first energy MorganStanleyConference_100907

Morgan Stanley Electric Utilities Corporate Access DayChicago, IL

October 9, 2007

Morgan Stanley Electric Utilities Corporate Access DayChicago, IL • October 9 ,2007

Forward-looking Statements. This presentation includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms “anticipate,”“potential,” “expect,” “believe,” “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), and the legal and regulatory changes resulting from the implementation of the EPACT (including, but not limited to, the repeal of the PUHCA), the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) and the various state public utility commissions as disclosed in the registrants’ SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the Distribution Rate Cases for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the Rate Stabilization Plan and the Rate Certainty Plan, including the deferral of fuel costs) and the Pennsylvania Public Utility Commission (including Penn’s default service plan filing), the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan filing for Met-Ed and Penelec, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the anticipated benefits from voluntary pension plan contributions, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the successful structuring and completion of a potential sale and leaseback transaction for Bruce Mansfield Unit 1 currently under consideration by management, any purchase price adjustment under the accelerated share repurchase program announced March 2, 2007, the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors. Dividends declared from time to time on FirstEnergy's common stock during any annual period may in aggregate vary from the indicated amounts due to circumstances considered by FirstEnergy's Board of Directors at the time of the actual declarations. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

Safe Harbor Statement under thePrivate Securities Litigation Reform Act of 1995

Corporate Profile & Strategic Vision


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 based on customers served

4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey

Control more than 14,000 megawatts of generating capacity

$11.5B in annual revenues and more than $31B in assets

Approx. $19B market capitalization

2Corporate Profile & Strategic Vision


Key Themes: 2007 and Beyond

Striving for continuous improvement– Realize full potential of generation assets – Mine existing opportunities for cost effective capacity additions– Reinvest to improve the long-term viability of our generation

fleet, distribution reliability and customer service

Successfully manage regulatory transitions– Seek full and timely recovery of distribution costs– Transition POLR load to competitive generation markets

Optimize financial strength and flexibility– Deploy cash effectively to increase shareholder value– Maintain strategic flexibility

3

Driving performance & delivering results

Corporate Profile & Strategic Vision

Generation


Akron

Toledo

Reading

Beaver Valley1,779 MW

Davis-Besse893 MW

Perry1,258 MW

R. E. Burger413 MW

W. H. Sammis2,233 MW

Bruce Mansfield2,460 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

Plant Load Strategy

Towanda

MW MWMW

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 2,460Beaver Valley 1,2 1,779Perry 1,258Sammis 6,7 1,200Davis-Besse 893Eastlake 5 597Bay Shore 1 136

Total Baseload 8,323

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 30

Total 493

Other MW

FirstEnergy Power Sources

C Coal 7,439 MWN Nuclear 3,930 H Hydro 651 G Gas & O Oil 1,599

Other 493Total 14,112 MW

FirstEnergy Sources of Power

2Generation


14,112 MW Capacity14,112 MW Capacity

Coal53%Coal53%

Nuclear28%

Nuclear28%

CT’s11%CT’s11%

Hydro 5%

Generation Output (MWh)Generation Output (MWh)

Other 3%

46.9 46.5 51.5 52.3

32.0

51.553.0

28.729.921.129.0 31.2

0

20

40

60

80

100

2003 2004 2005 2006 2007E 2008E

(mill

ion

MW

h)

Fossil & Other Nuclear

68.076.4 80.2 82.0 82.7 84.3

Striving for Continuous Improvement

Diverse and cost effective generation portfolio

– Over 35% of fleet is non-emitting

Continue improvement of asset utilization

– 2003 to 2006 = 22% increase in generation output

– 3 consecutive generation output records– Targeting new records in 2007 & 2008

Focus on reliability initiatives and outage execution

3

Realize full generation potential

Generation


Baseload units demonstrate consistent improvement

Top decile base load capacity factor in 2006 compared to Navigant benchmark database

Increased capacity factors and reliability initiatives drive baseload units towards top decile in 2006 Equivalent Availability

4

87.8%88.6%

85.9%84.5%

79.6%

76.0%

80.9%

68%

70%

72%

74%

76%

78%

80%

82%

84%

86%

88%

90%

2002 2003 2004 2005 2006 2007E 2008E

Top Decile

Top Quartile

•Top performance came from Navigant benchmarking study

Baseload Capacity FactorBaseload Capacity Factor

Generation


2006 generation reflects sustaining generation increase of close to 5M MWh over 2004Maximize operational flexibility for regulation, minimum loads and system rampingDispatch strategies focused on maximizing utilization in profitable markets

*Excludes the peaking units.

0

5

10

15

20M NMWh

0%

25%

50%

75%

100%Capacity Factor

Load Following 15.2 18.2 16.6 14.4 19.5 19.1 19.8Capacity Factor 54% 64% 59% 51% 69% 69% 70%

2001 2002 2003 2004 2005 2006 2007E

Focus on total fleet output has positive impact on fossil load following utilization

5Generation


* Record generation

3.153.1526.079.02002-2005 Avg

5.642.2729.088.0Fleet

19.843.4410.5*96.8Perry

0.171.766.483.1Davis-Besse

0.081.756.387.7Beaver Valley Unit 2

0.001.165.880.4Beaver Valley Unit 1

Forced Loss Rate

Forced Loss Rate

Net Generation (million MWh)

Capacity Factor (%)Plant

YTD 20072006 Fleet Performance

6Generation

Nuclear Generation

Reliability improvements during 2006 / 2007 outages– BV1 – New steam generators and reactor vessel head, main generator rewind– BV2 – Weld overlay on pressurizer nozzles, enlarged containment sump– DB – Replaced two reactor coolant pumps, replaced low pressure turbine

rotors and diaphragms

Strong plant reliability

Morgan Stanley Electric Utilities Corporate Access DayChicago, IL • October 9 ,2007 7

Nuclear Generation

Refueling *25$30Beaver Valley 2R14

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

30$30Beaver Valley 1R19

Refueling *10-year IVVI / Bioshield In-service InspectionRecirc Pump Motor Replacement

25$30Perry 1R12

2009

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


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

Split Pins *Containment Sump Modifications*Reactor Vessel ISI *100% Eddy Current TestReactor Vessel Head InspectionPressurizer Overlay


Refueling *IVVIActual Outage Period (4/2/07 – 5/13/07)

30$30Perry 1R11

2007

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

Expected Outage Duration

(days)

Expected Outage Costs

($ millions)PlantYear

Future refueling outages focus on reliability

Generation


Nuclear Generation

Through 2006, 46 of 102 plants reached capacity in used fuel pools49 operating plants built on-site dry cask fuel storage, 46 are under constructionPlans for federal repository for long-term storage – Yucca Mountain Congressional proposals for interim storage and reprocessing

8

FENOC PlanBV Unit 1BV Unit 1

BV Unit 2BV Unit 2

Davis-BesseDavis-Besse

PerryPerry

Implement dry storage by end of 2014

Criticality analysis frees up storage spaceRerack before 2011 to provide capacity through 2025Dry storage could then be implemented

Continue with wet storage until 2021Return to dry storage in 2022

Spent fuel pool campaign in 2007Implement dry storage before 2011

Managing our used fuel

Generation


2046201520132026Perry

2037201220102017Davis-Besse

204720092007*2027Beaver Valley Unit 2

203620092007*2016Beaver Valley Unit 1

NewExpiration

Approval Expected

SubmitRequest

(NRC Docket)

Current Expiration

License Renewal Schedule

9

Nuclear Generation

* License renewal application submitted to the NRC on August 27, 2007.

Continued safe operations through license renewal

Generation



Mining existing asset base for low risk, cost-effective growthWind power contracts helping to meet renewable portfolio standardsAdditional longer-term initiatives under review

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

675496179Total MW additions21418430Wind power contracts 1821820Peaking capacity enhancements* 14910049Nuclear baseload uprates13030100Fossil baseload uprates

Cumulative2007E–2008E2005–2006MW Additions

10

Asset mining initiatives

Generation


Realizing Full Potential of Asset Base

11

27957739950Total Uprates130305050Total3030Mansfield 35050Mansfield 25050Mansfield 1

Fossil149574349Total554510Beaver Valley 2684325Beaver Valley 1261214Davis-Besse

NuclearTotal2008200720062005(MW)

Baseload capacity uprates

Generation

Environmental Strategy


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

2


Fleet Emission Control Status

60%8,4389%1,269Natural Gas Peaking

18%2,569Coal Controlled(SO2/NOx – full control)

33%4,600Non-EmittingFleet %Capacity (MW)

Our generation fleet is well positioned for the future



AQCS Capital Expenditures

$54$136

$387

$593$530

$180

$13$0

$200

$400

$600

2005 2006 2007E 2008E 2009E 2010E 2011E

($ m

illio

ns)


3


AQCS expenditures estimated at $1.9B

Ensure the long-term viability of the fleet



4


Sammis Plant (2,220 MW) – $1.65 Billion– SO2 control (scrubbers) all units– NOx control (SCRs) Units 6 & 7 (1,200 MW)– NOx control (SNCR) Units 1–5 (1,020 MW)

completed

Mansfield Plant (2,460 MW) – $50 Million– SO2 control (scrubber) upgrades

– 1,660 MW completed, 800 MW to be completed in 2007

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

Units 4 & 5 (312 MW)

NOx Controls (SNCR) – $6 Million– Eastlake Unit 5 (600 MW) completed

AQCS Construction Overview


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

5Environmental Strategy


Firstenergy’s Diverse Generation Provides Strong Competitive Position

Over 35% of generation from non-emitting nuclear units in 2006

Uprates will further increase nuclear generating capacity

Long-term contracts for more than 200 MW of wind capacity



Current Greenhouse Gas Reduction Actions

$100M in investments planned 2006–2010– $50M on products, programs and activities to help reduce greenhouse

gas emissions– $50M to support relicensing and capacity uprates at non-emitting

generating plants; renewable energy development

Fleet modernization a key strategy:– Increased ownership of nuclear generation and decreased ownership

of coal– 1,383 MW of older coal-based boilers out of service since 1990

(estimated annual CO2 avoidance of 1.5 million tons)– 1,155 MW of new natural gas-fired peaking capacity since 1999– > 200 MW of wind generation secured through long-term agreements

Overall efforts resulted in average annual reductions of 8.9 million tons of CO2 equivalent; 143 million tons since 1991



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



FirstEnergy’s climate activities


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


Commodity Operations Strategy

Manage commodity value chain

Effectively deploy generation to capture market opportunities

Enhance fuel supply / logistics to maximize optionality

Efficiently manage purchased power requirements

Employ strict risk management controls and oversight– Volume and price risks– Generation availability risks– Transmission congestion risks

Maximizing Margins byMitigating Risks And Minimizing Supply Costs

2

Effectively managing commodity margins and risks



* Represents the percentage hedged of total forecasted generation.

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

3

Commodity Operations Strategy

100%100%Nuclear fuel*

100%100%NOx*

94%100%SO2*

98%100%Coal transportation*

95%100%Coal only*

20082007% Hedged


Effectively hedging commodity positions


Commodity Operations’ objective is to provide FirstEnergy with a predictable and profitable commodity margin

GenerationMargin

GenerationMargin

MWH

COST

FENOC

31M MWh

FENOC

31M MWh

MWH

COST

Fossil

51M MWh

Fossil

51M MWh

MWH

COST

Purchased Power34M MWh

Purchased Power34M MWh

MWH

REV

RegulatedSales

80M MWh

RegulatedSales

80M MWh

MWH

REV

CompetitiveSales

12M MWh

CompetitiveSales

12M MWh

MWH

REV

WholesaleSales

20M MWh

WholesaleSales

20M MWh

MWHLosses &Pumping4M MWh

Losses &Pumping4M MWh

+ Generation Revenue– Fuel– Purchased Power

Generation Margin

CommodityMargin

CommodityMargin

Excludes JCP&L and OVEC.

+ Generation Margin– Transmission Expense– RTO expense

Commodity Margin

PJM / MISOExpenses

PJM / MISOExpenses

4Commodity Operations



Balanced emission allowance position minimizes risks

Based on projected generation:

Emission allowance positions are well covered2007 SO2 position is covered2008 SO2 is slightly short due to economic fuel switching decisions in recent strategic planning processNOx positions are completely covered

SO2 Position (tons)

Needed Covered Position

NOx Position (tons)

0

10,000

20,000

30,000

2007 2008

Needed Covered Position

-30,000

60,000

150,000

240,000

330,000

2007 2008


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

Continue working to secure long-term fuel supply contracts

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

Engaged in fuel flexibility initiative to create more options

6

0

5,000

10,00

015

,000

20,00

025

,000

2008

2007

Total Covered TonsTotal Needed Tons

95%

100%

Securing Open Coal Commodity Positions



0

5,000

10,00

015

,000

20,00

025

,000

2008

2007

Total Covered Tons

Total Needed Tons

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

2007 transportation positions100% covered based on forecasted generation

2008 transportation positions will be closed shortly —agreements reached

Evaluating additional delivery options to increase both capabilities and flexibility

Actively working to close long term transportation position beyond 2009

7

98%

Securing Open Fuel Transportation Positions

100%



Fuel and Transportationoptions create leverage

EastlakeBurgerAshtabulaSammisMansfieldBay ShoreLake Shore

TruckVesselBargeRailCoal Delivery Options

0

5

10

15

20

PRB 3 3 0 3 3 3 6NAAP 1 0 10 3 3 8 3CAAP 6 4 0 10 8 8 8

Lake Shore Bay Shore Mansfield Sammis Ashtabula Burger Eastlake

107

10

1614

1917

Planned & PotentialMine Sources

# of

Min

es

8Commodity Operations


Annual requirementof 22–25 million tonsIncreasing usage ofPRB coal

2003 – 23%2004 – 25%2005 – 35%2006 – 37%2007E – 46%

Coal Supply 2007E Coal Mix by Origin (tons)

CAPP15%

PRB46%

NAPP39%

9

Coal Supply


Balanced and economic

Energy Delivery


Ohio

Ohio Edison 1,042,000 7,000

Illuminating Company 762,000 1,600

Toledo Edison 314,000 2,300

Met-Ed 542,000 3,300

Penelec 589,000 17,600

Pennsylvania Power 159,000 1,100

Jersey Central Power & Light 1,082,000 3,200Total 4,490,000 36,100

Customers Square Miles

Pennsylvania

NewJersey

2

FirstEnergy Service Areas

Energy Delivery



Targeted reinvestment in T&D infrastructure – Focus on reducing outages, restoration time, and customers affected

Leveraging technology– Focus on customer service and outage management

Implement “Energy Delivery Excellence Program”– Comprehensive review identified operational, technological,

scheduling and financial control opportunities for improvement

Significant improvement in reliability metrics– In 2006, outage duration improved 20%– 2007 YTD through June, outage duration improved 13%; outage

frequency improved 7%– Transmission outage frequency per circuit is at top-decile

3Energy Delivery

Improve distribution reliability and customer service


FirstEnergy’s Strengths

Residential35%

Commercial32%

Ohio2.1 million

Pennsylvania1.3 million

New Jersey1.1 million

Attractive Customer BaseLarge and Balanced

Industrial33%

4

Electric Customers – 5th Largest Balanced Sales Mix

Energy Delivery


0.00

0.10

0.20

0.30

0.40

0.50

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

Out

ages

per

Circ

uit

Energy Delivery Reliability Improvements

The Transmission Outage Frequency (TOF) is a measure of the average number of transmission circuit outages per circuit in the 230–500kV voltage classes.

Transmission Outage Frequency (TOF) Per Circuit

SAIDI represents the average total duration of outage minutes per customer in a year adjusted for major storms.

Distribution SAIDI (System Average Interruption Duration Index)

Industry Avg.* = 0.50Top Quartile* = 0.39Top Decile* = 0.31YTD = 0.30

2007YTD= 93.9

2006YE = 152

0

50

100

150

200

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

SAID

I (m

inut

es)

Threshold

2007

2006

2007 Commission Threshold = 148

5

* As defined by SGS benchmarking study.

Energy Delivery

Regulatory Matters


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 2018No restriction

Met-Ed

Penelec

Toledo Edison

CEI

CTC endedJan. 2006

CTC thru 20102

CTC thru 20092

Pass thruPJM costs

Norestriction

InGeneration

2Regulatory Matters


Successfully Manage Regulatory Transitions

3Regulatory Matters

Seek full and timely recovery of distribution costsOhio Edison, CEI, and Toledo Edison

Comprehensive Distribution rate requests filed on June 7; Update filed on August 6

Proposed rates would be effective January 1, 2009 for OE and TE; expected to be effective in May 2009 for CEI

Ohio

Proposed increase:Traditional distribution costs 212Recovery of costs deferred under prior rate plans 120

Total proposed increase to "distribution" revenues $332Offsetting RTC decrease ($594)Net decrease, including offsets * ($262)% Decrease, including offsets to total current revenues * -5.7%

* Assumes current Generation & Transmission rates


Generation asset transfer completed in 2005In July 2007, filed comprehensive generation supply plan for competitively priced service beginning January 2009Proposal includes:– Option to phase in generation price increases for residential tariff

groups with > 15% increase in average total price– Time-of-day and hourly pricing options– Renewable energy component

PUCO decision requested by November 1, 2007– Technical conference held on August 16– Initial Comments filed on September 5; PUCO Staff comments

filed on September 21; reply comments by October 12Competitive bid structuring alternatives– By Customer Class or Slice of System

4Regulatory Matters

Transition to competitive generation marketsSuccessfully Manage Regulatory Transitions

Ohio


Bid structuring 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

Initial bids to be conducted:– January 2008 (Slice of System), or– March 2008 (Customer Class)

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)

5Regulatory Matters


Ohio


On August 29, Governor Strickland Proposes Energy, Job and Progress Plan – 7 Key Principles– Market Rate Plan or Electricity Security Plan– Advanced Energy Portfolio Standard – 25% by 2025– Transparency & Accountability – Promote aggregation, demand response and advanced metering– Modernizing electric infrastructure/single issue ratemaking– Energy Efficiency Standard – 25% of projected growth,

decoupling– Address global climate change

Plan introduced as SB 221 on September 25– http://www.legislature.state.oh.us/bills.cfm?ID=127_SB_221

6Regulatory Matters


Ohio


Ohio Edison, CEI, and Toledo Edison

On August 29, the Ohio Supreme Court remanded the recovery of deferred fuel costs in distribution rates back to the PUCO for further consideration

The Court reaffirmed all other aspects of the Rate Certainty Plan

On September 7, the Companies filed a Motion for Reconsideration with the Court

On September 10, the Companies filed an Application on Remand with the PUCO proposing generation-related fuel cost recovery riders

Regulatory Matters

Supreme Court Remand on Rate Certainty PlanSuccessfully Manage Regulatory Transitions

Ohio


Transition Plan Rate Case– $109M 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

NUG Accounting Case– ALJ Initial Decision was to deny the Companies’ request– Awaiting PPUC Final Order

Generation transitions to market-based rates in 2011Governor’s Energy Independence Strategy – Special Legislative Session– PennSecurity Initiative (biofuel)– $850 million Energy Independence Fund – renewables and

efficiency

8

Successfully Manage Regulatory TransitionsMet-Ed and Penelec

Regulatory Update


POLR 1: transition to market-based generation rates– RFP process for 900 MW from January 2007–May 2008

POLR 2: continuation starting June 2008– Proposed full requirements product by class– Multiple RFPs with staggered delivery through 2011– Three year phase-out of promotional generation rates– Settlement Agreement filed on September 28, 2007– Anticipate commission order by November 29, 2007

Successfully Manage Regulatory TransitionsPenn Power

9Regulatory Update


Generation supplied through BGS auction process

Sale of Forked River Generating Station– Proceeds approximately $20M

Energy Master Plan – 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

10

Regulatory MattersJersey Central Power & Light

Regulatory Update

Financial Matters


Optimize Financial Strength and Flexibility

Use cash to benefit shareholders– Sustainable common stock dividend growth

– 11.1% increase (March 1, 2007)– Share repurchase

– 14.4 million ASR (March 2, 2007)

Continue focus on capital structure management– Additional transfers of tax-exempt debt from operating companies– Appropriately capitalize operating companies

Remain flexible to capitalize market opportunities– Executed Mansfield Unit 1 sale and leaseback transaction on July 13

Deliver consistent and predictable financial results

2Financial Matters

Maintain strategic flexibility


$ 1,744$ 1,464$ 1,170Total

5910439Other

609396136Environmental

7058116Fossil

110126229FENOC

$ 896$ 780$ 650Energy Delivery

2008E2007E2006($ millions)

* Total capital expenditures forecast for 2009–2011 estimated to be approx. $4.7B

3Financial Matters

Reinvest in the businessStriving for Continuous Improvement


Share Repurchase

On March 2, FirstEnergy repurchased 14.4 million shares– Represents approx. 4.5% of outstanding shares– $900M ASR at initial price of $62.63 per share– Final purchase price to be adjusted to reflect volume-weighted

average price of stock during acquisition period (up to approximately one year)

Coupled with August 2006 ASR program of 10.6 million shares, total buy-backs equal approx. 7.6% of shares outstanding

Projected net earnings impact from both buy-backs is approx. $0.18 per share in 2007 vs. 2006

4Financial Matters


Pension Contribution

Previously contributed $1B to plan during 2004–2005

Pension Protection Act of 2006 changed plan funding rules

$300M contribution ($193M after-tax) made in January

Increases plan funding– Improves PBO funded ratio to 105%

Financial impact of contribution equates to 15% pre-taxcash return, 9% after-tax return

Accretive to annual earnings by approx. $0.05 per share

FAS 87/106 cost: 2006 $ 94 M2007E (89) M

$ (183) M

5Financial Matters


Long-Term Dividend Policy

Annual growth target of 4–5%

Sustainable annual growth and a payout ratio appropriate for our level of earnings

Dividend Changes:

6

$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

11.1%50.00¢1Q 2007

Change fromPrior Period

QuarterlyRate

PaymentDate

Financial Matters


FirstEnergy Solutions (FES)

Wholly-owned competitive subsidiary– Holding company for FirstEnergy Genco and FirstEnergy

Nuclear Genco– Provides energy-related products and services to wholesale

and retail customers in MISO and PJM

Generation assets transferred in 2005

Investment grade ratings (BBB/Baa2) received in March

SEC registrant providing full financials

Targeting a debt ratio in the upper 50% range by 2008– $1.4B of genco-level tax exempt debt (4% avg. cost)

comprises approx. 45% of debt portfolio

7Financial Matters


FirstEnergy Solutions (FES) (cont.)

Executed Mansfield Unit 1 sale and leaseback transaction– Traditional leveraged lease structure: approx. 85% / 15%

debt/equity– After-tax proceeds of $1.2B used to repay short-term debt drawn

to fund share repurchases and voluntary pension contribution– Equivalent to borrowing at 3.6% for a term of 33 years

Additional transfers of tax-exempt debt from utilities– Planning to issue $455M insured Genco auction rate securities– Subsequent to this transaction, $1.9B of PCRBs will have been

transferred to FES with $265M PCRBs remaining at utilities to be transferred

8Financial Matters


$3.00

$3.50

$4.00

$4.50

$5.00

$3.88(1)

($0.05)

$0.07

($0.05)$4.15(1)

$0.18

Midpoint 2006 Non-GAAP EPS

GenerationOutput &

MixWiresGrowth

T&D Infra-structure

Midpoint 2007 Non-GAAP

EPS Guidance

$0.06

$0.17

($0.19)

NetBenefitCosts

ME/PERate Case (“D”)

OH Trans-ition Cost

Amort.

2007 Non-GAAP Earnings Per Share Guidance(2)

Issued January 31, 2007

(1) See GAAP to non-GAAP reconciliations in subsequent slides. (2) 2007 EPS guidance, excluding unusual items, is $4.05 – $4.25. On a GAAP basis, EPS is expected to be $4.09 – $4.29.

Net Share Repurchases Depr.

($0.10)

Penn Power

to Market

$0.12All

OtherNuclear Outage O&M

$0.08($0.02)

9Financial Matters


Net Pension Contribution: $373M ($90M tax benefit realized in 2006)

Securitization/Asset Sales in 2006: $310M

Higher Dividends / Capital Expenditures: $215M

Wires Growth: $20M

Gen Output/Mix: $15M

Penn Power to Market: $40M

Nuclear Outage O&M: $25M

PA Rate Increase: $60M

JCP&L NUG Recovery: $100M

Net Collateral: $80M

10

2007 Cash Flow Drivers

Financial Matters


Higher Ohio transition cost amortization

T&D infrastructure investment

Increased fuel and purchased power costs

Growth in delivery sales

Increased generation margin

Lower generation-related outage maintenance costs

11

2008 Earnings Drivers

Financial Matters


Adjusted Total Debt / Total Capital Funds from Operations / Interest Coverage

Funds from Operations / Total Debt

Maintaining Financial Strength and FlexibilityMaintaining Financial Strength and Flexibility

3.53.53.53.73.0

2.5

0

1

2

3

4

5

2002 2003 2004 2005 2006 2007E

17%17%18%18%

14%

11%

0%

5%

10%

15%

20%

2002 2003 2004 2005 2006 2007

60%58%56%58%60%67%

0%

10%

20%

30%

40%

50%

60%

70%

2002 2003 2004 2005 2006 2007E

FirstEnergy Credit Metrics

12Financial Matters


FirstEnergy Credit RatingsS&P’s outlook on all companies is stable

Moody’s outlook on FE Solutions is stable and positive for all other companies

13

Business Profile

Corporate Credit Rating (S&P) / Issuer Rating

(Moody's)

Senior Secured Senior Unsecured

S&P S&P Moodys S&P Moodys S&P MoodysFirstEnergy Corp. 7 BBB Baa3 - - BBB- Baa3

FirstEnergy Solutions 8 BBB Baa2 - - - -

Ohio Edison 5 BBB Baa2 BBB+ Baa1 BBB- Baa2

Cleveland Electric Illuminating Co. 5 BBB Baa3 BBB+ Baa2 BBB- Baa3

Toledo Edison 5 BBB Baa3 BBB Baa2 BBB- Baa3

Pennsylvania Power 5 BBB Baa2 A- Baa1 BBB- Baa2

Jersey Central Power & Light 4 BBB Baa2 BBB+ Baa1 BBB Baa2

Metropolitan Edison 4 BBB Baa2 BBB+ Baa1 BBB Baa2

Pennsylvania Electric Co. 4 BBB Baa2 BBB+ Baa1 BBB Baa2

As of September 7, 2007

Financial Matters


Strong Liquidity Position

Substantial liquidity available– $3.0B available borrowing capacity as of September 13, 2007

14

$ 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

Financial Matters


Issued on February 20, 2007

2006 Earnings Per Share

2006 EPSBasic EPS (GAAP basis) $ 3.84Excluding Unusual Items:

Trust Securities Impairment 0.02PPUC NUG Cost Reserve for Prior Years 0.02

Basic EPS (non-GAAP basis) $ 3.88

15Financial Matters

Reconciliation of GAAP to Non-GAAP


As of August 7, 2007

2007 Non-GAAP Earnings Per Share Guidance

2007 EPSBasic EPS (GAAP basis) $4.11 – $4.31Excluding Unusual Items:

Benefit from 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) $4.05 – $4.25

16Financial Matters

Reconciliation of GAAP to Non-GAAP

Investment Highlights


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

Significant Earnings Growth

Potential

Significant Earnings Growth

Potential

An attractive risk/reward opportunity

FirstEnergy – Driving Performance & Delivering ResultsFirstEnergy – Driving Performance & Delivering Results

2Investment Highlights

Economy & Finance

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