Exelon (EXC) 8-K Regulation FD Disclosure

Bank of America Merrill Lynch

2011

Power and

Gas Leaders

Conference

Christopher

M

Crane

–

President

and

COO,

Exelon

Corp.

September 20, 2011

EXHIBIT 99.1

Cautionary Statements Regarding

Forward-Looking Information

2

Except for the historical information contained herein, certain of the matters discussed in this communication

constitute “forward-looking statements” within the meaning of the Securities Act of 1933 and the Securities Exchange

Act of 1934, both as amended by the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,”

“anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “target,” “forecast,” and words and terms of

similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking

statements. These forward-looking statements include, but are not limited to, statements regarding benefits of the

proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration

plans and expected synergies, the expected timing of completion of the transaction, anticipated future financial and

operating performance and results, including estimates for growth. These statements are based on the current

expectations of management of Exelon and Constellation, as applicable. There are a number of risks and

uncertainties that could cause actual results to differ materially from the forward-looking statements included in this

communication regarding the proposed merger. For example, (1) the companies may be unable to obtain

shareholder approvals required for the merger; (2) the companies may be unable to obtain regulatory approvals

required for the merger, or required regulatory approvals may delay the merger or result in the imposition of

conditions that could have a material adverse effect on the combined company or cause the companies to abandon

the merger; (3) conditions to the closing of the merger may not be satisfied; (4) an unsolicited offer of another

company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (5) problems

may arise in successfully integrating the businesses of the companies, which may result in the combined company

not operating as effectively and efficiently as expected; (6) the combined company may be unable to achieve cost-

cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve

unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different

from the companies’ expectations; (8) the credit ratings of the combined company or its subsidiaries may be different

from what the companies expect; (9) the businesses of the companies may suffer as a result of uncertainty

surrounding the merger; (10) the companies may not realize the values expected to be obtained for properties

expected or required to be divested; (11) the industry may be subject to future regulatory or legislative actions that

could adversely affect the companies; and (12) the companies may be adversely affected by other economic,

business, and/or competitive factors. Other unknown or unpredictable factors could also have material adverse

effects on future results, performance or achievements of Exelon, Constellation or the combined company.

Cautionary Statements Regarding

Forward-Looking Information (Continued)

3

Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s

respective filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at

www.sec.gov, including: (1)  Exelon’s 2010 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 Quarterly Report on Form 10-Q for the quarterly period

ended June 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial

Information, ITEM 1. Financial Statements: Note 13; (3)  Constellation’s 2010 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 12; and (4) Constellation’s Quarterly Report on

Form 10-Q for the quarterly period ended June 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors and

ITEM 5. Other Information, (b) Part I, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial

Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Notes to

Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated

with the proposed merger, are more fully discussed in the preliminary joint proxy statement/prospectus included in

Amendment No. 1 to the Registration Statement on Form S-4 that Exelon filed with the SEC on August 17, 2011 in

connection with the proposed merger.  In light of these risks, uncertainties, assumptions and factors, the forward-looking

events discussed in this communication may not occur. Readers are cautioned not to place undue reliance on these

forward-looking statements, which speak only as of the date of this communication. Neither Exelon nor Constellation

undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or

circumstances after the date of this communication.

Additional Information and Where to Find It

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities, or a solicitation

of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale

would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction.  On August 17,

2011, Exelon filed with the SEC Amendment No. 1 to its Registration Statement on Form S-4 that included a preliminary

joint proxy statement/prospectus and other relevant documents to be mailed by Exelon and Constellation to their

respective security holders in connection with the proposed merger of Exelon and Constellation.

Additional Information and Where to Find It

These materials are not yet final and may be amended.  WE URGE INVESTORS AND SECURITY HOLDERS TO READ

THE PRELIMINARY JOINT PROXY STATEMENT/PROSPECTUS AND THE DEFINITIVE JOINT PROXY

STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE,

BECAUSE

THEY

CONTAIN

OR

WILL

CONTAIN

IMPORTANT

INFORMATION

about

Exelon,

Constellation

and

the

proposed

merger.

Investors

and

security

holders

will

be

able

to

obtain

these

materials

(when

they

are

available)

and

other

documents filed with the SEC free of charge at the SEC's website, www.sec.gov.  In addition, a copy of the preliminary joint

proxy statement/prospectus and definitive joint proxy statement/prospectus (when it becomes available) may be obtained

free of charge from Exelon Corporation, Investor Relations, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois

60680-5398, or from Constellation Energy Group, Inc., Investor Relations, 100 Constellation Way, Suite 600C, Baltimore,

MD 21202. Investors and security holders may also read and copy any reports, statements and other information filed by

Exelon, or Constellation, 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.

Participants in the Merger Solicitation

Exelon,

Constellation,

and

their

respective

directors,

executive

officers

and

certain

other

members

of

management

and

employees may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction.

Information regarding Exelon’s directors and executive officers is available in its proxy statement filed with the SEC by

Exelon on March 24, 2011 in connection with its 2011 annual meeting of shareholders, and information regarding

Constellation’s directors and executive officers is available in its proxy statement filed with the SEC by Constellation on

April 15, 2011 in connection with its 2011 annual meeting of shareholders. Other information regarding the participants in

the

proxy

solicitation

and

a

description

of

their

direct

and

indirect

interests,

by

security

holdings

or

otherwise,

is

contained

in the preliminary joint proxy statement/prospectus and will be contained in the definitive joint proxy statement/prospectus.

4

Creating Value Through a Strategic Merger

Delivers financial benefits to both sets of shareholders

Increases scale and scope of the business across the value chain

Matches the industry’s premier clean merchant generating fleet with the

leading retail and wholesale customer platform

Diversifies the generation portfolio

Continued upside to power market recovery

Maintains a strong regulated earnings profile with large urban utilities

Successful integration experience from prior mergers and acquisitions

Combining Exelon’s generation fleet and Constellation’s customer-facing

businesses creates a strong platform for growth and delivers benefits to

investors and customers

5

Combination Will Result in Enhanced Scale,

Scope, Flexibility and Financial Strength

•

$8 billion

•

$11 billion

•

11,980 (Total)

•

1,921 (Nuclear)

•

1.2 mil. (MD) 

•

0.7 mil. (MD)

•

44 states & D.C.

(5)

•

~110 TWh/yr

•

29% Generation

•

44% Utility

•

27% NewEnergy

Market  Value and

Enterprise

Value

(1)

Pro forma

Standalone

Owned

Generation

(in MW)

(2)

Regulated

Utilities

Competitive

Retail &

Wholesale

(4)

Business

Mix

(6)

•

$28 billion

•

$41 billion

•

26,339 (Total)

•

17,047 (Nuclear)

Electric customers

•

5.4 mil. (IL, PA)

Gas customers

•

0.5 mil. (PA)

•

4 states

•

~59

TWh/yr

2011 EBITDA

•

61% Generation

•

39% Utilities

•

$35 billion

•

$52 billion

•

44 states & D.C.

(5)

•

~169

TWh energy sales

•

Expect >50% pro forma EBITDA

from competitive business

•

35,671

(Total)

(3)

•

18,968 (Nuclear)

•

6.6 million electric & gas customers

in IL, PA and MD

Note: Data as of 12/31/10 unless stated otherwise.

(1)  Market Value as of 9/14/11. Enterprise Value represents Market Value plus Net Debt as of 6/30/11.

(2)  Exelon data includes 720 MW for Wolf Hollow. Constellation data includes 2,950 MW for Boston Generation assets.

(3)  Net of physical market mitigation assumed to be 2,648 MW.

(4)  TWh/yr represents 2011 booked electric sales as of 12/31/2010. Exelon load includes ComEd swap. Data also includes 2011 partial year                                                       

estimated electric sales from StarTex and MXEnergy (acquired by Constellation).

(5)  Competitive and wholesale business also active in Alberta, British Columbia and Ontario, Canada.

(6)  Exelon EBITDA estimates per equity research. Constellation EBITDA estimates per company guidance from Q1 2011.

6

On Track for Merger Close in Early Q1 2012

2011

2012

Q3

Q4

Q1

Filed for indirect transfer of Constellation Energy licenses on

May 12, 2011

Expect approval in Q4

Filed merger approval application related filings on

May 20, 2011

Submitted HSR filing on May 31, 2011 for review under U.S. antitrust laws

Filed for approval with the Maryland  PSC on May 25, 2011

Approvals

Shareholder vote

Shareholder vote

1/5/12

Decision deadline

SEC

NRC

Texas PUCT

Secured approval from Texas

FERC

DOJ

NY PSC

MD PSC

Regulatory

proceedings

are

progressing

well

and

we

are

on

track

to

close

in

early Q1, 2012

Proxy mailing

SEC has completed its

review of S-4

7

Project

Nuclear Uprates

Wind

Wolf Hollow Acquisition

RiteLine

Investment

$3.3 billion

$490 million

$305 million

$1.1 billion

Capacity

1,300 MW

230 MW

720 MW

N.A.

States

IL, PA

MI

TX

IL, IN,OH

Committed To Value Driven Growth

8

Capitalize on

operational

excellence

Straight forward

regulatory approval

process

Investment flexibility

Efficient tax

structure and

equity recovery

Low risk and

stable cash flows

Expansion in a

new market (MI)

Commitment to

competitive

markets 

Attractive

purchase price

and upside

opportunity in TX

Pre-determined

and guaranteed

return on equity

Enhance reliability

and support

renewable

integration

Nuclear

Renewables

CCGT

Transmission

These investments further our commitment to Exelon 2020 and a low carbon future,

while providing attractive financial returns and diversifying our earnings within the

merchant segment of our business

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% additional output

•

Requires NRC approval

197–233 MW

$330M

2-3 years

745–826 MW

$2,155M

EPU (Extended Power Uprate)

•

Through a combination of more sophisticated analysis and

upgrades to plant equipment, uprates can increase output by as

much as 20% of original licensed power level

•

Requires NRC approval

3 -

6

years

234–255 MW

$790M

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

3-4 years

~1,175–1,300 MW

$3,275M

Project

Duration

(1)

In 2011 dollars. Overnight costs do not include financing costs or cost escalation.

Estimated

Internal Rate

of Return

12-14%

13-16%

10-14%

Refined

scenario

analysis

highlights

that

uprates

continue

to

be

economic

9

Wolf Hollow Acquisition and Exelon Wind

Diversifies generation portfolio :

•

Expands geographic and fuel characteristics of fleet

•

Advances our merger strategy of matching load with generation

Creates value for shareholders :

•

$305M purchase price compares favorably to recent transactions

•

Free cash flow accretive beginning in 2012

•

Opportunity

to

benefit

from

future

market

heat

rate

expansion

in

ERCOT

ERCOT : Electric Reliability Council of Texas;  COD : Commercial

Operation Date

Wolf

Hollow

Acquisition

–

Successfully

closed

on

August

24,

2011

Exelon Wind –

Successfully executing on development projects

Successfully

acquired

and

integrated

a

sizeable

wind

generation

portfolio

Moving ahead with three development projects

•

Michigan Wind 2 project (90 MWs) expected COD December 2011

•

Harvest II wind project (59.4 MWs) expected COD December 2012

•

Blissfield wind project (81 MW)  expected COD December 2012

10

RITE Line Project Update

Project Background

•

420 miles of 765kV transmission

stretches from Northern Illinois to

Ohio.  The RITE Line will be built

from the existing 765kV system in

Ohio in the East to the West

•

Estimated construction to begin

2015 pending regulatory approvals

and siting

Strategic and Financial Objectives

•

Ensures reliability, enables states to

meet RPS standards, and supports

the integration of more renewables

•

ComEd/Exelon investment ~ $1.1

billion

•

Requested ROE 12.70%

Latest Developments

•

Signed partnership agreement with

ETA on July 13

•

Completed FERC incentive rate

filing on July 18. Expect FERC ruling

by October 2011.

Note: ETA = Electric Transmission America

RPS = Renewable Portfolio Standards

RTEP = Regional Transmission Expansion Planning

11

2016

2017

2018

FERC Final Rule on NOPR

PJM Compliance Filing

2010

State Local Outreach & Project Siting

Establish Definitive Agreement

Between Exelon & ETA

2012

FERC Incentive

Construction

RITE Line

2013

2011

2015

In-Service

Pursue PJM RTEP Approval

RTEP Approval expected by

2012, depending on

PJM Planning criteria

Time length is dependent on:

1.  Land negotiations

2.  Receipt of State

Line

can

be

in-serviced

in

phases

Construction

can

range

from

3-5

yrs

depending on the length of time

needed to site the project

Non

Project Specific Events

2014

Filing

-

Exelon Generation Hedging Disclosures

(as of June 30, 2011)

12

Important Information

13

The following slides are intended to provide additional information regarding the hedging

program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon

Generation’s gross margin (operating revenues less purchased power and fuel expense). The

information on the following slides is not intended to represent earnings guidance or a forecast

of future events.  In fact, many of the factors that ultimately will determine Exelon Generation’s

actual gross margin are based upon highly variable market factors outside of our control.  The

information on the following slides is as of June 30, 2011.  We update this information on a

quarterly basis.

Certain information on the following slides is based upon an internal simulation model that

incorporates assumptions regarding future market conditions, including power and commodity

prices, heat rates, and demand conditions, in addition to operating performance and dispatch

characteristics of our generating fleet.  Our simulation model and the assumptions therein are

subject to change.  For example, actual market conditions and the dispatch profile of our

generation fleet in future periods will likely differ – and may differ significantly – from the

assumptions underlying the simulation results included in the slides.  In addition, the forward-

looking information included in the following slides will likely change over time due to continued

refinement of our simulation model and changes in our views on future market conditions.

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

14

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 MWs 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

15

2011

2012

2013

Estimated

Open

Gross

Margin

($

millions)

(1)(2)

$5,450

$5,000

$5,600

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)

$4.37

$33.18

$46.07

$3.77

$4.84

$33.10

$46.02

$1.40

$5.16

$34.45

$47.45

$2.27

Exelon Generation Open Gross Margin and

Reference Prices

16

(1)

Based on June 30, 2011 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 RPM 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 revenues and 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.

2011

2012

2013

Expected Generation

(GWh)

(1)

166,100

165,600

163,000

Midwest

99,000

97,900

95,800

Mid-Atlantic

56,300

57,100

56,500

South & West

10,800

10,600

10,700

Percentage of Expected Generation Hedged

(2)

95-98%

82-85%

49-52%

Midwest

95-98

81-84

48-51

Mid-Atlantic

96-99

85-88

50-53

South & West

86-89

63-66

45-48

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

$40.00

Mid-Atlantic

$57.00

$50.00

$50.50

South & West

$4.50

$0.00

($2.00)

Generation Profile

17

(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 12

refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem.  Expected generation assumes capacity factors of 93.0%, 93.4% and 93.2% in

2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 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. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.

(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.

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%

2011

$5

$(5)

$5

$(5)

$5

$(5)

+/-

$25

2012

$85

$(35)

$95

$(75)

$55

$(55)

+/-

$45

2013

$340

$(290)

$250

$(245)

$155

$(150)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

18

(1) 

Based on June 30, 2011 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.

95% case

5% case

$5,500

$7,100

$6,900

$6,000

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

2013

$6,800

$5,200

19

(1) 

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged

supply is sold into the spot market.  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 2012 and 2013 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, 2011.

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

20

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin

$5.45 billion

Step 2

Determine

the

mark-to-market

value

of

energy hedges

99,000GWh * 96% *

($43.00/MWh-$33.18MWh)

= $0.93 billion

56,300GWh * 97% *

($57.00/MWh-$46.07MWh)

= $0.60 billion

10,800GWh * 87% *

($4.50/MWh-$3.77MWh)

= $0.00 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open

gross

margin:

$5.45

billion

MTM

value

of

energy

hedges:

$0.93

billion

+

$0.60

billion

+

$0.00

billion

Estimated

hedged

gross

margin:

$6.98

billion

20

25

30

35

40

45

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

35

40

45

50

55

60

65

70

75

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

50

55

60

65

70

75

80

85

90

95

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2012

$4.58

2013  $5.05

Forward NYMEX Coal

2012

$81.06

2013

$85.51

2012 Ni-Hub  $42.62

2013 Ni-Hub

$45.58

2013 PJM-West  $56.91

2012 PJM-West

$53.84

2012 Ni-Hub

$27.61

2013 Ni-Hub

$30.00

2013 PJM-West

$42.07

2012 PJM-West

$39.62

21

Rolling

12

months,

as

of

August

31    2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

st

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10.2

10.4

10.6

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

35

40

45

50

55

60

65

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

6/11

7/11

8/11

Market Price Snapshot

2013

10.14

2012

10.00

2012

$45.27

2013

$50.53

2012

$4.53

2013

$4.99

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2012

$10.09

2013

$12.06

ERCOT North On Peak Spark Spread

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

22

Rolling

12

months,

as

of

August

31    2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

st

Appendix

23

MISO (TWh)

PJM (TWh)

South

(1)

(TWh)

ISO-NE & NY ISO

(2)

(TWh)

West (TWh)

The combination establishes an industry-leading platform with regional

diversification of the generation fleet

(1)

Represents load and generation in ERCOT, SERC and SPP.

(2)

Constellation load includes ~0.7TWh of load served in Ontario.

31.8

147.3

Load

102.1

43.4

58.7

Generation

179.1

Constellation

Exelon

Load

6.3

5.8

0.5

Generation

9.1

9.1

29.5

Load

Generation

14.2

4.8

9.4

2.4

Load

Generation

0.8

0.4

0.4

28.5

23.2

Load

Generation

24

Portfolio Matches Generation with Load in

Key Competitive Markets

Data

for

Exelon

and

Constellation

represents

expected

generation

(owned

and

contracted)

and

booked

electric

sales

for

2011

as

of

12/31/10.  This data also includes 2011 partial year generation from Wolf Hollow (acquired by Exelon). Data also includes 2011 partial

year estimated electric sales from StarTex and MXEnergy (acquired by Constellation).

Exelon load includes ComEd Swap, load sold through affiliates, fixed and indexed load sales and load sold through POLR auctions.

Constellation load includes load sold through affiliates, fixed and indexed load sales and load sold through POLR auctions. 

Note:

A Clean Generation Profile Creates Long-

Term Value in Competitive Markets

(1)

Exelon

generation

includes

Wolf

Hollow

acquisition

(720

MW

of

natural

gas).

Constellation

generation

includes

Boston

Generation

acquisition

(2,950

MW

of

natural gas). Constellation nuclear reflects 50.01% interest in Constellation Energy Nuclear Group LLC. Generation capacity doesn’t reflect contracted

capacity.

(2)

Net of physical market mitigation assumed to be 2,648 MW.

Exelon Standalone

(1)

Total Generation: 26,339 MW

Constellation Standalone

(1)

Total Generation: 11,980 MW

Pro forma Company (Net of Mitigation)

(2)

Total Generation: 35,671 MW

Hydro

6%

Wind/Solar/Other

Gas

13%

Oil

Coal

5%

Nuclear

65%

Wind/Solar/Other

Hydro

Oil

Gas

54%

Coal

23%

Nuclear

16%

Wind/Solar/Other

3%

Hydro

5%

Oil

Gas

27%

Coal

6%

Nuclear

53%

25

Combined company remains the premier low-cost generator

7%

6%

3%

3%

2%

2%

Merger Approvals Process on Schedule    

(as of 9/15/11)

26

Stakeholder

Status of Key Milestones

Filed

Approved

•

SEC has completed its review of the amended S-4 

Registration Statement

•

Shareholder

approval

anticipated

in

mid

November

2011

•

Submitted Hart-Scott-Rodino filing on May 31, 2011

for review under U.S. antitrust laws

•

Approval expected by January 2012

•

Filed merger approval application and related filings

on May 20, 2011, which assesses market power-

related issues

•

Approval expected in Q4 2011

•

Filed for indirect transfer of Constellation Energy

licenses on May 12, 2011

•

Approval expected by January 2012

•

Filed for approval with the Maryland Public Service

Commission on May 25, 2011

•

Approval expected by January 5, 2012

•

Filed for approval with the New York State Public

Service Commission on May 17, 2011

•

Approval expected in Q4 2011

•

Filed for approval with the Public Utility Commission of

Texas on May 17, 2011

•

Approval received on  August 3, 2011

Securities and Exchange

Commission (SEC)

(File No. 333-175162)

Department of Justice

(DOJ)

Federal Energy Regulatory

Commission (FERC)

(Docket No. EC 11-83)

Nuclear Regulatory

Commission

(Docket Nos. 50-317, 50-318, 50-220,

50-410, 50-244, 72-8, 72-67)

Maryland PSC

(Case No. 9271)

New York PSC

(Case No. 11-E-0245)

Texas PUC

(Case No. 39413)

Significant Events

Date of Event

•

Filing of Application

May 25, 2011

•

Intervention Deadline

June 24, 2011

•

Prehearing Conference

June 28, 2011

•

Filing of Staff, Office of People Counsel and Intervenor Testimony

September 16, 2011*

•

Filing of Rebuttal Testimony

October 12, 2011*

•

Filing of Surrebuttal Testimony

October 26, 2011

•

Status Conference

October 28, 2011

•

Evidentiary Hearings

October 31, 2011 -

November 10, 2011

•

Public Comment Hearings

November 29, December 1 &

December 5, 2011

•

Filing of Initial Briefs

December 1, 2011

•

Filing of Reply Briefs

December 15, 2011

•

Decision Deadline

January 5, 2012

Maryland PSC Review Schedule

27

* Initial

intervenor

testimony

with

respect

to

market

power

is

due

on

September

23

rd

for

all

parties except for the Independent Market Monitor, and rebuttal testimony with respect to

market

power

is

due

on

October

17

th

.

EPA Regulations Are Moving Forward

Develop Toxics Rule

EPA regulations will provide regulatory certainty and

significant environmental benefits

Pre Compliance Period

Compliance With Toxics

Rule

Develop Cross-

State Air Pollution

Rule

Compliance With Cross-State Air Pollution Rule (CSAPR)

Develop 316(b) Regulations

Pre

Compliance Period

Phase In Of

Compliance

28

2010

2011

2012

2013

2014

2015

2016

Hazardous Air

Pollutants

Criteria

Pollutants

Cooling Water

For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/).

Multi-Regional Nuclear Uprate Program

Station

Base Case

MW

Max Potential

MW

MW Online

to Date

Year of Full

Operation

by Unit

MW Recovery & Component Upgrades:

Quad Cities

97

104

99

2011 / 2010

Dresden

3

3

2013 / 2012

Peach Bottom

25

32

2011 / 2012

Dresden

103

110

19

2012 / 2013

Limerick

4

4

2012 / 2013

Peach Bottom

2

2

2014 / 2015

MUR:

LaSalle

35

39

39

2011 / 2011

Limerick

33

41

30

2011 / 2011

Braidwood

34

42

2012 / 2012

Byron

34

42

2012 / 2012

Quad Cities

21

23

2014 / 2014

Dresden

28

31

2014 / 2015

TMI

12

15

2014

EPU:

Clinton

2

2

2

2010

Peach Bottom

134

148

2015 / 2016

LaSalle

303

336

2016 / 2015

Limerick

306

340

2016 / 2017

Total

1,176

1,314

189

TMI

Limerick

Peach

Bottom

Total Midwest Uprates:

660-732 MW

Total Mid-Atlantic Uprates:

516-582 MW

Quad

Cities

Dresden

Byron

LaSalle

Clinton

Braidwood

Notes:  MW shown at ownership.  An additional 11 MW expected to come online by end of

2011 at Peach Bottom 3.

Executing uprate projects across our

geographically diverse nuclear fleet

29

Exelon

Nuclear

Fleet

Overview

-

IL

Plant

Location

Type/

Containment

Water Body

License Extension

Status / License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full

core discharge

capacity

(2)

Braidwood, IL

(Units 1 and 2)

PWR

Concrete/Steel

Lined

Kankakee

River

Expect to file

application in 2013/

2026, 2027

100%

Dry Cask (Fall 2011)

Byron, IL

(Units 1 and 2)

PWR

Concrete/Steel

Lined

Rock River

Expect to file

application in 2013/

2024, 2026

100%

Dry Cask

Clinton, IL

(Unit 1)

BWR

Concrete/Steel

Lined

Clinton Lake

2026

100%

2018

Dresden, IL

(Units 2 and 3)

BWR

Steel Vessel

Kankakee

River

Renewed / 2029,

2031

100%

Dry cask

LaSalle, IL

(Units 1 and 2)

BWR

Concrete/Steel

Lined

Illinois River

2022, 2023

100%

Dry Cask

Quad Cities, IL

(Units 1 and 2)

BWR

Steel Vessel

Mississippi

River

Renewed / 2032

75% Exelon, 25%

Mid-American

Holdings

Dry cask

30

Exelon pursues license extensions well in advance of expiration to ensure adequate time 

for review by the NRC

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel

from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools.

Exelon Nuclear Fleet Overview –

PA and NJ

Plant, Location

Type,

Containment

Water Body

License Extension

Status / License

Expiration

(1)

Ownership

Spent Fuel Storage/

Date to lose full

core discharge

capacity

(2)

Limerick, PA

(Units 1 and 2)

BWR

Concrete/Steel

Lined

Schuylkill

River

Filed application in

June 2011

(decision expected

in 2013)/ 2024,

2029

100%

Dry cask

Oyster Creek, NJ

(Unit 1)

BWR

Steel Vessel

Barnegat Bay

Renewed / 2029

(3)

100%

Dry cask

Peach Bottom, PA

(Units 2 and 3)

BWR

Steel Vessel

Susquehanna

River

Renewed / 2033,

2034

50% Exelon,

50% PSEG

Dry cask

TMI, PA (Unit 1)

PWR

Concrete/Steel

Lined

Susquehanna

River

Renewed / 2034

100%

2023

Salem, NJ (Units 1

and 2)

PWR

Concrete/Steel

Lined

Delaware

River

Renewed / 2036,

2040

42.6% Exelon,

57.4% PSEG

Dry Cask

Exelon pursues license extensions well in advance of expiration to ensure adequate

time

for review by the NRC

31

(1)

Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.

(2)

The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from

the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools.

(3)

On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The

current NRC license for Oyster Creek expires in 2029.

2011 Projected Sources and Uses of Cash

32

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$800

Cash

Flow

from

Operations

(2)

375

875

3,175

4,350

CapEx (excluding Nuclear Fuel, Nuclear

Uprates, Exelon Wind, Utility Growth CapEx

and Wolf Hollow)

(725)

(325)

(850)

(1,950)

Nuclear Fuel

n/a

n/a

(1,050)

(1,050)

Dividend

(3)

(1,400)

Nuclear

Uprates

and

Exelon

Wind

(4)

n/a

n/a

(625)

(625)

Wolf Hollow Acquisition

n/a

n/a

(300)

(300)

Utility Growth CapEx

(5)

(300)

(125)

n/a

(425)

Net Financing (excluding Dividend):

Planned

Debt

Issuances

(6)

1,000

--

--

1,000

Planned Debt Retirements

(6)

(350)

(250)

--

(600)

Other

(7)

300

(125)

200

550

Ending Cash Balance

(1)

$350

(1)  Excludes counterparty collateral activity.

(2)  Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures. 

(3)  Assumes 2011 dividend of $2.10/share.  Dividends are subject to declaration by the Board of Directors.

(4)  Includes $400 million in Nuclear Uprates and $225 million for Exelon Wind spend.

(5)  Represents new business, smart grid/smart meter investment and transmission growth projects.

(6)  Planned Issuances of $1B at ComEd reflect the $600M January 18, 2011 issuance and $400M of ComEd’s $600M September 7, 2011 issuance. Incremental $200M of financing was primarily utilized

to retire $191M of tax-exempt debt  at ComEd.

(7)  “Other” includes proceeds from options and expected changes in short-term debt.

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

.

Note: Projected cash flows are as of 6/30/2011

ComEd Load Trends

Chicago

U.S.

Unemployment rate

(1)

9.3%

9.2%

2011 annualized growth in

gross domestic/metro product

(2)

2.5%               

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

2010 

2Q11      2011E

Average Customer Growth

0.2%  

0.4%    

Average Use-Per-Customer

(1.4)%

(2.0)%

Total Residential

(1.2)%   

(1.6)%     

Small C&I

(0.6)%

(0.2)%    

Large C&I

2.6%  

(0.9)%     

All Customer Classes

0.2%   

(0.8)%     

(1)

Source:  U.S. Dept. of Labor (June 2011) and Illinois

Department of Security (June 2011)

(2)  Source: Global Insight (May 2011)

-6.0%

-3.0%

0.0%

3.0%

6.0%

-6.0%

-3.0%

0.0%

3.0%

6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

All Customer Classes

Large C&I

Residential

Gross Metro Product

33

0.4%

0.0%

0.4%

(0.3)%

0.0%

0.0%

2.7%

PECO Load Trends

Philadelphia

U.S.

Unemployment rate

(1)

7.9%

9.2%               

2011 annualized growth in

gross domestic/metro product

(2)

2.4%                  2.7%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

2010

2Q11     2011E

Average Customer Growth

0.3%  

0.5%    

0.4%

Average Use-Per-Customer

0.3%

2.8%

1.7%

Total Residential

0.5%   

3.2%       2.2%

Small C&I

(1.9)%

1.7%        0.7%

Large C&I

0.8%  

(3.3)%      (2.3)%

All Customer Classes

0.1%   

(0.1)%      (0.0)%

(1)

Source:

U.S

Dept.

of

Labor

data

June

2011

-

US

U.S

Dept.

of

Labor

prelim.

data

May

2011

-

Philadelphia

(2)  Source: Global Insight May 2011

34

-6.0%

-3.0%

0.0%

3.0%

6.0%

-

6.0%

-

3.0%

0.0%

3.0%

6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

All Customer Classes

Large C&I

Residential

Gross Metro Product