Commonwealth Edison 8-K This presentation includes forward-looking statements within the meaning of the Private Securities

UBS Natural Gas, Electric Power &

Coal Conference

Lost Pines, TX

March 6, 2008

Exhibit 99.1

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 2007 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 19; and (2) 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 Companies. Please refer to the appendix to the

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

3

’07 Earnings:

$2,331M 

’08E Earnings:

$2,060 -

$2,260M

’07 EPS:

$3.45

’08E EPS:

$3.15 -

$3.45

Total Debt

(1)

:

$2.5B

Credit Rating

(2)

:

BBB+

The Exelon Companies

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘07 Operating Earnings:

$2.9B

‘07 EPS:

$4.32

‘08E Operating Earnings:

$2.6

-

$2.9B

‘08 EPS Guidance:

$4.00

-

$4.40

Assets

(1)

:                        

$45.9B

Total Debt

(1)

:

$13.7B

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 12/31/07.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 2/29/08.

Pennsylvania

Utility

Illinois

Utility

’07 Earnings:

$200M

$507M

’08E Earnings:

$220 -

$260M

$360 -

$400M

’07 EPS:

$0.30

$0.75

’08E EPS:

$0.35 -

$0.40

$0.55 -

$0.60

Total Debt

(1)

:

$5.2B

$3.8B

Credit Ratings

(2)

:

BBB

A

4

Multi-Regional, Diverse Company

Note: Megawatts based on Generation’s ownership as of 12/31/07,

using annual mean ratings for nuclear units (excluding Salem) and

summer ratings for Salem and the fossil and hydro units.

Midwest Capacity

Owned:

11,388 MW

Contracted:

4,271 MW

Total:

15,659 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

194MW

Total Capacity

Owned:

24,808 MW

Contracted:

7,524 MW

Total:

32,332 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:

11,004 MW

Contracted:

336 MW

Total:

11,340 MW

5

2008 Outlook

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

ComEd

PECO

Exelon Generation

HoldCo/Other ~$(0.10)

Exelon

(1)

Refer

to

Appendix

for

“Key

Assumptions”

slide

supporting

2008

earnings

guidance.

Operating

Company

ranges

do

not

add

to

Exelon

guidance

of

$4.00 -

$4.40/share due to rounding.

Key Drivers 2007 –

2008

Market conditions

Nuclear volume

Inflationary pressures

PECO CTC amortization

Weather

Load growth

ComEd transmission settlement

ComEd distribution rate case

26-29%

26-29%

21-24%

21-24%

4Q08

3Q08

2Q08

1Q08

Expected Quarterly EPS Distribution

We expect first quarter 2008 operating earnings to represent 21-24% of Exelon’s 2008

full year operating earnings.

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

(4)

($ 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

$1,040

2-3%

$1,020

$1,083

1-2%

$390

$339

2-3%

$650

$630

Exelon

(1)

NM

(2)

NM

(2)

~15%

2008-2012 CAGR

$3,120

$870

$730

2008E

$2,674

$696

$573

2007

Other

Nuclear

Fuel

CapEx

2-3%

2-3%

2008-2012 CAGR

$4,270

$2,620

2008E

$4,203

$2,469

2007

Exelon

(1)

O&M

Note:  Reflects operating O&M data and excludes Decommissioning 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

Disciplined Financial Management

•

Announced a new Value Return Policy in December 2006

–

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

Announced in December 2007:

•

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

(up 14%); 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.

The

Value

Return

Policy

provides

flexibility

to

navigate

through

volatile

business

cycles, make prudent investments in our operations, and return value to investors

9

Balance Sheet Capacity

•

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.

(4)

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

upon as a forecast of future results.

2008

-

2012

Cumulative

Available

Cash

(Illustrative)

(4)

2008 -

2012 Potential Uses of

Available Cash

Exelon

expects

to

create

substantial

incremental

balance

sheet

capacity

over

the

next

five years, based on planning assumptions

10

ComEd and PECO

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

of

which

are

subject

to

uncertainties

and

should

not

be

relied upon as a forecast of future results.

(2)

ComEd equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill).  Book equity ratio in 2007 was 58%.

(3)

ComEd 2008

estimated

operating

earnings

assume

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)

$200M

~5.5 -

6.5%

5.3%

45%

45%

7.8

8.6

~$460 -

$500M

~10 -

11%

~45%

2007E

2008E

2011

(1)

10.2

6.9

6.4

2007E

2008E

2011

(1)

4.9

~$245 -

$270M

~10 -

11%

~50%

$507M

Not applicable due to

transition rate structure

$360 -

$400M

Operating Earnings

ROE

Equity

(2)

2007A

2007A

2.6

2.8

3.1

0.5

0.5

0.6

2.7

2.0

1.1

1.1

1.2

Average Annual Rate Base

($ in Billions)

11

12

ComEd 2008 Operating EPS Contribution

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

of its Regulatory Recovery Plan

2007

$200M

RNF

O&M

Depreciation /

Amortization

Interest

Expense

Other

$0.35 -

$0.40

$0.30

$0.19

$0.04

($0.02)

$(0.03)

2008

(1)

$220M -

$260M

(2)

$(0.08)

Key Items:

Storms: $0.03

Uncollectible accounts: $0.02

($0.04)

Weather

$ / 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: $0.04

Load growth: $0.03

Key Items:

Income tax settlements: $(0.07)

13

(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)

Revenue increase needed to recover significant distribution system investment and

represents an important step in ComEd’s regulatory recovery plan

14

ComEd Delivery Service Rate Case –

Schedule

•

Filed: October 17, 2007

•

Staff

&

Intervenor

Direct

Testimony:

February

11,

2008

Staff proposal:

–

$112 million revenue increase

–

$5.7 billion rate base

–

Common equity ratio: 45.04%, ROE: 10.30%, ROR: 8.34%

•

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

15

15

15

ComEd Transmission Rate Case

($ in millions)

FERC Filing

3/1/07

Preliminary Order

6/5/07

FERC Orders

1/08

(1)

Total Revenue Requirement (in year 1)

$415

$387

$390

(2)

Revenue Requirement increase (in year 1)

$146

$116

(3)

$120

Rate Base (in year 1)

$1,826

$1,744

$1,847

(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%

(1) Settlement agreement filed 10/5/07, approved by FERC on 1/16/08.  Also, on 1/18/08

FERC granted request on rehearing for incentive on West Loop Phase II project.

(2) Includes settlement increase of $93 million + project incentives of $27 million, eff. 5/1/07.

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

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

includes $175 million construction work in progress (CWIP) for West Loop project.

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

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

RTO = Regional Transmission Organization

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

Rate settlement establishes reasonable framework for timely recovery of transmission

investment on an annual basis through formula rates

16

16

Formula Transmission Rate Annual

Update Process

•

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

17

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

18

19

PECO 2008 Operating EPS Contribution

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

increasing CTC amortization expense

2007

$507M

2008

(1)

$360M -

$400M

$0.75

($0.08)

$0.01

($0.03)

($0.06)

$0.55 -

$0.60

RNF

O&M

CTC

Amortization /

Depreciation

Other

NOTE:

Refer

to

“Key

Assumptions”

slide

in

Appendix.

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

($0.03)

Weather

$0.02

Interest

Expense

$ / Share

Key Items:

Tax settlements: $(0.08)

20

Pennsylvania Snapshot

•

Governor Rendell’s “Energy Independence Strategy”,

introduced in February 2007, continues to be focus of

legislative activity. 

Legislation aimed at reducing energy costs, increasing

clean energy resources, reducing reliance on foreign

fuels, expanding energy production in PA

Comprehensive bills dealing with procurement, and

rate mitigation remain in committee

Modest action on other key bills: Energy Fund bill

passed in Senate; House passed an Efficiency

/Demand-side Response bill.

•

Special Session on Energy runs concurrent with Regular

Session which continues thru Nov ’08.

Current State of Play

•

Governor continues to press for “Energy Independence

Fund”

and measures to mitigate energy prices

•

Legislators concerned with cost of Governor's initiatives, no

new taxes

•

Rate freeze bill being considered in House, but little

momentum

•

Industry coalition working together to develop a

comprehensive package

Positions of Stakeholders

•

Stakeholder outreach

•

Working with industry coalition

•

Negotiating legislative proposals with

Administration and legislative leadership

on key provisions:

Procurement rules

Rate increase phase-in/deferral

Smart meters and real time pricing

Energy efficiency and demand-side

management programs

•

Participating directly or through industry

associations in legislative hearings and

informational meetings

PECO Actions

21

Key Themes of Legislative Proposals

Competitive procurement process utilizing auctions, RFPs, spot purchases

and bilateral contracts, with provisions for long-term supply contracts

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

Largest industrial customers may negotiate terms and rates for retail supply

with DSP, subject to PUC review

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; cap annual increases for

defined period and defer any excess for future recovery over additional

defined period

Phase-in

plans

-

both

pre

and

post

-

are

to

be

opt-in

for

customer,

provide

utility and/or customer with recovery of carrying costs on pre-pay and/or

deferred balance

Securitization of deferred balance and carrying charges authorized

Establish

minimum

usage

reduction

and

peak

load

reduction

targets

Competing legislative proposals call for either DSP-run programs or

State-wide

Program

Administrator

with

network

of

3

party

suppliers

Cost cap proposed, with DSP authorized to fully recover expenses

Full deployment of smart meters within 9-10 years

Full

recovery

for

net

costs

of

smart

meter

deployment

through

base

rates

or

through automatic recovery mechanism

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

the end of rate cap period

Procurement

Smart Meters

Rate Phase-in

Program

Demand Side

Response & Energy

Efficiency (DSR/EE)

22

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)

+18%

13.65¢

(2)

CTC terminates at year-end 2010

Energy / Capacity price expected

to increase; price will reflect

associated full requirements

costs

Using latest PPL auction for

2010 as a proxy (10.5¢/kWh)

results in a system average

rate increase of ~18%

PECO’s 2011 full requirements

price expected to differ from PPL

due, in part, to the timing of the

procurement and locational

differences

Rates will vary by customer class

and will depend on legislation and

approved procurement model

Post Transition

Electric Restructuring

Settlement

Projected Rate Increase

Based on PPL Auction

Results  (Illustrative)

23

24

Exelon Generation 2008 Operating EPS

Contribution

Exelon Generation’s 2008 earnings are impacted primarily by increased planned refueling

outages and higher nuclear fuel expense

2007

$2,331M

2008

(1)

$2,060M -

$2,260M

($0.09)

$(0.15)

$0.13

$3.15 -

$3.45

RNF

O&M

Other

(2)

$30M

+/-

500 Btu/KWh ATC Heat Rate

$5.5M

+/-

$1/mmBtu Gas

2008

Market Sensitivities  (After-Tax)

Depreciation

$(0.02)

$3.45

$ / Share

NOTE:

Refer

to

“Key

Assumptions”

slide

in

Appendix.

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

(2)  Primarily reflects the change in shares outstanding.

Key Items:

Nuclear volume: $(0.10)

Nuclear fuel expense: $(0.06)

State Line buyout: $(0.03)

Market / portfolio: $0.12

Interest

Expense

$(0.03)

Key Items:

Inflation: $(0.07)

Add’l

refueling outages: $(0.06)

Nuclear security: $(0.02)

25

•

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

•

Complementary and flexible fossil and

hydro fleet

•

Improving power market fundamentals

(commodity prices, heat rates, and

capacity values)

•

End of below-market contracts in

Pennsylvania beginning 2011

•

Potential carbon restrictions

Value Proposition

Exelon Generation

•

Continue to focus on operating excellence,

cost management, and market discipline

•

Support competitive markets

•

Pursue nuclear & hydro plant 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

Exelon

Generation

is

the

premier

unregulated

generation

company

–

positioned

to

capture market opportunities and manage risk

26

World-Class Nuclear Operator

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

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

Sources:

Platt’s,

Nuclear

News,

Nuclear

Energy

Institute

and

Energy

Information

Administration

(Department

of

Energy).

EXC 93.5%

(1)

(1) Exelon values represent 2003-2007 period.

Average Capacity Factor

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

Sustained production excellence

65

70

75

80

85

90

95

100

Operator (# of Reactors)

Range

5-Year Average

27

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2007

2008

2009

2010

2011

2012

PJM-West

PJM-East

NI-Hub

ERCOT

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

Carbon Credit ($/Tonne)

Various

3rd

party

estimates

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 2/28/08.

Reserve Margins Declining

Natural Gas Prices Remaining High

Construction Costs Escalating

Carbon Legislation Progressing

Europe Carbon-Trading

2012: $36.10/tonne

Bingaman-Specter

2012: $12/tonne

EIA Carbon Case

2010: $31/tonne

Lieberman-Warner

Possible $20 to $40/tonne

$5

$6

$7

$8

$9

$10

2008

2010

2012

2014

2016

2018

2020

28

2008 “Open”

EBITDA

2008 EBITDA

2008 Un-hedged EBITDA

(No Carbon)

$ Millions

$4,119

~$3,900

2007 EBITDA

(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.

Note: Refer to Appendix for EBITDA reconciliation slide.

~$5,350

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:

$2,331

Hedged –

2007A

Hedged –

2008E

Un-hedged –

2008E

(1)

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

Exelon Generation’s value

29

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

Exelon Generation Operating Earnings

2007

(1)

2012

2008E

(1)

(1) 2007 and estimated 2008 contribution to Exelon operating earnings; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

$2,331M

$2,060M -

$2,260M

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

fundamentals, the end of the Pennsylvania transition period, and

carbon legislation

30

Hedging Targets

(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

5

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

Financial Hedging Range 

(1)

* Due to ComEd financial swap

Prompt Year

(2008)

Second Year

(2009)

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

mitigating downside risk

Third Year

(2010)

31

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

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

0

5

10

15

20

25

30

35

40

45

2000

2001

2002

2003

2004

2005

2006

2007

Exelon (excludes Salem)

Industry

Actual

Target

Impact of Refueling Outages

Refueling Outage Duration

Nuclear Output

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

32

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

2008

2009

2010

2011

2012

Effectively Managing Nuclear Fuel Costs

Enrichment

39%

Fabrication

17%

Nuclear Waste

Fund

22%

Tax/Interest

2%

Conversion

3%

Uranium

17%

0

200

400

600

800

1,000

1,200

1,400

2008

2009

2010

2011

2012

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

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.

2008 –

2011:

100% hedged in volume

2012:

~40% hedged in volume

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

Projected Exelon Uranium Demand

Components of Fuel Expense in 2008

Projected Exelon Average Uranium Cost vs. Market

Projected Total Nuclear Fuel Spend

33

Market Price Sensitivities

~$60M

+/-

500 Btu/KWh ATC Heat Rate

~$10M

+/-

$1/mmBtu Gas Price

(Pre-Tax Impact)

2008 EBITDA Sensitivities

($80M)

($40M)

($20M)

($5M)

-

Expense (Pre-Tax Impact)

($335M)

($160M)

($100M)

($60M)

-

Capital Expenditures

2012

2011

2010

2009

2008

-

$50/lb

$40M

$15M

$10M

$5M

-

Expense (Pre-Tax Impact)

$280M

$85M

$30M

$20M

-

Capital Expenditures

2012

2011

2010

2009

2008

+ $50/lb

(1)

Excludes Salem.

Note: Refer to Appendix for EBITDA reconciliation slide.

Uranium Sensitivity

(1)

34

Total Portfolio Characteristics

41,350

41,100

23,200

23,100

5,100

120,000

125,100

0

50,000

100,000

150,000

200,000

250,000

2007A

2008E

Actual Hedges & Open Position

ComEd Swap

IL Auction

PECO Load

189,300

189,650

140,400

138,100

31,800

33,800

17,450

17,400

0

50,000

100,000

150,000

200,000

250,000

2007A

2008E

Forward / Spot Purchases

Fossil & Hydro

Nuclear

189,300

189,650

Total Supply (GWh)

Total Sales (GWh)

The value of our portfolio resides in our nuclear fleet

35

35

Reliability Pricing Model Auction

40.80

197.67

111.92

174.29

174.29

148.80

102.04

191.32

191.32

Rest of Market

Eastern MAAC

        MAAC + APS

                              MAAC

2007/2008

2008/2009

2009/2010

2010/2011

2007 / 2008

2008 / 2009

2009 / 2010

2010 / 2011

in MW

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Rest of Market

16,000

(4)

6,600-6,800

14,500

(5)

6,600-6,800

12,700

4,750-4,950

(6)

12,700

0

Eastern MAAC

9,500

9,500-9,800

(3)

9,500

9,550-9,850

(3)

9,500

9,750-9,950

(3)

MAAC + APS

(7)

1,500

0

MAAC

11,000

9,300-9,500

(3)(8)

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

(2)  All

capacity

values

are

in

installed

capacity

terms

(summer

ratings)

located

in

the

areas.

(3)  EMAAC

obligation

consists

of

load

obligations

from

PECO

and

BGS.

The

PPL

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

begins January 2010 and ends December 2010.

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

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

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

(8) PECO PPA expires December 2010.

Region not applicable for this auction period

PJM RPM Auction ($/MW-day)

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

36

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

Midwest

•

~90,000 GWhs in Midwest

nuclear portfolio

•

~55% of time coal on the margin

•

~40% of time gas on the margin

Mid-Atlantic

•

~50,000 GWhs in Mid-Atlantic

nuclear portfolio

•

~45% of time coal on the margin

•

~50% of time gas on the margin

Assumes

Open

Position

(1)

Carbon Credit ($/Tonne)

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

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

(2) As of 2/29/08.

(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.

Carbon Value

Climate change legislation is expected to drive substantial gross margin expansion

at Exelon Generation

Europe Carbon Trading

2012: $36.10/tonne

(2)

EIA Carbon Case

(3)

2010: $31/tonne

Lieberman-Warner

Possible $20 to $40/tonne

Bingaman-Specter

(4)

2012: $12/tonne

37

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

–

Will

use

GE

Hitachi

Nuclear

Energy

Americas’

new

generation

of

reactor

technology

•

Texas

is

attractive

market

for

new

nuclear

–

selected

site

in

Victoria

County

–

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

38

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

•

Congress has granted authority

to issue guarantees totaling

$18.5B though 9/30/09

•

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

39

Current Market Prices

1.

2004, 2005, 2006 and 2007 are actual settled prices.

2.

Real Time LMP (Locational Marginal Price).

3.

Next day over-the-counter market.

4.

Average NYMEX settled prices.

5.

2008 information is a combination of actual prices through 2/29/08 and market prices for the balance of the year.

6.

2009 information is forward market prices as of 2/29/08.

Units

2004

1

2005

1

2006

1

2007

1

2008

5

2009

6

PRICES (as of February 29th, 2008)

PJM West Hub ATC

($/MWh)

42.35

2

60.92

2

51.07

59.76

74.29

75.06

PJM NiHub

ATC

($/MWh)

30.15

2

46.39

2

41.42

2

45.47

57.27

58.67

NEPOOL MASS Hub ATC

($/MWh)

52.13

2

76.65

2

59.68

2

66.72

84.37

85.17

ERCOT North On-Peak

($/MWh)

49.53

3

76.90

3

60.87

3

59.44

83.06

83.05

Henry Hub Natural Gas

($/MMBTU)

5.85

4

8.85

4

6.74

4

6.95

9.36

9.36

WTI Crude Oil

($/bbl)

41.48

4

56.62

4

66.38

4

69.72

98.80

98.37

PRB 8800

($/Ton)

5.97

8.06

13.04

9.67

15.82

17.01

NAPP 3.0

($/Ton)

60.25

52.42

43.87

47.54

76.44

77.06

ATC HEAT RATES (as of February 29th, 2008)

PJM West Hub / Tetco

M3

(MMBTU/MWh)

6.40

6.30

6.98

7.68

7.14

7.17

PJM NiHub

/ Chicago City Gate

(MMBTU/MWh)

5.52

5.52

6.32

6.65

6.10

6.25

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.53

8.21

8.28

7.80

7.96

7.76

2

40

40

Market Price Snapshot

As of February 27, 2008. Source: OTC quotes and electronic trading system. Quotes are daily.  2008 prices are Mar-Dec.

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

7.4

7.9

8.4

8.9

9.4

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

8.84

9.04

9.24

9.44

9.64

9.84

10.04

10.24

10.44

10.64

10.84

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

55

60

65

70

75

80

85

90

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

7

7.2

7.4

7.6

7.8

8

8.2

8.4

8.6

8.8

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

41

41

Market Price Snapshot

2008

2009

2008

2009

As of February 27, 2008. Source: OTC quotes and electronic trading system. Quotes are daily.  2008 prices are Mar-Dec.

2008

2009

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North ATC Forward Prices

ERCOT North ATC v. Houston Ship Channel

Implied Heat Rate

7.1

7.6

8.1

8.6

9.1

9.6

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

7.5

7.7

7.9

8.1

8.3

8.5

8.7

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

58

60

62

64

66

68

70

72

74

Mar-

07

Apr-

07

May-

07

Jun-

07

Jul-

07

Aug-

07

Sep-

07

Oct-

07

Nov-

07

Dec-

07

Jan-

08

Feb-

08

42

Exelon –

Climate Change

43

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

•

Developing a comprehensive low-carbon energy strategy

–

Goal will be to reduce, displace or offset Exelon’s entire carbon footprint by 2020

–

Expanding our low-carbon resources

–

Providing customers with green products and services

–

Being a model of green operations

44

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

45

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

that

supports

a

market

price

for

carbon

that

increases

over

time

46

Reduction Goals

47

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,  2007 Summer Seminar

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

To

stabilize

emissions

at

1990

levels,

multiple

technologies

and

intensive

R&D

will be required

48

Status of Legislative Initiatives

•

Several pending Legislative proposals and vehicles are gaining support in

Washington:

–

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 Papers

•

Scope of a Cap-and-Trade Program

•

Competitiveness Concerns/Engaging Developing Countries

•

Appropriate Roles for Different Levels of Government

•

More white papers in the works

•

Expect a draft bill sometime this summer

•

Dingell

has

characterized

the

issue

as

“the

hardest

thing

(he’s)

ever

dealt

with”

in

his

52+

years

in

Congress

•

Boucher says he is committed to enacting legislation this year

•

All the major Presidential contenders (McCain, Clinton and Obama) support

economy-wide, mandatory cap-and-trade legislation

49

Appendix

50

Key Assumptions

37.7

1.2

2.6

23.86

115.37

6.65

6.84

45.47

7.68

7.78

59.76

6.95

148,307

41,343

(5)

189,650

94.5

2007A

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

2008E

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)

2006A

2005A

(1)

Excludes Salem.

(2)

2007 actual and 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.

Note: 2005, 2006 and 2007 prices are average for the year; 2008 prices reflect observable prices as of 7/31/07.

51

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.

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 Earnings Reconciliation

Year Ended December 31, 2007

(5)

-

-

-

(5)

Settlement of a Tax Matter at Generation Related to Sithe

72

-

-

-

72

Georgia Power Tolling Agreement

(130)

-

-

-

(130)

Termination of State Line PPA

14

-

-

14

-

City of Chicago Settlement

(11)

-

-

-

(11)

Sale of Generation’s investments in TEG and TEP

$(115)

(63)

-

-

(87)

-

$35

Other

$2,923

(29)

280

(18)

(87)

101

$2,736

Exelon

$507

-

-

-

-

-

$507

PECO

$200

-

24

-

-

(3)

$165

ComEd

ExGen

(in millions)

256

2007 Illinois Electric Rate Settlement

(18)

Nuclear decommissioning obligation reduction

$2,331

2007 Adjusted (non-GAAP) Operating Earnings (Loss)

34

Non-Cash Deferred Tax Items

-

Investments in synthetic fuel-producing facilities

104

Mark-to-market adjustments from economic hedging activities

$2,029

2007 GAAP Reported Earnings (Loss)

Note: Amounts may not add due to rounding.

54

(1)

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

(0.01)

-

-

-

(0.01)

Settlement of a tax matter at Generation related to Sithe

(0.04)

(0.08)

-

-

0.04

Non-cash deferred tax items

(0.14)

(0.14)

-

-

-

Investments in synthetic fuel-producing facilities

0.41

-

-

0.03

0.38

2007 Illinois electric rate settlement

(0.19)

-

-

-

(0.19)

Termination of State Line PPA

0.11

-

-

-

0.11

Georgia Power tolling agreement

Exelon

Other

(1)

PECO

(1)

ComEd

(1)

ExGen

(1)

$4.32

$(0.18)

$0.75

$0.30

$3.45

2007 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.01)

-

-

-

(0.01)

Sale of Generation's investments in TEG and TEP

0.02

-

-

0.02

-

City of Chicago settlement

(0.03)

-

-

-

(0.03)

Nuclear decommissioning obligation reduction

0.15

-

-

-

0.15

Mark-to-market adjustments from economic hedging activities

$4.05

$0.04

$0.75

$0.25

$3.01

2007 GAAP Earnings Per Share

GAAP EPS Reconciliation

Year Ended December 31, 2007

55

2008 Earnings Outlook

•

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

excludes the earnings impacts of the following:

–

mark-to-market adjustments from economic hedging activities

–

unrealized gains and losses from nuclear decommissioning trust fund

investments

–

significant impairments of intangible assets, including goodwill

–

significant changes in decommissioning obligation estimates

–

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

previously announced customer rate relief programs

–

costs associated with ComEd’s settlement with the City of Chicago

–

other unusual items

–

significant future changes to GAAP

•

Both our operating earnings and GAAP earnings guidance are

based on the assumption of normal weather

56

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