9) (8.2) (19.6) (7.7)
Interest charges, preferred dividends,
and preferred redemption premiums 197.7 189.7 197.2 191.1 196.9 184.1 156.0
Other income and deductions (1.6) (8.2) (18.0) (4.4) (6.2) (1.5) (5.9)
- -------------------------------------------------------------------------------------------------------------
Consolidated income before
extraordinary charge
and cumulative effect
of accounting change 285.4 263.0 281.3 210.0 239.7 219.8 194.9
Extraordinary charge, net a (27.0) (275.4)
Cumulative effect of accounting change, net b 43.4
- -------------------------------------------------------------------------------------------------------------
Consolidated net income (loss) $ 258.4 $ (12.4) $ 281.3 $ 210.0 $ 239.7 $ 263.2 $ 194.9
- -------------------------------------------------------------------------------------------------------------
Common stock data c
Shares issued (thousands) 122,436 122,436 122,436 121,840 120,701 119,293 105,579
Treasury shares (thousands) (12,000)
- -------------------------------------------------------------------------------------------------------------
Shares outstanding (thousands) 110,436 122,436 122,436 121,840 120,701 119,293 105,579
- -------------------------------------------------------------------------------------------------------------
Average shares outstanding (thousands) 116,237 122,436 122,208 121,141 119,864 118,272 104,787
Earnings per average share: d
Consolidated income before
extraordinary charge
and cumulative effect
of accounting change $ 2.45 $ 2.15 $ 2.30 $ 1.73 $ 2.00 $ 1.86 $ 1.86
Extraordinary charge, net a (.23) (2.25)
Cumulative effect of accounting
change, net b .37
Consolidated net income (loss) $ 2.22 $ (.10) $ 2.30 $ 1.73 $ 2.00 $ 2.23 $ 1.86
Dividends paid per share $ 1.72 $ 1.72 $ 1.72 $ 1.69 $ 1.65 $ 1.64 $ 1.55
Dividend payout ratioe 64.6% 73.5% 74.7% 97.5% 82.5% 88.3% 83.3%
Shareholders 44,873 48,869 53,389 58,677 63,280 66,818 68,156
Market price per share:
High $ 35 3/16 $ 34 15/16 $ 32 19/32 $31 1/8 $ 29 1/4 $ 26 1/2 $21 1/4
Low $ 26 3/16 $ 26 5/8 $ 25 1/2 $ 28 $21 1/2 $ 19 3/4 $17 13/16
Close $ 26 15/16$ 34 1/2 $ 32 1/2 $ 30 3/8 $28 5/8 $ 21 3/4 $20 15/16
Book value per share $ 15.35 $ 16.61 $ 18.43 $ 17.80 $ 17.65 $ 17.26 $ 14.99
Return on average common equity e 16.16% 13.26% 12.63% 9.69% 11.35% 10.96% 12.41%
- --------------------------------------------------------------------------------------------------------------
Capitalization data (Millions of dollars)
Common stock $1,695.3 $2,033.9 $2,256.9 $2,169.1 $2,129.9 $2,059.3 $1,582.4
Preferred stock:
Not subject to mandatory redemption 74.0 170.1 170.1 170.1 170.1 300.1 235.1
Subject to mandatory redemption 25.2 30.6
Long-term debt and QUIDS 2,254.5 2,179.3 2,193.1 2,397.1 2,273.2 2,178.5 1,578.4
- -------------------------------------------------------------------------------------------------------------
Total capitalization $4,023.8 $4,383.3 $4,620.1 $4,736.3 $4,573.2 $4,563.1 $3,426.5
- -------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Common stock 42.1% 46.4% 48.8% 45.8% 46.6% 45.1% 46.2%

D-2

<PAGE>

Preferred stock:
Not subject to mandatory redemption 1.9 3.9 3.7 3.6 3.7 6.6 6.8
Subject to mandatory redemption .6 .9
Long-term debt and QUIDS 56.0 49.7 47.5 50.6 49.7 47.7 46.1
- --------------------------------------------------------------------------------------------------------------
Total assets (Millions of dollars) $6,852.4 $6,535.2 $6,654.1 $6,618.5 $6,447.3 $6,362.2 $4,433.3
- --------------------------------------------------------------------------------------------------------------
Property data (Millions of dollars)
Gross property $8,839.7 $8,395.3 $8,451.4 $8,206.2 $7,812.7 $7,586.8 $5,721.5
Accumulated depreciation (3,632.6) (3,395.6) (3,155.2) (2,910.0) (2,700.1) (2,529.4) (1,807.1)
- --------------------------------------------------------------------------------------------------------------
Net property $5,207.1 $4,999.7 $5,296.2 $5,296.2 $5,112.6 $5,057.4 $3,914.4
Gross additions during year-utility $ 266.2 $ 229.4 $ 284.7 $ 289.5 $ 319.1 $ 508.3 $ 302.5
-nonutility $ 141.3 $ 1.8 $ 1.4 $ 178.5
Ratio of provisions for
depreciation to depreciable property 3.23% 3.28% 3.34% 3.47% 3.50% 3.32% 3.26%
- -------------------------------------------------------------------------------------------------------------

Revenues (Millions of dollars) f
Residential $ 930.3 $ 880.6 $ 892.9 $ 932.2 $ 927.0 $ 863.7 $ 626.2
Commercial 500.3 501.4 490.5 492.7 493.7 459.3 327.5
Industrial 720.5 753.5 748.1 752.9 770.2 728.0 553.5
Wholesale and street lighting 42.4 69.0 65.1 66.6 59.6 58.7 46.2
- -------------------------------------------------------------------------------------------------------------
Revenues from
regular utility customers 2,193.5 2,204.5 2,196.6 2,244.4 2,250.5 2,109.7 1,553.4
Other non-gWh 9.2 9.9 6.4 7.7 6.5 7.1 5.0
Bulk power 22.5 69.8 39.6 22.4 13.0 29.0 189.7
Transmission and other energy services 48.5 45.2 41.1 52.4 45.2 38.8 42.5
- -------------------------------------------------------------------------------------------------------------
Total utility revenues $2,273.7 $2,329.4 $2,283.7 $2,326.9 $2,315.2 $2,184.6 $1,790.6
- -------------------------------------------------------------------------------------------------------------
Total nonutility revenues $ 887.4 $ 247.0 $ 85.8 $ .7
- -------------------------------------------------------------------------------------------------------------
Sales volumes-gWh
Residential 13,562 12,939 12,832 13,328 13,003 12,630 11,042
Commercial 8,955 8,626 8,176 8,132 7,963 7,607 6,479
Industrial 19,846 19,675 19,040 18,568 18,457 17,708 16,239
Wholesale and street lighting 1,478 1,409 1,422 1,456 1,304 1,275 1,110
- -------------------------------------------------------------------------------------------------------------
Regular utility transactions 43,841 42,649 41,470 41,484 40,727 39,220 34,870
- -------------------------------------------------------------------------------------------------------------
Bulk power 571 3,037 1,667 966 507 1,086 7,011
Transmission and other energy services 8,450 7,345g 12,367 17,402 14,586 9,405 17,777
- -------------------------------------------------------------------------------------------------------------
Total utility transactions 52,862 53,031 55,504 59,852 55,820 49,711 59,658
- -------------------------------------------------------------------------------------------------------------
Total nonutility transactions 15,854 8,278 3,734 109
- -------------------------------------------------------------------------------------------------------------
Output and delivery-gWh
Steam generation 44,776 44,323 43,463 40,067 39,174 38,959 43,497
Hydro and pumped-storage generation 1,648 1,326 1,171 1,348 1,234 1,390 1,774
Pumped-storage input (1,963) (1,498) (1,298) (1,405) (1,390) (1,564) (1,973)
Purchased power 17,365 11,505 6,485 5,518 5,021 4,136 1,797
Transmission and other energy services 8,450 7,777 12,367 17,402 14,586 9,405 17,777
Combustion turbines 7
Losses and system uses (3,066) (2,124) (2,950) (2,969) (2,805) (2,615) (3,214)
- -------------------------------------------------------------------------------------------------------------
Total transactions as above 67,217h 61,309 59,238 59,961 55,820 49,711 59,658
- -------------------------------------------------------------------------------------------------------------
Energy supply
Generating capability-MW
Utility-owned 4,451 8,121 8,071 8,070 8,070 8,070 7,906
Nonutility-owned 4,142 276 276
Nonutility contracts i 299 299 299 299 299 299 160
Maximum hour peak-MW 7,788j 7,314j 7,423 7,500 7,280 7,153 6,489

D-3

<PAGE>

Load factor 70.5%k 69.1%k 68.3% 67.5% 68.3% 66.8% 67.0%
Heat rate-Btus per kWh 9,963 9,939 9,936 9,910 9,970 9,927 9,967
Fuel costs-cents per million Btus 119.61 128.92 130.05 129.22 130.20 141.50 136.70
- -------------------------------------------------------------------------------------------------------------

</TABLE>

a Write-off in connection with deregulation proceedings in Maryland and
Pennsylvania and costs associated with the reacquisition of first
mortgage bonds.
b To record unbilled revenues, net of income taxes.
c Reflects a two-for-one common stock split effective November 4, 1993.
d Basic and diluted earnings per average share.
e Excludes the cumulative effect of the accounting change in 1994, the
extraordinary charge, net, and Pennsylvania restructuring activities
in 1998, and the extraordinary charge and other charges for merger-
related costs and a long dormant pumped-storage generation project
in 1999. Includes the effect of internal restructuring in 1995 and
1996.
f Eliminations between utility and nonutility are shown on page 32.
g Excludes 432 gWh delivered to customers participating in the Pennsylvania
pilot program that are included in regular utility transactions sales
volumes.
h Net of 1,499 gWh eliminated between utility and nonutility.
i Capability available through contractual arrangements with nonutility
generators.
j Peak coincident load of all customers provided delivery service within the
Company's service territory irrespective of the generation service chosen
by the customers therein.
k Based on peak coincident load.

UTILITY STATISTICS

Year ended December 31 1999 1998 1997 1996 1995 1994 1989
- ------------------------------------------------------------------------------------------------------------
Customers (thousands) a
<S> <C> <C> <C> <C> <C> <C> <C>
Residential 1,250.6 1,236.9 1,224.9 1,213.7 1,204.4 1,189.7 1,118.1
Commercial 158.1 154.7 151.5 148.5 146.0 143.0 128.9
Industrial 25.9 25.5 25.2 25.0 24.6 24.2 22.4
Other 1.3 1.3 1.3 1.3 1.3 1.3 1.2
- ------------------------------------------------------------------------------------------------------------
Total customers 1,435.9 1,418.4 1,402.9 1,388.5 1,376.3 1,358.2 1,270.6
- ------------------------------------------------------------------------------------------------------------
Average annual use-kWh per
customer b
Residential 10,913 10,486 10,521 11,042 10,865 10,682 9,950
All retail service 28,285 28,174 28,647 29,085 28,908 28,205 26,866
- ------------------------------------------------------------------------------------------------------------
Average rate-cents per kWh b
Residential 7.03 6.90 6.96 6.99 7.13 6.84 5.67
All retail service 5.45 5.32 5.36 5.46 5.58 5.43 4.48
- ------------------------------------------------------------------------------------------------------------

</TABLE>

a Customers in the Company's service territory receiving delivery service.
b Use and rate statistics are calculated based on full service customers
(customers receiving both generation and delivery from the Company).

<PAGE>
Allegheny Energy, Inc.

INVESTOR INFORMATION

Dividend Declarations Dividends are normally declared on the first Thursday of
March, June, September, and December. Record dates are normally the second
Monday after the dividend is declared, with payment dates the last business day
of March, June, September, and December.

D-4

<PAGE>

Dividend Reinvestment and Stock Purchase Plan Our Dividend Reinvestment and
Stock Purchase Plan provides shareholders with a convenient way to purchase
additional shares of the Company's stock. Participants may at the time of each
cash dividend payment on the stock have all or part of their dividends
automatically invested in additional shares or invest any additional amount they
wish between $50 and $10,000 in such shares or do both. The offering of shares
under the Plan is made only by Prospectus. To get the Prospectus and an
Authorization Form to enroll in the Plan, write to Eileen M. Beck, Secretary,
Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or
ebeck@alleghenyenergy.com.

Annual Meeting The Annual Meeting of Shareholders will be held on the eleventh
floor of the World Headquarters of Chase Manhattan Bank, 270 Park Ave., New
York, NY, on Thursday, May 11, 2000, at 9:30 a.m.

Form 10-K The Company will provide without charge to each beneficial holder of
its common stock, on the written request of such person, a copy of Allegheny
Energy's combined Annual Report to the Securities and Exchange Commission on
Form 10-K for 1999. Any such request should be directed to Cynthia A. Shoop,
Director, Corporate Communications, Allegheny Energy, Inc., 10435 Downsville
Pike, Hagerstown, MD 21740-1766, or cshoop@alleghenyenergy.com.

Duplicate Mailings/Direct Deposit of Dividends If you receive duplicate
mailings of the Annual Report or wish to have your dividends deposited directly
to your banking institution, please notify ChaseMellon Shareholder Services,
L.L.C., P.O. Box 3316, South Hackensack, NJ 07606. To speak to a representative
responsible for Allegheny Energy, Inc. shareholder accounts, call 1-800-648-
8389.

Stock Transfer Agent and Registrar ChaseMellon Shareholder Services, L.L.C.,
Overpeck Centre, 85 Challenger Road, Ridgefield Park, NJ 07660. The internet
address is www.chasemellon.com.

DIVIDENDS PAID-RANGE OF COMMON STOCK PRICES PER SHARE

1999 1998
------------------------------------------- ---------------------------------------------
NYSE Composite
Transactions Dividend High Low Close Dividend High Low Close
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1st Quarter .43 $ 34 1/2 $28 11/16 $ 29 1/2 .43 $ 33 9/16 $ 30 1/8 $ 33 9/16
2nd Quarter .43 35 3/16 29 1/2 32 1/16 .43 34 27 5/16 30 1/8
3rd Quarter .43 34 7/8 31 31 7/8 .43 31 15/16 26 5/8 31 9/16
4th Quarter .43 33 1/8 26 3/16 26 15/16 .43 34 15/16 29 1/2 34 1/2

</TABLE>

The high and low prices in 2000 were $ 29 and $ 25 9/16 through February 3,
2000. The last reported sale on that date was $ 28 5/8.
- ------------------------------------------------------------------------------

D-5

<PAGE>

Allegheny Energy, Inc.

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
(Millions of dollars)

Basic and Diluted Earnings Per Average Share
-------------------------------------------
Consolidated Consolidated
Income Before Consolidated Income Before Consolidated
Operating Operating Extraordinary Extraordinary Net Income Extraordinary Extraordinary Net Income
Quarter Ended Revenues Income Charge, Net Charge, Net (Loss) Charge, Net Charge, Net (Loss)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
March 1998 $645.5 $124.7 $78.2 $ 78.2 $.64 $ .64
June 1998* 627.6 100.1 53.8 $(265.4) (211.6) .44 $(2.17) (1.73)
September 1998 726.6 128.6 82.7 82.7 .68 .68
December 1998* 576.7 86.1 48.3 (10.0) 38.3 .39 (.08) .31
March 1999 690.0 140.2 97.8 97.8 .80 .80
June 1999 643.4 111.7 64.5 64.5 .55 .55
September 1999 741.4 117.2 71.3 71.3 .63 .63
December 1999** 733.7 105.5 51.8 (27.0) 24.8 .46 (.24) .22
- ----------------------------------------------------------------------------------------------------------------------

</TABLE>

*Results for the second and fourth quarters of 1998 reflect Pennsylvania
restructuring activities.
**Results for the fourth quarter of 1999 reflect charges for Maryland
restructuring, retiring debt related to the securitization of Pennsylvania
stranded costs, merger-related costs, and a long dormant pumped-storage
generation project.

D-6

<PAGE>

Monongahela Power Company

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

<TABLE>

Quarter Ended
1999 1998
Dec. Sept. June March Dec. Sept. June March
<S> <C> <C> <C> <C> <C> <C> <C> <C>

Electric operating
revenues ............. $163,904 $178,330 $160,459 $170,642 $155,712 $177,364 $153,774 $158,272
Operating income........ 31,019 32,595 25,102 30,321 28,154 31,887 24,087 27,358
Net income.............. 23,890 26,631 18,556 23,250 21,143 25,244 16,611 19,427

</TABLE>

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

<TABLE>

1999 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>
Electric operating revenues:
Residential.......................... $210,757 $200,896 $199,931 $206,033 $209,065 $190,861
Commercial........................... 130,052 126,464 118,825 121,631 124,457 116,201
Industrial........................... 217,792 208,613 196,716 200,970 212,427 202,181
Wholesale and street lighting........ 7,138 7,656 7,600 7,513 7,255 7,142
Revenues from regular customers.... 565,739 543,629 523,072 536,147 553,204 516,385
Affiliated........................... 84,747 77,314 83,600 74,825 73,216 79,674
Other non-kWh........................ 4,299 4,426 4,379 4,136 3,722 3,535
Bulk power........................... 6,567 8,509 7,299 4,772 2,749 7,681
Transmission and other energy
services........................... 11,983 11,244 9,961 12,591 10,589 9,172
Total revenues..................... 673,335 645,122 628,311 632,471 643,480 616,447

Operation expense...................... 345,565 313,795 305,487 310,480 330,740 330,909
Maintenance............................ 63,993 67,033 70,561 74,735 73,041 69,389
Internal restructuring charges
and asset write-off.................. 24,299 5,493
Depreciation........................... 60,905 58,610 56,593 55,490 57,864 57,952
Taxes other than income................ 43,395 44,742 38,776 40,418 38,551 40,404
Taxes on income........................ 40,440 49,456 47,519 34,496 41,834 30,650
Allowance for funds used
during construction.................. (1,774) (1,043) (1,386) (672) (1,393) (2,946)
Interest charges....................... 34,603 36,153 38,730 38,604 39,872 38,156
Other income, net...................... (6,119) (6,049) (8,498) (6,831) (9,235) (8,003)
Income before cumulative effect
of accounting change................. 92,327 82,425 80,529 61,452 66,713 59,936
Cumulative effect of accounting
change, net (a)...................... 7,945
Net income............................. $ 92,327 $ 82,425 $ 80,529 $ 61,452 $ 66,713 $ 67,881

Return on average common equity (b).... 15.29% 13.62% 13.99% 11.00% 11.92% 10.66%

</TABLE>

(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994
and a charge for a long dormant pumped-storage generation project
in 1999. Includes the effect of internal restructuring in 1995 and 1996.

D-7

<PAGE>

Monongahela Power Company

FINANCIAL AND OPERATING STATISTICS

<TABLE>

1999 1998 1997 1996 1995 1994

PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross.............................. $2,173,603 $2,007,876 $1,950,478 $1,879,622 $1,821,613 $1,763,533
Accumulated depreciation........... (958,867) (883,915) (840,525) (790,649) (747,013) (701,271)
Net.............................. $1,214,736 $1,123,961 $1,109,953 $1,088,973 $1,074,600 $1,062,262

GROSS ADDITIONS TO PROPERTY
(Thousands):......................... $ 82,483 $ 72,795 $ 78,139 $ 72,577 $ 75,458 $ 103,975

TOTAL ASSETS at Dec. 31
(Thousands).......................... $1,693,718 $1,519,764 $1,497,756 $1,486,742 $1,480,591 $1,476,483

CAPITALIZATION at Dec. 31
(Thousands):
Common stock....................... $ 578,951 $ 570,188 $ 540,930 $ 512,212 $ 505,752 $ 495,693
Preferred stock.................... 74,000 74,000 74,000 74,000 74,000 114,000
Long-term debt and QUIDS........... 503,741 453,917 455,088 474,841 489,995 470,131
$1,156,692 $1,098,105 $1,070,018 $1,061,053 $1,069,747 $1,079,824

Ratios:
Common stock....................... 50.0% 51.9% 50.6% 48.3% 47.3% 45.9%
Preferred stock.................... 6.4 6.8 6.9 7.0 6.9 10.6
Long-term debt and QUIDS........... 43.6 41.3 42.5 44.7 45.8 43.5
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31:
Company-owned...................... 2,352,250 2,326,300 2,326,300 2,326,300 2,326,300 2,326,300
Nonutility contracts (a)........... 161,000 161,000 161,000 161,000 161,000 161,000

KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential........................ 2,884,144 2,757,067 2,764,630 2,815,414 2,807,135 2,674,664
Commercial......................... 2,148,361 2,102,604 1,987,147 2,007,116 1,967,473 1,846,791
Industrial......................... 5,736,718 5,510,925 5,224,364 5,024,257 5,114,126 4,942,388
Wholesale and street lighting...... 152,476 142,797 142,827 142,198 138,456 134,351
Sales to regular customers....... 10,921,699 10,513,393 10,118,968 9,988,985 10,027,190 9,598,194
Affiliated......................... 2,746,111 1,950,803 2,080,542 1,694,722 1,596,081 1,791,099
Bulk power......................... 191,784 301,656 249,505 196,843 105,126 285,048
Transmission and other energy
services......................... 2,138,247 1,932,160 3,007,439 4,218,150 3,497,216 2,278,111
Total sales volumes............ 15,997,841 14,698,012 15,456,454 16,098,700 15,225,613 13,952,452
Output and Delivery:
Steam generation................... 12,146,537 11,251,721 10,936,469 10,678,491 10,620,003 10,743,934
Pumped-storage generation.......... 372,658 288,266 241,958 263,640 257,284 290,586
Pumped-storage input............... (481,872) (370,822) (310,565) (337,451) (330,915) (373,116)

D-8

<PAGE>

Purchased power.................... 2,562,752 2,283,055 2,294,059 2,040,136 1,903,644 1,685,938
Transmission and other energy
services......................... 2,138,247 1,932,160 3,007,439 4,218,150 3,497,216 2,278,111
Losses and system uses............. (740,481) (686,368) (712,906) (764,266) (721,619) (673,001)
Total transactions as above.... 15,997,841 14,698,012 15,456,454 16,098,700 15,225,613 13,952,452

CUSTOMERS at Dec. 31:
Residential.......................... 312,180 309,760 307,920 305,579 303,568 300,465
Commercial........................... 38,654 37,929 37,168 36,323 35,793 35,268
Industrial........................... 8,014 7,992 7,996 8,019 8,085 8,029
Other................................ 176 218 199 182 170 171
Total customers.................... 359,024 355,899 353,283 350,103 347,616 343,933

RESIDENTIAL SERVICE:
Average use-
kWh per customer................... 9,283 8,938 9,023 9,256 9,306 8,957
Average revenue-
dollars per customer............... 678.38 651.29 652.53 677.37 693.11 639.16
Average rate-
cents per kWh...................... 7.31 7.29 7.23 7.32 7.45 7.14

</TABLE>

(a) Capability available through contractual arrangements with nonutility
generator.

D-9

<PAGE>

The Potomac Edison Company

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

Quarter Ended
1999 1998
Dec.* Sept. June March Dec. Sept. June March
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Electric operating
revenues............. $186,099 $189,489 $174,691 $202,978 $177,744 $190,533 $177,519 $191,698
Operating income....... 28,736 34,348 27,543 45,095 34,458 36,680 30,036 37,622
Income before
extraordinary charge,
net.................. 19,191 26,492 18,736 36,164 25,757 27,299 20,504 27,922
Extraordinary charge, net (16,949)
Net income............. 2,242 26,492 18,736 36,164 25,757 27,299 20,504 27,922

</TABLE>

*Results for the fourth quarter of 1999 reflect charges for Maryland
restructuring and a long dormant pumped-storage generation project.

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

1999 1998 1997 1996 1995 1994
Electric operating revenues:
Residential.......................... $330,299 $309,058 $299,876 $324,120 $316,714 $296,090
Commercial........................... 168,469 156,973 148,287 146,432 145,096 135,937
Industrial........................... 212,205 206,638 198,174 196,813 200,890 195,089
Wholesale and street lighting....... 5,821(a) 27,667 30,443 32,907 27,028 26,109
Revenues from regular customers.... 716,794 700,336 676,780 700,272 689,728 653,225
Affiliated........................... 11,352 9,401 9,687 2,399 2,525 2,716
Other non-kWh........................ 539 1,358 (1,273) (405) (961) (4,647)
Bulk power........................... 8,410 11,690 10,035 7,577 4,566 8,932
Transmission and other
energy services.................... 16,162 14,709 13,552 16,917 14,811 12,675
Total.............................. 753,257 737,494 708,781 726,760 710,669 672,901

Operation expense...................... 396,153 369,998 359,350 373,133 374,731 362,167
Maintenance............................ 57,257 52,186 56,815 62,248 60,052 58,624
Internal restructuring charges
and asset write-off.................. 26,094 6,847
Depreciation........................... 75,917 74,344 71,763 71,254 68,826 59,989
Taxes other than income................ 50,924 49,567 47,585 45,809 47,629 46,740
Taxes on income........................ 37,284 52,603 44,496 34,132 36,936 33,126
Allowance for funds used
during construction.................. (1,993) (1,576) (2,830) (2,491) (1,752) (5,874)
Interest charges....................... 44,902 48,187 49,823 50,197 51,179 46,456
Other income, net...................... (7,770) (9,297) (13,976) (11,791) (12,044) (10,310)

D-10

<PAGE>

Income before extraordinary charge and
cumulative effect of accounting
change............................... 100,583 101,482 95,755 78,175 78,265 81,983
Extraordinary charge, net (b) ......... (16,949)
Cumulative effect of accounting
change, net (c)...................... 16,471
Net income............................. $ 83,634 $101,482 $ 95,755 $ 78,175 $ 78,265 $ 98,454

Return on average common equity (d).... 13.20% 13.90% 13.44% 11.42% 11.34% 11.86%

</TABLE>

(a) Includes reduction of $19,949 related to Maryland settlement.
(b) Write-off in connection with deregulation proceedings in Maryland.
(c) To record unbilled revenues, net of income taxes.
(d) Excludes the cumulative effect of the accounting change in 1994 and
the extraordinary charge, net and a charge for a long dormant
pumped-storage generation project in 1999. Includes the effect of
internal restructuring in 1995 and 1996.

D-11

<PAGE>

The Potomac Edison Company

FINANCIAL AND OPERATING STATISTICS

<S> <C> <C> <C> <C> <C> <C>
1999 1998 1997 1996 1995 1994
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross................................ $2,322,104 $2,249,716 $2,196,262 $2,124,956 $2,050,835 $1,978,396
Accumulated depreciation............. (998,710) (926,840) (859,076) (791,257) (729,653) (673,853)
Net................................ 1,323,394 $1,322,876 $1,337,186 $1,333,699 $1,321,182 $1,304,543

GROSS ADDITIONS TO PROPERTY
(Thousands)............................ $ 91,622 $ 60,525 $ 78,298 $ 86,256 $ 92,240 $ 142,826

TOTAL ASSETS at Dec. 31
(Thousands)............................ $1,638,851 $1,728,619 $1,688,482 $1,696,904 $1,654,444 $1,629,535

CAPITALIZATION at Dec. 31:
(Thousands):
Common stock......................... $ 700,422 $ 762,912 $ 689,781 $ 678,116 $ 667,242 $ 658,146
Preferred stock:
Not subject to mandatory redemption. 16,378 16,378 16,378 16,378 36,378
Subject to mandatory redemption.... 25,200
Long-term debt and QUIDS............. 510,344 578,817 627,012 628,431 628,854 604,749
$1,210,766 $1,358,107 $1,333,171 $1,322,925 $1,312,474 $1,324,473
Ratios:
Common stock......................... 57.8% 56.2% 51.8% 51.3% 50.8% 49.7%
Preferred stock:
Not subject to mandatory redemption. 1.2 1.2 1.2 1.3 2.7
Subject to mandatory redemption.... 1.9
Long-term debt and QUIDS............. 42.2 42.6 47.0 47.5 47.9 45.7
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31 2,099,120 2,073,292 2,073,292 2,072,292 2,072,292 2,072,292

KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential.......................... 4,643,621 4,401,238 4,290,117 4,599,758 4,377,416 4,214,997
Commercial........................... 2,667,928 2,498,546 2,331,789 2,288,229 2,213,052 2,136,081
Industrial........................... 5,841,102 5,922,274 5,593,722 5,567,088 5,485,220 5,339,737
Wholesale and street lighting........ 683,691 657,357 666,383 724,011 603,572 591,799
Sales to regular customers......... 13,836,342 13,479,415 12,882,011 13,179,086 12,679,260 12,282,614
Affiliated........................... 894,094 498,069 591,876 47,781 52,967 61,815
Bulk power........................... 233,189 402,635 369,732 315,808 173,110 331,832
Transmission and other
energy services.................... 2,789,957 2,470,365 4,044,837 5,617,912 4,740,010 3,031,339
Total sales volumes................ 17,753,582 16,850,484 17,888,456 19,160,587 17,645,347 15,707,600

D-12

<PAGE>

Output and Delivery:
Steam generation..................... 11,483,502 11,254,505 11,002,533 10,762,678 10,410,118 10,464,607
Hydro and pumped-storage generation.. 413,206 416,983 370,026 401,998 395,315 426,550
Pumped-storage input................. (499,497) (486,823) (426,087) (455,142) (452,151) (506,213)
Purchased power...................... 4,493,128 4,190,098 3,934,815 3,639,519 3,318,302 3,033,744
Transmission and other
energy services.................... 2,789,957 2,470,365 4,044,837 5,617,912 4,740,010 3,031,339
Losses and system uses............... (926,714) (994,644) (1,037,668) (806,378) (766,247) (742,427)
Total transactions as above........ 17,753,582 16,850,484 17,888,456 19,160,587 17,645,347 15,707,600

CUSTOMERS at Dec. 31:
Residential............................ 346,821 339,584 333,224 327,344 321,813 315,309
Commercial............................. 45,968 44,828 43,794 42,670 41,759 40,927
Industrial............................. 5,235 5,122 5,010 4,887 4,733 4,595
Other.................................. 620 641 598 571 543 524
Total customers...................... 398,644 390,175 382,626 375,472 368,848 361,355

RESIDENTIAL SERVICE:
Average use-
kWh per customer..................... 13,523 13,093 13,003 14,179 13,729 13,506
Average revenue-
dollars per customer................. 961.92 919.42 908.87 999.10 993.35 948.76
Average rate-
cents per kWh........................ 7.11 7.02 6.99 7.05 7.24 7.02

</TABLE>

D-13

<PAGE>

West Penn Power Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

Quarter Ended
1999 1998
Dec. Sept. June March Dec. Sept. June March

<S> <C> <C> <C> <C> <C> <C> <C> <C>
Electric operating
revenues................ $313,542 $395,662 $327,269 $317,730 $246,729 $288,272 $263,023 $280,703
Operating income.......... 45,711 42,295 47,089 58,674 17,038 56,248 40,627 52,619
Consolidated net income
(loss).................. $ 16,927 31,507 33,649 45,499 (5,504) 42,835 (239,138) 39,001

</TABLE>

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

1999 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>

Operating revenues..................... $1,354,203 $1,078,727 $1,082,162 $1,089,124 $1,081,093 $1,011,337
Operation expense...................... 800,438 552,514 524,051 531,522 523,279 531,059
Maintenance............................ 93,436 91,724 98,252 104,211 114,489 111,841
Internal restructuring charges
and asset write-offs................. 53,343 11,099 8,919
Depreciation and amortization.......... 114,268 114,709 113,793 119,066 112,334 88,935
Taxes other than income................ 80,719 88,722 90,140 90,132 89,694 87,224
Taxes on income........................ 71,573 64,526 73,279 47,455 61,745 46,645
Allowance for funds used
during construction.................. (2,933) (2,403) (4,085) (2,723) (5,041) (10,777)
Interest charges....................... 68,723 67,640 69,629 71,072 67,902 60,274
Other income, net...................... (9,621) (11,325) (17,562) (13,439) (12,287) (13,798)

Consolidated income before
extraordinary charge and cumulative
effect of accounting change.......... 137,600 112,620 134,665 88,485 117,879 101,015
Extraordinary charge, net (a).......... (10,018) (275,426)
Cumulative effect of accounting
change, net (b)...................... 19,031
Consolidated net income (loss)......... $ 127,582 $ (162,806) $ 134,665 $ 88,485 $ 117,879 $ 120,046

Return on average common equity (c).... 20.97% 13.12% 13.70% 8.72% 11.46% 9.94%

</TABLE>

(a) Write-off in connection with Pennsylvania deregulation proceedings.
(b) To record unbilled revenues, net of income taxes.
(c) Excludes the cumulative effect of the accounting change in 1994, the
extraordinary charge, net and Pennsylvania restructuring activities
in 1998, and the extraordinary charge, net and a long dormant pumped-
storage generation project in 1999. Includes the effect of internal
restructuring in 1995 and 1996.

D-14

<PAGE>

FINANCIAL AND OPERATING STATISTICS

<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 1994

PROPERTY DATA
at Dec. 31 (Thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross property................... $1,597,484 $3,365,784 $3,293,039 $3,182,208 $3,097,522 $3,013,777
Accumulated depreciation......... (506,416) (1,362,413) (1,254,900) (1,152,383) (1,063,399) (1,009,565)
Net property................... $1,091,068 $2,003,371 $2,038,139 $2,029,825 $2,034,123 $2,004,212

Gross additions during year:
Utility......................... $ 86,290 $ 95,975 $ 128,054 $ 130,606 $ 149,122 $ 260,366
Nonutility...................... $ 27,956

TOTAL ASSETS at Dec. 31
(Thousands)........................ $1,864,765 $2,887,706 $2,777,375 $2,724,367 $2,771,164 $2,731,858

CAPITALIZATION at Dec. 31
(Thousands):
Common stock..................... $ 79,658 $ 732,161 $ 997,027 $ 962,752 $ 973,188 $ 955,482
Preferred stock.................. 79,708 79,708 79,708 79,708 149,708
Long-term debt and QUIDS......... 966,026 837,725 802,319 905,243 904,669 836,426
$1,045,684 $1,649,594 $1,879,054 $1,947,703 $1,957,565 $1,941,616
Ratios:
Common stock..................... 7.6% 44.4% 53.1% 49.4% 49.7% 49.2%
Preferred stock.................. 4.8 4.2 4.1 4.1 7.7
Long-term debt and QUIDS......... 92.4% 50.8 42.7 46.5 46.2 43.1
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY
kW at Dec. 31:
Company-owned.................... 3,721,408 3,671,408 3,671,408 3,671,408 3,671,408
Nonutility contracts (a).......... 138,000 138,000 138,000 138,000 138,000 138,000

REVENUES (b)
Residential........................ $ 389,273 $ 370,636 $ 393,036 $ 402,083 $ 401,186 $ 376,776
Commercial......................... 201,728 217,954 223,347 224,663 224,144 207,165
Industrial......................... 290,491 338,254 352,730 355,120 356,937 330,739
Wholesale and street lighting...... 27,425 33,650 27,051 26,194 25,330 25,425
Revenues from regular utility
customers...................... 908,917 960,494 996,164 1,008,060 1,007,597 940,105
Affiliated......................... 33,987 45,180 39,031 44,231 44,293 37,915
Other non-kWh...................... 6,468 4,152 6,377 3,903 3,765 3,980
Bulk power......................... 7,549 49,605 22,188 10,012 5,687 12,339
Transmission services.............. 20,300 19,296 18,402 22,918 19,751 16,998
Total utility revenues........... $ 977,221 $1,078,727 $1,082,162 $1,089,124 $1,081,093 $1,011,337
Total nonutility revenues.......... $ 681,637

</TABLE>

D-15

FINANCIAL AND OPERATING STATISTICS (continued)
______________________________________________________________________________________________
1999 1998 1997 1996 1995 1994

KILOWATT-HOURS (Thousands):
Sales Volumes:
<S> <C> <C> <C> <C> <C> <C>
Residential..................... 6,028,420 5,778,155 5,756,594 5,913,412 5,818,838 5,740,028
Commercial...................... 3,903,446 4,023,523 3,833,178 3,835,831 3,782,250 3,624,117
Industrial...................... 7,222,636 8,237,627 8,046,166 7,974,265 7,857,689 7,426,267
Wholesale and street lighting... 641,605 617,841 611,105 591,122 561,893 548,296
Regular Utility transactions.. 17,796,107 18,657,146 18,247,043 18,314,630 18,020,670 17,338,708
Affiliated...................... 1,295,975 1,974,497 1,789,476 1,068,712 1,059,852 982,557
Bulk power...................... 145,717 2,332,825 1,046,905 453,028 227,893 471,050
Transmission services........... 3,522,145 2,942,868(c) 5,392,916 7,567,153 6,348,926 4,093,693
Total utility transactions.... 22,759,944 25,907,336 26,476,340 27,403,523 25,657,341 22,886,008
Total nonutility transactions... 9,970,100

Output and Delivery:
Steam generation................ 17,593,971 20,053,422 19,523,537 18,578,677 18,143,822 17,750,267
Hydro and pumped-storage
generation..................... 774,505 620,496 559,241 682,747 581,353 673,195
Pumped-storage input............ (878,237) (640,242) (561,135) (612,877) (606,953) (684,715)
Purchased power................. 12,979,203 2,890,986 2,968,258 2,583,166 2,507,196 2,253,701
Transmission services........... 3,522,145 3,850,394 5,392,916 7,567,153 6,348,926 4,093,693
Losses and system uses.......... (1,261,543) (867,720) (1,406,477) (1,395,343) (1,317,003) (1,200,133)
Total transactions as above... 32,730,044 25,907,336 26,476,340 27,403,523 25,657,341 22,886,008

CUSTOMERS at Dec. 31(d):
Residential....................... 591,665 587,503 583,745 580,816 578,983 573,963
Commercial........................ 73,480 71,920 70,559 69,457 68,500 66,842
Industrial........................ 12,615 12,389 12,142 12,051 11,801 11,563
Other............................. 570 608 629 607 598 586
Total customers................. 678,330 672,420 667,075 662,931 659,882 652,954

RESIDENTIAL SERVICE (e):
Average use-
kWh per customer................ 10,239 9,775 9,903 10,223 10,096 10,041
Average revenue-
dollars per customer............ 698.73 644.98 674.73 695.08 696.06 659.07
Average rate-
cents per kWh................... 6.82 6.60 6.81 6.80 6.89 6.56

(a) Capability available through contractual arrangements with
nonutility generators.
(b) Eliminations between utility and nonutility are shown on page 4.
(c) Excludes 907,526 kWh (in thousands) delivered to customers
participating in the Pennsylvania pilot program that are
included in regular customer transactions sales volumes.
(d) Customers in the Company's service territory receiving delivery
service.
(e) Use, revenue, and rate statistics are calculated based on full
service customers (customers receiving both generation and
delivery from the Company).

</TABLE>
D-16

<PAGE>
Allegheny Generating Company

QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)

<TABLE>
<CAPTION>
Quarter Ended
1999 1998
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dec. Sept. June March Dec. Sept. June March
Electric operating
revenues............... $16,853 $18,072 $17,810 $17,857 $17,783 $18,303 $19,126 $18,604
Operating income......... 8,220 8,821 8,586 8,455 8,699 9,297 9,258 9,400
Net income............... 5,344 5,516 5,302 5,053 5,230 5,625 5,961 5,937

</TABLE>

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

1999 1998 1997 1996 1995 1994

<S> <C> <C> <C> <C> <C> <C>
Electric operating revenues............ $ 70,592 $ 73,816 $ 76,458 $ 83,402 $ 86,970 $ 91,022

Operation and maintenance expense...... 5,023 4,592 4,877 5,165 5,740 6,695
Depreciation........................... 16,980 16,949 17,000 17,160 17,018 16,852
Taxes other than income taxes.......... 4,510 4,662 4,835 4,801 5,091 5,223
Federal income taxes................... 9,997 10,959 11,213 13,297 13,552 14,737
Interest charges....................... 13,261 13,987 15,391 16,193 18,361 17,809
Other income, net...................... (394) (86) (9,126) (3) (16) (11)
Net Income........................... $ 21,215 $ 22,753 $ 32,268 $ 26,789 $ 27,224 $ 29,717

Return on average common equity........ 13.08% 12.57% 15.98% 12.58% 12.46% 13.14%

FINANCIAL AND OPERATING STATISTICS

PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.............................. $828,894 $828,806 $828,658* $837,050 $836,894* $824,714
Accumulated depreciation........... (227,177) (210,198) (193,173) (176,178) (159,037) (143,965)
Net.............................. $601,717 $618,608 $635,485 $660,872 $677,857 $680,749

GROSS ADDITIONS TO PROPERTY
(Thousands).......................... $ 85 $ 69 $ 444 $ 178 $ 14,165* $ 1,065

TOTAL ASSETS
at Dec. 31 (Thousands)............... $620,883 $639,458 $663,920 $692,408 $710,287 $714,236

CAPITALIZATION AND SHORT-TERM DEBT
at Dec. 31:
(Thousands):
Common stock..................... $154,491 $165,276 $199,523 $202,955 $214,153 $222,729
Long-term and short-term debt.... 201,081 215,579 208,735 239,234 256,084 268,165

D-17

<PAGE>

Allegheny Generating Company

$355,572 $380,855 $408,258 $442,189 $470,237 $490,894

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

KILOWATT-HOURS (Thousands):
Pumping energy supplied by Parents... 1,962,534 1,497,887 1,297,787 1,405,470 1,390,019 1,564,044
Pumped-storage generation............ 1,526,824 1,164,325 1,011,366 1,098,278 1,081,112 1,218,446

</TABLE>

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

D-18

<PAGE>

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

Page No.

AE M-1

Monongahela M-28

Potomac Edison M-44

West Penn M-62

AGC M-79

ITEM 7A. Quantitative and Qualitative Disclosure About
Market Risk

Allegheny Energy Supply enters into power purchase and
sales contracts to sell power generation and meet its
contractual requirements. During 1999, the Operating
Subsidiaries also entered into power purchase and sales
contracts to meet native load requirements and to sell power
generation. Physical receipt or delivery is expected on all
these contracts. Neither the Operating Subsidiaries nor
Allegheny Energy Supply use futures contracts or options for
speculative or trading purposes. Costs and revenues are
recognized in the month the energy is received or delivered.

<PAGE>

Allegheny Energy, Inc.

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

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

Factors that could cause actual results to differ materially include, among
other matters, electric utility restructuring, including ongoing state and
federal activities; developments in the legislative, regulatory, and competitive
environments in which the Company operates, including regulatory proceedings
affecting rates charged by the Company's subsidiaries; environmental,
legislative, and regulatory changes; future economic conditions; earnings
retention and dividend payout policies; the Company's ability to compete in
unregulated energy markets; and other circumstances that could affect
anticipated revenues and costs such as significant volatility in the market
price of wholesale power and fuel for electric generation, unscheduled
maintenance or repair requirements, weather, and compliance with laws and
regulations.

Business Strategy Generation of electricity will continue to be a core
component of the Company's business. The Company's goal is to grow generation
through building and buying generating facilities. The energy delivery (wires
and pipes) business will also continue to be an important part of the Company's
business which the Company plans to expand. Existing nonutility businesses,
primarily telecommunications, that are closely tied to our core business will
continue to be developed.

The Company's settlement agreement in Pennsylvania permitted West Penn Power
Company (West Penn) to transfer 3,778 megawatts (MW) of generating capacity at
net book value to a new, unregulated, wholly owned subsidiary of the Company.
The recent settlement in Maryland will allow about 1,300 MW of additional
generating capacity to be transferred at net book value in 2000. The Company is
seeking to transfer the remaining generating assets in Ohio, Virginia, and West
Virginia to its unregulated subsidiary at book value in deregulation proceedings
in these jurisdictions. The unregulated electric supply is being sold in both
the wholesale and retail competitive marketplaces, allowing greater earnings
growth potential, subject to market risk, while allowing us to capitalize on the
Company's strengths in the generation business.

M-1

<PAGE>
Allegheny Energy, Inc.

SIGNIFICANT EVENTS IN 1999, 1998, AND 1997

Maryland Deregulation On September 23, 1999, a settlement agreement between The
Potomac Edison Company (Potomac Edison), the Staff of the Maryland Public
Service Commission (Maryland PSC), and other parties working to implement
customer choice and deregulation of electric generation for Potomac Edison in
Maryland was filed with the Maryland PSC. On December 23, 1999, the Maryland PSC
approved the settlement agreement, which provides nearly all of Potomac Edison's
211,000 Maryland customers with the ability to choose an electric generation
supplier starting July 1, 2000.

As a result of the Maryland settlement agreement, Potomac Edison discontinued
the application of the Financial Accounting Standards Board's (FASB) Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," for the electric generation portion of its
Maryland operations and has adopted SFAS No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71." Accordingly, Potomac
Edison recorded an extraordinary charge of $26.9 million ($17.0 million after
taxes) during the fourth quarter of 1999. This write-off reflects the impairment
of certain electric generation assets as determined by applying SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the write-off of generation-related net regulatory assets.
See Notes B and C to the consolidated financial statements for details of the
settlement agreement and other information about the deregulation process.

See Electric Energy Competition on page 38 for more information regarding
restructuring in Maryland.

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

As a result of the May 29, 1998, Pennsylvania PUC order and as revised by the
November 19, 1998, settlement agreement, West Penn determined in 1998 that,
under the provisions of SFAS No. 101, an extraordinary charge of $466.9 million
($275.4 million after taxes) was required to reflect a write-off of certain
disallowances. Charges of $40.3 million ($23.7 million after taxes) related to
the West Penn revenue refund and energy program payments were also recorded in
1998.

Under the terms of the Pennsylvania settlement agreement, two-thirds of West
Penn's customers were permitted to choose an alternate generation supplier
beginning in January 1999.

M-2

<PAGE>
Allegheny Energy, Inc.

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

See Electric Energy Competition on page 38 for more information regarding the
restructuring in Pennsylvania.

Nonutility Sales of Electricity Since 1997, the Company has been marketing
electric energy to customers in deregulated markets. During 1999, the Company's
energy supply business sold 2,912,273 megawatt-hours (MWh) of electricity to
customers in deregulated retail markets and 21,374,732 MWh to customers in
deregulated wholesale markets. During 1999, West Penn's former generation
customers purchased 2,522,611 MWh of electricity from alternative energy
suppliers as a result of customer choice in Pennsylvania.

Unregulated Generating Subsidiary During 1999, the Company obtained the
necessary regulatory approvals to form an unregulated generating subsidiary,
Allegheny Energy Supply Company, LLC (Allegheny Energy Supply). During the
fourth quarter of 1999, West Penn transferred its deregulated generating
capacity, which totaled 3,778 MW, to Allegheny Energy Supply at book value as
allowed by the final settlement in West Penn's Pennsylvania restructuring case.
In addition, Allegheny Energy Supply purchased from AYP Energy, Inc. (AYP
Energy) its 276 MW of merchant capacity at Fort Martin Unit No. 1.

Recapitalization In 1999, the Company completed the following steps in its
recapitalization process for West Penn concurrent with the implementation of
deregulation of electric generation in Pennsylvania:

* $600 million of transition bonds were issued in November 1999;

* $525 million of first mortgage bonds were called or redeemed during the year;

* $79.7 million of preferred stock was called or redeemed

in July 1999; and

* West Penn revised its Articles of Incorporation to provide greater financial
flexibility.

During 1999, West Penn reacquired all of its outstanding first mortgage bonds.
As a result, the Company incurred an extraordinary charge of $17.0

M-3

<PAGE>
Allegheny Energy, Inc.

million ($10.0 million after taxes) during the fourth quarter of 1999. The
extraordinary charge was the result of premiums paid to reacquire the first
mortgage bonds as compared to the carrying value of the bonds.

In addition, the Company repurchased 12 million shares of its outstanding common
stock for $398.4 million, and Potomac Edison also called $16.4 million of
preferred stock. Potomac Edison also plans to revise its Articles of
Incorporation to provide greater financial flexibility.

Additional Generation In 1999, the Company installed two 44-MW simple-cycle gas
combustion turbines in Springdale Borough in Allegheny County, Pennsylvania, at
a cost of approximately $46 million. These units are unregulated merchant plants
and became operational at the end of 1999. Both run on either No. 2 diesel oil
or natural gas. As part of the installation, existing gas lines were upgraded
and 500,000 gallons of oil storage capacity will be built. Transmission
facilities at the site and the nearby interconnections were also upgraded. The
generation output is being sold into the competitive power markets in the
eastern United States. These combustion turbines will be transferred to
Allegheny Energy Supply in the first quarter of 2000 or as soon thereafter that
the necessary regulatory approval can be obtained from the Securities and
Exchange Commission (SEC).

Allegheny Energy Supply is purchasing additional combustion turbines that will
add 220 MW to our fleet in 2000 at a cost of approximately $120 million. Also,
Allegheny Energy Supply is building a 540-MW combined-cycle generating plant at
Springdale, Pennsylvania, at a cost of $235 million. The new facility will
include two gas-fired combustion turbines and a steam turbine. All are expected
to be operational and providing power for sale into competitive markets in 2003.

Another new project is the anticipated development of a 100-MW generation
project in Warren County in northwestern Pennsylvania. A memorandum of
understanding was signed with Foster Wheeler Power Systems, Inc. (Foster
Wheeler) and United Refining Company (United Refining). The project will include
an upgrade by Foster Wheeler to United Refining's facility in the city of
Warren, Pennsylvania, with the installation of a petroleum coker and associated
equipment.

The generation project, if it is developed as planned, will be co-owned by
Allegheny Energy Supply, Foster Wheeler, and United Refining. It will
incorporate circulating fluidized-bed technology and use waste by-products from
the petroleum coking process in the production of electricity for the refinery
and for sale in the open market. Excess capacity from the generation will be
marketed by Allegheny Energy Supply, and steam produced by the project will be
used by the refinery. Construction expenditures for the entire project are
estimated at up to $300 million, of which Allegheny Energy Supply's share is
estimated at up to $100 million based on the participation of all three
potential co-owners or up to $150 million if one of the other potential co-
owners elects not to participate. Construction is anticipated to begin in early
2001. The memorandum of understanding to develop the facility has been signed by
all the parties, but a satisfactory feasibility study,

M-4

<PAGE>
Allegheny Energy, Inc.

acceptable financing terms and conditions, permitting, and execution of
definitive project agreements are necessary before construction can begin.

Acquisitions In December 1999, Monongahela Power Company (Monongahela Power),
one of the Company's West Virginia subsidiaries, purchased from UtiliCorp United
Inc. headquartered in Kansas City, Missouri, the assets of West Virginia Power,
an electric and natural gas distribution company located adjacent to Monongahela
Power's service territory in southern West Virginia, for approximately $95
million. As part of the transaction, Monongahela Power signed a 20-year option
agreement with UtiliCorp United's subsidiary, Aquila Energy, for gas supply to
Monongahela Power. Electricity is being supplied under an existing contract with
American Electric Power until December 31, 2001, and thereafter will be supplied
from the existing generation of the Company or from the market. Consumers will
benefit from a six-year freeze of natural gas base rates and a three-year freeze
of electric rates, with a reduction in electric rates in 2003 to rates now
offered by Monongahela Power. The acquisition included 26,000 electric and
24,000 natural gas customers, 1,989 miles of electric distribution lines, 670
miles of gas pipelines, and 1,360 square miles of electric and 500 square miles
of gas service territory. West Virginia Power has approximately 120 employees.

In conjunction with the acquisition of West Virginia Power's assets, the Company
purchased for $2.1 million the assets of a heating, ventilation, and air
conditioning business with approximately 10,000 customers and 52 employees.

In December 1999, Allegheny Communications Connect, Inc., the telecommunications
subsidiary of Allegheny Ventures, Inc., purchased for $3.1 million approximately
10% of Genosys Technology Management Inc., a recently formed network operation
center services company. The new enterprise will enable the Company to provide
value-added services, such as around-the-clock network monitoring and
maintenance services, to customers of its growing fiber optic network.

Monongahela Power also plans to purchase Mountaineer Gas Company, a natural gas
sales, transportation, and distribution company serving southern West Virginia
and the northern and eastern panhandles of West Virginia, from Energy
Corporation of America for $323 million (which includes the assumption of
approximately $100 million in existing debt). The planned acquisition also
includes the assets of Mountaineer Gas Services, which operates natural gas-
producing properties, natural gas-gathering facilities, and intrastate
transmission pipelines. Mountaineer Gas has 490 employees, approximately 200,000
residential, commercial, and industrial gas customers, 3,926 miles of gas
pipeline, and 11.7 billion cubic feet of gas storage. The completion of the
transaction is conditioned upon, among other things, the approvals of the Public
Service Commission of West Virginia (W.Va. PSC) and the SEC. The companies
anticipate that regulatory approval could be received by mid-2000.

M-5

<PAGE>
Allegheny Energy, Inc.

PURPA Power Project Terminations On August 26, 1997, and December 3, 1997, West
Penn announced that it had negotiated agreements to buy out and settle disputes
with developers of proposed power plants (the Milesburg and Washington Power
projects) for $15 million and $48 million, respectively, reducing costs over the
proposed 30- and 33-year lives of the projects by an estimated $1.4 billion. The
disputed projects were being developed under the Public Utility Regulatory
Policies Act of 1978 (PURPA) and would have required West Penn to buy 43 MW and
80 MW of capacity and energy, respectively, over the lives of the projects at
prices well above current market price estimates. In 1999, the Company settled
for $5 million litigation by another developer alleging failure by the Company
to comply with PURPA regulations.

Articles of Incorporation As a result of the passage of Maryland legislation
affecting corporate governance of companies incorporated in the state, the Board
of Directors by resolution in July 1999 amended the Company's Articles of
Incorporation. The Board resolution adopted a provision creating three classes
of directors of nearly even size, with the term of each director continuing for
the full initial term of the class to which he or she is designated; a provision
that directors cannot be removed from the Board except by a two-thirds vote of
all votes entitled to be cast by shareholders in an election of directors; that
vacancies may be filled only by the Board and for the full remainder of the
term; and that the number of directors may be fixed only by the Board.

Proposed Merger with DQE, Inc. See Note D to the consolidated financial
statements for information about the proposed merger with DQE, Inc.

Electric Industry Restructuring See Electric Energy Competition on page 38 for
ongoing information regarding electric industry restructuring.

REVIEW OF OPERATIONS
Earnings Summary

<TABLE>
<CAPTION>
Basic and Diluted
Earnings Per
Earnings Average Share
- --------------------------------------------------------------------------------
(Millions of dollars
except per share data) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------
Operations:
<S> <C> <C> <C> <C> <C> <C>
Utility $236.5 $ 283.3 $295.7 $2.03 $ 2.32 $2.42
Nonutility 48.9 (20.3) (14.4) .42 (.17) (.12)
- --------------------------------------------------------------------------------

Consolidated income 285.4 263.0 281.3 2.45 2.15 2.30
before extraordinary
charges
Extraordinary charges, (27.0) (275.4) (.23) (2.25)

M-6

<PAGE>
Allegheny Energy, Inc.

net (Notes B, C, and F to
consolidated financial statements)
- -------------------------------------------------------------------------------
Consolidated net income
(loss) $258.4 $ (12.4) $281.3 $2.22 $ (.10) $2.30
- --------------------------------------------------------------------------------

</TABLE>

The decrease in 1999 earnings from utility operations, before extraordinary
charges, reflects the deregulation of two-thirds of West Penn's electric
generation effective January 1, 1999, as approved by the Pennsylvania PUC's
restructuring order for West Penn. Accordingly, the operating results for these
assets are classified as nonutility in 1999. The 1999 utility operations also
reflect higher operation and maintenance expenses, including the write-off of
$19.7 million of merger-related costs and $16.2 million of costs from a long
dormant pumped-storage generation project. The decrease in 1998 earnings from
utility operations, before extraordinary charges, reflects $23.7 million of
costs, after taxes, related to the Pennsylvania restructuring settlement.

In 1999, earnings from nonutility operations, before extraordinary charges,
increased consolidated net income by $48.9 million, an increase of $69.2 million
over 1998's loss. This increase in nonutility earnings reflects the sale of
generation from two-thirds of West Penn's generation assets into deregulated
markets as discussed under Sales and Revenues and improved results over 1998
performance in such markets. The 1998 increase in the losses from nonutility
operations, before extraordinary charges, resulted from AYP Energy sales
commitments for energy in excess of owned generating capacity which required
settlement by open market purchases during periods of high wholesale prices.
Also contributing to the nonutility losses in 1998 and 1997 were losses of $1.7
million and $1.4 million, respectively, by Allegheny Energy Solutions for its
participation in the Pennsylvania pilot program (see Note B to the consolidated
financial statements for more information about the pilot program).

Extraordinary charges in 1999 and 1998 resulted from the Maryland and
Pennsylvania electric utility restructuring orders as discussed in Notes B and C
to the consolidated financial statements and the redemption of debt by West Penn
in 1999 related to the securitization of stranded costs as discussed in Note F
to the consolidated financial statements.

Earnings per share in 1999 increased $.11 per share due to the Company's common
stock repurchase program.

Sales and Revenues

Total operating revenues for 1999, 1998, and 1997 were as follows:

M-7

<PAGE>

Allegheny Energy, Inc.

OPERATING REVENUES
(Millions of dollars) 1999 1998 1997
- ---------------------------------------------------------------------------------------
Operating revenues:
Utility revenues:
<S> <C> <C> <C>
Regulated $2,168.4 $2,201.2 $2,203.0
Choice 34.3 14.0 2.5
Bulk power 22.5 69.8 39.6
Transmission and other energy services 48.5 45.2 41.1
- ---------------------------------------------------------------------------------------
Total utility revenues 2,273.7 2,330.2 2,286.2
- ---------------------------------------------------------------------------------------

Nonutility revenues:
Retail and other 156.0 31.7 4.9
Bulk power 731.4 215.3 80.9
- ---------------------------------------------------------------------------------------

Total nonutility revenues 887.4* 247.0 85.8
- ---------------------------------------------------------------------------------------

Elimination between utility and nonutility (352.7) (.8) (2.5)
- ---------------------------------------------------------------------------------------
Total operating revenues $2,808.4 $2,576.4 $2,369.5
- ---------------------------------------------------------------------------------------
</TABLE>

*Nonutility operating revenues include $57.1 million in 1999 of allocated
Competitive Transition Charge revenues to compensate for certain transition
costs transferred to nonutility operations.

The decrease in regulated revenues (regulated revenues include revenues from
West Penn customers eligible to choose an alternate energy supplier but electing
not to do so) in 1999 was due primarily to Pennsylvania deregulation, which gave
two-thirds of West Penn's regulated customers the ability to choose another
energy supplier and to a reduction in Potomac Edison's Maryland rates as part of
a settlement agreement. In 1999, 2,522,611 MWh of electric energy was supplied
to West Penn customers by alternative energy suppliers, which represented only
11% of West Penn's total MWh sales. The decrease to regulated revenues was
offset in part by colder winter weather in 1999, which led to increased
residential kilowatt-hour (kWh) sales and revenues. Utility regulated revenues
in 1998 included a $25.1 million rate refund, pursuant to the terms of the
Pennsylvania restructuring settlement agreement. Excluding this rate decrease,
utility regulated revenues increased $23.3 million in 1998, primarily due to
increased kWh sales to commercial and industrial customers. The increase in 1998
was also due to an increase in the number of customers.

Utility choice revenues for 1999 represent transmission and distribution
revenues from West Penn franchised customers (customers in West Penn's
territory) who chose another supplier to provide their energy needs. In 1999,
less than 2% of West Penn's customers chose alternate energy suppliers. The
Company's nonutility supply business had the primary objective of selling the
output from the two-thirds of West Penn's generation that had been freed up

M-8

<PAGE>

Allegheny Energy, Inc.

by the Electricity Generation Customer Choice and Competition Act (Customer
Choice Act) in Pennsylvania.

In 1998 and 1997, the choice revenues represent the 5% of previously fully
bundled customers (full service customers) who participated in the Pennsylvania
pilot program that began November 1, 1997, and continued through December 31,
1998, and were required to buy energy from an alternate supplier. To assure
participation in the pilot program, pilot participants received an energy credit
from their local utility and a price for energy pursuant to an agreement with an
alternate supplier. The credit established by the Pennsylvania PUC was
artificially high to encourage customer shopping, and, as a result, West Penn
incurred a revenue loss of $8.6 million for the pilot. The Pennsylvania PUC has
approved West Penn's pilot compliance filing and thus has indicated its intent
to treat the revenue loss as a regulatory asset.

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

On February 25, 1999, the Virginia SCC approved Potomac Edison's rate reduction
request, which decreased the fuel portion of Virginia customers' bills by
approximately 7.6% (a decrease in annual fuel revenue of about $2.2 million).
The decrease is primarily due to refunding a prior overrecovery of fuel costs,
coupled with a small decrease in projected energy costs. The new rates were
effective with bills rendered on or after March 9, 1999.

On May 21, 1999, the Virginia SCC approved an agreement reached between Potomac
Edison and the staff of the Virginia SCC which reduced base rates for Virginia
customers effective June 1, 1999, by about $3 million annually. The review of
rates is required by an annual information filing in Virginia.

On February 26, 1999, the W.Va. PSC entered an order to initiate a fuel review
proceeding to establish a fuel increment in rates for Potomac Edison and
Monongahela Power to be effective July 1, 1999, through June 30, 2000. The
parties have exchanged proposals which continue to be discussed. If an agreement
is not reached, the proposed fuel rates which would increase Monongahela Power's
fuel rates by $10.9 million and decrease Potomac Edison's fuel rates by $8.0
million will become effective March 15, 2000.

On November 8, 1999, Potomac Edison filed with the Maryland PSC a request to
decrease the fuel portion of Maryland customers' bills by about $6.4 million
annually. The requested decrease is primarily due to greater efficiencies, lower
fuel costs, and increased nonaffiliated generation and transmission sales. The
new fuel rates were effective with bills rendered on or after December 7, 1999,
subject to refund, based on the outcome of proceedings before the Maryland PSC.

On October 27, 1998, the Maryland PSC approved a settlement agreement for
Potomac Edison. Under the terms of that agreement, Potomac Edison increased its
rates $13 million in 1999, will increase its rates an additional $13

M-9

<PAGE>

Allegheny Energy, Inc.

million in 2000, and an additional increase of $13 million will go into
effect in 2001 (a $79 million total revenue increase during 1999 through
2001). The increases are designed to recover additional costs of about $131
million over the 1999 through 2001 period for capacity purchases from the AES
Warrior Run cogeneration project, net of alleged over-earnings of $52 million
for the same period. The net effect of these changes over the 1999 through 2001
time frame results in a pre-tax income reduction of $12 million in 1999, $21
million in 2000, and $19 million in 2001. Also, Potomac Edison will share, on a
50% customer, 50% shareholder basis, earnings above a return on equity of 11.4%
in Maryland for 1999 and 2000. This sharing will occur through an annual
true-up. Potomac Edison's 1999 revenues reflect an estimated obligation for
shared earnings above an 11.4% return on equity.

Utility-related revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy cost adjustment
clauses (fuel clauses) which are still applicable in all Company jurisdictions
served, except for Pennsylvania. Effective July 1, 2000, Potomac Edison's
Maryland jurisdiction will also cease to have a fuel clause under the terms of
the September 23, 1999, settlement agreement. Changes in fuel revenues in
jurisdictions for which a fuel clause continues to exist have no effect on
consolidated net income because increases and decreases in fuel and purchased
power costs and sales of transmission services and bulk power are passed on to
customers by adjustment of customers' bills through fuel clauses.

Effective May 1, 1997, as a result of the Customer Choice Act, West Penn
obtained Pennsylvania PUC authorization to set its fuel clause to zero and to
roll its then-applicable fuel clause rates into base rates. Thereafter, West
Penn assumed the risks and benefits of changes in fuel and purchased power
costs and sales of transmission services and bulk power. Effective July 1,
2000, Potomac Edison will assume similar risks and benefits for its Maryland
jurisdiction.

The 1999 decrease in revenues from utility bulk power was due to the movement of
generation available for sale from regulated utility to nonutility. The 1998
increase in revenues from utility bulk power and transmission and other energy
services sales was due to increased sales that occurred primarily in the second
quarter as a result of warm weather which increased the demand and price for
energy. In 1998, revenues from utility transmission and other energy services
were affected by a revenue refund resulting from a reduction in the Company's
standard transmission rate and rates for ancillary services which were approved
by the Federal Energy Regulatory Commission (FERC). A provision for these rate
reductions was recorded in 1998, with the revenues refunded to customers in the
first quarter of 1999.

Revenues from utility operations transmission and other energy services in 1998
increased, despite decreased transmission services activity. The increase in
revenues was due in part to transmission services reservation charges paid to
the Company by others for the right to transmit energy.

M-10
<PAGE>

Allegheny Energy, Inc.

outages, and transmission constraints. Wholesale prices for electricity rose
from a normal range of $25 to $40 per MWh to as high as $3,500 to $7,000 per
MWh. The potential exists for such volatility to significantly affect the
Company's operating results. The effect may be either positive or negative,
depending on whether the Company's subsidiaries are net buyers or sellers of
electricity during such periods, the open commitments which exist at such times,
and whether the effects of such transactions by the Company's utility
subsidiaries are included in fuel or energy cost recovery clauses in their
respective jurisdictions. The effect of such price volatility in June and July
of 1998 differed between the Company's utility and nonutility subsidiaries, but
was insignificant in total. The effect in 1999 was to measurably increase
earnings in total for the Company even though individual subsidiary experiences
were again diverse.

Nonutility revenues have increased primarily because of bulk power sales to
nonaffiliated companies and new sales in Pennsylvania's competitive marketplace.
The Company's supply business officially began supplying unregulated electricity
to retail customers in Pennsylvania and wholesale customers throughout eastern
North America on January 1, 1999. Allegheny Energy Supply also engages in other
transactions in the unregulated marketplace to sell electricity to both
wholesale and retail customers.

The elimination (see page 32) between utility and nonutility revenues is
necessary to remove the effect of affiliated revenues, primarily sales of power.

See Note B to the consolidated financial statements for information regarding
the Competitive Transition Charge.

OPERATING EXPENSES

Fuel expenses for 1999, 1998, and 1997 were as follows:

Fuel expenses

(Millions of dollars) 1999 1998 1997
- -------------------------------------------------------------
Utility operations $ 355.5 $545.4 $535.7
Nonutility operations 180.2 21.1 24.2
- -------------------------------------------------------------

Total fuel expenses $ 535.7 $566.5 $559.9
- -------------------------------------------------------------

Total fuel expenses decreased 5% in 1999 due to a 7% decrease in average fuel
prices offset by a 2% increase related to kWhs generated. The decrease in fuel
expenses for utility operations and the increase in fuel expenses for nonutility
operations in 1999 were due to the fuel expenses associated with the two-thirds
of West Penn's freed up generation being marketed as part of nonutility
operations.

M-11
<PAGE>

Allegheny Energy, Inc.

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

PURCHASED POWER AND EXCHANGES, NET

(Millions of dollars) 1999 1998 1997
- ------------------------------------------------------------------------------------
Utility operations:
Purchased power:
<S> <C> <C> <C>
From PURPA generation* $ 104.1 $129.0 $134.8
Other 395.8 50.0 41.2
- ------------------------------------------------------------------------------------

Total purchased power for utility operations 499.9 179.0 176.0
Power exchanges, net (2.6) (.7) .3
Nonutility operations purchased power 390.1 210.5 43.5
Elimination (356.0)
- ------------------------------------------------------------------------------------
Purchased power and exchanges, net $ 531.4 $388.8 $219.8
- ------------------------------------------------------------------------------------
*PURPA cost (cents per kWh) .048 .054 .056

</TABLE>

Utility purchased power from PURPA generation decreased $24.9 million in 1999.
This decrease reflects a $11.1 million reduction related to West Penn's purchase
commitment at costs in excess of the market value of the AES Beaver Valley PURPA
contract. This reduction reflects the amortization of the adverse purchased
power commitment reserve recorded in 1998, which is net of the Competitive
Transition Charge revenue recovery in conjunction with deregulation proceedings
in Pennsylvania. The decrease in purchased power also includes a $12.5 million
reduction in the purchase price for that contract due to a scheduled capacity
rate decrease defined annually in the contract. The decrease in utility
purchased power from PURPA generation in 1998 was due primarily to reduced
generation at hydroelectric plants due to river flow. PURPA purchased power
costs may be reduced by $197 million during the period 1999 through 2016 related
to the AES Beaver Valley contract as a result of the 1998 extraordinary charge.
See Notes B and C to the consolidated financial statements for further
information.

The increase in other utility operations purchased power in 1999 was due
primarily to West Penn's purchase of power from its nonutility affiliate,
Allegheny Energy Supply, in order to provide energy to the two-thirds of its
customers eligible to choose an alternate supplier, but who elected not to do
so. The increase in other utility operations purchased power in 1998 resulted
primarily from increased purchases for sales.

An increase in market prices caused by volatility in the spot prices for
electricity at the wholesale level in the second and third quarters of 1998 also
contributed to the increase.

M-12
<PAGE>

Allegheny Energy, Inc.

The increase in nonutility purchases in 1999 was due to increased purchases for
sale to its utility affiliate and to take advantage of transaction opportunities
in the market. The increase in nonutility purchases in 1998 was due primarily to
an increase in volume attributable to AYP Energy's increased participation in
the market.

The elimination as shown on page 34 between utility and nonutility purchased
power is necessary to remove the effect of affiliated purchased power expenses.

The AES Warrior Run PURPA cogeneration contract in Potomac Edison's Maryland
service territory will increase the cost of power purchases by about $60 million
annually. Commencement of operation was scheduled for October 1999. Pre-
commencement testing is not completed. Although AES Warrior Run has until
October 1, 2000, to complete pre-commencement testing, it is anticipated that it
will be in commercial operation in the first quarter of 2000. The Maryland PSC
has approved Potomac Edison's full recovery of the AES Warrior Run purchased
power costs as part of the September 23, 1999, settlement agreement. See Sales
and Revenues starting on page 32 for more information on the settlement
agreement.

Other operation expenses for 1999, 1998, and 1997 were as follows:

OTHER OPERATION EXPENSES

(Millions of dollars) 1999 1998 1997
- -----------------------------------------------------------------
Utility operations $346.7 $319.2 $292.3
Nonutility operations 72.4 18.2 16.7
Elimination (29.7)
- -----------------------------------------------------------------

Total other operation expenses $389.4 $337.4 $309.0
- -----------------------------------------------------------------

The increase in total other operation expenses in 1999 of $52.0 million was due
primarily to recording $19.7 million in merger-related costs previously deferred
and $16.2 million related to a pumped-storage generation project no longer
considered useful, increases in salaries and wages of $8.0 million, $5.0 million
for costs associated with settling litigation concerning a PURPA project, and
increased allowances for uncollectible accounts of $2.1 million. The increase in
utility other operation expenses in 1998 was due primarily to increased expenses
related to competition and the Pennsylvania restructuring order ($24.3 million).
See Note B to the consolidated financial statements for additional information
related to Pennsylvania restructuring. Nonutility other operation expenses
reflect increased business activity.

The elimination between utility and nonutility operation expenses is primarily
to remove the effect of affiliated transmission purchases.

Maintenance expenses for 1999, 1998, and 1997 were as follows:

M-13
<PAGE>

Allegheny Energy, Inc.

MAINTENANCE EXPENSES

(Millions of dollars) 1999 1998 1997
- -----------------------------------------------------------
Utility operations $182.6 $212.3 $227.1
Nonutility operations 40.9 5.3 3.5
- -----------------------------------------------------------
Total maintenance expenses $223.5 $217.6 $230.6
- -----------------------------------------------------------

Total maintenance expenses increased $5.9 million in 1999 due primarily to
increased maintenance and renovations of general plant structures of $5.1
million. The decrease in utility maintenance and the increase in nonutility
maintenance was due to the maintenance associated with the two-thirds of West
Penn generation which is now deregulated and being classified as nonutility
maintenance. The decrease in utility maintenance in 1998 was due primarily to a
management program to postpone such expenses for the year in response to limited
sales growth in the first quarter due to the warm winter weather. The Company
postponed these expenses primarily by extending the time between maintenance
outages and experienced no measurable effect on system performance. The increase
in nonutility maintenance expense in 1998 was primarily related to a 1998
planned outage for maintenance of Unit No. 1 of the Fort Martin Power Station.

Maintenance expenses represent costs incurred to maintain the power stations,
the transmission and distribution (T&D) system and general plant, and to reflect
routine maintenance of equipment and rights-of-way, as well as planned major
repairs and unplanned expenditures, primarily from forced outages at the power
stations and periodic storm damage on the T&D system. Variations in maintenance
expenses 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.

Depreciation and amortization expenses for 1999, 1998, and 1997 were as follows:

DEPRECIATION AND AMORTIZATION EXPENSES

(Millions of dollars) 1999 1998 1997
- -----------------------------------------------------------------------------
Utility operations $198.0 $264.6 $259.1
Nonutility operations 59.5 5.8 6.6
- -----------------------------------------------------------------------------
Total depreciation and amortization expenses $257.5 $270.4 $265.7
- -----------------------------------------------------------------------------

Total depreciation and amortization expenses in 1999 decreased $12.9 million due
primarily to a $24.6 million reduction related to a 1998 write-down of

M-14
<PAGE>

Allegheny Energy, Inc.

West Penn's share of costs in excess of the fair value of the Allegheny
Generating Company (AGC) pumped-storage project. Depreciation expense will be
reduced $234 million during the period 1999 through 2016 from the historical
depreciation amounts as a result of the AGC plant impairment charge recorded
as an extraordinary charge in 1998 by West Penn. Absent this decrease,
depreciation expense would have risen due to increased investment.

Higher utility depreciation in 1998 resulted from increased investment.
In 1999, utility and nonutility depreciation expense reflects the movement of
depreciation expense associated with the two-thirds of West Penn's generation
transferred from utility operations to nonutility operations.

Taxes other than income taxes for 1999, 1998, and 1997 were as follows:

TAXES OTHER THAN INCOME TAXES

(Millions of dollars) 1999 1998 1997
- --------------------------------------------------------------------
Utility operations $157.9 $187.7 $181.4
Nonutility operations 32.4 6.9 5.6
- --------------------------------------------------------------------
Total taxes other than income taxes $190.3 $194.6 $187.0
- --------------------------------------------------------------------

Total taxes other than income taxes decreased $4.3 million in 1999 primarily
due to an adjustment which increased 1998's West Virginia Business and
Occupation Taxes by $1.4 million related to a previous period, lower capital
stock taxes relating to the 1998 asset write-down as a result of Pennsylvania
restructuring, and decreased gross receipts taxes, partially offset by higher
FICA taxes. The increase in total taxes other than income taxes in 1998 was
due primarily to increased West Virginia Business and Occupation Taxes
resulting from an adjustment for a prior period and increased property taxes.
Utility and nonutility taxes other than income taxes reflect the movement of
taxes other than income taxes associated with the two-thirds of West Penn's
generation transferred from utility operations to nonutility operations.

The 1999 decrease in federal and state income taxes of $4.0 million was
primarily due to tax benefits related to plant removal costs, offset in part
by increased taxable income.

Note G to the consolidated financial statements provides a further analysis
of income tax expenses.

The increase in allowance for borrowed funds used during construction of $1.6
million in 1999 reflects an increase in construction activity financed by
short-term debt. The allowance for borrowed funds used during construction
component of the formula receives greater weighting when short-term debt
increases. The decrease in allowance for other than borrowed funds used during
construction of $2.8 million in 1998 reflects lower-cost short-term debt
financing. The decrease also reflects adjustments of prior periods.

M-15
<PAGE>

Allegheny Energy, Inc.

The decrease in other income, net, of $6.6 million in 1999, was primarily due to
a $4.3 million insurance settlement received in 1998. The decrease in other
income, net, of $9.8 million in 1998, was primarily due to 1997 increases for an
interest refund on a tax-related contract settlement ($8.3 million after taxes)
and income on the sale of land ($2.8 million after taxes) offset in part by a
$4.3 million insurance settlement received in 1998.

Interest on long-term debt and other interest for 1999, 1998, and 1997 were as
follows:

INTEREST EXPENSE

(Millions of dollars) 1999 1998 1997
- --------------------------------------------------------------------
Interest on long-term debt:
Utility operations $126.0 $151.0 $162.8
Nonutility operations 29.2 10.1 10.8
- --------------------------------------------------------------------
Total interest on long-term debt 155.2 161.1 173.6
- --------------------------------------------------------------------
Other interest:
Utility operations 27.9 19.4 14.4
Nonutility operations 3.7
- --------------------------------------------------------------------
Total other interest 31.6 19.4 14.4
- --------------------------------------------------------------------

Total interest expense $186.8 $180.5 $188.0
- --------------------------------------------------------------------

The decrease in total interest on long-term debt in 1999 of $5.9 million and in
1998 of $12.5 million resulted from reduced average long-term debt outstanding
and, in 1998, also from lower interest rates.

Other interest expense reflects changes in the levels of short-term debt
maintained by the companies throughout the year, as well as the associated
interest rates. The increase in other interest expense of $12.2 million in 1999
resulted primarily from the increase in short-term debt outstanding in
conjunction with the repurchase of the Company's common stock that began in the
first quarter of 1999.

Dividends on the preferred stock of the subsidiaries decreased due to the
redemption by Potomac Edison and West Penn of their cumulative preferred stock
on September 30, 1999, and July 15, 1999, respectively.

The redemption premiums on preferred stock of the subsidiaries represents the
premiums paid by Potomac Edison and West Penn to retire their cumulative
preferred stock.

M-16
<PAGE>

Allegheny Energy, Inc.

The extraordinary charge in 1999 of $43.9 million ($27.0 million after taxes)
was required to reflect a write-off of $26.9 million ($17.0 million after taxes)
of certain disallowances in the Maryland PSC's December 1999 order and $17.0
million ($10.0 million after taxes) for the difference between the reacquisition
price and the net carrying amount of first mortgage bonds repurchased with
proceeds from the sale of transition bonds as a result of the deregulation
process in Pennsylvania. The extraordinary charge in 1998 of $466.9 million
($275.4 million after taxes) was required to reflect a write-off of certain
disallowances in the Pennsylvania PUC's May and November 1998 orders. See Notes
B, C, and F to the consolidated financial statements for additional information.

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

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

Capital expenditures, primarily construction, of all of the subsidiaries in 1999
were $413 million and, for 2000 and 2001, are estimated at $419 million and $431
million, respectively. In addition, in 1999 Monongahela Power acquired the
assets of West Virginia Power for approximately $95 million, and, in 2000,
Monongahela Power also plans to purchase Mountaineer Gas Company for
approximately $323 million (which includes the assumption of approximately $100
million in existing debt). The 2000 and 2001 estimated expenditures include $115
million and $136 million, respectively, for construction of environmental
control technology. Future nonutility construction expenditures will reflect
additions of generating capacity to sell into deregulated markets. It is the
Company's goal to constrain future utility construction spending to the
approximate level of depreciation currently in rates. As described under
Environmental Issues starting on page 40, the subsidiaries could potentially
face significant mandated increases in construction expenditures and operating
costs related to environmental issues. Whether the regulated utility
subsidiaries can continue to meet the majority of their construction needs with
internally generated cash is largely dependent upon the outcome of these issues.
The subsidiaries also have additional capital requirements for debt maturities
(see Note M to the consolidated financial statements).

Internal Cash Flow

Internal generation of cash, consisting of cash flows from operations reduced by
dividends, was $415 million in 1999, compared with $381 million in 1998. Current
rate levels and reduced levels of construction expenditures permitted

M-17
<PAGE>

Allegheny Energy, Inc.

the utility subsidiaries to finance all of their construction expenditures
in 1999 and 1998 with internal cash flow.

Dividends paid on common stock in each of the years 1999 and 1998 were $1.72
per share. The dividend payout ratio in 1999 of 64.6%, excluding the
extraordinary and other charges, decreased from the 73.5% ratio in 1998,
excluding the extraordinary charge and the Pennsylvania settlement costs.

Financing The Company did not issue any common stock in 1999 or 1998. The
Company began a stock repurchase program in 1999 to repurchase common stock
worth up to $500 million from time to time at price levels the Company deems
attractive. The Company repurchased 12 million shares of its common stock in
1999 at an aggregate cost of $398.4 million (an average cost of $33.20 per
share). The shares for its Dividend Reinvestment and Stock Purchase Plan,
Employee Stock Ownership and Savings Plan, Restricted Stock Plan for Outside
Directors, and Performance Share Plan were purchased on the open market.

Short-term debt is used to meet temporary cash needs and increased $382.3
million to $641.1 million in 1999. At December 31, 1999, unused lines of
credit with banks were $435 million.

The Company and its subsidiaries anticipate meeting their 2000 cash needs
through internal cash generation, cash on hand, short-term borrowings as
necessary, external financings, and by issuing debt to refinance maturing
first mortgage bonds. In 1999, West Penn issued $600 million of transition
bonds with varying average lives ranging from one to eight years with a
weighted average cost of 6.887% to "securitize" transition costs related
to its restructuring settlement described in Note B to the consolidated
financial statements. During 1999, West Penn reacquired all of its outstanding
$525 million of first mortgage bonds.

West Penn called or redeemed all outstanding shares of its cumulative preferred
stock with a combined par value of $79.7 million plus redemption premiums of
$3.3 million on July 15, 1999, with proceeds from new $84-million five-year
unsecured medium-term notes issued in the second quarter at a 6.375% coupon
rate. Potomac Edison called all outstanding shares of its cumulative preferred
stock with a combined par value of $16.4 million plus redemption premiums of $.5
million on September 30, 1999, with funds on hand. The redemption of the
preferred stock allowed West Penn to revise its Articles of Incorporation,
providing greater financial flexibility in restructuring debt. Potomac Edison
also plans to revise its Articles of Incorporation.

In April 1999, Monongahela Power, Potomac Edison, and West Penn issued $7.7
million, $9.3 million, and $13.83 million, respectively, of 5.50% 30-year
pollution control revenue notes to Pleasants County, West Virginia. In December
1999, Monongahela Power issued $110 million of 7.36% unsecured medium-term
notes, due in January 2010, in part to finance the purchase of West Virginia
Power.

M-18
<PAGE>

Allegheny Energy, Inc.

In October 1999, AYP Energy prepaid $30 million of its bank loan, reducing the
obligation from $160 million to $130 million. In December 1999, the $130 million
debt obligation was assigned to Allegheny Energy Supply.

The Company's and West Penn's aggregate limit of short-term debt financing was
increased in accordance with SEC authorization on May 19, 1999, and October 8,
1999, respectively. The Company's limit increased from $400 million to $750
million through December 31, 2007, to enhance its ability to participate in
evolving energy markets resulting from deregulation and, upon application and
approval, to support acquisition and diversification plans. West Penn's limit
increased from $182 million to $500 million through December 31, 2001, related
to meeting the requirements of restructuring in Pennsylvania.

The long-term debt due within one year at December 31, 1999, of $189.7 million
represents $65 million of Monongahela Power 5-5/8% first mortgage bonds due
April 1, 2000, $75 million of Potomac Edison 5-7/8% first mortgage bonds due
March 1, 2000, and $49.7 million of West Penn Funding, LLC, transition bonds
due on various dates. The transition bonds are supported by an Intangible
Transition Charge (ITC) that replaces a portion of the Competitive Transition
Charge customers pay. The proceeds from the ITC will be used to pay the
principal and interest on these transition bonds, as well as other associated
expenses.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition The electricity supply segment of the electric
utility industry in the United States is becoming increasingly competitive. The
national Energy Policy Act of 1992 deregulated the wholesale exchange of power
within the electric industry by permitting the FERC to compel electric utilities
to allow third parties to sell electricity to wholesale customers over their
transmission systems. Since 1992, the wholesale electricity market has become
more competitive as companies are engaging in nationwide power trading. In
addition, an increasing number of states have taken active steps toward allowing
retail customers the right to choose their electricity supplier. The Company has
been an advocate of federal legislation to create competition in the retail
electricity markets to avoid regional dislocations and ensure level playing
fields. Legislation before the U.S. Congress to restructure the nation's
electric utility industry cleared an important hurdle on October 28, 1999, when
a House Commerce Committee subcommittee gave its approval to a bill. The bill
will now move on to the full Commerce Committee, where it will be considered in
2000.

In the absence of federal legislation, state-by-state implementation of
deregulation of electric generation is under way. The five states in which the
Company's utility operating companies serve customers are at various stages of
implementation or investigation of programs that allow customers to choose their
electric supplier. Pennsylvania is furthest along with a retail program in
place, while Maryland, Ohio, and Virginia passed legislation in 1999 to
implement retail choice. West Virginia continues to actively study

M-19
<PAGE>

Allegheny Energy, Inc.

this issue. On December 23, 1999, the Maryland PSC approved a settlement
agreement for Potomac Edison to implement generation competition in Maryland.

Activities at the Federal Level The Company continues to seek enactment of
federal legislation to bring choice to all retail electric customers, deregulate
the generation and sale of electricity on a national level, and create a more
liquid, free market for electric power. Fully meeting challenges in the emerging
competitive environment will be difficult for the Company unless certain
outmoded and anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 (Mandatory Purchase Provisions) of
PURPA, are repealed or significantly revised. The Company continues to advocate
the repeal of PUHCA and Section 210 of PURPA on the grounds that they are
obsolete and anti-competitive and that PURPA results in utility customers paying
above-market prices for power. H.R. 2944, which was sponsored by U.S.
Representative Joe Barton, was favorably reported out of the House Commerce
Subcommittee on Energy and Power. While the bill does not mandate a date certain
for customer choice, several key provisions favored by the Company are included
in the legislation, including an amendment that allows existing state
restructuring plans and agreements to remain in effect. Other provisions address
important Company priorities by repealing PUHCA and the mandatory purchase
provisions of PURPA. Consensus remains elusive, with significant hurdles
remaining in both houses of Congress. It is too early to tell whether momentum
on the issue will result in legislation in 2000.

Maryland Activities On April 8, 1999, Maryland Governor Glendening signed the
legislation that will bring competition to Maryland's electric generation
market, beginning July 1, 2000. The Maryland PSC is in the process of
implementing the new law. Final Electric Restructuring Roundtable reports were
filed with the Maryland PSC on May 3, 1999, and legislative-style hearings were
held last summer on the reports. The Company filed testimony in Maryland's
investigation into transition costs, price protection, and unbundled rates, and
a consensus settlement agreement was achieved with no protest by any of the
parties participating in the negotiations. The agreement was filed on September
23, 1999, and a hearing before the Commission was held on October 14, 1999. On
December 23, 1999, the Maryland PSC issued an order approving the settlement.
Potomac Edison filed an application on December 15, 1999, to transfer its
Maryland generating assets at book value to an affiliate under Section 7-508 of
the Electric Customer Choice and Competition Act of 1999. A Maryland PSC
decision approving the transfer of the generating assets is due by July 1, 2000.

See Note B to the consolidated financial statements for additional information
related to Maryland restructuring.

Ohio Activities On June 22, 1999, the Ohio General Assembly passed legislation
to restructure its electric utility industry. Governor Taft added his signature
soon thereafter, and all of the state's customers will be able to choose their

M-20
<PAGE>

Allegheny Energy, Inc.

electricity supplier starting January 1, 2001, beginning a five-year transition
to market rates. Total electric rates will be frozen over that period, and
residential customers are guaranteed a 5% cut in the generation portion of their
rate. The determination of stranded cost recovery will be handled by the Public
Utilities Commission of Ohio (Ohio PUC). On January 3, 2000, Monongahela Power
filed a transition plan with the Ohio PUC, including its claim for recovery of
stranded costs of $21.3 million. The Ohio PUC is expected to hold hearings on
Monongahela Power's transition plan filing and issue a decision by October 2000.

The Ohio legislation stipulates that an entity independent of the utilities
shall own or control transmission facilities after the start of competitive
retail electric service on January 1, 2001, but not later than December 31,
2003. Customer protections were kept intact with a low-income assistance plan
and a one-time forgiveness of past debts for low-income and handicapped
customers. In regard to renewable energy, the bill requires that electric
generators purchase excess electricity from small businesses and homes using
renewable energy sources.

Pennsylvania Activities In December 1996, Pennsylvania enacted the Customer
Choice Act to restructure its electric industry to create retail access to a
competitive electric energy supply market. Approximately 45% of the Company's
retail revenues were from its Pennsylvania subsidiary, West Penn. On May 29,
1998 (as amended on November 19, 1998), the Pennsylvania PUC granted final
approval to West Penn's restructuring plan. As of January 2, 2000, all
electricity customers in Pennsylvania had the right to choose their electric
suppliers. Two-thirds of all retail customers had a choice throughout 1999, the
first year of retail choice following a pilot program. The number of customers
who have switched suppliers and the amount of electrical load transferred in
Pennsylvania far exceed that of any other state so far. However, for the
Company, only about 12,700 of its 656,000 Pennsylvania customers eligible to
shop in 1999 have chosen an alternate energy supplier. The Company has retained
about 98% of its Pennsylvania customers through December 31, 1999. More than 100
electric generation suppliers have been licensed to sell to retail customers in
Pennsylvania. See Notes B and C to the consolidated financial statements for
additional information related to Pennsylvania restructuring.

Virginia Activities On March 25, 1999, Governor Gilmore signed the Virginia
Electric Utility Restructuring Act (Restructuring Act) passed by the Virginia
General Assembly. All utilities must submit a restructuring plan by January 1,
2001, to be effective on January 1, 2002. Customer choice will be phased in
beginning on January 1, 2002, with full customer choice by January 1, 2004. The
Legislative Transition Task Force on Electric Utility Restructuring, which was
established by the Restructuring Act to oversee the implementation of customer
choice, held hearings in the summer and fall of 1999 on a number of issues
concerning the implementation of retail competition in Virginia. Parties have
also been working with the Virginia SCC Staff to develop the

M-21
<PAGE>

Allegheny Energy, Inc.

rules governing the proposed retail pilot programs of other utilities in
the state.

West Virginia Activities

In March 1998, legislation was passed by the West Virginia Legislature that
directed the W.Va. PSC to meet with all interested parties to develop a
restructuring plan which would meet the dictates and goals of the legislation.
Interested parties formed a Task Force that met during 1998, but the Task
Force was unable to reach a consensus on a model for restructuring. The W.Va.
PSC held hearings in August 1999 that addressed certification, licensing,
bonding, reliability, universal service, consumer protection, code of conduct,
subsidies, and stranded costs. The W.Va. PSC on December 20, 1999, released
for comment and hearings a modified version of a proposal submitted by members
of the Task Force, including Monongahela Power and Potomac Edison, following
the August 1999 hearings that could open full retail competition as early as
January 1, 2001. The production of power would be deregulated and electricity
rates would be frozen for four years with rates gradually transitioning to
market rates over the six years thereafter. After hearings in January 2000,
the W.Va. PSC submitted a restructuring plan endorsed by members of the Task
Force, including Monongahela Power and Potomac Edison, to the Legislature
for approval.

Accounting for the Effects of Price Deregulation In July 1997, the Emerging
Issues Task Force (EITF) of the FASB released Issue No. 97-4, "Deregulation of
the Pricing of Electricity-Issues Related to the Application of FASB Statement
Nos. 71 and 101," which concluded that utilities should discontinue application
of SFAS No. 71 for the generation portion of their business when a deregulation
plan is in place and its terms are known. In accordance with guidance of EITF
Issue No. 97-4, the Company has discontinued the application of SFAS No. 71 to
its electric generation business in Pennsylvania and Maryland. The legislation
passed in Ohio and Virginia established definitive processes for transition to
deregulation and market-based pricing for electric generation. However, the
deregulation plans and their terms in Ohio and Virginia will not be known until
relevant regulatory proceedings are complete and final orders are received. The
Company is unable to predict the effect of discontinuing SFAS No. 71 in Ohio and
Virginia, but it may be required to write off unrecoverable regulatory assets,
impaired assets, and uneconomic commitments. Also, the Company is unable to
predict the outcome of the deregulation process in West Virginia until further
actions are taken by the Legislature and the W.Va. PSC.

Environmental Issues In the normal course of business, the subsidiaries are
subject to various contingencies and uncertainties relating to their operations
and construction programs, including legal actions and regulations and
uncertainties related to environmental matters.

M-22
<PAGE>

Allegheny Energy, Inc.

estimates that its banked emission allowances will allow it to comply with Phase
II sulfur dioxide (SO2) limits through 2005. Studies to evaluate cost-effective
options to comply with Phase II emission limits beyond 2005, including those
available in connection with the emission allowance trading market,
are continuing.

Title I of the CAAA established an Ozone Transport Commission to ascertain
additional nitrogen oxides (NOx) reductions to allow the Ozone Transport Region
(OTR) to meet the ozone National Ambient Air Quality Standards (NAAQS). Under
terms of a Memorandum of Understanding (MOU) among the OTR states, the
subsidiaries' generating stations located in Maryland and Pennsylvania were
required to reduce NOx emissions by approximately 55% from the 1990 baseline
emissions, with a compliance date of May 1999. Further reductions of 75% from
the 1990 baseline may be required by May 2003 under Phase III of the MOU.
However, this reduction will most likely be superceded by the proposed NOx State
Implementation Plan (SIP) call rule discussed below. If reductions of 75% are
required, installation of post-combustion control technologies would be very
expensive. Pennsylvania and Maryland promulgated regulations to implement Phase
II of the MOU in November 1997 and May 1998, respectively. However, as a result
of litigation, the Maryland regulation was revised to postpone compliance to May
2000.

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

M-23
<PAGE>

Allegheny Energy, Inc.

final approval of four of the petitions. The Section 126 petition rulemaking is
also under litigation.

The EPA is required by law to regularly review the NAAQS for criteria
pollutants. Recent court orders in litigation by the American Lung Association
have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and
NOx standards. Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997. However, the revised standards
were legally challenged, and, in May 1999, the District of Columbia Circuit
Court of Appeals remanded the revised standards back to the EPA for further
consideration. Also, in May 1999, the EPA promulgated final regional haze
regulations to improve visibility in Class I federal areas (national parks and
wilderness areas). If eventually upheld in court, subsequent state regulations
could require additional reduction of SO2 and/or NOx emissions from the
subsidiaries' facilities. The effect on the Company of revision to any of these
standards or regulations is unknown at this time, but could be substantial.

The final outcome of the revised ambient standards, Phase III of the MOU, SIP
call rule, and Section 126 petitions cannot be determined at this time. All are
being challenged by rulemaking, petition, and/or the litigation process.
Implementation dates are also uncertain at this time, but could be as early as
2003, which would require substantial capital expenditures in the 2000 through
2003 period. The Company's construction forecast includes the expenditure of
$358 million of capital costs during the 2000 through 2003 period to comply with
the SIP call. In addition, $12 million was spent in 1999.

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

M-24
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Allegheny Energy, Inc.

scale reduction in the use of fossil fuels. The Company will continue to explore
cost-effective opportunities to improve efficiency and performance.

The Company actively participates in climate-related research programs and is
responsive to the voluntary guidelines suggested in the national Energy Policy
Act of 1992, under Section 1605(b), directed toward reducing, controlling,
avoiding, and sequestering greenhouse gases. The Company has taken many concrete
steps to reduce greenhouse gases and help stimulate a business climate that
encourages improved efficiency, performance, electrical loss reductions, and
cost-effectiveness.

The EPA had identified Monongahela Power, Potomac Edison, and West Penn as
potentially responsible parties, along with approximately 175 others, in a
Superfund site subject to cleanup. A final determination has not been made for
the Company's share of the remediation costs based on the amount of materials
sent to the site. Monongahela Power, Potomac Edison, and West Penn have also
been named as defendants along with multiple other defendants in pending
asbestos cases involving one or more plaintiffs. The Company believes that
provisions for liability and insurance recoveries are such that final resolution
of these claims will not have a material effect on its financial position (see
Note P to the consolidated financial statements for additional information).

On Earth Day 1997, President Clinton announced the expansion of the federal
Emergency Planning and Community Right-to-Know Act (RTK) reporting to include
electric utilities, limited to facilities that combust coal and/or oil for the
purpose of generating power for distribution in commerce. The purpose of RTK is
to provide site-specific information on chemical releases to the air, land, and
water. On June 4, 1999, the Company joined with other members of the Edison
Electric Institute in reporting power station releases to the public. Packets of
information about the Company's releases were provided to the news media in the
Company's service area and posted on the Company's web site. The Company filed
its first RTK-related report with the EPA in advance of the July 1, 1999,
deadline, reporting 18 million pounds of total releases for calendar year 1998.

The Attorney General of the State of New York and the Attorney General of the
State of Connecticut in their letters dated September 15, 1999, and November 3,
1999, respectively, notified the Company of their intent to commence civil
actions against the Company and/or its subsidiaries alleging violations at the
Fort Martin Power Station under the federal Clean Air Act, which requires
existing power plants that make major modifications to comply with the same
emission standards applicable to new power plants. Similar actions may be
commenced by other governmental authorities in the future. Fort Martin is a
station located in West Virginia and is now jointly owned by Allegheny Energy
Supply, Monongahela Power, and Potomac Edison. Both Attorneys General stated
their intent to seek injunctive relief and penalties. In addition, the Attorney
General of the State of New York in his letter indicated that he may assert
claims under the State common law of public nuisance seeking to recover, among
other things, compensation for alleged environmental damage caused in New York
by the operation of Fort Martin Power Station. At this time, the Company and its
subsidiaries are not able to determine what effect,

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Allegheny Energy, Inc.

if any, these actions threatened by the Attorneys General of New York and
Connecticut may have on them.

Regional Transmission Organization In adopting its Rule 2000, the FERC defined
requirements for transmission facility owners to participate in some form of
Regional Transmission Organization. Additionally, the state jurisdictions within
which the Company operates have, to different degrees, started to define their
transition to a competitive marketplace. As part of this, they have identified
transmission as a key link to making the electricity market efficient. The
nature of this issue is at least regional in scope. As a result, any solution
will need to be one that satisfies a diverse group of stakeholders. The Company
has actively participated in this debate and continues to evaluate the available
options to provide its customers with the most reliable, cost-effective service
while maintaining a clear focus on the financial interests of its shareholders.

Energy Risk Management The Company is exposed through one of its nonutility
subsidiaries, Allegheny Energy Supply, to a variety of commodity-driven risks
associated with energy trading activities. Market risk arises from the potential
for changes in the value of energy related to price and volatility of the
market. These risks are reduced by using the Company's generation assets to back
positions on physical transactions. Credit risk represents the potential loss
that the Company would incur as a result of non-performance by counterparties in
honoring their contractual commitments. These risks can influence earnings, cash
flows, and the ability to provide value to shareholders.

The Company has a Corporate Energy Risk Control Policy adopted by the Board of
Directors and monitored by an Exposure Management Committee of senior
management. An independent risk management function is responsible for insuring
compliance with the Policy. A value at risk model is used to measure the market
exposure resulting from trading activities. Value at risk is a statistical model
that attempts to predict risk of loss based on historical market price and
volatility data over a given period of time. The credit standing of
counterparties is established through the evaluation of the prospective
counterparty's financial condition, specified collateral requirements where
deemed necessary, and the use of standardized agreements which facilitate the
netting of cash flows associated with a single counterparty. Financial
conditions of existing counterparties are monitored on an ongoing basis. Market
exposure and credit risk have established aggregate and counterparty limits that
are monitored within the guidelines of the Company's Energy Risk Control Policy.

Fort Martin Power Station Unit No. 1, a stand-alone unit owned by an unregulated
subsidiary, AYP Energy, was transferred to Allegheny Energy Supply. Transfer of
this generation asset mitigates the trading risk that exists with a single
generating unit.

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Allegheny Energy, Inc.

Derivative Instruments and Hedging Activities In June 1998, the FASB issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The Company will be required to recognize derivatives as defined by SFAS No. 133
on the balance sheet at fair value. The Company is evaluating the effect of
adopting SFAS No. 133 on its results of operations and financial position which
will be completed during the year 2000. Accounting for changes in the fair value
of a derivative depends on the intended use of the derivative and whether the
instrument meets the requirements for designation as a hedge. The Company
expects to adopt SFAS No. 133 no later than January 1, 2001.

M-27

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Monongahela Power Company

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

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including ongoing state and federal activities; developments in
the legislative and regulatory environments in which the Company
operates, including regulatory proceedings affecting rates
charged by the Company; environmental, legislative, and
regulatory changes; future economic conditions; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power and fuel for electric generation, unscheduled maintenance
or repair requirements, weather, and compliance with laws and
regulations.

Business Strategy

A component of the deregulation plans sponsored by the Company in
West Virginia and Ohio is the authority to transfer electric
generation assets at net book value to an unregulated affiliate.
Subject to the approval of the deregulation plans by the West
Virginia legislature and the Public Utilities Commission of Ohio
(Ohio PUC), the Company plans to transfer its generation assets
to Allegheny Energy Supply Company, LLC (Allegheny Energy
Supply). Allegheny Energy Supply is a subsidiary of Allegheny
Energy, Inc. (Allegheny Energy), the Company's Parent.

The settlement agreement in Pennsylvania permitted the Company's
affiliate, West Penn Power Company (West Penn), to transfer 3,778
megawatts (MW) of generating capacity at net book value to
Allegheny Energy Supply in 1999.
The recent settlement in Maryland will allow approximately 1,300
MW of additional generating capacity to be transferred at net
book value in 2000. Allegheny Energy is seeking to transfer the
remaining generating assets in Ohio, Virginia, and West Virginia
to its unregulated subsidiary at book value in deregulation
proceedings in these jurisdictions. The unregulated electric
supply is being sold in both the wholesale and retail competitive
marketplaces, allowing greater earnings growth potential, subject
to market risk, while allowing Allegheny Energy to capitalize on
its strengths in the generation business.

Following the transfer of generation assets to Allegheny Energy
Supply, the Company will be part of Allegheny Energy's delivery
business (wires and

M-28
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Monongahela Power Company

pipes). The delivery business will remain an important part of
Allegheny Energy's business which Allegheny Energy plans to expand.

SIGNIFICANT EVENTS IN 1999, 1998, AND 1997

Acquisitions

In December 1999, the Company purchased from UtiliCorp United
Inc. headquartered in Kansas City, Missouri, the assets of West
Virginia Power, an electric and natural gas distribution company
located adjacent to the Company's service territory in southern
West Virginia, for approximately $95 million. As part of the
transaction, the Company signed a 20-year option agreement with
UtiliCorp United's subsidiary, Aquila Energy, for gas supply to
the Company. Electricity is being supplied under an existing
contract with American Electric Power until December 31, 2001,
and thereafter will be supplied from the existing generation of
Allegheny Energy or from the market. Consumers will benefit from a
six-year freeze of natural gas base rates and a three-year freeze
of electric rates, with a reduction in electric rates in 2003 to
rates now offered by the Company. The acquisition included
26,000 electric and 24,000 natural gas customers, 1,989 miles of
electric distribution lines, 670 miles of gas pipelines, and
1,360 square miles of electric and 500 square miles of gas
service territory. West Virginia Power had approximately 120
employees.

In conjunction with the acquisition of West Virginia Power's
assets, Allegheny Energy purchased for $2.1 million the assets of
a heating, ventilation, and air conditioning business with
approximately 10,000 customers and 52 employees.

The Company also plans to purchase Mountaineer Gas Company, a
natural gas sales, transportation, and distribution company
serving southern West Virginia and the northern and eastern
panhandles of West Virginia, from Energy Corporation of America
for $323 million (which includes the assumption of approximately
$100 million in existing debt). The planned acquisition also
includes the assets of Mountaineer Gas Services, which operates
natural gas-producing properties, natural gas-gathering
facilities, and intrastate transmission pipelines. Mountaineer
Gas has 490 employees, approximately 200,000 residential,
commercial, and industrial gas customers, 3,926 miles of gas
pipeline, and 11.7 billion cubic feet of gas storage. The
completion of the transaction is conditioned upon, among other
things, the approvals of the Public Service Commission of West
Virginia (W.VA. PSC) and the Securities and Exchange Commission
(SEC). The companies anticipate that regulatory approval could
be received by mid-2000.

PURPA Power Project Termination

In 1999, the Company settled for $2.3 million litigation by a
developer alleging failure by the Company to comply with the
Public Utility Regulatory Policies Act of 1978 (PURPA) regulations.

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Monongahela Power Company

Electric Industry Restructuring

See Electric Energy Competition on page 8 for ongoing information
regarding electric industry restructuring.

REVIEW OF OPERATIONS

Earnings Summary

(Millions of Dollars) 1999 1998 1997
Net Income............................... $92.3 $82.4 $80.5

The increase in 1999 earnings resulted, in part, from increased
retail kilowatt-hour (kWh) sales, including increased sales to
residential customers due to winter weather that was cooler than
the relatively warm winter of 1998, as measured by heating degree
days. The increase is also due to a 1999
decrease in federal and state income taxes of $9.0 million
primarily due to the Company's share of tax savings in
consolidation related to its parent, Allegheny Energy, and to a
net change in income tax provisions related to prior years. The
1998 increase in earnings resulted from increased kWh sales to
commercial and industrial customers and from reduced power
station operations and maintenance spending.

Sales and Revenues

Percentage changes in revenues and kWh sales in 1999 and 1998 by
major retail customer classes were:

1999 vs. 1998 1998 vs. 1997
Revenues kWh Revenues kWh

Residential................. 4.9% 4.6% 0.5% (0.3)%
Commercial.................. 2.8 2.2 6.4 5.8
Industrial.................. 4.4 4.1 6.0 5.5
Total..................... 4.2% 3.8% 4.0% 4.0 %

The 1999 increase in residential kWh sales, which are more
weather sensitive than the other classes, was due primarily to
changes in customer usage because of weather conditions, and to a
lesser extent, growth in the number of customers. Colder winter
weather in 1999 led to the increased residential KWh sales and
revenues. The growth in the number of residential customers was
.8% and .6% in 1999 and 1998, respectively.

Commercial kWh sales are also affected by weather, but to a
lesser extent than residential. The 2.2% and 5.8% increases in
1999 and 1998, respectively, reflect growth in the number of
customers and increased usage. The increase in industrial kWh
sales in 1999 was due to increased kWh sales to iron and steel
customers and to paper and printing product customers. The
increase in industrial kWh sales in 1998 was primarily due to
increased sales

M-30
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Monongahela Power Company

to one of the Company's customers who switched an
additional portion of their load requirements to the Company in
September 1997.

On February 26, 1999, the W.Va. PSC entered an order to initiate
a fuel review proceeding to establish a fuel increment in rates
for the Company and its affiliate, The Potomac Edison Company, to
be effective July 1, 1999, through June 30, 2000. The parties
have exchanged proposals which continue to be discussed. If an
agreement is not reached, the proposed fuel rates which would
increase the Company's fuel rates by $10.9 million will become
effective March 15, 2000.

Changes in revenues from retail customers resulted from the
following:

Changes from Prior Year
(Millions of Dollars) 1999 vs. 1998 1998 vs. 1997

Fuel clauses............................... $ 9.4 $11.8
All other.................................. 13.2 8.7
Net change in retail revenues............ $22.6 $20.5

Revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy
cost adjustment clauses (fuel clauses) which have little effect
on net income because increases and decreases in fuel and
purchased power costs and sales of transmission services and bulk
power are passed on to customers by adjustment of customers'
bills through fuel clauses. The Company expects that the fuel
clause rates in Ohio and West Virginia will cease as these states
implement customer choice. The Company will then assume the
risks and benefits of changes in fuel and purchased power costs
and sales of transmission services and bulk power.

All other is the net effect of kWh sales changes due to changes
in customer usage (primarily weather for residential customers),
growth in the number of customers, and changes in pricing other
than changes in general tariff and fuel clause rates. The
increases in 1999 and 1998 all other retail revenues were
primarily the result of increased customer usage and growth in
the number of customers.

Wholesale and other revenues were as follows:

(Millions of Dollars) 1999 1998 1997

Wholesale customers...................... $ 4.6 $ 5.2 $ 4.9
Affiliated companies..................... 84.7 77.3 83.6
Street lighting and other................ 6.9 6.9 7.1
Total wholesale and other revenues..... $96.2 $89.4 $95.6

M-31
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Monongahela Power Company

services. All of the Company's wholesale customers have signed
contracts to remain as customers until November 30, 2003.

Revenues from affiliated companies represent sales of energy and
intercompany allocations of generating capacity, generation
spinning reserves, and
transmission services pursuant to a power supply agreement among
the Company and the other regulated utility subsidiaries of
Allegheny Energy. The 1999 increase of $7.4 million in
affiliated revenues was due to increased energy sales to
affiliates. As a result of increased generation at one of the
Company's power stations in 1999, the Company had more generation
available for sale after meeting the needs of its regular
customers. Some of this excess generation was sold to affiliates
to meet their needs. The affiliated

revenue decrease in 1998 resulted primarily from decreased
generating capacity sales.

Bulk power transactions include sales of bulk power and
transmission and other energy services to power marketers and
other utilities. Bulk power and transmission and other energy
services sales for 1999, 1998, and 1997 were as follows:

1999 1998 1997
KWh Transactions (in billions):
Bulk power............................... .2 .3 .3
Transmission and other energy services
to nonaffiliated companies............. 2.1 1.9 3.0
Total................................ 2.3 2.2 3.3
Revenues (in millions):
Bulk power............................... $ 6.6 $ 8.5 $ 7.3
Transmission and other energy services
to nonaffiliated companies............. 12.0 11.3 10.0
Total................................ $18.6 $19.8 $17.3

Revenues from bulk power transactions decreased in 1999 due to
decreased sales to power marketers and other utilities. The 1998
increase in revenues from bulk power was due to increased sales
that occurred primarily in the second quarter as a result of warm
weather which increased the demand and price for energy.

Revenues from transmission and other energy services in 1999 and
1998 increased $.7 million and $1.3 million, respectively.
Revenues from transmission and other energy services increased in
1999 due primarily to increased megawatt-hours (MWh) transmitted.
The increase in 1998 revenues, despite decreased transmission
services activity, was due to transmission services' reservation
charges paid to the Company by others for the right to transmit
energy. Transmission services activity was affected as a result
of some of the reservations to transmit energy not being used. In
1998, revenues from transmission and other energy services were
affected by a revenue refund resulting from a reduction in the
Company's standard transmission rate and rates for ancillary
services which were approved by the FERC. A provision
of $1.7 million for these rate reductions was recorded in 1998,
with revenues refunded to customers in the first quarter of 1999.

In June and July 1999 and June and July 1998, certain events
combined to produce significant volatility in the spot prices for
electricity at the

M-32
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Monongahela Power Company

wholesale level. These events included
extremely hot weather, generation unit outages, and transmission
constraints. Wholesale prices for electricity rose from a normal
range of $25 to $40 per MWh to as high as $3,500 to $7,000 per
MWh. The costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to the
fuel and energy cost recovery clauses may be positive or
negative, depending on whether the Company is a net buyer or
seller of electricity during such periods. The effect of such
price volatility in June and July of 1999 and 1998 was
insignificant to the Company because changes are passed through
to customers through operation of fuel clauses. The Company
expects that the fuel clause rates in Ohio and West Virginia will
cease as these states implement customer choice. The company will
then assume the risks and benefits of changes in fuel and purchased
power costs and sales of transmission services and bulk power.

Operating Expenses

Fuel expenses increased .9% in 1999 due to an 8.9% increase
related to kWhs generated, offset in part by an 8% decrease in
average fuel prices. The increase in kWhs generated was to meet
retail customer requirements and increased sales to affiliates.
The decrease in average fuel prices was due to renegotiated fuel
contracts. The 1.9% increase in fuel expenses in 1998 was due
primarily to an increase in kWhs generated.

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

(Millions of Dollars) 1999 1998 1997

Nonaffiliated transactions:
Purchased power:
From PURPA generation*................ $65.1 $65.5 $69.8
Other................................. 15.1 11.6 9.6
Power exchanges, net.................... (.6) (.2) .1
Affiliated transactions:
AGC capacity charges.................... 19.1 18.4 18.5
Energy and spinning reserve charges..... .1 .3 .3
Purchased power and exchanges, net.... $98.8 $95.6 $98.3

*PURPA cost (cents per kWh) .052 .051 .053

The decrease in purchased power from PURPA generation in 1998 was
due primarily to reduced generation at hydroelectric plants due
to reduced river flow. The increase in other purchased power in
1999 resulted primarily from increased purchases for sales. An
increase in price caused by volatility in the spot prices for
electricity at the wholesale level in the second and third quarters
of 1998 contributed to the 1998 increase in other purchased power costs.

M-33
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Monongahela Power Company

The increase in other operation expenses of $8.0 million in 1999
resulted primarily from a write-off of $4.2 million of costs
related to a pumped-storage generation project no longer
considered useful, $2.3 million of costs associated with settling
litigation concerning a PURPA project, and increases in salaries
and wages costs. The increase in other operations expenses in
1998 resulted primarily from increases in salaries and wages and
employee benefits, increased property insurance expense, and an
increase in expense related to Year 2000 readiness.

Maintenance expenses decreased in 1999 by $3.0 million due to
decreases in transmission and distribution maintenance expenses,
offset in part by increases in general plant maintenance which
includes renovations of office facilities. The decrease in
maintenance expenses in 1998 was due primarily to a management
program to postpone such expenses for the year in response to
limited sales growth in the first quarter due to the warm winter
weather. The Company postponed these expenses primarily by
extending the time between maintenance outages and experienced no
measurable effect on system performance.

Maintenance expenses represent costs incurred to maintain the
power stations, the transmission and distribution (T&D) system
and general plant, and to reflect routine maintenance of
equipment and rights-of-way, as well as planned major repairs and
unplanned expenditures, primarily from forced outages at the
power stations and periodic storm damage on the T&D system.
Variations in maintenance expense result primarily from unplanned
events and planned major projects, which vary in timing and
magnitude depending upon the length of time equipment has been in
service without a major overhaul and the amount of work found
necessary when the equipment is dismantled.

Depreciation expense in 1999 and 1998 increased $2.3 million and
$2.0 million, respectively, due to increased investment.

Taxes other than income taxes decreased $1.3 million in 1999 due
primarily to a 1998 adjustment to West Virginia Business and
Occupation Taxes for a prior period. Taxes other than income
taxes increased $6.0 million in 1998 due primarily to West
Virginia Business and Occupation Taxes.

The decrease in federal and state income taxes of $9.0 million
was primarily due to the Company's share of tax savings in
consolidation related to its parent, Allegheny Energy, and to a
net change in income tax provisions related to prior years. The
1998 increase in federal and state income taxes was primarily due
to increased taxable income. Note C to the financial statements
provides a further analysis of income tax expenses.

Other Income and Deductions

The decrease in other income, net, of $2.4 million in 1998 was
primarily due to a 1997 interest refund on a tax-related contract
settlement ($2.2 million after taxes) received by AGC, which is
partly owned by the Company.

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Monongahela Power Company

Interest Charges

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

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

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

The availability and cost of external financings depend upon the
financial health of the companies seeking those funds and market
conditions.

Construction expenditures in 1999 were $82 million and, for 2000 and
2001, are estimated at $75 million and $72 million, respectively. In
addition, in 1999 the Company acquired the assets of West
Virginia Power for approximately $95 million, and in 2000 the
Company also plans to purchase Mountaineer Gas
Company for approximately $323 million (which includes the
acquisition of approximately $100 million in existing debt). The
2000 and 2001 estimated expenditures include $27 million and $34
million, respectively, for construction of environmental control
technology. It is the Company's goal to constrain future
construction spending to the approximate level of depreciation
currently in rates. As described under Environmental Issues
starting on page 11, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues. The Company also has additional
capital requirements for debt maturities (see Note I to the
financial statements). The Company anticipates issuing new debt
to replace the $65 million of long-term debt maturing in 2000.

Internal Cash Flow

Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $86 million in 1999,
compared with $108 million in 1998. The decrease in 1999 cash
flows resulted from an increase in the level of common stock
dividends payable to its Parent, Allegheny Energy. Current
rate levels and reduced levels of construction expenditures
permitted the Company to finance all of its construction
expenditures in 1999 and 1998 with internal cash flow.

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Monongahela Power Company

Financing

Short-term debt is used to meet temporary cash needs. Short-term
debt, including notes payable to affiliates under the money pool,
decreased $20.3 million to $28.7 million in 1999. At December
31, 1999, the Company had Securities and Exchange Commission
(SEC) authorization to issue up to $106 million of short-term
debt. The Company and its regulated affiliates use an Allegheny
Energy internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that
certain of the companies have funds available. The Company
anticipates meeting its 2000 cash needs through internal cash
generation, cash on hand, short-term borrowings as necessary,
and by issuing debt to refinance maturing first mortgage bonds.

In April 1999, the Company issued $7.7 million of 5.50% 30-year
pollution control revenue notes to Pleasants County, West
Virginia. In December 1999, the Company issued $110 million of
7.36% unsecured medium-term notes due in January 2010, in part to
finance the purchase of West Virginia Power.

The Company's long-term debt due within one year at December 31,
1999 was $65 million of 5-5/8% first mortgage bonds due April 1,
2000.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition

The electricity supply segment of the electric utility industry
in the United States is becoming increasingly competitive. The
national Energy Policy Act of 1992 deregulated the wholesale
exchange of power within the electric industry by permitting the
FERC to compel electric utilities to allow third parties to
sell electricity to wholesale customers over their transmission
systems. Since 1992, the wholesale electricity market has become more
competitive as companies are engaging in nationwide power trading.
In addition, an increasing number of states have taken active steps toward
allowing retail customers the right to choose their electricity
supplier. The Company and its parent, Allegheny Energy, have been
advocates of federal legislation to create competition in the
retail electricity markets to avoid regional dislocations and
ensure level playing fields. Legislation before the U.S. Congress
to restructure the nation's electric utility industry cleared an
important hurdle on October 28, 1999, when a House Commerce
Committee subcommittee gave its approval to a bill. The bill will
now move on to the full Commerce Committee, where it will be
considered in 2000.

In the absence of federal legislation, state-by-state
implementation of deregulation of electric generation is under
way. The Company has franchised customers in the states of West
Virginia and Ohio. The five states in which the Company and its
affiliates serve customers are at various stages of
implementation or investigation of programs that allow customers
to choose their electric supplier. Pennsylvania is furthest along
with a retail program in place, while Maryland, Ohio, and
Virginia passed legislation in 1999 to implement retail
choice. West Virginia continues to actively study this issue. On
December 23, 1999, the Maryland PSC approved a settlement agreement
for one of the Company's affiliates, The Potomac Edison Company, to
implement generation competition in Maryland.

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Monongahela Power Company

At this time, the Company cannot determine the effect of
deregulation plans that may be approved in West Virginia and
Ohio. However, the approval of deregulation plans could have a
material impact on the Company regarding potential impairment of
electric generation assets and the Company's ability to recover
generation-related regulatory assets.

Activities at the Federal Level

The Company continues to seek enactment of federal legislation to
bring choice to all retail electric customers, deregulate the
generation and sale of electricity on a national level, and
create a more liquid, free market for electric power. Fully
meeting challenges in the emerging competitive environment will
be difficult for the Company unless certain outmoded and anti-
competitive laws, specifically the Public Utility Holding Company
Act of 1935 (PUHCA) and Section 210 (Mandatory Purchase
Provisions) of PURPA, are repealed or significantly revised. The
Company continues to advocate the repeal of PUHCA and Section 210
of PURPA on the grounds that they are obsolete and anti-
competitive and that PURPA results in utility customers paying
above-market prices for power. H.R. 2944, which was sponsored by
U.S. Representative Joe Barton, was favorably reported out of the
House Commerce Subcommittee on Energy and Power. While the bill
does not mandate a date certain for customer choice, several key
provisions favored by the Company are included in the
legislation, including an amendment that allows existing state
restructuring plans and agreements to remain in effect. Other
provisions address important Company priorities by repealing the
PUHCA and the mandatory purchase provisions of PURPA. Consensus
remains elusive, with significant hurdles remaining in both
houses of Congress. It is too early to tell whether momentum on
the issue will result in legislation in 2000.

Ohio Activities

On June 22, 1999, the Ohio General Assembly passed legislation to
restructure the electric utility industry. The Governor of Ohio
added his signature soon thereafter, and all of the state's
customers will be able to choose their
electricity supplier starting January 1, 2001, beginning a five-
year transition to market rates. Total electric rates will be
frozen over that period, and residential customers are guaranteed
a 5% cut in the generation portion of their rate. The
determination of stranded cost recovery will be handled by the
Ohio PUC. On January 3, 2000, the Company filed a transition plan
with the Ohio PUC, including its claim for recovery of stranded
costs of $21.3 million. The Ohio PUC is expected to hold hearings
on the Company's transition plan filing and issue a decision by
October 2000.

The Ohio legislation stipulates that an entity independent of the
utilities shall own or control transmission facilities after the
start of competitive retail electric service on January 1, 2001,
but not later than December 31, 2003. Customer protections were
kept intact with a low-income assistance plan and a one-time
forgiveness of past debts for low-income and handicapped
customers. In regard to renewable energy, the bill requires that
electric generators purchase excess electricity from small
businesses and homes using renewable energy sources.

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Monongahela Power Company

West Virginia Activities

In March 1998, legislation was passed by the West Virginia
Legislature that
directed the W.Va. PSC to meet with all interested parties to
develop a restructuring plan which would meet the dictates and
goals of the legislation. Interested parties formed a Task Force
that met during 1998, but the Task Force was unable to reach a
consensus on a model for restructuring. The W.Va. PSC held
hearings in August 1999 that addressed certification, licensing,
bonding, reliability, universal service, consumer protection,
code of conduct, subsidies, and stranded costs. The W.Va. PSC on
December 20, 1999, released for comment and hearings a modified
version of a proposal submitted by members of the Task Force,
including the Company and its affiliate, Potomac Edison,
following the August 1999 hearings that could open full retail
competition as early as January 1, 2001. The production of power
would be deregulated and electricity rates would be frozen for
four years with rates gradually transitioning to market rates
over the six years thereafter. After hearings in January 2000,
the W.Va. PSC submitted a restructuring plan endorsed by members
of the Task Force, including the Company and Potomac Edison, to
the Legislature for approval.

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

Virginia Activities

On March 25, 1999, Governor Gilmore signed the Virginia Electric
Utility Restructuring Act (Restructuring Act) passed by the
Virginia General Assembly. All utilities must submit a
restructuring plan by January 1, 2001, to be effective on January
1, 2002. Customer choice will be phased in beginning on January
1, 2002, with full customer choice by January 1, 2004. The
Legislative Transition Task Force on Electric Utility
Restructuring, which was established by the Restructuring Act to
oversee the implementation of customer choice, held hearings in
the summer and fall of 1999 on a number of issues concerning the
implementation of retail competition in Virginia. Parties have
also been

working with the Virginia SCC staff to develop the rules
governing the proposed retail pilot programs of other utilities in the state.

Maryland Activities

On April 8, 1999, Maryland Governor Glendening signed the
legislation that will bring competition to Maryland's electric
generation market beginning July 1, 2000. The Maryland PSC is in
the process of implementing the new law. Final Electric
Restructuring Roundtable reports were filed with the Maryland PSC
on May 3, 1999, and legislative-style hearings were held last
summer on the reports. The Company's affiliate, Potomac Edison,
filed testimony in Maryland's investigation into transition
costs, price protection, and unbundled rates, and a consensus
settlement agreement was achieved with no protest by any of the
parties participating in the negotiations. The agreement was
filed on September 23, 1999, and a hearing before the Commission
was held on October 14, 1999. On December 23, 1999, the Maryland
PSC issued an order approving the settlement. Potomac Edison
filed an application on December 15, 1999, to transfer its
Maryland generation assets

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Monongahela Power Company

at book value to an affiliate under Section 7-508 of the Electric
Customer Choice and Competition Act of 1999. A Maryland PSC
ecision approving the transfer of the generating assets is due by
July 1, 2000.

Pennsylvania Activities

In December 1996, Pennsylvania enacted the Electricity Generation
Customer Choice and Competition Act to restructure the electric
industry to create retail access to a competitive electric energy
supply market. On May 29, 1998
(as amended on November 19, 1998), the Pennsylvania Public
Utility Commission granted final approval to West Penn's
restructuring plan. As of January 2, 2000, all electricity
customers in Pennsylvania had the right to choose their electric
suppliers. Two-thirds of all retail customers had a choice
throughout 1999, the first year of retail choice following a
pilot program. The number of customers who have switched
suppliers and the amount of electrical load transferred in
Pennsylvania far exceed that of any other state so far. However,
for West Penn, only 12,700 of its Pennsylvania customers
eligible to shop in 1999 have chosen an alternate energy
supplier. West Penn has retained about 98% of its Pennsylvania
customers through December 31, 1999. More than 100 electric
generation suppliers have been licensed to sell to retail
customers in Pennsylvania.

Environmental Issues

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

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

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

M-39
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Monongahela Power Company

a result of litigation, the Maryland regulation was revised to
postpone compliance to May 2000.

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

In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included). The petitions claim NOx
emissions from these upwind sources are preventing their
attainment with the ozone standard. In December 1997, the
petitioning states and the EPA signed a Memorandum of Agreement
to address these petitions in conjunction with the related SIP
call. In May 1999, the EPA issued a technical approval of the
petition and, in December 1999, granted final approval of four of
the petitions. The Section 126 petition rulemaking is also under
litigation.

The EPA is required by law to regularly review the NAAQS for
criteria pollutants. Recent court orders in litigation by the
American Lung Association have expedited these reviews. The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997. However, the
revised standards were legally challenged, and, in May 1999, the
District of Columbia Circuit Court of Appeals remanded the
revised standards back to EPA for further consideration. Also, in
May 1999, the EPA promulgated final regional haze regulations to
improve visibility in Class I federal areas (national parks and
wilderness areas). If eventually upheld in court, subsequent state
regulations could require additional reduction of SO2 and/or NOx
emissions from Company facilities. The effect on the Company of
revision to any of these standards or regulations is unknown at
this time, but could be substantial.

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

M-40
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Monongahela Power Company

Implementation dates are also uncertain at this time, but could be as
early as 2003, which would require substantial capital expenditures in
the 2000 through 2003 period. The Company's construction forecast includes
the expenditure of $96 million of capital costs during the 2000 through
2003 period to comply with the SIP call. In addition, $3 million was spent
in 1999.

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

The Company actively participates in climate-related research
programs and is responsive to the voluntary guidelines suggested
in the national Energy Policy Act of 1992, under Section 1605(b),
directed toward reducing, controlling, avoiding, and sequestering
greenhouse gases. The Company has taken many concrete steps to
reduce greenhouse gases and help stimulate a business climate
that encourages improved efficiency, performance, electrical loss
reductions, and cost effectiveness.

The Company believes that provisions for liability and insurance
recoveries are such that final resolution of these claims will
not have a material

M-41

<PAGE>

Monongahela Power Company

effect on its financial position (see Note L to the financial
statements for additional information).

On Earth Day 1997, President Clinton announced the expansion of
the federal Emergency Planning and Community Right-to-Know Act
(RTK) reporting to include electric utilities, limited to
facilities that combust coal and/or oil for the purpose of
generating power for distribution in commerce. The purpose of RTK
is to provide site-specific information on chemical releases to
the air, land, and water. On June 4, 1999, the Allegheny Energy
companies (the System) joined with other members of the Edison
Electric Institute in reporting power station releases to the
public. Packets of information about the System's releases were
provided to the news media in the System's service area and
posted on the Parent Company's web site. The System filed its
first RTK-related report with the EPA in advance of the July 1,
1999, deadline, reporting 18 million pounds of total releases for
calendar year 1998.

The Attorney General of the State of New York and the Attorney
General of the State of Connecticut in their letters dated
September 15, 1999, and November 3, 1999, respectively, notified
Allegheny Energy of their intent to commence civil actions
against Allegheny Energy and/or its subsidiaries alleging
violations at the Fort Martin Power Station under the federal
Clean Air Act, which requires power plants that make major
modifications to comply with the same emission standards
applicable to new power plants. Similar actions may be
commenced by other governmental authorities in the future. Fort
Martin is a station located in West Virginia and is now jointly
owned by the Company and its affiliates, Allegheny Energy Supply
and Potomac Edison. Both Attorneys General stated their intent to
seek injunctive relief and penalties. In addition, the Attorney
General of the State of New York in his letter indicated that he
may assert claims under the State common law of public nuisance
seeking to recover, among other things, compensation for alleged
environmental damage caused in New York by the operation of Fort
Martin Power Station. At this time, Allegheny Energy and its
subsidiaries are not able to determine what effect, if any, these
actions threatened by the Attorneys General of New York and
Connecticut may have on them.

Regional Transmission Organization

In adopting its Rule 2000, the FERC defined requirements for
transmission facility owners to participate in some form of Regional
Transmission Organization. Additionally, the state jurisdictions
within which the Company operates have, to different degrees,
started to define their transition to a competitive marketplace. As
part of this, they have identified transmission as a key link to
making the electricity market efficient. The nature of this issue is
at least regional in scope. As a result, any solution will need to
be one that satisfies a diverse group of stakeholders. The Company
has actively participated in this debate and continues to evaluate
the available options to provide our customers with the most
reliable, cost-effective service while maintaining a clear focus on
the financial interests of our shareholders.

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Monongahela Power Company

Derivative Instruments and Hedging Activities

In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The Company will be
required to recognize derivatives as defined by SFAS No. 133 on the
balance sheet at fair value. The Company is evaluating the impact
of adopting SFAS No. 133 on its results of operations and financial
position which will be completed during the year 2000. Accounting
for changes in the fair value of a derivative depends on the
intended use of the derivative and whether the instrument meets the
requirements for designation as a hedge. The Company expects to
adopt SFAS No. 133 no later than January 1, 2001.

M-43

<PAGE>

The Potomac Edison Company

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

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including ongoing state and federal activities; developments in the
legislative and regulatory environments in which the Company
operates, including regulatory proceedings affecting rates charged
by the Company; environmental, legislative, and regulatory changes;
future economic conditions; and other circumstances that could
affect anticipated revenues and costs such as significant volatility
in the market price of wholesale power and fuel for electric
generation, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.

BUSINESS STRATEGY

In July 2000, the Company plans to transfer the Maryland
jurisdictional portion of its electric generation assets at net book
value to Allegheny Energy Supply Company, LLC (Allegheny Energy
Supply), in accordance with a settlement agreement approved by the
Maryland Public Service Commission (Maryland PSC). Allegheny Energy
Supply is a subsidiary of Allegheny Energy, Inc. (Allegheny Energy),
the Company's Parent. See Note B to the financial statements for
additional information regarding the settlement agreement. The
Company expects to transfer approximately 1,300 megawatts (MW) of
generating capacity as of July 1, 2000. At December 31, 1999, the
generation assets to be transferred had a net book value of
approximately $282 million.

A component of the deregulation plans sponsored by the Company in
West Virginia and Virginia is the authority to transfer the
Company's remaining electric generation assets to Allegheny Energy
Supply at net book value. The Company intends to transfer its
remaining generation assets subject to receiving the necessary
approvals of West Virginia and Virginia deregulation plans as well
as other required regulatory approvals.

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The Potomac Edison Company

Ohio, Virginia, and West Virginia to its unregulated subsidiary at
book value in deregulation proceedings in these jurisdictions. The
unregulated electric supply is being sold in both the wholesale and
retail competitive marketplaces, allowing greater earnings growth
potential, subject to market risk, while allowing Allegheny Energy
to capitalize on its strengths in the generation business.

Following the transfer of generation assets to Allegheny Energy
Supply, the Company will be part of Allegheny Energy's delivery
business (wires and pipes). The delivery business will remain an
important part of Allegheny Energy's business which Allegheny Energy
plans to expand.

SIGNIFICANT EVENTS IN 1999, 1998, AND 1997

Maryland Deregulation

On September 23, 1999, a settlement agreement between the Company,
the Staff of the Maryland PSC, and other parties working to
implement customer choice and deregulation of electric generation
for the Company in Maryland was filed with the Maryland PSC. On
December 23, 1999, the Maryland PSC approved the settlement
agreement, which provides nearly all of the Company's 211,000
Maryland customers with the ability to choose an electric generation
supplier starting July 1, 2000.

As a result of the Maryland settlement agreement, the Company
discontinued the application of the Financial Accounting Standards
Board's (FASB) Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation,"
for the electric generation portion of its Maryland operations and
has adopted SFAS No. 101, "Accounting for the Discontinuation of
Application of FASB Statement No. 71." Accordingly, the Company
recorded an extraordinary charge of $26.9 million ($17.0 million
after taxes) during the fourth quarter of 1999. This write-off
reflects the impairment of certain electric generation assets as
determined by applying SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
and the write-off of the Maryland portion of generation-related net
regulatory assets. See Notes B and C to the financial statements for
details of the settlement agreement and the effect on the Company.

PURPA Power Project Termination

In 1999, the Company settled for $2.7 million litigation by a
developer alleging failure by the Company to comply with the Public
Utility Regulatory Policies Act of 1978 (PURPA) regulations.

Electric Industry Restructuring
See Electric Energy Competition on page 10 for more information
regarding electric industry restructuring activities.

M-45
<PAGE>

The Potomac Edison Company

Recapitalization

On September 30, 1999, the Company called $16.4 million of preferred
stock. The Company also plans to revise its Articles of
Incorporation to provide greater financial flexibility.

REVIEW OF OPERATIONS

Earnings Summary
Earnings
(Millions of Dollars) 1999 1998 1997

Operations................................... $100.6 $101.5 $95.8
Extraordinary charge, net (Notes B and C
to the financial statements)............... (17.0)

Net Income................................... $ 83.6 $101.5 $95.8

The decrease in 1999 earnings from operations, before the
extraordinary charge, resulted from increased operation and
maintenance (O&M) expenses and lower other income, net. Included as
part of other operation expenses is a $5.3 million write-off of a
pumped-storage generation project no longer considered useful. The
decrease in earnings was offset in part by increased kilowatt-hour
(kWh) sales to retail customers, tax benefits related to plant
removal costs
and to the Company's share of tax savings in consolidation related
to its parent, Allegheny Energy, and reduced interest expenses. The
extraordinary charge in 1999 resulted from the Maryland electric
utility restructuring order as discussed in Notes B and C to the
financial statements.

The increase in 1998 earnings from operations resulted from
increased sales to retail customers and from reduced power station
O&M spending.

Sales and Revenues

Percentage changes in revenues and kWh sales in 1999 and 1998 by
major retail customer classes were:
1999 vs. 1998 1998 vs. 1997
Revenues kWh Revenues kWh

Residential................... 6.9% 5.5% 3.1% 2.6%
Commercial.................... 7.3 6.8 5.9 7.2
Industrial.................... 2.7 (1.4) 4.3 5.9
Total....................... 5.7% 2.6% 4.1% 5.0%

The changes in residential kWh sales, which are more weather
sensitive than the other classes, were due primarily to changes in
customer usage because of weather conditions and growth in the
number of customers. The growth in the number of residential
customers was 2.1% and 1.9% in 1999 and 1998, respectively.

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The Potomac Edison Company

Commercial kWh sales are also affected by weather, but to a lesser
extent than residential. The increase in commercial kWh sales of
6.8% and 7.2% in 1999 and 1998, respectively, reflects increased
usage due to weather and commercial activity as well as growth in
the number of customers. The growth in the number of commercial
customers was 2.5% and 2.4% in 1999 and 1998, respectively.

The decrease in industrial kWh sales in 1999 results primarily from
decreased sales to primary metals industry customers. The increase
in 1998 reflects increased sales to paper and printing customers and
to the Eastalco aluminum reduction plant.

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

On February 25, 1999, the Virginia SCC approved the Company's rate
reduction
request, which decreased the fuel portion of Virginia customers'
bills by approximately 7.6% (a decrease in annual fuel revenue of
about $2.2 million). The decrease is primarily due to refunding a
prior overrecovery of fuel costs, coupled with a small decrease in
projected energy costs. The new rates were effective with bills
rendered on or after March 9, 1999.

On May 21, 1999, the Virginia SCC approved an agreement between the
Company and the staff of the Virginia SCC which reduced base rates
for Virginia customers effective June 1, 1999, by about $3 million
annually. The review of rates is required by an annual information
filing in Virginia.

On February 26, 1999, the Public Service Commission of West Virginia
(W.Va. PSC) entered an order to initiate a fuel review proceeding to
establish a fuel increment in rates for the Company and its
affiliate, Monongahela Power Company, to be effective July 1, 1999,
through June 30, 2000. The parties have exchanged proposals which
continue to be discussed. If an agreement is not reached, the
proposed fuel rates which would decrease the Company's fuel rates by
$8.0 million will become effective March 15, 2000.

On November 8, 1999, the Company filed with the Maryland PSC a
request to decrease the fuel portion of Maryland customers' bills by
about $6.4 million annually. The requested decrease is primarily
due to greater efficiencies, lower fuel costs, and increased
nonaffiliated generation and transmission sales. The new fuel rates
were effective with bills rendered on or after December 7, 1999,
subject to refund, based on the outcome of proceedings before the
Maryland PSC.

On October 27, 1998, the Maryland PSC approved a settlement
agreement for the Company. Under the terms of that agreement, the
Company increased its rates $13 million in 1999, will increase its
rates an additional $13 million in 2000, and an additional increase
of $13 million will go into effect in 2001 (a $79 million total
revenue increase during 1999 through 2001). The increases are
designed to recover additional costs of about $131 million over the
1999 through 2001 period for capacity purchases from the AES Warrior
Run

M-47
<PAGE>

The Potomac Edison Company
cogeneration project, net of alleged over-earnings of $52
million for the same period. The net effect of these changes over
the 1999 through 2001 time frame results in a pre-tax income

reduction of $12 million in 1999, $21 million in 2000, and $19
million in 2001. Also, the Company will share, on a 50% customer,
50% shareholder basis, earnings above a return on equity of 11.4% in
Maryland for 1999 and 2000. This sharing will occur through an
annual true-up. The Company's 1999 revenues reflect an estimated
obligation for shared earnings above an 11.4% return on equity.

Changes in revenues from retail customers resulted from the
following:

Changes from Prior Year
(Millions of Dollars) 1999 vs. 1998 1998 vs. 1997

Fuel clauses............................. $ 5.7 $10.9
All other................................ 32.6 15.4
Net change in retail revenues.......... $38.3 $26.3

Revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy cost
adjustment clauses (fuel clauses) which are still applicable in the
Company's jurisdictions.

Effective July 1, 2000, the Company's Maryland jurisdiction will cease
to have a fuel clause under the terms of the September 23, 1999,
settlement agreement. Changes in fuel revenues in jurisdictions for which
a fuel clause continues to exist have no effect on net income because
increases and decreases in fuel and purchased power costs and sales of
transmission services and bulk power are passed on to customers by
adjustment of customers' bills through fuel clauses. Effective July 1,
2000, the Company will assume the risks and benefits of changes in fuel
and purchased power costs and sales of transmission services and bulk power
in its Maryland jurisdiction. The Company expects that the fuel clause
rates in Virginia and West Virginia will cease as these states implement
customer choice. The Company will then assume the risks and benefits of
changes in fuel and purchased power costs and sales of transmission services
and bulk power.

All other is the net effect of kWh sales changes due to changes in
customer usage (primarily weather for residential customers), growth
in the number of customers, and changes in pricing other than
changes in general tariff and fuel clause rates. The increase in
1999 in all other retail revenues was primarily due to increased kWh
sales as customer usage increased as a result of weather conditions
and to customer growth. The increase in 1998 all other retail
revenues was primarily the result of increased customer usage and
growth in the number of customers.

Wholesale and other revenues were as follows:

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The Potomac Edison Company

(Millions of Dollars) 1999 1998 1997

Wholesale customers....................... $21.5 $23.5 $26.6
Affiliated companies...................... 11.4 9.4 9.7
Street lighting and other................. 4.7 5.5 2.6
Deferred revenues......................... (19.9)
Total wholesale and other revenues...... $17.7 $38.4 $38.9

Wholesale customers are cooperatives and municipalities that own
their distribution systems and buy all or part of their bulk power
needs from the Company under Federal Energy Regulatory Commission
(FERC) regulation. Competition in the wholesale market for
electricity was initiated by the national Energy Policy Act of 1992,
which permits wholesale generators, utility-owned and otherwise, and
wholesale customers to request from owners of bulk power
transmission facilities a commitment to supply transmission
services. The decrease in wholesale revenues in 1999 was due
primarily to renegotiated contracts with some wholesale customers.
The decrease in wholesale revenues in 1998 was primarily due to the
mild 1998 winter weather.

The increase in street lighting and other revenues in 1998 was
primarily due to the recording in 1998 of additional pole attachment
revenues.

Deferred revenues of $19.9 million in 1999 result from settlement
agreements approved by the Maryland PSC.

Bulk power transactions include sales of bulk power and transmission
and other energy services to power marketers and other utilities.
Bulk power and transmission and other energy services sales for
1999, 1998, and 1997 were as follows:

1999 1998 1997
<S> <C> <C> <C>
kWh Transactions (in billions):
Bulk power................................ .2 .4 .4
Transmission and other energy services
to nonaffiliated companies.............. 2.8 2.5 4.0
Total................................. 3.0 2.9 4.4

Revenues (in millions):
Bulk power................................ $ 8.4 $11.7 $10.0
Transmission and other energy services
to nonaffiliated companies.............. 16.2 14.7 13.6
Total................................. $24.6 $26.4 $23.6

</TABLE>

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The Potomac Edison Company

Revenues from bulk power transactions decreased in 1999 due to
decreased sales to power marketers and other utilities. The 1998
increase in revenues from bulk power was due to increased sales that
occurred primarily in the second quarter as a result of warm weather
which increased the demand and price for energy.

In 1999, revenues from transmission and other energy services
increased primarily due to increased megawatt-hours (MWh)
transmitted. Revenues from transmission and other energy services
in 1998 increased, despite decreased transmission services activity.
The increase in 1998 revenues was due to transmission services
reservation charges paid to the Company by others for the right to
transmit energy. Transmission services activity was affected as a
result of some of the reservations to transmit energy not being
used. In 1998, revenues from transmission and other energy services
were affected by a revenue refund resulting from a reduction in the
Company's standard transmission rate and rates for ancillary
services which were approved by the FERC. A provision of $2.2
million for these rate reductions was recorded in 1998, with
revenues refunded to customers in the first quarter of 1999.

In June and July 1999 and June and July 1998, certain events
combined to produce significant volatility in the spot prices for
electricity at the wholesale level. These events included extremely
hot weather, generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of $25 to
$40 per MWh to as high as $3,500 to $7,000 per MWh. The costs of
purchased power and revenues from sales to power marketers and other
utilities, including transmission services, are currently recovered
from or credited to customers under fuel and energy cost recovery
procedures. The impact to the fuel and energy cost recovery clauses
may be positive or negative depending on whether the Company is a
net buyer or seller of electricity during such periods and the open
commitments which exist at such times. The impact of such price
volatility in 1999 and 1998 was insignificant to the Company because
changes are passed to customers through operation of fuel clauses.
However, effective July 1, 2000, the fuel clause will be
discontinued in Maryland which may cause an increase in the
volatility of earnings for the Company.

The Company expects that the fuel clause rates in Virginia and West
Virginia will cease as these states implement customer choice. The
Company will then assume the risks and benefits of changes in fuel
and purchased power costs and sales of
transmission services and bulk power.

Operating Expenses

Fuel expenses decreased 3.4% in 1999 due to a 6.0% decrease in
average fuel prices offset in part by a 2.6% increase related to
kWhs generated to meet retail customer requirements and increased
sales to affiliates. The decrease in average fuel prices was due to
renegotiated fuel contracts. In 1998 fuel expenses increased 2.1%
due to increased kWhs generated. The 1998 increase in kWhs
generated was primarily the result of increased bulk power sales to
power marketers and other utilities and also due to increased sales
to retail customers.

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The Potomac Edison Company

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

(Millions of Dollars) 1999 1998 1997

Nonaffiliated transactions:
Purchased power:
Other.................................. $15.7 $ 15.2 $ 13.2
From PURPA generation.................. 1.5
Power exchanges, net..................... (2.6) (.1)
Affiliated transactions:
AGC capacity charges..................... 19.8 23.8 25.5
Other affiliated capacity charges........ 39.0 42.9 50.8
Energy and spinning reserve charges...... 53.6 56.5 50.7
Purchased power and exchanges, net..... $127.0 $138.3 $140.2

The increases in other purchased power in 1999 and 1998 resulted
primarily from increased kWh purchases to supply retail customers.
An increase in price caused by volatility in the spot prices for
electricity at the wholesale level in the second and third quarters
of 1998 also contributed to the 1998 increase.

The AES Warrior Run PURPA cogeneration project in the Company's
Maryland service territory will increase the cost of power purchases
by about $60 million annually. Commencement of operation was
scheduled for October 1999. Pre-commencement testing is not
completed. Although AES Warrior Run has until October 1, 2000, to
complete pre-commencement testing, it is anticipated that it will be
in commercial operation in the first quarter of 2000. The Maryland
PSC has approved the Company's full recovery of the AES Warrior Run
purchased power costs as part of the September 23, 1999, settlement
agreement. See Sales and Revenues starting on page 3 for more
information on the settlement agreement.

On January 1, 1999, an amendment to the Company and its affiliates'
power supply agreement became effective. The amendment sets the
generation demand for each owner proportional to its ownership in
AGC. Previously, demand for each shared owner of AGC fluctuated due
to customer usage. The decrease in AGC capacity charges in 1999 was
primarily due to this change. Energy and spinning reserve
charges decreased in 1999 due to decreased kWh purchases from
affiliates.

The increase in other operation expenses in 1999 of $13.5 million
resulted primarily from increased expenses due to a write-off of
$5.3 million of costs related to a pumped-storage generation project
no longer considered useful, $2.7 million of costs associated with
settling litigation concerning a PURPA project, increases in salaries
and wages of $1.9 million, and increased provisions for uninsured
claims of $1.4 million. The increase in other

M-51
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The Potomac Edison Company

operation expenses of $2.9 million in 1998 resulted primarily from
increased expenses related to competition in Maryland of $1.6 million.

The increase in maintenance expenses in 1999 of $5.1 million was due
to a $2.8 million increase in power station maintenance, a $1.4
million increase in transmission and distribution maintenance, and a
$.9 million increase in general plant maintenance which includes
renovations of office facilities. The decrease in maintenance
expenses in 1998 was due primarily to a management program to
postpone such expenses for the year in response to limited sales
growth in the first quarter due to the warm winter weather. The
Company postponed these expenses primarily by extending the time
between maintenance outages and experienced no measurable effect on
system performance.

Maintenance expenses represent costs incurred to maintain the power
stations, the transmission and distribution (T&D) system and general
plant, and to reflect routine maintenance of equipment and rights-of-
way, as well as planned major repairs and unplanned expenditures,
primarily from forced outages at the power stations and periodic
storm damage on the T&D system. Variations in maintenance expense
result primarily from unplanned events and planned major projects,
which vary in timing and magnitude depending upon the length of time
equipment has been in service without a major overhaul and the
amount of work found necessary when the equipment is dismantled.

Depreciation expense increases resulted from increased investment.

The increase in taxes other than income taxes of $1.4 million in
1999 was due to an increase in the assessment of property in
Maryland. The increase in taxes other than income taxes of $2
million in 1998 was primarily due to an increase in gross receipts
taxes resulting from greater revenues from retail customers and
increased property taxes.

The 1999 decrease in federal and state income taxes was due
primarily to decreased taxable income, tax benefits related to plant
removal costs for which deferred taxes were not provided, and to the
Company's share of tax savings in consolidation related to its
parent, Allegheny Energy. The 1998 increase in federal and state
income taxes was primarily due to increased taxable income. Note D
to the financial statements provides a further analysis of income
tax expenses.

Other Income and Deductions

The decrease in allowance for other than borrowed funds used during
construction of $1.1 million in 1998 was due to property placed in
service.

The decrease in other income, net of $1.5 million in 1999 was due
primarily to the discontinuance of a demand side management program.
The decrease in other income, net, of $4.7 million in 1998 was
primarily due to a 1997 interest refund on a tax-related contract
settlement ($2.5 million, after taxes) received by AGC, which is
partly owned by the Company.

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The Potomac Edison Company
Interest Charges

The decrease in interest on long-term debt in 1999 of $3.1 million
and in 1998 of
$1.6 million resulted from reduced average long-term debt
outstanding and, in 1998, also lower interest rates. Other interest
expense reflects changes in the levels of short-term debt maintained
by the Company throughout the year, as well as the associated interest
rates.

Extraordinary Item

The extraordinary charge in 1999 of $26.9 million ($17.0 million
after taxes) was required to reflect a write-off of certain
disallowances in the Maryland PSC's December 1999 order. See Notes B
and C to the financial statements for additional information.

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

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

Construction expenditures in 1999 were $92 million and, for 2000 and
2001, are estimated at $88 million and $72 million, respectively.
The 2000 and 2001 estimated expenditures include $31 million and $40
million, respectively, for construction of environmental control
technology. It is the Company's goal to constrain future
construction spending to the approximate level of depreciation
currently in rates. As described under Environmental Issues
starting on page 13, the Company could potentially face significant
mandated increases in construction expenditures and operating costs
related to environmental issues. Whether the Company can continue
to meet the majority of its construction needs with internally
generated cash is largely dependent upon the outcome of these
issues. The Company also has additional capital requirements for
debt maturities (see Note I to the financial statements). The
Company anticipates issuing new debt to replace the $75 million of
long-term debt maturing in 2000.

Internal Cash Flow

Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $58 million in 1999, compared
with $187 million in 1998. The decrease in 1999 cash flows resulted
primarily from an increase in the level of common stock dividends
payable to its Parent, Allegheny Energy, Inc. Current rate levels
permitted the Company to finance 64% of its construction

M-53
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The Potomac Edison Company

expenditures in 1999 and all of its construction expenditures in
1998 with internal cash flow.

Financing

Short-term debt is used to meet temporary cash needs. The Company
had no short-term debt outstanding at December 31, 1999 or December 31,
1998. At December 31, 1999, the Company had Securities and Exchange
Commission (SEC) authorization to issue up to $130 million of short-
term debt. The Company and its regulated affiliates use an Allegheny Energy
internal money pool as a facility to accommodate intercompany short-
term borrowing needs, to the extent that certain of the companies
have funds available. The Company anticipates meeting its 2000 cash
needs through internal cash generation, cash on hand, short-term
borrowings as necessary, and by issuing debt to refinance maturing
first mortgage bonds.

The Company called all outstanding shares of its cumulative
preferred stock with a combined par value of $16.4 million plus
redemption premiums of $.5 million on September 30, 1999, with funds
on hand. The redemptions of the preferred stock will allow the
Company to revise its Articles of Incorporation, providing greater
financial flexibility in restructuring debt.

In April 1999, the Company issued $9.3 million of 5.5% 30-year
pollution control revenue notes to Pleasants County, West Virginia.

The Company's long-term debt due within one year at December 31,
1999 was $75 million of 5-7/8% first mortgage bonds due March 1,
2000.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition

The electricity supply segment of the electric utility industry in
the United States is becoming increasingly competitive. The
national Energy Policy Act of 1992 deregulated the wholesale
exchange of power within the electric industry by permitting the
FERC to compel electric utilities to allow third parties to sell
electricity to wholesale customers over their transmission systems.
Since 1992, the wholesale electricity market has become more
competitive as companies are engaging in nationwide power trading.
In addition, an increasing number of states have taken active steps
toward allowing retail customers the right to choose their
electricity supplier. The Company and its parent, Allegheny Energy
have been advocates of federal legislation to create competition in
the retail electricity markets to avoid regional dislocations and
ensure level playing fields. Legislation before the U.S. Congress
to restructure the nation's electric utility industry cleared an
important hurdle on October 28, 1999, when a House Commerce
Committee subcommittee gave its approval to a bill. The bill will
now move on to the full Commerce Committee where it will be
considered in 2000.

In the absence of federal legislation, state-by-state implementation
of deregulation of electric generation is under way. The Company
has franchised

M-54
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The Potomac Edison Company

customers in Maryland, Virginia, and West Virginia.
The five states in which the Company and its affiliates serve
customers are at various stages of implementation or investigation
of programs that allow customers to choose their electric supplier.
Pennsylvania is furthest along with a retail program in place, while
Maryland, Ohio, and Virginia passed legislation in 1999 to implement
retail choice. West Virginia continues to actively study this
issue. On December 23, 1999, the Maryland PSC approved a settlement
agreement for the Company to implement generation competition in
Maryland.

At this time, the Company cannot determine the effect of
deregulation plans that may be approved in West Virginia and
Virginia. However, the approval of deregulation plans could have a
material impact on the Company regarding potential impairment of
electric generation assets and the Company's ability to recover
generation-related regulatory assets.

Activities at the Federal Level

The Company continues to seek enactment of federal legislation to
bring choice to all retail electric customers, deregulate the
generation and sale of electricity
on a national level, and create a more liquid, free market for
electric power. Fully meeting challenges in the emerging
competitive environment will be difficult for the Company unless
certain outmoded and anti-competitive laws, specifically the Public
Utility Holding Company Act of 1935 (PUHCA) and Section 210
(Mandatory Purchase Provisions) of PURPA, are repealed or
significantly revised. The Company continues to advocate the repeal
of PUHCA and Section 210 of PURPA on the grounds that they are
obsolete and anti-competitive and that PURPA results in utility
customers paying above-market prices for power. H.R. 2944, which was
sponsored by U.S. Representative Joe Barton, was favorably reported
out of the House Commerce Subcommittee on Energy and Power. While
the bill does not mandate a date certain for customer choice,
several key provisions favored by the Company are included in the
legislation, including an amendment that allows existing state
restructuring plans and agreements to remain in effect. Other
provisions address important Company priorities by repealing the
PUHCA and the mandatory purchase provisions of the PURPA. Consensus
remains elusive with significant hurdles remaining in both houses of
Congress. It is too early to tell whether momentum on the issue
will result in legislation in 2000.

Maryland Activities

On April 8, 1999, Maryland Governor Glendening signed the
legislation that will bring competition to Maryland's electric
generation market beginning July 1, 2000. The Maryland PSC is in the
process of implementing the new law. Final Electric Restructuring
Roundtable reports were filed with the Maryland PSC on May 3, 1999,
and legislative-style hearings were held last summer on the reports.
The Company filed testimony in Maryland's investigation into
transition costs, price protection, and unbundled rates, and a
consensus settlement agreement was achieved with no protest by any
of the parties participating in the negotiations. The agreement was
filed on September 23, 1999, and a hearing before the Commission was
held on October 14, 1999. On December 23, 1999, the Maryland PSC
issued an order approving the settlement. The Company filed an
application on December 15, 1999, to transfer its

M-55
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The Potomac Edison Company

Maryland generation assets at book value to an affiliate under
Section 7-508 of the Electric Customer Choice and Competition Act of
1999. A Maryland PSC decision approving the transfer of the generating
assets is due by July 1, 2000.

Virginia Activities

On March 25, 1999, Governor Gilmore signed the Virginia Electric
Utility Restructuring Act (Restructuring Act) passed by the Virginia
General Assembly. All utilities must submit a restructuring plan by
January 1, 2001, to be effective on January 1, 2002. Customer
choice will be phased in beginning on January 1, 2002, with full
customer choice by January 1, 2004. The Legislative Transition Task
Force on Electric Utility Restructuring, which was established by
the Restructuring Act to oversee the implementation of customer
choice, held hearings in the summer and fall of 1999 on a number of
issues concerning the implementation of retail competition in
Virginia. Parties have also been working with the Virginia SCC
Staff to develop the rules governing the proposed retail pilot
programs of other utilities in the state.

West Virginia Activities

In March 1998, legislation was passed by the West Virginia
Legislature that directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan which would meet the
dictates and goals of the legislation. Interested parties formed a
Task Force that met during 1998, but the Task Force
was unable to reach a consensus on a model for restructuring. The
W.Va. PSC held hearings in August 1999 that addressed certification,
licensing, bonding, reliability, universal service, consumer
protection, code of conduct,
subsidies, and stranded costs. The W.Va. PSC on December 20, 1999
released for comment and hearings a modified version of a proposal
submitted by members
of the Task Force, including the Company and its affiliate,
Monongahela Power, following the August 1999 hearings that could
open full retail competition as early as January 1, 2001. The
production of power would be deregulated and electricity rates would
be frozen for four years with rates gradually transitioning to
market rates over the six years thereafter. After hearings in
January 2000, the W.Va. PSC submitted a restructuring plan endorsed
by members of the Task Force, including the Company and Monongahela
Power, to the Legislature for approval.

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

Ohio Activities

On June 22, 1999, the Ohio General Assembly passed legislation to
restructure its electric utility industry. The Governor of Ohio
added his signature soon thereafter, and all of the state's
customers will be able to choose their electricity supplier starting
January 1, 2001, beginning a five-year transition to market rates.
Total electric rates will be frozen over that period, and
residential customers are guaranteed a 5% cut in the generation
portion of their rate. The determination of stranded cost recovery
will be handled by the Public Utilities Commission of Ohio (Ohio
PUC). On January 3,

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The Potomac Edison Company

2000, the Company's affiliate, Monongahela Power filed a transition
plan with the Ohio PUC, including its claim for recovery of stranded
costs of $21.3 million. The Ohio PUC is expected to hold hearings on
Monongahela Power's transition plan filing and issue a decision by
October 2000.

The Ohio legislation stipulates that an entity independent of the
utilities shall own or control transmission facilities after the
start of competitive retail electric service on January 2001, but
not later than December 31, 2003. Customer protections were kept
intact with a low-income assistance plan and a one-time forgiveness
of past debts for low-income and handicapped customers. In regard
to renewable energy, the bill requires that electric generators
purchase excess electricity from small businesses and homes using
renewable energy sources.

Pennsylvania Activities

In December 1996, Pennsylvania enacted the Electricity Generation
Customer Choice and Competition Act to restructure the electric
industry to create retail access to a competitive electric energy
supply market. On May 29, 1998 (as amended on November 19, 1998),
the Pennsylvania Public Utility Commission granted final approval to
West Penn's restructuring plan. As of January 2, 2000, all
electricity customers in Pennsylvania had the right to choose their
electric suppliers. Two-thirds of all retail customers had a choice
throughout 1999, the first year of retail choice following a pilot
program. The number of customers who have switched suppliers and
the amount of electrical load transferred in Pennsylvania far exceed
that in any other state so far. However, for West Penn, only about
12,700 of its Pennsylvania customers eligible to shop in 1999 have
chosen an alternate energy supplier. West Penn has retained about
98% of its Pennsylvania customers through December 31, 1999. More
than 100 electric generation suppliers have been licensed to sell to
retail customers in Pennsylvania.

Accounting for the Effects of Price Deregulation

In July 1997, the Emerging Issues Task Force (EITF) of the FASB
released Issue No. 97-4, "Deregulation of the Pricing of Electricity
- - Issues Related to the Application of FASB Statement Nos. 71 and
101," which concluded that utilities should discontinue application
of SFAS No. 71 for the generation portion of their business when a
deregulation plan is in place and its terms are known. In accordance
with guidance of EITF Issue No. 97-4, the Company has discontinued
the application of SFAS No. 71 to its electric generation business
in Maryland. See Note C to the financial statements for information
regarding the impact of the Maryland deregulation plan on the 1999
financial statements. The legislation passed in Virginia
established a definitive process for transition to deregulation and
market-based pricing for electric generation. However, the
deregulation plans and their terms in Virginia will not be known
until relevant regulatory proceedings are complete and final orders
are received. The Company is unable to predict the effect of
discontinuing SFAS No. 71 in Virginia, but it may be required to
write off unrecoverable regulatory assets, impaired assets, and
uneconomic commitments. Also the Company is unable to predict the
outcome of the deregulation process in West Virginia until further
actions are taken by the Legislature and the W.Va PSC.

M-57
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The Potomac Edison Company

Environmental Issues

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

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

Title I of the CAAA established an Ozone Transport Commission to
ascertain additional nitrogen oxides (NOx) reductions to allow the
Ozone Transport Region (OTR) to meet the ozone National Ambient Air
Quality Standards (NAAQS). Under terms of a Memorandum of
Understanding (MOU) among the OTR states, the
Company's generating stations located in Maryland and Pennsylvania
were required to reduce NOx emissions by approximately 55% from the
1990 baseline emissions, with a compliance date of May 1999.
Further reductions of 75% from the 1990 baseline may be required by
May 2003 under Phase III of the MOU. However, this reduction will
most likely be superceded by the proposed NOx State Implementation
Plan (SIP) call rule discussed below. If reductions of 75% are
required, installation of post-combustion control technologies would
be very expensive. Pennsylvania and Maryland promulgated regulations
to implement Phase II of the MOU in November 1997 and May 1998,
respectively. However, as a result of litigation, the Maryland
regulation was revised to postpone compliance to May 2000.

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

M-58
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The Potomac Edison Company

In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up to
an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included). The petitions claim NOx
emissions from these upwind sources are preventing their attainment
with the ozone standard. In December 1997, the petitioning states
and the EPA signed a Memorandum of Agreement to address these
petitions in conjunction with the related SIP call. In May 1999,
the EPA issued a technical approval of the petition and in December
1999, granted final approval of four of the petitions. The Section
126 petition rulemaking is also under litigation.

The EPA is required by law to regularly review the NAAQS for
criteria pollutants. Recent court orders in litigation by the
American Lung Association have expedited these reviews. The EPA in
1996 decided not to revise the SO2 and NOx standards. Revisions to
particulate matter and ozone standards were proposed by the EPA in
1996 and finalized in July 1997. However, the revised standards
were legally challenged, and, in May 1999, the District of Columbia
Circuit Court of Appeals remanded the revised standards back to the
EPA for further consideration. Also, in May 1999, the EPA
promulgated final regional haze regulations to improve visibility in
Class I federal areas (national parks and wilderness areas). If
eventually upheld in court, subsequent state regulations could
require additional reduction of SO2 and/or NOx emissions from
Company facilities. The effect on the Company of revision to any of
these standards or regulations is unknown at this time, but could be
substantial.

The final outcome of the revised ambient standards, Phase III of the
MOU, SIP call rule, and Section 126 petitions cannot be determined
at this time. All are being challenged by rulemaking, petition,
and/or the litigation process. Implementation dates are also
uncertain at this time, but could be as early as 2003, which would
require substantial capital expenditures in the 2000 through 2003
period. The Company's construction forecast includes the
expenditure of $103 million of capital costs during the 2000 through
2003 period to comply with the SIP call. In addition, $3 million
was spent in 1999.

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

M-59
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The Potomac Edison Company

raise considerable uncertainty about the future viability of
coal as a fuel source for new and existing power plants. The Company
has taken numerous voluntary, precautionary steps to address the
issue of global climate change.

The Company actively participates in climate-related research
programs and is responsive to the voluntary guidelines suggested in
the national Energy Policy Act of 1992, under Section 1605(b),
directed toward reducing, controlling, avoiding, and sequestering
greenhouse gases. The Company has taken many concrete steps to
reduce greenhouse gases and help stimulate a business climate that
encourages improved efficiency, performance, electrical loss
reductions, and cost-effectiveness.

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

On Earth Day 1997, President Clinton announced the expansion of the
federal Emergency Planning and Community Right-to-Know Act (RTK)
reporting to include electric utilities, limited to facilities that
combust coal and/or oil for the purpose of generating power for
distribution in commerce. The purpose of RTK is to provide site-
specific information on chemical releases to the air, land, and
water. On June 4, 1999, the Allegheny Energy companies (the System)
joined with other members of the Edison Electric Institute in
reporting power station releases to the public. Packets of
information about the System's releases were provided to the news
media in the System's service area and posted on the Parent
Company's web site. The System filed its first RTK-related report
with the EPA in advance of the July 1, 1999, deadline, reporting 18
million pounds of total releases for calendar year 1998.

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The Potomac Edison Company

the Company and its affiliates, Allegheny Energy Supply, and
Monongahela Power. Both Attorneys General stated their intent to
seek injunctive relief and penalties. In addition, the Attorney General
of the State of New York in his letter indicated that he may assert
claims under the State common law of public nuisance seeking to
recover, among other things, compensation for alleged environmental
damage caused in New York by the operation of Fort Martin Power
Station. At this time, Allegheny Energy and its subsidiaries are
not able to determine what effect, if any, these actions threatened
by the Attorneys General of New York and Connecticut may have on
them.

Regional Transmission Organization

In adopting its Rule 2000, the FERC defined requirements for
transmission facility owners to participate in some form of Regional
Transmission Organization. Additionally, the state jurisdictions
within which the Company operates have, to different degrees,
started to define their transition to a competitive marketplace. As
part of this, they have identified transmission as a key link to
making the electricity market efficient. The nature of this issue
is at least regional in scope. As a result, any solution will need
to be one that satisfies a diverse group of stakeholders. The
Company has actively participated in this debate and continues to
evaluate the available options to provide its customers with the
most reliable, cost-effective service while maintaining a clear
focus on the financial interests of its shareholders.

Derivative Instruments and Hedging Activities

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

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; developments in
the legislative, regulatory, and competitive environments in which
West Penn Power Company (the Company) operates, including regulatory
proceedings affecting rates charged by the Company; environmental,
legislative, and regulatory changes; future economic conditions; the
Company's ability to compete in unregulated energy markets; and
other circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather, and
compliance with laws and regulations.

Business Strategy

The energy delivery or wires business will continue to be an
important part of the Company's business. The settlement agreement
in Pennsylvania permitted the Company to transfer its 3,778
megawatts (MW) of generating capacity at net book value to Allegheny
Energy Supply Company, LLC (Allegheny Energy Supply), a new,
unregulated, wholly owned subsidiary of Allegheny Energy, Inc.
(Allegheny Energy), the Company's Parent. The recent settlement in
Maryland will allow approximately 1,300 MW of additional generating
capacity to be ransferred from the Company's affiliate, The Potomac
Edison Company (Potomac Edison) to Allegheny Energy Supply at net
book value in 2000. Allegheny Energy is seeking to transfer the
remaining generating assets in Ohio, Virginia, and West Virginia to
its unregulated subsidiary at book value in deregulation proceedings
in these jurisdictions. The unregulated electric supply is being
sold in both the wholesale and retail competitive marketplaces,
allowing greater earnings growth potential, subject to market
risk, while allowing Allegheny Energy to capitalize on its strengths in the
generation business.

SIGNIFICANT EVENTS IN 1999, 1998, AND 1997

Pennsylvania Deregulation

On November 19, 1998, the Pennsylvania Public Utility Commission
(Pennsylvania PUC) approved a settlement agreement between the Company
and parties to the Company's restructuring proceedings related to
legislation in

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Pennsylvania to provide customer choice of electric suppliers and deregulate
electricity generation.

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

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

See Electric Energy Competition on page 11 for more information regarding
the restructuring in Pennsylvania.

Nonutility Sales of Electricity

Prior to transferring its electric generation assets to Allegheny Energy
Supply, the Company participated in unregulated energy markets as a supplier
of electricity. During 1999, the Company's energy supply business sold
2,234,137 megawatt-hours (MWh) of electricity to customers in deregulated
retail markets and 17,040,799 MWh to customers in deregulated wholesale
markets. Also during 1999, the Company's former generation customers
purchased 2,522,611 MWh of electricity from alternative energy suppliers as
a result of customer choice in Pennsylvania.

Unregulated Generating Affiliate

During 1999, Allegheny Energy obtained the necessary regulatory approvals to
form an unregulated generating subsidiary, Allegheny Energy Supply. On
November 18, 1999, the Company transferred its generating capacity, which
totaled 3,778 MW, to Allegheny Energy Supply at book value as allowed by the
final settlement in the Company's Pennsylvania restructuring case. The
Company continued to be responsible for providing generation to meet the
regulated electric load of its retail customers who did not have the right
to choose their generation supplier until January 2, 2000. During the
period from November 18, 1999, through January 1, 2000, Allegheny Energy
Supply leased back to the Company one-third of its generating assets,
providing the Company with the unlimited right to use those facilities to
serve its regulated load.
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Recapitalization

In 1999, the Company completed the following steps in its recapitalization
process concurrent with the implementation of deregulation of electric
generation in Pennsylvania:

- -- $600 million of transition bonds were issued in November 1999;
- -- $525 million of first mortgage bonds were called or redeemed during the
year;
- -- $79.7 million of preferred stock was called or redeemed in July 1999; and
the Company revised its Articles of Incorporation to provide greater
financial flexibility.

During 1999, the Company reacquired all of its outstanding first mortgage
bonds. As a result, the Company incurred an extraordinary charge of $17.0
million ($10.0 million after taxes) during the fourth quarter of 1999. The
extraordinary charge was the result of premiums paid to reacquire the first
mortgage bonds as compared to the carrying value of the bonds.

PURPA Power Project Terminations

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

Electric Industry Restructuring

See Electric Energy Competition on page 11 for ongoing information regarding
electric industry restructuring.

REVIEW OF OPERATIONS

Earnings Summary

(Millions of Dollars) 1999 1998 1997

Operations:
Utility...................................... $ 98.0 $ 112.6 $134.7
Nonutility................................... 39.6
Consolidated income before extraordinary
charges...................................... 137.6 112.6 134.7
Extraordinary charges, net (Notes B, C, and D
to consolidated financial statements)........ (10.0) (275.4)
Consolidated net income (loss)................. $127.6 $(162.8) $134.7

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The decrease in 1999 earnings from utility operations, before extraordinary
charges, reflects the deregulation of two-thirds of the Company's electric
generation effective January 1, 1999, as approved by the Pennsylvania PUC's
restructuring order. Accordingly, the operating results for these assets
are classified as nonutility in 1999. The 1999 utility operations also
reflects in operation expense the write-off of $6.6 million of costs from
a long dormant pumped-storage generation project. The increase in 1999
earnings, before extraordinary charges, was due primarily to increased
kilowatt-hour (kWh) sales, including increased sales to residential customers
due to winter weather that was cooler than the relatively warm winter of 1998
as measured by heating degree days, and nonutility sales. The decrease in
1998 earnings, before extraordinary charges, reflects $23.7 million of costs,
after taxes, related to the Pennsylvania restructuring settlement.

In 1999, earnings from nonutility operations reflects the sale of generation
from two-thirds of the Company's generation assets as discussed under Sales
and Revenues.

The extraordinary charge in 1999 resulted from the redemption of debt related
to the securitization of stranded costs as discussed in Note D to the
consolidated financial statements. The 1998 extraordinary charge resulted
from the May 1998 restructuring order and November 1998 settlement agreement
as discussed in Notes B and C to the consolidated financial statements.

Sales and Revenues

Total operating revenues for 1999, 1998, and 1997 were as follows:

OPERATING REVENUES:

(Millions of Dollars) 1999 1998 1997

Utility revenues:
Regulated.................................. $ 915.1 $ 995.8 $1,039.1
Choice..................................... 34.3 14.0 2.5
Bulk power................................. 7.5 49.6 22.2
Transmission and other energy services..... 20.3 19.3 18.4
Total utility revenues................... 977.2 1,078.7 1,082.2
Nonutility revenues:
Retail and other........................... 126.6
Bulk power................................. 555.0
Total nonutility revenues................ 681.6*
Elimination between utility and nonutility... (304.6)
Total operating revenues................. $1,354.2 $1,078.7 $1,082.2

*Nonutility operating revenues include $53.5 million in 1999 of allocated
Competitive Transition Charge revenues to compensate for certain transition
costs transferred to nonutility operations.

The decrease in regulated revenues (regulated revenues include revenues from
customers eligible to choose an alternate energy supplier but electing not to

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do so) in 1999 was due primarily to Pennsylvania deregulation, which gave
two-thirds of the Company's regulated customers the ability to choose
another energy supplier. In 1999, 2,522,611 MWh of electric energy was
supplied to the Company's customers by alternative energy suppliers, which
represented only 11% of total MWh sales. The decrease to regulated
revenues was offset in part by colder winter weather in 1999, which led to
increased residential kWh sales and revenues. Utility regulated revenues
in 1998 included a $25.1 million rate refund, pursuant to the terms of the
Pennsylvania restructuring settlement agreement. Excluding this rate
decrease, utility regulated revenues decreased $18.2 million in 1998
primarily due to previously fully bundled customers participating in the
Pennsylvania pilot by buying energy from another supplier of their choice.
As a result of the Company's nonutility affiliate, Allegheny Energy
Solutions, being permitted to sell to all Pennsylvania customers
participating in the pilot, Allegheny Energy was able to recover some of the
Company's generation sales lost as a result of customers participating in
the Pennsylvania pilot program.

Utility choice revenues for 1999 represent transmission and distribution
revenues from franchised customers (customers within the Company's
territory) who chose another supplier to provide their energy needs. In
1999, about 2% of franchised customers chose alternate energy suppliers.
The Company's nonutility supply business had the primary objective of
selling the output from the two-thirds of the Company's generation that
had been freed up by the Electricity Generation Customer Choice and
Competition Act (Customer Choice Act) in Pennsylvania through
November 17, 1999.

In 1998 and 1997, the choice revenues represent the 5% of previously
fully bundled customers (full service customers) who participated in the
Pennsylvania pilot program that began November 1, 1997, and continued
through December 31, 1998, and were required to buy energy from an alternate
supplier. To assure participation in the pilot program, pilot participants
received an energy credit from their local utility and a price for energy
pursuant to an agreement with an alternate supplier. The credit established
by the Pennsylvania PUC was artificially high to encourage customer shopping,
and, as a result, the Company incurred a revenue loss of $8.6 million for
the pilot. The Pennsylvania PUC has approved the Company's pilot compliance
filing and thus has indicated its intent to treat the revenue loss as a
regulatory asset.

Effective May 1, 1997, as a result of the Customer Choice Act, the Company
obtained Pennsylvania PUC authorization to set its fuel clause to zero and
to roll its then-applicable fuel clause rates into base rates. Thereafter,
the Company assumed the risks and benefits of changes in fuel and purchased
power costs and sales of transmission services and bulk power.

The 1999 decrease in revenues from utility bulk power was due to the
movement of generation available for sale from regulated utility to
nonutility operations. The 1998 increase in revenues from utility bulk
power and transmission and other energy services sales was due to increased
sales that occurred primarily in the second quarter as a result of warm
weather which increased the demand and price for energy. In 1998, revenues
from utility transmission and other energy services were affected by a
revenue refund resulting from a reduction in the Company's standard
transmission rate and rates for ancillary services which were approved
by the Federal Energy

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Regulatory Commission (FERC). A provision of $2.9 million for these rate
reductions was recorded in 1998, with the revenues refunded to customers
in the first quarter of 1999.

Revenues from transmission and other energy services increased in 1999 due
primarily to increased MWh's transmitted. Revenues from utility
transmission and other energy services to nonaffiliated companies in 1998
increased, despite decreased transmission services activity. The increase
in revenues was due to transmission services reservation charges paid to
the Company by others for the right to transmit energy.

Nonutility revenues reflect bulk power sales to nonaffiliated companies
and new sales in Pennsylvania's competitive marketplace. The Company's
supply business officially began supplying unregulated electricity to
retail customers in Pennsylvania and wholesale customers throughout
eastern North America on January 1, 1999.

The elimination between utility and nonutility revenues is necessary to
remove the effect of affiliated revenues, primarily sales of power.

See Note B to the consolidated financial statements for information
regarding the Competitive Transition Charge.

Operating Expenses

Fuel expenses for 1999, 1998, and 1997 were as follows:

FUEL EXPENSES:

(Millions of dollars) 1999 1998 1997

Utility operations........................... $ 72.0 $258.2 $254.2
Nonutility operations........................ 141.6
Total fuel expenses........................ $213.6 $258.2 $254.2

Total fuel expenses decreased 17% in 1999 due to an 11% decrease related to
kWhs generated and a 6% decrease in average fuel prices. The decrease in
average fuel prices was due to renegotiated fuel contracts. In 1999, utility
and nonutility fuel expenses reflect the movement of fuel expenses associated
with the two-thirds of the Company's generation transferred from utility
operations to nonutility operations. Also, fuel expenses decreased in 1999
due to the November 18, 1999, transfer of the Company's generating capacity
to its unregulated affiliate, Allegheny Energy Supply.

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

PURCHASED POWER AND EXCHANGES, NET

(Millions of Dollars) 1999 1998 1997

Utility operations:

Purchased power:
From PURPA generation*................ $ 37.5 $ 63.5 $ 65.1
Other................................. 359.8 23.2 18.4
Power exchanges, net.................... .5 (.3) .2
AGC capacity charges.................... 11.6 31.5 32.4
Energy and spinning reserve charges..... 3.5 3.4 3.9
Total utility operations.............. 412.9 121.3 120.0
Nonutility operations purchased power....... 298.4
Elimination................................. (313.1)
Purchased power and exchanges, net........ $ 398.2 $121.3 $120.0

*PURPA cost (cents per kWh) 4.6 5.8 6.0

Utility purchased power from PURPA generation decreased $26 million in 1999.
This decrease reflects an $11.1 million reduction related to the Company's
purchase commitment at costs in excess of the market value of the AES Beaver
Valley PURPA contract. This reduction reflects the amortization of the adverse
purchased power commitment reserve recorded in 1998, which is net of the
Competitive Transition Charge revenue recovery in conjunction with deregulation
proceedings in Pennsylvania. The decrease in purchased power also includes a
$12.5 million reduction in the purchase price for that contract due to a
scheduled capacity rate decrease defined annually in the contract. PURPA
purchased power costs may be reduced by $197 million during the period 1999
through 2016 related to the AES Beaver Valley contract as a result of the 1998
extraordinary charge. See Notes B and C to the consolidated financial
statements for further information.

The increase in other utility operations purchased power in 1999 was due
primarily to the Company's purchase of power from its energy supply business
and its nonutility affiliate, Allegheny Energy Supply, in order to provide
energy to the two-thirds of its customers eligible to choose an alternate
supplier, but who elected not to do so. An increase in market prices caused
by volatility in the spot prices for electricity at the wholesale level in
the second and third quarters of 1998 contributed to the increase in other
utility operations purchased power in 1998.

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The decrease in AGC capacity charges was due to a $16.8 million reduction in
purchased power expense related to the Company's purchase commitments at
costs in excess of the market value of the AGC pumped-storage capacity
contract. As reported previously, the Company, in 1998, recorded an
extraordinary charge to reflect the cost of this and another adverse power
purchase commitment that is not recoverable from customers under the
Pennsylvania PUC's order and settlement agreement.

The nonutility operations purchased power in 1999 was due to the Company's
purchase of power to provide energy to new customers in deregulated markets
who chose the Company as their alternate supplier of electricity.

The elimination between utility and nonutility purchased power is necessary
to remove the effect of affiliated purchased power expenses.

Other operations expenses for 1999, 1998, and 1997 were as follows:

OTHER OPERATION EXPENSES:

(Millions of dollars) 1999 1998 1997

Utility operations............................. $152.5 $173.0 $157.8
Nonutility operations.......................... 49.9
Elimination.................................... (13.8)
Total other operations expenses.............. $188.6 $173.0 $157.8

The increase in total other operation expenses in 1999 of $15.6 million was
primarily due to recording $6.6 million of costs related to a pumped-storage
generation project no longer considered useful, provisions for uninsured
claims of $2.8 million, the reversal of an internal restructuring liability
in the 1998 period of $2.0 million, and increased allowances for uncollectible
accounts of $1.7 million.

The increase in utility other operation expenses in 1998 was due primarily to
increased expenses related to competition and the Pennsylvania restructuring
order ($22.7 million). See Note B to the consolidated financial statements
for additional information related to Pennsylvania restructuring. In 1999,
utility and nonutility other operations expenses reflects the movement of
other operations expenses associated with the two-thirds of the Company's
generation transferred from utility operations to nonutility operations.
The elimination between utility and nonutility operation expenses is
necessary to remove the effect of affiliated transmission purchases.

Maintenance expenses for 1999, 1998, and 1997 were as follows:

MAINTENANCE EXPENSES:

(Millions of dollars) 1999 1998 1997

Utility operations............................. $ 60.2 $ 91.7 $ 98.3
Nonutility operations.......................... 33.2
Total maintenance expenses................... $ 93.4 $ 91.7 $ 98.3

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Total maintenance expenses increased $1.7 million in 1999 due primarily to
increased maintenance and renovations of general plant structures. In 1999,
utility and nonutility maintenance expenses reflect the movement of
maintenance expenses associated with the two-thirds of the Company's
generation transferred from utility operations to nonutility operations.
The decrease in utility maintenance in 1998 was due primarily to a
management program to postpone such expenses for the year in response
to limited sales growth in the first quarter due to the warm winter weather.
The Company postponed these expenses primarily by extending the time between
maintenance outages and experienced no measurable effect on system
performance.

Maintenance expenses represent costs incurred to maintain the power stations,
the transmission and distribution (T&D) system, and general plant, and to
reflect routine maintenance of equipment and rights-of-way, as well as
planned major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the T&D system.
Variations in maintenance expense result primarily from unplanned events and
planned major projects, which vary in timing and magnitude depending upon
the length of time equipment has been in service without a major overhaul
and the amount of work found necessary when the equipment is dismantled.

Depreciation and amortization expenses for 1999, 1998, and 1997 were as
follows:

DEPRECIATION AND AMORTIZATION EXPENSES:

(Millions of dollars) 1999 1998 1997

Utility operations................................ $ 68.7 $114.7 $113.8
Nonutility operations............................. 45.6
Total depreciation and amortization expenses.... $114.3 $114.7 $113.8

Total depreciation and amortization expenses in 1999 remained about the same
as 1998. Depreciation and amortization expenses in 1999 reflect the
amortization of the generation-related regulatory asset related to the
Company's 1998 settlement agreement and reduced depreciation expense due
to the transfer of the Company's generation to Allegheny Energy Supply in
the fourth quarter of 1999. Absent these changes, depreciation expense
would have risen due to increased investments.

Higher utility depreciation expense in 1998 resulted from increased
investment. In 1999, utility and nonutility depreciation expense reflects
the movement of depreciation expense associated with the two-thirds of the
Company's generation transferred from utility operations to nonutility
operations.

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Taxes other than income taxes for 1999, 1998, and 1997 were as follows:

TAXES OTHER THAN INCOME TAXES:

(Millions of dollars) 1999 1998 1997

Utility operations............................... $58.9 $88.7 $90.1
Nonutility operations............................ 21.8
Total taxes other than income taxes............ $80.7 $88.7 $90.1

Total taxes other than income taxes decreased $8.0 million in 1999 primarily
due to reduced West Virginia Business and Occupation Taxes, property tax,
and gross receipts tax related to the transfer of generation assets to
Allegheny Energy Supply on November 18, 1999, and lower capital stock taxes
relating to the 1998 write-down as a result of Pennsylvania
restructuring. Utility and nonutility taxes other than income taxes reflect
the movement of taxes other than income taxes associated with the two-thirds
of the Company's generation transferred from utility operations to
nonutility operations.

The 1999 increase in federal and state income taxes of $7.0 million was
primarily due to increased taxable income offset in part by tax benefits
related to plant removal costs. The decrease in federal and state income
taxes in 1998 of $8.8 million resulted primarily from a decrease in taxable
income, primarily because of costs related to restructuring activities
recorded in 1998. Note E to the consolidated financial statements provides
a further analysis of income tax expenses.

Allowance for other than borrowed funds decreased $.5 million in 1999 due
to adoption in July 1998 of SFAS No. 34, "Capitalizing Interest Costs",
which eliminated this accrual for nonutility generation construction
projects. Capitalized interest is reported with allowance for borrowed
funds used during construction in the consolidated statement of income.
1999 also reflects an increase in construction activity financed by
short-term debt. The allowance for borrowed funds used during
construction component of the formula receives greater weighting when
short-term debt increases. The decrease in allowance for other than
borrowed funds used during construction of $1.5 million in 1998 reflects
lower-cost short-term debt financing. The decrease also reflects
adjustments of prior periods.

The decrease in other income, net, of $1.7 million in 1999 was primarily
due to a decrease in timber sales. The decrease in other income, net, in
1998 of $6.2 million was primarily due to 1997 increases for an interest
refund on a tax-related contract settlement ($3.6 million after taxes)
received by the Company's subsidiary, AGC, and income on the sale of land
($2.8 million after taxes) by the Company's subsidiary, West Virginia
Power and Transmission Company.

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Interest on long-term debt and other interest for 1999, 1998, and 1997 were
as follows:

INTEREST EXPENSE:
(Millions of dollars) 1999 1998 1997

Interest on long-term debt:
Utility operations.............................. $42.9 $61.7 $65.0
Nonutility operations........................... 18.8
Total interest on long-term debt.............. 61.7 61.7 65.0
Other interest
Utility operations.............................. 3.4 5.9 4.6
Nonutility operations........................... 3.6
Total other interest.......................... 7.0 5.9 4.6
Total interest expense...................... $68.7 $67.6 $69.6

The decrease in utility operations interest on long-term debt in 1998 of $3.3
million resulted from reduced long-term debt and lower interest rates. Other
interest expense reflects changes in the levels of short-term debt maintained
by the Company throughout the year, as well as the associated interest rates.

EXTRAORDINARY ITEM

The extraordinary charge in 1999 of $17.0 million ($10.0 million after taxes)
was required to reflect the difference between the reacquisition price and the
net carrying amount of first mortgage bonds repurchased with proceeds from the
sale of transition bonds as a result of the deregulation process in
Pennsylvania. The extraordinary charge in 1998 of $466.9 million ($275.4
million after taxes) was required to reflect a write-off of certain
disallowances in the Pennsylvania PUC's May and November 1998 orders. See
Notes B, C, and D to the consolidated financial statements for additional
information.

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

Liquidity and Capital Requirements

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

Capital expenditures, primarily construction, in 1999 were $114 million and,
for 2000 and 2001, are estimated at $47 million and $43 million,
respectively. It is the Company's goal to constrain future utility
construction spending to the approximate level of depreciation currently in

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rates. The Company also has additional capital requirements for debt
maturities (see Note J to the consolidated financial statements).

Internal Cash Flow

Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $188 million in 1999, compared with $151 million
in 1998. Current rate levels and reduced levels of construction expenditures
permitted the Company to finance all of its construction expenditures in
1999 and 1998 with internal cash flow.

Financing

Short-term debt is used to meet temporary cash needs. The Company had no
short-term debt outstanding at December 31, 1999. At December 31, 1998,
short-term debt outstanding was $65 million, including notes payable to
affiliates.

The Company anticipates meeting its 2000 cash needs through internal cash
generation, cash on hand, and short-term borrowings as necessary. In 1999,
the Company issued $600 million of transition bonds with varying average
lives ranging from one to eight years with a weighted average cost of
6.887% to "securitize" transition costs related to its restructuring
settlement described in Note B to the consolidated financial statements.
During 1999, the Company reacquired all of its outstanding $525 million
of first mortgage bonds.

The Company called or redeemed all outstanding shares of its cumulative
preferred stock with a combined par value of $79.7 million plus redemption
premiums of $3.3 million on July 15, 1999, with proceeds from new
$84-million five-year unsecured medium-term notes issued in the second
quarter at a 6.375% coupon rate. The redemption of the preferred stock
allowed the Company to revise its Articles of Incorporation, providing
greater financial flexibility in restructuring debt.

In April 1999, the Company issued $13.83 million of 5.50% 30-year
pollution control revenue notes to Pleasants County, West Virginia.

In November 1999, the service obligation for $231 million of pollution
control debt was assumed by Allegheny Energy Supply
in conjunction with the transfer of the Company's generating assets to
Allegheny Energy Supply. However, the pollution control debt remains
an obligation of the Company. Allegheny Energy Supply will indemnify the
Company for any debt service the Company may incur.

The Company's aggregate limit of short-term debt financing was increased
in accordance with Securities and Exchange Commission authorization on
October 8, 1999, from $182 million to $500 million through December 31,
2001, related to meeting the requirements of restructuring in
Pennsylvania.

The Company's long-term debt due within one year at December 31, 1999
was $49.7 million of West Penn Funding, LLC, transition bonds due on
various

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dates. The transition bonds are supported by an Intangible Transition
Charge (ITC) that replaces a portion of the Competitive Transition Charge
customers pay. The proceeds from the ITC will be used to pay the principal
and interest on these transition bonds, as well as other associated
expenses.

SIGNIFICANT CONTINUING ISSUES

Electric Energy Competition

The electricity supply segment of the electric utility industry in the
United States is becoming increasingly competitive. The national Energy
Policy Act of 1992 deregulated the wholesale exchange of power within the
electric industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers over their
transmission systems. Since 1992, the wholesale electricity market has
become more competitive as companies are engaging in nationwide power
trading. In addition, an increasing number of states have taken active
steps toward allowing retail customers the right to choose their
electricity supplier. The Company and its parent, Allegheny Energy, have
been advocates of federal legislation to create competition in the retail
electricity markets to avoid regional dislocations and ensure level
playing fields. Legislation before the U.S. Congress to restructure the
nation's electric utility industry cleared an important hurdle on
October 28, 1999, when a House Commerce Committee subcommittee gave its
approval to a bill. The bill will now move on to the full Commerce
Committee where it will be considered in 2000.

In the absence of federal legislation, state-by-state implementation of
deregulation of electric generation is under way. The five states in
which the Company and its affiliates serve customers are at various
stages of implementation or investigation of programs that allow
customers to choose their electric supplier. Pennsylvania is furthest
along with a retail program in place, while Maryland, Ohio, and Virginia
passed legislation in 1999 to implement retail choice. West Virginia
continues to actively study this issue. On December 23, 1999, the
Maryland Public Service Commission (Maryland PSC) approved a settlement
agreement for the Company's affiliate, Potomac Edison, to implement
generation competition in Maryland.

Activities at the Federal Level

Allegheny Energy continues to seek enactment of federal legislation to
bring choice to all retail electric customers, deregulate the generation
and sale of electricity on a national level, and create a more liquid,
free market for electric power. Fully meeting challenges in the emerging
competitive environment will be difficult for Allegheny Energy unless
certain outmoded and anti-competitive laws, specifically the Public
Utility Holding Company Act of 1935 (PUHCA) and Section 210 (Mandatory
Purchase Provisions) of PURPA, are repealed or significantly revised.
Allegheny Energy continues to advocate the repeal of PUHCA and Section
210 of PURPA on the grounds that they are obsolete and anti-competitive
and that PURPA results in utility customers paying above-market prices
for power. H.R. 2944, which was sponsored by U.S. Representative Joe
Barton, was favorably reported out of the House Commerce Subcommittee
on Energy and Power. While the bill does not mandate a date certain
for customer choice, several key provisions favored by the Company are
included in the legislation, including an amendment that allows
existing

M-74

<PAGE>

West Penn Power Company
and Subsidiaries

state restructuring plans and agreements to remain in effect. Other
provisions address important Allegheny Energy priorities by repealing
PUHCA and the mandatory purchase provisions of PURPA. Consensus remains
elusive, with significant hurdles remaining in both houses of Congress.
It is too early to tell whether momentum on the issue will result in
legislation in 2000.

Pennsylvania Activities

In December 1996, Pennsylvania enacted the Customer Choice Act to
restructure its electric industry to create retail access to a competitive
electric energy supply market. On May 29, 1998 (as amended on November 19,
1998), the Pennsylvania PUC granted final approval to the Company's
restructuring plan. As of January 2, 2000, all electricity customers
in Pennsylvania had the right to choose their electric suppliers.
Two-thirds of all retail customers had a choice throughout 1999, the
first year of retail choice following a pilot program. The number of
customers who have switched suppliers and the amount of electrical load
transferred in Pennsylvania far exceed that in any other state so far.
However, for the Company, only about 12,700 of its customers eligible to
shop in 1999 have chosen an alternate energy supplier. The Company has
retained about 98% of its customers through December 31, 1999. More
than 100 electric generation suppliers have been licensed to sell to
retail customers in Pennsylvania.

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

Maryland Activities

On April 8, 1999, Maryland Governor Glendening signed the legislation that
will bring competition to Maryland's electric generation market beginning
July 1, 2000. The Maryland PSC is in the process of implementing the new
law. Final Electric Restructuring Roundtable reports were filed with the
Maryland PSC on May 3, 1999, and legislative style hearings were held this
summer on the reports. Potomac Edison filed testimony in Maryland's
investigation into transition costs, price protection, and unbundled
rates, and a consensus settlement agreement was achieved with no protest
by any of the parties participating in the negotiations. The agreement
was filed on September 23, 1999, and a hearing before the Commission was
held on October 14, 1999. On December 23, 1999, the Maryland PSC issued
an order approving the settlement. Potomac Edison filed an application on
December 15, 1999, to transfer its Maryland generating assets at book
value to an affiliate under Section 7-508 of the Electric Customer Choice
and Competition Act of 1999. A Maryland PSC decision approving the
transfer of the generating assets is due by July 1, 2000.

Ohio Activities

M-75

<PAGE>

West Penn Power Company
and Subsidiaries

period, and residential customers are guaranteed a 5% cut in the
generation portion of their rate. The determination of stranded cost
recovery will be handled by the Public Utilities Commission of Ohio (Ohio
PUC). On January 3, 2000, the Company's affiliate, Monongahela Power
Company (Monongahela Power) filed a transition plan with the Ohio PUC,
including its claim for recovery of stranded costs of $21.3 million. The
Ohio PUC is expected to hold hearings on Monongahela Power's transition
plan filing and issue a decision by October 2000.

The Ohio legislation stipulates that an entity independent of the utilities
shall own or control transmission facilities after the start of competitive
retail electric service on January 1, 2001, but not later than December 31,
2003. Customer protections were kept intact with a low-income assistance
plan and a one-time forgiveness of past debts for low-income and
handicapped customers. In regard to renewable energy, the bill requires
that electric generators purchase excess electricity from small businesses
and homes using renewable energy sources.

Virginia Activities

On March 25, 1999, Governor Gilmore signed the Virginia Electric Utility
Restructuring Act (Restructuring Act) passed by the Virginia General
Assembly. All utilities must submit a restructuring plan by January 1,
2001, to be effective on January 1, 2002. Customer choice will be phased
in beginning on January 1, 2002, with full customer choice by January 1,
2004. The Legislative Transition Task Force on Electric Utility
Restructuring, which was established by the Restructuring Act to oversee
the implementation of customer choice, held hearings in the summer and
fall of 1999 on a number of issues concerning the implementation of retail
competition in Virginia. Parties have also been working with the Virginia
State Corporation Commission Staff to develop the rules governing the
proposed retail pilot programs of other utilities in the state.

West Virginia Activities

In March 1998, legislation was passed by the West Virginia Legislature
that directed the Public Service Commission of West Virginia (W.Va.PSC)
to meet with all interested parties to develop a restructuring plan which
would meet the dictates and goals of the legislation. Interested parties
formed a Task Force that met during 1998, but the Task Force was unable
to reach a consensus on a model for restructuring. The W.Va. PSC held
hearings in August 1999 that addressed certification, licensing, bonding,
reliability, universal service, consumer protection, code of conduct,
subsidies, and stranded costs. The W.Va. PSC on December 20, 1999
released for comment and hearings a modified version of a proposal
submitted by members of the Task Force, including Monongahela Power and
Potomac Edison, following the August 1999 hearings that could open full
retail competition as early as January 1, 2001. The production of power
would be deregulated and electricity rates would be frozen for four years
with rates gradually transitioning to market rates over the six years
thereafter. After hearings in January 2000, the W.Va. PSC submitted a
restructuring plan endorsed by members of the Task Force, including
Monongahela Power and Potomac Edison, to the Legislature for approval.

M-76

<PAGE>

West Penn Power Company
and Subsidiaries

Accounting for the Effects of Price Deregulation

In July 1997, the Emerging Issues Task Force (EITF) of the FASB released
Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues
Related to the Application of FASB Statement Nos. 71 and 101," which
concluded that utilities should discontinue application of SFAS No. 71
for the generation portion of their business when a deregulation plan is
in place and its terms are known. In accordance with guidance of EITF
Issue No. 97-4, the Company has discontinued the application of SFAS
No. 71 to its electric generation business in 1998.

Environmental Issues

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

The Company previously reported that the Environmental Protection Agency
had identified the Company and its regulated utility affiliates as
potentially responsible parties, along with approximately 175 others, in
a Superfund site subject to cleanup. A final determination has not been
made for the Company's share of the remediation costs based on the amount
of materials sent to the site. The Company and its regulated affiliates
have also been named as defendants along with multiple other defendants
in pending asbestos cases involving one or more plaintiffs. The Company
believes that provisions for liability and insurance recoveries are such
that final resolution of these claims will not have a material effect on
its financial position. A reserve previously recorded by the Company
related to the asbestos cases was transferred to Allegheny Energy Supply
as part of the transfer of the Company's deregulated generating capacity.
(See Note O to the consolidated financial statements for additional
information)

Regional Transmission Organization

In adopting its Rule 2000, the FERC defined requirements for transmission
facility owners to participate in some form of Regional Transmission
Organization. Additionally, the state jurisdictions within which the
Company and its utility affiliates operate have, to different degrees,
started to define their transition to a competitive marketplace. As
part of this, they have identified transmission as a key link to making
the electricity market efficient. The nature of this issue is at least
regional in scope. As a result, any solution will need to be one that
satisfies a diverse group of stakeholders. Allegheny Energy has actively
participated in this debate and continues to evaluate the available
options to provide its customers with the most reliable, cost-effective
service while maintaining a clear focus on the financial interests of
its shareholders.

M-77

<PAGE>

West Penn Power Company
and Subsidiaries

Derivative Instruments and Hedging Activities

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Company will be required to
recognize derivatives as defined by SFAS No. 133 on the balance sheet at
fair value. The Company is evaluating the effect of adopting SFAS No. 133
on its results of operations and financial position which will be completed
during the year 2000. Accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and whether the
instrument meets the requirements for designation as a hedge. The Company
expects to adopt SFAS No. 133 no later than January 1, 2001.

M-78

<PAGE>

Allegheny Generating Company

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

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

Factors that could cause actual results to differ materially include,
among other matters, electric utility restructuring, including ongoing state
and federal activities; developments in the legislative, regulatory, and
competitive environments in which Allegheny Generating Company (the Company)
operates, including regulatory proceedings affecting rates charged by the
Company; environmental, legislative, and regulatory changes; future economic
conditions; and other circumstances that could affect anticipate
scheduled maintenance or repair requirements and compliance with laws and
regulations.

SIGNIFICANT EVENTS IN 1999, 1998, AND 1997

On November 19, 1998, the Pennsylvania Public Utility Commission
(Pennsylvania PUC) approved a settlement agreement between West Penn
Power Company (West Penn) and parties to West Penn's restructuring
proceedings related to legislation in Pennsylvania to provide customer
choice of electric suppliers and deregulate electricity generation.
Two-thirds of all retail customers in Pennsylvania had the right to
choose their electric supplier throughout 1999. As of January 2000,
all Pennsylvania customers have a choice.

The terms of the settlement agreement permitted West Penn to transfer
its generating assets to a separate legal entity at book value,
contingent upon other regulatory approvals. During 1999, Allegheny
Energy obtained the necessary regulatory approvals and formed an
unregulated generating subsidiary, Allegheny Energy Supply Company,
LLC (Allegheny Energy Supply). On November 18, 1999, West Penn
transferred its deregulated generating capacity, which included its
45% ownership share in the common stock of the Company, to Allegheny
Energy Supply.

West Penn continued to be responsible for providing generation to meet
the regulated electric load of their retail customers who did not have
the legal right to choose their generation supplier until January 2,
2000. During the period from November 18, 1999 through January 1, 2000,
Allegheny Energy Supply leased back to West Penn one-third of its
generating assets, including one-third of its 45% ownership share in
the Company, providing West Penn with the unlimited right to use those
facilities to serve its regulated load.

M-79

<PAGE>
Allegheny Generating Company

REVIEW OF OPERATIONS

As described under Liquidity and Capital Requirements, revenues are
determined under a cost-of-service formula rate schedule. Revenues
are expected to decrease each year due to a normal continuing reduction
in the Company's net investment in the Bath County station and its
connecting transmission facilities upon which the return on investment
is determined. The net investment (primarily net plant less deferred
income taxes) decreases to the extent that provisions for depreciation
and deferred income taxes exceed net plant additions. Revenues for 1999
and 1998 decreased due to a reduction in net investment.

The decreases in operating expenses in 1999 and 1998 resulted from
decreases in federal income taxes due to decreases in operating income
before taxes, and in 1998 also due to a decrease in operation and
maintenance expense.

Effective June 1, 1995, the Federal Energy Regulatory Commission (FERC)
gave approval for the Company to add a prior tax payment of approximately
$12 million to rate base. In September 1997, the Company received a
tax-related contract settlement of $8.8 million of taxes related to the $12
million added to rate base in 1995. The 1997 settlement amount was
recorded as a reduction to plant and was removed from rate base.

The decrease in other income, net in 1998 was due to interest recorded in
1997 on the refund on the tax-related contract settlement (see above).

The decreases in interest on long-term debt in 1999 and 1998 resulted from
reduced average long-term debt outstanding.

The increases in other interest expense in 1999 and 1998 were due to an
increased level of short-term debt maintained by the Company upon retirement
of medium-term debt.

LIQUIDITY AND CAPITAL REQUIREMENTS

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

Pursuant to an agreement, Monongahela Power Company, The Potomac Edison
Company (Potomac Edison), and Allegheny Energy Supply (the Parents), buy all
of the Company's capacity in the station priced under a "cost-of-service
formula" wholesale rate schedule approved by the FERC. Under this arrangement,
the Company recovers in revenues all of its operation and maintenance
expenses, depreciation, taxes, and a return on its investment. Effective
November 18, 1999, West Penn transferred its 45% ownership share in the
Company to Allegheny Energy Supply. On December 29, 1998, the FERC issued
an Order accepting a proposed amendment to the Parent's Power Supply
Agreement for the Company effective January 1, 1999. This amendment sets
the generation demand for each Parent proportional to its ownership in the
Company. Previously, demand for each Parent fluctuated due to customer usage.

The Company's rates are set by a formula filed with and previously accepted by
the FERC. The only component which changes is the return on equity (ROE).

M-80

<PAGE>
Allegheny Generating Company

Pursuant to a settlement agreement filed with and approved by the FERC, the
Company's ROE is set at 11% and will continue at that rate unless any affected
party seeks a change.

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

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

SIGNIFICANT CONTINUING ISSUES

Maryland Deregulation

On September 23, 1999, a settlement agreement between Potomac Edison, the
Staff of the Maryland Public Service Commission (Maryland PSC), and other
parties working to implement customer choice and deregulation of electric
generation for Potomac Edison in Maryland was filed with the Maryland PSC.
On December 23, 1999, the Maryland PSC issued an order approving the
settlement agreement. Potomac Edison filed an application on December 15,
1999, to transfer its Maryland generating assets at book value to a
nonutility affiliate under Section 7-508 of the Electric Customer Choice
and Competition Act of 1999. A Maryland PSC decision approving the
transfer of the generating assets is due by July 1, 2000.

It is anticipated that an allocated portion of each of Potomac Edison's
generating assets, corresponding to deregulated service for Maryland
customers, will be transferred to Allegheny Energy Supply in 2000. A 62%
portion of each of Potomac Edison's generating assets has been allocated
to the Maryland jurisdiction, including 62% of Potomac Edison's 28%
ownership share in the common stock of the Company.

M-81

<PAGE>
49

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements

Index

Monon- Potomac West
AE gahela Edison Penn AGC

Report of Independent Accountants F-1 F-30 F-47 F-66 F-92

Statement of Income for
the three years ended
December 31, 1999 F-2 F-31 F-48 F-67 F-93

Statement of Retained Earnings
for the three years ended
December 31, 1999 - F-31 F-48 F-68 F-93

Statement of Cash Flows for
the three years ended
December 31, 1999 F-3 F-32 F-49 F-69 F-94

Balance Sheet at December 31,
1999 and 1998 F-4 F-33 F-50 F-71 F-95

Statement of Capitalization at
December 31, 1999 and 1998 F-6 F-34 F-51 F-73 -

Statement of Common Equity for
the three years ended
December 31, 1999 F-7 - - - -

Notes to financial statements F-8 F-34 F-52 F-75 F-96

Financial Statement Schedules -
Schedules for the three years
ended December 31, 1999 50 50 50 50 50

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

<PAGE>

Allegheny Energy, Inc.

REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the accompanying consolidated balance sheets, consolidated
statements of capitalization and of common equity and the related consolidated
statements of income and of cash flows present fairly, in all material respects,
the financial position of Allegheny Energy, Inc. and its subsidiaries at
December 31, 1999 and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.
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
auditing standards generally accepted in the United States, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.

PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania

February 3, 2000

F-1

Allegheny Energy, Inc.

CONSOLIDATED STATEMENT OF INCOME
Allegheny Energy, Inc.

Year ended December 31 1999 1998 1997
- --------------------------------------------------------------------------------------------
(Thousands of dollars except per share data)

Operating revenues:*
<S> <C> <C> <C>
Utility $2,273,727 $2,329,450 $2,283,697
Nonutility 534,714 246,986 85,794
- --------------------------------------------------------------------------------------------
Total operating revenues 2,808,441 2,576,436 2,369,491
- --------------------------------------------------------------------------------------------

Operating expenses:
Operation:
Fuel 535,674 566,453 559,939
Purchased power and exchanges, net 531,431 388,758 219,837
Deferred power costs, net 41,577 (6,639) (22,916)
Other 389,406 337,440 308,991
Maintenance 223,538 217,559 230,602
Depreciation and amortization 257,456 270,379 265,750
Taxes other than income taxes 190,271 194,583 186,978
Federal and state income taxes 164,441 168,396 168,073
- --------------------------------------------------------------------------------------------

Total operating expenses 2,333,794 2,136,929 1,917,254
- --------------------------------------------------------------------------------------------

Operating income 474,647 439,507 452,237
- --------------------------------------------------------------------------------------------

Other income and deductions:
Allowance for other than borrowed
funds used during construction 1,840 1,553 4,393
Other income, net 1,605 8,180 18,016
- --------------------------------------------------------------------------------------------

Total other income and deductions 3,445 9,733 22,409
- --------------------------------------------------------------------------------------------

Income before interest charges,
preferred dividends,
preferred redemption premiums,
and extraordinary charge, net 478,092 449,240 474,646
- --------------------------------------------------------------------------------------------

Interest charges, preferred dividends,
and preferred redemption premiums:
Interest on long-term debt 155,198 161,057 173,568
Other interest 31,612 19,395 14,409
Allowance for borrowed funds used
during construction and interest capitalized (5,070) (3,471) (3,907)
Dividends on preferred stock of subsidiaries 7,183 9,251 9,280
Redemption premiums on preferred stock of subsidiaries 3,780
- --------------------------------------------------------------------------------------------

Total interest charges, preferred dividends,
and preferred redemption premiums 192,703 186,232 193,350
- --------------------------------------------------------------------------------------------
Consolidated income before extraordinary charge 285,389 263,008 281,296
Extraordinary charge, net (26,968) (275,426)
- --------------------------------------------------------------------------------------------

Consolidated net income (loss) $ 258,421 $ (12,418) $ 281,296
- --------------------------------------------------------------------------------------------

Common stock shares outstanding (average) 116,237,443 122,436,317 122,208,465
Basic and diluted earnings per average share:
Consolidated income before extraordinary charge $ 2.45 $ 2.15 $ 2.30
Extraordinary charge, net (.23) (2.25)
- --------------------------------------------------------------------------------------------

Consolidated net income (loss) $ 2.22 $ (.10) $ 2.30
- --------------------------------------------------------------------------------------------

</TABLE>

*Excludes intercompany sales between utility and nonutility.
See accompanying notes to consolidated financial statements.

F-2

<PAGE>

Allegheny Energy, Inc.

CONSOLIDATED STATEMENT OF CASH FLOWS
Allegheny Energy, Inc.

Year ended December 31 1999 1998* 1997*
- --------------------------------------------------------------------------------------------

(Thousands of dollars)

Cash flows from operations:
<S> <C> <C> <C>
Consolidated net income (loss) $ 258,421 $ (12,418) $ 281,296
Extraordinary charge, net of taxes 26,968 275,426
- --------------------------------------------------------------------------------------------

Consolidated income before extraordinary charge 285,389 263,008 281,296
Depreciation and amortization 257,456 270,379 265,750
Amortization of adverse purchase power contract (11,146)
Deferred revenues 34,849
Deferred investment credit and income taxes, net 40,035 20,998 66,362
Deferred power costs, net 41,577 (6,639) (22,916)
Allowance for other than
borrowed funds used during construction (1,840) (1,553) (4,393)
Internal restructuring liability (5,504) (50,597)
PURPA project buyout (48,000)
Write-off of merger-related and generation project costs 35,862
Changes in certain assets and liabilities:
Accounts receivable, net (77,679) 15,365 (6,052)
Materials and supplies 2,209 (12,852) (1,385)
Accounts payable 80,224 23,118 (17,172)
Taxes accrued 7,798 14,312 (3,653)
Benefit plans' investments (6,700) (7,994) (16,277)
Prepayments (19,158)
Restructuring settlement rate refund (25,100)
Other, net (25,516) 18,544 35,663
- ---------------------------------------------------------------------------------------------
618,260 591,182 478,626
- ---------------------------------------------------------------------------------------------
Cash flows from investing:
Utility construction expenditures
(less allowance for other than
borrowed funds used during construction) (264,365) (227,809) (280,255)
Nonutility construction expenditures and investments (147,160) (6,205) (829)
Acquisition of businesses (98,714)
- ---------------------------------------------------------------------------------------------

(510,239) (234,014) (281,084)
- ---------------------------------------------------------------------------------------------

Cash flows from financing:
Sale of common stock 16,706
Repurchase of common stock (398,407)
Retirement of preferred stock (96,086)
Issuance of long-term debt 824,143 211,952
Retirement of long-term debt (555,000) (419,780) (46,892)
Funds on deposit with trustees and restricted funds (13,279)
Short-term debt, net 382,258 52,436 49,971
Cash dividends paid on common stock (203,225) (210,591) (210,195)
- ---------------------------------------------------------------------------------------------

(59,596) (365,983) (190,410)
- ---------------------------------------------------------------------------------------------

Net change in cash and temporary cash investments 48,425 (8,815) 7,132
Cash and temporary cash investments at January 1 17,559 26,374 19,242
- --------------------------------------------------------------------------------------------

Cash and temporary cash investments at December 31 $ 65,984 $ 17,559 $ 26,374
- ---------------------------------------------------------------------------------------------

Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $ 170,498 $ 171,719 $ 178,121
Income taxes 124,180 145,053 108,519
- ---------------------------------------------------------------------------------------------

</TABLE>

See accompanying notes to consolidated financial statements.
*Certain amounts have been reclassified for comparative purposes.

F-3

<PAGE>

Allegheny Energy, Inc.

CONSOLIDATED BALANCE SHEET
Allegheny Energy, Inc.

As of December 31 1999 1998*
- --------------------------------------------------------------------------------------------

(Thousands of dollars)

ASSETS

Property, plant, and equipment:
<S> <C> <C>
Utility plant $ 6,547,533 $8,041,628
Nonutility plant 2,060,423 187,309
Construction work in progress 231,763 166,330
- --------------------------------------------------------------------------------------------

8,839,719 8,395,267
Accumulated depreciation (3,632,568) (3,395,603)
- --------------------------------------------------------------------------------------------

5,207,151 4,999,664

Investments and other assets:
Excess of cost over net assets acquired 42,584 15,077
Benefit plans' investments 94,168 87,468
Nonutility investments 15,252 9,361
Other 1,479 1,566
- --------------------------------------------------------------------------------------------

153,483 113,472

Current assets:
Cash and temporary cash investments 65,984 17,559
Accounts receivable:
Electric service 383,316 294,877
Other 12,273 17,712
Allowance for uncollectible accounts (26,975) (19,560)
Materials and supplies--at average cost:
Operating and construction 92,560 99,439
Fuel 62,280 57,610
Prepaid taxes 58,190 56,658
Deferred income taxes 30,477 21,868
Other, including current portion of regulatory assets 31,205 30,788
- --------------------------------------------------------------------------------------------

709,310 576,951
Deferred charges:
Regulatory assets 663,847 704,506
Unamortized loss on reacquired debt 41,825 48,671
Other 76,825 91,931
- --------------------------------------------------------------------------------------------

782,497 845,108
- --------------------------------------------------------------------------------------------

Total $ 6,852,441 $6,535,195
- --------------------------------------------------------------------------------------------

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital,
retained earnings, less treasury stock (at cost) $ 1,695,325 $ 2,033,889
Preferred stock 74,000 170,086
Long-term debt and QUIDS 2,254,463 2,179,288
- --------------------------------------------------------------------------------------------

4,023,788 4,383,263
Current liabilities:
Short-term debt 641,095 258,837
Long-term debt due within one year 189,734
Accounts payable 233,331 153,107
Taxes accrued:
Federal and state income 20,699 17,442
Other 67,292 62,751
Interest accrued 34,979 35,945
Adverse power purchase commitments 24,895 22,622
Other, including current portion of regulatory liabilities 96,510 101,239
- --------------------------------------------------------------------------------------------

1,308,535 651,943

F-4

<PAGE>

Deferred credits and other liabilities:
Unamortized investment credit 116,971 125,396
Deferred income taxes 920,943 882,779
Regulatory liabilities 78,743 80,354
Adverse power purchase commitments 303,935 328,830
Other 99,526 82,630
- --------------------------------------------------------------------------------------------

1,520,118 1,499,989
Commitments and contingencies (Note P)
Total $ 6,852,441 $6,535,195
- --------------------------------------------------------------------------------------------

</TABLE>

*Certain amounts have been reclassified for comparative purposes.
See accompanying notes to consolidated financial statements.

F-5

<PAGE>

Allegheny Energy, Inc.

CONSOLIDATED STATEMENT OF CAPITALIZATION
Allegheny Energy, Inc.

Thousands of dollars Capitalization
ratios
As of December 31 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------

Common stock:
<S> <C> <C> <C> <C>
Common stock of Allegheny Energy, Inc.--
$1.25 par value per share,
260,000,000 shares authorized,
122,436,317 shares issued,
110,436,317 shares outstanding $ 153,045 $ 153,045
Other paid-in capital 1,044,085 1,044,085
Retained earnings 896,602 836,759
Treasury stock (at cost)--
12,000,000 shares (398,407)
- --------------------------------------------------------------------------------------------

Total 1,695,325 2,033,889 42.1% 46.4%
- --------------------------------------------------------------------------------------------

</TABLE>

Preferred stock of subsidiaries-cumulative, par value
$100 per share, authorized 38,878,611 shares:

<TABLE>
<CAPTION>
December 31, 1999
--------------------------------
Shares Regular Call Price
Series Outstanding Per Share
- ---------------------------------------------
<S> <C> <C> <C> <C> <C>
4.40-4.80% 190,000 $103.50 to $106.50 19,000 65,086
$5.88-$7.73 550,000 $100.00 to $102.86 55,000 65,000
Auction 40,000
- --------------------------------------------------------------------------------------------

Total (annual dividend requirements $5,037) 74,000 170,086 1.9% 3.9%
- --------------------------------------------------------------------------------------------

</TABLE>

Long-term debt and QUIDS of subsidiaries:

First mortgage bonds: December 31, 1999
Maturity Interest Rate--%
- ---------------------- ---------------------

<S> <C> <C> <C> <C>
2000 5 5/8 - 5 7/8 140,000 140,000
2002-2004 7 3/8 25,000 175,000
2006-2007 7 1/4 - 8 75,000 120,000
2021-2025 7 5/8 - 8 5/8 480,000 810,000

Transition bonds due 2000-2008 6.32 - 6.98 600,000
Debentures due 2003-2023 5 5/8 - 6 7/8 150,000 150,000
Quarterly Income Debt
Securities due 2025 8.00 155,457 155,457
Secured notes due 2003-2029 4.70 - 6.875 399,130 368,300
Unsecured notes due 2002-2012 4.35 - 5.10 23,695 23,695
Installment purchase
obligations due 2003 4.50 19,100 19,100
Medium-term debt due 2001-2010 5.56 - 7.36 401,025 237,025
Unamortized debt discount and premium, net (13,937) (19,289)
- --------------------------------------------------------------------------------------------

Total (annual interest requirements $165,938) 2,454,470 2,179,288
- --------------------------------------------------------------------------------------------

Less amounts on deposit with trustees (10,273)
Less current maturities (189,734)
- --------------------------------------------------------------------------------------------

Total 2,254,463 2,179,288 56.0% 49.7%
- --------------------------------------------------------------------------------------------

Total capitalization $4,023,788 $4,383,263 100.0% 100.0%
- --------------------------------------------------------------------------------------------

</TABLE>

See accompanying notes to consolidated financial statements.

F-6

<PAGE>

Allegheny Energy, Inc.

CONSOLIDATED STATEMENT OF COMMON EQUITY
Allegheny Energy, Inc.

Thousands of Dollars
-------------------------------------------------

Other Retained Total
Shares Common Paid-In Earnings Treasury Common
Year ended December 31 Outstanding Stock Capital (Note H) Stock Equity
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1997 121,840,327 $ 152,300 $1,028,124 $988,667 $2,169,091
- -----------------------------------------------------------------------------------------------------------
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan, Employee Stock
Ownership and Savings Plan,
and Performance Share Plan 595,990 745 15,961 16,706
Consolidated net income 281,296 281,296
Dividends on common stock of
the Company (declared) (210,195) (210,195)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 122,436,317 $ 153,045 $1,044,085 $1,059,768 $2,256,898
- -----------------------------------------------------------------------------------------------------------
Consolidated net loss (12,418) (12,418)
Dividends on common stock of the
Company (declared) (210,591) (210,591)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 122,436,317 $ 153,045 $1,044,085 $836,759 $2,033,889
- -----------------------------------------------------------------------------------------------------------
Consolidated net income 258,421 258,421
Treasury stock (12,000,000) $(398,407) (398,407)
Dividends on common stock
of the Company (declared) (198,578) (198,578)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 110,436,317 $ 153,045 $1,044,085 $896,602 $(398,407) $1,695,325
- -----------------------------------------------------------------------------------------------------------
</TABLE>

See accompanying notes to consolidated financial statements.

F-7

<PAGE>

Allegheny Energy, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Allegheny Energy, Inc.

(These notes are an integral part of the consolidated financial statements.)

NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Allegheny Energy, Inc. (the Company) is a utility holding company and its
principal business segments are utility and nonutility operations. The utility
subsidiaries, Monongahela Power Company (Monongahela Power), The Potomac Edison
Company (Potomac Edison), and West Penn Power Company (West Penn), collectively
now doing business as Allegheny Power, are engaged in the generation (except
West Penn), purchase, transmission, distribution, and sale of electric energy
and are subject to federal and state regulation including the Public Utility
Holding Company Act of 1935 (PUHCA). The markets for the subsidiaries' regulated
electric retail sales are in Pennsylvania, West Virginia, Maryland, Virginia,
and Ohio. In 1999, revenues from the 50 largest electric utility customers
provided approximately 15% of the consolidated retail revenues. Nonutility
operations consist of the Company's unregulated energy supply business, with the
primary objective of selling electricity into the competitive marketplace, and
Allegheny Ventures, Inc. (Allegheny Ventures), a wholly owned subsidiary which
develops new business opportunities, with an emphasis on telecommunications and
energy-related products and services. Unregulated energy supply includes the
Company's existing generation as deregulation is implemented in the five states
where the Company's traditional utility business has operated and new generating
capacity to be constructed or acquired by the Company. In November 1999, the
Company formed Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), a
wholly owned nonutility generating subsidiary, to consolidate its unregulated
energy supply business.

Allegheny Energy Supply was formed when West Penn transferred its deregulated
generating capacity of 3,778 megawatts (MW) at book value to Allegheny Energy
Supply, as allowed by the final settlement in West Penn's Pennsylvania
restructuring case. Allegheny Energy Supply also purchased from AYP Energy, Inc.
(AYP Energy) its 276 MW of merchant capacity at Fort Martin Unit No. 1.

The Company's nonutility subsidiaries operate primarily in the Mid-Atlantic
region. In 1999, 82% of nonutility revenues were from bulk power sales.
Nonutility operations may be subject to federal regulation, but are not subject
to state regulation of rates.

See Note B for significant changes in the Pennsylvania and Maryland regulatory
environment. Certain amounts in the December 31, 1998, consolidated balance
sheet and in the December 31, 1998, and 1997 consolidated statement of cash
flows have been reclassified for comparative purposes. 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.

F-8

<PAGE>
Allegheny Energy, Inc.

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. Revenues from nonutility
activities are recorded in the period earned.

Deferred Power Costs, Net The costs of fuel, purchased power, and certain other
costs, and revenues from sales to other utilities and power marketers, including
transmission services, are deferred until they are either recovered from or
credited to customers under fuel and energy cost-recovery procedures in
Maryland, Ohio, Virginia, and West Virginia. West Penn discontinued this
practice in Pennsylvania, effective May 1, 1997, and Potomac Edison will
discontinue this practice in Maryland, effective July 1, 2000.

Property, Plant, and Equipment Utility property, plant, and equipment are
stated at original cost, less contributions in aid of construction, except for
capital leases, which are recorded at present value. Costs include direct labor
and material; allowance for funds used during construction on utility property
for which construction work in progress is not included in rate base; and
indirect costs such as administration, maintenance, and depreciation of
transportation and construction equipment, postretirement benefits, taxes, and
other benefits related to employees engaged in construction.

The cost of depreciable utility property units retired, plus removal costs less
salvage, are charged to accumulated depreciation by the utility subsidiaries
that apply the Financial Accounting Standards Board's (FASB) Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation."

Nonutility property, plant, and equipment are stated at original cost for self-
constructed assets. Property acquired from others is stated at fair market value
when acquired. West Penn transferred its deregulated generation plant to
Allegheny Energy Supply at book value. Nonutility property is depreciated by the
straight-line method over its estimated useful life.

For the nonutility subsidiaries, the cost and accumulated depreciation of
property, plant, and equipment retired or otherwise disposed of are removed from
related accounts and included in the determination of the gain or loss on
disposition.

The Company capitalizes the cost of software developed for internal use. These
costs are amortized on a straight-line basis over a five-year period beginning
upon a project's completion.

Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest
AFUDC, an item that does not represent current cash income, is defined in

F-9

<PAGE>
Allegheny Energy, Inc.

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 utility
subsidiaries as a cost of utility property, plant, and equipment. Rates used by
the utility subsidiaries for computing AFUDC in 1999, 1998, and 1997 averaged
6.83%, 7.78%, and 8.59%, respectively.

For nonutility construction, which began after January 1, 1998, the Company
capitalizes interest costs in accordance with SFAS No. 34, "Capitalizing
Interest Costs." The interest capitalization rates in 1999 and 1998 were 7.14%
and 7.45%, respectively.

Depreciation and Maintenance Depreciation expense is determined generally on a
straight-line method based on estimated service lives of depreciable properties
and amounted to approximately 3.2% of average depreciable property in 1999 and
3.3% in each of the years 1998 and 1997. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.

Investments The Company records the acquisition cost in excess of net assets
acquired as an investment in goodwill. Goodwill recorded prior to 1966 is not
being amortized because, in management's opinion, there has been no reduction in
its value. Goodwill related to the acquisition of West Virginia Power Company in
December 1999 will be amortized over 40 years.

Benefit plans' investments primarily represent the estimated cash surrender
values of purchased life insurance on qualifying management employees under
executive life insurance and supplemental executive retirement plans.

Temporary Cash Investments For purposes of the consolidated statement of cash
flows, temporary cash investments with original maturities of three months or
less, generally in the form of commercial paper, certificates of deposit, and
repurchase agreements, are considered to be the equivalent of cash.

Regulatory Assets and Liabilities In accordance with SFAS No. 71, the Company's
consolidated financial statements include certain assets and liabilities
resulting from cost-based ratemaking regulation.

Income Taxes Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions for tax
purposes are recorded in the financial income statement in another period.
Deferred tax assets and liabilities represent the tax effect of temporary
differences between the financial statement and tax basis of assets and
liabilities computed using the most current tax rates.

The Company has deferred the tax benefit of investment tax credits. Investment
tax credits are amortized over the estimated service lives of the related
properties.

Postretirement Benefits The Company's subsidiaries have a noncontributory,
defined benefit pension plan covering substantially all employees, including
officers. Benefits are based on the employee's years of service and

F-10

<PAGE>
Allegheny Energy, Inc.

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. Plan assets consist of
equity securities, fixed income securities, short-term investments, and
insurance contracts.

The Company's subsidiaries also provide partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical benefits, which
make up the largest component of the plans, are based upon an age and years-of-
service vesting schedule and other plan provisions. Subsidized medical coverage
is not provided in retirement to employees hired on or after January 1, 1993.
The funding policy is to contribute the maximum amount that can be deducted for
federal income tax purposes. Funding of these benefits is made primarily into
Voluntary Employee Beneficiary Association trust funds. Medical benefits are
self-insured. The life insurance plan is paid through insurance premiums.

Comprehensive Income SFAS No. 130, "Reporting Comprehensive Income," effective
for 1998, established standards for reporting comprehensive income and its
components (revenues, expenses, gains, and losses) in the financial statements.
The Company does not have any elements of other comprehensive income to report
in accordance with SFAS No. 130.

NOTE B: INDUSTRY RESTRUCTURING

Maryland Deregulation On September 23, 1999, Potomac Edison filed a settlement
agreement (covering its stranded cost quantification mechanism, price
protection mechanism, and unbundled rates) with the Maryland Public Service
Commission (Maryland PSC). The agreement was signed by all parties active in
the case, except Eastalco, which stated that it would not oppose it. The
settlement agreement, which was approved by the Maryland PSC on December 23,
1999, includes the following provisions:

- -- The ability for nearly all of our 211,000 Maryland customers to have the
option of choosing an electric generation supplier starting July 1, 2000.

- -- The transfer of Potomac Edison's Maryland jurisdictional generating assets
to a nonutility affiliate at book value as of July 1, 2000.

- -- A reduction in base rates of 7% ($10.4 million each year totaling $72.8
million) for residential customers from 2002 through 2008. A reduction in
base rates of one-half of 1% ($1.5 million each year totaling $10.5 million)
for the majority of commercial and industrial customers from 2002 through
2008.

- -- Standard Offer Service (provider of last resort) will be provided to
residential customers during a transition period from July 1, 2000,
to December 31, 2008, and to all other customers during a transition p