Deutsche Bank -...

NYSE:FE

Deutsche Bank 2008 Energy and Utilities Conference

Miami, FL • May 28, 2008

Rich MarshSenior Vice President and CFO

May 28, 2008Deutsche Bank 2008 Energy and Utilities Conference 2

Safe Harbor Statement under the Private SecuritiesLitigation Reform Act of 1995This presentation includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding our, or our management’s, intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Actual results may differ materially due to the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania, 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 FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, other legislative and regulatory changes including revised environmental requirements and possible greenhouse gas emissions regulation, 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 or other potential regulatory initiatives, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight by the Nuclear Regulatory Commission including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) as disclosed in our SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the Distribution Rate Cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Supreme Court of Ohio regarding the Rate Stabilization Plan and the Rate Certainty Plan, including the deferral of fuel costs) and Met-Ed’s and Penelec’s transmission service charge filings with the PPUC as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec, the continuing availability of generating units and their ability to continue to operate at or near full capacity, the ability to comply with applicable state and federal reliability standards, the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the ability to improve electric commodity margins and to experience growth in the distribution business, changing market conditions that could affect the value of assets held in our nuclear decommissioning trust fund, pension fund and other trust funds, the ability to access the public securities and other capital markets and the cost of such capital, the risks and other factors discussed from time to time in our SEC filings, and other similar factors. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. 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. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.


FirstEnergy Overview

Competitive

FirstEnergy Solutions (FES), an unregulated subsidiary:

– Controls 14,000+ MW of FirstEnergy’s generation capacity

– Separate SEC Registrant

Strategic Focus– Expand generation output– Transition to market-based rates– Effectively hedge commodity exposures– Leverage proven skills to succeed in

competitive markets

Regulated

7 Regulated Utilities– Fifth largest investor-owned electric utility

in U.S. with 4.5 million customers in OH, PA and NJ

– Geographic and regulatory diversity

Strategic Focus– Enhance reliability and customer service– Invest in infrastructure – Pursue timely cost recovery – Control expenditures through continuous

improvement culture

Balanced Integrated Approach

Objective: Maximize margins from each business


FirstEnergy Utilities

Large and balanced sales mix – 35% residential, 32% commercial, 33% industrial

Constructive regulatory environments– Achieve timely and full recovery of costs– Distribution rate cases pending for all three Ohio utilities

– Requested $332M revenue increase (including $120M of deferred cost recovery)– PUCO Staff recommended $114M-$132M increase (including $46M of deferred

cost recovery)– PUCO Staff recommended $115M be addressed in subsequent cases

T&D infrastructure being upgraded to enhance system reliability and customer service

Distribution outage duration reduced by 31% over past two years

Strong and Stable Cash Flows


FES Generation Fleet OverviewDiversified and cost-effective generating fleet

– Balanced fuel mix – Participates in both MISO and PJM markets

Mission-driven strategy– Each unit plays a specific role in fleet: baseload, load-following, or peaking– Strategy optimizes performance and reliability

Well-positioned for environmental regulations– CO2 control - over 35% of generation output is non-emitting

2007 Output Mix (MWh)

Fossil and Other

63%

Fossil and Other

63%

Nuclear37%

Nuclear37%

Generation Capacity (MW)*

Baseload 61%

Baseload 61%

Load-Following

22%

Load-Following

22%

Peaking17%

Peaking17%

* Based on May 2008 NDC


FES Generation Fleet StrategyExpand MWh Output

Expand output through efficiency improvements & uprates at existing units– Added 447 MW from 2005 - 2007; 266 additional MWs planned 2008 – 2011– Cost-effective, low risk approach – quick to market– ~$700/kW average capital cost substantially less than cost of new build– Since 1999: 27% increase in MWh production– No plans to build a baseload generating unit (less risky approach)

– Lower capital expenditures, less borrowing, and lower financing costs

Fremont Acquisition– Partially completed 707-MW combined-cycle gas plant purchased for $254M– 544 MW intermediate, 163 MW peaking – MISO/PJM dual interconnection– Cost to complete estimated at $150M-$200M* over 18-24 months for total cost of

approx. $600/kW

Expand wind energy contracts to enhance renewable portfolio– 145 MW currently on-line with 70 additional MWs scheduled to be completed in 2008

* Based on estimate from prior owner. Actual cost to complete subject to change following construction study.


FES Generation Fleet StrategyMaximize Generation Value

Effectively implement environmental compliance strategy– Air Quality Control (AQC) projects will enhance coal fleet emission control

status and long-term viability – Upon completion of upgrades, 80% of baseload and load-following generation

capacity will be fully scrubbed or non-emitting

Commodity Operations focuses on maximizing margins from generation with appropriate hedging of risks

– Deploy generation to capture market opportunities– Coal, coal transportation, nuclear fuel, and emission allowance needs

significantly closed for 2008 – 2010 forecasted generation

“Fuel Flex” expands margins and fuel choices– Blend coal to match market conditions on near real-time basis

– Maximize revenues when prices are high– Minimize fuel costs when prices are low


Transitioning Generation to Market Prices Industry Restructuring Status

New Jersey– Competitive generation service with market-based pricing in effect

(Basic Generation Service auction process began in 2002)

Pennsylvania– Transition to market-based pricing partially implemented

– Penn Power transitioned to market-based pricing in Jan. 2007

– Met-Ed (ME) and Penelec (PN) maintain POLR obligations at fixed rates through year-end 2010

– ME and PN scheduled to transition to market-based pricing in Jan. 2011

Ohio– Utilities transferred generation assets to competitive affiliate FES in 2005– Utilities maintain POLR obligations at fixed rates through year-end 2008– Utilities scheduled to transition to market-based pricing in Jan. 2009


Transitioning Generation to Market PricesOhio Legislative Update

Existing S.B. 3 – Enacted 1999– Generation rates to be market-based on January 1, 2009

Amended Sub. S.B. 221 – Signed by Governor on May 1, 2008– Requires all utilities to file an electric security plan (ESP)– Could also file a market rate offer (MRO) with the following criteria:

– Belongs to a FERC-approved RTO – RTO has a market-monitor function and the ability to mitigate market power– A published source exists that identifies information for traded electricity and energy

products scheduled for delivery two years into the future

– The Commission would test the ESP (pricing and all other terms and conditions) against the MRO and may only approve the ESP if it is more favorable to customers

– Bill also contains advanced and renewable energy standards and energy efficiency – Requires annual progress toward 2025 goal of 25% alternative energy– Requires energy efficiency programs to achieve annual progress toward 2025 goal of

cumulative energy usage reduction of 22%– Expect to file an ESP in the 2nd or 3rd quarter of 2008


Deploying Cash Effectively

Net cash from operating activities:– 2007: $1,694M– 2008F: $2,300M

AQC capital expenditures forecast: – 2008: $649M – 2009: $500M – 2010: $156M

Potential uses of free cash following completion of AQC projects– Dividend growth– Invest for future growth– Potential for share repurchases– Ability to take advantage of strategic opportunities


Annualized Total Shareholder Returns(Periods Ending December 31, 2007)

23.6%26.4%

21.3%

16.6% 17.8%19.9%

0%

5%

10%

15%

20%

25%

30%

1 year 3 years 5 years

FE EEI Index

Financial Performance

Positioned for continued earnings growth

Strong operations with financial discipline

Integrated strategy that diversifies risks

Annualized Dividend Per Share

$2.00$1.80

$1.72

$1.50

$2.20

$1.00

$1.25

$1.50

$1.75

$2.00

$2.25

$2.50

YE 2004 YE 2005 YE 2006 YE 2007 Mar. 08

47% IncreaseSince End of 2004


Bottom Line –FirstEnergy is an attractive risk/reward opportunity

Managing transition to competitive markets

Continuing to mine our assets

Reinvesting for future growth

Minimizing financing risks

Deploying strong cash flow

Achieving continuous improvement

Maintaining strategic flexibility

Well-positioned for climate legislation

NYSE:FE

Appendix


Corporate Profile


FirstEnergy Corporate Profile

Diversified energy company headquartered in Akron, Ohio

Involved in generation, transmission and distribution of electricity, as well as other energy-related services

Fifth largest investor-owned electric utility in U.S.– 4.5 million customers in Ohio, Pennsylvania and New Jersey

Controls over 14,000 MW of generating capacity

Approx. $13B in annual revenues and more than $32B in assets

Approx. $24B market capitalization

Investment grade credit ratings

OHPA

NJ


Generation


Akron

Toledo

Reading

Beaver Valley1,779 MW

Davis-Besse893 MW

Perry1,273 MW

R. E. Burger413 MW

W. H. Sammis2,233 MW

Bruce Mansfield2,490 MW

Eastlake1,262 MW

Ashtabula244 MW

Seneca451 MW

Edgewater48 MW

Richland432 MW

Stryker18 MW Yards Creek

200 MW

Mad River60 MW

West Lorain545 MW

Lake Shore249 MW

Sumpter340 MW

Erie

Ohio

Pennsylvania

NewJersey

Harrisburg

MorristownNewark

Allenhurst

Trenton

Bay Shore648 MW

Columbus

New Castle

Cleveland

Johnstown

Michigan

Baseload Load Following Peaking Units

Unit Mission Strategy

Towanda

MW MWMW

FirstEnergy Generation – Diversity & Scale

West Lorain 545Seneca 451Richland 432Sumpter 340Yards Creek 200Burger 3 & EMDs 101Mad River 60Edgewater 48Stryker 18Other 63

Total Peaking Units 2,258

Mansfield 1-3 2,490Beaver Valley 1,2 1,779Perry 1,273Sammis 6,7 1,200Davis-Besse 893Eastlake 5 597Bay Shore 1 136

Total Baseload 8,368

Sammis 1-5 1,020Eastlake 1-4 636Bay Shore 2-4 495Burger 4 -5 312Lake Shore 245Ashtabula 244

Total Load Following 2,952

OVEC 463Wind 145

Total 608

Other MW

FirstEnergy Power Sources*

C Coal 7,469 MWN Nuclear 3,945H Hydro 651 G Gas & O Oil 1,599

Other 522Total 14,186 MW

* Does not reflect the Fremont plant


Generation Output*

0

20

40

60

80

100

(mill

ion

MW

h)

Nuclear 29.9 28.7 29.0 30.3 32.0 31.0 32.2 32.0Fossil 46.5 51.5 53.0 50.7 52.7 52.4 53.7 54.6

2004 2005 2006 2007 2008F 2009F 2010F 2011F

* Does not reflect the Fremont plant.

Realizing Full Potential of Generating Fleet

Significant scale: FirstEnergy Solutions (FES) controls over 14,000 MW

Fleet strategy optimizes performance and reliability– Each unit has a specific mission (baseload, load-following or peaking) – Increases efficiency and reduces wear and tear on baseload units

Nuclear fleet produced a record 30.3 million MWh in 2007

Fleet Characteristics and Mission-Driven Strategy



Mining Our Assets benefits:– ~$700/kW average capital cost is competitive vs. current market price of new capacity– Lower risk than large, long lead-time projects– Quicker to market

Factors impacting future generation asset decisions:– Capacity and ancillary services market structure– Technological advances– Environmental regulations

*Reflects elimination of seasonal reductions in output due to summer temperatures on peaking units** Reflects 45 MW baseload unit and 84 MW load-following unit efficiency and capacity factor improvements

Type of MW Addition 2005–2007 2008F–2011F Cumulative MW

Fossil baseload uprates 130 44 174

Peaking unit uprates 16 0 16

Nuclear baseload uprates 152 93 245

Efficiency and capacity factor improvements 149* 129** 278

Total MW additions 447 266 713

Mining Our Assets – incremental, low-risk investment approach to fleet expansion


Status Capacity RECs/Year

In-service 2007 145 MW 384 GWh

ForecastedIn-service 2008 70 MW 180 GWh

Total: 215 MW 564 GWh

FES Wind Energy PortfolioState Renewable

Mandate Overview

PA 18% by 2020Drives our renewable strategy today

Will impact our renewable strategy

Represents a minimal part of our renewable requirements

OH 12.5% by 2025

NJ 22.5% by 2020

Leading the Way in Procuring Renewable Energy to Meet Growing Demand

Leading wind energy supplier in PA

Evaluating expansion of current wind portfolio

Considering other renewable technologies:– Solar– Compressed air– Biomass– Land fill gas– Anaerobic digestion



Reinvesting in the Business

FirstEnergy Generation Corp. acquired partially complete 707-MW natural gas, combined-cycle generating plant in Fremont, Ohio

– Includes two combined-cycle combustion turbines and a steam turbine– 544 MW of load-following capacity and 163 MW of peaking capacity

– Purchased in bankruptcy auction from Calpine Corporation for $253.6M– Aggregate construction costs expended to date exceeded $300M– Calpine has estimated that the plant is 70% complete

– Based on this, FirstEnergy estimates cost to complete is approximately $150M - $200M* over 18-24 months

Key benefits to FirstEnergy:– Plant is connected to two RTOs – MISO & PJM – Expands fleet capacity and further diversifies generation mix– Low-emitting characteristics will further reduce our average CO2 emission rate

Enhancing Our Generation Portfolio for the Future

* Based on estimate from prior owner. Actual cost to complete subject to change following construction study.


Fossil 2007 2008F 2011 Target*OSHA Incident Rate (per 100 employees) 1.04 1.12 0.80

Total Generation (million MWh) 50.7 52.7 54.6

Capacity Factor (Baseload %) 80.4 87.2 90.7

Fossil Operating Performance2007 Highlights

– Top-quartile safety performance – New monthly all time generation record

set Aug. 2007 (4.6 million MWh)– Environmental projects (AQC) on track– Outage performance improving– Implemented Fossil Excellence at

Bay Shore and Sammis (continuous improvement)

– On track for workforce replenishment– Improved performance accountability– Mansfield Unit 3 uprate (30 MW)

2008 Look Ahead– Achieve top-decile safety performance – Drive continuous improvement through

fleet standardization of best practices, benchmarking and Fossil Excellence annual diagnostics

– Continue to focus on transitioning workforce knowledge and skills to a new generation of employees

– Execute Mining Our Assets strategies– Develop and implement a full start-up

testing, training and operation strategy for AQC



Nuclear Operating Performance2007 Highlights

– Top-quartile safety performance– DB worked > 7.6 million hours without

a Lost Time Accident– Record Fleet Generation (30.3 million MWh) – BV1 uprate (43 MW); BV2 uprate (24 MW)– No forced losses at BV1; BV2 top quartile

(0.05%)– NRC accepted BV license renewal application– Successful NRC Security drills at PY and BV– Lowest BV dose during fall outage

2008 Look Ahead– Maintain top-quartile safety performance– Targeting record generation

(32.0 million MWh) – Two outages – DB (Completed 2/14/08)

and BV2 (Expected return in late May)– 15 MW uprate at PY effective 1/1/08– Additional 12 MW from DB Caldon

modification– Additional 45 MW from BV power uprate– NRC Emergency Preparedness

Evaluated Exercises at BV and PY – Dry Cask Fuel Storage underway at PY

Nuclear 2007 2008F 2011 TargetOSHA Incident Rate (per 100 employees) 0.29 0.25 0.25

Total Generation (million MWh) 30.3 32.0 32.0

Capacity Factor (%) 88.8 92.9 92.4


Top-Tier Operational Capability

Garnered significant nuclear reliability improvements during 2006–2007 outages

Fossil fleet expected to return to top-quartile performance in 2008 – AQC-related outages will lower capacity factors in 2009 and 2010– Expect to reach top-decile performance levels by 2011

Baseload Capability/Capacity Factors

75%

80%

85%

90%

95%

100%

Fact

ors

(%)

Fossil baseload 84.6% 86.9% 88.5% 80.4% 87.2% 90.7%

Nuclear 89.5% 86.2% 86.8% 88.8% 92.9% 92.4%

2004 2005 2006 2007 2008F 2011 Target

Continued Improvement of Asset Utilization


Operational Performance Targets

Operational Performance 2004 2005 2006 2007 2008F 2011 Targets*

Total Generation (million MWh) 76.4 80.2 82.0 81.0 84.7 86.6

Fossil Reliability

Capacity Factor (Baseload %) 84.6 86.9 88.5 80.4 87.2 90.7

Nuclear Reliability

Capability Factor % 89.5 86.2 86.8 88.8 92.9 92.4



Nuclear Generation

Year PlantExpected

Outage Duration(days)

Scope Driving Duration(Items with asterisk* denote duration drivers)

Davis-Besse1R15 Complete

Refueling *In-vessel visual inspection (IVVI)Rewind Main GeneratorReinforce welds on plant equipment

2008

Beaver Valley 2R13

Complete (expected return

in late May)

Split Pins*Low Pressre-2 Turbine Inspection*Reactor Vessel Head InspectionMain Cond Tube Replacement, Expansion Joints*Replace High Pressure Turbine*Type A Containment Pressurization Test

Perry 1R12 35Refueling*10-year IVVI / Bioshield In-service InspectionRecirc Pump Motor Replacement

Beaver Valley 1R19 30

Replace Low Pressure Turbines (2)*Reactor Coolant System Loop Stop Valves (2)Reactor Vessel Head Inspection

Beaver Valley 2R14 25 Refueling*

2009F

Future Refueling Outages Focus on Reliability


Generation – Implementing Plans for the Future

Nuclear license renewal

Nuclear steam generator replacements– Davis-Besse in 2014– Beaver Valley Unit 2 in 2017

Current Expiration

Submit Request (NRC Docket)

Approval Expected

New Expiration

Submitted 2007* 2036

Beaver Valley Unit 2 2027 Submitted 2007* 2009 2047

Davis-Besse 2017 2010 2012 2037

2046Perry 2026 2013 2015

Beaver Valley Unit 1 2016 2009

* The NRC accepted the application for review.


Generation – Implementing Plans for the Future

Nuclear spent fuel storage– At the federal level, Yucca Mountain has been proposed as a site for

long-term storage and may be available as early as 2017 to receive used fuel, but this is not likely. If Yucca Mountain is available in 2017, FirstEnergy will be eligible to ship fuel starting in 2021.

Beaver ValleyUnit 1 Implement dry storage by the end of 2014

Beaver ValleyUnit 2

Current ongoing criticality analysis will increase storage spaceRe-rack before 2011 to provide capacity through 2025 Dry storage could then be implemented

Davis-BesseContinue with wet storage until 2021Switch back to dry storage in 2022

Perry Implement dry storage before 2011


Environmental Strategy


Longer-term environmental considerations:CO2 control – Over 35% of annual fleet output (MWh) is non-emitting

– Involved in CO2 capture and sequestration R&D

Mercury control – Excellent reduction through “co-benefits”– Participating in future mercury regulatory developments


Fleet Emission Control Status2007 2010F*

Fleet % Fleet %

34% 34%

19% 38%

9% 9%62% 81%

Capacity (MW) Capacity (MW)

Non-Emitting 4,581 4,653Coal Controlled(SO2/NOx – full control) 2,626 5,237

Natural Gas Peaking 1,283 1,1978,490 11,087

Our Generation Fleet is Well-Positioned for the Future



AQC Construction OverviewReinvesting in the Business

Sammis Plant (2,233 MW) – $1.65B– SO2 control (scrubbers) all units– NOx control (SCRs) Units 6 & 7 (1,200 MW)

NOx control (SNCR) Units 1–5 (1,033 MW) completed

Mansfield Plant (2,490 MW) – $50MSO2 control (scrubber) upgrades completed

Burger Plant – $180M– NOx control (SNCR) and SO2 control

Electro-Catalytic Oxidation (ECO) Units 4 & 5 (312 MW)

Eastlake Plant – $6MNOx control (SNCR) Unit 5 (597 MW) completed


Sammis Plant with computer overlay of Wet Flue Gas Desulphurization (WFGD) equipment

AQC Upgrades – Sammis Plant

Flue Duct Work – 9,000 tons (9,000 ft.)

Electrical Cable – 9,120 circuits (530 miles)

Foundation Piles – 5,600 piles (445,000 LF)

Concrete – 51,000 cubic yards

Tons of Steel – 17,200 tons

DCS I/O Points – 8,200

Large Bore Pipe – 88,300 ft. (17 miles)

Small Bore Pipe – 13,000 ft. (2.5 miles)

Overland “Pipe” Conveyor – 3.0 miles long


Participating in Global Climate Change Policy• Global Roundtable on Climate Change• EPRI Global Climate Policy Costs & Benefits Research• EEI Climate Change Policy Subcommittee• NEI Climate Change Policy Subcommittee

GHG Reduction Technologies & Voluntary Actions• Asia-Pacific Partnership• EPA SF6 Reduction Partnership• EPRI GHG Reduction and Electric Transportation Research• Climate Vision• DOE 1605(b) Voluntary Reporting of GHGs Program• Powertree Carbon Company

Generation Initiatives• Fossil plant efficiencies • Nuclear plant uprates

CO2 Capture and Storage Technologies• MRCSP – R.E. Burger Plant Sequestration test well• ECO2 Carbon Capture – Powerspan• EPRI research• Power Partners• Oxy Fuel – B&W

End-user Energy Management• NJ Clean Energy Program• PA Sustainable Energy Fund• Ohio Energy-efficiency Programs

Renewables• 650 MWs Hydro• >200 MWs Wind Purchase Agreements

Renewal of Nuclear and Hydro Plant Operating Licenses

• Continued operation of non-emitting generation

Environmental StrategyFirstEnergy’s Climate Activities

http://www.eei.org/


FirstEnergy’s Position on Global Climate Change

Climate change is a global issue ultimately requiring a global solution

Technology development is key – Energy efficiency and demand-side management– Clean coal technologies– Carbon capture and sequestration

Significant future impact on price of electricity whether states are regulated or deregulated

– Be consistent over broad geographic region– Include reasonable compliance timeframes – Encourage new cost-effective technologies


Additional Key Technologies FirstEnergy is Actively Co-Funding

Plug-in hybrid electric vehicles (PHEV)

– Considerably cleaner than internal combustion engine vehicle, including battery charging

– 30% less GHG– 15% less SO2 and NOx

– Provides largely off-peak demand, an opportunity for growth– Advanced meters are an enabling technology


Commodity Operations


Coal Commodity Position

Continue working to secure long-term fuel supply contracts

Actively testing alternate fuel blends at various plants to optimize plant economics and flexibility

Engaged in fuel flexibility initiative to expand margins and fuel choices

FirstEnergy is well positioned with respect to its total coal supply through 2010

Securing Open Coal Commodity Positions

0 5,000 10,000 15,000 20,000 25,000

2010

2009

2008

Total Needed Tons Total Covered Tons

98%

100%

100%

As of May 13, 2008


Coal Transportation Position

All transportation positions including both rail and barge are closed thru 2010 year end

Continuing to evaluate additional delivery options to increase both capabilities and flexibility

Enhanced rail unloading capabilities in process at Ashtabula, Bay Shore and Lake Shore

In 2008, FES is managing PRB rail logistics previously outsourced

Securing Open Coal Transportation Positions

0 5,000 10,000 15,000 20,000 25,000

2010

2009

2008

Total Needed Tons Total Covered Tons

100%

100%

100%

As of May 13, 2008


Emission Allowance Position

Based on projected generation:– Latest fuel assumptions for 2008 &

2009 have further solidified our SO2length

– 2010 SO2 position was closed early to mitigate potential scrubber projects completion risks

– Seasonal NOx is covered for 2008 & 2009; 2008 & 2009 length will secure a portion of the 2010 position; 2010 is expected to be covered by the end of Q1 2009

– Majority of 2009 – 2010 annual NOx requirements are covered from allocations made by states

SO2 Position

0

90,000

180,000

270,000

2008 2009 2010

(ton

s)

Needed Covered Position

Seasonal NOx Position

-10,000

0

10,000

20,000

30,000

2008 2009 2010

(ton

s)

Needed Covered Position

As of May 13, 2008


Fuel Flexibility Creates Margin & Fuel Choices

Enhanced systems, tools and processes providing the ability to react and adjust blends quickly to match market prices

“Fuel Flex” creates value by continuously increasing fuel blend choices– Maximize revenues when real-time market prices are favorable– Minimize costs when market prices are low

The Right Fuel at the

Right Time


Expected Total Supply

020406080

100120

(mill

ion

MW

h)

Forward / Spot Purchases 12 7 9Nuclear 32 31 32Fossil, Hydro, Wind 53 52 53

2008F 2009F 2010F

Supply numbers exclude JCP&L and firm contract portion of ME/PN

Managing Commodity Positions

Significant reductions in mostly on-peak energy purchases

97 90 94

•*Assumes move to open market in Ohio in 2009 and beyond. Does not reflect the Fremont plant.

Expected Supply Portfolio for FES*


Expected Total Sales

020406080

100120

(mill

ion

MW

h)

Retail Auction 1 31 29Competitive Retail 12 20 24Forward / Spot Sales 18 20 21ME/PN PRA Obligations 14 19 20OH PSA Obligations 52 0 0

2008F 2009F 2010F

Sales numbers exclude JCP&L and f irm contract portion of ME/PN

Managing Commodity Positions

Transition from Power Supply Agreement (PSA) obligations to higher margin sales

97 90 94

•* Assumes move to open market in Ohio in 2009 and beyond. Does not reflect the Fremont plant.•PRA- Partial Requirements Agreement•NOTE: Supply includes generation output and forward/spot purchases

Expected Sales Portfolio for FES*


PJM Net Capacity

(3500)

(2500)

(1500)

(500)

500

1500

2500

3500

MW

2008 20102009

Includes Beaver Valley, Forked River, and Seneca

PJM Capacity PositionME and PN have long-term capacity contracts

Beaver Valley nuclear plant (1,779 MW) committed in PJM to cover capacity position

Covered capacity prior to RPM auction for planning year 2008-2009 to replace long-term contracts

Committed Seneca pumped storage (451 MW) to PJM as a capacity resource for planning year 2009 (commencing in June 2009)

FES View (continuing to serve ME and PN PRA)


Energy Delivery


FirstEnergy Service Areas

Toledo Edison 313,000 2,300

Ohio Edison 1,040,000 7,000

The Illuminating Company 756,000 1,600

Penelec 589,000 17,600

Penn Power 159,000 1,100

Met-Ed 542,000 3,300

Jersey Central Power & Light 1,087,000 3,200

Total 4,490,000 36,100

Customers Square Miles


Focus Area Key Metrics 2007 2008F 2011 Target

Reliability

Distribution SAIDI (minutes) 131 128 107

TOF (per circuit) * 0.72 0.69 0.63

Financial PerformanceAchieve top-quartile total spend per customer Total Cost Per Customer $273 $272 $277

Top-quartile performance SAIDI and TOF

* TOF has been revised to include all circuits 69KV and above (previously 230KV and above)


Total Direct Cost per Customer

$150$180$210$240$270$300

2005 2006 2007 2008 2009 2010 2011 2012

Tota

l Dire

ct C

PC

ED&CS Top Quartile

Energy Delivery – Striving to Achieve Top-Quartile Performance

SAIDI Performance

104070

100130160190220

2005 2006 2007 2008 2009 2010 2011 2012

SAID

I (M

inut

es)

ED&CS Top Quartile


Regulated Rate Base and Sales Growth

Projected Rate Base –Regulated Companies (T&D)($ millions)

2008F 2011 Target

Net Plant for Rate Base $10,100 $11,000

Capital Expenditures, Net of Depreciation $365 $330

Average Annual (2009F – 2011F) OH PA NJ

0.9% 2.2%

Net Plant for Rate Base ($ millions) $4,420 $3,290 $3,000

1.12.1

Growth Rate (kWh) 1.7%

# of Customers (millions) 1.3

Projected Annual Growth

Growing asset base and increased distribution throughput


Capital Planning Enhancements

Benchmarked leading performers in the area of capital allocation

Selected Navigant to help develop capital allocation tool based on fundamental engineering economics (quantified benefits)

E-CAT provides the granularity which drives our ability to prioritize thousands of projects based on predicted benefits

Energy Delivery Capital Allocation Tool (E-CAT)

Game Plan:

Target spend with an emphasis on improving reliability

Continued focus on operational improvements

Capital planning has undergone a fundamental change to enhance our financial discipline


Workforce Management

Power Systems Institute (PSI)– Started in 2000; partnered with two colleges in Ohio to offer

lineworker training– Currently, partnerships with 11 local community colleges

and universities across OH, PA and NJ

Enrollment/Hires 2000–2007

Started Program Graduated Hired

Line Workers 276 236 214

Substation Electricians 110 87 82

Total 386 323 296

2008F 2009F

123 177

31 60

154 237


Regulatory / Legislative Matters


Retail Regulatory Structure

1 CEI fixed through April 2009.2 NUG recovery thru 2020.

Generation Transmission Distribution Transition Costs

Ohio Edison

CEI

Toledo Edison

Stable rates thru 2008 “g + RSC”

Pass thru MISO costs

Fixed ratesthru 20081

RTC thru:2008 – OE, TE

2010 – CEI

Penn Power Market in2007

InGeneration No restriction CTC ended

Jan. 2006

Met-Ed CTC thru 20102

Penelec

Pass thruPJM costs CTC thru 20092

JCP&L BGS Supply No restriction MTC thru 2018

POLR ratesthru 2010 No restriction


Ohio Regulatory Update

Ohio Edison, CEI and Toledo Edison– Case detail (as filed)

– Request: $332M increase (7% on overall rates)– Distribution revenue requirements: $212M– Deferral recovery: $120M

– Case schedule– Filed June 2007, with 2008 test period and date certain of May 31, 2007– PUCO Staff report issued Dec. 4, 2007– Evidentiary hearings held Jan. 29, 2008 – Feb. 25, 2008– Public hearings held Mar. 5 – Mar. 24– Main briefs filed Mar. 28; reply briefs filed Apr. 18– Rates to be effective Jan. 2009 (CEI in May 2009)– Expect PUCO Order in 2nd or 3rd quarter of 2008

Distribution Rate Requests



* Assumes current Generation & Transmission rates

Proposed Changes in Revenues ($ millions) TotalCurrent "Distribution" Revenues $1,118Requested Increase:

Associated with RCP Fuel Expense Deferrals 34Associated with RCP Infrastructure Expense Deferrals 40Associated with RCP DSM Deferrals (through a rider) 4Associated with ETP & Ohio Line Extension Deferrals 42"Base" Revenue Requirement Increases 212

Total Requested Increase to "Distribution" Revenues $332Proposed "Distribution" Revenues $1,450Offsetting RTC Decrease ($594)Net Decrease, Including Offsets * ($262)% Decrease, Including Offsets to Total Current Revenues * -5.7%

Distribution Rate Requests (as filed)


Requested Increase in Revenues ($ Millions)To be effective 1/09 for OE & TE 1/09; 5/09 for CEI

Company Filing

PUCO Staff Testimony

Traditional distribution costs $212 $68 – $86Recovery of costs deferred under prior rate plans 120 46Total requested increase to "distribution" revenues $332 $114 – $132

Ohio Regulatory UpdateDistribution Rate Requests (as filed)

Key PUCO Staff Testimony Differences

Matters to be considered in other cases ($115)*ROE @ 10 to 11% (vs. Co. @ 11.75%) ($35) – ($16)Other issues (net) ($68)

Expect PUCO Order in 2nd or 3rd quarter of 2008

Timing of requested distribution rate increases coincides with reduction/ elimination of regulatory transition revenues and amortization expenses

* $52M related to expenses in distribution case amount, $63M related to recovery of costs deferred for fuel and post date certain



Rate Certainty Plan provided for the deferral of 2006 – 2008 incremental fuel costs

– Recovery was planned to occur in distribution rates over 25 years, but Supreme Court of Ohio remanded the recovery mechanism to PUCO

– On Jan. 9, 2008, the PUCO:– Authorized concurrent recovery of actual 2008 fuel costs via a fuel generation

rider commencing Jan. 1, 2008 (currently projected at approx. $189M)– Directed the Companies to file an alternative recovery mechanism to collect the

2006-2007 deferred fuel costs ($220M) and carrying charges ($6M)

– On Feb. 8, 2008, the Companies filed a separate fuel cost recovery rider for the 2006-2007 fuel and carrying charge deferrals

– Proposed recovery periods ranging from 5 and 25 years– Evidentiary hearing scheduled for July 15, 2008

Supreme Court of Ohio Remand on Deferred Fuel Recovery



Ohio Edison, CEI and Toledo Edison– On July 10, 2007, filed a comprehensive supply plan for competitively

priced generation service to implement market provisions of S.B. 3 effective Jan. 1, 2009

– Proposal includes:– Option to phase in generation price increases for residential tariff groups that

experience > 15% increase in avg. total price– Time-of-day and hourly pricing options– Renewable energy component

– Competitive bid process (CBP) alternatives– By Customer Class, or– Slice of System

Competitive Generation Procurement Proposal



CBP process– Descending clock bidding format– Full requirements product (energy, capacity, transmission)– Individual bidders limited to 75% of total customer load– Multiple solicitations; three-year ladder

Bids secured in 2008 would be for service beginning Jan. 1, 2009, and ending:

– May 31, 2010 (17-month)– May 31, 2011 (29-month)– May 31, 2012 (41-month)

Subsequent annual bids for 1/3 of load (3-year supply)

Competitive Generation Procurement Proposal (continued)


Pennsylvania Regulatory Update

Met-Ed (ME) and Penelec (PN)

Commonwealth Court appeals of rate cases– $109M net increase effective Jan. 2007– Pending appeals to Commonwealth Court

– ME & PN – denial of generation relief and tax expense adjustment– Industrials & OCA – transmission recovery– Oral arguments before panel of judges scheduled for September 2008

Generation procurement filing plan– ME and PN transition to competitive generation market prices on

Jan. 1, 2011– Plan to submit generation procurement proposal in 2008

Commonwealth Court Appeals & Generation Procurement Filing


Penn Power POLR II CasePennsylvania Regulatory Update

Penn Power successfully transitioned to competitive generation market prices on Jan. 1, 2007

POLR I RFPs implemented for Jan. 2007 – May 2008

POLR II (June 2008 – May 2011)– Multiple RFPs for residential and small commercial customers– Hourly pricing for large commercial and industrial customers

RFP Tranches (50 MW)Group Term

Feb 08 Mar 08 Apr 08 May 08

2 2

2

0

2

0

Oct 08 Jan 09 Oct 09 Jan 10

Residential 1 year 0 0 0 0 2 2

Residential 2 year 0 0 2 2 0 0

Small Commercial 1 year 3 4 3 4 3 4

Small Commercial■ RFPs held on Feb. 20 and Mar. 18 for June 2008 – May 2009 ■ Average price of winning bids was $80.49/ MWH (before line

losses, administration fees, and gross receipt taxes)

Residential■ RFPs held on Apr. 14 and May 14 for June 2008 – May 2010 ■ Average price of winning bids was $80.48/ MWH (before line

losses, administration fees, and gross receipt taxes)


New Jersey Regulatory Matters

Draft New Jersey Energy Master Plan (Apr. 17, 2008)– Plan goals

– Maximize energy conservation and energy efficiency– Reduce peak electricity demand– Meet 22.5% of the State’s electricity needs from renewable resources– Develop new low carbon emitting, efficient power plants to help close the gap

between supply and demand of electricity– Invest in innovative clean energy technologies and businesses to stimulate the

industry’s growth in New Jersey

– Public meetings held Apr. 28 and May 1– Public roundtable discussions with state and national energy experts

tentatively scheduled for late June– Public hearings to be held in July

JCP&L focus: Peak demand management and cost recovery

Jersey Central Power & Light


Financial Matters


($ millions) 2008F** 2009F – 2012F Average**

$730 $730259168

66Subtotal without AQC $1,389 $1,223

132354

Corporate/ Other 173

$2,038

Energy DeliveryNuclearFossil

Total with AQC

($ millions) 2008F 2009F 2010F 2011F 2012F$649 $11

($145)$263$4

($7)$500Air Quality Control (AQC)

($149)$156

($344)Change from Prior Year

Reinvesting in the BusinessProjected 2008 – 2012 Capital Expenditures*

* Per 2007 10-K**Reflects Fremont plant purchase price of $253.6 million in 2008, but does not yet reflect additional construction costs under study to complete the facility.


Capital Expenditures ($ millions)Business

Unit Project Area2004 2005 2006 2007 2008F** 2009F-2012F

Average**

Energy Delivery

– Aged infrastructure rebuild– Pockets of load growth– Reliability improvements

$445 $724 $650 $746 $730 $730

Fossil– Improve managing operating risk– Upgrade aged equipment– Environmental / fuel enhancements

$106 $148 $116 $106 $354** $168**

Nuclear– Availability improvements– Dry fuel storage / license renewal– Materials issues

$141 $173 $229 $150 $132 $259

Corporate – Information Technology, etc. $29 $45 $39 $108 $173 $66

Sub-Total $731 $1,090 $1,034 $1,110 $1,389 $1,223

AQCCompliance strategy totals - Sammis, Burger Units, Mansfield and Eastlake Unit 5

$0 $54 $136 $386 $649 $168***

Total $731 $1,144 $1,170 $1,496 $2,038 $1,391

Reinvesting in the BusinessCapital Expenditure Forecast*

* Per 2007 10-K** Reflects Fremont plant purchase price of $253.6 million in 2008, but does not yet reflect additional construction costs under study to complete the facility.*** AQC annual expenditures include $500M (2009), $156M (2010), $11M (2011), $4M (2012).


Conversion of Auction Rate Bonds

In early 2008, FirstEnergy’s debt portfolio included $530M of long-term debt sold at auction rates Auction rate market severely impacted by loss of liquidity and weak investor demand

– Resulted in higher auction rate resets and failed auctions

Securities were repurchased and are currently held in Treasury– Initially funded with short-term facilities– Exposure capped at short-term borrowing rate, currently around 3%

On Apr. 22, Met-Ed ($28.5M) and Penelec ($45M) remarketed their former auction-rate bonds into a variable-rate mode supported by an LOCSubject to market conditions, plan to refinance remainder of these securities over the balance of the year in either a fixed-rate or variable-rate mode


Acquiring Additional 18.26% Equity Interest in Beaver Valley 2

On Mar. 3, 2008, notice of intent was given that FirstEnergy Nuclear Generation Corp. (NGC) would acquire ownership of an additional 18.26% undivided interest in Beaver Valley Unit 2 (BV2)

– NGC is exercising an early purchase option under certain existing BV2 leases originally entered into in 1987

– Purchase price is higher of specified lease casualty values (approx. $239M for equity portion of all nine leases) or fair market value of such interests.

– Proposed structure: NGC purchases equity portion from current owners/lessors and becomes the new lessor. The lessor notes of the nine owner trusts that secure lease obligation bonds associated with the debt portion of the original sale and leaseback transactions would remain in place.

– Alternative structure: NGC would purchase the equity and terminate the lease. Would require an additional payment of approx. $236M to prepay the outstanding principal of the lessor notes. The bonds are not subject to prepayment. If prepayment of the notes is insufficient to pay the bonds when due, NGC would provide a mechanism to address any such potential shortfall in a timely manner.


Achieving Targeted Growth

$3.50

$4.00

$4.50

$5.00

Midpoint 2007 Non-GAAP

EPS Guidance

Midpoint 2008Non-GAAP

EPS Guidance

$4.20*$0.04

$0.06 $0.03

$0.14

($0.13)

($0.10)

$4.25*Financing

Costs

GenerationOutput

WiresSales

Growth

2007Share

Buyback

OhioTransition

CostAmortization

Depreciation &General Taxes

OutageO&MCosts

$0.05 Other

($0.04)

Issued on Dec. 5, 2007

* See GAAP to Non-GAAP reconciliations in the Appendix. 2008 EPS guidance, excluding special items, is $4.15 to $4.35. On a GAAP basis, 2008 EPS is expected to be $4.23 to $4.43 reflecting $0.08 of special items.

2008 Earnings Guidance


2008 Non-GAAP Earnings Per Share GuidanceReconciliation of GAAP to Non-GAAP

As of May 1, 2008

2008 EPS

Basic EPS (GAAP basis) $4.18 – $4.38Gain on Sale of Non-Core Assets 0.06Trust Securities Impairment (0.03)

Basic EPS (Non-GAAP basis) $4.15 – $4.35


2007 Non-GAAP Earnings Per ShareReconciliation of GAAP to Non-GAAP

2007 EPS

Basic EPS (GAAP basis) $4.27Excluding Special Items:

New Regulatory AssetAuthorized by PPUC (0.05)Gain on sale of non-core assets (0.04)Trust Securities Impairment 0.05

Basic EPS (Non-GAAP basis) $4.23


Distribution rate case in OH effective 2009

Market generation prices in OH in 2009

Market generation prices in PA in 2011

Asset mining / realizing full potential of generation assets

Further operational enhancements

Timely recovery of regulated costs and capital investments

Achieving Targeted GrowthMajor Earnings Drivers 2009 – 2011


Declining margin from OH transition plans

Impact of expiring Met-Ed/Penelec third-party power contract in 2009

Increasing fuel and purchased power costs

Increasing O&M costs

Higher depreciation expenses (non-cash)

Achieving Targeted Growth (continued)Major Earnings Drivers 2009 – 2011


FirstEnergy Credit Ratings

On Oct. 18, 2007, S&P revised the outlook of FE and its subsidiaries to negative from stable

On Nov. 2, 2007, Moody’s revised the outlook of FE and its subsidiaries to stable from positive

Corporate Credit Rating (S&P) / Issuer Rating

(Moody's)

Senior Secured Senior Unsecured

S&P Moodys S&P Moodys S&P MoodysFirstEnergy Corp. BBB Baa3 - - BBB- Baa3

FirstEnergy Solutions BBB Baa2 - - BBB Baa2

Ohio Edison BBB Baa2 BBB+ Baa1 BBB- Baa2

Cleveland Electric Illuminating BBB Baa3 BBB+ Baa2 BBB- Baa3

Toledo Edison BBB Baa3 BBB Baa2 BBB- Baa3

Pennsylvania Power BBB Baa2 A- Baa1 BBB- Baa2

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

Metropolitan Edison BBB Baa2 BBB+ Baa1 BBB Baa2

Pennsylvania Electric BBB Baa2 BBB+ Baa1 BBB Baa2

As of December 6, 2007As of May 13, 2008


Strong Liquidity Position

Company Type Term Maturity Amount ($M)

Aug. 2012 $ 2,750

120

550

$ 3,420**

Various

Various

Total

FirstEnergy Corp. RCA* 5-year

FirstEnergy Corp. Bank Lines Various

OH & PA Utilities A/R Fin. 1-year

* Revolving Credit Agreement

** As of March 31, 2008



Potential uses of free cash following completion of AQC projects– Dividend growth– Invest for future growth– Potential for share repurchases– Ability to take advantage of strategic opportunities

Available Cash Forecast*

($ millions) 2007 2008F* Change

$1,694 $2,300

(2,038)

(132)

$130

(1,496)

$606

(542)

(37)(95)

$103 $27

Net Cash from Operating Activities

Capital Expenditures

Nuclear Fuel Fabrication

Available Cash before Dividends

* Reflects Fremont plant purchase price of $253.6 million in 2008, but does not yet reflect additional construction costs under study to complete the facility.



At its Dec. 18, 2007, meeting, the Board of Directors declared aquarterly dividend of $0.55 per share, payable Mar. 1, 2008

Dividend Increases:Payment

DateQuarterly

RateChange fromPrior Period

AnnualizedRate

1Q 2008 55.00¢ 10.00% $2.20

$2.00

$1.80

$1.72

$1.65

$1.50

1Q 2007 50.00¢ 11.10%

1Q 2006 45.00¢ 4.65%

4Q 2005 43.00¢ 4.24%

1Q 2005 41.25¢ 10.00%

4Q 2004 37.50¢ –

Common Dividend


Share Repurchase Summary

(Shares in millions) 2006 2007 Cumulative

Beginning Shares 329.8 319.2 329.8

Shares Repurchased 10.6 14.4 25.0

Ending Shares 319.2 304.8 304.8

% Reduction 3.2% 4.5% 7.7%

Cost ($ millions) $627 $942 $1,567

Avg. Price per Share $58.99 $65.54 $62.68

Annual EPS Benefit $0.13 $0.22 $0.35


Finance Plans: 2008 and Beyond

Maintain financial flexibility– Investment grade credit metrics at all entities

– Metrics maintained over near-term – Metrics improved as AQC capital spend winds down post-2009

– Maintain substantial liquidity– $3.4B total capacity

Reduce holding company debt while appropriately capitalizing operating companies and FirstEnergy Solutions

– Utility debt maturities of only $685M over 2008 – 2011 period– Opportunistically transfer remaining $263M of utility tax-exempt debt to

Generating Companies– $1.9B already transferred

– $1.5B, 6.45% Series B FE Notes due Nov. 2011


Finance Plans: 2008 and Beyond (continued)

Efficient funding of capital program – Capital expenditures financed largely through internal cash flow, even

during peak AQC spend– New tax-exempt financings of approximately $200M planned to support

Sammis AQC project

Potential uses of substantial growth in free cash following completion of AQC projects

– Dividend growth– Invest for future growth– Potential for share repurchases– Ability to take advantage of strategic opportunities

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