8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

December 19, 2007

Date of Report (Date of earliest event reported)

Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 7 — Regulation FD

Item 7.01. Regulation FD Disclosure

On December 19, 2007, Exelon Corporation (Exelon) will host its annual investor conference and will reaffirm its adjusted (non-GAAP) operating earnings guidance range for 2007 at $4.15 to $4.30 per share for Exelon. Management believes that actual results are likely to come in at the upper end of this range. In addition, Exelon revised its 2007 GAAP earnings guidance range to $4.05 to $4.20. Exelon will also reaffirm its adjusted (non-GAAP) operating earnings guidance range for 2008 and will provide its GAAP earnings guidance range for 2008.

In addition, Exelon announced via press release a regular first-quarter 2008 dividend of $0.50 per share on Exelon’s common stock, a 14 percent increase over the dividend for the fourth quarter of 2007. Exelon’s board of directors also authorized a new share repurchase program of up to $500 million of Exelon’s outstanding common stock. This new program is in addition to the $1.25 billion share repurchase executed in September 2007. In line with Exelon’s value return policy, additional share repurchases may be authorized by the board of directors later in 2008 based on availability of cash and other factors. The board authorization of the share repurchase permits the company to effect the repurchases from time to time through a variety of methods including open market repurchases, privately negotiated transactions and/or accelerated share repurchase transactions. There can be no assurance as to the amount, timing or prices of repurchases. The specific timing and amount of repurchases may also vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the board of directors at any time.

The press release is attached to this Current Report on Form 8-K as Exhibit 99.1. In addition, attached as Exhibits 99.2 and 99.3 to this Current Report on Form 8-K are the presentation slides to be used at the conference and the supplemental information made available to investors, respectively.

Section 9 — Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Press Release
99.2	Presentation Slides
99.3	Supplemental Information

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This Current Report 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 I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ John F. Young

John F. Young

Executive Vice President, Finance and Markets

and Chief Financial Officer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/ Robert K. McDonald

Robert K. McDonald

Senior Vice President, Chief Financial Officer,

Treasurer and Chief Risk Officer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

December 19, 2007

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press Release
99.2	Presentation Slides
99.3	Supplemental Information

EX-99.1

Exhibit 99.1

Contact:	Chaka Patterson	FOR IMMEDIATE RELEASE
	Investor Relations
	312-394-7234
	Kathleen Cantillon
	Corporate Communications
	312-394-2794

Exelon Announces Dividend Increase and Share Buyback;

Reaffirms 2007 and 2008 Earnings Guidance

CHICAGO (December 19, 2007) – Exelon Corporation today announced that its board of directors has declared a regular first-quarter 2008 dividend of $0.50 per share on Exelon’s common stock, a 14 percent increase over the dividend for the fourth quarter of 2007. The first-quarter dividend is payable on March 10, 2008, to Exelon shareholders of record at 5:00 p.m. New York Time on February 15, 2008.

Last December, Exelon’s board of directors approved a value return policy that established an annual base dividend rate of $1.76 per share, which was expected to grow modestly over time. Largely due to improved market fundamentals and our superior operations, the board of directors is resetting Exelon’s annual base dividend rate at $2.00 per share. The company expects to grow the dividend modestly over time. Future dividends are subject to declaration by the board of directors.

“Our cash flow and balance sheet continue to be robust,” said John W. Rowe, Exelon’s chairman, president and CEO. “Considering our financial strength and the improving fundamentals of our business, our board has reset the annual base dividend rate at $2.00 per share. This increase will return more immediate value to our shareholders, while still providing the financial flexibility needed to make sound investments in our business and take advantage of opportunities as they arise.”

Share Repurchase

Exelon’s board of directors also authorized a new share repurchase program of up to $500 million of Exelon’s outstanding common stock. This new program is in addition to the $1.25 billion share repurchase executed in September 2007. In line with Exelon’s value return policy, additional share repurchases may be authorized by the board of directors later in 2008 based on availability of cash and other factors.

Exelon’s value return policy considers the use of share repurchases from time to time, when authorized by the board of directors, to return cash or balance sheet capacity to Exelon shareholders after funding maintenance capital and other commitments and in the absence of higher value-added growth opportunities.

1

Earnings Outlook

Exelon reaffirmed adjusted (non-GAAP) operating earnings guidance range for 2007 at $4.15 to $4.30 per share. Management believes that actual results are likely to come in at the upper end of this range.

In addition, Exelon reaffirmed adjusted (non-GAAP) operating earnings guidance range for 2008 at $4.00 to $4.40 per share.

The outlook for 2007 and 2008 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items included in GAAP earnings:

• 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 (2007 only)

• costs associated with the Illinois electric rate settlement, including ComEd’s previously announced customer rate relief and assistance initiatives

• gains or losses on the State Line Energy, L.L.C. and Tenaska Georgia Partners, LP transactions (2007 only)

• other unusual items

• any future changes to GAAP

In consideration of these factors, Exelon revised 2007 GAAP earnings guidance to $4.05 to $4.20 per share from $3.90 to $4.20 per share and provided 2008 GAAP earnings guidance of $3.70 to $4.10 per share. Both Exelon’s adjusted (non-GAAP) operating earnings and GAAP earnings guidance are based on the assumption of normal weather for future periods.

Rowe and John F. Young, Exelon’s executive vice president and chief financial officer, will discuss the dividend, the share buyback and earnings guidance today at Exelon’s Investor Conference in New York City. The presentation will be webcast live at 10:00 a.m. Eastern time. To view the webcast, go to www.exeloncorp.com and select the Investor Relations page.

This news release 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 I, Financial Information, ITEM 1. 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

2

to place undue reliance on these forward-looking statements, which apply only as of the date of this news release. 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 news release.

###

Exelon Corporation is one of the nation’s largest electric utilities with approximately 5.4 million customers and more than $15 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in Illinois and Pennsylvania and natural gas to more than 480,000 customers in southeastern Pennsylvania. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

3

EX-99.2

John W. Rowe

Chairman, President and Chief Executive Officer

2007 Exelon Investor Conference

New York, NY

December 19, 2007

Exhibit 99.2

2

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

I,

Financial

Information,

ITEM

1.

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

Supplemental

Information

presentation

in

Form

8-K

filed

on

December

19,

2007

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

earnings

to

GAAP

earnings

and

a

reconciliation

of

GAAP

net

income

to

adjusted

(non-GAAP)

EBITDA.

3

Today’s Conference Agenda

10:00 a.m. –

10:35 a.m.

John Rowe –

Welcome and Strategic Overview

10:35 a.m. –

11:00 a.m.      John Young –

Financial Overview

11:00 a.m. –

11:15 a.m.  

Break

11:15 a.m. –

12:15 p.m.

Panel Q&A –

John Rowe, John Young, Chris Crane, Lisa Crutchfield,

Ian McLean, Betsy Moler, Anne Pramaggiore

12:15 p.m. –

12:30 p.m.

John Rowe –

Wrap-up

12:30 p.m. –

1:30 p.m.

Lunch / Informal discussion (Hilton Room)

4

5

  $3.22

$3.10

$2.78

$2.61

$2.41

$2.24

$1.93

Oct-

00

Apr-

01

Oct-

01

Apr-

02

Oct-

02

Apr-

03

Oct-

03

Apr-

04

Oct-

04

Apr-

05

Oct-

05

Apr-

06

Oct-

06

Apr-

07

Oct-

07

10/20/00 –

11/30/07

Assumes dividend reinvestment

Source: Bloomberg

EXC

241%

UTY

105%

(1) 8-year

growth

rate

through

2008;

calculated

using

midpoint

of

2008

Operating

EPS

guidance

range

and

2000

Operating

EPS

of

$1.93/share

as

base

year.

$4.15-$4.30

Sustainable Financial Performance

Total Shareholder Return

Adjusted (non-GAAP) Operating EPS

$4.00-$4.40

2000 –

2008 compound annual operating EPS growth is projected at ~10%.

Seven-year total return exceeds 240%

6

Sustainable Operating Excellence –

Exelon Generation

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

Average Capacity Factor

Note:

Exelon

data

prior

to

2000

represent

ComEd-only

nuclear

fleet.

Sources:

Platt’s,

Nuclear

News,

Nuclear

Energy

Institute

and

Energy

Information

Administration

(Department

of

Energy).

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

65%

70%

75%

80%

85%

90%

95%

100%

Operator (# of Reactors)

Range

5-Year Average

EXC 93.2%

7

Sustainable Operating and Regulatory

Performance –

ComEd

Fewer Interruptions and Shorter Outages

Note: Data based on IEEE definition which excludes major events and

planned outages.

“State touts rate-relief plan; Proposal could

trim average ComEd bill $8 a month”

(July 24, 2007)

0.50

1.00

1.50

2.00

1998

2007 Projected

0

50

100

150

200

Frequency (SAIFI)

Duration (CAIDI)

8

Sustainable Operating and Regulatory

Performance –

PECO

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1998

2007 Projected

0

40

80

120

160

Frequency (SAIFI)

Duration (CAIDI)

Fewer Interruptions and Shorter Outages

“Rendell sees urgent need to

complete energy plan”

(September 14, 2007)

Note: Data based on IEEE definition which excludes major events and

planned outages.

9

5

DRAFT 12/7/2006 10:00 AM

A Sustainable Vision, A Dynamic Strategy

Exelon’s Strategic Direction

Protect Today’s Value

•

Deliver superior operating performance

–

Keep the lights on

–

Continue nuclear excellence

•

Support competitive markets

–

Maintain/bolster PJM

–

Step up advocacy

–

Encourage market-based new entry

–

Enhance auction construct

–

Participate in competitive new entry

•

Protect the value of our generation

–

Optimize the generation portfolio

–

Hedge market risk appropriately

•

Build healthy, self-sustaining delivery 

companies

–

ComEd –

fight rate freeze legislation,

seek long-term peace and drive path to

financial health

–

PECO –

maintain performance and

prepare for 2011 transition to market

Grow Long-Term Value

•

Take the organization to the next level of

performance

–

Foster positive employee relations

–

Require accountability for results and values

–

Acquire, develop and retain key talent

–

Continuously improve productivity

•

Align our financial management policies with the

changing profile of our company

•

Rigorously evaluate new growth opportunities

–

Generation

–

Transmission

–

Distribution

•

Advance an environmental strategy that

leverages our carbon position

+

10

A Sustainable Environment

11

John F. Young

Executive Vice President, Finance and Markets, and Chief Financial Officer

2007 Exelon Investor Conference

New York, NY

December 19, 2007

13

YTD Highlights

•

Solid financial operating EPS results

-

Higher generation margins

-

Favorable weather

-

Strong nuclear performance

•

Illinois Settlement

•

Engaged in Pennsylvania transition

•

Value Return Plan implementation

•

ComEd Regulatory Recovery Plan execution

2007 Operating EPS Guidance of $4.15 -

$4.30

2008 Operating EPS Guidance of $4.00 -

$4.40

Financial Update

YTD EPS Results

$3.26

$2.53

Weather Normalized

$3.31

$2.50

Operating

Sep-07

Sep-06

2008

(1)

$0.55 -

$0.60

$3.15 -

$3.45

$4.00 -

$4.40

$0.35 -

$0.40

2008 EPS Guidance

(1)

Operating EPS:  $4.00 -

$4.40

GAAP EPS:  $3.70 -

$4.10

(1)

Refer to Appendix for key assumptions supporting 2008 earnings guidance and for expected 2008 earnings drivers for Exelon Generation, ComEd  and

PECO.  Operating Company ranges do not add to Exelon guidance of

$4.00 -

$4.40/share due to rounding.

ComEd

PECO

Exelon Generation

HoldCo/Other ~$(0.10)

Exelon

14

PECO

ExGen

Operating EPS Guidance:

$4.15 –

$4.30

2007

~9% Compound Annual Growth Rate in EPS from 2007 to 2011

2011

ExGen

ComEd

Major Driver:

End of below-market contract in PA

Exelon Is Uniquely Positioned for

Sustainable Value Creation

15

PECO and ComEd

Average Annual Rate Base

($ in Billions)

CTC

Electric Transmission

Electric Distribution

Gas

Numbers may not sum due to rounding

(1)

Illustrative.

Provided

solely

to

illustrate

possible

future

outcomes

that

are

based

on

a

number

of

different

assumptions,

all

ofwhich

are

subject

to

uncertainties

and

should

not

be

relied

upon as a forecast of future results.

(2)

ComEd

estimated

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%.

(3)

ComEd 2008 estimated net income assumes full $361M revenue increase granted in current distribution rate case.

6.0

6.6

8.0

1.8

2.0

2.2

$220 -

$260M

(3)

$130 -

$165M

~5.5 -

6.5%

~3.8 -

4.8%

45%

44%

7.8

8.6

~$460 -

$500M

~10 -

11%

~45%

2007E

2008E

2011

(1)

10.2

2.6

2.8

3.1

0.5

0.5

0.6

2.7

2.0

1.1

1.1

1.2

6.9

6.4

2007E

2008E

2011

(1)

4.9

~$245 -

$270M

~10 -

11%

~50%

$435 -

$470M

Not applicable due to

transition rate structure

$360 -

$400M

Net Income

ROE

Equity

(2)

16

•

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 is the premier unregulated generation company –

positioned to

capture market opportunities and manage risk

Exelon Generation

•

Continue to focus on operating excellence,

cost management, and market discipline

•

Support competitive markets

•

Pursue nuclear & hydro plant license

extension 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

•

Capture increased value of low-carbon

generation portfolio

Grow Value

17

Sustainable Operating Excellence

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

Average Capacity Factor

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

Sources:

Platt’s,

Nuclear

News,

Nuclear

Energy

Institute

and

Energy

Information

Administration

(Department

of

Energy).

65

70

75

80

85

90

95

100

Operator (# of Reactors)

Range

5-Year Average

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

EXC 93.2%

18

-15%

-10%

-5%

0%

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

$5

$6

$7

$8

$9

$10

2008

2010

2012

2014

2016

2018

2020

NYMEX

(1)

Positively Exposed to Market Dynamics

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

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

0

5

10

15

20

25

30

35

40

45

0

5

10

15

20

25

30

EIA Carbon Case

2010: $31/tonne

Europe Carbon-Trading

2012: $36.50/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

New Generation Installed Cost

Combined Cycle

Gas Turbine

Coal

Nuclear

0

500

1,000

1,500

2,000

2,500

3,000

2006

2007

2006

2007

2006

2007

(1)

As of 7/31/07.

19

2008 “Open”

EBITDA

2008 EBITDA

2008 Un-hedged EBITDA

(No Carbon)

$ Millions

~$4,100

~$3,900

2007 EBITDA

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)

1 tonne = 2,205 lbs.

~$5,350

Hedged –

2008E

Un-hedged –

2008E

(1)

Hedged –

2007E

169.10

Eastern MAAC Capacity Price ($/MW-day)

82.40

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

5.60

NI-Hub Implied Heat Rate (mmBtu/MWh)

6.60

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 Un-hedged EBITDA

(1)

Assumptions

~$1,000M

+ $10/Tonne Carbon Price

(2)

~$80M

+/-

$10/MW-Day Capacity Price

~$750M

+/-

500 Btu/KWh ATC Heat Rate

~$560M

+/-

$1/mmBtu Gas Price

(Pre-Tax Impact)

2008 Un-hedged EBITDA

(1)

Sensitivities

$2,060 -

$2,260

Operating

Earnings:

$2,320 -

$2,385

20

Disciplined Financial Management

•

Announced a new Value Return Policy last December

–

Established annual base dividend of $1.76/share; anticipated to grow

modestly over time

–

Returns excess cash and/or balance sheet capacity through share

repurchases

•

Executed a $1.25 billion accelerated share repurchase agreement in

September 2007

Today’s announcement:

•

New share repurchase program of $500 million

–

Incremental to $1.25 billion buyback executed in September 2007

and

to any additional buybacks that may be authorized in 2008

•

Annual base dividend rate reset at $2.00/share

(beginning Q1 2008);

anticipated to grow modestly over time

(1)

–

Higher base dividend reflects higher expected long-term earnings due

to improved market fundamentals

(1)

Future dividends are subject to declaration by the Board of Directors.

21

2008 Projected Sources and Uses of Cash

$1,240

Cash available after Dividend

($1,310)

Dividend

(3)

$2,550

Cash available before Dividend

$1,220

Net Financing (excluding Dividend)

(2)

($3,120)

Capital Expenditures

$4,450

Cash Flow from Operations

(1)

Exelon

(4)

$ Millions

(1)

Cash

Flow

from

Operations

=

Net

cash

flows

provided

by

operating

activities

less

net

cash

flows

used

in

investing

activities

other

than

capital

expenditures.

(2)

Net

Financing

(excluding

Dividend)

=

Net

cash

flows

used

in

financing

activities

excluding

dividends

paid

on

common

and

preferred

stock.

(3)

Assumes 2008 Dividend of $2.00 per share.

(4)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

22

0

2

4

6

8

10

12

14

16

18

(-25%)

Forward Gas Prices as of 7/31/07

(+25%)

Balance Sheet Capacity

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

five years, based on planning assumptions

2008 -

2012 Potential Uses of

Available Cash

•

Growth opportunities

•

Future unfunded liabilities

•

Buffer against potentially lower

commodity prices

•

Share repurchases or other

value return options

(1)

Available

Cash

after

Dividend

=

Cash

Flow

from

Operations

-

CapEx

-

Dividends

+/-

Net

Financings.

Cash

Flow

from

Operations

=

Net

cash

flows

provided

by

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

$2.00

/share

in

2008,

growing

5%

annually;

actual

amounts

may

vary,

subject

to

board

approval.

(2)

Available

Cash

after

Dividend

excludes

any

benefit

from

potential

carbon

impact .

(3)

See

“FFO

Calculation

and

Ratios”

definitions

slide

in

Appendix.

FFO

/

Debt

includes:

debt

equivalents

for

purchased

power

agreements,

unfunded

pension

and

other

postretirement

benefits

obligations,

capital

adequacy

for

energy

trading,

and

related

imputed

interest.

S&P “BBB”

Range for FFO/Debt Ratio: 20% to 30%

Gas Price Sensitivity

2008 -

2012 Cumulative Available Cash (Illustrative)

23

Sustainable Value

•

Continued strong financial and operating performance, and

long-term earnings growth driven by 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

Exelon is uniquely positioned to create sustainable value

24

25

Appendix

26

Key Assumptions

37.3

1.2

2.0

23.90

115.40

6.40

6.80

43.60

7.30

7.80

57.1

7.00

149,800

40,900

(5)

190,700

94.7

2007 Est.

37.2

1.6

1.2

82.40

169.10

5.60

8.40

47.00

6.60

9.50

62.90

8.50

148,200

41,100

(5)

189,300

93.1

2008 Est.

6.56

8.41

Chicago City Gate Gas Price ($/mmBtu)

7.31

9.67

Tetco M3 Gas Price ($/mmBtu)

37.0

37.5

Effective Tax Rate (%)

(4)

0.6

1.3

ComEd

1.2

0.9

PECO

Electric Delivery Growth (%)

(3)

1.75

0.13

PJM West Capacity Price ($/MW-day)

1.75

0.13

PJM East Capacity Price ($/MW-day)

6.32

5.52

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

41.42

46.39

NI Hub ATC Price ($/MWh)

6.98

6.30

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

51.07

60.92

PJM West Hub ATC Price ($/MWh)

6.74

8.85

Henry Hub Gas Price ($/mmBtu)

71,326

72,376

Total Genco Market and Retail Sales (GWhs)

(2)

119,354

121,961

Total Genco Sales to Energy Delivery (GWhs)

190,680

194,337

Total Genco Sales Excluding Trading (GWhs)

93.9

93.5

Nuclear Capacity Factor (%)

(1)

2006 Actual

2005 Actual

(1)

Excludes Salem.

(2)

2008 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.

27

ComEd 2008 EPS Contribution

ComEd’s operating earnings are expected to increase in 2008 primarily due to execution

of its Regulatory Recovery Plan

2007

(1)

RNF

O&M

Depreciation /

Amortization

Interest

Expense

Other

$0.35 -

$0.40

$220M -

$260M

(2)

$0.20 -

$0.25

$0.21

$0.02

($0.02)

$(0.04)

2008

(1)

$0.01

Key Items:

Storms: $0.02

Inflation: $(0.02)

Post-2006/Opt-in: $0.02

Bad Debt: $0.01

($0.03)

Weather

$130M -

$165M

$ / Share

NOTE:

Refer

to

“Key

Assumptions”

slide

in

Appendix.

(1)

Estimated contribution to Exelon’s operating earnings guidance.

(2)

Assumes full $361M revenue increase granted in current distribution rate case and effective 10/1/08.

Key Items:

Distribution case

(2)

: $0.09

Transmission revenue: $0.06

Load growth: $0.03

28

PECO 2008 EPS Contribution

PECO’s operating earnings are expected to decrease in 2008 primarily due to

increasing CTC amortization expense

2007

(1)

2008

(1)

$0.65 -

$0.70

$451M

($0.08)

$0.01

($0.02)

($0.01)

$0.55 -

$0.60

$360M -

$400M

RNF

O&M

CTC

Amortization /

Depreciation

Other

NOTE:

Refer

to

“Key

Assumptions”

slide

in

Appendix.

(1) Estimated contribution to Exelon’s operating earnings guidance.

($0.02)

Weather

$0.01

Interest

Expense

$435M -

$470M

$ / Share

29

Exelon Generation 2008 EPS Contribution

Exelon Generation’s earnings are impacted primarily by increased number of refueling

outages and nuclear fuel expense

2007

(1)

2008

(1)

($0.05)

$(0.17)

$0.05

$3.15 -

$3.45

$2,060M -

$2,260M

RNF

O&M

Other

Key Items:

Inflation: ($0.07)

Nuclear security: ($0.02)

Add’l

refueling outages: ($0.06)

$50M

+/-

500 Btu/KWh ATC Heat Rate

$6M

+/-

$1/mmBtu Gas

2008

Market Sensitivities

(After-Tax)

Depreciation

$(0.03)

$3.45 -

$3.55

$2,320M -

$2,385M

$ / Share

NOTE:

Refer

to

“Key

Assumptions”

slide

in

Appendix.

(1) Estimated contribution to Exelon’s operating earnings guidance.

Key Items:

Market / portfolio: $0.08

Add’l

refueling outages: ($0.10)

Nuclear fuel expense: ($0.06)

State Line buyout: ($0.02)

30

Projected 2008 Key Credit Measures

3.5x –

5.5x

BBB

2.6x

2.6x

FFO / Interest

ComEd:

25% –

40%

11%

9%

FFO / Debt

52% –

42%

57%

60%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 44%

2.5x –

3.5x

A

4.1x

4.1x

FFO / Interest

PECO:

12% –

20%

20%

17%

FFO / Debt

62% –

52%

49%

52%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 49%

52% –

42%

44%

60%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 44%

25% –

40%

77%

43%

FFO / Debt

3.5x –

5.5x

BBB+

13.9x

7.2x

FFO / Interest

Exelon

Generation:

62%

29%

5.6x

Without PPA &

Pension / OPEB

(2)

55% –

45%

69%

Rating Agency Debt Ratio

Adjusted Book Debt Ratio: 55%

20% –

30%

22%

FFO / Debt

3.2x –

4.5x

BBB

4.6x

FFO / Interest

Exelon

Consolidated:

“BBB”

Target

Range

(4)

S&P Credit

Ratings

(3)

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

to

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, capital adequacy for energy trading, operating lease obligations, and other off-balance sheet debt.  Debt is imputed for estimated pension and OPEB

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO as of 12/14/07.

(4)

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

31

FFO Calculation and Ratios

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

FFO + Adjusted Interest

= 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)

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

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= 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

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

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

(1) Uses 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.

EX-99.3

Supplemental Information

2007 Exelon Investor Conference

December 19, 2007

Exhibit 99.3

2

3

’07E Earnings:

$2,320 -

$2,385M 

’08E Earnings:

$2,060 -

$2,260M

’07 EPS:

$3.45 -

$3.55

‘08 EPS:

$3.15 -

$3.45

Total Debt

(1)

:

$1.8B

Credit Rating

(2)

:

BBB+

The Exelon Companies

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘07E Operating Earnings:

$2.8 -

$2.9B

‘07 EPS Guidance:

$4.15 -

$4.30

‘08E Operating Earnings:

$2.6 -

$2.9B

‘08 EPS Guidance:

$4.00 -

$4.40

Assets

(1)

:                        

$44.3B

Total Debt

(1)

:

$13.0B

Credit Rating

(2)

:                            BBB

Note: All estimates represent adjusted (Non-GAAP) Operating Earnings and EPS. Exelon Generation, ComEd and PECO estimates represent expected contribution to  

Exelon’s operating earnings EPS (per Exelon share). Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(1)

As of 12/31/06.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 12/14/07.

Pennsylvania

Utility

Illinois

Utility

’07E Earnings:

$130 -

$165M

$435 -

$470M

’08E Earnings:

$220 -

$260M

$360 -

$400M

’07 EPS:

$0.20 -

$0.25

$0.65 -

$0.70

’08 EPS:

$0.35 -

$0.40

$0.55 -

$0.60

Total

Debt

(1)

:

$4.6B

$4.2B

Credit

Ratings

(2)

:

BBB

A

4

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 1 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

5

Illinois Settlement

•

Continued ComEd membership in PJM

•

Competitive procurement for supply

•

Filed competitive declaration for 100 -

400 kW 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

Protects Competitive

Markets

Protects Value of

Generation

Provides Strategic

Flexibility

Customer Focused

•

Eliminated the IL Attorney General’s challenges to the

2006 auction

•

Financial swap at market prices

•

No generation tax

6

$4,450

$2,740

$920

$700

Cash Flow from Operations

(1)

($3,120)

($1,600)

($390)

($1,000)

Capital Expenditures

$1,220

$1,240

($50)

$300

Net Financing (excluding Dividend)

(2)

$2,550

$2,380

$480

$0

Cash available before Dividend

($1,310)

Dividend

(3)

$1,240

Cash available after Dividend

Exelon

(1)

($ in Millions)

2008 Projected Sources and Uses of Cash

(1)

Cash

Flow

from

Operations

=

Net

cash

flows

provided

by

operating

activities

less

net

cash

flows

used

in

investing

activities

other

than

capital

expenditures.

(2)

Net Financing (excluding Dividend) = Net cash flows used in financing activities excluding dividends paid on common and preferred stock.

(3)

Assumes 2008 Dividend of $2.00 per share.

(4)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

7

3-4%

$1,000

$1,060

2-3%

$1,020

$1,030

1-2%

$390

$350

2-3%

$650

$620

Exelon

(1)

NM

(2)

NM

(2)

~15%

2008-2012 CAGR

$3,120

$870

$730

2008E

$2,740

$720

$580

2007E

Other

Nuclear

Fuel

CapEx

2-3%

2-3%

2008-2012 CAGR

$4,250

$2,620

2008E

$4,090

$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)

O&M and CapEx Expectations

($ in Millions)

8

Industry Is Facing a Capital

Investment Challenge

Source: Cambridge Energy Research Associates

Current Industry Market Cap ($B)

~$750B

Generation for 230+ GWs

Transmission

Distribution

$50B Conservation & Energy Efficiency

$50B (excl. Carbon) Environmental Retrofits

CapEx Spend Next 15 Years ($B)

Investment required over the next 15 years exceeds the current

market capitalization of the entire electric industry

$300B

$350B

$150B

~$900B

9

10

10

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%

58%

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%

9.87%

9.40%

Rate settlement establishes reasonable framework for timely recovery of transmission

investment on an annual basis through formula rates

(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)

11

11

Formula Transmission Rate Annual

Update Process

(1)

•

Annual filing by May 15th 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 1st

•

Interested parties have 180 days to submit information requests

and  raise concerns; unresolved concerns go before FERC for

resolution

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

(1) Subject to final FERC approval.

12

Revenue increase needed to recover significant distribution system investment and

represents an important step in ComEd’s regulatory recovery plan

(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.

ComEd Delivery Service Rate Case Filing

(Docket No. 07-566)

$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)

13

ComEd Delivery Service Rate Case –

Schedule

•

Filed: October 17, 2007

•

Staff & Intervenor Direct Testimony: February 11, 2008

•

ComEd Rebuttal Testimony: March 12

•

Staff & Intervenor Rebuttal Testimony: April 8

•

ComEd Surrebuttal Testimony: April 21

•

Hearings: April 28 -

May 5

•

Initial Briefs: May 29

•

Reply Briefs: June 12

•

Administrative Law Judge (ALJ) Order expected: July

•

Final Illinois Commerce Commission (ICC) Order expected:

September 2008

14

Financial Swap Agreement

•

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

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

15

16

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

17

th

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

17

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

Procurement

Smart Meters

Rate Phase-in

Program

Demand Side

Response & Energy

Efficiency (DSR/EE)

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

18

2.63

2.63

0.48

0.48

2.41

6.00

10.54

PECO Average Electric Rates

(1) System

Average

Rates

based

upon

Restructuring

Settlement

Rate

Caps

on

Energy

and

Capacity

increased

from

original

settlement

by

1.6%

to

reflect

the

roll-in

of

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

on

current

sales

forecast.

Assumes

continuation

of

current

Transmission

and

Distribution

Rates.

(2) Energy/Capacity

Price

is

an

average

of

the

results

for

residential

(10.51¢/kWh)

and

small

commercial

customers

(10.58¢/kWh)

from

the

second

round

of

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)

Electric Restructuring

Settlement

+18%

13.65¢

(2)

Post Transition

Post Transition

Projected Rate Increase

Based on PPL Auction

Results  (Illustrative)

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

19

PECO Average Annual Rate Base

2.6

2.8

2.9

3.0

3.1

3.3

2.7

2.0

1.3

1.1

1.1

1.1

1.1

1.2

1.2

0.6

0.6

0.6

0.6

0.5

0.5

0.5

2007E

2008E

2009E

2010E

2011E

2012E

Gas

CTC

Electric Transmission

Electric Distribution

6.9

6.4

5.9

5.2

4.9

5.1

($ in Billions)

20

21

Exelon Generation Operating Earnings

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

fundamentals, the end of the Pennsylvania transition period, and

carbon legislation

2007E

(1)

2012

2008E

(1)

(1) 2007 and 2008 estimated contribution to Exelon operating earnings; 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

$2,060M -

$2,260M

22

Long-Run Marginal Cost of Electricity

IGCC –

No CO2

Recapture

Pulverized Coal

CCGT

Nuclear

Excluding energy efficiency, nuclear is the least expensive generation option

in a carbon-constrained environment

CCGT = Combined Cycle Gas Turbine; IGCC = Integrated Gasification Combined Cycle

0

20

40

60

80

100

120

140

0

5

10

15

20

25

30

35

40

45

50

CO2 Price ($/Metric Ton)

23

Hedging Targets

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

mitigating downside risk

(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

at

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

Target Ranges

50% -

70%

70% -

90%

90% -

98%

Above the

range*

Current Position

Upper end

of range

Midpoint of

range

Prompt Year

(2008)

Second Year

(2009)

Third Year

(2010)

Financial Hedging Range

(1)

* Due to ComEd financial swap

24

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

7

8

9

10

11

12

13

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

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

0

5

10

15

20

25

30

35

40

45

2000

2001

2002

2003

2004

2005

2006

2007

Exelon (excludes Salem)

Industry

Actual

Target

Estimate

2007 Industry data

is spring only

Impact of Refueling Outages

25

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

2%

Conversion

3%

Uranium

17%

Components of Fuel Expense in 2007

0

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

0%

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.

2007 –

2011:

100% hedged in volume

2012:

~40% hedged in volume

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

26

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

Uranium Sensitivity

(1)

(1) Excludes Salem.

27

Total Portfolio Characteristics

The value of our portfolio resides in our nuclear fleet

The value of our portfolio resides in our nuclear fleet

40,900

41,100

23,300

23,100

5,100

126,500

120,000

0

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

Expected Total Supply (GWh)

Expected Total Supply (GWh)

Expected Total Sales (GWh)

140,600

138,100

31,600

33,800

18,500

17,400

0

50,000

100,000

150,000

200,000

250,000

2007

2008

Forward / Spot Purchases

Fossil & Hydro

Nuclear

189,300

190,700

28

Financial Swap Agreement

•

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

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

29

Reliability Pricing Model Auction

40.80

197.67

111.92

148.80

102.04

191.32

191.32

Rest of Market

Eastern MAAC

                                    MAAC + APS

2007/2008

2008/2009

2009/2010

0

1,500 MW

N/A

N/A

N/A

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)

PJM RPM Auction Results ($/MW-day)

(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

in

installed

capacity

terms

(summer

ratings).

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

30

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

0

5

10

15

20

25

30

35

40

45

0

5

10

15

20

25

30

Carbon Value

Climate change legislation is expected to drive substantial gross margin expansion

at Exelon Generation

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

Assumes Open Position

(1)

Lieberman-Warner

Possible $20 to $40/tonne

EIA Carbon Case

(3)

2010: $31/tonne

Bingaman-Specter

(4)

2012: $12/tonne

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 12/11/07.

(3) The

EIA

Carbon

Stabilization

Case

(Case

4)

dated

March

2006,

EIA

report

number

SR/OIAF/2006-1.

(4)

Low

Carbon

Economy

Act

initial

“Technology

Accelerator

Payment”

(TAP)

price

in

2012.

Allowance

price

increases

at

5%

above

the

rate

of

inflation

thereafter.

Europe Carbon Trading

2012: $36.50/tonne

(2)

31

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

•

Long-lead material for dual unit ESBWR has been reserved

•

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

32

Exelon Nuclear Fleet Overview

2011

42.6% Exelon, 56.4 %

PSEG

2016, 2020

969

(1)

W

PWR

2

Salem, NJ

Life of plant capacity

100% AmerGen

2014; renewal to be

filed 2008

837

B&W

PWR

1

TMI-1, PA

Dry cask

100% AmerGen

2009; renewal filed

2005

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50% PSEG

Renewed: 2033,

2034

1135

(1)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

1303

(1)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

871, 871

GE

BWR

2

Dresden, IL

2012

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask in process

100%

2024, 2029

1151, 1151

GE

BWR

2

Limerick, PA

Re-rack completed

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

GE

W

W

Vendor

BWR

PWR

PWR

Type

1

2

2

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

MW

Plant, Location

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

(1) Capacity based on ownership interest.

33

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

•

Loan guarantee volume

dependent upon congressional

appropriations action

•

Cost of credit subsidy is still

uncertain

Government Loan

Guarantee

•

“Insurance”

protecting against

regulatory and litigation-related

delays in commissioning a

completed plant

•

Eligible costs include principal

and interest on debt coverage and

the incremental cost of

replacement power

–

First two reactors each

receive 100% of covered

costs up to $500M

–

The next four reactors each

receive 50% of covered costs

incurred after six months of

delay, up to $250M

Regulatory Delay

“Backstop”

Energy Policy Act provides financial incentives and reduced risk

by way of

production tax credits and loan guarantees

34

Announced Nuclear Projects

22 projects totaling ~40,000 MWs have been announced

Letter of intent

Greenfield

western Idaho

TBD

TBD

Mid-American Nuclear

Announced intent

Greenfield

San Joaquin Valley  CA

EPR

1

Fresno Nuclear Energy

Announced intent

Greenfield

Bruneau

ID

EPR

1

Alternative Energy Hldings

Letter of intent

Operating

Turkey Pt   FL

TBD

TBD

FPL

Letter of intent

Operating

Susquehanna  PA

EPR

1

PPL

Letter of intent

Operating

Fermi  MI

TBD

1

DTE Energy

Letter of intent

Greenfield

Victoria

TX

ESBWR

2

Exelon

Letter of intent

Operating

Comanche Peak TX

APWR

2

TXU

Letter of intent

Operating

Callaway  MO

EPR

1

Unistar/Ameren

Letter of intent

Operating

Nine Mile Pt  NY

EPR

1

Unistar

COL submitted Sept 2007

Operating

South Texas Project  TX

ABWR

2

NRG Energy

Letter of intent

Greenfield

Amarillo  TX

EPR

2

Amarillo Power

COL Jan 2008

Operating

Harris  NC

AP1000

2

Progress

COL 2008

Operating

Vogtle

GA

AP1000

2

Southern

COL May 2008

Operating

River Bend  LA

ESBWR

1

Entergy

COL submitted December 2007

Characterized

Lee  SC

AP1000

2

Duke

COL July 2008

Greenfield

Levy Co.  FL

AP1000

2

Progress

Letter of intent

Operating

Summer  SC

AP1000

2

South Carolina E&G

ESP approved; COL February 2008

Operating

Grand Gulf  MS

ESBWR

1

Entergy/NuStart

COL submitted Oct 2007.  Reference plant for AP1000

Characterized

Bellefonte  AL

AP1000

2

TVA/NuStart

Reference plant for ESBWR COL application; submitted

November 2007; ESP approved

Operating

North Anna  VA

ESBWR

1

Dominion

Partial COL submitted; remainder expected in 2007

Operating

Calvert Cliffs  MD

EPR

1

Unistar

Status

Type of site

Site

Technology

Units

Applicant

35

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 submitted

to NRC.  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

•Exelon

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.

36

0

1

2

3

4

5

6

7

8

9

10

Building a new nuclear plant is not a one-step process or

decision:  It is a sequence of 3 successive decisions

Years (estimates)

1

2

3

First Decision: File an application for a COL

Second Decision: Procure major long-lead

procurement components and commodities

Third Decision: Proceed

with construction

Source: Exelon estimates.

Roadmap to Nuclear Commercial

Operation

37

0

20

40

60

80

100

120

140

160

Uranium Price Volatility

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

0

20

40

60

80

100

120

140

160

Seven-Month Uranium Price Trend

Long-term Uranium Price Trend

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)

38

Current Market Prices

1.

2004, 2005 and 2006 are actual settled prices.

2.

Real Time LMP (Locational Marginal Price).

3.

Next day over-the-counter market.

4.

Average NYMEX settled prices.

5.

2007 information is a combination of actual prices through 12/14/07 and market prices for the balance of the year.

6.

2008 and 2009 are forward market prices as of 12/14/07.

PRICES (as of December 14, 2007)

Units

2004

1

2005 1

2006 1

2007

5

2008

6

2009

6

PJM West Hub ATC

($/MWh)

42.35 2

60.92 ²

51.07

2

60.52

59.36

57.91

PJM NiHub

ATC

($/MWh)

30.15 2

46.39 ²

41.42 2

46.20

44.92

44.75

NEPOOL MASS Hub ATC

($/MWh)

52.13 2

76.65 ²

59.68 2

68.03

75.08

72.20

ERCOT North On-Peak

($/MWh)

49.53 3

76.90 ³

60.87

3

59.53

75.85

73.19

Henry Hub Natural Gas

($/MMBTU)

5.85

4

8.85

4

6.74

4

6.97

8.25

7.95

WTI Crude Oil

($/bbl)

41.48

4

56.62

4

66.38

4

69.72

90.50

87.48

PRB 8800

($/Ton)

5.97

8.06

13.04

9.67

12.03

12.18

NAPP 3.0

($/Ton)

60.25

52.42

43.87

47.54

57.62

55.08

ATC HEAT RATES (as of December 14, 2007)

PJM West Hub / Tetco

M3

(MMBTU/MWh)

6.40

6.30

6.98

7.77

7.04

6.31

PJM NiHub

/ Chicago City Gate

(MMBTU/MWh)

5.52

5.52

6.32

6.74

6.02

5.43

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.53

8.21

8.28

8.97

9.19

9.46

39

8.84

9.04

9.24

9.44

9.64

9.84

10.04

10.24

10.44

10.64

10.84

1-07

2-07

3-07

4-07

5-07

6-07

7-07

8-07

9-07

10-07

11-07

12-07

39

7

7.2

7.4

7.6

7.8

8

8.2

8.4

8.6

8.8

1-07

2-07

3-07

4-07

5-07

6-07

7-07

8-07

9-07

10-07

11-07

12-07

55

60

65

70

75

80

85

90

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

7.4

7.6

7.8

8

8.2

8.4

8.6

8.8

9

9.2

9.4

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

Market Price Snapshot

As of December 14, 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

2008

2009

2009

2008

2008 PJM-West

2009 PJM-West

2009 Ni-Hub

2008 Ni-Hub

2008

2009

40

25

27

29

31

33

35

37

39

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

40

42

44

46

48

50

52

54

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

40

42

44

46

48

50

52

54

56

58

60

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

50

52

54

56

58

60

62

64

66

68

70

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

Market Price Snapshot

PJM-West ATC Forward Prices

2008

2009

PJM-West Wrap Forward Prices

2008

2009

NIHUB ATC Forward Prices

NIHUB Wrap Forward Prices

2009

2008

2009

2008

As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

41

47

49

51

53

55

57

59

61

63

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

7.7

7.8

7.9

8

8.1

8.2

8.3

8.4

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

56

58

60

62

64

66

68

70

72

74

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

7

7.5

8

8.5

9

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

Market Price Snapshot

2008

2009

2009

2008

2008

2009

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

As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

42

42

65

67

69

71

73

75

77

79

81

83

85

1/07

2/07

3/07

4/07

5/07

6/07

7/07

8/07

9/07

10/07

11/07

12/07

Market Price Snapshot

ERCOT North On-Peak Forward Prices

2008

2009

As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

43

Exelon –

Climate Change

44

Advancing Exelon’s Low-Carbon Strategy

•

Lobbying in favor of climate change legislation that is

national, mandatory

and economy-wide

•

Taking voluntary action to reduce our greenhouse gas

(GHG) emissions 8% from 2001 levels by 2008

•

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

45

Recognized Environmental Leadership

•

Named to 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

46

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) –

ramping 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 fleet

•

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

47

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

to

help

offset

the

cost

of

carbon

for

the

end-

user

•

To limit near-term economic impacts, supports a cost containment

mechanism, such as a safety valve, that supports a market price for

carbon that increases over time

48

Reduction Goals

0

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

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

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

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.

49

0

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

Source:  Electric Power Research Institute

To stabilize emissions at 1990 levels, multiple technologies and

intensive R&D

will be required

CO2 Reductions Demand Multiple Generation

Technologies

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,

demonstration, and

deployment are required

50

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)

•

Approved by U.S. Senate Environment and Public Works Committee

•

Slated for action by the full U.S. Senate in the Spring

•

Needs 60 votes to break expected filibuster and pass

•

Economy-wide:  All major GHG producing sectors

–

Seeks to reduce GHG to the 2005 level by 2012; phases to 70% below the 2005 level by 2050

–

Points of regulation: Electric power sector –

large coal generators; Natural gas –

natural gas processors

and importers; Industrial sector –

large facilities emitting more than 10,000 tonnes per year

–

“Free”

allowances include: 10% to states, 19% to generators (phase out

in 2031); 10% to industry; 9% to

electric distribution companies, to benefit their customers; 2% to gas distribution companies, to benefit

their customers

–

Creates a Carbon Market Efficiency Board (“Carbon Fed”) with limited authority to oversee market

–

Dingell-Boucher White Paper

•

Seeks to reduce emissions by 60% to 80% by 2050

•

Best achieved by a cap-and-trade system

51

GAAP Reconciliation

52

Reconciliation of Net Income to EBITDA

GAAP net income (loss)

+/-

Impact of certain non-operating items

Adjusted non-GAAP net income (loss)

+/-

Cumulative effect of changes in accounting principle

+/-

Discontinued operations

+/-

Minority interest

+   Income taxes

Adjusted non-GAAP income (loss) from continuing operations

before income taxes and minority interest

+  Interest expense

+  Interest expense to affiliates

-

Interest income from affiliates

+  Depreciation and amortization

Adjusted non-GAAP earnings before interest, taxes,

depreciation and amortization (adjusted non-GAAP EBITDA)

53

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

54

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

55

GAAP Earnings Reconciliation

Year Ended December 31, 2006

776

-

-

776

-

Impairment of ComEd’s goodwill

(52)

-

-

(52)

-

Recovery of debt costs at ComEd

(89)

-

-

-

(89)

Nuclear decommissioning obligation reduction

(95)

-

-

(95)

-

Recovery of severance costs at ComEd

$(83)

-

1

36

24

-

$(144)

Other

$2,175

1

18

58

24

(58)

$1,592

Exelon

$455

-

4

10

-

-

$441

PECO

$528

-

4

4

-

3

$(112)

ComEd

ExGen

(in millions)

9

Severance charges

8

Charges related to now terminated merger with PSEG

$1,275

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

1

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.

56

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

0.01

-

-

ComEd

(1)

-

-

-

(0.13)

0.01

0.01

-

(0.09)

ExGen

(1)

-

-

-

-

0.01

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.

57

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

58

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

59

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 (2007 only)

–

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

60

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

Karie Anderson, Director

312-394-4255

Karie.Anderson@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com

Len Epelbaum, Principal Analyst

312-394-7356

Len.Epelbaum@ExelonCorp.com