Commonwealth Edison 8-K Barclays Capital CEO Energy/Power Conference

1

Barclays Capital CEO Energy/Power Conference

William A. Von Hoene, Jr., EVP Finance and Legal

September 9, 2009

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 2008

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 Second Quarter

2009 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

14

and

(3) other factors discussed in filings with the Securities and Exchange Commission (SEC)

by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and

Exelon Generation Company, LLC (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.

3

Key Messages

•

Consistently operating the largest nuclear fleet in the U.S. at

world-class levels

•

Executing hedging program to protect the value of our assets

•

Achieving constructive financial and regulatory results at

ComEd and PECO

•

Delivering on cost savings commitments

•

Pursuing financially disciplined organic growth across the

business

•

Improving long-term financial flexibility, including a discretionary

pension contribution

4

70%

75%

80%

85%

90%

95%

Range

5 Year Average

Operational Excellence Across the Fleet

Nuclear Capacity Factor

Production Cost ($/MWh)

Exelon Power Fleet Availability

$10.00

$11.00

$12.00

$13.00

$14.00

$15.00

$16.00

$17.00

$18.00

$19.00

$20.00

2003

2004

2005

2006

2007

2008

Exelon

Industry (excl. Exelon)

EXC: 93.8%

90.7%

93.5%

91.2%

89.1%

96.9%

92.9%

93.8%

94.8%

95.8%

96.6%

80%

85%

90%

95%

100%

2005

2006

2007

2008

2009 YTD

through 6/30

Fossil Fleet Commercial Availability

Hydro Equivalent Availability

5

(1)

Percent

of

expected

generation

hedged

represents

how

many

equivalent

MW

have

been

hedged

at

forward

market

prices

as

of

June

30,

2009;

all

hedge

products

used

are

converted

to

an

equivalent

average

MW

volume

and

the

calculation

considers

whether

hedges

are

power

sales

or

financial

products.

(2)

Represents

an

approximate

range

of

expected

gross

margin,

taking

into

account

hedges

in

place,

between

the

5th

and

95th

percentile

confidence

levels.

Approximate

gross

margin

ranges

are

based

upon

an

internal

simulation

model

and

are

subject

to

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

of

approximate

gross

margin

in

2010

and

2011

do

not

represent

earnings

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products

and

options

as

of

June

30,

2009.

Hedging program objectives:

•

Manage market risks and protect the value of our generation and investment-grade balance sheet

•

Preserve our ability to participate in improving long-term market fundamentals

2009

2010

2011

Percentage of Expected

Generation Hedged

(1)

95-98%

87-90%

59-62%

Midwest

96-99

87-90

63-66

Mid-Atlantic

95-98

91-94

56-59

South

90-93

68-71

34-37

95% case

5% case

$6,700

$6,500

$6,100

$6,700

$6,100

$8,400

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

Protecting the Long-Term Value of Our Assets

By design, our hedging program allows us to weather short-term, adverse market

conditions, while positioning us to participate in long-term upside potential

6

Well-Positioned Delivery Companies

•

Targeting earned ROEs of ~8% in

2009 and 9-10% in 2010

•

Rate structure and customer

diversity in Large Commercial &

Industrial customer class lessens

the impact of declining load

•

Legislation passed to enable

recovery of uncollectible expense

through a rider

•

Annual Illinois Power Authority

procurement events progressing

as expected

•

Anticipate filing electric distribution

rate case in 2010

•

Targeting earned ROEs in excess of

11% in 2009-2010; 9-11.5% post-

transition

•

Solid credit coverage ratios and

balance sheet strength

•

First procurement event for post-2010

supply held in June, second this month

•

Act 129 Energy Efficiency and Demand

Reduction Plan filed on 7/1

•

Anticipate filing electric and gas

distribution rate cases in 2010

Financial

Regulatory/Legislative

ComEd and PECO continue to deliver on financial targets and build constructive

regulatory and legislative relationships

7

Delivering on Cost Savings Commitments

•

Exelon is delivering on promise to hold 2009 O&M spending flat to 2008 and is

committed to savings of $350 million in 2010 from original planning assumptions,

including the following changes:

–

Reduced positions by 500 (400 in corporate support and 100 at ComEd)

–

Freezing executive salaries and reducing other compensation benefits in 2010

Exelon is responding to today’s challenging environment by driving productivity and

cost reductions while maintaining superior operations

(1)  Reflects operating O&M data and excludes decommissioning impact. ComEd and PECO operating O&M exclude energy efficiency costs recoverable under a rider.

(2)  Exelon Consolidated includes operating O&M expense from Holding Company.

(3)  Reflects ~$175 million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense.

Note: Data contained on this slide is rounded.

ExGen

PECO

ComEd

$4.5B

(2)(3)

$4.5B

(2)

$4.35B

(2)

$4.7B

(2)

+4%

O&M Expense

(1)

$2.7

$2.8

$2.7

$0.8

$0.7

$0.7

$1.1

$1.1

$1.0

2008A

2009E

2010 (Original Est)

2010 (Revised Est)

8

Nuclear

Uprates

-

ComEd and PECO have filed plans to make up to $1 billion in

investments to build smart grid infrastructure over the coming

years, providing for a regulated return on investment

-

1,300–1,500 MW in Exelon nuclear uprates by 2017, the equivalent

of a new nuclear plant at roughly half the cost of building a new

plant and no incremental operating costs

Exelon’s Long-Term Growth Proposition

Smart Grid

Today’s Highlights

Other Key Growth Initiatives

Carbon

PA

Procurement

-

Lowest carbon intensity in the sector –

$1.1 billion

(2)

and growing

annual upside to Exelon revenues if Waxman-Markey legislation is

enacted

-

$101.30/MWh

(1)

result in June PECO power procurement suggests

higher margins at Exelon Generation in 2011 and beyond

-

Developing business plan for transmission company to improve

reliability, reduce congestion, mitigate oversupply and allow our

Midwest fleet to maintain its baseload value

Transmission

(1)    Reflects retail price including line losses and gross receipts tax.

(2)    Assumes $15/tonne carbon pricing.

9

9

Nuclear Uprates Offer Long-Term Growth

at Low Cost and Low Risk

1400

Year Uprates Become Operational

Exelon’s Uprate Plan: 1,300 –

1,500 MW

0

200

400

600

800

1000

1200

1600

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

1,100 MW

1,300 –

1,500  MW

Average Overnight Cost

Estimate: $2,200 -

2,500/KW

Exelon has proven experience in safe and economical nuclear uprates to improve

efficiency and output at substantially lower cost than building a new nuclear plant

•

Equivalent size of a new nuclear unit

•

Low Cost

–

About half the cost of a new nuclear unit

–

No incremental O&M expense

•

Low Risk

–

Compared to the potential delays

and

cost

overruns

of

building

a

new

plant

–

Able to phase in based on market

and

economic

conditions

–

provides

flexibility to ensure appropriate

returns for shareholders

•

Proven Experience

–

1,100 MW of nuclear uprates on Exelon

fleet already successfully executed

–

Leverages competitive advantage in

operating the nation’s largest nuclear fleet

10

ComEd Smart Grid/Smart Meter

•

Smart Meter (or Advanced Metering Infrastructure -

AMI) Pilot

–

Filed with ICC for approval on June 1, 2009

–

Decision expected in November 2009

–

1-year pilot program for 141,000 smart meters and related programs

–

Recovery with regulated return for capital investment expected to begin in 2010 through a rider

•

Federal Stimulus Funding

–

Request for $175 million in matching funds made on August 4, 2009

–

Investment would occur through 2011

Projected Spend

$ millions

$350

$23

$78

$107

$139

Total

$92

$6

--

$84

--

Transmission

$78

Distribution Automation

$23

Communication Support Systems

$139

AMI & Customer Applications

$258

$17

Distribution

TOTAL

Intelligent Substation

Project

Note: Totals may not add due to rounding.  ComEd includes approximately $4 million of unallocated contract expense

that will be distributed to specific projects upon finalization of scope.

ComEd’s Smart Grid project expands the AMI pilot and provides for

regulated returns on our investments

11

PECO Smart Grid/Smart Meter

PECO Smart Grid project provides strong returns with low recovery risk

•

PECO intends to invest up to $750M in its Smart Grid Infrastructure

–

$650M

for

Advanced

Metering

Infrastructure/Smart

Meter

investment

over

10

–

15

years

and

$100M

for Smart Grid over next 3 years

–

Requested $200M Federal Stimulus Grant on August 6, 2009

–

Amount and timing of spending will depend on Federal Stimulus Grant and RFPs with suppliers

•

Smart Meter investment required by Act 129, which provides for recovery through

surcharge including a return on capital investment.

•

Smart Grid investment to be recovered through transmission and distribution rate

cases, with approximately half the costs in each.

•

Smart Meter rate increase starts at 0.5% in 2010 and peaks at a cumulative 2.5% in

2012; with awarded stimulus grant, increase begins at 1% and peaks at 2.1% in 2012.

$ Millions

2010

2011

2012

Total

Act 129 Smart Meter Initial Deployment (without Stimulus Grant)

37

$    

149

$  

30

$    

215

$  

With Federal Stimulus Grant Filing:

Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012)

37

$    

155

$  

99

$    

291

$  

Smart Grid Stimulus Case

45

52

10

107

Total Stimulus Case

82

207

109

398

Stimulus Grant Request

(41)

(103)

(53)

(197)

Total Expenditures net of Stimulus grant

41

$    

103

$  

56

$    

201

$  

12

Value Return Framework

Less

Equals

Maintenance Capital and Committed Dividends

Free Cash Flow before Dividends and CapEx

Strengthen Balance Sheet /

Increase Financial Flexibility

Invest in Growth

Available Cash and Balance Sheet Capacity

Return Value via

Share Repurchases,

Dividends

Monetize

13

Discretionary Pension Contribution

Investing in pension plan with $350M cash on hand is estimated to

create $1 billion of financial flexibility in 2011

(1) 

Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, which allows for a 24-month

average of plan assets reflecting

expected asset returns over the averaging period.

•

Taking advantage of federal relief provided by the Worker, Retiree and

Employer Recovery Act of 2008, election and contribution required by 9/15/09

to impact 2008 plan year

• 

Making $350 million discretionary 2008 pension contribution with smoothing

election

(1)

–

$1 billion reduction in forecasted contribution in 2011

–

Smoothing election reduces present value of estimated future contributions by ~$300M

compared to status quo, over the next 10 years

–

Lowers volatility in future contributions, as smoothing election uses 24-month average of

asset returns

•

Evaluated within our Value Return Framework:

–

Funded with $350 million cash on hand – from $700 million generated in excess of original

2009 plan

–

Increases future financial flexibility with excess cash “today”

14

Protect Today’s Value

•

Deliver superior operating

performance

•

Advance competitive markets

•

Exercise financial discipline and

maintain financial flexibility

•

Build healthy, self-sustaining delivery

companies

Grow Long-Term Value

•

Drive the organization to the next

level of performance

•

Adapt and advance Exelon 2020

•

Rigorously evaluate and pursue

growth opportunities and

advancements in clean technology

•

Build the premier, enduring

competitive generation company

+

Exelon’s Strategic Direction

Exelon remains focused on creating shareholder value

15

Appendix

15

16

Climate Change Legislation Status

Exelon’s advocacy efforts working to advance climate change legislation

•

Key Dates

–

June 26:  House passage of H.R. 2454, American Clean Energy and Security Act

–

September 28:  Deadline for Senate Committees to report out climate change

legislation –

but will slide due to postponement of bill introduction

–

December 7-18:  UN Climate Conference in Copenhagen

•

Exelon Advocacy

–

Grassroots:  Mobilizing our employees, retirees, and shareholders

–

Media:  Working with a diverse group of stakeholders on earned and paid media

opportunities in favor of climate legislation

–

Direct Lobbying:  Exelon executives are meeting with key Senators and staff

–

Coalitions:  Working with United States Climate Action Partnership (USCAP),

Edison Electric Institute and Clean Energy Group to advance climate legislation

17

•

Acquired 198 MW of wind farm output, 4.8 MW of landfill gas output and 4.5 MW of

solar output, bringing Exelon’s renewables portfolio to more than 2,000 MW

•

Unveiled plans to develop the nation’s largest urban solar power plant in Chicago

•

Completed a 38-MW nuclear uprate at Quad Cities Station, launching a series of

planned uprates that will generate 1,300-1,500 MW of additional nuclear capacity

Exelon 2020 –

Progress Update for 2009

Offer more low

carbon electricity in

the marketplace

Help our customers

and the communities

we serve reduce their

GHG emissions

Reduce or offset our

footprint by greening

our operations

Exelon’s strategy to reduce, offset or displace more than 15 million metric

tons of GHG emissions per year by 2020

•

Retired less efficient and higher-emitting fossil fuel power plants in Massachusetts,

Pennsylvania and Texas

•

Reduced energy use across Exelon’s facilities by 16%

•

Earned LEED certification for three Exelon buildings

•

Greened Exelon’s vehicle fleet to include 1,900 hybrid-electric and alternative-fuel

vehicles at ComEd and a 57% environmentally friendly fleet at PECO

•

Unveiled plans to spend more than $350 million through 2011 on energy efficiency and

demand

response

programs

to

reduce

customers’

energy

consumption

by

1.6

million

MWh and reduce peak load by 226 MW

•

Building

on

its

residential

real-time

pricing

program,

ComEd

introduced

a

“smart”

meter

pilot program that will provide advanced automated meters to up to 141,000 customers

•

PECO is investing $342 million in customer programs to reduce overall electricity

consumption by 3% and peak load by 4.5% by 2013

3

2

1

18

Nuclear Uprates Offer Sustainable Value

Key component of Exelon 2020 low carbon roadmap

Creates additional low-carbon generation capacity

Capitalizes on Exelon’s proven track record of execution

Dedicated project management team

Proven technology design

No ongoing incremental O&M expense

Creates long-term value over extended license lives

Uprates equivalent in size to a new nuclear plant but significantly

lower cost, shorter timeline and more predictable spend

Straightforward regulatory and environmental licenses, permits

and approvals

Potential for uprates to meet state alternative energy standards

Uprate projects enable cost-effective growth and leverage Exelon’s

operational excellence

Strategic

Value

Grow

Value

Regulatory

Feasibility

Execution

Feasibility

19

Three Major Categories of Exelon Uprates

Uprates

Overnight

Cost

(1)

MUR (Measurement Uncertainty Recapture)

•

Through the use of advanced techniques and more precise

instrumentation, reactor power can be more accurately calculated

•

Can achieve up to 1.7 percent additional output

•

Requires NRC approval

187–234 MW

$300M

2 years

899–1016 MW

$2,400M

EPU (Extended Power Uprate)

•

Through a combination of more sophisticated analysis and upgrades

to plant equipment, uprates can be obtained for as much as 20

percent of original licensed power level

•

Requires NRC approval

3 -

5

years

237–266 MW

$800M

Megawatt Recovery and Component Upgrades

•

Replacement

of

major

components

in

the

plant

occur

in

the

normal

life

cycle process –

with newer technology, replacements result in

increased efficiency

•

Equipment includes generators, turbines, motors and transformers

•

Megawatt Recovery and Component Upgrades must conform to NRC

standards, but do not require additional NRC approval

2 -

3

years

~1,300–1,500 MW

$3,500M

Project Duration

Exelon’s

$2,200

–

$2,500

/

kW

overnight

cost

for

its

MUR

and

EPU

projects

is

an

advantageous deployment of capital relative to other generation options

(1) In 2007 Dollars. Overnight costs do not include financing costs or cost escalation.

20

Phased Execution Lowers Risk

•

Safe, economical and proven methods to improve efficiency and output

•

Leverages Exelon’s substantial experience managing successful uprate

projects over the past 10 years

Note: Data contained in this slide is rounded.

Uprates program allows us to adjust timing to respond to market conditions

EPUs

MURs

MW Recovery and           

Component Upgrades

Maximum                        

Potential MW

Year Uprates Become Operational

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

Exelon’s Uprate Plan

1,100 MW

1,300 –

1,500  MW

Average Overnight Cost

Estimate: $2,200 -

2,500/KW

0

200

400

600

800

1,000

1,200

1,400

1,600

Planned Capital

Spend

(1)

$150

2017

$625

2013

$675

2012

$550

2011

$350

2010

$725

2015

$725

2014

$400

2016

$4,425

2008 -

2017

$225

2008 -

2009                                           

(1)

Dollars shown are nominal, reflecting 6% escalation, in millions. 

21

Uprates Across the Exelon Fleet

Base

Maximum

Station

Case

Potential

MW

MW

Braidwood - MUR

34

-

42

2012

Byron - MUR

34

-

42

2012

Clinton - EPU

17

-

17

2016

Clinton - EPU

2

-

3

2010

Dresden - MW Recovery & Component Upgrades

103

-

110

2012

Dresden - MW Recovery & Component Upgrades

5

-

5

2011

Dresden - MUR

25

-

31

2014

LaSalle - MUR

32

-

40

2011

LaSalle - EPU

303

-

336

2016

Limerick - MUR

33

-

41

2011

Limerick - MW Recovery & Component Upgrades

6

-

6

2012

Limerick - EPU

306

-

340

2017

Peach Bottom - MW Recovery & Component Upgrades

25

-

32

2012

Peach Bottom - EPU

134

-

148

2015

Peach Bottom - MW Recovery & Component Upgrades

3

-

3

2014

Quad Cities - MUR

19

-

23

2013

Quad Cities - MW Recovery & Component Upgrades

95

-

110

2011

TMI - EPU

138

-

172

2016

TMI - MUR

12

-

15

2014

Total

1,323

-

1,516

Year of

Operation

Uprates will largely be completed during scheduled refueling outages

22

PECO Procurement

With a successful residential procurement in June, PECO has made

progress toward

purchasing the power needed to serve customers beginning in 2011

On June 17, 2009, the PAPUC approved the bids from the Spring RFP held on June 15,

2009, which included 21% of PECO’s residential default service load for 2011 and a portion

of its load obligation for 2012 and 2013

Contracts were awarded to two bidders out of eleven total bidders

RFP for full requirements

(1)

resulted in average wholesale price of $88.61($/MWh)

Fall RFP bids due September 21, 2009

(1) Full requirements product includes load following energy, capacity, ancillary transmission services and Alternative Energy Portfolio Standard requirements.

(2) See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s procurement plan and RFP results.

Residential

23% of planned full requirements

contracts (17 and 29-mo. terms)

40MW of baseload (24x7) energy

block products (12-mo. duration)

Small Commercial

24% of planned full requirements

contracts (17-mo. term)

Medium Commercial & Industrial

16% of planned full requirements

contracts (17-mo. term)

85% full requirements

15% full requirements spot

Medium Commercial &

Industrial

(peak demand >100 kW

but <= 500 kW)

100% full requirements spot

Large Commercial &

Industrial

(peak demand >500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% energy block

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

Residential

26% of planned full requirements   

contracts

•

17 month (Jan 2011 -

May 2012)

•

29 month (Jan 2011 -

May 2013)

40MW of baseload (24x7) energy

block products

•

12 month (Jan 2011 -

Dec 2011)

PECO

Procurement

Plan

(2)

Fall 2009 RFP

Spring 2009 RFP

23

Potential Variability in Future Pension

Expense and Contributions

$159

$4,055

$305

$251

$4,058

$270

6.09% for 2009

5.92% for 2010

6.10% for 2011

8.5% in 2009-2011

B -

Asset returns at long-term rate

Unfunded balance –

end of year

$144

$3,687

$289

$207

$3,705

$260

6.09% for 2009

5.92% for 2010

6.10% for 2011

14.15% in 2009

8.5% in 2010

8.5% in 2011

A –

Current baseline

Unfunded balance –

end of year

$134

$2,802

$243

$182

$2,670

$196

6.09% for 2009

7.00% for 2010

7.00% for 2011

8.5% in

2009

15% in 2010

8.5% in 2011

C –

Accelerated equity recovery

Unfunded balance –

end of year

$723

$4,611

$327

$326

$5,111

$285

6.09% for 2009

5.92% for 2010

6.10% for 2011

0% in

2009

0% in 2010

8.5% in 2011

D -

Equity recovery in 2 years

Unfunded balance –

end of year

Required

contribution

(1)

Pre-tax

expense

Required

contribution

(1)

Pre-tax

expense

Discount Rate

Actual Asset

Returns

2011

2010

Assumptions

Illustrative Scenario

($ in millions)

Other

Postretirement

Benefits

(OPEB)

2010

Expense:

Exelon

estimates

pre-tax

2010

OPEB

expense

of

~$226

million,

$240

million,

$193

million,

and

$254

million

under

Scenarios

A-D,

respectively.

2010

Contributions:

Exelon

estimates

roughly

$150

million

of

contributions

to

its

OPEB

plans

in

2010,

which

is

subject

to

change,

with

an

additional

approximately

$6

million

paid

out

of corporate assets.

(1)

The contributions shown above include estimated pension contributions required under ERISA and the Pension Protection Act of 2006, as well as certain discretionary contributions

necessary to avoid benefit restrictions. Also included within these amounts are expected payments to Exelon’s non-qualified plans of approximately $18 million and $6 million in 2010

and 2011, respectively.  Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, as well

as a discretionary $350 million contribution allocated to the 2008 plan year.

Note: Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes 20% overall capitalization rate of pension and OPEB costs.

24

Exelon Investor Relations Contacts

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:

Martha Chavez, Executive Admin

Coordinator

312-394-4069

Martha.Chavez@ExelonCorp.com

Investor Relations Contacts:

Karie Anderson, Vice President

312-394-4255

Karie.Anderson@ExelonCorp.com

Stacie Frank, Director

312-394-3094

Stacie.Frank@ExelonCorp.com

Paul Mountain, Manager

312-394-2407

Paul.Mountain@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com

25

25

25

Exelon Generation Hedging Disclosures

(As disclosed on July 24, 2009)

26

26

26

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

27

27

27

27

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MW Sold

Expected Generation

=

•

Our normal practice is to hedge commodity risk on a ratable basis

over the three years leading to the spot market

•

Carry operational length into spot market to manage forced outage and load-following

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

Participation in larger procurement events, such as utility auctions, and some flexibility

in the timing of hedging may mean the hedge program is not strictly ratable from

quarter to quarter

Exelon Generation Hedging Program

28

28

28

28

2009

2010

2011

Estimated Open Gross Margin (millions)

(1,2)

$5,100

$6,000

$6,150

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT

North

ATC

Spark

Spread

($/MWh)

(3)

$4.26

$29.42

$40.30

($0.09)

$6.06

$33.38

$48.64

($2.17)

$6.89

$35.12

$52.21

($0.77)

(1)

Based on June 30, 2009 market conditions. 

(2)

Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental revenues. Open

gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices.  Open gross margin

assumes

there

is

no

hedging

in

place

other

than

fixed

assumptions

for

capacity

cleared

in

the

RPMT

auctions

and

uranium

costs

for

nuclear

power

plants.

Open

gross

margin

contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity payments.  The estimation of open gross margin

incorporates

management

discretion

and

modeling

assumptions

that

are

subject

to

change.

(3)

ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.

Exelon Generation Open Gross Margin

and Reference Prices

29

29

29

29

(1)

Expected

generation

represents

the

amount

of

energy

estimated

to

be

generated

or

purchased

through

owned

or

contracted

for

capacity.

Expected

generation

is

based

upon

a

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,

which

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options.

Expected generation assumes 10 refueling outages in 2009 and 2010 and 11 refueling outages in 2011 at Exelon-operated nuclear plants and Salem.  Expected generation assumes

capacity factors of 93.6%, 92.8% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 do not represent

guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation.  Includes all hedging products, such as wholesale and retail sales of

power, options, and swaps.  Uses expected value on options.

(3)

Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by considering the

energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity

revenue,

but

includes

the

mark-to-market

value

of

capacity

contracted

at

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

It

can

be

compared

with

the

reference

prices

used

to

calculate

open

gross

margin

in

order

to

determine

the

mark-to-market

value

of

Exelon

Generation's

energy

hedges.

2009

2010

2011

Expected Generation

(GWh)

(1)

169,800

165,500

164,700

Midwest

99,600

97,700

97,700

Mid-Atlantic

57,500

58,500

58,100

South

12,700

9,300

8,900

Percentage

of

Expected

Generation

Hedged

(2)

95-98%

87-90%

59-62%

Midwest

96-99

87-90

63-66

Mid-Atlantic

95-98

91-94

56-59

South

90-93

68-71

34-37

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$47.00

$46.75

$45.00

Mid-Atlantic

$36.25

$34.50

$62.00

ERCOT North ATC Spark Spread

$5.25

$3.50

$4.75

Generation Profile

30

30

30

30

Gross Margin Sensitivities with Existing Hedges (millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2009

$8

$0

$6

($3)

$8

($2)

+/-$20

2010

$40

($30)

$55

($50)

$25

($20)

+/-$50

2011

$280

($240)

$205

($195)

$170

($165)

+/-$55

(1)

Based on June 30, 2009 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal

model that is updated periodically.

Power

prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant.

Due

to

correlation

of

the

various

assumptions,

the

hedged

gross

margin

impact

calculated

by

aggregating

individual

sensitivities

may

not

be

equal

to

the

hedged

gross margin impact calculated when correlations between the various assumptions are also considered.

Exelon Generation Gross Margin

Sensitivities (with Existing Hedges)

31

31

31

31

95% case

5% case

$6,700

$6,500

$6,100

$6,700

$6,100

$8,400

Exelon Generation Gross Margin

Upside / Risk (with Existing Hedges)

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

(1)

Represents

an

approximate

range

of

expected

gross

margin,

taking

into

account

hedges

in

place,

between

the

5th

and

95th

percentile

confidence

levels.

Approximate

gross

margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These

ranges

of

approximate

gross

margin

in

2010

and

2011

do

not

represent

earnings

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options

as

of

June

30, 2009.

32

32

32

32

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$5.10 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,600GWh * 97% *

($47.00/MWh-$29.42/MWh)

= $1.70 billion

57,500GWh * 96% *

($36.25/MWh-$40.30/MWh)

= ($0.22 billion)

12,700GWh * 91% *

($5.25/MWh-($0.09)/MWh)

= $0.06 billion

Step 3

Estimate hedged gross margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.10 billion

MTM value of energy hedges:              $1.70 billion + ($0.22 billion) + $0.06 billion

Estimated hedged gross margin:          $6.64 billion

Illustrative Example of Modeling Exelon Generation

2009 Gross Margin

(with Existing Hedges)

33

33

33

50

60

70

80

90

100

110

120

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

20

25

30

35

40

45

50

55

60

65

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

35

45

55

65

75

85

95

105

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

5.5

6.5

7.5

8.5

9.5

10.5

11.5

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

33

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2010

2011

Rolling

12

months,

as

of

August

31,

2009.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

$5.57

$6.57

2010

2011

$51.20

$63.34

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

$53.18

$59.86

$39.56

$24.05

$39.38

$21.89

$43.85

$36.28

34

34

34

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

14.5

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

45

50

55

60

65

70

75

80

85

90

95

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

5

6

7

8

9

10

11

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

34

Market Price Snapshot

2011

2010

2010

2011

2010

2011

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2010

2011

ERCOT North On Peak Spark Spread

Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder

$5.38

$6.36

$55.39

$47.02

$8.74

$8.70

$5.70

$6.98

Rolling

12

months,

as

of

August

31,

2009.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.