EX-99.1 2 dex991.htm LITERATURE TO BE FURNISHED TO INVESTORS BY ALLEGHENY ENERGY, INC. Literature to be furnished to investors by Allegheny Energy, Inc.
EEI Financial
Conference
October 31 -
November 2, 2010
Exhibit 99.1

2
Table of Contents
Page
Page
I.
COMPANY OVERVIEW
IV.
MERCHANT GENERATION
Primary businesses
6
Overview
23
Service area
7
Coal fleet characteristics
24-26
Overview
8
Plant availability
27
Quality and costs
9-11
Generation hedged
28
Business units
12
PJM price hubs
29-30
Coal
31-32
II.
UTILITY OPERATIONS
Overview
13
V.
OUTLOOK
Revenue mix
14
Outlook:  Consolidated
33
Capital structures and ROE's
15
Outlook:  Merchant generation
34-38
Growing rate base
16
Capital expenditures
39
Competitive rates
17
PA transition to market
18
VI.
MERGER
Overview
40
III.
TRANSMISSION EXPANSION
Fuel mix
41
Overview
19
Scale and scope
42
Capital expenditures
20
State procedural schedules
43-44
Growing rate base
21
TrAIL construction update
22
VII.
SUPPLEMENTAL MATERIAL
EPS and EBITDA
46-47
Cash flow
48
Credit ratings
49
Merchant generation formulas
50

3
Forward-Looking Statements
INFORMATION CONCERNING 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.  Forward-looking statements involve estimates, expectations, and projections and, as a result,
are subject to risks and uncertainties.  Forward-looking statements often may be identified by the use of 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.  However, the absence of these or similar words does not mean that any particular statement is not forward-looking. 
Forward-looking statements in this presentation may relate to, among other matters: regulatory issues, including but not limited to
environmental regulation, and the status of retail generation service supply competition in states served by Allegheny’s  delivery
business, Allegheny Power; financing plans; market demand for energy, the cost and availability of raw materials, including coal and
natural gas, and Allegheny’s ability to enter into, modify and enforce long-term fuel purchase agreements; 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; changes in technology and their effects on the competitiveness of Allegheny’s generation facilities;
work stoppages by Allegheny’s unionize employees; capacity purchase commitments; statements about the benefits of the proposed
merger involving Allegheny and FirstEnergy, including future financial and operating results; Allegheny’s and FirstEnergy’s plans,
objectives, expectations and intentions; the expected timing of completion of the transaction; and other statements relating to the
merger that are not historical facts.  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: the results of regulatory proceedings, including proceedings related to rates; plant performance
and unplanned outages; volatility and changes in the price and demand for energy and capacity and changes in the value of financial
transmission rights; volatility and changes in the price of coal, natural gas and other energy-related commodities; Allegheny’s ability to
enter into, modify and enforce supplier performance under long-term fuel purchase agreements; the ability and willingness of
counterparties to satisfy their financial and performance obligations; changes in the weather and other natural phenomena; changes in
Allegheny’s requirements for, and the availability and price of, emission allowances; changes in industry capacity, development and
other activities by Allegheny’s competitors; changes in market rules, including changes to the participant rules and tariffs for PJM
Interconnection, LLC and defaults by other market participants; the loss of any significant customers or suppliers; changes in both
customer usage and customer switching behavior and their resulting effects on existing and future load requirements; dependence on
other electric transmission and gas transportation systems and their constraints on availability; environmental regulation; changes in
other laws and regulations applicable to Allegheny, its markets or its activities; changes in the underlying inputs and assumptions,
including market conditions used to estimate the fair values of commodity contracts; complications or other factors that make it
difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis; recent and any future
disruptions in the financial markets and changes in access to capital markets; the availability of credit; actions of rating agencies;
inflationary and deflationary trends and interest rate trends; the effect of accounting pronouncements issued periodically by accountin
standard-setting bodies; entry into, any failure to consummate, or any delay in the consummation of, contemplated asset sales or other
strategic transactions; the likelihood and timing of the completion of the proposed merger with FirstEnergy, the terms and conditions of
any required regulatory approvals of the proposed merger, the impact of the proposed merger on Allegheny’s employees and the
potential diversion of management’s time and attention from ongoing business during this time period; general economic conditions;
and other risks, including the  continuing effects of global instability, terrorism and war. Additional risks and uncertainties are identified
and discussed in Allegheny's reports and registration statements filed with the Securities and Exchange Commission.

4
Forward-Looking Statements
Risks and uncertainties associated with the merger are more fully discussed in the preliminary joint proxy statement/prospectus that is
included in the Registration Statement on Form S-4 (Registration No. 333-165640) that was filed by FirstEnergy with the SEC in
connection with the merger. Allegheny and FirstEnergy urge investors and shareholders to read the definitive joint proxy
statement/prospectus regarding the proposed merger, as well as other documents filed with the SEC, because they contain important
information.  You may obtain copies of all documents filed with the SEC regarding the proposed merger, free of charge, at the SEC’s
website (www.sec.gov).  You may also obtain these documents, free of charge, from Allegheny’s website (www.alleghenyenergy.com)
under the tab “Investors” and then under the heading “SEC Filings.”  You may also obtain these documents, free of charge, from
FirstEnergy’s website (www.firstenergycorp.com) under the tab “Investors” and then under the heading “Financial Information” and
then under the item “SEC Filings.”  Readers are cautioned not to place undue reliance on these forward-looking statements, which
speak only as of the date of this document. Allegheny disclaims any obligation to update its forward-looking statements to reflect
events or circumstances after the date of this presentation, except as may be required by law.
Certain information in this presentation is based upon an internal model that incorporates assumptions regarding future market
conditions, including power and commodity prices, demand conditions, and the operating performance and dispatch characteristics of
our generating facilities, among other factors.  Many of these assumptions are based upon highly variable market factors outside of our
control and ultimately may differ significantly from the assumptions currently included in our model.  As a result, our model and the
related forward-looking information included in this presentation are subject to change. The information in this presentation that is
derived from our internal model is based in part on market conditions, forward prices and our hedged position as of September 30,
2010. We intend to update this information on a quarterly basis.

5
Non-GAAP Financial Measures
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, reconciliations of
non-GAAP financial measures in this
presentation to the most directly comparable GAAP measures are contained herein or within our earnings
release and the tables attached thereto, which, together with this presentation, are available on our Investors
page at www.alleghenyenergy.com.
We have not included reconciliations of the forward-looking non-GAAP financial measures included in this
presentation to the most directly comparable GAAP financial measures, because it is not possible to predict in
the manner necessary for a quantitative reconciliation the amount of the items that we would remove from
GAAP earnings, such as unrealized gains or losses on our economic hedges.  The probable significance of
providing these forward-looking non-GAAP financial measures without the directly comparable GAAP financial
measures is that the non-GAAP financial measures may be materially different from the corresponding, actual
GAAP financial measures.

6
Primary Businesses
Output for 12 months ended December 31, 2009.  Customers exclude
VA.  Sale of VA distribution
operations was completed on June 1, 2010.
Allegheny
Energy
Merchant
Generation
Coal-fired, PJM
26.0 million MWH
Utility
Operations
1.5 million customers,
regulated generation
Transmission
Expansion
TrAIL, PATH,
other projects

7
Service Area and
Generation Facilities

8
Focused on high performance
Quality
Costs
Growing utility and transmission rate base
Merchant generation
Primarily scrubbed supercritical coal-fired units
Well-positioned for recovering economy
Merger with FirstEnergy scheduled for completion in
first half 2011
Overview

9
4.76
4.91
3.64
2.81
1.96
1.56
1.40
2003
2004
2005
2006
2007
2008
2009
OSHA Recordable Incident Rate
Allegheny Power
Focused on Quality
and Costs
Safety has improved from 3rd quartile in 2001
to top quartile.

10
Focused on Quality
and Costs
2002
2003
2004
2005
2006
2007
2008
2009
$1,166
$799
$735
$686
$682*
$665*
$668*
$965
Operations and Maintenance Expense
($ millions)
Costs have been held virtually
unchanged for four years.
*
2007-2009
excludes
formulaic
recovery
(2007
-
$5;
2008
-
$10,
2009
-
$19)

11
COMMERCIAL/INDUSTRIAL
Top quartile in 2010
First in northeastern US for six
consecutive years
Source:  TQS Research
Customer Satisfaction
Focused on Quality
and Costs
RESIDENTIAL
Top quartile in 2009
Top third in 2010
Source:  American Customer
Satisfaction Index
“Allegheny Energy does one of the best jobs in the nation at determining what its
largest customers want on an individual basis and then doing everything possible to
meet those needs.”
TQS Research, October 2010

12
Utility operations
Distribution
Transmission
Regulated generation (WV)
Transmission expansion
TrAIL
PATH
PJM transmission reliability projects
Merchant generation
Unregulated
Business Units

13
Utility Operations:
Overview
In 4 states (PA, WV, MD, VA)
1.5 million electric customers
Retail sales:  39.1 million MWH
Regulated generation:  over 2,700 MW (84% coal)
Allegheny Power
West Penn
Power
Monongahela
Power
Potomac
Edison
VIRGINIA
CHARLESTON
OHIO
HARRISBURG
MARYLAND
KENTUCKY
PENNSYLVANIA
CLEVELAND
BALTIMORE
PITTSBURGH
WASHINGTON, DC
WEST
VIRGINIA
Sales for 12 months ended December 31, 2009.  Capacity as of December 31, 2009.  Customers
and sales exclude VA.  Sale of VA distribution operations was completed on June 1, 2010.

14
PA
49%
WV
33%
MD
18%
Utility Operations:
Retail Revenue Mix, 2009
By State
By Customer Class
Residential
51%
Industrial
25%
Commercial
24%
Excludes VA.  Sale of VA distribution operations was completed on June 1, 2010.

15
Authorized Capital Structures
and ROE’s
STATE
RATE BASE
($ millions;
12/31/09)
APPROVED
EQUITY RATIO
APPROVED
ROE
RATIO/ROE
APPROVED ON
WV
$1,426
46%
10.5%
May 2007
PA
1,029
46
11.5
Dec. 1994
MD
447
44
11.9
Feb. 1993

16
2008
2009
2010
2011
2014
$2.9
$3.0
~$3.9
$3.1
$ billions
Potomac Edison*
West Penn
Mon Power
Utility Operations:
Growing Rate Base
$3.2
//
*
Excludes PE-VA distribution assets for all periods.
Note: Reflects PA Act 129 smart meter plan filed October 19, 2010 ($19 million in 2010 and $9
million in 2011).

17
9.29
9.18
10.37
12.90
8.61
13.91
Pennsylvania
West Virginia
Maryland
Allegheny Power
State Average
Utility Operations:
Competitive Rates
National
Average =
11.65 ¢/kWh
Residential Rates
¢/kWh as of January 1, 2010

18
80%
52%
13%
2011
2012
2013
2011 Customer Bill*
Residential
3% increase
Small/medium
non-residential
3-4% decrease
*
Based on power procured and
estimated spot prices
Pennsylvania:  Transition
to Market-Based Rates
Generation rate caps expire on December 31, 2010.
As of October 2010
Power Procured
% of residential needs

19
Transmission Expansion:
Overview
Allegheny is investing $2.7 billion in these projects.

20
($ millions; cash basis)
*
Allegheny’s portion of PATH project costs.
FERC-approved equity ratio = 50%
Transmission Expansion
Incentive returns have been approved by FERC.
APPROVED
ROE
PROJECT
TOTAL
2008
2009
2010
2011
TrAIL
12.7%
$960
$67
$384
$420
$45
Other projects
11.7-12.7%
385
37
71
81
64
PATH
14.3%
1,400*
8
44
29
133
CAPITAL EXPENDITURES

21
2008
2009
2010
2011
2014
$0.2
$0.8
~$2.4
$1.3
$ billions, year end
TrAIL
Other PJM
PATH
(Allegheny portion)
$1.3
//
Transmission Expansion:
Growing Rate Base
Note: Assumed weighted average ROE based on rates for TrAIL (12.7%), Other (11.7-12.7%), and  PATH (14.3%).

22
As of October 15, 2010
Transmission Expansion:
TrAIL Nearing Completion
Towers Constructed
Under
construction
3%
Constructed
97%
Under
construction
24%
Installed
76%
Wire Installed
Projected in-service date:
June 1, 2011

23
Merchant Generation:
Overview
Capacity (MW)*
* Capacity as of December 31, 2009.  Output for 12 months ended December 31, 2009.
Capacity:  over 7,000 MW*
Primarily scrubbed supercritical coal-fired units
Located in PJM (13 states)
Output (MWH)*
Hydro
10%
Gas
13%
Supercritical
Coal
64%
Other Coal
12%
Oil
1%
Supercritical
Coal
86%
Gas
3%
Hydro and
Other
5%
Other Coal
6%
Coal
92%

24
51%
86%
49%
14%
PJM
AYE
Merchant Coal Generation:
Only 14% is Subcritical
Subcritical
Supercritical
% of Coal Fleet Capacity
Allegheny’s coal fleet is more efficient and
has lower exposure to subcritical plants.

25
39%
58%
50%
53%
91%
53%
Scrubbers
SCRs
PJM
AYE
Merchant Coal Generation:
Environmental Controls
Allegheny’s coal fleet has more environmental controls.
% of Coal Fleet Capacity
Scrubbers and
SCRs

26
30-34
35-39
40-44
45-49
50-54
55+
Age of Unit (years)
AYE Capacity in MW
AYE Merchant Coal Generation:
Environmental Controls and Age
1,200
2,146
1,140
288
444
28
Scrubber & SCR      
Scrubber & SNCR Trim      
Scrubber Only      
SNCR Trim Only      
Non-Controlled
23%                 41%                 22%              
5%                   8%                <1%

27
Supercritical Coal Plants
(merchant and regulated)
Plant Availability
82%
78%
76%
83%
84%
83%
87.5%
82%
84%
87%
2002
2003
2004
2005
2006
2007
2008
2009
Top
Quartile
2010
9 Mos.

28
2011
2012
2013
74%
80-90%
29%
30-50%
Actual           Target by year-end 2010
Merchant Generation:
Power Hedges
7%
0-30%
% of Projected Coal Fired Output
October 20, 2010

29
AEP
Dayton
Hub
APS
Zone
PJM
W. Hub
AYE
Generator
Nodes
Transmission
Less Congestion
More Congestion
Each plant sells all its output
at its generator node price in
PJM energy market
APS Zone: legacy retail
customer base
Due to transmission
congestion, plants’
realized
energy prices tend to be
closer to AEP-Dayton Hub
today than to PJM W. Hub
PJM Western Hub, AYE Plants
and AEP-Dayton Hub

30
Key drivers:
Amount and location of supply and demand
Capability of transmission system
Marginal cost of unit(s) that respond to meet demand and resolve
transmission constraints
Basis differential is the difference between PJM energy
prices at two locations.
Basis Differential
Gas strongly influences
prices, especially on
peak
Located in a coal-dominated
region of PJM
Prices typically below W. Hub
Located in a coal-dominated
region of PJM
Prices typically below W. Hub
Less liquid than W. Hub
PJM WESTERN HUB
AYE SUPERCRITICAL
PLANTS
AEP-DAYTON HUB

31
Adjacent to reserves, rivers
Low transportation costs
Flexible procurement
Competing suppliers
A natural partner for
independent mines in need of an
“anchor”
purchaser
Contract costs in line with
operating costs of leading
producers
Location:  Favorable for
Coal Procurement
Supercritical coal generation facilities
Northern Appalachian coal basin
Rivers

32
Coal Type and
Delivery Methods
2010
(merchant; estimates)
Northern App.
Scrubber
57%
Northern App.
29%
PRB
4%
Illinois
10%
Rail
10%
Truck
11%
Conveyor
24%
Barge
55%

33
($ millions adjusted pre-tax; estimates as of 09/30/10)
2009
2010 Earnings
Actual
Increase (Decrease)
Adjusted EBITDA:
Merchant generation
$     578
$     (4)
Utility operations
540
8
Transmission expansion
65
83
Other
(2)
(7)
Depreciation
(282)
(43)
Interest
(258)
(51)
2010 Outlook

34
Merchant Generation:
Key Drivers of EBITDA
1
Excludes volumes from Buchanan and volumes consumed by pumping at Bath County.
2
The expected realized price received from PJM at the generator.
3
Includes emissions, lime, urea, natural gas, other fuels, OVEC purchased power, and Bath County pumping costs.
4
Includes ancillaries, Kern River, and other miscellaneous income.
5
Includes O&M, taxes other than income, and other income.
Note: numbers may not add due to rounding
Estimates as of 09/30/10 -
$ millions unless stated
2009
Actual
2010
Change
vs
2009
Total generation volume (TWh)
1
26
33
7 TWh
PJM Western Hub RTC price ($/MWh)
39
$      
45
$      
Basis and shaping ($/MWh)
(3)
(7)
Realized energy price ($/MWh)
2
36
$      
38
$      
$ 2 / MWh
Unhedged
energy revenues
937
$    
1,254
$ 
Coal expense
(552)
(745)
Other fuel related
3
(162)
(218)
Unhedged
energy margin
223
$    
291
$    
68
$         
Capacity
356
404
47
Other net revenues
4
83
78
(5)
Unhedged
net revenues
662
$    
773
$    
Operating expenses and other
5
(293)
(295)
(2)
Unhedged
EBITDA
369
$    
477
$    
108
$       

35
Merchant Generation:
Key Drivers of EBITDA
1
Includes POLR obligations, marketing contracts, and financial hedges.
2
Volume weighted contract price, including energy, capacity, ancillaries, congestion, and shaping.
3
Volume weighted market price as of 9/30/10 including energy, capacity, ancillaries, congestion, and shaping.
4
Difference between average contract price and contract market value multiplied by power hedge volume.
Note: numbers may not add due to rounding
Estimates as of 09/30/10 -
$ millions unless stated
2009
Actual
2010
Change
vs
2009
Unhedged
EBITDA
369
$   
477
$    
108
$   
Power hedge volume (TWh)
1
27
29
Average contract price ($/MWh)
2
55
$     
55
$      
Estimated market value ($/MWh)
3
47
51
Power hedge margin ($/MWh)
8
$        
3
$        
Power hedge margin
4
209
$   
97
$      
(112)
Adjusted EBITDA
578
$   
574
$    
(4)
$       

36
Note: For period 2010-2012 power volumes, % power hedged, and % coal priced are based upon 9/30/10
production forecasts which are subject to change; coal contract prices include delivery costs
Merchant Generation:
Key Drivers of EBITDA
1
Includes supplemental auctions
Estimates as of 09/30/10 -
$ millions unless stated
2009
Actual
2010
2011
2012
POWER VOLUMES
Coal-fired generation (TWh)
24.4
31.3
30.8
32.0
Total generation (TWh)
26.0
33.2
32.4
33.5
POWER HEDGES
% of coal-fired generation hedged
N/A
93%
67%
25%
Volumes (TWh)
26.7
29.0
20.7
7.9
Average contract price ($/MWh)
55
$                 
55
$    
56
$    
54
$        
Estimated market value ($/MWh)
47
51
49
49
Power hedge margin ($ millions)
209
$             
97
$    
150
$  
41
$        
COAL CONTRACTS
% of coal burn priced
N/A
100%
98%
69%
Volumes priced (tons)
10.1
12.9
12.5
9.0
Contract price ($/ton)
55
$                 
56
$    
59
$    
58
$        
CAPACITY REVENUES
1
Capacity (MW)
6,335
6,300
6,218
6,228
Price ($/MW-day)
154
$             
176
$  
138
$  
56
$        
Revenues ($ millions)
356
$             
404
$  
308
$  
127
$      

37
Note: broker estimates
1
SO2 allowance to ton of emission ratio –
2009 = 1:1 and 2010-2012 = 2:1
Merchant Generation:
Key Drivers of EBITDA
Actual
Balance
As of 09/30/10
2009
2010
2011
2012
POWER
($/MWh)
PJM West Hub RTC
38.75
$
37.67
$
41.08
$
43.15
$
AEP Dayton Hub RTC
32.98
31.50
34.78
37.83
NATURAL GAS
($/MMBtu)
Henry Hub NYMEX
3.92
$ 
3.94
$ 
4.44
$ 
5.07
$ 
COAL
($/ton)
-
excludes transportation
NAPP mid SO2
N/A
$73
$70
$73
NAPP high SO2
N/A
$48
$52
$56
EMISSIONS
($/allowance)
SO2
1
82
$    
7
$      
6
$      
3
$      
NOx
-
ozone season
302
60
33
N/A
NOx
-
annual
1,382
335
288
163

38
1
Change
in
pre-tax
income
=
(Total
generation
volume
–
power
hedge
volume
–
Bath
pumping
annual
volume
of
approximately
1.5
TWh)
x
realized
energy
price
sensitivity
($/MWh)
Note: does not reflect potential dispatch changes, load changes, changes in basis, or
correlations between variables; all sensitivities reflect hedge positions and production
forecasts as of 09/30/10
Merchant Generation:
Key Drivers of EBITDA
Change in adjusted pre-tax income ($ millions)
2010
2011
2012
REALIZED ENERGY PRICE
1
+ $10/MWh
4
$      
102
$  
240
$  
COAL PRICE
+ $10/ton
--
(3)
(41)

39
2008
2009
2010
2011
$991
$1,152
$996
$802
$
millions;
cash
basis
Capital Expenditures
Note:
includes
securitized
scrubber
capital
expenditures,
Allegheny’s
portion
of
PATH,
and
expenditures
for
PA
Act
129
smart
meter
plan
filed
October
19,
2010
($19
million
in
2010
and
$9
million
in
2011).
Transmission expansion
$112
$499
$530
$242
Utility operations
532
420
301
388
Merchant generation
347
233
165
172

40
Significant benefits to shareholders
Premium
Dividend increase
Diversifies fuel mix by adding nuclear capacity
Provides greater scale and scope
Strong business portfolio, excellent growth
opportunities
FirstEnergy Merger

41
FirstEnergy Merger:
Diversifies Fuel Mix
Coal:  Unscrubbed
17%
Coal:  Scrubbed
44%
Natural Gas
12%
Non-Emitting
1
26%
Combined Merchant Generation Capacity
1
Includes nuclear, wind and hydro
Other
1%

42
Revenue
$16.4 billion
Electric Customers
6.1 million
Rate Base
$10.3 billion
2
Total Generation
24 GW
Competitive Generation
21 GW
Service Territory
64,700 sq miles
Employees
~17,750
FirstEnergy Merger:
Greater Scale and Scope
Combined Statistics¹
1
12/31/2009 data, except where noted.
2
Excludes American Transmission Systems Incorporated (ATSI) and Allegheny Energy Transmission, LLC.
3
Reflects the sale of Allegheny Energy’s Virginia distribution assets, which was completed on June 1, 2010, and indicates the transmission
service area within Virginia. 
FirstEnergy (FE) Service Area
Allegheny Energy (AYE) Service Area
Potomac Edison/TrAILCo
VA
Transmission
Zone
3
FirstEnergy Power Plants
Allegheny Power Plants
OH
PA
NJ
MD
WV
VA

43
October 15 . . . . . . .
evidentiary hearings concluded
November 3 . . . . . .
main briefs due
November 15 . . . . .
reply briefs due
November 3  . . . . . .
evidentiary hearings commence
November 30  . . . . .
public comment hearings
commence
December 3  . . . . . .
initial briefs due
December 10  . . . . .
written public comments due
December 17  . . . . .
reply briefs due
January 7, 2011  . . .
decision deadline
FirstEnergy Merger:
State Procedural Schedules
Pennsylvania
Maryland

44
November 1 . . . . . .
company rebuttal testimony due
November 8 . . . . . .
evidentiary hearings commence
December 6*  . . . . .
initial briefs due
December 16*  . . . .
reply briefs due
FirstEnergy Merger:
State Procedural Schedules
*
Initial briefs due 20 days after transcript is available (estimated to be
November 15, 2010; reply briefs due 10 days after initial briefs).
West Virginia

Supplemental Information

46
Earnings (Loss) Per Share
As Reported
As Adjusted
As Reported
As Adjusted
2003:
Q1
$
(0.46)
$
(0.32)
2007:
Q1
$
0.65
$
0.65
Q2
(1.82)
(0.23)
Q2
0.45
0.45
Q3
(0.40)
0.11
Q3
0.67
0.67
Q4
(0.11)
(0.14)
Q4
0.65
0.46
Year
(2.80)
(0.37)
Year
2.43
2.26
2004:
Q1
$
0.25
$
(0.03)
2008:
Q1
$
0.80
$
0.80
Q2
(0.31)
(0.21)
Q2
0.91
0.45
Q3
(2.40)
0.37
Q3
0.52
0.54
Q4
0.48
0.22
Q4
0.10
0.51
Year
(1.83)
0.47
Year
2.33
2.30
2005:
Q1
$
0.29
$
0.39
2009:
Q1
$
0.79
$
0.67
Q2
(0.12)
0.08
Q2
0.43
0.41
Q3
0.21
0.45
Q3
0.45
0.59
Q4
0.02
0.02
Q4
0.64
0.66
Year
0.40
0.94
Year
2.31
2.33
2006:
Q1
$
0.67
$
0.68
2010:
Q1
$
0.52
$
0.61
Q2
0.18
0.22
Q2
0.71
0.57
Q3
0.65
0.56
Q3
0.68
0.73
Q4
0.38
0.37
Year
1.89
1.83

47
EBITDA
As Reported
As Adjusted
As Reported
As Adjusted
2003:
Q1
$
77.6
$
92.9
2007:
Q1
$
312.6
$
312.6
Q2
(203.5)
150.1
Q2
263.8
263.8
Q3
117.3
225.3
Q3
308.6
308.6
Q4
197.4
185.6
Q4
242.9
243.6
Year
156.8
634.9
Year
1,128.0
1,131.1
2004:
Q1
$
247.8
$
175.5
2008:
Q1
$
323.1
$
323.1
Q2
110.3
122.0
Q2
371.4
244.1
Q3
243.2
243.2
Q3
258.6
262.6
Q4
312.7
221.8
Q4
152.0
268.3
Year
914.0
762.5
Year
1,105.3
1,098.3
2005:
Q1
$
261.3
$
261.3
2009:
Q1
$
360.6
$
328.2
Q2
210.6
192.7
Q2
247.8
243.2
Q3
254.7
274.2
Q3
278.7
297.0
Q4
162.1
162.1
Q4
320.3
312.4
Year
888.6
890.2
Year
1,207.6
1,181.0
2006:
Q1
$
322.1
$
322.1
2010:
Q1
$
300.8
$
324.9
Q2
193.7
193.7
Q2
354.2
316.8
Q3
286.3
286.3
Q3
338.2
346.8
Q4
234.7
234.7
Year
1,036.8
1,036.8
$ millions

48
($1,200)
($700)
($200)
$300
$800
Cash Flow
$ millions
*
Adjusted cash from operations net of capital expenditures excluding securitization and
project financings.
Cash From
Operations
Capital
Expenditures
2004
2007
2006
2005
2008
Free Cash
Flow*
2009

49
Credit Ratings
Baa3
Ba3
B3
Moody’s
BBB-
BB-
CCC+
S&P
Senior Unsecured Debt
Baa2
Baa3
B1
Moody’s
BBB
BBB-
B
S&P
Senior Secured Debt
AE Supply
Ba1
Ba2
B2
Moody’s
BB+
BB-
CCC+
S&P
Senior Unsecured Debt
BBB-
BB+
B
S&P
Corporate Family Rating
AYE, Inc.
October
2010
2006
2003

50
Unhedged
energy margin:
Unhedged
energy revenues -
hedged coal expense
-
unhedged
coal expense -
other fuel related
Unhedged
net revenue:
Unhedged
energy margin + capacity +
ancillaries + other net revenues
Unhedged
EBITDA:
Unhedged
net revenues -
operating expenses
Power hedge margin:
(Average contract price -
estimated market value) x
power hedge volume
Adjusted EBITDA:
Unhedged
EBITDA + power hedge margin
Merchant Generation Outlook:
Formulas