Presentation Slides and Handouts

Forward-Looking Statements

This presentation includes forward-looking statements within the meaning of the Private Securities

Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause

actual results to differ materially from these forward-looking statements include those discussed herein

as well as those discussed in (1) Exelon’s 2006 Annual Report on Form 10-K in (a) ITEM 1A. Risk

Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of

Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s

Third Quarter 2007 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk

Factors and

(b)

Part

Financial

Information,

ITEM

Financial

Statements:

Note

13;

and

(3)

other

factors discussed in filings with the Securities and Exchange Commission by Exelon Corporation,

Exelon Generation

Company,

LLC,

Commonwealth

Edison

Company,

and

PECO

Energy

Company

(Companies). Readers are cautioned not to place undue reliance on these forward-looking

statements, which apply only as of the date of this presentation. None of the Companies undertakes

any obligation to publicly release any revision to its forward-looking statements to reflect events or

circumstances after the date of this presentation.

This presentation includes references to adjusted (non-GAAP) operating earnings that exclude the

impact of certain factors. We believe that these adjusted operating earnings are representative of the

underlying operational results of the company. Please refer to the Appendix to the presentation for a

reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings.

Agenda

Industry & Market Dynamics

PECO

ComEd

Exelon Generation

Exelon

Appendix

•

O&M and Capital Expenditure Expectations

•

Pennsylvania Legislative/Regulatory Snapshot

•

ComEd Transmission Settlement and Distribution Case Summaries

•

Generation Portfolio Characteristics and Hedging Targets

•

Required Break-Even Cost by Technology (Illustrative)

•

Nuclear Fleet Details

•

Exelon and Climate Change

Today’s discussion will focus on Exelon’s five-year outlook

Energy dependency /

geopolitical concerns

Declining US reserve

margins

Environmental /

climate change

concerns

Continued strong

global growth in

energy consumption

Continued high fossil

fuel prices

Massive capital

investment

Increasing cost of

new build

Technology

improvements

Increasing heat rates

Increasing capacity

prices

With Numerous Forces Driving

the Industry…

Political /

regulatory

pressures

>80% EPS from unregulated

generation

Largest, lowest-cost nuclear fleet in

competitive markets

Complementary and flexible fossil

and hydro fleet

Executing regulatory recovery plan

at ComEd

Managing transition to competitive

markets in Pennsylvania

Increasingly strong cash flows and

balance sheet

Exelon Position

Macro Trends

Market Response

PECO

ExGen

ComEd

PECO

ExGen

Operating EPS

(3)

$2.41

Operating EPS Guidance

(3)

$4.15 –

$4.30

(1)

Total Shareholder

Return

for

the

period

12/31/01

–

10/31/07.

(2)

~65% EPS growth assumes $10/tonne carbon and equates to ~10%+ CAGR; ~13%+ CAGR assuming $20/tonne carbon; 1 tonne = 2,205 lbs.

(3) See Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

ExGen

ComEd

2002

2007

2012

…Exelon Is Uniquely Positioned for

Continued Strong Value Creation

~10%+ Compound Annual Growth Rate in EPS from 2007 to 2012

4.2

4.3

5.0

2.7

2.0

Competitive Transition Charge (CTC)

Rate Base (Transmission, Distribution & Gas)

PECO –

Moving Forward

(1)

Rate base details provided in Appendix.

(2)

2007 Operating Earnings Guidance; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(3)

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to uncertainties and should not be relied

upon as a forecast of future results.

Transitioning through an orderly

structure to market-based rates

•

Increasing CTC amortization

results in declining rate base

and net income through 2010

Working proactively with the Governor,

Legislature, and PAPUC for post-

transition rates and structure

Supporting plans to implement energy

efficiency and renewable programs

Preparing power procurement filing for

2008 to address post-transition plan

beginning in 2011

Net Income

ROE

Equity

$435 –

$470M

Not applicable due to

transition rate structure

$360 –

$400M

6.9

6.3

5.0

~$250 –

$270M

~10 –

11%

~50%

2007 (Guidance)

(2)

2008 (Preliminary)

2012 (Illustrative)

(3)

PECO provides a predictable source of earnings to Exelon through

the remainder

of the transition period

Actively Engaged in Transition

Average Annual Rate Base

(1)

($ in Billions)

6.0

6.6

8.4

1.8

2.0

2.3

Transmission

Distribution

ComEd –

Moving Forward

(1)

2007 Operating Earnings Guidance; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2)

Equity based

definition

provided

most

recent

ICC

distribution

rate

case

order

(book

equity

less

goodwill).

Projected

book

equity

ratio

2007

58%.

(3)

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to uncertainties and should not be

relied upon as a forecast of future results.

(4)

Assumes full $361M revenue increase granted in current distribution rate case.

Executing Regulatory

Recovery Plan

Net Income

ROE

Equity

(2)

$220M –

$260M

(4)

$130M –

$165M

~5.5 –

6.5%

~3.8 –

4.8%

45%

44%

After

2007,

ComEd’s

earnings

are

expected

increase

regulatory

lag

reduced

over

time through regular rate requests, putting ComEd on a path toward appropriate returns

Implementing progressive formula

transmission rate upon FERC

approval of settlement

Supporting recently filed

distribution rate case

Actively promoting/implementing

efficiency, renewable energy, and

demand-side management

programs

Studying innovative future test

year approach for distribution rate

filing in 2009

7.8

8.6

10.7

Average Annual Rate Base

($ in Billions)

~$490M –

$530M

~10 –

11%

~45%

2007 (Guidance)

(1)

2008 (Preliminary)

2012 (Illustrative)

(3)

Average Capacity Factor

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

Complementary and flexible fossil and

hydro fleet

Improving power market fundamentals

(commodity prices, heat rates, and

capacity values)

End of below-market contracts in

Pennsylvania beginning 2011

Potential carbon restrictions

Value Proposition

Exelon Generation

Continue to focus on operating excellence,

cost management, and market discipline

Support competitive markets

Pursue nuclear & hydro plant relicensing

and strategic investment in material

condition

Maintain industry-leading talent

Protect Value

Pursue nuclear plant uprates (~200MW by

2012) and investigate potential for more

Pursue nuclear Construction and

Operating License in Texas and Mountain

Creek expansion

Capture increased value of low-carbon

generation portfolio

Grow Value

Exelon Generation is the premier unregulated generation company –

positioned to

capture market opportunities and manage risk

World-Class Nuclear Operator

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

Note: Exelon data prior to 2000 represent ComEd-only nuclear fleet.

Sources: Platt’s,

Nuclear

News,

Nuclear

Energy

Institute

and

Energy

Information

Administration

(Department

Energy).

100

Operator (# of Reactors)

Range

5-Year Average

EXC 93.2%

Average Capacity Factor

Range of Fleet 2-Yr Avg Capacity Factor (2002-2006)

Sustained production excellence

-15%

-10%

-5%

10%

15%

20%

25%

30%

2007

2008

2009

2010

2011

2012

Reserve Margins Declining

Natural Gas Prices Remaining High

PJM-West

PJM-East

NI-Hub

ERCOT

$10

2008

2010

2012

2014

2016

2018

2020

NYMEX

Positively Exposed to Market Dynamics

Note: Illustrative estimate. Overnight, all-in capital cost without interest during construction.

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

EIA Carbon Case

2010: $31/tonne

Europe Carbon-Trading

2012: $35.50/tonne

Carbon Credit ($/Tonne)

Carbon Legislation Progressing

Lieberman-Warner

Possible $20 to $40/tonne

Bingaman-Specter

2012: $12/tonne

Various

3rd

party

estimates

Construction Costs Escalating

Note: Refer to the Appendix for additional information.

New Generation Installed Cost

Combined Cycle

Gas Turbine

Coal

Nuclear

500

1,000

1,500

2,000

2,500

3,000

2006

2007

2006

2007

2006

2007

Exelon Generation –

Long-Term Value

Exelon Generation is poised for significant earnings growth driven by improving market

fundamentals, the

end

the

Pennsylvania

transition

period,

and

carbon

legislation

2007 Guidance

(1)

2012

2008

(1) 2007 Operating Earnings Guidance; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

$2,320M -

$2,385M

2009 –

2012 Earnings Drivers

End of PECO PPA (2011+)

Carbon (2012+)

Market conditions

Heat rate

Capacity prices

New build costs

Nuclear uprates

Higher O&M costs

Higher nuclear fuel costs

Higher interest and

depreciation expense

2008 Earnings Drivers

Market conditions

Capacity prices

Marginal losses

More nuclear outages

Higher nuclear fuel costs

Higher O&M costs

State Line buyout

Higher interest and

depreciation expense

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

Based on the refueling cycle, we

will conduct 12 refueling outages

in 2008, versus 9 in 2007, and

10 to 11 in a typical year

Impact of Refueling Outages

Note: Net nuclear generation data based on ownership interest; includes Salem.

18 or 24 months

Duration: ~24 days

Nuclear Refueling Cycle

2008 is an exception:

•

Salem steam generator

replacement

•

3 more outages than 2007

•

~2,600 GWh less than 2007

$100-$110M negative after-tax

impact

2008 Refueling Outage Impact

Refueling Outage Duration

Nuclear Output

2000

2001

2002

2003

2004

2005

2006

Sept '07

YTD

Exelon

Industry

Actual

Target

Estimate

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

2007

2008

2009

2010

2011

2012

Effectively Managing Nuclear Fuel Costs

Enrichment

38%

Fabrication

17%

Nuclear Waste

Fund

23%

Tax/Interest

Conversion

Uranium

17%

Components of Fuel Expense in 2007

200

400

600

800

1,000

1,200

1,400

2007

2008

2009

2010

2011

2012

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

Projected Total Nuclear Fuel Spend

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2007

2008

2009

2010

2011

2012

Exelon Average Reload Price

Projected Market Price (Term)

Note: Excludes costs reimbursed under the settlement agreement with the DOE.

Market source: UxC

composite forecasts.

Refer to Appendix for uranium price sensitivities.

2007 –

2011:

100% hedged in volume

2012:

~40% hedged in volume

All charts exclude Salem, except Projected Total Nuclear Fuel Spend.

2008 “Open”

EBITDA

2008

EBITDA

2008

Open EBITDA

(No Carbon)

$ Millions

~$4,100

~$3,900

2007

EBITDA

(2)

Un-hedged (“Open”) EBITDA plus upside from energy, capacity, and carbon drives

Exelon Generation’s value

(1) Un-hedged EBITDA assumes that existing hedges (including the PECO load, Illinois auction load, ComEd financial swap, and other sales) are priced at market prices as of 7/31/07.

(2) Refer to the Appendix for a reconciliation of Net Income to EBITDA.

(3) 1 tonne = 2,205 lbs.

~$5,350

Hedged –

2008

Un-Hedged –

2008

(1)

Hedged –

2007

169.20

Eastern MAAC Capacity Price ($/MW-day)

82.30

Rest-of-Market Capacity Price ($/MW-day)

5.6

NI-Hub Implied Heat Rate (mmBtu/MWh)

6.6

PJM W-Hub Implied Heat Rate (mmBtu/MWh)

47.00

NI-Hub ATC Price ($/MWh)

62.90

PJM W-Hub ATC Price ($/MWh)

8.50

Henry Hub Gas Price ($/mmBtu)

2008 Open EBITDA

(1)

Assumptions

~$1,000M

+ $10/Tonne Carbon Price

(3)

~$80M

+/-

$10/MW-Day Capacity Price

~$750M

+/-

500 Btu/KWh ATC Heat Rate

~$560M

+/-

$1/mmBtu Gas Price

(Pre-Tax Impact)

2008 Open EBITDA

(1)

Sensitivities

Exelon’s Strategic Direction

Deliver superior operating

performance

Support competitive markets

Protect the value of our generation

Build healthy, self-sustaining

delivery companies

Take the organization to the next

level of performance

Advance an environmental strategy

that leverages our carbon position

Rigorously evaluate new growth

opportunities

Align our financial management

policies with the changing profile of

our company

Protect Today’s Value

Grow Long-Term Value

Advancing Exelon’s Low-Carbon

Strategy

Advocating in favor of climate change legislation that is national,

mandatory and economy-wide

Taking voluntary action to reduce our greenhouse gas (GHG)

emissions 8% by 2008

(1)

Continuing to invest in our low-carbon generation portfolio

Developing a comprehensive low-carbon energy strategy

•

Expanding our low-carbon resources

•

Providing customers with green products and services

•

Being a model of green operations

(1) From 2001 levels

Potential Nuclear New Build

Intend to file Construction and Operating License (COL) for plant in

Texas by end of 2008

•

Preserves option to participate in Energy Policy Act incentives

Texas is attractive market for new nuclear

•

Growing demand for baseload

power, robust market prices

•

State and local support for new nuclear

•

Existing Exelon presence in Texas

Exelon’s phased approach allows for go/no-go decisions at major

funding/commitment milestones

Exelon’s conditions for new build remain unchanged: the economics

must be right

Nuclear new build would capitalize on improving fundamentals, high gas prices,

and Exelon’s core strength in nuclear operations

Disciplined Financial Management

In December 2006, the Exelon Board approved a new “Value

Return Policy”

The Policy:

•

Established a base dividend at $1.76/share, growing modestly over

time

•

Returns excess cash and/or balance sheet capacity through share

repurchases

Consistent with the Policy, we executed a $1.25 billion accelerated

share repurchase agreement in September

We expect to ask the Exelon Board to consider a normal increase

in the dividend for 2008 and to consider expanding the 2007 share

repurchase program in the first quarter of 2008

Exelon has an increasingly strong balance sheet that will be deployed both

to protect and grow shareholder value

Exelon –

Value Driven

Continued strong financial and operating performance

>80% EPS from unregulated generation

Largest, lowest-cost nuclear fleet in competitive markets

Executing regulatory recovery plan to put ComEd on a

path toward appropriate returns and solid credit metrics

Managing transition to competitive markets in

Pennsylvania

Increasingly strong cash flows and balance sheet

Implementing value return policy

With numerous forces driving the industry, Exelon is uniquely positioned for

continued strong value creation

’06 Earnings

(1)

$1,275M

’07E Earnings

(2)

$2,320 -

$2,385M

’06

EPS

(1)

$1.88

’07

EPS

Guidance

(2)

$3.45

$3.55

Total Debt

(3)

$1.8B

Credit Rating

(4)

BBB+

The Exelon Companies

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘06 Operating Earnings

(1)

$2.2B

‘07E Operating Earnings

(2)

: $2.8 -

$2.9B

‘07 EPS Guidance

(2)

: $4.15 -

$4.30

Assets (12/31/06):

$44.3B

Total Debt (12/31/06):

$13.0B

Credit Rating

(4)

: BBB

(1) 2006 Adjusted (Non-GAAP) Operating Earnings and Operating EPS.

(2) Estimated 2007 Adjusted (Non-GAAP) Operating Earnings and 2007 Operating Earnings Guidance per Exelon share.

(3) As of 12/31/06.

(4) Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 10/31/07.

Pennsylvania

Utility

Illinois

Utility

’06 Earnings

(1)

$528M

$455M

’07E Earnings

(2)

: $130 -

$165M

$435 -

$470M

’06 EPS

(1)

$0.78

$0.67

’07

EPS

Guidance

(2)

$0.20

$0.25

$0.65

$0.70

Total Debt

(3)

$4.6B

$4.2B

Credit Ratings

(4)

: BBB

Multi-Regional, Diverse Company

Note: Megawatts based on Generation’s ownership as of

10/1/07, using annual mean ratings for nuclear units (excluding

Salem) and summer ratings for Salem and the fossil and hydro

units;

capacity

excludes

New

Boston

Unit

and

State

Line

PPA.

Mid-Atlantic contracts include wind and cogeneration projects.

Midwest Capacity

Owned:

11,373 MW

Contracted:

4,271 MW

Total:

15,644 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

181MW

Total Capacity

Owned:

24,746 MW

Contracted:

7,524 MW

Total:

32,270 MW

Electricity Customers:

1.6M

Gas Customers:

0.5M

Electricity Customers: 3.8M

Generating Plants

Nuclear

Hydro

Coal/Oil/Gas Base-load

Intermediate

Peaker

Mid-Atlantic Capacity

Owned:

10,970 MW

Contracted:

336 MW

Total:

11,306 MW

YTD ‘07 Highlights

•

Solid financial operating EPS results

Higher generation margins

Favorable weather

Strong nuclear performance

•

Illinois settlement

•

Value return plan implementation

•

ComEd regulatory recovery plan execution

Strong Financial Performance

Year-to-Date EPS Results

$3.26

$2.53

Weather Normalized

(2)

$3.31

$2.50

Operating

Adjusted (non-GAAP)

EPS

(1)

Sep-07

Sep-06

Operating EPS

$4.15 -

$4.30

(1) Refer to reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2) Excludes

$0.03

per

unfavorable

impact

versus

normal

2006

and

$0.05

per

favorable impact versus normal in 2007, based on Exelon models.

(3) Operating EPS growth rate through 2007 calculated using midpoint of 2007 Operating

EPS guidance range.

YTD 2007 weather-normalized operating earnings are 29% higher than 2006

$3.22

$3.10

$2.78

$2.61

$2.41

$2.24

$1.93

2000

2001

2002

2003

2004

2005

2006

2007E

Illinois Settlement

•

Continued ComEd membership in PJM

•

Competitive procurement for supply

•

Filed competitive

declaration

for

100

400

customers

•

Statute mandates cost recovery for purchased power

•

Reduced uncertainty around conditions for ICC approval

for strategic transactions such as reorganizations or

mergers

•

Immediate rate relief for customers

•

Provisions to help stabilize rates

•

Energy efficiency and demand response programs and

renewable portfolio standards

•

Eliminated the IL Attorney General’s challenges to the

2006 auction

•

Financial swap at market prices

•

No generation tax

Customer Focused

Protects Value of

Generation

Protects Competitive

Markets

Provides Strategic

Flexibility

O&M and CapEx Expectations

Exelon

(1)

(2)

1-2%

3-4%

(2)

~15%

2008-2012 CAGR

$3,110

$390

$1,000

$870

$730

2008E

$2,740

$350

$1,060

$720

$580

2007E

Other

Nuclear

Fuel

Capital

2-3%

2008-2012 CAGR

$4,240

$650

$1,010

$2,620

2008E

$4,090

$620

$1,030

$2,450

2007E

Exelon

(1)

O&M

Note: Reflects operating O&M data and excludes Decommissioning Trust Fund impact.

(1) Includes eliminations and other corporate entities.

(2) Due to varying capital investment for the period 2008-2012, the CAGR is not meaningful.

($ in Millions)

Industry Is Facing a Capital

Investment Challenge

Source: Cambridge Energy Research Associates

~$750B

Generation for 230+ GWs

Transmission

Distribution

$50B Conservation & Energy Efficiency

$50B (excl. Carbon) Environmental Retrofits

$300B

$350B

$150B

~$900B

Current Industry Market Cap ($B)

Investment required over the next 15 years exceeds the current

market capitalization of the entire electric industry

CapEx Spend Next 15 Years ($B)

Ability to Fund Major Investment

Cost as % of

Market Cap

(1)

($B)

1.2

247

1.1

278

Royal Dutch Shell

0.6

510

Exxon Mobil

15.0

“Average”

Investor Owned Utility

(excl. Exelon)

10.7

Largest Investor Owned Utility

9.4

Largest Investor Owned Utility

5.5

Exelon

$3B Power Plant

(2)

$3B Deep Water

Drilling Platform

(1)

Market Cap as of 10/31/07.

(2)

Represents approximate equity investment after taking into account government loan guarantees; includes cost escalation and interest during construction.

Large

and

strong

balance

sheets

will

required

for

the

utility

and

generation infrastructure investment that must occur

PECO Average Electric Rates

(1) System

Average

Rates

based

upon

Restructuring

Settlement

Rate

Caps

Energy

and

Capacity

increased

from

original

settlement

1.6%

reflect

the

roll-in

increased

Gross

Receipts

Tax

and

$0.02/kWh

for

Universal

Service

Fund

Charge

and

Nuclear

Decommissioning

Cost

Adjustment.

System

Average

Rates

also

adjusted

for

sales

mix

based

current

sales

forecast.

Assumes

continuation

current

Transmission

and

Distribution

Rates.

(2) Energy/Capacity

Price

average

the

results

for

residential

(10.51¢/kWh)

and

small

commercial

customers

(10.58¢/kWh)

from

the

second

round

PPL Auction

held 10/07. Assumes continuation of current Transmission and Distribution Rates.

2011

2008 –

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

11.52¢

(1)

Unit Rates (¢/kWh)

+18%

13.65¢

(2)

CTC terminates at year-end 2010

Energy / Capacity price expected

to increase; price will reflect

associated full requirements costs

Using latest PPL auction for

2010 as a proxy (10.5¢/kWh)

results in a system average

rate increase of ~18%

PECO’s 2011 full requirements

price expected to differ from PPL

due, in part, to the timing of the

procurement and locational

differences

Rates will vary by customer class

and will depend on legislation and

approved procurement model

Electric

Restructuring

Settlement

Projected Rate Increase

Based on PPL Auction

Results (IIIustrative)

Post Transition

2.63

0.48

2.41

6.00

10.54

Pennsylvania Snapshot

Governor Rendell proposed an Energy Independence

Strategy (EIS) in February 2007

Aimed at reducing energy costs, increasing clean

energy sources, reducing reliance on foreign fuels

and expanding energy production in PA

Funded through a systems benefit charge

Special legislation session on Energy Policy began

September 17th

Runs through mid-December

Current State of Play

Legislators concerned with cost of funding Governor's

initiatives, no new taxes

Rate freeze and/or generation tax legislation being

considered

Industry coalition working together to develop a

comprehensive package

Position of Stakeholders

Stakeholder outreach

Working with industry coalition

Negotiating legislative proposals with

Administration and legislative leadership

Smart meters and real time pricing

Energy efficiency and demand side

management programs

Procurement

Contracts for large industrials

Utilities owning generation

Rate increase deferral/phase-in

Participating directly or through industry

associations in legislative hearings and

informational meetings

Evaluating alternative proposals

PECO Actions

Key Themes of Legislative Proposals

Competitive procurement process utilizing auctions, RFPs, spot purchases

and bilateral contracts

Full and current cost recovery for default service provider (DSP)

DSP must offer residential and small commercial customers a rate

that

changes no more frequently than annually with reconciliation for

under or

over-recovery

Must file a rate phase-in plan for all customers with the option to phase-in

rate increase if class average total rate increases by more than

15%

Phase-in plans are to be opt-in for customer, provide utility with full

recovery of carrying costs with return on deferred balance

Securitization of deferred balance and carrying charges authorized

Utility may propose an early phase-in plan

Energy efficiency goal of usage reduction of 2% by 2013

Peak demand reduction goal of 3% by 2012

Utilities may file for cost recovery

Full deployment of smart meters within 6-10 years

Full recovery for net costs of smart meter deployment through base rates or

on full and current basis through automatic recovery mechanism

Must submit a time-of-use rate plan with voluntary customer participation by

the end of rate cap period

Procurement

Smart Meters

Rate Phase-in

Program

Demand Side

Response & Energy

Efficiency (DSR/EE)

ComEd Transmission Case Settlement

(1)

($ in millions)

FERC Filing

3/1/07

Preliminary Order

6/5/07

Settlement Filing

10/5/07

(1)

Total Revenue Requirement (in year 1)

(2)

$415

$387

$364

Revenue Requirement increase (in year 1)

$146

$116

(3)

$93

Rate Base (in year 1)

$1,826

$1,744

$1,672

(4)

Common Equity Ratio

58%

(5)

Return on Equity (ROE)

(6)

12.20%

11.70% + 0.50% RTO adder

12.20%

11.70% + 0.50% RTO adder

11.50%

11.0% + 0.50% RTO adder

Return on Rate Base (ROR)

9.87%

9.40%

(1) Subject to final FERC approval.

(2) Included a request for project incentives of $16 million.

(3) Rates effective 5/1/07, subject to refund.

(4) Excludes pension asset; 6.51% debt return allowed in operating expenses.

(5) Equity cap of 58% for 2 years, declining to 55% by 2011.

(6) ROE is fixed and not subject to annual updating.

RTO = Regional Transmission Organization

(Docket Nos. ER07-583-000 & EL07-41-000)

Rate settlement establishes reasonable framework for timely recovery of transmission

investment on an annual basis through formula rates

Formula Transmission Rate Annual

Update Process

(1)

Annual filing by May 15

will update the current year revenue

requirement and true-up prior year to actual:

Update current year

Estimate current year revenue requirement using updated costs based on prior

year actual data per FERC Form 1 plus projected plant additions for the current

calendar year

True-up prior year

Perform a true-up of the prior year’s rates by comparing prior year actual data

per FERC Form 1 to the estimate used for that year; over/under-recoveries for

the prior year are collected in the current year

Rates take effect on June 1

Interested parties have 180 days to submit information requests and

raise concerns; unresolved concerns go before FERC for resolution

(1) Subject to final FERC approval.

The combination of annual updating and true-up virtually eliminates regulatory lag

ComEd Delivery Service

Rate Case Filing

$361

(6)

Total ($2,049 revenue requirement)

$(51)

Other adjustments

(5)

$48

O&M expenses

$99

Administrative & General expenses

(4)

$50

Capital Structure

(3)

: ROE -

10.75% /

Common Equity -

45.11% / ROR -

8.55%

$215

(2)

Rate Base: $7,071

(1)

Requested Revenue

Requirement Increase

($ in millions)

(1) Based on 2006 test year, including pro forma capital additions through 3Q 2008; represents a $1,550 million increase from 2006 ICC order.

(2) Includes increased depreciation expense associated with capital additions.

(3) Requested cap structure does not include goodwill; ICC docket 05-0597 allowed 10.045% ROE, 42.86% equity ratio and 8.01% ROR (return on rate base).

(4) Primarily includes increases in pension and other post-retirement benefits costs and effects of a reclassification of rental revenue of $20 million, which is offset in

“Other adjustments”.

(5) Includes taxes other than income, regulatory expenses, and reductions for other revenues and load growth.

(6) Or approximately $359 million adjusted for normal weather.

Revenue increase needed to recover significant distribution system investment and

represents an important step in ComEd’sregulatory

recovery plan

Financial Swap Agreement

3,000

$53.48

January 1, 2013 -

May 31, 2013

3,000

$52.37

January 1, 2012 -

December 31, 2012

3,000

$51.26

January 1, 2011 -

December 31, 2011

3,000

$50.15

June 1, 2010 -

December 31, 2010

2,000

$50.15

January 1, 2010 -

May 31, 2010

2,000

$49.04

June 1, 2009 -

December 31, 2009

1,000

$49.04

January 1, 2009 -

May 31, 2009

1,000

$47.93

June 1, 2008 -

December 31, 2008

Notional Quantity (MW)

Fixed Price ($/MWH)

Portion of Term

•

Financial Swap Agreement between ComEd and Exelon Generation promotes

price stability for residential and small business customers

•

Designed to dovetail with ComEd’s remaining auction contracts for energy,

increasing in volume as the auction contracts expire

–

Will cover about 60% of the energy that ComEd’s residential and small business

customers use

•

Includes ATC baseload energy only

–

Does not include capacity, ancillary services or congestion

Market Price Sensitivities

~$80M

+/-

500 Btu/KWh ATC Heat Rate

~$10M

+/-

$1/mmBtu Gas Price

(Pre-Tax Impact)

2008 EBITDA Sensitivities

($80M)

($40M)

($20M)

($5M)

Expense (Pre-Tax Impact)

($335M)

($160M)

($100M)

($60M)

Capital Expenditures

2012

2011

2010

2009

2008

$50/lb

$40M

$15M

$10M

$5M

Expense (Pre-Tax Impact)

$280M

$85M

$30M

$20M

Capital Expenditures

2012

2011

2010

2009

2008

+ $50/lb

(1) Excludes Salem.

Uranium Sensitivity

(1)

Total Portfolio Characteristics

40,900

41,100

23,300

23,100

5,100

126,500

120,000

50,000

100,000

150,000

200,000

250,000

2007

2008

Actual Hedges & Open Position

ComEd Swap

IL Auction

PECO Load

189,300

190,700

140,700

138,100

31,600

33,800

18,400

17,400

50,000

100,000

150,000

200,000

250,000

2007

2008

Forward / Spot Purchases

Fossil & Hydro

Nuclear

189,300

190,700

Expected Total Supply (GWh)

Expected Total Sales (GWh)

The value of our portfolio resides in our nuclear fleet

Hedging Targets

Target Ranges

50% -

70%

70% -

90%

98%

Above the

range*

Current Position

Upper end

of range

Midpoint of

range

(1) Percent financially hedged is our estimate of the gross margin that is not at risk due to a market price drop and assuming normal generation operating conditions.

The formula

is:

gross

margin

the

5th

percentile

expected

gross

margin.

Power Team employs commodity hedging

strategies to optimize Exelon Generation’s

earnings:

Maintain length for opportunistic sales

Use cross commodity option strategies to

enhance hedge activities

Time hedging around view of market

fundamentals

Supplement portfolio with load following

products

Use physical and financial fuel products to

manage variability in fossil generation output

Financial Hedging Range

(1)

* Due to ComEd financial swap

Flexibility in our targeted financial hedge ranges allows us to be opportunistic while

mitigating downside risk

Prompt Year

(2008)

Second Year

(2009)

Third Year

(2010)

Financial Swap Agreement

3,000

$53.48

January 1, 2013 -

May 31, 2013

3,000

$52.37

January 1, 2012 -

December 31, 2012

3,000

$51.26

January 1, 2011 -

December 31, 2011

3,000

$50.15

June 1, 2010 -

December 31, 2010

2,000

$50.15

January 1, 2010 -

May 31, 2010

2,000

$49.04

June 1, 2009 -

December 31, 2009

1,000

$49.04

January 1, 2009 -

May 31, 2009

1,000

$47.93

June 1, 2008 -

December 31, 2008

Notional Quantity (MW)

Fixed Price ($/MWH)

Portion of Term

•

Market-based contract for ATC baseload energy only

–

Does not include capacity, ancillary services or congestion

•

Preserves competitive markets

•

Fits with Exelon Generation’s hedging policy and strategy

•

Small portion of Exelon Generation’s supply

Reliability Pricing Model Auction

40.80

197.67

111.92

148.80

102.04

191.32

Rest of Market

Eastern MAAC

MAAC + APS

2007/2008

2008/2009

2009/2010

1,500 MW

N/A

MAAC + APS

(7)

9,750 -

9,950 MW

(3)

9,500 MW

9,550 -

9,850 MW

(3)

9,500 MW

9,500 -

9,800 MW

(3)

9,500 MW

Eastern MAAC

4,750 -

4,950 MW

(6)

12,700 MW

6,600 -

6,800 MW

14,500 MW

(5)

6,600 -

6,800 MW

16,000 MW

(4)

Rest of Market

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

2009 / 2010

2008 / 2009

2007 / 2008

Exelon Generation

Participation

within

PJM

Reliability

Pricing

Model

(1)

(6) In 09/10, obligation is reduced due to roll-off of part of ComEd auction load obligation in May 2009.

(3) EMAAC obligation consists of load from PECO and BGS commitments.

(7) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.

(5) 08/09 Capacity supply decreased due to roll-off of several purchase power agreements (PPAs).

(4) Removing State Line from the supply in October 2007 reduces this by 515 MW.

(2) All

capacity

values

are

installed

capacity

terms

(summer

ratings).

(1) All values are approximate and not inclusive of wholesale transactions.

PJM RPM Auction Results ($/MW-day)

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Carbon Value

Midwest

•

~90,000 GWhs in Midwest nuclear

portfolio

•

~55% of time coal on the margin

•

~40% of time gas on the margin

Mid-Atlantic

•

~50,000 GWhs in Mid-Atlantic

nuclear portfolio

•

~45% of time coal on the margin

•

~50% of time gas on the margin

Assumes Open Position

(1)

Carbon Credit ($/Tonne)

(1) Carbon sensitivity excludes ComEd SWAP and upside of Kincaid/Elwood due to contract expiration in 2012. Assumes below $45/tonne carbon cost, no carbon

reduction technology (e.g., sequestration) is economical.

(2) As of 10/31/07.

(3) The

EIA

Carbon

Stabilization

Case

(Case

dated

March

2006,

EIA

report

number

SR/OIAF/2006-1.

(4) Low

Carbon

Economy

Act

initial

“Technology

Accelerator

Payment”

(TAP)

price

2012.

Allowance

price

increases

above

the

rate

inflation

thereafter.

Carbon Value

Climate change legislation is expected to drive substantial gross margin expansion

at Exelon Generation

Europe Carbon Trading

2012: $35.50/tonne

(2)

Bingaman-Specter

(4)

2012: $12/tonne

EIA Carbon Case

(3)

2010: $31/tonne

Lieberman-Warner

Possible $20 to $40/tonne

Required Break-Even Cost

by Technology –

Illustrative Assumptions

Combined Cycle

Gas Turbine

(CCGT)

Integrated

Gasification

Combined Cycle

(IGCC)

Coal

(Pulverized)

Nuclear

(Dual-Unit)

Assumption

Construction time (years)

Permitting time (years)

CO2 -

$/tonne

2008 Market fuel cost

(held flat for fossil fuels)

Fuel type

Range of all-in capital cost ($/kw)

(overnight, without interest during construction)

Capacity net MWe

N/A

$7.68/ MMBtu

$2.22/ MMBtu

$2.22/MMBtu

$10.00/MWh

Gas

Coal

Nuclear

800 –

1,200

2,800 –

3,000

2,100 –

2,400

2,800 –

3,400

500

3,000

Global Assumptions:

In 2008$; 40-year life assumed; 9-12% after-tax weighted avg. cost of capital; 32% effective tax rate; ~1%-3% cost escalation.

Fuel assumptions are PRB (coal) and Houston Ship Channel (gas).

Exelon Nuclear Fleet Overview

2011

42.6% Exelon, 56.4 %

PSEG

2016, 2020

969

(1)

PWR

Salem, NJ

Life of plant capacity

100% AmerGen

2014; renewal to

be filed 2008

837

B&W

PWR

TMI-1, PA

Dry cask

100% AmerGen

2009; renewal filed

2005

625

BWR

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

1135

(1)

BWR

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

1303

(1)

BWR

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

871, 871

BWR

Dresden, IL

2012

100%

2022, 2023

1138, 1150

BWR

LaSalle, IL

Dry cask in process

100%

2024, 2029

1151, 1151

BWR

Limerick, PA

Re-rack completed

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

Vendor

BWR

PWR

Type

Units

100% AmerGen

2026

1048

Clinton, IL

100%

2024, 2026

1183, 1153

Byron, IL

100%

2026, 2027

1194, 1166

Braidwood, IL

Ownership

License

Expiration /

Status

Net Annual

Mean Rating

Plant, Location

Fleet also includes 4 shutdown units: Peach Bottom 1, Dresden 1, Zion 1 & 2.

(1) Capacity based on ownership interest.

Energy Policy Act –

Nuclear Incentives

$18 per MWh, 8 year PTC for

first 6,000 MWe of new capacity

Cap of $125M per 1,000 MWe of

capacity per year

Protects against a decrease in

market prices and revenues

earned

Benefit will be allocated/ prorated

among those who:

•

File COL by year-end 2008

•

Begin construction (first

safety-related concrete) by

1/1/2014

•

Place unit into service by

1/1/2021

Production Tax Credit (PTC)

Results in ability to obtain

non-recourse project

financing

Up to 80% of the project

cost, repayment within 30

years or 90% of the project

life

Timing of application subject

to DOE solicitations for

projects

Loan guarantee volume

dependent upon

congressional appropriations

action

Government Loan

Guarantee

“Insurance”

protecting against

regulatory delays in

commissioning a completed

plant

•

First two reactors would

receive immediate “standby

interest coverage”

including

replacement power up to

$500M

•

The next four reactors

would be covered up to

$250M after six months of

delay

Regulatory Delay “Backstop”

Energy Policy

Act

provides

financial

incentives

and

reduced

risk

way

production tax credits and loan guarantees

Announced Nuclear Projects

Announced intent

Greenfield

San Joaquin Valley CA

EPR

Fresno Nuclear Energy

Announced intent

Greenfield

Bruneau

EPR

Alternative Energy Hldings

Letter of intent

Operating

Turkey Pt FL

TBD

FPL

Letter of intent

Operating

Susquehanna PA

EPR

PPL

Letter of intent

Operating

Fermi MI

TBD

DTE Energy

Letter of intent

Greenfield

Victoria or Matagorda TX

TBD

Exelon

Letter of intent

Operating

Comanche Peak TX

APWR

TXU

Letter of intent

Operating

Callaway MO

EPR

Unistar/Ameren

Letter of intent

Operating

Nine Mile Pt NY

EPR

Unistar

COL submitted Sept 2007

Operating

South Texas Project TX

ABWR

NRG Energy

Letter of intent

Greenfield

Amarillo TX

EPR

Amarillo Power

COL Jan 2008

Operating

Harris NC

AP1000

Progress

COL 2008

Operating

Vogtle

AP1000

Southern

COL May 2008

Operating

River Bend LA

ESBWR

Entergy

Letter of intent

Characterized

Lee SC

AP1000

Duke

COL July 2008

Greenfield

Levy Co. FL

AP1000

Progress

Letter of intent

Operating

Summer SC

AP1000

South Carolina E&G

ESP approved; COL February 2008

Operating

Grand Gulf MS

ESBWR

Entergy/NuStart

COL submitted Oct 2007. Reference plant for AP1000

Characterized

Bellefonte AL

AP1000

TVA/NuStart

Reference plant for ESBWR COL application; planned for 2007

Operating

North Anna VA

ESBWR

Dominion

Partial COL submitted; remainder expected in 2007

Operating

Calvert Cliffs MD

EPR

Unistar

Status

Type of site

Site

Technology

Units

Applicant

21 projects totaling ~39,000 MWs have been announced

Advanced Nuclear Designs –

U.S. Market

Luminant

(formerly TXU)

Will apply for design

certification in 2008

1700 MW

Mitsubishi

APWR

(Advanced PWR)

NRG

Evolutionary improvement

from current BWR. Design

certification in 1997. In

operation in Japan since 1996.

1350 MW

GE-Hitachi

ABWR

(Advanced BWR)

UniStar

PPL

Ameren

Alternate Energy Holdings

Design certification to be filed

1Q 2008. AREVA in UniStar

joint venture with Constellation

to deploy EPR in US. Under

construction in Finland, France

1600 MW

AREVA

EPR

(Evolutionary PWR)

TVA/NuStart

SCE&G

Progress

Duke

Southern

PWR, passive safety features,

Design certification received

December 2005

1150 MW

Westinghouse

AP1000

(Advanced Passive

1000)

Dominion

Entergy/NuStart at Grand Gulf

Entergy at River Bend

Passive safety features,

simplified from ABWR design.

NRC design certification

expected 2010

1500 MW

GE-Hitachi

ESBWR

(Economic

Simplified Boiling

Water Reactor)

Selected in US by:

Status

Capacity

Vendor

Reactor

Sources: World Nuclear Association; Nuclear Fuel Cycle Monitor,

September 17, 2007.

100

120

140

160

Uranium Price Volatility

100

120

140

160

Spring 2003

McArthur River

flood

December 2003

GNSS/Tenex

termination;

ConverDyn

UF6 release

and shutdown

Early 2004

ERA / Ranger

water problems

Early 2006

First Cigar Lake flood;

Cyclone Monica halts

ERA / Ranger

operations for

approximately two

weeks

October 2006

Second Cigar

Lake flood

March 2007

ERA / Ranger flooding

(cyclone George)

Long-term Uranium Price Trend

Seven-Month Uranium Price Trend

Long-term equilibrium price expected to be $40-$60/lb

Current Market Prices

2004, 2005 and 2006 are actual settled prices.

Real Time LMP (Locational Marginal Price).

Next day over-the-counter market.

Average NYMEX settled prices.

2007 information is a combination of actual prices through 10/31/07 and market prices for the balance of the year.

2008 and 2009 are forward market prices as of 10/31/07.

PRICES (as of October 31, 2007)

Units

2004

2005

2006

2007

2008

2009

PJM West-Hub ATC

($/MWh)

42.35

60.92

51.07

59.56

65.94

68.01

PJM NI-Hub ATC

($/MWh)

30.15

46.39

41.42

45.77

50.17

51.55

NEPOOL MASS Hub ATC

($/MWh)

52.13

76.65

59.68

65.61

77.03

78.98

ERCOT North On-Peak

($/MWh)

49.53

76.90

60.87

60.08

74.76

78.95

Henry Hub Natural Gas

($/MMBTU)

5.85

8.85

6.74

7.07

8.48

8.69

WTI Crude Oil

($/bbl)

41.48

56.62

66.38

69.67

88.79

83.19

PRB 8800

($/Ton)

5.97

8.06

13.04

9.70

11.50

12.30

NAPP 3.0

($/Ton)

60.25

52.42

43.87

47.97

54.50

53.50

ATC HEAT RATES (as of October 31, 2007)

PJM West-Hub / Tetco

(MMBTU/MWh)

6.40

6.30

6.98

7.56

7.01

7.04

PJM NI-Hub / Chicago City Gate

(MMBTU/MWh)

5.52

6.32

6.55

5.94

5.91

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.53

8.21

8.28

7.73

7.83

7.92

7.1

7.2

7.3

7.4

7.5

7.6

7.7

7.8

7.9

8.1

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

7.4

7.6

7.8

8.2

8.4

8.6

8.8

9.2

9.4

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

Market Price Snapshot

As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Natural Gas

PJM-West and NI-Hub On-Peak Forward Prices

PJM-West On-Peak Implied Heat Rate

NI-Hub On-Peak Implied Heat Rate

8.84

9.04

9.24

9.44

9.64

9.84

10.04

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

2008

2009

2008

2008 PJM-West

2009 PJM-West

2009 Ni-Hub

2008 Ni-Hub

2008

2009

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

Market Price Snapshot

As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

PJM-West ATC Forward Prices

2008

2009

PJM-West Wrap Forward Prices

2008

2009

NI-Hub ATC Forward Prices

NI-Hub Wrap Forward Prices

2009

2008

2009

2008

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

7.7

7.8

7.9

8.1

8.2

8.3

8.4

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

7.5

8.5

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

9/2/07

10/2/07

Market Price Snapshot

2008

2009

2008

2009

As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

2008

2009

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North ATC Forward Prices

ERCOT North ATC v. Houston Ship Channel

Implied Heat Rate

ERCOT North Wrap Forward Prices

Recognized Environmental Leadership

Named

the

2006/2007

and

2007/2008

Dow

Jones

Sustainability North America Index

Named to Climate Disclosure Leadership Index of the Carbon

Disclosure Project in 2005, 2006 and 2007

Signatory to the Global Roundtable on Climate Change and the

Ceres/Investor Network on Climate Risk statements

Member of the United States Climate Action Partnership (USCAP)

Corporate headquarters awarded Leadership in Energy and

Environmental Design (LEED

) Platinum Commercial Interiors

certification by the U.S. Green Building Council

Exelon’s Climate Actions

Achieved SF6 leak rate of under 10% for 2006

Provides customer-based energy-efficiency

programs (compact fluorescent light bulbs, demand

response programs) –

will ramp up to one of the

country’s leading programs in four years

ComEd is the largest private user of biodiesel in

Illinois thereby helping to create a healthy

biodiesel market

First utility in PA to file to meet Tier 1

requirements under Alternative Energy Portfolio

Standards (AEPS)

Achieved SF6 leak rate of under 10% for 2006

Supporting implementation of smart meters

system-wide and time-of-use programs

Nation’s largest low-carbon generation

Retired older, inefficient plant

Invested in landfill gas power generation

expansion

Committed to going beyond world-class nuclear performance and compliance with

regulations, Exelon is taking voluntary action to address climate change

Largest marketer of wind power east of the

Mississippi River

Signed 20-year deal to purchase output from

largest solar photovoltaic installation in PJM

region

Exelon and Federal Climate

Change Legislation

Actively involved in the climate debate in Washington, D.C.

Lobbying in favor of enacting legislation that is national,

mandatory

and economy-wide

Favors a cap-and-trade system over a carbon tax

Believes that any allocation scheme should include allowances

for

distribution

companies

help

offset

the

cost

carbon

for

the

end-user

limit

near-term

economic

impacts,

supports

“safety

valve”

for

cost of carbon that needs to increase over time

Reduction Goals

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

Historical U.S. emissions (EPA, 1990-2005)

Business-as-usual projection (AEO2007)

Sanders-Boxer / Waxman

Kerry-Snowe

McCain-Lieberman

Bingaman-Specter assuming "safety valve" not hit

Lieberman-Warner draft principles

Olver-Gilchrest

Bingaman-Specter assumes multiple low-carbon

policies, including:

•

Car & light truck fuel economy of 41 mpg by 2027

•

Federal RPS of 15% by 2020

•

Optimistic assumptions about new technologies

coming online

Under these policies, the safety valve is not triggered.

Without these policies the safety valve is expected to

be reached in the early years and the target will be

exceeded. The program ends in 2030 unless the

President sets additional long-term targets.

Comparison of Economy-wide Cap-and-Trade Emissions Targets

Includes Legislation Introduced in the 110th Congress as of September 2007

CO2 Reductions Demand Multiple

Generation Technologies

Source: Electric Power Research Institute

EIA Base Case 2007

The technical potential exists

for the U.S. electricity sector

to significantly reduce CO2

emissions over the coming

decades

No one technology will be a

silver bullet –

a portfolio of

technologies will be needed

Much of the needed

technology is not available

yet –

substantial R&D and

demonstration are required

To stabilize emissions at 1990 levels, multiple technologies and

intensive R&D will be required

500

1000

1500

2000

2500

3000

3500

1990

1995

2000

2005

2010

2015

2020

2025

2030

Advanced Coal Generation

Distributed Energy Resources

Plug-In Hybrid Electric Vehicles

Carbon Capture & Storage

Nuclear Generation

Renewables

Efficiency

Technology

Key Climate Bills

Several bills and white papers and drafts are gaining support in

Washington:

•

Bingaman-Specter (S. 1766, the Low Carbon Economy Act of 2007)

Economy-wide: All major GHG producing sectors

Point of regulation: Oil and natural gas refineries and coal-fired generators

Increasing auction of allowances

Allowance allocations include: 9% to states, 53% to industry declining 2% per year starting in 2017, 5% set

aside for agricultural

Safety Valve: Price of allowances capped at $12/tonne of CO2 (“technology accelerator payment”) starting

in 2012 and increasing 5% per year above inflation rate

•

Lieberman-Warner (S. 2191, America’s Climate Security Act of 2007)

Major vehicle for action in the U.S. Senate Environment and Public Works Committee

Economy-wide: All major GHG producing sectors

Point of regulation: Electric power sector-

large generators; Industrial sector: Large facilities emitting

than

10,000

tonnes

per

year

Increasing auction of allowances

Allowance allocations include: 4% to states, 19% to power plants

(transitions to zero in 2034), 20% to

industry, 10% to electricity load-serving entities

Creates Carbon Market Efficiency Board to allow for borrowing of

future year allowances with payback;

limited authority to oversee market

•

Dingell-Boucher White Paper

Reduce emissions by 60% to 80% by 2050

Best achieved by a cap-and-trade system

Projected 2007 Key Credit Measures

62% –

52%

53%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 49%

12% –

20%

18%

17%

FFO / Debt

2.5x –

3.5x

4.4x

FFO / Interest

PECO:

52% –

42%

58%

61%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 43%

25% –

40%

12%

10%

FFO / Debt

3.5x –

5.5x

BBB

3.0x

FFO / Interest

ComEd:

52% –

42%

40%

58%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 38%

25% –

40%

79%

41%

FFO / Debt

3.5x –

5.5x

BBB+

12.4x

6.5x

FFO / Interest

Generation:

63%

28%

5.6x

Without PPA &

Pension / OPEB

55% –

45%

70%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 54%

20% –

30%

22%

FFO / Debt

3.2x –

4.5x

BBB

4.6x

FFO / Interest

Exelon Cons:

“BBB”

Target

Range

(3)

S&P Credit

Ratings

(2)

With PPA &

Pension / OPEB

(1)

Notes: Projected credit measures reflect impact of Illinois electric rates and policy settlement. Exelon, ComEd and PECO metrics exclude securitization debt. See following slide for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

GAAP.

(1)

Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits

(OPEB) obligations, and capital adequacy for energy trading. Debt is imputed for estimated pension and OPEB obligations by operating company.

(2)

Current senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO as of 10/31/07.

(3)

Based on S&P Business Profiles: 7 for Exelon, 8 for Generation and ComEd, and 4 for PECO.

Exelon’s balance sheet is strong

FFO Calculation and Ratios (updated)

FFO Calculation

= FFO

PECO Transition Bond Principal Paydown

+ Gain on

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

+ Depreciation,

amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

= Adjusted Interest

+ 7% of Present Value (PV) of Operating Leases

+ Interest on imputed debt related to PV of Purchased Power Agreements

(PPA), unfunded Pension and Other Postretirement Benefits (OPEB)

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

applicable

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

Adjusted Interest

FFO+ Adjusted Interest

FFO Interest Coverage

+ Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

+ 100%

Purchased

Power

Agreements

(2)

+ Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(1)

FFO Debt Coverage

= Total Rating Agency Capitalization

+ Off-balance

sheet

debt

equivalents

(2)

Goodwill

Total Adjusted Capitalization

= Rating Agency Debt

+ ComEd Transition Bond Principal

Balance

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

Rating Agency Capitalization

Rating Agency Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Total Adjusted Capitalization

Adjusted Book Debt

Debt to Total Cap

Note: Updated to reflect revised S&P guidelines and company forecast. FFO and Debt related to non-recourse debt are excluded from the calculations.

(1) Use current year-end adjusted debt balance.

(2) Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital

Adequacy for Energy Trading.

(3) Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions.

GAAP EPS Reconciliation 2000-2002

2000 GAAP Reported EPS

$1.44

Change in common shares

(0.53)

Extraordinary items

(0.04)

Cumulative effect of accounting change

Unicom pre-merger results

0.79

Merger-related costs

0.34

Pro forma merger accounting adjustments

(0.07)

2000 Adjusted (non-GAAP) Operating EPS

$1.93

2001 GAAP Reported EPS

$2.21

Cumulative effect of adopting SFAS No. 133

(0.02)

Employee severance costs

0.05

Litigation reserves

0.01

Net loss on investments

0.01

CTC prepayment

(0.01)

Wholesale rate settlement

(0.01)

Settlement of transition bond swap

2001 Adjusted (non-GAAP) Operating EPS

$2.24

2002 GAAP Reported EPS

$2.22

Cumulative effect of adopting SFAS No. 141 and No. 142

0.35

Gain on sale of investment in AT&T Wireless

(0.18)

Employee severance costs

0.02

2002 Adjusted (non-GAAP) Operating EPS

$2.41

2004 GAAP Reported EPS

$2.78

Charges associated with debt repurchases

0.12

Investments in synthetic fuel-producing facilities

(0.10)

Employee severance costs

0.07

Cumulative effect of adopting FIN 46-R

(0.05)

Settlement associated with the storage of spent nuclear fuel

(0.04)

Boston Generating 2004 impact

(0.03)

Charges associated with investment in Sithe Energies, Inc.

0.02

Charges related to the now terminated merger with PSEG

0.01

2004 Adjusted (non-GAAP) Operating EPS

$2.78

2003 GAAP Reported EPS

$1.38

Boston Generating impairment

0.87

Charges associated with investment in Sithe Energies, Inc.

0.27

Employee severance costs

0.24

Cumulative effect of adopting SFAS No. 143

(0.17)

Property tax accrual reductions

(0.07)

Enterprises’

Services goodwill impairment

0.03

Enterprises’

impairments due to anticipated sale

0.03

March 3 ComEd Settlement Agreement

0.03

2003 Adjusted (non-GAAP) Operating EPS

$2.61

GAAP EPS Reconciliation 2003-2005

2005 GAAP Reported EPS

$1.36

Investments in synthetic fuel-producing facilities

(0.10)

Charges related to the now terminated merger with PSEG

0.03

Impairment of ComEd’s goodwill

1.78

2005 financial impact of Generation’s investment in Sithe

(0.03)

Cumulative effect of adopting FIN 47

2005 Adjusted (non-GAAP) Operating EPS

0.06

$3.10

GAAP Earnings Reconciliation

Year Ended December 31, 2006

776

Impairment of ComEd’s goodwill

(52)

Recovery of debt costs at ComEd

(89)

Nuclear decommissioning obligation reduction

(95)

Recovery of severance costs at ComEd

$(83)

$(144)

Other

$2,175

(58)

$1,592

Exelon

$455

$441

PECO

$528

$(112)

ComEd

ExGen

(in millions)

Severance charges

Charges related to now terminated merger with PSEG

$1,275

2006 Adjusted (non-GAAP) Operating Earnings (Loss)

Impairment of Generation’s investments in TEG and TEP

Investments in synthetic fuel-producing facilities

(61)

Mark-to-market adjustments from economic hedging activities

$1,407

2006 GAAP Reported Earnings (Loss)

Note: Amounts may not add due to rounding.

GAAP EPS Reconciliation

Year Ended December 31, 2006

$3.22

(0.11)

0.67

$0.78

$1.88

2006 Adjusted (non-GAAP) Operating EPS

$2.35

(0.21)

0.65

(0.17)

$2.08

2006 GAAP Reported EPS

0.05

0.04

Other

(1)

(0.14)

1.15

(0.08)

0.01

ComEd

(1)

(0.13)

0.01

(0.09)

ExGen

(1)

0.01

PECO

(1)

Exelon

1.15

Impairment of ComEd’s goodwill

(0.08)

Recovery of debt costs at ComEd

0.03

Severance charges

(0.13)

Nuclear decommissioning obligation reduction

(0.14)

Recovery of severance costs at ComEd

0.09

Charges related to now terminated merger with PSEG

0.04

Investments in synthetic fuel-producing facilities

(0.09)

Mark-to-market adjustments from economic hedging activities

Note: Amounts may not add due to rounding.

(1) Amounts shown per Exelon share and represent contributions to Exelon's EPS.

GAAP EPS Reconciliation

Nine Months Ended September 30, 2006

$2.50

Q3 2006 YTD Adjusted (non-GAAP) Operating EPS

(0.08)

Recovery of debt costs at ComEd

1.15

Impairment of ComEd's goodwill

0.02

Severance charges

(0.13)

Nuclear decommissioning obligation reduction

0.09

Charges related to now terminated merger with PSEG

0.08

Investments in synthetic fuel-producing facilities

(0.11)

Mark-to-market adjustments from economic hedging activities

$1.48

Q3 2006 YTD GAAP Reported EPS

GAAP EPS Reconciliation

Nine Months Ended September 30, 2007

$3.31

Q3 2007 YTD Adjusted (non-GAAP) Operating EPS

(0.01)

Sale of Generation's investments in TEG and TEP

0.14

2007 Illinois electric rate settlement

(0.01)

Settlement of a tax matter at Generation related to Sithe

(0.03)

Nuclear decommissioning obligation reduction

(0.10)

Investments in synthetic fuel-producing facilities

0.12

Mark-to-market adjustments from economic hedging activities

$3.20

Q3 2007 YTD GAAP Reported EPS

2007/2008 Earnings Outlook

Exelon’s outlook for 2007/2008 adjusted (non-GAAP) operating

earnings excludes the earnings impacts of the following:

•

mark-to-market adjustments from economic hedging activities

•

significant impairments of intangible assets, including goodwill

•

significant changes in decommissioning obligation estimates

•

investments in synthetic fuel-producing facilities

•

costs associated with the Illinois electric rate settlement, including

ComEd’s previously announced customer rate relief programs

•

gains or losses on the State Line Energy, L.L.C. and Tenaska Georgia

Partners, LP transactions (2007 only)

•

other unusual items which the Company is unable to forecast

•

significant future changes to GAAP

Both our operating earnings and GAAP earnings guidance are

based on the assumption of normal weather

Net income (loss)

+/-

Cumulative effect of changes in accounting principle

+/-

Discontinued operations

+/-

Minority interest

+ Income taxes

Income (loss) from continuing operations before income taxes and

minority

interest

+ Interest expense

+ Interest expense to affiliates

Interest income from affiliates

+ Depreciation and amortization

Earnings before interest, taxes, depreciation and amortization (EBITDA)

Reconciliation of Net Income to

EBITDA

Exelon Investor Relations Contacts

Inquiries concerning this presentation should

be directed to:

Exelon Investor Relations

10 South Dearborn Street

Chicago, Illinois 60603

312-394-2345

312-394-4082 (Fax)

For copies of other presentations,

annual/quarterly reports, or to be added to our

email distribution list please contact:

Felicia McGowan, Executive Admin Coordinator

312-394-4069

Felicia.McGowan@ExelonCorp.com

Investor Relations Contacts:

Chaka Patterson, Vice President

312-394-7234

Chaka.Patterson@ExelonCorp.com

JaCee Burnes, Director

312-394-2948

JaCee.Burnes@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com

Len Epelbaum, Principal Analyst

312-394-7356

Len.Epelbaum@ExelonCorp.com