Filed by Exelon Corporation

(Commission File No. 1-16169)

Pursuant to Rule 425 under the Securities Act of 1933

and deemed filed pursuant to Rule 14a-12 of the Securities Exchange Act of 1934

Subject Company: Constellation Energy Group, Inc.

(Commission File No. 1-12869)

On May 19, 2011, Exelon began to use the following slides concerning the proposed merger and other information in a series of meetings with investors:

Investor Meetings

May 2011

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, 

“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,

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 Corporation (Exelon) and Constellation Energy Group, Inc. (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. 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; 

both

as

amended

by

the

Private

Securities

Litigation

Reform

Act

of

1995.

Words

such

as

“may,”

“will,”

“anticipate,”

Cautionary Statements Regarding

Forward-Looking Information (Continued)

3

(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 the

combined company. 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 March 31, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors, (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: Note 12; (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 March 31, 2011 in (a) Part II, Other Information, 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, 

fully discussed in the joint proxy statement/prospectus that will be included in the Registration Statement on Form S-4 that

Exelon will file with the SEC 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.

Commitments

and

Contingencies.

These

risks,

as

well

as

other

risks

associated

with

the

proposed

merger,

will

be

more

Additional Information and Where to Find It

4

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.  Exelon intends to

file with the SEC a registration statement on Form S-4 that will include a 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. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE

JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME

AVAILABLE, BECAUSE THEY 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 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, will be

contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when they become

available.

Transaction Overview

100%

stock

–

0.930

shares

of

EXC

for

each

share

of

CEG

Upfront

transaction

premium

of

18.1%

$2.10 per share Exelon dividend maintained

Expect to close in early 1Q 2012

Exelon and Constellation shareholder approvals in 3Q 2011

Regulatory approvals including FERC, DOJ, MD, NY, TX 

Executive Chairman: Mayo Shattuck

President and CEO: Chris Crane

Board of Directors: 16 total (12 from Exelon, 4 from Constellation)

Exelon Corporation

78% Exelon shareholders

22% Constellation shareholders

Corporate headquarters: Chicago, IL

Constellation headquarters: Baltimore, MD

No change to utilities’

headquarters

Significant employee presence maintained in IL, PA and MD

Company Name

Consideration

Pro Forma

Ownership

Headquarters

Governance

Approvals &

Timing

(1)  Based on the 30-day average Exelon and Constellation closing stock prices as of April 27, 2011.

5

(1)

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

6

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

businesses creates a strong platform for growth and delivers benefits to investors

and customers

Exelon Transaction Rationale

Increases

geographic

diversity

of

generation,

load

and

customers

in

competitive     

markets

Shared

Commitment to

Competitive

Markets

Enhances

Scalable Growth

Platform

Creates

Shareholder

Value

Expands a valuable channel to market our generation

Enhances margins in the competitive portfolio

Diversifies portfolio across the value chain

EPS break-even in 2012 and accretive by +5% in 2013

Maintains

strong

credit

profile

and

financial

discipline

Maintains earnings upside to future environmental regulations and power market

recovery

Adds stability to earnings and cash flow

Adds mix of clean generation to the portfolio

Clean

Generation Fleet

This transaction meets all of our M&A criteria and can be executed

7

This Combination Is Good for Maryland

Maintains employee presence and platform for growth in Maryland

–

Exelon’s Power Team will be combined with Constellation’s wholesale and retail

business

under

the

Constellation

brand

and

will

be

headquartered

in

Baltimore

–

Constellation and Exelon’s renewable energy business headquartered in Baltimore

–

BGE maintains independent operations headquartered in Baltimore

–

No involuntary merger-related job reductions at BGE for two years after close

Supports Maryland’s economic development and clean energy infrastructure

–

$10 million to spur development of electric vehicle infrastructure

–

$4

million

to

support

EmPower

Maryland

Energy

Efficiency

Act

–

25 MWs

of renewable energy development in Maryland

–

Charitable contributions maintained for at least 10 years

Provides direct benefits to BGE customers

–

$5 million provided for Maryland’s

Electric Universal Service Program (EUSP)

–

Over $110 million to BGE residential customers from $100 one-time rate credit

8

We will

bring

direct

benefits

to

the

State

of

Maryland,

the

City

of

Baltimore

and

BGE

customers. Total investment in excess of $250 million.

5.8

0.5

9.1

Exelon

Constellation

23.2

27.8

MISO (TWh)

PJM (TWh)

South

(1)

(TWh)

ISO-NE & NY ISO

(2)

(TWh)

West (TWh)

Load

Generation

31.8

42.8

147.3

58.7

Exelon

Constellation

4.8

27.1

9.1

Exelon

Constellation

Exelon

Constellation

2.4

0.4

0.4

Exelon

Constellation

Load

Generation

Generation

Load

Load

Generation

Load

Generation

6.3

9.1

101.5

179.1

27.8

23.2

27.1

13.9

2.4

0.8

Portfolio Matches Generation with Load in

Key Competitive Markets

(1)

Represents load and generation in ERCOT, SERC and SPP.

(2)

Constellation load includes ~0.7TWh of load served in Ontario

Note: Data for Exelon and Constellation represents expected generation and load for 2011 as of 12/31/10.

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. 

The combination establishes an industry-leading platform with regional

diversification of the generation fleet

9

Transaction Economics Are Attractive for

Both Companies

EPS break-even in 2012 and accretive by +5% in 2013

Free cash flow accretive beginning in 2012

Run-rate synergies of ~$260 million

–

Total

costs

to

achieve

of

~$500

million

–

Synergies primarily from corporate consolidation and power marketing platform

integration

Lower consolidated liquidity requirements, resulting in cost savings

Investment-grade ratings and credit metrics

10

Wolf Hollow Acquisition

11

Wolf Hollow Overview

Diversifies generation portfolio

•

Expands geographic and fuel characteristics

of fleet

•

Advances Exelon and Constellation merger

strategy of matching load with generation in

key competitive markets

Creates value for shareholders

•

Purchase price compares favorably to cost of

new build

•

Free cash flow accretive beginning in 2012;

earnings and credit neutral

•

Eliminates current above market purchase

power agreement (PPA) with Wolf Hollow

•

Enhances opportunity to benefit from future

market heat rate expansion in ERCOT

Transaction expected to close in Q3 2011

Location

Granbury, Texas

Commercial Operation Date

August 2003

Nominal Net Operating Capacity

720MW

Equipment Technology

2 Mitsubishi combined-cycle gas

turbines

Primary Fuel

Natural Gas

Secondary Fuel

None

ERCOT = Electric Reliability Council of Texas

12

Appendix

A Clean Generation Profile Creates Long-Term

Value in Competitive Markets

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

(2)

Constellation generation includes Boston Generation acquisition (2,950 MW of natural gas) and excludes Quail Run (~550 MW of natural gas). Constellation nuclear reflects 50.01%

interest in Constellation Energy Nuclear Group LLC.

Exelon Standalone

Total Generation: 25,619 MW

Constellation Standalone

(2)

Total Generation: 11,430 MW

Pro forma Company (Net of Mitigation)

(1)

Total Generation: 34,401 MW

13

Combined company remains premier low-cost generator

Coal

6%

Oil

8%

Gas

11%

Hydro

6%

Wind/Solar/Other

3%

Nuclear

67%

Coal

24%

Nuclear

17%

Gas

52%

Wind/Solar/Other

2%

Hydro

3%

Oil

3%

Nuclear

55%

Coal

6%

Oil

7%

Gas

24%

Hydro

6%

Wind/Solar/

Other

2%

Increased Regional Diversity in PJM:

Capacity

Eligible

for

2014/15

RPM

Auction

(1)

Pro forma Company

4,390 MW

2,535 MW

9,230 MW

11,345 MW

Exelon Standalone

Constellation Standalone

(1)

All

generation

values

are

approximate

and

not

inclusive

of

wholesale

transactions;

all

capacity

values

are

in

installed

capacity

terms

(summer

ratings)

located

in

the

areas

and

adjusted

for mid-year PPA roll-offs.

8,700 MW

10,300 MW

1,500 MW

1,035 MW

4,390 MW

1,045 MW

530 MW

14

2014/15 RPM auction results announced on May 13, 2011

42%

7%

51%

RTO

MAAC

EMAAC

8%

15%

15%

63%

EMAAC

MAAC

RTO

SWMAAC

16%

34%

41%

9%

RTO

EMAAC

MAAC

SWMAAC

15

15

15

ComEd Load Trends

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

(1)

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

Department of Security (March 2011)

(2)  Source: Global Insight February 2011

-6.0%

-3.0%

0.0%

3.0%

6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

-6.0%

-3.0%

0.0%

3.0%

6.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

Chicago

U.S.

Unemployment rate

(1)

8.5%

8.8%

2011 annualized growth in

gross

domestic/metro

product

(2)

2.5%

3.2%

2010 

1Q11      2011E

Average Customer Growth

0.2%  

0.4%    

0.5%

Average Use-Per-Customer

(1.4)%

(2.2)%

0.1%

Total Residential

(1.2)%   

(1.8)%      

0.5%

Small C&I

(0.6)%

0.6%    

(0.3)%

Large C&I

2.6%  

1.4%     

(0.1)%

All Customer Classes

0.2%   

(0.1)%     

0.0%

16

16

16

ComEd 2010 Rate Case Update

ComEd Reply Brief (2/23/11)

$343M increase requested

11.50% ROE / 47.28% equity ratio

Rate base $7,349M

2009 test year with pro forma plant additions through 6/30/11

ICC Staff Reply Brief Position (2/23/11)

$113M increase proposed

10.00% ROE / 47.11% equity ratio

Rate base $6,480M

Pro forma plant additions and depreciation reserve through 12/31/10

ALJ Proposed Order (4/1/11)

$152M increase proposed (after correcting ~$14M calculation error)

10.50% ROE / 47.28% equity ratio

Rate base $6,629M

Pro forma plant additions and depreciation reserve through 12/31/10 with very limited exceptions

(ICC Docket No. 10-0467)

Illinois Commerce Commission Final Order will be issued by May 31

Illinois Power Agency (IPA)

RFP Procurement

Note: Chart is for illustrative purposes only.

REC = Renewable Energy Credit; RFP = request for proposal

June 2011

June 2012

June 2013

June 2014

Financial Swap Agreement with ExGen

(ATC

baseload

energy

only

–

notional

quantity 3,000 MW)

Term

Fixed Price

1/1/11-12/31/11

$51.26/MWh

1/1/12-12/31/12

$52.37

1/1/13-5/31/13

$53.48

17

Financial Swap

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2012 RFP

2013 RFP

2013 RFP

2014 RFP

ICC has approved Long Term REC Procurement held in November 2010

–

1.26

Million

MWh

of

renewable

resources

annually

beginning

in

June

2012

under

20

year

contract

–

8 winning suppliers with an average 2012-13 plan-year price of $55.18/MWh

Spring 2011 Procurement Plan

–

IPA Procurement Plan approved by the ICC

•

Standard Product bids due 5/16; ICC decision on 5/20

•

Annual REC bids due 5/18; ICC decision on 5/24

–

Provisions included:

•

Annual energy procurements over a three-year time frame

•

Target a 35%/35%/30% laddered procurement approach

•

No additional Energy Efficiency, Demand Response purchases

•

No additional long term contracts for renewables

•

No 10% overprocurement for summer peak energy

June 2015

18

PECO Load Trends

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

(1)  Source: U.S Dept. of Labor data March 2011 -US

U.S

Dept.

of

Labor

prelim.

data

February

2011

-

Philadelphia

(2)  Source: Global Insight February 2011

-6.0%

-3.0%

0.0%

3.0%

6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

-6.0%

-3.0%

0.0%

3.0%

6.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

Philadelphia

U.S.

Unemployment rate

(1)

8.4%

8.8%

2010 annualized growth in

gross

domestic/metro

product

(2)

3.0%

3.2%

2010

1Q11     2011E

Average Customer Growth

0.3%  

0.4%    

0.4%

Average Use-Per-Customer

0.3%

0.2%

1.7%

Total Residential

0.5%   

0.5%

Small C&I

(1.9)%

(1.1)%      0.1%

Large C&I

0.8%  

(2.7)%

All Customer Classes

0.1%   

(1.1)%

2.1%

(1.6)%

0.1%

19

19

EPA Regulations Will Move Forward in 2011

2010

2011

2012

2013

2014

2015

2016

2017

2018

PJM RPM Auction

14/15

15/16

16/17

17/18

Hazardous Air

Pollutants

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

By-Products

Cooling Water

Effluents

Develop Toxics Rule

Develop ICI

MACT

Pre Compliance Period

Compliance With Toxics Rule

Pre Compliance Period

Compliance With ICI MACT

Develop

Transport Rule

Compliance With Transport Rule

Interim CAIR

Develop O3

Transport

Rule (TR 2)

Estimated Compliance

Develop Criteria

NSPS revision

Compliance with Revised Criteria NSPS

Develop Revised

NAAQS

SIP provisions developed in response to revised NAAQS

(e.g., Ozone, PM2.5, SO2, NO2, NOx/SOx, CO)

Compliance with Federal GHG Reporting Rule

PSD/BACT and Title V Apply to GHG Emissions (PSD only for new and modified sources)

Develop GHG NSPS

Pre Compliance Period

Compliance With GHG NSPS

Develop Coal Combustion

By-Products Rule

Pre Compliance Period

Compliance With Federal CCB Regulations

Develop 316(b) Regulations

Pre Compliance Period

Phase In Of Compliance

Develop Effluent Regulations

Pre Compliance Period

Phase In Of

Compliance

Notes: RPM auctions take place annually in May.

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

20

2011 Events of Interest

Q1

Q2

Q3

Q4

RPM Auction results

(5/13)

Illinois Power Agency

RFP (5/16)

ALJ Proposed Order

–

DST Rate Case

(4/1)

Procurement RFP

(bids accepted 5/2;

results 5/18)

DST Rate Case Final

Order  (by 5/31)

EPA Final Toxics

Rule (November)

Retirement of Cromby

1 & Eddystone 1 units

(5/31)

Proposed Toxics Rule 

(3/16)

Procurement RFP

(bids due 9/19;

results by 10/19)

Retirement of

Cromby 2 unit

(12/31)

Proposed 316(b) EPA

Regulation (3/28)

EPA Final Transport

Rule (June)

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

21

Exelon Generation Hedging Disclosures

(as of March 31, 2011)

22

22

Important Information

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 March 31, 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.

23

23

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

24

24

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

25

25

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,250

$4,900

$5,500

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)

$4.47

$31.32

$44.23

$4.42

$5.06

$31.32

$46.19

$1.88

$5.41

$32.83

$48.10

$2.06

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on March 31, 2011 market conditions. 

(2)

(3)

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

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.

26

26

2011

2012

2013

Expected Generation

(GWh)

(1)

165,800

165,400

162,800

Midwest

99,000

97,800

96,100

Mid-Atlantic

56,300

57,200

56,400

South & West

10,500

10,400

10,300

Percentage of Expected Generation Hedged

(2)

93-96%

73-76%

38-41%

Midwest

93-96

75-78

35-38

Mid-Atlantic

94-97

72-75

42-45

South & West

76-79

59-62

40-43

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

$41.00

Mid-Atlantic

$56.50

$50.50

$50.50

South & West

$4.50

$0.00

($3.00)

Generation Profile

(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%, 93.6% and 93.1% 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.

27

27

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)

$15

$(10)

$10

$(10)

+/-

$30

2012

$145

$(65)

$145

$(125)

$90

$(90)

+/-

$45

2013

$425

$(380)

$315

$(310)

$180

$(175)

+/-

$45

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1) 

Based on March 31, 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.

28

28

95% case

5% case

$5,500

$7,100

$6,800

$6,200

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

$6,900

$4,900

(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 March 31, 2011.

29

29

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin 

$5.25 billion

Step 2

Determine

the

mark-to-market

value

of

energy hedges

99,000GWh * 94% *

($43.00/MWh-$31.32MWh)

= $1.09 billion

56,300GWh * 95% *

($56.50/MWh-$44.23MWh)

= $0.66 billion

10,500GWh * 77% *

($4.50/MWh-$4.42/MWh)

= $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:                              $5.25 billion

MTM

value

of

energy

hedges:

$1.09billion

+

$0.66billion

+

$0.00

billion

Estimated hedged gross margin:          $7.00 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

20

25

30

35

40

45

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

30

35

40

45

50

55

60

65

70

75

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

50

55

60

65

70

75

80

85

90

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

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

2013

Rolling

12

months,

as

of

May

6

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2012

2013

2012 Ni-Hub

2013 Ni-Hub

2013 PJM-West

2012 PJM-West

2012 Ni-Hub

2013 Ni-Hub

2013 PJM-West

2012 PJM-West

th

$5.49

$54.37

$52.35

$42.66

$40.60

$82.04

$78.21

$40.97

$39.03

$27.24

$25.18

$5.21

31

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

35

40

45

50

55

60

65

70

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

Market Price Snapshot

2013

9.36

2012

9.23

2012

$46.94

2013

$50.23

2012

$5.09

2013

$5.37

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

$7.72

2013

$9.00

ERCOT North On Peak Spark Spread

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

Rolling

12

months,

as

of

May

6

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

5/11

th