first energy MorganStanley307

Morgan Stanley Anthony J. Alexander
Global Electricity & Energy Conference President & CEO
New York • March 15, 2007

Safe Harbor Statement under the
Private Securities Litigation Reform Act of 1995
Forward-Looking Statements: This presentation includes forward-looking statements based on information currently available to
management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to,
the terms quot;anticipate,quot; quot;potential,quot; quot;expect,quot; quot;believe,quot; quot;estimatequot; and similar words. Actual results may differ materially due to the speed
and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales
and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being
higher than anticipated or inadequately hedged, the continued ability of the registrant’s regulated utilities to collect transition and other
charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes
(including revised environmental requirements), and the legal and regulatory changes resulting from the implementation of the Energy
Policy Act of 2005 (including, but not limited to, the repeal of the Public Utility Holding Company Act of 1935), the uncertainty of the timing
and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such
amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source
Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or
operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the
Securities and Exchange Commission, the United States Attorney’s Office, the Nuclear Regulatory Commission and the various state
public utility commissions as disclosed in the registrant’s Securities and Exchange Commission filings, generally, and with respect to the
Davis-Besse Nuclear Power Station outage in particular, the timing and outcome of various proceedings before the Public Utilities
Commission of Ohio (including, but not limited to, the successful resolution of the issues remanded to the PUCO by the Ohio Supreme
Court regarding the Rate Stabilization Plan) and the Pennsylvania Public Utility Commission, including the transition rate plan filings for
Met-Ed and Penelec, the continuing availability and operation of generating units, the ability of generating units to continue to operate at,
or near full capacity, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce
initiatives), the anticipated benefits from voluntary pension plan contributions, the ability to improve electric commodity margins and to
experience growth in the distribution business, the ability to access the public securities and other capital markets and the cost of such
capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August
14, 2003 regional power outage, the successful structuring and completion of a potential sale and leaseback transaction for Bruce
Mansfield Unit 1 currently under consideration by management, the successful completion of the share repurchase program announced
March 2, 2007, the risks and other factors discussed from time to time in the registrant’s Securities and Exchange Commission filings,
including the registrant’s annual report on Form 10-K for the year ended December 31, 2006, and other similar factors. Dividends
declared from time to time on FirstEnergy's common stock during any annual period may in aggregate vary from the indicated amounts
due to circumstances considered by FirstEnergy's Board of Directors at the time of the actual declarations. Also, a security rating is not a
recommendation to buy, sell or hold securities and it may be subject to revision or withdrawal at any time and each such rating should be
evaluated independently of any other rating. The registrant expressly disclaims any current intention to update any forward-looking
statements contained herein as a result of new information, future events, or otherwise.
Morgan Stanley Global Electricity & Energy Conference
2

Strategic Vision: 2007 and Beyond
Our strategic focus continues to be on the
fundamentals…
Realizing the full potential of our asset base
Efficiently achieving environmental improvement
Controlling commodity costs and risks
Pursuing continuous improvement in all aspects
of the business
Managing transition to competitive markets
Enhancing financial strength and flexibility

DRIVING PERFORMANCE & DELIVERING RESULTS

3

Generation Strategy
Realizing our full potential

Pursue continuous improvement
– Benchmark analysis
– Fleet reliability
– Controlling costs
– Outage execution
– Excellence standards
Explore opportunities to mine existing assets for
cost-effective capacity additions
Effectively implement environmental compliance strategy

WELL-POSITIONED TO SUCCEED
IN A COMPETITIVE GENERATION MARKET

4

Generation Strategy
Continued improvement of asset utilization
(million MWh) Nuclear
100 Fossil & Hydro
84.4
82.3
81.6
79.8
76.4
80
66.8
32.0
29.0 31.2
28.7
29.9
60
21.1

40

52.6 52.4
51.1 51.1
46.5
45.7
20

0
2003 2004 2005 2006 2007E 2008E
Note: Excludes JCP&L

2003 to 2006 = 22% INCREASE IN GENERATION OUTPUT
3 CONSECUTIVE RECORD YEARS
5

Generation Strategy
Fossil and nuclear fleet highlights
Fossil Baseload Capacity Factor
Fossil Baseload Capacity Factor Capacity Forced Loss Net Generation
Nuclear Fleet 2006 Factor (% ) Rate (% ) (million MWh)
90%
Beaver Valley Unit 1 80.4 1.16 5.8
88.6%
88%
Beaver Valley Unit 2 87.7 1.75 6.3
85.9%
86% Davis-Besse 83.1 1.76 6.4
84.5%
Top Decile
84% Perry 96.8 3.44 10.5 *
82.2%
82% Top Quartile Fleet 88.0 2.27 29.0
79.6%
80%
2002 – 2005 Avg 79.0 3.15 26.0
78% * Record Generation
76.0%
76%

74%
Top decile nuclear performance in 2006
72%
– OSHA Rate
70%

– Fuel costs ($4.28 / MWh)
68%
2002 2003 2004 2005 2006 2007E
– Corrective Maintenance backlog
•Top performance came from Navigant benchmarking study

Recognized for on-line dose control
Top decile fossil baseload capacity
Summer Capacity Factor = 97.6%
factor in 2006
All units now under normal NRC oversight
Fossil load following unit capacity
factor reached 69% in 2006

6

Generation Strategy
Asset mining initiatives

MW Additions 2005-2006 2007E-2008E Cumulative
Fossil baseload uprates 100 30 130
Nuclear baseload uprates 49 100 149
Peaking capacity enhancements* 0 197 197
Wind power contracts 30 284 314
Total MW additions 179 611 790

* Reflects 12 separate projects including returning 70 MW at Burger Unit 3 that has not been available since summer 2005.

Mining existing asset base for low risk, cost-effective growth
Wind power contracts helping to meet renewable portfolio standards
Additional longer-term initiatives under review

7

Environmental Strategy
Our generation fleet is well positioned for the future
Fleet Emission Control Status

Capacity (MW) Fleet %
Non-Emitting 4,530 33%
Coal Controlled 2,569 19%
(SO2/NOx – full control)
Natural Gas Peaking 1,269 10%
8,368 62%

Longer-term environmental considerations
CO2 control – Approx. 40% fleet output is non-emitting
– Involved in CO2 capture and sequestration R&D
Mercury control – Excellent reduction through “co-benefits”
– Based on current rules and plans, in compliance until 2015
8

Environmental Strategy
AQCS expenditures estimated at $1.8B
Capital Expenditures
($ millions)
563
600
496
380
400

178
200 136
54
0
2005 2006 2007E 2008E 2009E 2010E

Construction Overview
– Sammis Plant (2,220 MW) – SO2 and NOx controls
– Mansfield Plant (2,460 MW) – SO2 control upgrades
– Eastlake Unit 5 (600 MW) & Burger Units 4 & 5 (300 MW) – NOx controls
– Bay Shore Unit 4 (215 MW) – SO2 and NOx controls

9

Commodity Operations Strategy
Effectively managing commodity margins and risks

Deploy generation to capture market opportunities
– Leverage presence in two RTOs
– Leverage FES retail market competencies
Enhance fuel supply optionality and flexibility
Effectively hedge commodity positions
Employ strict risk management controls and oversight
– Volume and price risks
– Generation availability risks
– Transmission congestion risks

10

Commodity Operations Strategy
Effectively hedging commodity positions

% Hedged 2007 2008
Coal only* 100% 98%
Coal transportation* 100% 46%
SO2* 100% 100%
NOx* 100% 100%
Nuclear fuel* 100% 100%

* Represents the percentage hedged of total forecasted generation.

Coal delivery optionality and fuel flexibility
– At least 3 coal delivery options for each baseload plant
– 8 units can burn any of 3 coal types and can switch quickly
– 9 additional units can operate within a wide blending range

11

Energy Delivery Strategy
Targeting improved operational & financial performance
Continued focus on enhancing reliability and
customer service
– Targeted reinvestment in T&D infrastructure
– Leveraging technology

Implement “Energy Delivery Excellence Program”
– Comprehensive review identified operational, technological,
scheduling, and financial control opportunities for improvement

Significant improvement in 2006 reliability metrics
– Distribution SAIDI improved 20%
– Transmission Outage Frequency per circuit is at top-decile

12

Financial Strategy
2007 Focal Points

Continue to use cash to benefit shareholders
– Sustainable common stock dividend growth
– 11.1% increase (March 1, 2007)
– Share repurchase
– 14.4 million ASR (March 2, 2007)
– Reinvest in business to generate future earnings
Execute Mansfield Unit 1 sale and leaseback transaction
– Capture benefit of $785M of expiring tax capital loss carryforwards
– Projected after-tax cash proceeds of $1.2B
Continue focus on capital structure management
Deliver consistent and predictable financial results

13

Financial Strategy
Improved operations & strategic execution

FirstEnergy’s financial accomplishments since 2004
– Achieved 3-year annualized total shareholder return of 24%
– Increased market capitalization by $7.6B (66%)
– Voluntarily contributed $1.3B to pension plan
– Invested over $3B in capital expenditures
– Reduced outstanding debt and preferred stock by over $1.2B
– Restored investment grade credit ratings
– Returned over $3B to shareholders in the form of share
repurchases and common stock dividends
– Increased common stock dividend 33%
– Repurchased 25 million shares of common stock (7.6%)

14

Financial Strategy
Aligning management and shareholder interests

Stock ownership*
– CEO = approx. 477,000 shares
– Executive Officers = approx. 1,754,000 shares
CEO compensation
– 80% of 2006 target total compensation was variable and delivered
through annual incentives and equity-based opportunities
Management incentive plan
– Includes both short-term and long-term incentives
– Tied to EPS, cash generation, safety, operational performance,
and long-term stock performance
* Includes shares beneficially owned and common stock equivalents

15

Financial Strategy
Compelling long-term growth potential
2010 &
2010 &
2007 2008 2009
2007 2008 2009 Beyond
Beyond

Managing the transition to competitive markets
– Penn Power (2007)
– Ohio Edison, Illuminating Company & Toledo Edison (2009)
– Met-Ed & Penelec (2011)
Phase-out of transition cost amortization
Power uprates and capacity additions
Wires growth and distribution rate cases
Aggressive operating efficiencies / cost savings
Well-positioned to succeed in a carbon-constrained world

16

FirstEnergy – Driving Performance & Delivering Results

WELL-PREPARED FOR THE FUTURE
Effectively managing transition
to competitive markets
Mining full potential of efficient,
Significant
low-cost generation fleet
Earnings
Reinvesting for future growth
Growth
Potential
Pursuing continuous improvement
Disciplined risk-management approach
Maintaining financial strength
and flexibility

17

Morgan Stanley
Appendix
Global Electricity & Energy Conference

FirstEnergy Generation Sources
Michigan Ashtabula
Perry 244 MW
Seneca
1,258 MW
Eastlake
Sumpter 443 MW
1,262 MW
340 MW Bay Shore
Stryker Erie
648 MW Lake Shore
18 MW Towanda Yards Creek
249 MW
Toledo
200 MW
Cleveland

Pennsylvania
New Castle
Akron
Davis-Besse Edgewater Morristown
Richland Newark
898 MW 48 MW
432 MW
West Lorain Johnstown Reading
Harrisburg
545 MW Allenhurst

Trenton

W. H. Sammis
2,233 MW
New
Columbus Beaver Valley Bruce Mansfield York Haven
Jersey
R. E. Burger 1,722 MW 2,460 MW 19 MW
413 MW
Mad River Forked River
60 MW
Ohio 86 MW
Plant Load Strategy
Baseload Peaking Units Other
Load Following
MW MW MW MW

Mansfield 1-3 2,460 Sammis 1-5 1,020 West Lorain 545 OVEC 463
Wind 30
Beaver Valley 1,2 1,722 Eastlake 1-4 636 Seneca 443
Perry 1,258 Bay Shore 2-4 495 Richland 432 Total 493
FirstEnergy Power Plants
Sammis 6,7 1,200 Burger 4 -5 312 Sumpter 340
C Coal 7,439 MW Davis-Besse 898 Lake Shore 245 Yards Creek 200
N Nuclear 3,878 Eastlake 5 597 Ashtabula 244 Burger 3 & EMDs 101
H Hydro Bay Shore 1 136 Forked River 86
662 Total Load Following 2,952
G Gas & O Oil 1,599 York Haven 19 Mad River 60
Other 129
Total Baseload 8,290
Other 493
Total Peaking Units 2,336
Total 14,071MW
Generation
App-3

Realizing Full Potential of Asset Base
Generation – Capacity Additions & Opportunities
Cost-effective capacity uprates (MW) 2005 2006 2007 2008 Total
Nuclear
Renewable portfolio additions Davis-Besse 14 12 26
Beaver Valley 1 25 43 68
– Long-term purchase power contracts Beaver Valley 2 10 45 55
from third-party wind-turbine facilities Total 49 43 57 149
– 314MW by end of 2007 Fossil
Mansfield 1 50 50
Potential opportunities Mansfield 2 50 50
Mansfield 3 30 30
– Re-powering projects Total 50 50 30 130
– Additional turbine upgrades Total Uprates 50 99 73 57 279

License renewal for 20-year
life extensions planned for
all nuclear units

Generation
App-4

Fulfilling Our Vision
Future Outages Focus on Reliability
Outage Outage
Scope Driving Duration
Year Plant Costs Duration
Items with asterisk* denote duration drivers
($ millions) (days)
Perry Refueling *
$30 30
1R11 IVVI
Split Pins *
Containment Sump Modifications*
Beaver Valley Reactor Vessel ISI *
2007 $32 28
1R18 100% Eddy Current Test
Reactor Vessel Head Inspection
Pressurizer Overlay

Davis-Besse 1R15 $30 31 Rewind Main Generator *

Split Pins *
Low Pressre-2 Turbine Inspection *
2008
Beaver Valley Reactor Vessel Head Inspection
$30 30
2R13 Main Cond Tube Replacement, Expansion Joints *
Replace High Pressure Turbine *
Type A Containment Pressurization Test
Refueling *
Perry
$30 25 10-year IVVI / Bioshield In-service Inspection
1R12
Recirc Pump Motor Replacement
Replace Low Pressure Turbines (2) *
2009 Beaver Valley
$30 30 Reactor Coolant System Loop Stop Valves (2)
1R19
Reactor Vessel Head Inspection
Beaver Valley
$30 25 Refueling *
2R14

Generation
App-5

Looking Forward
Continued Safe Operations through License Renewal

License Renewal Schedule
Submit
Current Approval New
Request
Expiration Expected Expiration
(NRC Docket)
Beaver Valley Unit 1 2016 2007 2009 2036
Beaver Valley Unit 2 2027 2007 2009 2047
Davis-Besse 2017 2010 2012 2037
Perry 2026 2013 2015 2046

Generation
App-6

Looking Forward
Cost-effective Operations

Fleet Production Costs
$/MWh
25

20

15

10

5

0
2002 2003 2004 2005 2006 2007E 2008E 2009E
24.88 20.88 16.73 18.94 20.43 17.57 17.16 19.29
Fleet

Production Costs includes O&M and Fuel.

Generation
App-7

Commodity Operations’ objective is to provide FE
with a predictable and profitable commodity margin.
+ Generation Margin
Commodity
Commodity – Transmission Expense
Margin
Margin – RTO expense
Commodity Margin

+ Generation Revenue
– Fuel
PJM // MISO
PJM MISO – Purchased Power
Expenses
Expenses Generation Margin

Regulated
MWH Regulated
Sales
Sales
MWH
FENOC
FENOC REV
80M MWh
80M MWh
COST
31M MWh
31M MWh
Competitive
MWH Competitive
Sales
Sales
REV
MWH
Generation 12M MWh
12M MWh
Fossil
Fossil
Margin
COST
Wholesale
51M MWh MWH Wholesale
51M MWh
Sales
Sales
REV
20M MWh
20M MWh
Purchased Power MWH
Purchased Power
34M MWh
34M MWh Losses &
Losses &
COST Pumping
MWH Pumping
4M MWh
4M MWh
Excludes JCP&L.
Commodity Operations
App-9

Purchased Power
(million MWh)
40
34 16.6
35

30

25

20 10.3
15

10
4.4
5 2.7
0
2007E Committed To Be Spot
Met-Ed
Committed
Penelec

App-10

Wholesale Sales
(million MWh)
25

20.6 14.6
20

15

10

2.4
5 0.6 3.0

0
2007E Committed To Be Spot Transmission
Committed Losses

App-11

Balanced emission allowance position minimizes risks.
SO2 Position (tons)
330,000 Needed Covered

240,000
Based on projected
generation:
150,000

Emission allowance
60,000
positions are well covered
-30,000
2007 2008
NOx positions are
completely covered
NOx Position (tons)
2007 and 2008 net SO2
30,000 Needed Covered
positions are covered
20,000

10,000

0
2007 2008

App-12

Procurement of coal supply will be vital to asset
utilization and a “predictable” margin.

Securing Open Coal
Commodity Positions
Aggressively working to
secure longer-term fuel
100%
2007
supply requirements
Actively testing alternate fuel
blends at various plants to
98%
2008
optimize plant economics
Engaged in fuel flexibility
00

00

00

00
0

0

initiative to create more options
00

,0

,0

,0

,0
5,

10

15

20

25

Total Covered Tons
Total Needed Tons

App-13

Secured fuel transportation position will be vital
to asset utilization and a “predictable” margin.

Securing Open Fuel
Transportation Positions
2007 transportation positions
100% covered based on
2007
budgeted generation
2008 transportation positions
54%
will be closed shortly —
2008
agreements reached
Evaluating additional delivery
00

00

00

00
0

0

options to increase both
00

,0

,0

,0

,0
5,

10

15

20

25

capabilities and flexibility
Total Open Tons
Total Covered Tons
Total Needed Tons

App-14

Coal Delivery Options
Fuel and Transportation Rail Barge Vessel Truck
options create leverage. Lake Shore
Bay Shore
Mansfield
Sammis
Ashtabula
Burger
Eastlake

Planned & Potential
15 14
14
Mine Sources 13
12
10
# of Mines

10

7
6
5

0
Lake Shore Bay Shore Mansfield Sammis Ashtabula Burger Eastlake
3 3 0 3 4 3 5
PRB
0 0 10 3 3 5 3
NAAP
3 4 0 6 6 6 6
CAAP

App-15

FOSSIL FUEL
($ millions) ($/MWh)
(excludes JCP&L)

Fuel Costs 1,200 $25.00

Generation and Fuel Expense
$20.00
($ millions) ($/MWh)
900
1,500 $20.00

1,200

$15.00
900
$16.00
600
600
300

$10.00
0 $12.00
2006 2007E 2008E
1209.0 1231.7 1356.0
Total Fuel
120.4 140.2 146.8
Nuclear Fuel 300
1088.6 1091.5 1209.2
Fossil Fuel (excl JCPL) $5.00
$14.83 $15.23 $16.15
$'s per MWh

0 $0.00
2006 2007E 2008E
1,088.6 1,091.5 1,209.2
Total Fossil Fuel
1.4 1.5 1.5
Other
20.8 22.9 24.6
Fuel Handling
14.9 13.1 13.8
Ash Disposal
11.2 11.8 12.0
Oil
20.0 25.6 22.5
Natural Gas
57.3 34.8 45.9
Emission
Allowances
52.8 58.6 62.5
Re-agents
254.6 358.8 402.2
Coal Transportation
655.6 564.4 624.2
Coal Commodity
$21.20 $21.02 $23.26
Fuel per MWh

App-16

Retail Regulatory Structure
Generation Transmission Distribution Transition Cost
Generation Transmission Distribution Transition Cost
Ohio Edison
RTC thru
Stable rates
Pass thru Fixed rates
thru 2008 2008 – OE, TE
CEI
thru 20081
MISO costs
“g + RSC” 2010 – CEI
Toledo Edison
Market in No CTC ended
In
Penn Power
2007 restriction Jan. 2006
Generation
CTC thru 20102
Met-Ed
POLR rates Pass thru No
thru 2010 PJM costs restriction CTC thru 20092
Penelec

JCP&L BGS Supply No restriction MTC thru 2018
1 CEI fixed through April 2009.
2 NUG recovery thru 2020.

Regulatory Matters
App-18

Regulatory Strategy
Managing the Transition to Competitive Markets
Pennsylvania

Penn Power
Successful transition to market-based generation rates
RFP process for 900 MW from Jan. 2007 – May 2008
Average auction price of $85/MWh replaced $55/MWh
for non-shoppers

Met-Ed and Penelec
PUC Order on transition rate plan issued Jan. 11, 2007
NUG accounting case heard in Feb. 2007

Regulatory Matters
App-19

Regulatory Strategy
Pennsylvania
Summary: Met-Ed and Penelec
Transition Plan Decision
Overall: $109M increase effective Jan. 12, 2007
Transmission recovery granted in full ($193M increase)
– Ongoing costs recoverable using a reconcilable rider
– 10-year recovery of 2006 deferral with carrying charges
Generation increase of $219M and NUG deferral
of $92M denied
Distribution decrease of $84M; ROE set at 10.1%

Regulatory Matters
App-20

Regulatory Strategy

Ohio Senate Bill 3 – Ohio Restructuring Legislation
(July 1999)
Generation Asset Transfer completed (4Q 2005)
Rate Certainty Plan approved (Jan. 2006)
– Stable transition for customers/companies through 2008
– Provides for synchronization of the following in 2009:
– Distribution rate increase, including recovery of
RCP deferrals
– Market-based generation rates
– Elimination/reduction of transition cost recovery

Regulatory Matters
App-21

Regulatory Strategy

Ohio
Rate shock experienced in other states not likely
for FirstEnergy
Termination/reduction of transition cost recovery
(average of $15/MWh in 2008) will substantially
mitigate any price increases to customers

Well positioned to participate in development
of the post-2008 market structure in Ohio

Regulatory Matters
App-22

Sale and Leaseback – Mansfield Unit 1
Structure of potential transaction under development
Retain operating control of asset
Projected after-tax cash proceeds of $1.2B
– Current use of proceeds assumptions
– $900M Share repurchase
– $193M Pension contribution (after-tax)
– $107M Short-term debt paydown

NPV expected to exceed $500M
Low-cost source of financing
Potential capital structure impact
– Maximum debt leverage impact of 200 bp
Target closing early in 2nd Qtr 2007

Financial Matters
App-24

Share Repurchase
On March 2, FE repurchased 14.4 million shares
– Represents approx. 4.5% of outstanding shares
– $900M ASR at initial price of $62.63 per share
Coupled with Aug. 2006 ASR program of 10.6 million
shares, total buy-backs equal approx. 7.6% of shares
outstanding
Projected net earnings impact from both buy-backs
is approx. $0.18 per share in 2007 vs. 2006

Financial Matters
App-25

Long-Term Dividend Policy
Annual growth target of 4–5%
Sustainable annual growth and a payout ratio appropriate
for our level of earnings

Dividend Changes:
Payment Quarterly Change from Annualized
Payment Quarterly Change from Annualized
Date Rate Prior Period Rate
Date Rate Prior Period Rate
1Q 2007 50.00¢ 11.1% $2.00
1Q 2006 45.00¢ 4.65% $1.80
4Q 2005 43.00¢ 4.24% $1.72
1Q 2005 41.25¢ 10.00% $1.65
4Q 2004 37.50¢ – $1.50

Financial Matters
App-26

FE Solutions (FES)
Targeting a debt ratio in the upper 50% range by 2008
– Genco-level tax-exempt debt with 4% average current cost
comprises approx. 44% of debt portfolio
– $1.4B of tax-exempt pollution control debt transferred from
operating companies to Gencos ($700M still to be transferred)
Targeting investment grade credit rating
Investment grade rating will enable FES to guarantee
– Mansfield 1 sale and leaseback performance and payment
obligations
– Letters of credit supporting tax-exempt debt at the Gencos
(replacing FE guarantees)
SEC registrant providing full financials during 2007

Financial Matters
App-27

FirstEnergy Credit Metrics
Funds from Operations /Interest Coverage
Adjusted Total Debt / Total Capital
5
70%

67%
60%
4
60% 58% 58%
56%
50%
3.7 3.5 3.5
3
40%
3.0
30%
2.5
2
20%
1
10%

0% 0
2002 2003 2004 2005 2006* 2002 2003 2004 2005 2006
*Includes the equity reduction of approximately $409m from the implementation of FAS 158

Funds from Operations / Total Debt
20%

18% 18%
17%
15%
14%
10%
11%

5%

0%
2002 2003 2004 2005 2006

Maintaining Financial Strength and Flexibility
Financial Matters
App-28

Capital Expenditures
($ millions)

Estimate
Estimate

2006 2007 2008
2006 2007 2008
Energy Delivery $ 650 $ 729 $ 868
FENOC 229 145 131
Fossil 116 90 68
Environmental 136 389 579
Other 39 90 68
Total $ 1,170 $ 1,443 $ 1,714

Financial Matters
App-29

FirstEnergy Credit Ratings
Corporate Credit Rating
(S&P) / Issuer Rating
Senior
As of March 7, 2007 (Moody's) / Issuer Default
Senior Secured Unsecured
Rating (Fitch)
S&P Moodys Fitch S&P Moodys Fitch S&P Moodys Fitch
FirstEnergy Corp. BBB Baa3 BBB - - - BBB- Baa3 BBB

Ohio Edison BBB Baa2 BBB- BBB+ Baa1 BBB+ BBB- Baa2 BBB

Cleveland Electric Illuminating Co. BBB Baa3 BB+ BBB Baa2 BBB BBB- Baa3 BBB-

Toledo Edison BBB Baa3 BB+ BBB Baa2 BBB BBB- Baa3 BBB-

Pennsylvania Power BBB Baa2 BBB- BBB+ Baa1 BBB+ BBB- Baa2 BBB

Jersey Central Power & Light BBB Baa2 BBB BBB+ Baa1 A- - - -

Metropolitan Edison BBB Baa2 BBB- BBB+ Baa1 BBB+ BBB Baa2 BBB

Pennsylvania Electric Co. BBB Baa2 BBB- BBB+ Baa1 BBB+ BBB Baa2 BBB

On February 2, 2007, Fitch upgraded the ratings of FE Corp, JCP&L, CEI, and TE.
The Rating Outlook is Positive for CEI and TE and Stable for all other rated subsidiaries.
The Ratings Outlook from Moody’s on all securities is Positive.
The Ratings Outlook from S&P on all securities is Stable.

Financial Matters
App-30

Strong Liquidity Position
Company Type Term Maturity Amount ($M)
Company Type Term Maturity Amount ($M)
FE Corp. RCA* 5-year Aug. 2011 $ 2,750
FE Corp. Bank Lines Various Various 370
OH & PA Utilities A/R Fin. 1-year Various 550
FE Solutions Bank Line 90 days 2007 250
Total $ 3,920
* Revolving Credit Agreement.

Substantial liquidity available
– $1.6B available borrowing capacity as of March 9, 2007

Financial Matters
App-31

2007 Non-GAAP Earnings Per Share Guidance
Issued January 31, 2007
$5.00

$0.18 ($0.19)
$4.50 $0.17 ($0.05)
($0.05)
($0.10)
$0.08 Net Share ME/PE
Repurchases Rate OH Trans- ($0.02) $4.15(1)
$0.12 Depr.
Case ition Cost
Net T&D Infra-
$0.06 Amort.
Nuclear All
(“D”)
Benefit
$0.07 structure
$4.00 Outage Other
Penn
$3.88(1) Costs
O&M
Generation Power
Wires Output & to Market
Growth Mix

$3.50

$3.00
Midpoint 2006 Midpoint 2007
Non-GAAP EPS Non-GAAP
EPS Guidance

See GAAP to non-GAAP reconciliation in the Appendix. 2007 EPS guidance, excluding unusual items, is $4.05 – $4.25.
(1)

On a GAAP basis, EPS is expected to be $4.10 – $4.30.
Financial Matters
App-32

2007 Cash Flow Drivers
Wires Growth: $20M
Gen Output/Mix: $15M
Penn Power to Market: $40M
Nuclear Outage O&M: $25M
PA Rate Increase: $60M
JCP&L NUG Recovery: $100M
Net Collateral: $80M

Net Pension Contribution: $373M
($90M tax benefit realized in 2006)
Securitization/Asset Sales in 2006: $310M
Higher Dividends / Capital Expenditures: $215M
Financial Matters
App-33

2008 Earnings Drivers
Growth in delivery sales
Increased generation margin
Lower generation-related outage maintenance costs

Higher Ohio transition cost amortization
T&D infrastructure investment
Increased fuel and purchased power costs

Financial Matters
App-34

2006 Earnings Per Share
Reconciliation of GAAP to Non-GAAP

Issued on February 20, 2007

2006 EPS
Basic EPS (GAAP basis) $ 3.84
Excluding Unusual Items:
Trust Securities Impairment 0.02
PPUC NUG Cost Reserve for Prior Years 0.02
Basic EPS (non-GAAP basis) $ 3.88

Financial Matters
App-35

2007 Non-GAAP Earnings Per Share Guidance
Reconciliation of GAAP to Non-GAAP

As of February 20, 2007

2007 EPS
Basic EPS (GAAP basis) $4.10 – $4.30
Excluding Unusual Items:
Benefit from New Regulatory Asset
Authorized by PPUC (0.05)
Basic EPS (non-GAAP basis) $4.05 – $4.25

Financial Matters
App-36

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