Investor Handout

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

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

Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I,

Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings

with the Securities and Exchange Commission (SEC) 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.

The Exelon Story –

Value Driven

•

Premier U.S. nuclear generator uniquely positioned to capture

market opportunities through operational and commercial excellence

•

Primary source of Exelon’s value going forward

•

~9% annual operating EPS growth since inception

•

Continued strong growth trend through 2011

•

Strong balance sheet and financial discipline

•

New value return policy

•

Experienced management team

•

Predictable source of earnings through transition period;

preparing for 2011

•

Completed the transition to a “wires-only”

business with a

regulatory recovery plan in place

’06

Earnings

(1)

$1,275M

’07E

Earnings

(2)

$2,280 -

$2,420M

’06

EPS

(1)

$1.88

’07

EPS

Guidance

(2)

$3.40 -

$3.60

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)

: $2.7

$2.9B

‘07 EPS Guidance

(2)

: $4.00 -

$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 8/10/07.

Pennsylvania

Utility

Illinois

Utility

’06

Earnings

(1)

$528M

$455M

’07E

Earnings

(2)

$65 -

$125M

$400 -

$420M

’06

EPS

(1)

$0.78

$0.67

’07

EPS

Guidance

(2)

$0.10 -

$0.20

$0.60 -

$0.65

Total

Debt

(3)

$4.6B

$4.2B

Credit

Ratings

(4)

BBB-

A-

Multi-Regional, Diverse Company

Note: Megawatts based on Exelon

Generation’s ownership as of 12/31/06.

Midwest Capacity

Owned:

11,389 MW

Contracted:

4,791 MW

Total:

16,180 MW

ERCOT/South Capacity

Owned:

2,299 MW

Contracted:

2,900 MW

Total:

5,199 MW

New England Capacity

Owned:

622MW

Mid-Atlantic Capacity

Owned:

11,233MW

Total Capacity

Owned:

25,543 MW

Contracted:

7,691 MW

Total:

33,234 MW

Electricity Customers:

1.6M

Gas Customers:

0.5M

Electricity Customers: 3.8M

Generating Plants %MW

Nuclear

Hydro

Coal/Oil/Gas Base-load

Intermediate

Peaker

$3.22

$3.10

$2.78

$2.61

$2.41

$2.24

$1.93

2000

2001

2002

2003

2004

2005

2006

Q2 2007 Highlights

•

Strong financial and operating results

Higher wholesale margins on energy sales

Favorable weather conditions

Partially offset by lower nuclear output reflecting more

refueling outage days, lower net income at ComEd, and

higher O&M and D&A expense across Exelon

•

ComEd and Generation agreed to a settlement on electric

rates and policy in Illinois

•

FERC issued conditional order in ComEd’s transmission rate

case

Q2 2007 earnings were primarily driven by higher energy margins at Generation and

the end of ComEd’s regulatory transition period

(1) Excludes $0.02 per share unfavorable impact versus normal weather in Q2 2006 and $0.02 per share favorable impact versus normal weather in Q2 2007.

Financial Performance

$1.01

$1.03

Q2 2007

$0.87

Weather Normalized

(1)

$4.00

$4.30

$0.85

Operating

Adjusted (non-GAAP) Operating EPS

2007

Guidance

Q2 2006

Adjusted (non-GAAP) Operating EPS

2006

2007

$3.22

$0.78

$0.67

$1.88

$0.60 -

$0.65

$3.40 -

$3.60

$4.00 -

$4.30

$0.10 -

$0.20

2006 Operating

EPS Actual

2007 Operating

EPS Guidance

(1)

$ / Share

HoldCo/Other

ExGen

PECO

ComEd

$0.60 -

$0.63

Note: See

“Key

Assumptions”

slide

Appendix.

(1)

Earnings Guidance.

(2)

GAAP Guidance revised on 7/25/07 from $4.10 -

$4.40 per share.

2007 –

2011

Exelon Generation

ComEd

PECO

Exelon expects to see robust earnings growth over next five years driven by Exelon

Generation and ComEd’s recovery

Operating EPS

(1)

: $4.00 -

$4.30 per share

GAAP EPS

(2)

$3.70 -

$4.00 per share

2007 Operating Earnings Guidance

ComEd regulatory recovery plan

Improving market fundamentals

Gas prices

Capacity values

Heat rates

End of IL and PA transition periods

Carbon regulation

Earnings Drivers

$10

$12

$14

20%

25%

30%

35%

2011 Balance Sheet Capacity

(Illustrative)

Exelon expects to create substantial incremental balance sheet capacity over the next

five years, based on planning assumptions

Potential Uses of

Balance Sheet Capacity

Acquisitions or other

growth opportunities

Future unfunded liabilities

Buffer against potentially lower

commodity prices

Share repurchases or other

value return options

Note: Data has not been updated since December 12, 2006 Investor Conference.

(1) Available

Cash

Flow

from

Operations

CapEx

Dividends

+/-

Net

Financings.

Cash

Flow

from

Operations

Net

cash

flows

provided

operating

activities

less

net

cash flows used in investing activities other than capital expenditures. Net Financing (excluding Dividends) = Net cash flows used in financing activities excluding dividends

paid on common stock. Assumes annualized dividend of $1.76 per share in 2007, growing 5% annually; actual amounts may vary, subject to board approval.

(2) Assumes regulatory recovery plan at ComEd.

(3)

See

“FFO

Calculation

and

Ratios”

definitions

slide.

Adjusted

FFO

Debt

includes:

debt

equivalents

for

purchased

power

agreements,

unfunded

pension

and

other

postretirement

benefits

obligations,

capital

adequacy

for

energy

trading,

and

imputed

interest.

S&P “BBB”

Target Range

Unadjusted FFO / Debt

(2)

Adjusted FFO / Debt

(2) (3)

2011 FFO / Debt (Forecasted)

(3)

2006 EPS

RNF

O&M

Depreciation

Interest Exp

Other

2007 EPS Guidance

Exelon Generation 2007

Operating EPS

Earnings growth is driven by the expiration of the below-market ComEd PPA, favorable

market conditions, and a contractual price increase in the PECO PPA

2006 Actual

2007 Guidance

$1.88

$1,275M

$1.73

$(0.13)

$0.07

$3.40 -

$3.60

$2,280M -

$2,420M

RNF

O&M

Other

Note: See “Key Assumptions”

slide in Appendix.

Key Items:

Inflation -

($0.06)

Pension & benefits -

($0.04)

Texas Construction & Operating

License -

($0.03)

Nuclear security -

($0.02)

Fewer

refueling

outages

$0.03

$25

+/-

500 Btu/KWh ATC

Heat Rate

$10

+/-

$10/MW-Day

Capacity

$25

+/-

$1/mmBtu Gas

2007

Market Sensitivities

As of 12/31/06

(After-Tax $M)

Depreciation

$(0.02)

Interest

Expense

$(0.02)

Exelon Generation Operating

Earnings Drivers: Next Five Years

Exelon Generation is poised for earnings growth over the next five years driven by the

end of the IL and PA transition periods and its unique competitive position

2007 Guidance

Note: See

“Key

Assumptions”

slide

Appendix.

(1) Differences in sensitivities are largely due to differences in the amount hedged in 2007 vs. 2011.

$2,280M -

$2,420M

$660

N/A

+ $10/Ton Carbon

$340

$25

+/-

500 Btu/KWh ATC Heat rate

$50

$10

+/-

$10/MW-Day Capacity

$390

$25

+/-

$1/mmBtu Gas

2011

2007

Market Sensitivities

(1)

As of 12/31/06

(After-Tax $M)

Exelon Generation’s

Competitive Position

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

Complementary and flexible fossil

and hydro fleet

Improving power market

fundamentals (heat rates and

capacity values)

Potential carbon restrictions

Valuing Exelon Generation

$ Millions

Revenue Net Fuel

(2)

O&M and

Other Expenses

EBITDA

(3)

–

Hedged

EBITDA

(3)

–

Un-Hedged

Hedged –

2007

Un-Hedged –

2007

(1)

Mid-

Atlantic

$2,650

$6,700

Midwest

$4,050

($2,600)

$4,100

$4,700

Un-hedged (“Open”) EBITDA plus upside from unique competitive position drives

Exelon Generation’s value

(1)

Exelon Generation’s Un-hedged EBITDA assumes that the PECO load is priced at current market prices and removes the impact of

“in-the-money”

hedges (prices as of 9/14/06).

(2)

Exelon Generation’s estimated total Revenue Net Fuel of $6,700M reflects the Midwest, Mid-Atlantic, South and Other.

(3)

Includes Nuclear Fuel Amortization; refer to last page of Appendix for a reconciliation of Net Income to EBITDA.

Nuclear Performance –

Fuel Costs

Uranium market prices have increased, but

Exelon is managing its portfolio

•

Reduced uranium demand by 25%

•

Contracting strategy protects us and ensures

we are significantly below current spot market

prices through 2011

•

Uranium is small component of total

production cost

•

Expect long-term market price to decrease

due to increasing supply; stabilize based on

cost of production

Exelon Nuclear is managing fuel costs

Components of Exelon Nuclear's Fuel Cost in 2006

Uranium

21%

Conversion

Fabrication

16%

Tax/Interest

Nuclear Waste

Fund

18%

Enrichment

40%

Exelon Projected Uranium Portfolio

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2005

2006

2007

2008

2009

2010

2011

Contracted Supply

2003 Demand Projection

Current Demand Projection

Exelon Uranium Cost vs. Market

100

2007

2008

2009

2010

2011

Exelon average re-load price

Projected market price

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

Significantly improves EPS

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

Need clarification of

implementation specifics

Availability of funds to

nuclear projects at risk given

latest program guidelines

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 by way of production tax credits and

loan guarantees

% Hedged

Low End of Profit

High End of Profit

Portfolio Management

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

mitigating downside risk

90% -

98%

Prompt Year

(2008)

Target Financial Hedge

(1)

Range

50% -

70%

70% -

90%

Third Year

(2010)

Second Year

(2009)

(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

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

The transition to competitive power procurement allows Exelon Generation to

capture the full market value of its generation portfolio and places more

emphasis on hedging and risk management

37,500

Fossil & Hydro

139,750

Nuclear

184,550

Total

7,300

Forward & Spot Purchases

2007 Expected Total Supply (GWh)

PECO PPA

22%

Other Midwest

Sales

42%

Other Mid-

Atlantic Sales

13%

IL Auction

15%

Other South

Sales

Portfolio Characteristics

2007 Expected Total Sales (GWh)

Fundamentals

The overbuild is ending in the

Eastern Interconnect

New build costs are increasing

rapidly and are difficult to project with

precision due to limited active construction

Cost

New

Build

Generation

Construction

(1)

2,123

1,581

1,316

615

428

EIA ($/KW)

S&P ($/KW)

700

CCGT

4,000

Nuclear

2,795

–

2,925

IGCC

2,438

Pulverized Coal

Gas CT

Technology

(1) Notes:

•

EIA estimates from Annual Energy Outlook 2007; capital costs converted to

2006 dollars.

•

S&P costs from Commodity Report, "Which Power Generation Technologies

Will Take the Lead in Response to Carbon Controls," May 11, 2007.

•

Cost

estimates

from

EIA

and

S&P

are

generic

and

not

take

into

account

site-specific issues such as transmission and fuels access.

2007

2008

2009

2010

2011

2012

2013

Source: WoodMackenzie

Year New Capacity is Needed

VACAR

MRO

MAAC

ERCOT

SPP

ECAR

NEPOOL

MAIN

$12.40

$10.30

$15.50

$1.50

$1.00

$102.51/MWh

(36-Month Price)

2006 Auction

2007 Auction

~ $35

$67.20 -

$67.50

~ $41

$98.88/MWh

(36-Month Price)

$57.70 -

$58.45

$102.51/MWh

(36-Month Price)

2006 Auction

2007 Auction

~ $35

$67.20 -

$67.50

~ $41

$98.88/MWh

(36-Month Price)

$57.70 -

$58.45

Full Requirements Cost

New Jersey BGS Auction for PSEG

ATC

Forward

Energy

Price

(1)

Full-Requirements Costs ($/MWh):

The higher full-requirements component is due to increases in costs associated with

capacity and congestion

(1) Range of forward market prices that traded during the 2006 and 2007 auctions. The 2006 auction occurred on Feb. 6-7, 2006, and the 2007 auction occurred on Feb. 5-7, 2007.

$140/MW-Day

Transmission and Congestion

Migration Risk

and Volumetric

Risk

Capacity

Renewable

Energy

Load Shape and

Ancillary Services

PJM RPM 2007/2008 & 2008/2009

RPM will have limited impact on Exelon’s 2007 earnings due to current contracts and

forward sales commitments

Eastern MACC

•

2007/2008 RPM auction:

$197.67/MW-day

•

2008/2009 RPM auction:

$148.80/MW-day

Rest of Market

•

2007/2008 RPM auction:

$40.80/MW-day

•

2008/2009 RPM auction:

$111.92/MW-day

Southwest MAAC

•

2007/2008 RPM auction:

$188.54/MW-day

•

2008/2009 RPM auction:

$210.11/MW-day

2007/2008 System

Total CTR Value = 4,599 MW

2008/2009 System

Total CTR Value = 5,128 MW

2007/2008 System Total

CTR Value = 5,134 MW

2008/2009 System Total

CTR Value = 4,717 MW

0 MW

N/A

0 MW

Southwest MAAC

480 -

525 MW

480 -

525 MW

NJ BGS

9,000 -

9,300 MW

9,000 -

9,300 MW

PECO PPA

9,500 MW

Eastern MAAC

6,600 -

6,800 MW

6,600 -

6,800 MW

IL Auction

16,000 MW

(3)

Rest of Market

2008/09

2007/08

Obligation

Exelon Generation Capacity Obligation

(2)

ExGen

Capacity

(1)

RPM = Reliability Pricing Model

CTR = Capacity Transfer Rights

(1) All values are approximate. (2) Not inclusive of all wholesale transactions.

(3) 2008/2009 ExGen Rest of Market Capacity decreases to 15,100 MW due to the roll-off of several PPAs.

500

1,000

1,500

2,000

2,500

3,000

Carbon Credit ($/Ton)

Carbon Value

Climate change legislation is expected to drive substantial gross margin expansion

at Exelon Generation

(1) As of 7/23/07.

(2) The

EIA

Carbon

Stabilization

Case

(Case

dated

March

2006,

EIA

report

number

SR/OIAF/2006-1.

(3) The

Energy

Information

Administration

(EIA)

valuation

the

McCain

Lieberman

Bill,

EIA

report

number

SR/OIAF/2003-02.

(4) Low

Carbon

Economy

Act

initial

“Technology

Accelerator

Payment”

(TAP)

price

2012.

Allowance

price

increases

above

the

rate

inflation

thereafter.

Note: Assumes below $45/ton carbon cost, no carbon reduction technology (e.g., sequestration) is economical.

EXC Market Sensitivity

2011: $10/ton

Europe Carbon Trading

2011: $28.20/ton

(1)

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

Carbon Value

McCain Lieberman Bill

(3)

2010-11: $22/ton

Assumes Open Position at Exelon Generation

EIA Carbon Case

(2)

2010: $31/ton

Bingaman Specter

(4)

: $12/ton

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 August 8, 2007 and market prices for the balance of the year

2008 and 2009 are forward market prices as of August 8, 2007.

PRICES (as of August 8th, 2007)

Units

2004 ¹

2005 ¹

2006 ¹

2007

2008

2009

PJM West Hub ATC

($/MWh)

42.35 ²

60.92 ²

51.07 2

56.27

61.93

64.43

PJM NiHub ATC

($/MWh)

30.15 ²

46.39 ²

41.42 ²

43.37

46.34

48.38

NEPOOL MASS Hub ATC

($/MWh)

52.13 ²

76.65 ²

59.68 ²

65.75

75.60

78.13

ERCOT North On-Peak

($/MWh)

49.53 ³

76.90 ³

60.87 3

60.39

73.88

76.60

Henry Hub Natural Gas

($/MMBTU)

5.85

8.85

6.74

7.07

8.28

8.60

WTI Crude Oil

($/bbl)

41.48

56.62

66.38

67.57

70.48

69.88

PRB 8800

($/Ton)

5.97

8.06

13.04

9.72

10.80

11.50

NAPP 3.0

($/Ton)

60.25

52.42

43.87

45.60

47.50

48.75

ATC HEAT RATES (as of August 8th, 2007)

PJM West Hub / Tetco M3

(MMBTU/MWh)

6.40

6.30

6.98

7.10

6.60

6.65

PJM NiHub / Chicago City Gate

(MMBTU/MWh)

5.52

6.32

6.22

5.66

5.62

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.53

8.21

8.28

7.90

8.11

8.04

Market Price Snapshot

7.4

7.6

7.8

8.2

8.4

8.6

8.8

9.2

9.4

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

8.84

8.94

9.04

9.14

9.24

9.34

9.44

9.54

9.64

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

2008

2009

7.1

7.2

7.3

7.4

7.5

7.6

7.7

7.8

7.9

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

2009

2008

2008 PJM-West

2009 PJM-West

2009 Ni-Hub

2008 Ni-Hub

As of August 8, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

2008

2009

Forward NYMEX Natural Gas

PJM-West and Ni-Hub On-Peak

Forward Prices

PJM-West Implied Heat Rate

Ni-Hub Implied Heat Rate

Market Price Snapshot

1/2/07

2/2/07

3/2/07

4/2/07

5/2/07

6/2/07

7/2/07

8/2/07

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

Ni-Hub Spread Between On-Peak and

Off-Peak Forward Prices

2008

2009

PJM-West Spread Between On-Peak and

Off-Peak Forward Prices

2008

2009

As of August 8, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

Market Price Snapshot

7.5

8.5

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

7.8

7.85

7.9

7.95

8.05

8.1

8.15

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

2008

2009

1/2/2007

2/2/2007

3/2/2007

4/2/2007

5/2/2007

6/2/2007

7/2/2007

8/2/2007

2009

2008

2009

As of August 8, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

2008

2009

Houston Ship Channel Natural Gas

Forward Prices

ERCOT ATC Forward Prices

ERCOT ATC v. Houston Ship Channel

Implied Heat Rate

ERCOT Wrap Forward Prices

2006 EPS

Weather

RNF

O&M

Depreciation /

Amortization

Interest Expense

Other

2007 EPS

Guidance

ComEd 2007 Operating EPS

As a “wires-only”

company, ComEd is expected to earn less on an operating basis in 2007

than in prior years due to the end of the transition period in Illinois and related transition

revenues. The unfavorable ICC Order in the Distribution Case and continued regulatory

lag further reduces ComEd’s 2007 earnings

2006 Actual

RNF

O&M

Depreciation /

Amortization

Interest

Expense

Other

$0.10 -

$0.20

$65M -

$125M

$0.78

$528M

$(0.51)

$(0.09)

$0.00

$(0.06)

2007 Guidance

(2)

Note: See

“Key

Assumptions”

slide

Appendix.

(1) Variance driven by nonrecurring credit in 2006.

(2) Reflects the 12/20/06 ICC amended order on the rehearing of ComEd’s Distribution Rate Case.

$0.02

Key Items:

Recovery of Manufactured

Gas Plant cost -

($0.04)

(1)

Inflation -

($0.02)

Pension & benefits -

($0.02)

$0.01

Weather

Depr. -

($0.02)

Amort. -

$0.02

ComEd Operating Earnings:

Next Five Years

2011

(1)

2011 Assumptions

(1)

Rate base:

~$9.6B

Equity

(2)

~45%

ROE:

~10%

2007 Guidance

Note: See

“Key

Assumptions”

slide

Appendix.

(1) Provided solely for illustrative purposes, not intended as earnings guidance. The earnings figure represents a possible scenario that is based on the assumptions shown above as

well as assumptions about other factors, including, but not limited to, judgments about changes in load growth, spending and ratemaking proceedings, as well as future economic,

competitive and financial market conditions, and the absence of adverse regulatory and legislative developments, all of which are subject to uncertainties and have not been subject

to the same degree of analysis as we apply to 2007 forecasts. The scenario should not be relied upon as being necessarily indicative of future results.

(2) Reflects equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill). Projected book equity ratio in 2007 is 58%.

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

$65M -

$125M

~$430M

2006 Actual

$528M

2007 Assumptions

Rate Base:

~$8.1B

Equity

(2)

~43%

ROE:

~2.0

–

3.5%

ComEd Highlights

IPA and new procurement process

Roll-out of customer rate relief

programs per the IL Settlement

Regulatory recovery plan

Transmission formula rate approved

by FERC, effective May 1, 2007

(subject to hearing and potential

refund)

Distribution rate case filing expected

late 3Q07; decision expected 11

months after filing

Rate Design docket (No. 07-0166)

Legislative Overview

The Pennsylvania General Assembly introduced four bills that would

enable elements of Governor Rendell’s Energy Independence Plan

One of the four bills, HB 1203, was passed by the General Assembly and

was signed into law on July 17, 2007

•

HB 1203 amends the Alternative Energy Portfolio Standards (AEPS)

Act by

increasing solar obligations and modifying standards that utilities must meet in

order to obtain “force majeure”

waiver from PAPUC

A bill not originally part of the Governor’s Energy Initiative, HB 1530, was

passed by the General Assembly and signed into law on July 17, 2007

•

Supported by Duquesne Energy, US Steel and ATI

•

Allows all distribution companies to provide long-term, fixed price contracts for

customers with peak demands of 15 MW or greater

•

Allows Duquesne to own generation to serve customers with peak demands

of 20 MW or greater (3-year window to enter into a contract or acquire

generation)

Legislature agreed to hold a Special Session on Energy Policy set to

begin on September 17, 2007

Senate

has

agreed

take

the

following

topics

the

Special

Session:

•

Investment in clean and renewable energy and incentives for conservation

without new taxes

•

Legislation to set standards for liquid fuels

Additional legislation supporting the Governor’s Energy Independence

Strategy is still under consideration in the Legislature; elements of those

bills may be considered in the Special Session:

•

Procurement

•

Conservation and renewable power

•

Rate increase phase-in plan

•

System benefits charge to support $850M bond initiative

•

Smart meters and time-of-use pilot

•

Micro-grids

•

Pennsylvania Energy Development Authority (PEDA) energy procurement

authority

•

Alternative fuels

Special Session Agenda

Governor’s Energy Independence

Strategy –

Legislative Package

HB 1200 –

PEDA

Authorization

HB 1203 –

Renewable

Portfolio Standards

Amendment

HB 1202 –

Liquid

Fuels Bill

•

Procurement using the portfolio model with “lowest reasonable

rates”

and prioritizes demand side management and

alternative energy resources

•

Allows for long-term, cost-based rates for larger energy users

•

Provides for 3-year phase-in of rate increases for all customers

•

Establishes system benefits charge of 0.5 mills/KWh

•

Mandates time-of-use pilot for all customers and full

deployment of “smart meter”

program in 6 years

•

Authorizes Pennsylvania Energy Development Authority

(PEDA) to spend the $850M of proceeds from securitization of

systems benefit charge

•

Provides PEDA right to “acquire, buy and sell electric power”

•

Accelerates the minimum thresholds for the acquisition of

Solar/Photovoltaic as Tier-1 Resource

•

Force Majeure language modified to consider “good faith

effort”

by utilities to procure renewable energy

•

Sets standards for ethanol content in transportation fuels

•

Sets standards for bio-diesel content of diesel fuel

HB 1201 –

PAPUC

Statute Bill

Summary of PAPUC Rulemakings

It will likely be effective

immediately, as it is a

policy statement

Expected in the Fall

2007

Will address the

benefits of DSR/EE and

requirements for utilities

to implement such

programs

Demand Side Response

Energy Efficiency

(DSR/EE)

May 17, 2007

Issued May 10, 2007

Discusses consumer

education, conservation

and energy efficiency,

impact on low income

customers

Mitigation of Rate

Increases

May 10, 2007

Issued May 10, 2007

Reflects the PAPUC’s

current thinking on

application of the

regulations

Default Service

Policy Statement

Expected in September

2007

Issued May 10, 2007

Addresses issues

around procurement,

rate design, cost

recovery, filing

requirements

Default Service

Regulations

Effective Date

Final Order

Description

Rulemaking

Default Service Provider

Regulations/Policy

Procurement

•

Competitive process but no statewide auction

•

Utility run RFPs

or auctions are preferred; portfolio approach is

allowed

•

Staggered auctions/RFPs

to avoid high market risk

•

Long term contracts limited to renewable resources

•

Non-renewable contracts limited to 1-3 years

•

Encourages spot market purchases for a portion of supply

Cost Recovery

•

Full cost recovery, no prudence review

•

Reconciliation not required but is mandatory for AEPS

Rate Design

•

Preference for a single price for each rate class

•

Eliminates declining block rates and demand charges

•

Frequent rate changes –

quarterly or monthly, to better track

the market

•

Hourly or monthly pricing for large customers

Mitigation

•

Provides for an opt-in phase-in for increases of >25% for

customers <25 KW; must be competitively neutral

•

Transition period of up to 3 years for rate design changes

•

Statewide education program

•

Utility specific education plans to be filed by 12/31/2007

•

Encourages energy efficiency and demand response

PECO Post-2010 Strategy

•

PECO to propose an auction approach to conduct multiple

procurements prior to 2011

•

May offer 1-year fixed rate for large energy users

•

Requirement for some spot market purchases

•

PECO will file its individual Customer Education Plan with

PAPUC by 12/31/07

•

Participate in PAPUC Working Group to develop effective

statewide campaign

•

Expect PAPUC action on DSR/EE in 4th

quarter 2007

•

PECO to begin real-time pricing pilot for 300 customers

in 2008

•

Plan to expand current offerings and add new programs,

based upon PAPUC rules and cost recovery

Procurement

Rate Stabilization

Consumer Education

Demand Side

Response & Energy

Efficiency (DSR/EE)

•

Procurement plan will include early, staggered procurement

•

Rate increase phase-in for residential & small commercial

customers offered on an opt-in basis if rate increase > 25%

•

Three-year phase-out to minimize impact of rate design

changes

2011

PECO Average Electric Rates

(1) Rates

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.

2.59

0.46

2.70

4.92

5.43

2006

2007

2008 -

2010

Energy / Capacity

Competitive

Transition Charge

Transmission

Distribution

10.67¢

11.18¢

Unit Rates (¢/kWh)

(1)

Electric Restructuring Settlement

+4.8%

CTC terminates at year-end 2010

Energy / Capacity price is expected to

increase; price will reflect associated

full requirements costs (including

capacity, load shaping, ancillary

services, line losses, transmission

congestion and gross receipts tax)

PECO’s 2011 full requirements price is

expected

differ

from

PPL’s

first

auction price 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

Post-Transition Factors

Procurement Models

Modified Full

Requirements

Procurement

Full-Blown

Integrated Resource

Planning

Horizontal

Procurement w/

Capacity-Based

Planning

Full Requirements

Auction

Horizontal

Procurement w/

Non-Discriminatory

Pricing

•

Descending clock full requirements auction

•

Limited uneconomic entry

Description

•

Full requirements procurement, but change to RFP/pay as bid

structure with longer-term contract for differences

•

Delivery company procures financial blocks of power, but no

discrimination based on resource type (e.g., renewable vs. other,

new versus existing)

•

Delivery company procures blocks of power plus conducts new

resource-only RFPs

for capacity

•

Delivery company procures portfolio of supply contracts, conducts

new

resource-only

RFPs

for

different

types

resources,

and

possibly builds regulated plants as directed by regulators

Favorable

Unfavorable

Procurement Models (cont’d)

Vertical Procurement

Energy shortfall

•

Upfront regulatory planning process

•

Utility procures “standard”

products

•

Contracts are for fixed volume

•

Utility manages risks

•

All decisions subject to prudence review

Horizontal Procurement

Peak Demand

Excess energy

•

Full Requirements

•

Product is % of actual load

•

Suppliers assume all risk

•

Fixed price including risk

2006 EPS

Weather

RNF

O&M

Depreciation /

Amortization

Other

2007 EPS

Guidance

PECO’s

operating

earnings

are

expected

decrease

slightly

from

2006

2007

primarily due to increasing CTC amortization

2006 Actual

(2)

2007 Guidance

(2)

$0.67

$451M

$(0.07)

$0.04

$0.00

$(0.07)

$0.60 -

$0.65

$400M -

$420M

RNF

O&M

CTC

Amortization /

Depreciation

Other

PECO 2007 Operating EPS

Note: See

“Key

Assumptions”

slide

Appendix.

(1)

Variance primarily driven by nonrecurring credits in 2006.

(2)

Adjusted for ($4M) preferred securities from HoldCo.

$0.05

Weather

Key Items:

Storms -

$0.03

Inflation -

($0.01)

Pension & benefits -

($0.01)

Key Items:

ITC & R&D Credit (Net

of Fees

(1)

) -

($0.05)

Taxes other than

income -

($0.03)

$0.00

Interest

Expense

PECO Operating Earnings:

Next Five Years

2011

(1)

2011 Assumptions

(1)

Rate Base:

~$4.7B

Equity:

~50%

ROE:

~10%

2007 Guidance

$400M -

$420M

PECO is expected to provide a predictable source of earnings to Exelon through the

remainder of the transition period

~$235M

Note: See “Key Assumptions”

slide in Appendix.

(1) Provided solely for illustrative purposes, not intended as earnings guidance. The earnings figure represents a possible scenario that is based on the assumptions shown above as

well as assumptions about other factors, including, but not limited to, judgments about changes in load growth, spending and ratemaking proceedings, as well as future

economic, competitive and financial market conditions, and the absence of adverse regulatory and legislative developments, all of which are subject to uncertainties and have

not been subject to the same degree of analysis as we apply to 2007 forecasts. The scenario should not be relied upon as being necessarily indicative of future results.

PECO Highlights

Legislative activity:

HB 1203 and HB 1530 signed by governor on

7/17/07

Other energy issues are expected to be

addressed in a special legislative session

scheduled for 9/17/07

PAPUC:

Issued POLR rules on 5/10/07

PUC’s Final Default Service rules provide

competitive procurement framework with full

cost recovery

PUC’s Price Mitigation Order focuses on

customer education to prepare customers for

potential rate increase

AEPS Act –

PECO expects a recommendation

from the ALJ by the end of 3Q07 with a PUC

decision in 4Q07 on its early procurement filing of

3/07

Key Assumptions

7.60

6.56

8.41

Chicago City Gate Gas Price ($/mmBtu)

9.00

7.31

9.67

Tetco M3 Gas Price ($/mmBtu)

37.0

37.5

Effective Tax Rate (%)

(4)

0.9

0.6

1.3

ComEd

0.6

1.2

0.9

PECO

Electric Delivery Growth (%)

(3)

ComEd

PECO

Electric Volume Retention (%)

16.60

1.75

0.13

PJM West Capacity Price ($/MW-day)

44.30

1.75

0.13

PJM East Capacity Price ($/MW-day)

5.80

6.32

5.52

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

44.00

41.42

46.39

NI Hub ATC Price ($/MWh)

6.60

6.98

6.30

PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)

59.50

51.07

60.92

PJM West Hub ATC Price ($/MWh)

8.00

6.74

8.85

Henry Hub Gas Price ($/mmBtu)

144,000

71,326

72,376

Total Genco Market and Retail Sales (GWhs)

(2)

40,500

(5)

119,354

121,961

Total Genco Sales to Energy Delivery (GWhs)

184,500

190,680

194,337

Total Genco Sales Excluding Trading (GWhs)

94.0

93.9

93.5

Nuclear Capacity Factor (%)

(1)

2007 Est.

2006 Actual

2005 Actual

(1)

Excludes Salem.

(2)

2007 estimate includes Illinois Auction Sales.

(3)

Weather-normalized retail load growth.

(4)

Excludes results related to investments in synthetic fuel-producing facilities.

(5)

Sales to PECO only.

Notes: 2005 and 2006 prices are average for the year.

2007 prices reflect observable prices as of 9/14/06.

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

A-

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 8/10/07.

(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

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)

as 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% of PV of 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

3 Months Ended June 30, 2006 and 2007

$0.85

2006 Adjusted (non-GAAP) Operating EPS

$0.95

2006 GAAP Reported EPS

Exelon

(0.13)

Nuclear decommissioning obligation reduction

0.01

Charges related to now terminated merger with PSEG

0.08

Investments in synthetic fuel-producing facilities

(0.06)

Mark-to-market adjustments from economic hedging activities

Note: Amounts may not add due to rounding

$1.03

2007 GAAP Reported EPS

$1.03

2007 Adjusted (non-GAAP) Operating EPS

(0.02)

ComEd 2007 rate relief program

0.04

Investments in synthetic fuel-producing facilities

(0.02)

Mark-to-market adjustments from economic hedging activities

2007 Earnings Outlook

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

excludes the earnings impacts of the following:

•

costs associated with the Illinois electric rate settlement, including ComEd’s

previously announced customer Rate Relief and Assistance Initiative

•

mark-to-market adjustments from economic hedging activities

•

investments in synthetic fuel-producing facilities

•

significant impairments of intangible assets, including goodwill

•

significant changes in decommissioning obligation estimates

•

other unusual items

•

any future changes to GAAP

GAAP guidance excludes the impact of unusual items which the Company

is unable to forecast, including any 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