Exhibit 99.1

October 24-27, 2004

Allegheny Energy, Inc.

Edison Electric Institute
Financial Conference

Forward-Looking Statements

In addition to historical information, this presentation contains a number of "forward-looking statements" as
defined in the Private Securities Litigation Reform Act of 1995.  Words such as anticipate, expect, project, intend,
plan, believe, and words and terms of similar substance used in connection with any discussion of future plans,
actions, or events identify forward-looking statements.  These include statements with respect to: regulation and
the status of retail generation service supply competition in states served by Allegheny Energy's delivery
business, Allegheny Power; the closing of various agreements; execution of restructuring activity and liquidity
enhancement plans; results of litigation; financing requirements and plans to meet those requirements; demand
for energy and the cost and availability of inputs; demand for products and services; capacity purchase
commitments; results of operations; capital expenditures; regulatory matters; internal controls and procedures
and outstanding financial reporting obligations; and stockholder rights plans. Forward-looking statements
involve estimates, expectations, and projections and, as a result, are subject to risks and uncertainties.  There
can be no assurance that actual results will not materially differ from expectations.  Factors that could cause
actual results to differ materially include, among others, the following: execution of restructuring activity and
liquidity enhancement plans; complications or other factors that render it difficult or impossible to obtain
necessary lender consents or regulatory authorizations on a timely basis; general economic and business
conditions; changes in access to capital markets; the continuing effects of global instability, terrorism, and war;
changes in industry capacity, development, and other activities by Allegheny's competitors; changes in the
weather and other natural phenomena; changes in technology; changes in the price of power and fuel for electric
generation; the results of regulatory proceedings, including those related to rates; changes in the underlying
inputs, including market conditions, and assumptions used to estimate the fair values of commodity contracts;
changes in laws and regulations applicable to Allegheny, its markets, or its activities; environmental regulations;
the loss of any significant customers and suppliers; the effect of accounting policies issued periodically by
accounting standard-setting bodies; additional collateral calls; and changes in business strategy, operations, or
development plans. Additional risks and uncertainties are identified and discussed in Allegheny Energy's reports
filed with the Securities and Exchange Commission.

1

Non-GAAP Financial Measures

2

This presentation includes non-GAAP financial measures as defined in the Securities
and Exchange Commission’s Regulation G.  Where noted, the presentation shows
certain financial information on an “as adjusted” basis, to exclude the effect of certain
items as described herein. By presenting “as adjusted” results, management intends
to provide investors with a better understanding of the core results and underlying
trends from which to consider past performance and prospects for the future.

Users of this financial information should consider the types of events and
transactions for which adjustments have been made. “As adjusted” information
should not be considered in isolation or viewed as a substitute for, or superior to, net
income or other data prepared in accordance with GAAP as measures of our operating
performance or liquidity. In addition, the “as adjusted” information is not necessarily
comparable to similarly titled measures provided by other companies.                     

Pursuant to the requirements of Regulation G, we have attached a table that reconciles
the non-GAAP financial measures in this presentation to the most directly comparable
GAAP measures. The table is also available at www.alleghenyenergy.com.

Paul Evanson

Chairman, President and Chief Executive Officer

Jeffrey Serkes

Senior Vice President and Chief Financial Officer

3

Allegheny Energy

Allegheny
Energy

Generation &
Marketing

48.3 billion KWH
generated (2003)

Delivery &
Services

46.5 billion KWH sold
(2003)

46.4 billion
KWH under
long-term
contracts

4

Major Priorities: First Year

Increase liquidity

Decrease risk and volatility of earnings, cash flow

Re-establish financial reporting

Re-focus on core business

Rebuild senior management team

5

Rebuilt Senior Management Team

Paul J Evanson, Chairman

H. Furlong Baldwin

Cyrus F. Freidheim, Jr.

Julia Johnson

Michael H. Sutton

Eleanor Baum

Ted J. Kleisner

Steven H. Rice

Gunnar E. Sarsten

Since June 2003

Existing

Chairman, President and CEO

Paul Evanson

SVP & Chief

Financial Officer

Jeffrey Serkes

VP &

General Counsel

David Hertzog

President

Allegheny Power

Joseph
Richardson

VP Strategic
Planning &

Chief Commercial
Officer

Philip Goulding

VP

Human
Resources

Edward
Dudzinski

Board of Directors

6

President

AE Supply

John Campbell

Current Priorities

Restore financial strength

Build high performance organization

Optimize value of generation

7

Restore Financial Strength

Goal: reduce debt by $1.5 billion*

Repaid $900 million of debt

On track to further reduce debt by $600 million

*December 1, 2003 through year-end 2005

8

High Performance Organization:

Balanced Scorecard

Financial

Performance

Engaged

Employees

Environmental

Stewardship

Shareholder

Value

Operational

Excellence

9

VISION:

“To Be a Top Performing Utility by
Year-End 2007”

Customer

Satisfaction

High Performance Organization:
2007 Targets

10

YEAR END

2007 TARGET

Operational:

Plant availability

91% (1^st quartile)

Service unavailability

172 minutes/year

Financial:

Credit rating

Investment grade

O&M expense

Reduce by $250-300M

High Performance Organization:
2007 Targets

11

YEAR END

2007 TARGET

Customer satisfaction

1^st quartile

Engaged employees:

OSHA incident rate

2.10

Engagement survey

Continuous

improvement

Environmental

Continued full

compliance

Shareholder value

Higher share

price

$0

$20

$40

$60

$80

$100

$120

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

Optimize Value of Generation:
Low-Cost Fleet

Capacity in MW

DispatchCost

AlleghenyUnits

Hydro

Allegheny

58 MW

Nuclear

Coal

Allegheny 7,617 MW

Oil & Gas

Allegheny 951 MW

Allegheny has an advantaged dispatch in PJM

PJM Dispatch Cost  (Ozone Season): $/MWH

Dispatch curve assumes gas delivered at approximately $5.00/mmBtu.  Includes PJM Traditional, PJM West, AEP, ComEd, DPL, DQE  and
Virginia Power.

Pumped Storage

Allegheny 960 MW

12

2004 Average

2004 Peak

Optimize Value of Generation:
Transition to Market

13

*2004 through 2007: spot and forward markets. 2008: independent market forecast.

Independent
Market Forecast*

POLR Contract
Prices

Maryland –
Additional Industrial

Optimize Value of Generation:
Transition to Market

2003

2004

2005

2006

2007

2008

Ohio – Com

           & Ind

POLR Agreements Expiring

Transitioning to Market
MWH millions

2004

2005

2006

2007

2008

2009

0

5

10

15

25

35

20

30

Ohio       Maryland       Pennsylvania

14

Maryland - Res

Maryland – Com

                   & Ind

Ohio –

Additional Industrial

Pennsylvania

32 million MWH,
2004 - 2009

New rates/ timeline proposed

Pennsylvania Rate Petition

$20

$25

$30

$35

$40

$45

$50

$55

2005

2006

2007

2008

2009

2010

$0

$50

$100

$150

$200

$250

$300

$350

$400

$450

2006

2007

2008

2009

2010

Current

Proposed

Generation Rate, Pennsylvania

$ per MWH

Cumulative Increase in

Pre-Tax Operating Income*

$ millions

15

*Based on 2003 MWH

Challenge: Coal Costs

16

100%

90%

50%

2004

2005

2006

Contracted Coal

$31

$34

$35*

2004

2005

2006

Average Cost Per Ton

* Existing contracts only

Challenge:  SO₂ Allowance Costs

Emit 370,000 - 380,000 tons of SO₂ /year

Receive allowances for 220,000 tons/year

Additional allowance inventory of 450,000 tons
phases in over five years

Exposure to allowance market:

< 50,000 tons in 2005

~100,000 tons/year in 2006-2008

17

Potential for Coal and
SO₂ Cost Recovery

Market-

Based

19%

Fixed

Price

61%

Regulated

20%

18

Generation Sales in 2006
(MWH; estimates)

39%

Challenge: Environmental Issues

19

In compliance with all
environmental laws

Evaluating options for the
future

If install scrubbers/SCRs  
at 5 remaining major
units, estimated cost =
$1.3 billion

In discussions with
state/federal authorities

The Road to Recovery

$80

$100

$120

$140

$160

$180

$200

$220

AYE

Dow Electric Utilities

S&P 500

Stock Performance
($100 Invested on July 1, 2003)

Refinanced
bank debt

Exited
energy
trading

Brought
reporting
up to date

Announced OVEC,
Mountaineer, Lincoln sales

Filed PA
rate
proposal

Completed  
equity
financing

Launched high
performance
organization

20

Completed
convertible
financing

21

The Road to Recovery

FINANCIAL

Reduce interest expense

STRENGTH

Issued equity; conversion of trust preferred

HIGH

Increase plant availability

PERFORMANCE

Reduce O&M expense

OPTIMIZE

Approved rate increase, PA (2006 & 2008)

GENERATION

Market-based rates/PA settlement

CHALLENGES

Coal and SO₂ costs

Other environmental costs

Paul Evanson

Chairman, President and Chief Executive Officer

Jeffrey Serkes

Senior Vice President and Chief Financial Officer

22

Financial Review

Reducing debt, interest expense

O&M expense targets

Financial results

Outlook

23

Restore Financial Strength:
Reducing Debt by $1.5 Billion

*Allegheny expects free cash flow of more than $250 million for 2004 and 2005 combined

497

Announced asset sales

   > 103

Free cash flow*

$ 1,500

TOTAL EXPECTED DEBT REDUCTION

$    900

Achieved to date (includes

  October 2004 equity proceeds)

$ MILLIONS

24

Reducing Debt:
Announced Asset Sales

25

PROCEEDS

TOTAL

EXPECTED

ANNOUNCED ($ millions):

AT CLOSING

PROCEEDS

CLOSING

Lincoln generating facility

$173

$173

Q4 2004

OVEC (9% equity interest)

96

102

Q4 2004/

Q1 2005

Mountaineer Gas

228

244

mid-2005

Total cash and assumed debt

$497

$519

IN PROGRESS:

Wheatland and Gleason generating facilities  

Reducing Interest Expense

26

ANNUALIZED INTEREST SAVINGS FROM:

$ MILLIONS

(PRE-TAX)

Reducing debt $1.5 billion by Dec. 2005⁽¹⁾

$  90

Refinanced bank debt (March 2004)

50

Repricing bank debt (October 2004)⁽²⁾

10

TOTAL

~ $150

(1)

4Q 2003 annualized interest expense vs. estimated 4Q 2005

annualized interest expense

(2)

Expected to close on or around week of October 29, 2004

O&M Expense:  2000 - 2003

$ millions

$641

$830

$1,144

$1,010

$0

$200

$400

$600

$800

$1,000

$1,200

2000

2001

2002

2003

Up $369

since 2000

27

Salaries, Wages &

Benefits

$98

Contract Work

$52

Insurance, Rent &

Other

$33

Outside Services

$78

Cancelled Projects

$31

Midwest Assets &

Mountaineer Gas

$77

Sources of Higher O&M Expense

Total Increase, 2000 – 2003:

$369 million

28

O&M Expense: 2007 Target
($ millions)

$830

$1,144

$1,010

$700 - 750

$641

$0

$200

$400

$600

$800

$1,000

$1,200

2000

2001

2002

2003

2007

29

Target

Reduce O&M Expense by
$250-$300 Million

75

Planned asset sales

$250 - 300

TOTAL

125 - 175

Headquarters costs and

non-recurring items (net)

$          50

T&D and coal plant costs
(excludes fuel and SO₂
allowances)

Targeted Decrease, 2003 – 2007

($ millions)

30

31

Improving Financial Results in 2004

Reported net loss for first half

Outages at Pleasants, Hatfield plants

Special maintenance expense

Expect net profit on core operations in Q3, Q4

Pleasants, Hatfield in service

Less special maintenance

Expect losses on asset sales, impairment charges
(~$430 million net of tax)

Outlook: Beyond 2004

Achieve predictable earnings, cash flow

Restore long-term earnings growth

Reduce debt, interest, O&M expense

Improve plant availability

Transition to market-based pricing

Return to investment grade credit rating

32

Allegheny Energy

Solid regulated business with stable cash flows

Low-cost coal generation in PJM

Improving financial performance

Earnings growth potential

33

Supplemental
Information

34

Net Income (Loss)

35

$ millions

As Reported

As Adjusted

2003:

Q1

$

(58.8)

$

(41.0)

Q2

(231.5)

(28.5)

Q3

(51.0)

TBA

Q4

(13.7)

TBA

2004:

Q1

$

33.3

$

(0.3)

Q2

(39.5)

(32.8)

TBA:  to be announced

EBITDA

36

$ millions

As Reported

As Adjusted

2003:

Q1

$

77.6

$

92.9

Q2

(203.5)

150.1

Q3

134.5

TBA

Q4

212.6

TBA

2004:

Q1

$

274.3

$

202.0

Q2

116.6

128.3

TBA:  to be announced

Delivery and Services: Overview

Allegheny Power

In 5 states (PA, WV, MD,
VA, OH)

1.5 million electric customers

Load growth: 2.2% (1993-2003)

VIRGINIA

WEST

VIRGINIA

CHARLESTON

HARRISBURG

PENNSYLVANIA

OHIO

CLEVELAND

WASHINGTON, DC

MARYLAND

PITTSBURGH

BALTIMORE

VIRGINIA

WEST

VIRGINIA

CHARLESTON

HARRISBURG

PENNSYLVANIA

OHIO

CLEVELAND

WASHINGTON, DC

MARYLAND

PITTSBURGH

BALTIMORE

West Penn
Power

Monongahela
Power

Potomac
Edison

37

Delivery and Services:  
Competitive Rates

Residential Rates
as of January 1, 2004

#2 in customer satisfaction in East region for past six years

9.65

6.47

8.98

7.34

9.39

0

2

4

6

8

10

12

Pennsylvania

West Virginia

Maryland

Virginia

Ohio

6.76

7.01

6.94

6.81

6.82

¢/kWh

National
Average =
9.12 ¢/kWh

Allegheny Power

State Average

38

Regulatory Timeline

39

2004

2005

2006

2007

2008

Through 2005

Through 2005

Increases through 2008

Through 2005

Increases through 2008

Through 2005

Increases through 2008

Other classes through 2005

Through 2005

Small through 2005

Through 2005

Through 2005

Increases through 2008

Through 2005

Increases through 2008

Through 2005

Increases through 2008

Regulated Generation and T&D

Through 2008

Through 2004

Through 2007

Through 2007

Through 2007

Other classes through 2005

Large through 2003

Small through 2005

Through 2003

Through 2005

Large C&I through 2003

T&D

Gen.

Gen.

Gen.

T&D

Gen.

Gen.

Gen.

T&D

Gen.

Gen.

T&D

Gen.

Gen.

Gen.

T&D

Gen.

Gen.

Gen.

2003

Through 2007*

Through 2004

Through 2005

Through 2003

Through 2010*

*

One-time T&D increase can be requested through 2007.  Fuel cost pass-through and one-time T&D and
generation increases can be requested between 2007 and 2010.

State

PA

WV

MD

VA

OH

Res.

Com.

Ind.

Res.

Com.

Ind.

Res.

Ind.

Res.

Com.

Ind.

Res.

Com.

Ind.

Through 2004

Gen.

Com.

Generation and Marketing:
Generation Assets

Capacity

MWH Output

Capacity by Region

Coal

68%

Gas

22%

Hydro & Oil

10%

Coal

95%

Gas

1%

Hydro & Oil

4%

PJM

85%

Midwest

15%

Note:  Data for year ended December 31, 2003 for AE Supply and Monongahela Power generation.

11,500 MW of primarily base load coal-fired plants

Predominantly in Pennsylvania-New Jersey-Maryland (“PJM”)
region

40

World’s largest competitive power market

51 million people

700 million MWH of energy annually

160,000 MW of capacity

Nation’s most liquid spot power market

Model for FERC’s proposed Standard Market Design

Provides transactional flexibility: contracts not
required

Generation and Marketing:
PJM -- An Attractive Market

41

Expanded PJM includes PJM Traditional, PJM West, AEP, ComEd,
DPL, DQE and Virginia Power

Generation and Marketing:
Maintenance Spending

Legacy Assets Maintenance Spending* and

Operating Performance

$120

$140

$160

$180

$200

$220

$240

$260

$280

$300

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

0

2

4

6

8

10

12

14

Total

Maintenance

Spending

Equivalent

Forced Outage

Rate

Note:

      Glide path to

      91% availability

* 2004 constant $, maintenance includes O&M and capital less environmental

42

                               RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
                                    (in millions, except per share data)
                                                (unaudited)



                                                          INCOME BEFORE INCOME                      DILUTED
                                                           TAXES AND MINORITY     NET INCOME       EARNINGS
 THREE MONTHS ENDED MARCH 31, 2004                             INTEREST             (LOSS)         PER SHARE
-------------------------------------------------------------------------------------------------------------
 GAAP basis                                                      $60.7              $33.3            $0.25

 Adjustments(1):
 Gain on California contract escrow release                      (68.1)             (39.4)
 Write-off of 2003 financing costs                                14.1                8.2
 Gain on land sale, New York office space charge (net)            (4.2)              (2.4)
-------------------------------------------------------------------------------------------------------------
 As Adjusted                                                      $2.5              ($0.3)           $ ---
=============================================================================================================

 GAAP basis                                                                         $33.3
 Interest expense and preferred dividends                                           132.2
 Income tax expense                                                                  25.5
 Depreciation and amortization                                                       83.3
----------------------------------------------------------------------------------------------
 EBITDA                                                                             274.3
 Gain on California contract escrow release                                         (68.1)
 Gain on land sale, New York office space charge (net)                               (4.2)
----------------------------------------------------------------------------------------------
 Adjusted EBITDA(1)                                                                 $202.0
==============================================================================================



                                                                LOSS BEFORE
                                                              INCOME TAXES,
                                                          MINORITY INTEREST
                                                             AND CUMULATIVE                         DILUTED
                                                                  EFFECT OF                        LOSS PER
 THREE MONTHS ENDED MARCH 31, 2003                       ACCOUNTING CHANGES       NET LOSS            SHARE
-------------------------------------------------------------------------------------------------------------
 GAAP basis                                                     ($79.0)            ($58.8)          ($0.46)

 Adjustments(2):
 Gain on SFAS 71                                                 (75.8)             (39.3)
 Loss on assets retired/held for sale                             37.5               19.4
 Special termination and other benefits                           15.7                8.1
 Impairment of New York office                                     4.6                2.4
 Other(3)                                                         12.6                6.5
 Cumulative effect of accounting changes                                             20.7
--------------------------------------------------------------------------------------------------------------
 As Adjusted                                                   ($84.4)             ($41.0)          ($0.32)
==============================================================================================================

 GAAP basis                                                                        ($58.8)
 Interest expense and preferred dividends                                            96.8
 Income tax benefit                                                                 (38.0)
 Depreciation and amortization                                                       77.6
--------------------------------------------------------------------------------------------
 EBITDA                                                                              77.6
 Gain on SFAS 71                                                                    (75.8)
 Loss on assets retired/held for sale                                                37.5
 Special termination and other benefits                                              15.7
 Impairment of New York office                                                        4.6
 Other(3)                                                                            12.6
 Cumulative effect of accounting changes                                             20.7
--------------------------------------------------------------------------------------------
 Adjusted EBITDA(2)                                                                 $92.9
============================================================================================

FOOTNOTES:
----------

(1) Not adjusted for $9.2 million of charges related to Allegheny Ventures for
write-downs of inventory and discontinued product ($4.3 million), equity
interests ($2.3 million) and adjustments in revenue recognition for a
percentage of completion contract ($2.6 million).

(2) Not adjusted for estimated energy trading losses totaling $102.2 million.
These losses were primarily the result of trading activities in the Western
United States energy markets, which Allegheny exited in 2003.

(3) Charges related to the St. Joseph's generating plant lease ($2.0 million),
additional Enron litigation reserves ($7.0 million) and additional costs
attributable to asset sales ($3.6 million).






                                                               LOSS BEFORE                           DILUTED
                                                          INCOME TAXES AND                          LOSS PER
 THREE MONTHS ENDED JUNE 30, 2004                        MINORITY INTEREST       NET LOSS              SHARE
---------------------------------------------------------------------------------------------------------------
 GAAP basis                                                   $(69.5)             $(39.5)           $(0.31)
 Adjustments:                                                                                       =======
 Loss on release of gas pipeline capacity(1)                    11.7                 6.7
---------------------------------------------------------------------------------------------------------------
 As Adjusted                                                  $(57.8)             $(32.8)           $(0.26)
===============================================================================================================

 GAAP basis                                                                       $(39.5)
 Interest expense and preferred dividends                                          100.2
 Income tax benefit                                                                (29.3)
 Depreciation and amortization                                                      85.2
----------------------------------------------------------------------------------------------
 EBITDA                                                                            116.6
 Loss on release of gas pipeline capacity                                           11.7
----------------------------------------------------------------------------------------------
 Adjusted EBITDA                                                                  $128.3
==============================================================================================



                                                                  LOSS BEFORE
                                                                 INCOME TAXES,
                                                             MINORITY INTEREST
                                                                AND CUMULATIVE                      DILUTED
                                                                     EFFECT OF                     LOSS PER
 THREE MONTHS ENDED JUNE 30, 2003                           ACCOUNTING CHANGES    NET LOSS            SHARE
-------------------------------------------------------------------------------------------------------------
 GAAP basis                                                      $(403.6)        $(231.5)           $(1.82)
 Adjustments(2):                                                                                    =======
 Unrealized loss on renegotiation of CDWR contract(3)              152.2            87.4
 Unrealized losses on West Book trading activities(3)              169.4            97.2
 Baltimore Gas & Electric contract termination costs(4)             32.0            18.4
-------------------------------------------------------------------------------------------------------------
 As Adjusted                                                      $(50.0)         $(28.5)           $(0.23)
=============================================================================================================

 GAAP basis                                                                      $(231.5)
 Interest expense and preferred dividends                                          115.9
 Income tax benefit                                                               (167.4)
 Depreciation and amortization                                                      79.5
-------------------------------------------------------------------------------------------
 EBITDA                                                                           (203.5)
 Unrealized loss on renegotiation of CDWR contract                                 152.2
 Unrealized losses on West Book trading activities                                 169.4
 Baltimore Gas & Electric contract termination costs                                32.0
-------------------------------------------------------------------------------------------
 Adjusted EBITDA(2)                                                               $150.1
===========================================================================================


FOOTNOTES:
----------

(1) This amount is included in Purchased power and transmission on the
Consolidated Statement of Operations.

(2) Not adjusted for estimated net energy trading gains of $18.2 million,
consisting of realized gains of $19.7 million and unrealized losses of $1.5
million.

(3) These amounts are included in Operating revenues on the Consolidated
Statement of Operations.

(4) This amount is included in Operations and maintenance expense on the
Consolidated Statement of Operations.





       THREE MONTHS ENDED SEPTEMBER 30, 2003
      -------------------------------------------------------------------------
       Net Loss - GAAP basis                                           $(51.0)
       Interest expense and preferred dividends                         126.1
       Income tax benefit                                               (26.6)
       Depreciation and amortization                                     86.0
      -------------------------------------------------------------------------
       EBITDA                                                          $134.5
      =========================================================================




       THREE MONTHS ENDED DECEMBER 31, 2003
      -------------------------------------------------------------------------
       Net Loss - GAAP basis                                           $(13.7)
       Interest expense and preferred dividends                         127.5
       Income tax expense                                                15.0
       Depreciation and amortization                                     83.8
      -------------------------------------------------------------------------
       EBITDA                                                           $212.6
      -------------------------------------------------------------------------