Peco Energy 8-K This presentation relates, in part, to the offer (the “Offer”) by Exelon Corporation (“Exelon”) through its direct wholly-owned subsidiary, Exelon

Exhibit 99.1

2

Important Information

This presentation relates, in part, to the offer (the “Offer”) by Exelon Corporation (“Exelon”) through its direct wholly-owned subsidiary, Exelon

Xchange

Corporation

(“Xchange”),

to

exchange

each

issued

and

outstanding

share

of

common

stock

(the

“NRG

shares”)

of

NRG

Energy,

Inc.

(“NRG”)

for

0.485

of

a

share

of

Exelon

common

stock.

This

presentation

is

for

informational

purposes

only

and

does

not

constitute

an

offer

to

exchange,

or

a

solicitation

of

an

offer

to

exchange,

NRG

shares,

nor

is

it

a

substitute

for

the

Tender

Offer

Statement

on

Schedule

TO

or

the

Prospectus/Offer

to

Exchange

included

in

the

Registration

Statement

on

Form

S-4

(Reg.

No.

333-155278)

(including

the

Letter

of

Transmittal

and related documents and as amended from time to time, the “Exchange Offer Documents”) previously filed by Exelon and Xchange with the

Securities and Exchange Commission (the “SEC”). The Offer is made only through the Exchange Offer Documents. Investors and security

holders are urged to read these documents and other relevant materials as they become available, because they will contain

important information.

Exelon expects to file a proxy statement on Schedule 14A and other relevant documents  with the SEC in connection with the solicitation of

proxies (the “NRG Meeting Proxy Statement”) for the 2009 annual meeting of NRG stockholders (the “NRG Meeting”). Exelon will also file a

proxy statement on Schedule 14A and other relevant documents  with the SEC in connection with its solicitation of proxies for a meeting of

Exelon shareholders (the “Exelon Meeting”) to be called in order to approve the issuance of shares of Exelon common stock pursuant to the

Offer

(the

“Exelon

Meeting

Proxy

Statement”).

Investors

and

security

holders

are

urged

to

read

the

NRG

Meeting

Proxy

Statement

and

the Exelon Meeting Proxy Statement and other relevant materials as they become available, because they will contain important

information.

Investors and security holders can obtain copies of the materials described above (and all other related documents filed with the SEC) at no

charge

on

the

SEC’s

website:

www.sec.gov.

Copies

can

also

be

obtained

at

no

charge

by

directing

a

request

for

such

materials

to

Innisfree

M&A Incorporated, 501 Madison Avenue, 20th Floor, New York, New York 10022, toll free at 1-877-750-9501. Investors and security holders

may also read and copy any reports, statements and other information filed by Exelon, Xchange or NRG with the SEC, at the SEC public

reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 or visit the SEC’s website for further

information on its public reference room.

Exelon, Xchange and the individuals to be nominated by Exelon for election to NRG’s Board of Directors will be participants in the solicitation of

proxies from NRG stockholders for the NRG Meeting or any adjournment or postponement thereof. Exelon and Xchange will be participants in

the solicitation of proxies from Exelon shareholders for the Exelon Meeting or any adjournment or postponement thereof. In addition, certain

directors and executive officers of Exelon and Xchange may solicit proxies for the Exelon Meeting and the NRG Meeting.  Information about

Exelon and Exelon’s directors and executive officers is available in Exelon’s proxy statement, dated March 20, 2008, filed with the SEC in

connection

with

Exelon’s

2008

annual

meeting

of

shareholders.

Information

about

Xchange

and

Xchange’s

directors

and

executive

officers

is

available in Schedule II to the Prospectus/Offer to Exchange.  Information about any other participants will be included in the NRG Meeting

Proxy Statement or the Exelon Meeting Proxy Statement, as applicable.

3

Forward-Looking Statements

This presentation includes forward-looking statements.  There are a number of risks and uncertainties

that could cause actual results to differ materially from the forward-looking statements made herein.  

The

factors

that

could

cause

actual

results

to

differ

materially

from

these

forward-looking

statements

include 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) the Exchange

Offer Documents; and (3) other factors discussed in Exelon’s filings with the SEC.  Readers are

cautioned not to place undue reliance on these forward-looking statements, which apply only as of the

date of this filing.  Exelon does not undertake any obligation to publicly release any revision to its

forward-looking statements to reflect events or circumstances after the date of this filing, except as

required by law.

Statements made in connection with the exchange offer are not subject to the safe harbor protections

provided to forward-looking statements under the Private Securities Litigation Reform Act of 1995.

4

4

Our Sustainable Advantage Remains

5

The Exelon Companies

’08 Earnings:

$2,293M 

’08 EPS:

$3.46

Total Debt

(1)

:

$2.5B

Credit Rating

(2)

:

BBB

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘08 Operating Earnings:

$2.8B

‘08 EPS:

$4.20

Assets

(1)

:                        

$47.8B

Total Debt

(1)

:

$13.2B

Credit Rating

(2)

:                            BBB-

Note: All ’08 income numbers represent adjusted (Non-GAAP) Operating Earnings and EPS. Refer to Appendix for reconciliation of adjusted (non-GAAP)

operating EPS to GAAP EPS.

(1)

As

of

December

31,

2008.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of February 27,

2009.

Pennsylvania

Utility

Illinois

Utility

’08 Earnings:

$219M

$325M

’08 EPS:

$0.33

$0.49

Total Debt

(1)

:

$5.0B

$3.4B

Credit Ratings

(2)

:

BBB+

A-

6

Multi-Regional, Diverse Company

Note:

Owned

megawatts

based

on

Generation’s

ownership

at

December

31,

2008,

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:

3,230 MW

Total:

14,618 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

182 MW

Total Capacity

Owned:

24,809 MW

Contracted:

6,483 MW

Total:

31,292 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:

11,017 MW

Contracted:

336 MW

Total:

11,353 MW

7

Well-Positioned in Near-Term

Macroeconomic Uncertainty

•

Hedging strategy provides near-term earnings and cash flow

stability

•

Over 90% and ~90% financially hedged in 2009 and 2010,

respectively

Risk management

•

Proven management team

•

Lowest-cost

nuclear

fleet

operator

with

~94%

capacity

factor

Best-in-class management /

operations

•

Nuclear remains a low-cost generation source

•

Improving

utilities’

performance

and

regulatory

environment

Basics of business unchanged

•

Nation’s largest nuclear fleet ~140,000 GWhs of annual

production

Market leader

•

Progress made on transition to competitive markets in PA

•

ComEd on path to regulatory recovery

•

Positively levered to long-term fundamentals

Long-term value in place

•

Strong

and

consistent

cash

flows

from

operations

(2)

:

~$4.75

billion estimated in 2009

•

Over 12% annual growth rate in dividend since 2001

Stable cash flows and

commitment to value return

•

~$6.8 billion of available credit facilities as of 2/27/2009

•

Debt

maturities

of

$29

million

(1)

,

in

total,

through

12/31/2009

Sufficient liquidity

Investment Criteria

Exelon Profile

(1)  Excludes securitization debt and includes capital leases.

(2) Cash Flow from Operations = Primarily includes net cash flows provided by operating activities, excluding counterparty collateral activity, and including net cash

flows

used

in

investing

activities

other

than

capital

expenditures.

8

2009 Operating Earnings Guidance

2009E

2008A

$0.49

$3.46

$4.20

ComEd

PECO

Exelon

Generation

ComEd distribution revenue

PECO gas revenue

O&M and other

Pension/OPEB

Inflation

Cost reduction initiatives

Bad debt expense

Nuclear fuel costs

Depreciation and amortization

PECO CTC

2009 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.33

Exelon

$4.00 -

$4.30

(1)

$0.45 -

$0.55

$0.45 -

$0.55

$3.10 -

$3.35

(1)

Adjusted

(non-GAAP)

Operating

Earnings

Guidance.

Excludes

the

earnings

impact

of

certain

items

as

disclosed

in

the

Appendix.

Note: A = Actual; E = Estimate

Reaffirming

2009

operating

earnings

guidance

of

$4.00-$4.30/share

(1)

–

expect

1Q09 results between $1.10 to $1.20/share

9

Exelon Cost and Capital Management

We

are

forecasting

$150

million

of

sustainable

O&M

reductions

in

2009;

to

date,

approximately $100 million has been identified

•

Reducing nuclear outage expenses

•

Focusing on inventory management

and reducing inventory growth

•

Right-sizing business unit

administrative functions

•

Reducing capital spend for decreased

new business requirements and

declining load growth

•

Executing "ComEd Sustainable

Solutions", "Engineering Excellence",

"Operational Excellence" and "Putting

Customers First"

•

Reducing new business and potential

deferred capacity spend

•

Implementing “Productivity

Improvement Cost Reduction”

program

•

Executing credit and collections

initiatives

Intelligently reduce costs while maintaining superior operations

•

Optimizing the Exelon governance structure to drive efficiency, accountability, and costs

•

Driving a consistent focus on productivity throughout the operating companies

•

Executing rapid resourcing of Exelon’s $3.5B+ in external spend

•

Reviewing and reducing discretionary spend (consulting, travel, etc.)

•

Improving Exelon’s financial systems, contributing to improved staff productivity

10

~1%

(2)

$1,050

$1,100

~3%

(2)

$700

$750

~3%

~4%

2009-2013 CAGR

$4,500

$2,750

2009E

$4,500

$2,700

2008A

Exelon

(3)

O&M Expense

(1)

($ in Millions)

O&M and CapEx Expectations

($ in Millions)

~1%

(5)

$850

$950

~4%

$400

$400

Exelon

(3)

~3%

~9%

~(3%)

2009-2013 CAGR

(4)

$3,300

$900

$1,050

2009E

$3,200

$800

$950

2008A

Nuclear

Fuel

Plant &

Other

CapEx

A combination of company-wide cost-savings initiatives and controlled spending will offset

inflationary

pressures

and

rising

pension

and

retiree

health

and

welfare

costs

(1)

Reflects Operating O&M data and excludes Decommissioning impact.

(2)

For ComEd and PECO, O&M excludes energy efficiency spend recoverable under a rider. 2009-2013 Compound Annual Growth Rate (CAGR) would be ~3% for

ComEd and ~4% for PECO if spend were included.

(3)

Includes eliminations and other corporate entities.

(4)

Subject to change based upon proposed NRG acquisition.

(5)    ComEd CAGR assumes New Business expenditures remain at current levels; only includes pilot program implementation of automated metering infrastructure (AMI)

and does not include full scale Smart Grid implementation.

11

2009 Pension and OPEB Expense and

Contributions

Cash Contributions

$0

$50

$100

$150

$200

$250

Pension

OPEB

Pre-Tax Expense

$0

$50

$100

$150

$200

$250

Pension

OPEB

Pension

and

OPEB

Plans

Key

Metrics

–

12/31/08E

($

in

millions)

Pension

Assets

$6,650

Obligations

$10,800

2009E

2008

$85

$200

$160

$225

$80

$175

$163

$155

2009E

2008

(1) 

Excludes settlement charges.

(2)

Management

has

not

yet

made

a

definitive

decision

regarding

its

2009

pension

contributions

and

may

make

additional

discretionary

contributions

based

upon

final

interpretations

of

the

Worker,

Retiree

and

Employer

Recovery

Act

of

2008.

(3)

Management has not yet made a definitive decision regarding its 2009 OPEB contributions.  Approximately $100 million of the estimated 2009 OPEB contributions is

discretionary.  Contributions shown above include contributions paid out of corporate assets.

Note: OPEB = other postretirement benefits; EROA = expected return on assets

(1)

(2)

(3)

OPEB

Assets

$1,200

Obligations

$3,500

Key Metrics

2008 asset return

-26%

12/31/08 discount rate

6.09%

L-T EROA

8.50%

12

Potential Variability in Future Pension

Expense and Contributions

$700

$3,730

74%

$300

$130

$4,190

64%

$260

6.09% for 2009

6.19% for 2010

6.26% for 2011

8.5% in 2009-2011

A-

Asset returns at long-term rate

Unfunded balance –

end of year

ERISA funded percentage (1)

$1,175

$4,735

64%

$320

$960

$5,570

61%

$285

6.09% for 2009

6.19% for 2010

6.26% for 2011

-15% in

2009

-3% in 2010

8.5% in 2011

D-

2 years of low asset returns

Unfunded balance –

end of year

ERISA funded percentage (1)

$1,020

$4,510

66%

$330

$205

$5,210

60%

$275

6.09% for 2009

6.19% for 2010

6.26% for 2011

0% in

2009

0% in 2010

8.5% in 2011

C-

Equity recovery in 2 years

Unfunded balance –

end of year

ERISA funded percentage (1)

$640

$2,770

74%

$270

$155

$3,525

64%

$220

6.09% for 2009

7.00% for 2010

7.00% for 2011

0% in

2009

15% in 2010

15% in 2011

B-

Equity recovery

Unfunded balance –

end of year

ERISA funded percentage (1)

Required

contribution (2)

Pre-tax

expense

Required

contribution (2)

Pre-tax

expense

Discount Rate

Actual Asset

Returns

2011

2010

Assumptions

Illustrative Scenario

(1) 

The net funded percentage (used to amortize future contribution requirements) at the end of 2010 is 60%, 60%, 60% and 61% under Scenarios A-D, respectively.

(2) 

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.

Exelon

also

expects

to

make

payments

related

to

its

non-qualified

plans

of

approximately

$22

million

and

$9

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.

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.

Other Postretirement Benefits (OPEB)

2010 Expense:

Exelon estimates pre-tax 2010 OPEB expense of ~$220 million, $200 million, $235 million and $260 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.

($ in Millions)

13

2009 Projected Sources and Uses of Cash

$1,050

$800

$350

$250

Cash Available before Dividend

100

0

350

0

Other

(400)

0

(150)

0

Net Financing (excluding Dividend):

(2)

250

0

250

0

Planned Debt Issuances

Net Financing (excluding Dividend):

(2)

(750)

0

(750)

0

Planned Debt Retirements

(3)

$4,750

$2,750

$900

$1,100

Cash Flow from Operations

(1)

(3,300)

(1,950)

(400)

(850)

Capital Expenditures

$1,400

Dividend

(4)

Exelon

(5)

($ in Millions)

Numbers are rounded and may not add.

(1)

Cash Flow from Operations = Primarily includes net cash flows provided by operating activities, excluding counterparty collateral activity, and including 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)

Planned Debt Retirements are $17M, $728M, and $12M for ComEd, PECO, and ExGen, respectively.  Includes securitized debt.

(4)

Assumes

2009

Dividend

of

$2.10

per

share.

Dividends

are

subject

to

declaration

by

the

board

of

directors.

(5)

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

14

Sufficient Liquidity

(1)  Excludes previous commitment from Lehman Brothers Bank.

(2)  Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit.  The amount of

commercial paper outstanding does not reduce the available capacity under the credit agreements.

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

(150)

--

--

(150)

Outstanding Facility Draws

(325)

(124)

(55)

(141)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate

Bank

Commitments

(1)

6,842

4,710

519

661

Available

Capacity

Under

Facility

(2)

(110)

--

--

--

Outstanding Commercial Paper

$6,732

$4,710

$519

$661

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ in Millions)

We have minimal commercial paper outstanding and our bank facilities are largely untapped

Available Capacity Under Bank Facilities as of February 27, 2009

15

Large and Diverse Bank Group

Exelon

has

a

large

and

diverse

bank

group

with

over

$7.3

billion

in

aggregate

credit

facility commitments –

23 banks committed to the facilities with each bank having less

than 10% of the aggregate commitments at Exelon

•

Bank

of

America,

N.A.

/

Merrill

Lynch

USA

(2)

•

The Royal Bank of Scotland PLC (RBS)

•

Barclays Bank PLC

•

JP Morgan Chase Bank, N.A.

•

The Bank of Nova Scotia (Scotia)

•

Wachovia Bank, N.A.

•

Citibank, N.A.

•

Commerzbank AG

•

BNP Paribas

•

Deutsche Bank AG, New York Branch

•

Credit Suisse, Cayman Islands Branch

•

Morgan Stanley Bank

•

UBS Loan Finance LLC

•

The Bank of New York / Mellon Bank, N.A.

•

Mizuho Corporate Bank, LTD

•

Goldman Sachs

(3)

•

The Bank of Tokyo-Mitsubishi UFJ, LTD

•

KeyBank N.A.

•

U.S. Bank, N.A.

•

SunTrust Bank

•

The Northern Trust Company

•

Malayan Banking Berhad (May Bank)

•

National City Bank

(1)

As of February 27, 2009.

(2)

Assumes that Bank of America assumes Merrill Lynch’s previous commitment.

(3)

Includes

funding

commitments

by

Williams

Street

Commitment

Corporation,

Williams

Street

Credit

Corporation,

Goldman

Sachs

Credit

Partners,

L.P.

Banks Committed to Exelon’s Facilities

(1)

16

$0

$150

$300

$450

$600

$750

2009

2010

2011

2012

2013

Exelon Corp

Exelon Generation

ComEd

PECO

2009-2013 Debt Maturities

Note: Balances shown exclude securitized debt and includes capital leases.

Minimal debt maturities before 2011

$29 M

Total

$615 M

Total

$1,800 M

Total

$827 M

Total

$554 M

Total

17

Factors Impacting 2011 Earnings Outlook

PJM W-Hub ATC Price:

+/-

$5/MWh       +/-

$0.25

ComEd ROE:

+/-

0.5%    

+/-

$0.03

2011 EPS

Sensitivities

Volatility Risk

Factors

NI-Hub ATC Price:

+/-

$5/MWh       +/-

$0.25

PECO ROE:

+/-

0.5%          +/-

$0.02

O&M CAGR:

+/-

1%           

+/-

$0.10

Uranium Prices:

+/-

$25/lb   

+/-

$0.01

ExGen

Revenue

PECO

ROE

ComEd

ROE

O&M

Expense

Nuclear

Fuel

Medium

•

PECO rate making expectation is ~9-11.5% ROE for 2011

•

Achieving expected ROE depends on future rate case results

High

•

Generally, hedges are executed on a ratable basis over 3

years.  The position is physically well hedged in the prompt

year (2009) and significantly open in the outer year (2011).

Medium

•

ComEd expectation is ~9-10% ROE for 2011

•

Achieving expected ROE depends on future rate case results

Low-Medium

•

Company-wide cost savings initiative

•

Inflationary pressures and rising pension & post-

retirement costs

Low

•

100% physically contracted in 2011 with modest contractual

price inflators/deflators

2011 Earnings Outlook will be impacted by changes in future commodities

and forward power prices

18

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

2001

2002

2003

2004

2005

2006

2007

2008

2009E

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Cash flow from operations

Annual cash dividend / share

Stable Cash Flows and Commitment to

Value Return

(1)

Cash Flows from Operations primarily include net cash flows provided by operating activities, excluding counterparty collateral activity, and including net cash flows

used in investing activities other than capital expenditures.  Cash Flows from Operations in 2005 reflect discretionary aggregate pension contributions of $2 billion.

(2)

Dividend

Yield

was

calculated

as

(Annual

Dividend

Paid

/

Average

Daily

Closing

Share

Price)

Exelon produces strong and consistent cash flows and continues to honor its commitment to

return value to shareholders

Strong and consistent

cash flows from

operations

(1)

Over 12% compound

annual dividend growth

rate since 2001

Sustainable Value

Dividend Yield

1.58%        1.76%       1.68%        2.66%        3.24%        2.77%        2.40%        2.75%       3.91%

(2)

19

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

(1)

Return Value via

Share Repurchases,

Dividends

Monetize

We evaluate value return on an annual basis

(1)

Exelon on a standalone basis targets a FFO/Debt Ratio of 20-30%.

20

Implementing Exelon’s Low-Carbon

Strategy

•

Voluntary commitment: 8% reduction in GHG by YE2008 (from 2001)

–

Achieved greater than 30% reduction

•

Initiatives included:

–

Closed older, inefficient fossil-fueled power plants;

–

Incorporated emissions and their potential cost into its business analyses;

–

Reduced leakage of SF6 and methane;

–

Increased use of renewable energy; and

–

Internal energy efficiency initiatives

•

Validating goal achievement with EPA in Q1 2009

EPA Climate Leaders (2001 –

2008)

•

Reduce,

offset

or

displace

>15

million

metric

tons

of

GHG

emissions

(M

MT

CO2e)

per

year by 2020

–

Reduce or offset Exelon’s carbon footprint (Potential:  ~5M MT C02e)

–

Help our customers/communities reduce their emissions (Potential: >3.5M MT C02e)

–

Offer

more

low-carbon

electricity

in

the

marketplace

(Potential:

up

to

12.5M

MT

C02e)

Exelon 2020: A Low Carbon Roadmap (2008 –

2020)

21

Increased

our

portfolio

of

PPAs

for

renewable

generation

by

over

200

MW

in

2008

Advancing nuclear power uprate projects totaling 350 MW by 2013

Exelon 2020 Update

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

Reduce, offset or displace more than 15 million metric tons

of GHG emissions per year by 2020

Implemented

improvements

that

reduce

building

energy

consumption

11%

toward

our

25%

goal

Increased utilization of hybrid vehicles and introduced new vehicle guidelines to enhance fuel

efficiency and reduce emissions

Launched comprehensive program to green the supply chain, including Carbon Disclosure

Project Supply Chain survey and Electric Utility Industry Sustainable Supply Chain Alliance

Recycled/reused >30 million pounds of scrap metal, meters and transformers, along with

>0.7 million gallons of oil in 2008

Introduced portfolio of department and employee initiatives

Introduced suite of new energy efficiency programs

ComEd Smart Ideas: Programs for residential and commercial customers which will save

in excess of 166,000 MWhs in the first year

PECO: Planning underway to reduce consumption by 3% and peak load by 4.5% by 2013

Investing

in

smart

grid

technology

and

new

pricing

programs

–

ComEd

is

preparing

for

the

2009 AMI pilot launch for 100,000 customers

Expanding green products, e.g. Green-e certified renewable energy credits (RECs), Emission

Free Energy Certificates

Conducting comprehensive customer education and outreach around energy efficiency

3

2

1

22

Recognized Environmental Leadership

•

Named for the third consecutive

year to the

Dow Jones

Sustainability Index -

North America

•

Named to Carbon Disclosure Leadership Index of the

Carbon Disclosure Project for the fourth consecutive year

•

Named an Electric Sector Sustainability Leader, Silver

Class in PwC/SAM’s “The Sustainability Yearbook 2008”

•

Signatory to the Ceres/Investor Network on Climate Risk and the Global

Roundtable on Climate Change statements

•

Member of the United States Climate Action Partnership (USCAP), Pew

Center on Global Climate Change’s Business Environmental Leadership

Council, and Ceres

•

Environmental Management Systems (EMS) at over 80% of Exelon’s

operating sites/organizations are ISO 14001 certified

•

Three Exelon facilities have obtained Leadership in Energy and Environmental

Design (LEED

®

) certification by the U.S. Green Building Council; other

facilities are pursuing certification

23

Exelon’s Strategic Direction

•

Deliver superior operating performance

–

Assure safety at all times

–

Keep the lights on

–

Maintain nuclear excellence

–

Enhance environmental performance

•

Advance competitive markets

–

Support the continued improvement of

competitive wholesale markets

–

Provide reliable, affordable, low-carbon products

to customers

–

Build economic new generation

•

Exercise financial discipline and maintain

financial flexibility

–

Maintain adequate liquidity and ensure

investment grade credit rating

–

Hedge market risk appropriately

–

Focus on value, deploy our capital wisely

•

Build healthy, self-sustaining delivery

companies

–

Pursue fair regulatory treatment and improved

financial health for ComEd

–

Manage PECO’s 2011 transition to market

•

Drive the organization to the next level of

performance

–

Continuously improve productivity

–

Insist on accountability for results and values

–

Foster

positive

employee

relations

–

Identify, develop and retain key and diverse talent

•

Adapt and advance Exelon 2020

–

Reduce or offset our carbon footprint

–

Help our customers reduce their GHG emissions

–

Offer more low-carbon electricity

•

Rigorously evaluate and pursue growth

opportunities and advancements in clean

technology

–

Aggressively

pursue

‘smart

grid’

opportunities

–

Capture value from emerging renewable

technologies

•

Build the premier, enduring competitive

generation company

–

Increase our scope and scale to succeed

throughout industry cycles

–

Adapt the generation portfolio to a changing

marketplace

+

Protect Today’s Value

Grow Long-Term Value

24

25

Exelon Generation 2009 EPS Contribution

Generation’s 2009 earnings holding up well despite difficult economic environment

(1) 

Estimated contribution to Exelon’s operating earnings guidance.

(2) 

Primarily

reflects

uranium

settlements

and

option

gains

reported

in

2Q08.

($0.20)

($0.05)

$0.09

RNF

O&M

Other

Depreciation

($0.05)

$ / Share

Key

Items:

Pension & OPEB            

($0.09)

Inflation                            

($0.07)

Cost Efficiency Initiative      $0.06

Nuclear Outages         

$0.04

2008A

2009E

(1)

$3.10 –

$3.35

$3.46

Key

Items:

Discrete

2008

Gains

(2)

($0.16)

Nuclear

Fuel

Expense

($0.08)

Market/Portfolio

Position/Generation

$0.04

26

Exelon Generation

•

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

•

Complementary and flexible fossil and

hydro fleet

•

Potential Carbon legislation

•

Well positioned to capture improving

power market fundamentals

•

End of below-market contract in

Pennsylvania beginning 2011

Value Proposition

•

Continue to focus on operating excellence,

cost management, and market discipline

•

Support competitive markets

•

Execute on power and fuel hedging

programs

•

Pursue nuclear & hydro plant relicensing

and strategic investment in material

condition

•

Maintain industry-leading talent

Protect Value

•

Pursue potential for nuclear plant uprates

•

Rigorously evaluate generation

development opportunities

•

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

27

Basics of Business Unchanged

$10.00

$12.00

$14.00

$16.00

$18.00

$20.00

2003

2004

2005

2006

2007

2008

Exelon

Industry

Industry leader in Production Cost

Nuclear Annual Average Production Cost ($/MWhr)

Petroleum

Gas

Coal

Nuclear

U.S. Electricity Production Costs (2000-2007)

(1)

(1)

In 2007 Cents/kWh.  Source Global Energy Decisions May 2008;  Production Costs = Operations and Maintenance + Fuel Costs

10.26

6.78

2.47

1.76

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2003

2004

2005

2006

2007

28

Lowest Cost Nuclear Fleet Operator

Among major nuclear plant fleet operators, Exelon is consistently the lowest-cost

producer of electricity in the nation

1   Quartile

2    Quartile

3   Quartile

4   Quartile

2006-2007 Average Production Cost

for Major Nuclear Operators

(1)

Average

(1)

Source:

2007

Electric

Utility

Cost

Group

(EUCG)

survey.

Includes

Fuel

Cost

plus

Direct

O&M

divided

by

net

generation.

st

nd

rd

th

29

Effectively Managing Nuclear Fuel Costs

Components of Fuel Expense in 2008

Projected Total Nuclear Fuel Spend

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

Note: At Ownership.  Excludes costs reimbursed under the settlement agreement

with the DOE.

2008

–

2011:

100% hedged in volume

2012:

~80% hedged in volume

2013:

~70% hedged in volume

All charts exclude Salem

0.0

2.0

4.0

6.0

8.0

10.0

2008

2009

2010

2011

2012

2013

Enrichment

38%

Fabrication

17%

Nuclear Waste

Fund

22%

Tax/Interest

1%

Conversion

3%

Uranium

19%

0

200

400

600

800

1,000

1,200

1,400

2008

2009

2010

2011

2012

2013

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

2013

Exelon Average Reload Price

Projected Market Price (Spot)

30

Uranium Price Volatility

Long-term Uranium Price Trend

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

Eighteen-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)

0

20

40

60

80

100

120

140

160

0

20

40

60

80

100

120

140

31

World-Class Nuclear Operator

Average Capacity Factor

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 (2003-2007)

EXC 93.5%

Sustained production excellence

80%

85%

90%

95%

100%

Exelon

Industry

32

Impact of Refueling Outages

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

7

8

9

10

11

12

13

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

•

18 or 24 months

•

Duration: ~24 days

Nuclear Refueling Cycle

•

Reflects extended steam generator

replacement outage

•

Based on the refueling cycle, we will

conduct 10 refueling outages in 2009,

versus 12 in 2008

2009 Refueling Outage Impact

Refueling Outage Duration

Nuclear Output

Actual

Target

•

2008 reflects Salem’s extended

steam generator replacement outage

•

2008 average outage duration is 24

days without Salem

2008 Refueling Outage Impact

0

10

20

30

40

50

60

2004

2005

2006

2007

2008

Exelon w/ Salem

Industry w/o Exelon

33

Total Portfolio Characteristics

106,385

99,800

23,686

18,900

13,900

40,900

40,966

5,137

0

50,000

100,000

150,000

200,000

2008A

2009E

ComEd Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

Expected

Total

Supply

(GWh)

Expected Total Sales

(GWh)

91,595

91,600

47,747

47,300

30,300

29,449

7,383

4,300

0

50,000

100,000

150,000

200,000

2008A

2009E

Forward / Spot Purchases

Fossil & Hydro

Mid-Atlantic Nuclear

Midwest Nuclear

176,174

176,174

173,500

173,500

(1)

(1)

Includes

supply

from

fossil

and

hydroelectric

generation

under

Exelon

Generation’s

long-term

power purchase

agreements

(PPAs).

34

Hedging Targets

(1)

Percent financially hedged is our estimate of the gross margin that is hedged at a 95% confidence level given the current assessment of market volatility.  The

formula

is

the

gross

margin

at

the

5 

percentile

/

expected

gross

margin.

Power Team utilizes various products and

channels to market in order to optimize

Exelon Generation’s earnings:

•

Block product sales in power

•

Options in power and natural gas

•

Full requirements sales via retail channel and

wholesale load procurement processes

•

Supplement the portfolio with structured

transactions

•

Use physical and financial fuel products to

manage variability in fossil generation output

Target Ranges

90% -

98%

70% -

90%

60% -

80%

>90%

Current Position

~90%

Near top end of

range

Prompt Year

(2009)

Second Year

(2010)

Third Year

(2011)

Financial Hedging Range

(1)

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

mitigating downside risk

Financial hedge ratios reflect a range of

revenue net fuel based on observed

market prices and volatility

•

Generally, hedges are executed on a ratable

basis over a three-year window; therefore, the

position is well hedged in the prompt year and

significantly open in the outer years

•

Utilize options to hedge risk and preserve

upside

How to Calculate a Financial Hedge Ratio:

Gross

Margin

@

the

5 

percentile

Financial

Expected Gross Margin               Hedge Ratio

=

th

th

35

Exelon Generation Has Limited

Counterparty Exposure

Net Exposure After Credit Collateral

(1)

(in millions)

Investment grade

$1,113

Non-investment grade

3

No external ratings

27

Total

$1,143

(1)

As of December 31, 2008.  Does not include credit risk exposure from uranium procurement contracts or exposure through Regional Transmission Organizations,

Independent System Operators and New York Mercantile Exchange and Intercontinental Exchange commodity exchanges.  Additionally, does not include

receivables related to the supplier forward agreements with ComEd and the PPA with PECO. 

Exelon Generation transacts with a diverse group of counterparties, predominantly all

investment grade, and has ample liquidity to support its operations

Exelon Generation –

Sufficient Liquidity

Aggregate credit facility commitments of $4.8

billion

that

largely

extend

through

2012

–

$4.7

billion

available

as

of

February

27,

2009

Strong

balance

sheet

–

A3/BBB/BBB+

Senior

Unsecured Rating

Net Exposure by Type of Counterparty

(1)

Coal

Producers

1%

Financial Institutions

34%

Investor-Owned Utilities,

Marketers, and

Power Producers

62%

Other

3%

36

Long-Term Natural Gas Price

Forecasts Remain High

Reserve Margins Declining

Market Dynamics

Carbon Credit ($/Tonne)

Carbon Legislation Progressing

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

PJM-East

ERCOT

NI-Hub

PJM West

(1) As of 2/13/2009

Europe Carbon-Trading

2012: $11-13/tonne

Bingaman-Specter

2012: $12/tonne

EIA Carbon Case

2010: $31/tonne

Lieberman-Warner

Possible $20 to $40/tonne

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

2008

2009

2010

2011

2012

2013

NYMEX

(1)

$3

$4

$5

$6

$7

$8

$9

$10

$11

2008

2010

2012

2014

2016

2018

2020

Various

3

rd

party

estimates

37

Long-Term Investment Thesis

Power Market Fundamentals

Reserve Margins

Capacity Prices

Construction Costs

Demand Trends

Demand Profile Changes

Off-Peak Usage

Commodities

Natural Gas

Coal

Environmental Position

Carbon

SO2, NOX

Mercury

Exelon Generation’s long-term value is driven by having well-run nuclear assets located

in competitive markets, supported by positive market dynamics

Lowest-cost,

low-emissions

nuclear fleet

38

Exelon Energy

•

Provides another channel to market to

execute Power Team’s hedging strategy

•

Exelon Energy aggregate load profile complements

generation portfolio

•

Provides long-term sales to creditworthy customers,

reducing price and earnings risk

•

Vehicle for Exelon Generation to advocate

for competitive markets

•

Provides customer benefits from competitively priced

energy offerings

•

Direct access to customers

•

Provides market intelligence: trends in demand,

expectations for product and services

•

Channel to offer products that support Exelon 2020

Plan and demand reduction related programs

•

Renewable Energy Credit (REC) sales

•

Low Carbon Energy (Generation Attribute

Tracking System (GATS) tracking and transfer of

nuclear energy attributes)

•

Demand Side Management Programs

•

Growth vehicle in target regions as Exelon

Generation footprint expands

•

Planned expansion into Pennsylvania market will

provide another channel to market when PECO

purchase power agreement (PPA) ends in 2011

Exelon Energy supplies a wide range of energy and natural gas products directly to

industrial and commercial customers in Illinois, Michigan and Ohio.  Exelon Energy

leverages

broad

experience

in

wholesale

markets,

providing

a

key

element

to

executing Exelon’s Strategic Direction.

Exelon Energy

39

Reliability Pricing Model Auction

PJM RPM Auction ($/MW-day)

(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

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 PPAs.

(6)

In 09/10, obligation is reduced due to roll-off of part of ComEd auction load obligation in

May 2009.

(7)

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

(8)

PECO PPA expires December 2010.

2007 / 2008

2008 / 2009

2009 / 2010

2010 / 2011

2011/2012

in MW

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Obligation

RTO

16,000

(4)

6,600-

6,800

14,500

(5)

6,600-

6,800

12,700

4,750-

4,950

(6)

12,700

0

23,200

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)

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

40.80

197.67

148.80

111.92

191.32

191.32

102.04

174.29

174.29

110.00

RTO

Eastern MAAC

MAAC + APS

MAAC

2007/2008

2008/2009

2009/2010

2010/2011

2011/2012

40

$0

$20

$40

$60

$80

$100

$120

2008 Auction

2009 Auction

Full Requirements Cost

ATC Forward Energy Price

NJ

BGS

Auction

Results

(2008

–

2009)

$111.50/MWh

(36 month price)

$103.72/MWh

(36 month price)

~$42

~$48

$69.50

-$71

$55.50

-$57.25

•

The results shown are for PSE&G

•

“ATC

Forward

Energy

Price”

represents

the

range

of

forward

market prices that traded during the 2008 and 2009 Auctions

Full Requirements Costs

Auction Results

Load Shape &

Ancillary Services

$10.00

Capacity

$16.00

Transmission &

Congestion

$16.00

Renewable

Energy

$3.00

Migration &

Volumetric

Risk & Other

$3.00

Note: BGS = Basic Generation Service

41

Current Market Prices

8.28

6.32

6.98

43.87

13.04

66.38

(4)

6.74

(4)

60.87

(3)

59.68

(2)

41.42

(2)

51.07

(2)

2006

(1)

7.80

6.65

7.68

47.54

9.67

69.72

(4)

6.74

(4)

59.44

(3)

66.72

(2)

45.47

(2)

59.76

(2)

2007

(1)

7.42

5.57

6.97

105.36

12.17

104.97

(4)

8.85

(4)

73.36

(3)

80.56

(2)

49.00

(2)

68.52

(2)

2008

(1)

7.44

6.70

8.15

61.80

10.66

46.39

4.71

38.56

48.98

30.63

45.08

2009

(5)

7.46

5.30

7.23

65.51

12.45

55.79

6.08

51.03

56.69

31.64

50.35

2010

(6)

7.65

5.63

7.12

67.51

13.71

60.63

6.69

57.52

61.58

36.93

54.18

2011

(6)

Units

2012

(6)

PRICES (as of February 27, 2009)

PJM West Hub ATC

($/MWh)

56.40

PJM NiHub ATC

($/MWh)

41.51

NEPOOL MASS Hub ATC

($/MWh)

63.56

ERCOT North On-Peak

($/MWh)

60.13

Henry Hub Natural Gas

($/MMBTU)

6.88

WTI Crude Oil

($/bbl)

64.12

PRB 8800

($/Ton)

14.60

NAPP 3.0

($/Ton)

67.50

ATC HEAT RATES (as of February 27, 2009)

PJM West Hub / Tetco M3

(MMBTU/MWh)

7.22

PJM NiHub / Chicago City Gate

(MMBTU/MWh)

6.15

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.68

(1)  2006, 2007 and 2008 are actual settled prices.

(2)  Real Time LMP (Locational Marginal Price).

(3)  Next day over-the-counter market.

(4)  Average NYMEX settled prices.

(5)  2009 information is a combination of actual prices through February 27, 2009 and market prices for

the balance of the year.

(6)  2010, 2011 and 2012 are forward market prices as of February 27, 2009.

42

Market Price Snapshot

20

30

40

50

60

70

80

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

35

45

55

65

75

85

95

105

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

50

60

70

80

90

100

110

120

130

140

150

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

5.5

6.5

7.5

8.5

9.5

10.5

11.5

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

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 February 27, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

$6.08

$6.69

2010

2011

$57.75

$62.25

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

$58.28

$63.04

$39.75

$29.25

$46.46

$24.52

$45.75

$43.39

43

Market Price Snapshot

7

8

9

10

11

12

13

14

15

16

17

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

50

55

60

65

70

75

80

85

90

95

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

5.5

6.5

7.5

8.5

9.5

10.5

11.5

2/08

3/08

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

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

$5.69

$6.32

$57.52

$51.03

$8.97

$9.11

$7.47

$9.46

Rolling 12 months, as of February 27, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

44

Exelon Nuclear Fleet Overview

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

(1)

Capacity based on ownership interest.

Average in-service time = 28 years

2011

42.59% Exelon,

57.41% PSEG

2016, 2020

503, 491

(1)

W

PWR

2

Salem, NJ

Life of plant capacity

100%

2014; renewal filed

2008

837

B&W

PWR

1

TMI-1, PA

Dry cask

100%

2009; renewal filed

2005

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

570, 570

(1)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

650, 653

(1)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

869, 871

GE

BWR

2

Dresden, IL

2010

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask

100%

2024, 2029

1149, 1146

GE

BWR

2

Limerick, PA

2018

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%

2026

1065

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 2008

Plant, Location

45

46

ComEd 2009 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

(2)

Disallowances recorded in September 2008 in connection with the Illinois Commerce Commission (ICC) order in ComEd’s distribution rate case.

ComEd’s operating earnings are expected to increase in 2009 primarily due to

continued execution of its Regulatory Recovery Plan

2008A

RNF

O&M

Depreciation /

Amortization

Interest

Expense

$0.45 -

$0.55

$0.33

$0.20

$0.01

($0.04)

2009E

(1)

Key Items:

Cost

Efficiency

Initiative

$0.08

Rate

Case

Disallowance

(2)

$0.02

Storms

$0.02

Energy

Efficiency

($0.04)

Pension

&

OPEB

($0.04)

Inflation

($0.03)

$ / Share

Key Items:

Distribution Rates            $0.17

Energy Efficiency             $0.04

Weather                            $0.01

Load

Growth

($0.02)

($0.00)

$0.03

Other

47

ComEd Load Growth Trends

Weather-Normalized Load Growth

ComEd Customer Usage by Revenue Class

Key Economic Indicators

Top 380 Customer Usage by Segment

Other

2%

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

3%

Leisure & Hospitality

9%

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Chicago

U.S.

Unemployment rate

(1)

7.1%

7.6%

4   Qtr ‘08 annualized growth in

gross domestic/metro product

(2)

(7.0%)

(6.2%)

12/08 Home price index

(3)  

(14.3%)    

(18.5%)

(1)  Source: Illinois Dept. of Employment Security (Dec08) and U.S. Dept. of Labor (Jan09)

(2)  Source: Moody’s Economy.com

(3)  Source: S&P Case-Shiller Index

Q4 2008

FY 2008

2009E

Customer Growth

0.1%

0.5%

0.2%

Average Use-Per-Customer

(0.6%)

0.0%

(0.8%)

Total Residential

(0.5%)

0.5%

(0.6%)

Small C&I

(2.9%)

(0.3%)

(0.8%)

Large C&I

(1.0%)

(0.4%)

(2.1%)

All Customer Classes

(1.6%)

(0.1%)

(1.1%)

Note: C&I = Commercial & Industrial

th

48

6.1

2.0

6.9

6.4

2.0

2.1

Transmission

Distribution

ComEd –

Moving Forward

Executing Regulatory

Recovery Plan

~9 –

10%

~ 45%

~7.3 –

8.8%

~ 46%

ROE

Equity

(1)

~5.0 –

6.0%

~

45%

8.1

8.4

9.0

2008

2009E

2011

(Illustrative)

(2)

Average

Annual

Rate

Base

(1)

($ in Billions)

ComEd’s

earnings

are

expected

to

increase

as

regulatory

lag

is

reduced

over

time

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

(1)     Equity

based

on

definition provided

in

most

recent

ICC

distribution

rate

case

order

(book

equity

less

goodwill).

Projected

book

equity

ratio

in

2008

is

58%.

(2)   

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.

•

Cost reduction and control initiatives

combined with the recent delivery service

tariff (DST) rate increase and regular

transmission rate updates 

•

Illinois Power Agency proposed

procurement

plan

for

ComEd

-

first

procurement in Spring 2009

•

Actively promoting/implementing

efficiency, renewable energy, and

demand-side management programs

•

Studying future test year approach for

distribution rate filing

49

Illinois Power Agency Procurement Plan

•

On January 7, 2009 the Illinois Commerce Commission’s Final Order was

entered

(1)

which approved, with minor modifications, the Illinois Power

Agency’s proposed procurement plan originally filed in September 2008.

•

In April/May 2009 a single procurement event will be conducted to procure

the remaining ComEd 2009-10 load (~29% of the total ComEd load).

Auction Contracts

Financial Swap

3/08

RFP

Jun 2007

Jun 2008

Jun 2009

Jun 2010

Jun 2011

Jun 2012

Jun 2013

NOTE: For illustrative purposes

only.  Assumes constant load profile

each year. 

2009

2009

Future Procurement by Illinois Power Agency

2010

2010

2011

2012

2011

(1)

Reference:

ICC

Docket

#

08-0519

Auction Contracts

Financial Swap

3/08

RFP

Jun 2007

Jun 2008

Jun 2009

Jun 2010

Jun 2011

Jun 2012

Jun 2013

NOTE: For illustrative purposes

only.  Assumes constant load profile

each year. 

2009

2009

Future Procurement by Illinois Power Agency

2010

2010

2011

2012

2011

50

The ICC issued a final Order in ComEd’s distribution rate case –

granting a revenue increase of $273.6 million that took effect on

September 16, 2008:

(14)

345

359

Depreciation and Amortization

$(87)

274

361

Total Revenue Increase

3  

129

132

Other Revenues

(11)

987

998

O&M Expenses

(22)

10.30% ROE /   

45.04% Equity

10.75% ROE /

45.11% Equity

ROE / Cap Structure

$(43)

$6,694

$7,071

Rate Base

Impact on

Revenue

Increase

ICC Order

ComEd

Original

Request

($ in millions)

ComEd Executing on Regulatory Recovery

Plan –

2008 Rate Case

51

52

PECO 2009 EPS Contribution

(1)

Excludes preferred dividends

(2)

Estimated Operating Earnings

PECO’s 2009 operating earnings are expected to be comparable to 2008 due to

the gas distribution rate increase and lower bad debt expense, offset by higher

CTC amortization

$/Share

RNF

$0.45-$0.55

(1)

$0.49

(1)

$0.05

($0.10)

Depreciation/

Amortization

2008A

2009E

(2)

Key Items:

Gas Rate Case     $0.07

Weather                   0.03

Load Growth          (0.02)

Pricing/Cust. Mix    (0.02)

Other                       (0.01)

Key Items:

Bad

Debt

$0.07

Cost

Efficiency

0.02

Inflation/Other

(0.06)

Regulatory/Post

2010

(0.01)

Pension

&

OPEB

(0.01)

$0.01

O&M

$0.04

Interest

Expense/ Other

Key Items:

Competitive Transition

Charge (CTC) Amortization      ($0.09)

Key Items:

CTC Interest Expense/

Other                                     $0.04

53

PECO Load Growth Trends

Other

2%

Other Large

C&I

21%

150 Large

C&I

21%

Small C&I

22%

Residential

34%

Weather-Normalized Electric Load Growth

Q4 2008

FY 2008

2009E

Customer Growth

0.5%

0.7%

0.1%

Average Use-Per-Customer

(0.9%)

1.1%

(0.6%)

Total Residential

(0.4%)

1.8%

(0.5%)

Small C&I

0.7%

(0.2%)

(0.8%)

Large C&I

(2.4%)

0.1%

(1.9%)

All Customer Classes

(1.1%)

0.6%

(1.1%)

PECO Customer Usage by Revenue Class

Philadelphia

U.S.

1/09 Unemployment rate

(1)

6.8%

7.6%

4

th

Qtr ‘08 annualized growth in

gross domestic/metro product

(2)

(4.0%)

(6.2%)

Key Economic Indicators

Top 150 Customer Usage by Segment

18%

Health & Educational Services

19%

Manufacturing

21%

Petroleum

3%

Retail Trade

4%

Other

9%

Transportation, Communication

& Utilities

13%

Finance, Insurance & Real

Estate

13%

Pharmaceuticals

(1)  Source: Moody’s Economy.com and U.S. Department of Labor

(2)  Source: Moody’s Economy.com

54

2.8

2.9

3.2

0.5

0.6

1.7

0.9

1.1

1.1

1.2

0.7

Gas

CTC

Electric Transmission

Electric Distribution

PECO –

Moving Forward

Actively Engaged in Transition

~9 –

11.5%

(3)

Not applicable due to

transition rate structure

Rate Making ROE

Equity

~50 –

53%

6.1

5.5

5.1

Average

Annual

Rate

Base

(1)

($ in Billions)

2008

2009E

2011

(Illustrative)

(2)

(1)

Rate base as determined for rate-making purposes.

(2)

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.

(3)

Assumes PECO is awarded 100% of potential requested revenue increases for rate cases filed during the planning period.

•

Successful outcome of 2008 gas rate

case provides for increased gas revenues

of $76.5 million

•

Next rate case(s) expected to be filed in

2010 –

2011

•

Developing plans and programs to

implement energy efficiency, demand

response and smart meter provisions of

Act 129 (HB2200)

•

Transitioning through an orderly structure

to market-based rates

–

Working with the Governor, Legislature and

Pennsylvania Public Utility Commission

(PAPUC) for post-transition rates and

structure

–

Power Procurement Plan filed 9/10/08 to

address post-transition plan beginning in

2011 along with mitigation alternatives

Pursuing a successful transition to market-based rates and regular rate case outcomes

55

2.63

2.63

0.48

0.48

2.41

6.00

10.75

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) 

Provided for illustration only.  Not necessarily representative of PECO’s internal forecast, which is highly dependent at any point in time on

energy market conditions.

2011

2008 –

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

11.52¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~20%

13.86¢

Assumptions

Illustrative Rate Increase Based on

Average

PPL

Procurement

Results

(2)

•

2011 default service rate will reflect

associated full requirements costs and be

acquired through multiple procurements

•

Using the average results of completed

PPL procurements for 2010 and assuming

a 50/50 weighting of Residential and

Small

C&I

customers

produces

a

proxy

of

10.75¢/kWh. This will result in a system

average rate increase of ~20%

•

PECO’s 2011 full requirements price

expected to differ from PPL due, in part, to

the timing of the procurement (2011 vs.

2010) and locational differences

•

Rates will vary by customer class and 

may be impacted by legislation and

procurement model

Residential

Small C&I

Round 1, 7/2007

$101.77

$105.11

Round 2, 10/2007

$105.08

$105.75

Round 3, 3/2008

$108.80

$108.76

Average

PPL Procurement Results

Round 4, 10/2008

$112.51

$111.94

$107.04

$107.89

56

PECO’s procurement plan

for obtaining default service Post 2010

includes a portfolio of full requirements and spot products competitively

procured through multiple RFP solicitations

Mitigation plan

includes early staggered procurement, voluntary post-rate

cap

phase-in,

gradual

phase-out

of

declining

block

rate

design,

customer

education, enhanced retail choice program, and low-income rate design

changes

Block Products & Spot

Long-Term contracts

No intervener challenge on one-way margining

Default Service

Procurement and

Mitigation Filing

Early Phase-in Filing

Addressing Key

Intervener Issues

Early phase-in proposal

provides a voluntary opt-in program for

customers to pre-pay towards 2011 prices

PAPUC approval expected in March 2009 to allow for implementation

July 1, 2009

PECO’s third quarter 2008 regulatory filings address procurement and rate mitigation –

allowing PECO to execute on its regulatory strategy

PECO Post-2010 Procurement Plan

57

Pennsylvania Act 129 Highlights

•

Energy Efficiency (EE) and Demand Response (DR)

–

EE Targets of 1% reduction in consumption by 2011, 3% reduction by 2013

–

DR target of 4.5% reduction in peak demand by 2013

–

Up to $20 million in penalties for failure to achieve targets

–

Full and current program cost recovery through surcharge mechanism

–

Reduced consumption reflected in future rate base proceedings

–

Spending cap equal to 2% of revenue

•

Smart Meters

–

Utilities must file smart meter file plan with PAPUC by August 2009

–

Required to furnish meters upon 1) customer request, 2) for new construction,

and 3) on a depreciation schedule not to exceed 15 years

–

Base rate or surcharge recovery

•

Procurement

–

Competitive procurement using auctions, RFPs or bilateral agreements

–

Prudent mix of spot, short term or long term (defined as 4-20 years) contracts

PECO will file Energy Efficiency and Demand-Side Management plan in 2009

58

Federal Policy Update

59

Advocating for Coherent Public Policies

Actively involved in the climate

debate in Washington, D.C.

Lobbying in favor of enacting

legislation that is national, mandatory

and economy-wide

Favor a cap-and-trade system over a

carbon tax

Believe that allowances should be

provided to local distribution

companies for the benefit of their

customers, including rate impact

mitigation

To limit economic impacts, support a

cost containment mechanism that

supports a market price for carbon

that increases over time

Federal, mandatory, economy-wide cap & trade

climate legislation

Support for energy efficiency and conservation

across the entire economy, including new

standards as well as programs and investment

by utilities

An economically responsible approach to

renewable energy

Financial support for new low-carbon, base

load generation, such as clean coal and next-

generation nuclear

Continued commitment to competitive

electricity markets to spur investment and

innovation in new low-carbon solutions

Advocating for Federal Climate Change

Legislation

60

Status of Legislative Initiatives

–

Cap and Trade program to reduce emissions by 80% by 2050 with 100% auction of

allowance permits

–

Proposed long-term budget plans assume ~$70B of annual carbon revenues

beginning in 2012

–

Renewable Electricity Standard (RES): 10% by 2012 and 25% by 2025

Congress:

Senate: 

•

Climate: Chairman Boxer released principles for climate change legislation

•

Majority Leader Reid has indicated his hope for a bill in late summer

•

Renewable

Electricity

Standard:

Chairman

Bingaman

introduced

20%

RES

by

2021

House: 

•

Climate: Chairman Waxman pledges to have a bill out of the Energy and Commerce

Committee by Memorial Day

•

Renewable Electricity Standard: Chairman Markey introduced 25% RES by 2025

Obama Administration Climate and Energy Plan:

61

Stimulus Package Impact On Energy

Industry

•

Long-term extension of production tax credit (PTC)

•

Temporary election to claim investment tax credit in

lieu of PTC

•

Grants in lieu of tax credits for renewables

•

Provides loan guarantees for renewable and

transmission projects

•

Provides $2.5 billion for renewable and energy

efficiency research, development, demonstration

and deployment (RDD&D)

Renewables

Energy Efficiency

Smart Grid

•

Provides $3.1 billion for State Energy Programs

•

Provides $3.2 billion for Energy Efficiency and

Conservation Block Grants to the States

•

Provides $5 billion for weatherization

•

Provides $4.5 billion for the Smart Grid Investment

Program

•

Authorizes Federal match for up to 50 percent of

project costs

Actively working with local

officials to discuss coordination

opportunities

62

Federal Environmental Regulatory Update

Clean Air Interstate

Rule (CAIR)

Clean Air Mercury

Rule (CAMR)

Greenhouse Gas

(GHG) Emissions

In a December 2008 decision, the D.C. Circuit Court of Appeals allowed CAIR to

remain

in

effect

in

eastern

states

pending

U.S.

EPA

revisions

to

address

issues

raised

by

the

court

in

its

original

July

11,

2008

opinion.

CAIR

NOx

reductions

begin

in 2009 (ozone-season and, for the first time, annual).  Annual NOx imposes new

costs in non-ozone season months. CAIR SO2 reductions start in 2010.

Rule

vacated

by

D.C.

Circuit

Court

of

Appeals

in

February

2008.

EPA

appeal

to

Supreme Court withdrawn in January 2009.  EPA now expected to propose new

hazardous

air

pollutant

(HAP)

rulemaking

for

electric

generating

units

that

may

include other HAPs in addition to mercury from coal-fired generation.

In response to Massachusetts vs. U.S. EPA, EPA is required to consider whether

GHG emissions may reasonably be anticipated to endanger public health or

welfare.  Should it issue an affirmative finding, EPA could elect to pursue

regulation

of

GHG

emissions

under

the

existing

federal

Clean

Air

Act.

An

advanced notice of proposed rulemaking (ANPR) was issued last year.  EPA

currently reviewing ANPR comments.  Federal legislation is the preferred option.

Significant short-term environmental regulatory uncertainty remains due to litigation

results and change of administration.  However, long-term trend remains towards

tighter air quality regulations that will benefit lower-emission generation

63

Key Assumptions, Projected 2009 Credit

Measures &

GAAP Reconciliation

64

Key Assumptions

37.3

1.2

2.6

23.86

115.37

6.65

6.84

45.47

7.68

7.78

59.76

6.74

148,307

41,343

189,650

94.5

2007 Actual

36.1

(0.1)

0.6

82.39

169.09

5.57

8.79

49.00

6.97

9.83

68.52

8.85

135,208

40,966

176,174

93.9

2008 Actual

5.00

Chicago City Gate Gas Price ($/mmBtu)

5.91

Tetco M3 Gas Price ($/mmBtu)

36.7

Effective Tax Rate (%)

(4)

(1.1)

ComEd

(1.1)

PECO

Electric Delivery Growth (%)

(3)

106.13

PJM West Capacity Price ($/MW-day)

173.73

PJM East Capacity Price ($/MW-day)

6.96

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

34.79

NI Hub ATC Price ($/MWh)

8.15

PJM West Hub Implied ATC Heat Rate

(mmbtu/MWh)

48.18

PJM West Hub ATC Price ($/MWh)

4.98

Henry Hub Gas Price ($/mmBtu)

132,600

Total Genco Market and Retail Sales (GWhs)

(2)

40,900

Total Genco Sales to PECO (GWhs)

173,500

Total Genco Sales Excluding Trading (GWhs)

93.1

Nuclear Capacity Factor (%)

(1)

2009 Est.

(1)

Excludes Salem

.

(2)

Includes Illinois Auction sales and ComEd swap.

(3)

Weather-normalized retail load growth.

(4)

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

Notes:

2007 and 2008 prices are averages for those years.

2009 prices reflect observable prices as of January 31, 2009.

65

Projected 2009 Key Credit Measures

BBB

A-

BBB+

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa2

Baa1

Moody’s Credit

Ratings

(3)

3.5x

3.6x

FFO / Interest

ComEd:

17%

13%

FFO / Debt

42%

50%

Rating Agency Debt Ratio

3.2x

3.0x

FFO / Interest

PECO:

12%

10%

FFO / Debt

49%

54%

Rating Agency Debt Ratio

24%

47%

Rating Agency Debt Ratio

123%

47%

FFO / Debt

28.2x

10.6x

FFO / Interest

Exelon

Generation:

50%

34%

6.9x

Without PPA &

Pension / OPEB

(2)

61%

Rating Agency Debt Ratio

23%

FFO / Debt

5.6x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

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 Exelon Generation and senior secured ratings for ComEd and PECO as of February 27, 2009.  On October 21, 2008, S&P put

Exelon, ComEd, PECO and Exelon Generation on CreditWatch with negative implications. On October 21, 2008, Fitch placed Exelon and Exelon Generation on rating watch

negative.

On

November

12,

2008,

Moody’s

placed

the

ratings

of

Exelon,

Exelon

Generation

and

PECO

under

review

for

possible

downgrade.

66

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)

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.

67

2008 GAAP Reconciliation

(0.02)

-

-

(0.02)

-

City of Chicago settlement with ComEd

(0.02)

(0.02)

-

-

-

NRG acquisition costs

0.03

0.03

Settlement of tax matter at Generation related to Sithe

0.02

-

-

-

0.02

Decommissioning obligation reduction

$4.13

($0.10)

$0.49

$0.30

$3.44

2008 GAAP Earnings (Loss) Per Share

$4.20

($0.08)

$0.49

$0.33

$3.46

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.22)

-

-

(0.01)

(0.21)

2007 Illinois Electric Rate Settlement

0.41

-

-

-

0.41

Mark-to-market adjustments from economic hedging activities

(0.27)

-

-

-

(0.27)

Unrealized gains & losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

2008 GAAP EPS Reconciliation

(1)

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

Note: Amounts may not add due to rounding.

20

-

-

-

20

Settlement

of

tax

matter

at

Generation

related

to

Sithe

272

-

-

-

272

Mark-to-market adjustments from economic hedging activities

(145)

-

-

(7)

(138)

2007 Illinois Electric Rate Settlement

15

-

-

-

15

Decommissioning obligation reduction

(11)

(11)

-

-

-

NRG acquisition costs

($67)

-

-

($56)

Other

$2,737

(11)

(184)

$2,781

Exelon

$325

-

-

$325

PECO

$201

(11)

-

$219

ComEd

ExGen

2008 GAAP Earnings Reconciliation (in millions)

-

City of Chicago settlement with ComEd

$2,278

2008 GAAP Earnings (Loss)

(184)

Unrealized gains & losses related to nuclear decommissioning trust funds

$2,293

2008 Adjusted (non-GAAP) Operating Earnings (Loss)

68

2009 Earnings Outlook

•

Exelon’s outlook for 2009 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

primarily related to the AmerGen nuclear plants

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement,

including

ComEd’s previously announced customer rate relief programs

•

Costs associated with ComEd’s 2007 settlement with the City of Chicago

•

Certain costs associated with the proposed offer to acquire NRG Energy Inc.

•

Other unusual items

•

Significant future changes to GAAP

•

Both our operating earnings and GAAP earnings guidance are

based on the assumption of normal weather

69

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

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

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com