Allegheny Energy

Investor Presentation

August 16-18, 2006

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Forward-Looking StatementsIn 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; financing plans; demand for energy and the cost and availability of raw materials, including coal; provider-of-last resort and power supply contracts; results of litigation; results of operations; internal controls and procedures; capital expenditures; status and condition of plants and equipment; regulatory matters; and accounting issues. 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. Actual results have varied materially and unpredictably from past expectations. Factors that could cause actual results to differ materially include, among others, the following: changes in the price of power and fuel for electric generation; general economic and business conditions; changes in access to capital; complications or other factors that render it difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis; environmental regulations; the results of regulatory proceedings, including proceedings related to rates; changes in industry capacity, development, and other activities by Allegheny's competitors; changes in the weather and other natural phenomena; changes in the underlying inputs and assumptions, including market conditions used to estimate the fair values of commodity contracts; changes in laws and regulations applicable to Allegheny, its markets or its activities; the loss of any significant customers and suppliers; dependence on other electric transmission and gas transportation systems and their constraints on availability; changes in PJM, including changes to participants rules and tariffs; the effect of accounting policies issued periodically by accounting standard-setting bodies; and the continuing effects of global instability, terrorism and war. Additional risks and uncertainties are identified and discussed in Allegheny Energy's reports and registration statements filed with the Securities and Exchange Commission. These forward-looking statements speak only as of the date of this document. Allegheny Energy undertakes no obligation to update its forward-looking statements to reflect events or circumstances after the date of this document.

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Non-GAAP Financial MeasuresThis 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.

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Allegheny Energy

AlleghenyEnergy

Generation

Coal-fired, PJM48.1 million MWH*

Delivery

1.5 million customers,PA-MD-WV-VA

* 12 months ended December 31, 2005

5

Turnaround

• Restructured andreduced debt

• Strengthened financial reporting, internal controls

• Refocused on core business

• Launched high performance organization

• Returned to profitability

Turnaround

• Restructured andreduced debt

• Strengthened financial reporting, internal controls

• Refocused on core business

• Launched high performance organization

• Returned to profitability

Entering a Growth Phase

GrowthGrowth

6

Earnings Growth Drivers

Increase Pennsylvania POLR rates

Transition to market-based rates

Improve plant availability

Decrease O&M expense

Reduce interest expense

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$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

Generation Rate$ per MWH

Cumulative Increase inPre-Tax Operating Income

$ millions; estimates

Growth Driver: Increase Pennsylvania POLR Rates

8

$25

$30

$35

$40

$45

$50

$55

$60

$65

$70

$75

2005 2006 2007 2008

Growth Driver:Transition to Market-Based Rates

Market: Current*

POLR: Maryland, Ohio

Generation Rates$ per MWH

Assumption for 2006 Outlook

* As of July 10, 2006

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Growth Driver:Transition to Market-Based Rates

2006 2009

State Maryland, MarylandOhio

MWH transitioning 4.8 million 3.5 millionto market

Increase in pre-tax income $90 million $60 million

Total: $150 millionTotal: $150 million

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Other Contracts

9%

Excess6%

POLR85%

Other Contracts

1%

Excess32%

POLR67%

Decreasing POLR Obligation

% of Total Projected Output(existing contracts only)

2006 2010

11

83%

76%

82%

78%

83%

91%

83%79%

2002 2003 2004 2005

Growth Driver: Improve Plant Availability

2008Goal

Proforma*

Actual

* Excludes extended unplanned outages at Hatfield, Pleasants

Supercritical units

Each 1% improvement provides benefit >$10 million

2006Goal

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Achieving 91% Availability by 2008

2002 2003 2004 2005 2006 2007 2008

Outage Factor(supercritical units)

22%

24%

17% 17%

15%

9%

Reduce planned outages

Reduce unplanned outages

18%

Goal

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Power Plant Investment

$100 $105

$192

$165

2002 2003 2004 2005

Maintenance Spending(O&M and capital; $ millions)

14

Coal Supply Under Contract

98%

85%

70%

2006 2007 2008

% of Total Requirements

100% 100%95%

2006 2007 2008

% of POLR Requirements

15

Coal Costs and Usage

$35$37 $37 $38

2005 2006 2007 2008

Average Delivered Cost/Ton(Existing contracts only)

2005: 18 million

2006: >19 million

Usage(Tons)

16

$1,186

$985

$818$758* <$730

2002 2003 2004 2005 2006 2007

$700-730

Growth Driver:Decrease O&M Expense

Target

* 2005 = $775 after adjustment

($ millions)

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Growth Driver:Reduce Interest Expense

Reduced debt by $2.1 billion (Dec. 1, 2003 – June 30, 2006)

Refinanced $1.5 billion in 2006

Projected reduction in interest expense: $65 million in 2006

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2006 Priorities

Strengthen financial condition; investment grade by year-end 2007

Strong earnings growth

Improve environmental performance

Expand transmission system

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Priority: Environmental Performance

ACTION STATUS

Low-sulfur PRB coal Began in 3rd quarter 2005

Close Pleasants bypass By early 2008

Fort Martin scrubbers (West Virginia)

Received regulatory approvals

Funded by securitized surcharge

In service 2009

Hatfield scrubbers (Pennsylvania)

Signed contracts In service 2009

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Exposure toSO2 Allowance Market

SO2 Emissionsin Excess of Allowances

(tons; estimated as of July 28, 2006)

* Approximately half of 2008 short position is at Allegheny Supply and half is at Monongahela Power.

2006 -0-

2007 0 - 40,000

2008 40,000 - 80,000*

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Priority:Expand Transmission System

PJM approved ~210-mile line

Cost: over $850 million (preliminary estimate) 80% of spending in 2009-2011 In service 2011

FERC approved incentive rate treatment

Other approvals needed

State regulatory commissions FERC (rate filing)

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Approved Transmission Line

MMtt.. SSttoorrmm

MMeeaaddooww BBrrooookk

LLoouuddoouunn

PPrreexxyy

550022 JJuunnccttiioonn

Existing Substation

New Substation

Existing Lines

New 500 kV Line

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Requested $100 million net increase

Fuel, purchased power: $126 million increase Base rates: $26 million decrease 10% net increase (residential)

Requested reinstatement of fuel cost adjustment

Proposed ROE: 11.75%

Probable effective date: late May 2007

West Virginia Rate Case Filing

Financial Review

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Improving Financial Results

As Reported

As AdjustedEarnings per Share

($2.80)

($1.83)

$0.40$0.86

$0.47$0.94

($0.37)

$0.90

2003 2004 2005 20066 mos.

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Increasing Free Cash Flow ($ millions)

Cash from Operations Free Cash Flow(adjusted cash from operations

net of capital expenditures)$507$486

$563*

$347*

2004 2005

$81

$257

>$200**

2004 2005 2006

As reported As adjusted

* 2004 excludes OVEC proceeds and California contract escrow release. 2005 excludes costs for St. Joe’s notes redemption and convertible trust preferred securities tender offer.

** Assumes $115 million of spending for Hatfield scrubbers.

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Strengthening the Balance Sheet

Debt Outstanding($ billions)

Equity Ratio

$5.7

$4.9

$4.1 $3.9

2003 2004 2005 2006 Q2

21% 21%

29%32%

2003 2004 2005 2006 Q2

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Improving Credit Statistics

8.5

6.1

<3.54.3

3.8

Dec-03 Dec-04 Dec-05 Jun-06 Target

Debt/EBITDA* EBITDA/Interest*

* Based on adjusted EBITDA and adjusted interest for 12-month periods. Excludes securitized debt and interest.

1.6

2.2

>4.0

3.0

3.5

Dec-03 Dec-04 Dec-05 Jun-06 Target

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2006 Earnings Growth:Key Drivers

CONTRIBUTION TO PRE-TAX INCOME*($ millions; estimates)

Pennsylvania rates $55Maryland contract expiration 55Ohio territory sale 45Market prices positive/negativeDecember 2005 adjustment 27Plant availability no impactTransmission contract (30)Higher coal costs (80)

SO2 allowance costs no impact

Lower O&M expense 50Lower depreciation 30Lower interest expense 65Other factors positive/negative

* 2006 vs. 2005 as adjusted

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Supplemental Information

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Earnings (Loss) Per Share

As Reported As Adjusted

2003: Q1 $ (0.46) $ (0.32)Q2 (1.82) (0.23)Q3 (0.40) 0.11Q4 (0.11) (0.14)

Year (2.80) (0.37)

2004: Q1 $ 0.25 $ (0.03)Q2 (0.31) (0.21)Q3 (2.40) 0.37Q4 0.48 0.22

Year (1.83) 0.47

2005: Q1 $ 0.29 $ 0.39Q2 (0.12) 0.08Q3 0.21 0.45Q4 0.02 0.02

Year 0.40 0.94

2006: Q1 $ 0.67 $ 0.68Q2 0.18 0.22

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EBITDA$ millions As Reported As Adjusted

2003: Q1 $ 77.6 $ 92.9Q2 (203.5) 150.1Q3 117.3 225.3Q4 197.4 185.6

Year 156.8 634.9

2004: Q1 $ 247.8 $ 175.5Q2 110.3 122.0Q3 243.2 243.2Q4 312.7 221.8

Year 914.0 762.5

2005: Q1 $ 261.3 $ 261.3Q2 210.6 192.7Q3 254.7 274.2Q4 162.1 162.1

Year 888.6 890.2

2006: Q1 $ 322.1 $ 322.1Q2 193.6 193.6

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$0

$100

$200

$300

$400

$500

7/1/2

003

9/1/2

003

11/1

/2003

1/1/2

004

3/1/2

004

5/1/2

004

7/1/2

004

9/1/2

004

11/1

/2004

1/1/2

005

3/1/2

005

5/1/2

005

7/1/2

005

9/1/2

005

11/1

/2005

1/1/2

006

3/1/2

006

5/1/2

006

7/1/2

006

AYE Dow Electric Utilities S&P 500

731/

2006

Stock Price Performance$100 Invested on July 1, 2003 AYE: $495

Dow Electrics: $155 S&P: $130

The Road to Growth

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Enhance Operating Performance

FinancialPerformance

EngagedEmployees

EnvironmentalStewardship

ShareholderValue

OperationalExcellence

VISION:

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

CustomerSatisfaction

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Generation and Marketing:Overview

Capacity*

Coal96%

Gas1%

Hydro3%

* Excludes Gleason peaking unit (held for sale). Output for year ended December 31, 2005.

Capacity: over 9,600 MW* Primarily base load coal-fired plants Located in PJM (13 states)

Hydro11%

Gas9%

Coal79%

MWH Output*

Oil1%

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Low-Cost Generation FleetAllegheny has an advantaged dispatch in PJM

PJM Dispatch Cost (Ozone Season): $/MWh

Allegheny Supercritical Coal UnitsDispatch Cost Allegheny – Other Units

Assumptions: natural gas delivered at approximately $8.00/mmBTU; coal at approximately $2.75/mmBTU; SO 2 at $670/ton; NOx at $1,750/ton.

$0

$20

$40

$60

$80

$100

$120

$140

$160

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000

Capacity in MW

Hydro Nuclear

Coal

Oil & Gas

2006 Average

2006 Peak

Allegheny58 MW

Allegheny7,604 MW

Allegheny973 MW

Pumped StorageAllegheny 1,035

MW

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World’s largest competitive power market

Over 51 million people 700 million MWH of energy annually 163,500 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

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Only 15% of Coal Delivered by Rail

Note: Some barge coal originates on short line railroads.

Rail15%

Barge49%

Conveyor15%

Truck21%

Coal Delivery Methods

2006

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Delivery and Services:Overview

In 4 states (PA, WV, MD, VA)

1.5 million electric customers Load growth: 2.0% compounded

annually (1995-2005; retail)

Allegheny Power

West PennPower

Monongahela Power

Potomac Edison

VIRGINIA

CHARLESTON

OHIO

HARRISBURG

MARYLAND

KENTUCKY

PENNSYLVANIA

CLEVELAND

BALTIMORE

PITTSBURGH

WASHINGTON, DC

WEST

VIRGINIA

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PA43%

WV29%

MD20%

VA6%

OH2%

Delivery and Services: Retail Revenue Mix, 2005

By State By Customer Class

Residential43%

Industrial31%

Commercial25%

Other1%

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7.10 7.01 6.89 6.82

11.11

6.27

7.498.38

0.00

2.00

4.00

6.00

8.00

10.00

12.00

Pennsylvania West Virginia Maryland Virginia

Allegheny Power State Average

Delivery and Services: Competitive Rates

National Average = 10.62 ¢/kWh

Residential Rates¢/kWh as of January 1, 2006

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2006 2008 2009 2010

T&D

Generation

T&DGen. - Res.

Through 20072

Gen. - Com. & Ind.

T&DandGeneration

RegulatedCapped through 2008 Market-based

Market-based

RegulatedDistribution capped through 2007

Increases through 20101

2007

Through 20102

State

WV

T&DandGeneration

Regulated

PA

MD

VA

1 Generation rate caps include rate increases in each year, 2006-2010. 2 One-time T&D increase can be requested through 2007. After 2007, can

request recovery of purchased power and annual incremental T&D reliability and environmental costs, and one additional T&D cost increase.

Regulatory Timeline