first energy analystmtg_120607

Analyst MeetingNew York, NY • December 6, 2007


Welcome

Ronald E. SeeholzerVice President, Investor Relations

Analyst MeetingNew York, NY ▪ December 6, 2007

Safer Harbor Statement under the Private SecuritiesLitigation Reform Act of 1995These Presentations 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, 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 the PPUC (including 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 inability 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, 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 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.


Today’s Agenda

Corporate and Strategic Overview – Tony Alexander

Regulatory Update – Dave Blank

Operations Overview – Gary Leidich

Energy Delivery & Customer Service – Don Schneider

Generation and Commodity Operations – Chuck Jones

Commodity Operations – Ali Jamshidi

Financial Outlook – Rich Marsh

Closing Remarks – Tony Alexander

Q & A



Corporate and Strategic Overview

Tony AlexanderPresident and CEO


People and Culture– One company culture– Continuous learning and

leadership platforms

Financial Strength & Flexibility– Achieve targeted growth– Deploy cash effectively

Capital Management– Build on our existing generation

portfolio– Rebuild our T&D infrastructure

Regulatory– Recover cost of service– Transition to market prices

Objectives

Our objectives for 2007 and beyond continue to be based on the fundamentals.


A strong and stable corporation with a focus on the fundamentals

– Operational excellence– Financial discipline– Management credibility– Continuous improvement

2


FirstEnergy’s strategic focus is on making an orderly and effective transition to competitive market-based pricing.

Met-Ed and Penelec – Cost recovery

Penn Power POLR to market

2009–2010 20112004–2006

Rebuild the core

Rebuild financial stability

Start the transition to market (e.g., generation asset transfer)

2007–2008

OH POLR to market

Distribution rate cases

End of OE and TE transition cost amortization

Met-Ed and Penelec POLR to market

End of CEI transition cost amortization

Transition


3


Legislative Update: Ohio and Pennsylvania

Efforts are underway in both OH and PA on potential new energy legislation

FirstEnergy actively engaged in the legislative process

Multiple issues being considered…key is to assure a smooth transition to market in both states

PA still working to enact legislation by end of year

OH legislation likely in the first quarter of 2008


FirstEnergy is positioned in each state FirstEnergy is positioned in each state to successfully transition to marketto successfully transition to market

4


Successfully transitioned Penn Power to competitive generation market prices Filed distribution rate case requests and competitive generationprocurement proposal for Ohio utilities

Regulatory

In 2007, we continue to build on the fundamentals and deliver strong financial results…

Narrowed EPS guidance to top-half of the original range: $4.15–$4.25* Expecting to generate $1.7B of cash from operationsIncreased dividend 11.1% Completed accelerated repurchase of approx. 14.4 million sharesCompleted $1.3B sale and leaseback transaction on 779 MW of Mansfield Unit 1

Financial


* See GAAP to Non-GAAP reconciliations in the Financial Outlook Appendix.

5


Expecting generation output in excess of 81 million MWh –20% increase from 2003

Added over 300 MW of additional generating capacity through uprates, wind contracts and peaking enhancements – with significantly less risk than new plant construction

Continued improvement in T&D reliability metrics – SAIDI down 15%

Achieving top-decile safety performance – 0.89 YTD OSHA rate

On schedule and budget for Air Quality Control (AQC) projects at the Sammis Plant

NRC accepted Beaver Valley Units 1 & 2 license renewal applications for review

Operational

…And strong operational results.


6


2008 – A Challenging Year

No expected rate increases

Higher Ohio transition cost amortization expense

Increased capital expenditures for AQC projects

Continued improvements in distribution reliability

Continued investments in generation fleet capacity and performance


We have demonstrated our ability to deliver We have demonstrated our ability to deliver results and will continue to meet our objectivesresults and will continue to meet our objectives

7


2008 – Expect Modest Improvement in Earnings

As we manage our transition to market, we will continue to drive performance and deliver results


8

2007 Non-GAAP Earnings Guidance*

Original (Feb. 2007) $4.05 – $4.25

Revised (Oct. 2007) $4.15 – $4.25

Affirmed (Dec. 2007) $4.15 – $4.25

2008 Non-GAAP Earnings Guidance* $4.15 – $4.35* See GAAP to Non-GAAP reconciliations in the Financial Outlook Appendix. On a GAAP basis, 2008 EPS is expected to be

$4.23 to $4.43 reflecting an $0.08 gain on the planned sale of non-core assets.


SignificantEarningsGrowth

Potential

Bottom Line –FirstEnergy is an attractive risk/reward opportunity

Effectively managing transitionto competitive markets

Realizing full potential of assets

Reinvesting for future growth

Effectively deploying strong cash flow

Striving for continuous improvement

Maintaining strategic flexibility

Well-positioned for climate legislation


9


Regulatory Update

Dave BlankVice President, Rates and Regulatory Affairs


Discussion Topics

Ohio regulatory update– Distribution rate cases– Competitive generation procurement proposal– Supreme Court of Ohio remand on Rate Certainty Plan

Pennsylvania regulatory update– Commonwealth Court appeal in Met-Ed/Penelec rate cases– Met-Ed/Penelec comprehensive generation procurement filing– Penn Power POLR II case

New Jersey regulatory update– Energy Master Plan

Regulatory Update

2


Ohio Edison, CEI and Toledo EdisonCase detail– 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 expected early December– Hearings expected 1st quarter 2008– 275-day timeline reached in March 2008– Rates to be effective January 2009 (CEI in May 2009)

Ohio

Ohio Regulatory UpdateDistribution Rate Requests

Regulatory Update

3


Ohio Edison, CEI and Toledo EdisonOn July 10, 2007, filed a comprehensive supply plan for competitively priced generation service to implement market provisions of S.B. 3 effective January 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

Ohio Regulatory Update

Ohio

Competitive Generation Procurement Proposal

Regulatory Update

4


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 January 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)

Ohio Regulatory Update

Ohio

Competitive Generation Procurement Proposal (continued)

Regulatory Update

5


Ohio Edison, CEI and Toledo EdisonAugust 29: Supreme Court of Ohio remanded recovery of deferred fuel costs in distribution rates to PUCO for further consideration

The Court reaffirmed all other aspects of the Rate Certainty Plan

September 10: Companies filed a Remand Application with the PUCO seeking generation-related fuel cost recovery rider

– Remand remains at PUCO

Ohio

Ohio Regulatory UpdateSupreme Court of Ohio Remand on Rate Certainty Plan

Regulatory Update

6


PAMet-Ed and Penelec

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

– ME & PN - denial of generation relief and tax expense adjustment– Industrials & OCA - transmission recovery– Oral arguments expected late 4Q or early 2008– Decision expected in 2008

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

on January 1, 2011– Plan to submit generation procurement proposal in 2008

Pennsylvania Regulatory UpdateCommonwealth Court Appeals & Generation Procurement Filing

Regulatory Update

7


Penn Power successfully transitioned to competitive generation market prices on January 1, 2007– POLR I RFPs implemented for January 2007–May 2008– POLR II multiple RFP’s with staggered delivery

June 2008 through May 2011– Proposed full requirements product by class– Settlement Agreement filed in September 2007– Favorable ALJ Recommended Decision received in October 2007– Anticipate Commission Order in December 2007

– Industrial customers on hourly priced default service

4343431 yearCommercial0022222 yearResidential2200221 yearResidential

Jan 10Oct 09Jan 09Oct 08Mar 08Jan 08RFP Tranches (50 MW)TermGroup

PA

Pennsylvania Regulatory UpdatePenn Power POLR II Case

Regulatory Update

8


NJ

Regulatory Matters

New Jersey Energy Master Plan – State goals

– Reduce total projected electricity demand by 20% by 2020– Meet 22.5% of electricity needs with renewable energy– Reduce air pollution and energy use– Encourage and maintain economic development– Achieve a 20% reduction in CAIDI and SAIFI by 2020– Unit prices at no more than +5% of the regional price level– Eliminate transmission congestion by 2020

– Detailed draft plan expected by year end 2007– JCP&L focus: Peak demand management and cost recovery

Jersey Central Power & Light

Regulatory Update

9


Appendix

appendix

App-1


Retail Regulatory Structure

1 CEI fixed through April 2009.2 NUG recovery thru 2020.

Ohio Edison Stable ratesthru 2008“g + RSC”

RTC thru2008 – OE, TE2010 – CEI

Fixed ratesthru 20081

Pass thruMISO costs

Penn Power Market in2007

POLR ratesthru 2010

GenerationGeneration TransmissionTransmission DistributionDistribution Transition CostTransition Cost

Norestriction

JCP&L BGS Supply MTC thru 2018Norestriction

Met-Ed

Penelec

Toledo Edison

CEI

CTC endedJan. 2006

CTC thru 20102

CTC thru 20092

Pass thruPJM costs

Norestriction

InGeneration

App-2Appendix


* Assumes current Generation & Transmission rates

Proposed Changes in Revenues ($ millions) TotalCurrent "Distribution" Revenues $1,118Proposed 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 Proposed 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%

Ohio Regulatory Matters

App-3Appendix

Distribution Rate Requests (as filed)


Operations Overview –Strategies / Initiatives

Gary LeidichSenior Vice President, Operations


Operations Strategy

GenerationGeneration

Commodity OperationsCommodity Operations

Energy DeliveryEnergy Delivery

EnvironmentalEnvironmental

Operations Overview – Strategies / Initiatives

Maximizing generation fleet utilization is key to driving improved generation marginMaximizing margins by mitigating risks and minimizing supply costsMining existing assets for cost-effective capacity additionsEffectively implement environmental compliance strategyContinued focus on enhancing reliability and customer serviceImplement continuous improvement initiatives

Strategic ObjectivesStrategic Objectives

Driving Performance and Delivering Results

2


An Unwavering Commitment to Safety

“Make Safety A Way Of Life”

0.96 0.89

1.591.24

1.44

0.0

0.5

1.0

1.5

2.0

2.5

2003 2004 2005 2006 2007 YTD

OSH

A In

cide

nt R

ate*

*

FE Performance Top Decile* Top Quartile*

* Based on 2006 EEI industry benchmarks

** Per 100 employees


3


Operational Performance TargetsOperational Performance 2004 2005 2006 2007F 2008F 2011

Targets

Total Generation (million MWh) 76.4 80.2 82.0 82.2 84.7 86.6

Fossil Reliability

Capacity Factor (Baseload %) 84.6 86.9 88.5 81.0 87.2 90.7

Nuclear Reliability

Capability Factor % 89.5 86.2 86.8 90.0 92.9 92.4

Energy Delivery Reliability

Distribution SAIDI (minutes) 159 191 152 128 118 103


4


Business Planning Principles

Playbook for each business unit

Emphasis on closing gaps to top performance

No ambiguity – clearly defined performance metrics

Issues/challenges identified

Risk management tools applied

Communication

Continuous Improvement initiatives and specific action plans


5


Improved Linkage

Improved Linkage of Operational Execution and Financial Results

Common template for metrics, assumptions, and initiatives improves communications“Sharpened” financials: more efficient and timely– <2% targeted O&M growth annually

Improved capital portfolio management– Stabilized Energy Delivery costs– Sequence Air Quality Control (AQC) costs with other major projects – Cross-functional peer reviews/challenges

Process for capturing Continuous Improvement initiatives

OperationalDecisions

FinancialResults


6



Reinvesting in the Business

* AQC annual expenditures include $500M (2009), $156M (2010), and $11M (2011)

2004 2005 2006 2007F 2008F2009F-2011F

Average

Energy Delivery

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

$455 $724 $650 $746 $730 $730

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

$106 $148 $116 $104 $96 $155

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

$141 $173 $229 $149 $131 $260

Corporate - Information Technology, etc $29 $45 $39 $88 $86 $75

Sub-Total $731 $1,090 $1,034 $1,087 $1,043 $1,220

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

$0 $54 $136 $387 $650 $222 *

Total $731 $1,144 $1,170 $1,474 $1,693 $1,442

Capital Expenditures ($ millions)Project AreasBusiness

Unit

7


Environmental Strategies

Tactical– Managed compliance with environmental operating standards to

achieve 100% compliance

Strategic– Comprehensive environmental compliance and economic analysis

for fossil fleet ready for implementation– Clean Air Interstate Rule and Clean Air Mercury Rule – effective March 2005– New Source Review – effective July 1, 2005– Clean Water Act, Section 316(b) Phase II – effective July 9, 2004

– AQC Group focused to address environmental compliance implementation plans across the fleet with $1.9B investment through 2011

Long Term– Actively partner with government agencies, EPRI and equipment

manufacturers to R&D new control technologies and system efficiency improvements to address potential future emissions regulations


8


AQC Construction OverviewEnvironmental Strategies

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


9


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

AQC Upgrades – Sammis PlantFlue 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


10


Chimney Shell Completion

Chimney Shell and Overall Site Construction


11


Fiberglass Strands for Spinning

Flue Spinning Mandrill

Fiberglass Flue –Spinning Facility


12


“A&B” Absorber Foundations –Formwork and Underground in Building Areas

Absorber “C”Building Steel


13


Unit 6 SCR Inlet FluesUnit 6 SCR Inlet Flues


14


Ammonia Tank Farm Railroad Unloading Slab


15


CO2 control – Over 35% of annual 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, additional equipment not required before 2018

Longer-term environmental considerations

Environmental Status

20102007

81%62%

9%9%

38%19%

34%34%

Fleet%

Fleet%

Fleet Emission Control Status

11,1588,490

1,2831,283Natural Gas Peaking

5,2372,626Coal Controlled(SO2/NOx – full control)

4,6384,581Non-Emitting

Capacity (MW)

Capacity (MW)

Our generation fleet is well-positioned for the future


16


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


17


90.787.281.0Capacity Factor (Baseload %)

54.652.751.5Total Generation (million MWh)

0.801.121.12OSHA Incident Rate (per 100 employees)

2011 Target2008F2007FFossil

Fossil Operating Performance

2007 Highlights– Top-quartile safety performance – New monthly all time generation

record set August 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


18


2007 Highlights – Top-quartile safety performance– DB worked > 7.5 million hours

without a Lost Time Accident – Record Fleet Generation projected

(30.7 million MWh) – BV1 uprate (43 MW); BV2 uprate (24 MW)– No forced losses at BV1; BV2 top

quartile (0.24%)– PY returned to Standard Reactor

Oversight Process– 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 and BV2– 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

92.492.990.0Capability Factor (%)

32.032.030.7Total Generation (million MWh)

0.250.250.25OSHA Incident Rate (per 100 employees)

2011 Target2008F2007FNuclear

Nuclear Operating Performance


19


Tactical fuel managementAQC implementationClimate change

Maximize utilizationReinvest to manage reliabilityMining of assetsMaximize margins

Generation Generation (including (including

Commodity Operations)Commodity Operations)

Reliability improvementsReinvest in infrastructure

Transitioning to our Future

EnvironmentalEnvironmental

Energy DeliveryEnergy Delivery

Well-positioned to Succeed in Competitive Generation Markets


20


appendix

App-1Appendix


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

Appendix

App-2


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

Appendix

App-3


Generation – Implementing Plans for the Future

Nuclear license renewal

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

20472009Submitted 2007*2027Beaver Valley Unit 2

2037201220102017Davis-Besse

2046

2036

New Expiration

201520132026Perry

Submitted 2007*

Submit Request (NRC Docket)

20092016Beaver Valley Unit 1

Approval Expected

Current Expiration

Appendix

App-4

* The NRC accepted the application for review


Nuclear spent fuel storage– Since 1983, FirstEnergy has collected $494M from the rate-payers

for the long-term storage of used nuclear fuel. 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.

Generation – Implementing Plans for the Future

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

Beaver ValleyBeaver ValleyUnit 2Unit 2

Continue with wet storage until 2021Switch back to dry storage in 2022DavisDavis--BesseBesse

Implement dry storage before 2011PerryPerry

Implement dry storage by the end of 2014Beaver ValleyBeaver ValleyUnit 1Unit 1

Appendix

App-5


Energy Delivery & Customer Service

Don SchneiderSenior Vice President, Energy Delivery & Customer Service


Discussion Topics

Energy Delivery & Customer Service (ED&CS) Vision, Mission and Focus Areas

Regulated rate base

Our “Game Plan”

Operational performance goals



2


Providing safe and reliable electric service at a reasonable cost by leveraging the resources, skills and diversity of our workforce

Mission

An industry leading performer that shapes the future of the energy delivery and customer service businessVision

ED&CS Vision, Mission and Focus Areas

Focus AreasSafetyCustomer SatisfactionReliabilityFinancial PerformanceEmployees


3


Regulated Rate Base and Sales Growth

$394

$9,800

2007F

$330$365Capital Expenditures, Net of Depreciation

$11,000

2011 Target

$10,100Net Plant for Rate Base

2008FProjected Rate Base –Regulated Companies (T&D)($ millions)

Growing asset base and increased distribution throughput Growing asset base and increased distribution throughput

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

1.1

2.2%

NJ

2.1

0.9%

OH

1.3# of Customers (millions)

1.7%Growth Rate (kWh)

PAAverage Annual (2009F – 2011F)

Projected Annual Growth


4


Our “Game Plan” is about Performance


* Top quartile** Per 100 employees

Safety

Consistently achieve top-decile (1.24) OSHA Incident Rate** 1.70* 1.62 1.00

Reliability

Distribution SAIDI (minutes) 128 118 103

TOF (per circuit) 0.39* 0.31 0.31

Financial Performance

Total Cost Per Customer $270 $265 $263

EmployeesAn environment where employees are valued and accountable for the performance of the business

Total Staffing 7,637 7,898 7,995

Focus Area Key Metrics

Top-quartile performance SAIDI and top-decile in TOF

Achieve top-quartile total spend per customer

2007F 2008F 2011 Target

5


Operational Performance Goals

Top Quartile

ED&CS

$150

$180

$210

$240

$270

$300

Tota

l CPC

2005 2006 2007 2008 2009 2010 2011 2012

Total Cost per CustomerSAIDI Performance

Top Quartile

ED&CS

10

40

70

100

130

160

190

220

SAID

I (M

inut

es)

2005 2006 2007 2008 2009 2010 2011 2012


Our strategy is to achieve topOur strategy is to achieve top--quartile operational performancequartile operational performance

6


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)

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


Game Plan:

Target spend with an emphasis on improving reliability

Continued focus on operational improvements

7


Assigned owner for each project

Detailed layout of milestones and subsequent activities for project completion (Primavera)

Monthly status reports – Narrative of project status– Enhanced financial rigor

Execution of our capital plan is being achieved Execution of our capital plan is being achieved by driving discipline and accountabilityby driving discipline and accountability

Project ManagementDriving Discipline and Accountability


8


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


296323386Total

8287110Substation Electricians

214236276Line Workers

HiredGraduatedStarted Program

Enrollment/Hires 2000–2007

237154

6031

177123

2009F2008F

9


Customer Satisfaction

Contact Center Survey– 81% of customers rated FirstEnergy with a score of 9 or 10

(out of 10)

Collection Effort– Reduced number of accounts in arrears by 29% since

May 2007– Deposits received from eligible customers have increased

62% since the beginning of the year– Justified complaints are down 13% from last year


Improving the interface with our customers Improving the interface with our customers supports our supports our ““Game PlanGame Plan””

10


Achieving Energy

Delivery and Customer Service’s

Vision


Safety– Consistently achieve top-decile

performance

Customer Satisfaction– A top performer in our industry

Reliability– Top-quartile performance SAIDI

and top-decile in TOF

Financial Performance– Achieve top-quartile total spend

per customer

Employees– An environment where employees

are valued and accountable for the performance of the business


11


Generation & Commodity OperationsIntegrated Portfolio Overview

Chuck JonesPresident, FirstEnergy Solutions


Discussion Topics

Diversity and scale of generation fleet

Top-tier operational capability & ongoing commitment to operational excellence

Integrated Generation, Commodity & Retail operations

Leveraging the value of our existing generating fleet

FirstEnergy Solutions’ (FES) renewable energy strategy

Generation & Commodity OperationsIntegrated Portfolio Overview 2


Akron

Toledo

Reading

Beaver Valley1,779 MW

Davis-Besse893 MW

Perry1,258 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

Forked River86 MW

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 101Forked River* 86Mad River 60Edgewater 48Stryker 18Other 63

Total Peaking Units 2,344

Mansfield 1-3 2,490Beaver Valley 1,2 1,779Perry 1,258Sammis 6,7 1,200Davis-Besse 893Eastlake 5 597Bay Shore 1 136

Total Baseload 8,353

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 3,930 H Hydro 651 G Gas & O Oil 1,599

Other 608Total 14,257 MW


* Sale pending

3


Diversity and Scale of Generation Fleet

Significant scale: FES controls about 14,000 MW

Balanced mix of fuel types– 38% nuclear; 62% fossil & other (2007F output)

Transportation optionality– Three delivery options for our largest baseload plants – barge, rail and truck

Geographic diversity– Participation in two RTOs (MISO and PJM) allows for price discovery and the

ability to take advantage of inter-market price differentials

Baseload/load following strategy optimizes fleet performance and reliability

– Each unit has a specific mission (baseload, load-following or peaking) that provides clear operating objectives

– Increases efficiency and reduces wear and tear on baseload units– More efficient plant operation drives increased output and cost reductions

Fleet Characteristics and Mission-Driven Strategy



Mission-driven strategy in Fossil has resulted in significant reductions in cost since 2004 as well as increased outputIn spite of increased AQC-related O&M in 2008–2010, non-fuel production costs are expected to remain stable Cost-effective execution of outages is expected to drive improvement and stability of nuclear non-fuel expenses

Focus on Cost Control Top-Tier Operational Capability

Fossil

2004 2005 2006 2007F 2008F

($ /

MW

h)

Non-Fuel Fuel

Nuclear

2004 2005 2006 2007F 2008F

($ /

MW

h)

Non-Fuel Fuel



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% 81.0% 87.2% 90.7%

Nuclear 89.5% 86.2% 86.8% 90.0% 92.9% 92.4%

2004 2005 2006 2007F 2008F 2011 Target

Continued Improvement of Asset Utilization



Integrated Generation, Commodity & Retail Operations

Real-time coordination of fuel burn and unit availability drives generation dispatch optimization

– Integrated approach maximizes unit profitability and asset value– Minimize costs when prices are low and maximize revenue when prices

are high

An integrated portfolio outperforms generation-only or retail-only models

– Mitigates the risk associated with independently managed positions

Proven experience and capabilities in wholesale markets– Skill, experience and influence in PJM and MISO– Successful participation in multiple auction structures (BGS, Penn Power RFP)

Strong presence in retail markets provides market intelligence and maximizes commodity margin



Integrated Generation, Commodity & Retail Operations

FES Retail provides a retail sales channel for FES generation– Maximize generation value through higher margin retail sales

FES Retail provides natural hedge for FES POLR obligations– Integrated wholesale/retail strategy provides natural hedge for shopping

risk inherent in POLR obligation– Successfully implemented integrated wholesale/retail strategy for

Penn Power market

Focus on competitive electric markets within MISO and PJM– FES Retail ranks #13 out of 81 competitive suppliers (1)

– Active participation since 1998 in OH, PA, NJ, MD and MI markets– Market leader in PA market (Duquesne Light, Penn Power)– Competitive expertise allows FES Retail to maximize opportunities as

markets transition

Execute wholesale/retail strategy in Ohio when market opens in 2009

Competitive Skills to Succeed in Competitive Generation Markets


(1) Non-residential market share (GW). Source: KEMA Semi-Annual Review of U.S. Retailer Rankings: August 2007

8


Maximizing Potential of Generating Fleet

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– Low technology and construction risk

Clarity on capacity and ancillary services market structure, technological advances, and environmental regulations will impact generation asset decisions in the future

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

84840Fossil load following uprates

622251371Total MW additions1490149Peaking capacity enhancements* 1707892Nuclear baseload uprates

21989130Fossil baseload uprates

Cumulative MW2008F–2011F2005–2007FType of MW Addition

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



564 GWh215 MWTotal:

180 GWh70 MWIn-service 2008

384 GWh145 MWIn-service 2007

RECs/YearCapacityStatus



FES Wind Energy Portfolio

Represents a minimal part of our renewable requirements

On the horizon and will impact our renewable strategy in the future

Drives our renewable strategy today

Overview

22.5% by 2020NJ

25% by 2025(Proposed)

OH

18% by 2020PA

Renewable MandateState

Leading the Way in Procuring Renewable Energy to Meet Growing Demand

Leading wind energy supplier in PAEvaluating expansion of current wind portfolio Considering other renewable technologies:

– Solar– Compressed air– Biomass– Land fill gas– Anaerobic digestion

10


Generation Output

0

20

40

60

80

100

(mill

ion

MW

h)

Nuclear 29.9 28.7 29.0 30.7 32.0 31.0 32.2 32.0Fossil 46.5 51.5 53.0 51.5 52.7 52.4 53.7 54.6

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



11



Diversity and scale of generation fleet

Top-tier operational capability and commitment to operational excellence

Integrated Generation, Commodity and Retail operations

Maximizing potential of generating fleet

Well-positioned in a carbon-constrained world


FES is well-positioned to succeed in competitive

markets

12


Commodity Operations

Ali JamshidiVice President, Commodity Operations


Discussion Topics

Near-term commodity hedge positions

Market trends

MISO and PJM overview

Long-term readiness


2


Commodity Operations’ Objectives

Effectively manage commodity positions

Effectively deploy generation to meet retail obligations and capture market opportunities

Enhance fuel supply / logistics to maximize optionality

Efficiently manage purchased power requirements

Employ strict risk management controls and oversight to minimize exposure to MISO and PJM markets– Volume and price risks– Generation availability risks– Transmission congestion risks

Maximizing Margins by Mitigating Risks and Minimizing Supply Costs


3


Expected Total Supply

0

20

40

60

80

100(m

illio

n M

Wh)

Forward / Spot Purchases 11 7 9Nuclear 32 31 32Fossil, Hydro, Wind 52 52 53

2008F 2009F 2010F

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

Expected Supply Portfolio for FES*

Significant reductions in mostly on-peak energy purchases

95 90 94


•*Assumes move to open market in Ohio in 2009 and beyond

4


Expected Total Sales

020406080

100

(mill

ion

MW

h)

Retail Auction 1 31 29Competitive Retail 12 20 24Forward / Spot Sales 16 20 21ME/PN PRA Obligations 14 19 20OH PSA Obligations 52 0 0

2008F 2009F 2010F

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

Expected Sales Portfolio for FES*

Significant increases in higher margin sales

95 90 94

•*Assumes move to open market in Ohio in 2009 and beyond


5


PJM Capacity PositionME and PN have long-term capacity contractsBeaver Valley nuclear plant (1,779 MW) committed in PJM to cover capacity positionCovered capacity prior to RPM auction for planning year 2008-2009 to replace long-term contractsCommitted Seneca pumped storage (451 MW) to PJM as a capacity resource for planning year 2009 (commencing in June 2009)Continue to actively explore other options with our assets

PJM Net Capacity

(3500)(2800)(2100)(1400)(700)

0700

1400210028003500

Jan

Feb

Mar

Apr

May Jun

Jul

Aug

Sep

Oct

Nov

Dec Jan

Feb

Mar

Apr

May Jun

Jul

Aug

Sep

Oct

Nov

Dec Jan

Feb

Mar

Apr

May Jun

Jul

Aug

Sep

Oct

Nov

Dec

MW

FES View (continuing to serve the ME and PN PRA)

2008 2009

Includes Beaver Valley, Forked River and Seneca

2010


6


Commodity Positions – Policy / Strategy

Significantly close positions in the near term

Layer in longer physical term contracts to smooth out supply costs

Maintain some flexibility in hedging activities to take advantage of market opportunities

Continuously explore and enhance fuel blends and inventory management

Use financial hedges as necessary to manage variability

Trade around our assets – no speculative trading

Coal and Related Commodities


7


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

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

91%

99%

100%


8


Coal Transportation PositionActively pursuing closure to long-term transportation positions – rail contract signed, 2010 barge contract agreement reachedContinuing to evaluate additional delivery options to increase both capabilities and flexibilityEnhanced rail unloading capabilities in process at Ashtabula, Bay Shore and Lake ShoreIn 2008, FES will manage 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

91%

97%

58%


9


Emission Allowance PositionBased on projected generation:

– SO2 emission allowance positions are well covered for 2008 and 2009

– Closed 2010 SO2 positions early to mitigate potential scrubber projects completion risks

– 2008 seasonal NOx is covered– 2009 – 2010 seasonal NOx

requirements are expected to be fully covered as allocations are made to states (OH due in Jan. 2008)

– Annual NOx allocations are beginning and markets are still thin

SO2 Position

-10,000

80,000

170,000

260,000

350,000

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


SO2 Position

10


Fuel Flexibility Creates Margin & Fuel ChoicesEnhanced 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


11


Energy Forward Prices – 2008

2008 Calendar Strips - Power

$20

$30

$40

$50

$60

$70

$80

$90

Nov-06 Dec-06 Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Aug-07 Sep-07 Oct-07

$/M

Wh

PJM WH On Cinergy On PJM WH Off Cinergy Off


12


Energy Forward Prices – 2009

2009 Calendar Strips - Power

$20

$30

$40

$50

$60

$70

$80

$90

Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Aug-07 Sep-07 Oct-07

$/M

Wh

PJM WH On Cinergy On PJM WH Off Cinergy Off


13


Energy Forward Price – Outlook

Natural Gas Forward Average Price and Heat Rates(12-month, last day of month)

4.005.006.007.008.009.00

10.0011.0012.0013.00

11/3

0/20

05

12/3

0/20

05

1/30

/200

6

2/28

/200

6

3/30

/200

6

4/30

/200

6

5/30

/200

6

6/30

/200

6

7/30

/200

6

8/30

/200

6

9/30

/200

6

10/3

0/20

06

11/3

0/20

06

12/3

0/20

06

1/30

/200

7

2/28

/200

7

3/30

/200

7

4/30

/200

7

5/30

/200

7

6/30

/200

7

7/30

/200

7

8/30

/200

7

9/30

/200

7

10/3

0/20

07

$/D

th o

r Dth

/MW

h

NG Price CIN Heat rate PJM Heat Rate


14


Commodity Forward Prices – Overview

Demand continues to outpace supply

Reserve margins shrinking

Underlying commodity prices increasing

Environmental requirements increasing

Construction costs escalating

Heat rates and dark spread exhibiting growth

Prices / Outlook– Energy– Capacity– Ancillary Services


15



Near-term commodity positions well hedged

Proven skills in managing commodity risks

Track record in maximizing asset utilization

Well positioned in MISO and PJM

Proven retail/wholesale skills in MISO and PJM


16


Appendix

appendix

App-1


Generation by Type – 2006Coal plants nearing their maximum capacity factorsExpect gas units to be on the dispatch margin more oftenDispatch prices should trend upward

•Source: EIA database & EPA

RFC Capacity (MW)

28%

13%

5% 3% 1%

49%

CoalGasNuclearOilHydroOther

RFC Net Energy (MMWh)

68%

6%

24%

1% 1%

RFC – Reliability First Corporation (ECAR, MAIN, MAAC)

App-2Appendix


Resource adequacy needed to maintain reliabilityMISO portion of RFC reserve margins continue to be unfavorable to the PJM portionMISO capacity value opportunities

Reserve Margin Outlook

Based on the November 2007 RFC Long Term Resource Assessment, 2007-2016

Existing Generation Only:

2008 2009 2010 2011Total RFC 18.8% 16.4% 14.7% 12.9%

MISO Portion of RFC 11.5% 10.2% 9.0% 7.5%PJM Portion of RFC 20.3% 17.6% 15.8% 14.0%

Existing Generation + Planned Resources:

2008 2009 2010 2011Total RFC 19.5% 17.7% 16.3% 14.8%

MISO Portion of RFC 12.3% 11.7% 11.4% 10.0%PJM Portion of RFC 21.0% 18.7% 16.8% 15.5%

App-3Appendix


RPM and Resource Adequacy in PJM

Reliability Pricing Model (RPM) has increased capacity pricing, however not enough generation is being built yet

MISO capacity value, particularly ECAR portion, will demand premium

RPM Base Residual Auction Capacity Prices

0

50

100

150

200

250

Planning Year

$/M

W D

ay SWMAAC

EMAAC

MAAC + APS

RTO

2007/08A 2008/09A 2009/10F

App-4Appendix


Resource Adequacy in MISO

Current operating reserve requirements met by Designated Network Resources (DNR)

DNR, while not an organized market, are purchased and sold

Planning Reserve Sharing Group to meet planning requirements underway

Reliability requirements will force deliverability tests

Reserve short zones/areas will demand premium

App-5Appendix


Ancillary Service Market (ASM) in MISO

ASM market set to start next June

Market-based ASM is good for the MISO market and good for reliability

Some generators will see an upside

•*Figures are estimates only

•**Rate amounts are estimates based on MISO Tariff Schedule 3,5, & 6

Rate ($/MWH)FES Current

Rate* **PJM

Market*

Regulation $0.13 $0.78

Spinning & Suplemental $0.29 $0.10

Total $0.42 $0.88

App-6Appendix


Financial Outlook

Rich MarshSenior Vice President and Chief Financial Officer


Discussion Topics

Review of Key 2007 Financial Accomplishments

2008 Financial Overview

Major Earnings and Cash Drivers 2009–2011

Capital Expenditures 2009–2011

Finance Plans

Conclusions

Financial Outlook

2


2007 – Key Financial Accomplishments

Consistent financial results– Narrowed Non-GAAP 2007 earnings guidance to $4.15 to $4.25*,

the top half of original guidance range

Continued strong cash flow– Expect net cash from operating activities of $1.7B

– Includes pension contribution of $300M

Enhanced capital structure– Transferred $427M of tax-exempt pollution control debt from utilities to

unregulated Gencos– Issued approximately $1.1B of operating company debt

Strengthened pension fund– Voluntary $300M contribution– Plan well funded

Financial Outlook

* See GAAP to Non-GAAP reconciliations in the Financial Outlook Appendix.

3


2007 – Key Financial Accomplishments (continued)

Positioned FirstEnergy Solutions (FES) as an independent capital raising entity– Investment grade credit ratings (BBB/Baa2) received in March 2007– Completed $1.3B sale and leaseback transaction on 779 MW portion

of Unit 1 of the Bruce Mansfield Plant– Captured benefit of $752M of expiring tax capital loss carryforwards– Equivalent to borrowing at 3.6% for a term of 33 years

– Upsized FES’ borrowing capacity under FirstEnergy’s revolver to $1.0B

Increased shareholder value– Year-to-date stock price appreciation of 13.7% (through Nov. 2007)– Three year annualized TSR of 21.5% (through Nov. 2007)– Dividend increase of 11.1% (March 2007)– Accelerated repurchase of approx. 14.4 million shares (March 2007)

Financial Outlook

4


2007 / 2008 Earnings Guidance

Establishing 2008 Non-GAAP earnings guidance of $4.15 to $4.35 per share*– Normalized to exclude anticipated gain on the planned

sale of non-core assets, currently estimated at $0.08 per share in 2008

Financial Outlook

5

2007 Non-GAAP Earnings Guidance*

Original (Feb. 2007) $4.05 – $4.25

Revised (Oct. 2007) $4.15 – $4.25

Affirmed (Dec. 2007) $4.15 – $4.25

* See GAAP to Non-GAAP reconciliations in the Financial Outlook Appendix. On a GAAP basis, 2008 EPS is expected to be $4.23 to $4.43 reflecting an $0.08 gain on the planned sale of non-core assets.


$3.50

$4.00

$4.50

$5.00

Midpoint 2007 Non-GAAP

EPS Guidance

Midpoint 2008Non-GAAP

EPS Guidance

2008 Earnings Per Share Guidance

Financial Outlook

* 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 an $0.08 gain on the planned sale of non-core assets.

$4.20*$0.04

$0.06$0.03

$0.14

($0.13)

($0.10)$4.25*

Financing Costs

Generation Output

Wires Sales

Growth

2007 Share

Buyback

Ohio Transition

Cost Amortization

Depreciation & General

Taxes

Outage O&M Costs

$0.05 Other

($0.04)

6


Common Dividend

Management will recommend that the Board of Directors declare a quarterly dividend of $0.55 per share payable March 2008 at their December 18 meeting

Dividend Increases:

$2.2010.00%55.00¢1Q 2008

$1.50

$1.65

$1.72

$1.80

$2.00

AnnualizedRate

–37.50¢4Q 2004

10.00%41.25¢1Q 2005

4.24%43.00¢4Q 2005

4.65%45.00¢1Q 2006

11.10%50.00¢1Q 2007

Change fromPrior Period

QuarterlyRate

PaymentDate

Financial Outlook

7


Capital Expenditures Forecast

$1,693

650

$1,043

86

96

131

$730

2008F

$219

263

$(44)

(2)

(8)

(18)

$(16)

Change

387AQC

$1,087Subtotal

88Corporate

$1,474

104

149

$746

2007F

Fossil

Total

FENOC

Energy Delivery

($ millions)

Financial Outlook

8


Available Cash Forecast

$395

(136)

(1,693)

$2,224

2008F

$265

(42)

(219)

$526

Change

$130

(94)

(1,474)

$1,698

2007F

Capital Expenditures

Nuclear Fuel Fabrication

Available Cash before Dividends

Net Cash from Operating Activities

($ millions)

Financial Outlook

9


Major Earnings & Cash Drivers 2009 – 2011

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

Financial Outlook

10


Major Earnings & Cash Drivers 2009 – 2011(continued)

Declining margin from Ohio 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)

Financial Outlook

11


Projected 2008 – 2011 Capital Expenditures

$1,220

75

155

260

$730

2009F – 2011F Average

86Corporate

$1,043

96

131

$730

2008F

Fossil

Subtotal without AQC

FENOC

Energy Delivery

($ millions)

Financial Outlook

$261$650

2008F

($150)$500

2009F

($145)$11

2011F

($344)$156

2010F

Change from Prior YearAQC

($ millions)

12


Projected 2008 – 2011 Capital Expenditures

FENOC capital incorporates Davis-Besse steam generator replacement in 2014 and power uprates at Davis-Besse, Perry and Beaver Valley

Fossil capital reflects $17M for generator work at Mansfield and Sammis in 2008 and $33M for asset mining initiatives over 2008 – 2010 period

Financial Outlook

$55$52$34—2013 & 2014$34$15$8$42008 – 2011

Power Uprates$65$62$41$3Steam Generator

2011F2010F2009F2008F($ millions)

13


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 November 2011

Financial Outlook

14


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

Financial Outlook

15



Flexible and agile financial strategy – avoid “big bets”

Favorable competitive generation assets; well-positioned regarding potential carbon legislation

“Asset mining” provides low-risk, low-capital approach to increasing generation capacity

Proven record of operational performance

Aggressive plan to drive further efficiencies

Manageable capital spending program

Financial Outlook

16


Transitioning to our Future (continued)

Potential to change earnings and cash flow growth trajectory through transition to competitive generation markets

Financial flexibility and ample liquidity

Competitive and growing dividend

Substantial free cash flow following completion of AQC projects

Management and employees incentivized to drive value growth for investors

Financial Outlook

17


Appendix

appendix

App-1


Share Repurchase Summary

$0.32*$0.19*$0.13Annual EPS Benefit

$62.68*$65.39*$58.99Avg. Price per Share

$1,567*$940*$627Cost ($ millions)

7.7%4.5%3.2%% Reduction

304.8304.8319.2Ending Shares

25.014.410.6Shares Repurchased

329.8319.2329.8Beginning Shares

Cumulative2007F2006

(Shares in millions)

* Estimate subject to settlement

App-2Appendix


FirstEnergy Credit Ratings

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

On November 2, 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 November 30, 2007

App-3Appendix


FFO Calculation and Coverage Ratios

= Regulatory Capitalization= Rating Agency Capitalization

Capitalization:+ Regulatory Debt+ Common stockholders’ equity

Capitalization:+ Rating Agency Debt+ Common stockholders’ equity

= Regulatory Debt= Rating Agency Debt

Debt:+ Long-term debt

Debt:+ Short-term borrowings+ Long-term debt+ Present Value of sale and

leasebacks- Securitization bonds

Regulatory ViewRating Agency ViewDebt / Capitalization

FFO Calculation

= FFO

Net IncomeAdd back non-cash items:

+ Depreciation, amortization (incl. nuclear fuel and lease amortization), and deferral of regulatory assets

+ Deferred purchased power and other costs+ Deferred income taxes and investment tax credits+ Investment impairments+ Deferred rents and lease market valuation liability+ Accrued compensation and retirement benefits- AFUDC

FFO + Adjusted InterestAdjusted Interest

FFO Interest Coverage

= Adjusted Interest

Adjusted Interest:+ Interest expense (before AFUDC)+ Interest portion of leases- JCP&L securitization bond expense

FFOAdjusted Debt

FFO Debt Coverage

= Adjusted Debt

Adjusted Debt:+ Short-term borrowings+ Long-term debt+ Present value of sale and leasebacks- Cash and cash equivalents- JCP&L securitization bonds

=

=

App-4Appendix


Strong Liquidity Position

Substantial liquidity available– $3.1B available borrowing capacity at November 30, 2007

$ 3,420

550

120

$ 2,750

Amount ($M)

Total

Various

Various

Aug. 2011

Maturity

* Revolving Credit Agreement

1-yearA/R Fin.OH & PA Utilities

VariousBank LinesFirstEnergy Corp.

5-yearRCA*FirstEnergy Corp.

TermTypeCompany

App-5Appendix


2007 Non-GAAP Earnings Per Share Guidance

App-6Appendix

Reconciliation GAAP to Non-GAAP

Affirmed on December 5, 2007

2007 EPS

Basic EPS (GAAP basis) $4.21 – $4.31Excluding Special Items:

New Regulatory AssetAuthorized by PPUC (0.05)Gain on sale of non-core assets (0.04)Trust Securities Impairment 0.03

Basic EPS (Non-GAAP basis) $4.15 – $4.25


2008 Non-GAAP Earnings Per Share Guidance

App-7Appendix

Reconciliation GAAP to Non-GAAP

Issued on December 5, 2007

2008 EPSBasic EPS (GAAP basis) $4.23 – $4.43Excluding Special Items:

Gain on sale of non-core assets (0.08)Basic EPS (Non-GAAP basis) $4.15 – $4.35



Closing Marks

Tony AlexanderPresident and CEO


SignificantEarningsGrowth

Potential

Bottom Line –FirstEnergy is an attractive risk/reward opportunity

Effectively managing transitionto competitive markets

Realizing full potential of assets

Reinvesting for future growth

Effectively deploying strong cash flow

Striving for continuous improvement

Maintaining strategic flexibility

Well-positioned for climate legislation


first energy analystmtg_120607

Economy & Finance

forwardlooking statements

regulatory changes

transition rate plan

rate stabilization plan

rate certainty plan

generation supply plan

maintenance costs

future results