September 2011

Exelon Corporation

Investor Meetings

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

5

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

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

•

$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

Combination Will Result in Enhanced Scale,

Scope, Flexibility and Financial Strength

(1)  Market Value as of 9/2/11. Enterprise Value represents Market Value plus Net Debt as of 6/30/11.

(2)  Data as of 12/31/10. 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.

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

•

$36 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

7

Transaction Overview

•

100%

stock

–

0.930

shares

of

EXC

for

each

share

of

CEG

•

Upfront

transaction

premium

of

18.5%

(1)

•

$2.10 per share Exelon dividend maintained

•

Expect to close in early 2012

•

Exelon and Constellation shareholder approvals in Q4 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 26, 2011.

8

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 clean baseload 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

9

This transaction meets all of Exelon’s M&A criteria and can be executed

Constellation Transaction Rationale

•

Upfront premium of 18.5%

(1)

•

Dividend accretion of 103% post-closing

•

Enhances upside to power market recovery and synergies

Creates 

Shareholder

Value

•

Creates balance sheet capacity to pursue growth opportunities

throughout the competitive portfolio

•

Reduces cost of capital and rating agency pressure with potential

credit uplift from existing standalone rating

•

Rating agency reaction has been positive, with S&P and Moody’s

changing Constellation rating outlook to positive

Balance Sheet

Strength

Complementary

Portfolios

•

Advances

strategy of matching load with physical generation in key

competitive markets

•

Lowers collateral costs of competitive businesses

(1)  Based on the 30-day average Exelon and Constellation closing stock prices as of April 26, 2011.

10

The transaction creates financial and strategic value that is consistent with

Constellation’s existing strategy

11

Merger Approvals Process on Schedule    

(as of 9/1/11)

•

Filed S-4 Amended Registration Statement

August 17, 2011

•

Shareholder approval anticipated in Q4 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

Stakeholder

Securities

and

Exchange

Commission

(SEC)

(File

No.

333-175162)

Department of Justice

Federal

Energy

Regulatory

Nuclear

Regulatory

Maryland

PSC

(Case

No.

9271)

New

York

PSC

(Case

No.

11-E-0245)

Texas

PUC

(Case

No.

39413)

Status of Key Milestones

Filed

Approved

(DOJ)

Commission

(FERC)

(Docket

No.

EC

11-83)

(Docket

Nos.

50-317,

50-318,

50-220,

Commission

50-410,

50-244,

72-8,

72-67)

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

12

*

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

Maryland PSC Review Schedule

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

13

We will

bring

direct

benefits

to

the

State

of

Maryland,

the

City

of

Baltimore

and BGE customers. Total investment in excess of $250 million.

Transaction Economics Are Attractive for

Both Companies

•

Refined synergy run-rate and costs to achieve

estimates due to greater accessibility and availability of

data post-merger announcement  

–

Higher net O&M savings over 5 years of ~$50

million

•

Updated synergy run-rate of ~$310 million/year

–

Additional synergies primarily from corporate and

commercial consolidation

–

Most synergies to accrue to shareholders

•

Total costs to achieve of ~$650 million

–

Incremental costs to achieve attributable to

employee related costs and transaction costs

Financial Metrics

•

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

•

Free cash flow accretive beginning in 2012

•

Lower consolidated liquidity requirements, resulting in cost savings

•

Investment-grade ratings and credit metrics

Synergies

14

Other

~20%

Corporate &

Commercial

Consolidation

~80%

Scale, Scope and Flexibility Across the

Value Chain

Upstream

Downstream

Reserves (gas)

266 bcf

Owned Generating

Capacity

36 GWs

(1)

Electric

Transmission

7,350 miles

Electric & Gas Dist.

6.6 million customers

Retail &

Wholesale Volumes

(2)

(Electric & Gas)

~169 TWh, 405 bcf

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

(1)    Generation capacity net of market mitigation assumed to be 2,648 MW consisting of Brandon Shores (1,273 MW),

H.A. Wagner (976 MW) and CP Crane (399 MW). Exelon capacity updated to reflect Wolf Hollow.

(2)

Electric load includes all booked 2011E competitive retail sales, wholesale sales, and sales to load serving entities

including ComEd swap. Gas load includes all booked and forecasted 2011E competitive retail sales. Data also

includes

2011

partial

year

estimated

electric

sales

from

StarTex

and

MXEnergy

(acquired

by

Constellation).

15

MISO (TWh)

PJM (TWh)

South

(1)

(TWh)

ISO-NE & NY ISO

(2)

(TWh)

West (TWh)

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 (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. 

Load

102.1

43.4

58.7

Generation

179.1

31.8

147.3

Constellation

Exelon

Load

6.3

5.8

0.5

Generation

9.1

9.1

Load

Generation

14.2

4.8

9.4

Load

Generation

0.8

0.4

0.4

Load

Generation

16

The combination establishes an industry-leading platform with regional

diversification of the generation fleet

23.2

28.5

29.5

2.4

17

18

2011 Operating Earnings Guidance

2011 Prior

Guidance

(2)

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$3.90 -

$4.20

(1)

$0.55 -

$0.65

$0.50 -

$0.60

$2.85 -

$3.05

(1)

We raised 2011 earnings guidance on July 27, 2011, and we are not updating earnings guidance at this time. Earnings guidance is only reviewed in connection with our

quarterly earnings announcements or if we expressly indicate that we are updating the guidance.  Refer to the Appendix for a reconciliation of adjusted (non-GAAP)

operating EPS to GAAP EPS.

(2)

Earnings guidance for OpCos may not add up to consolidated EPS guidance.

2Q 2011 operating earnings of

$1.05/share

Strong operating results in second

quarter

•

Nuclear capacity factor of 89.6% largely

due to a higher number of nuclear

refueling outages

•

Strong operating results at utilities

despite severe storms in ComEd

service territory

2011 Revised

Guidance

(2)

$4.05 -

$4.25

(1)

$0.55 -

$0.65

$0.50 -

$0.60

$2.95 -

$3.10

Updating

2011

operating

earnings

guidance

to

$4.05

-

$4.25/share

from

$3.90 -

$4.20/share

(1)

19

2011 Projected Sources and Uses of Cash

($ 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.

20

Sufficient Liquidity

($ millions)

Exelon

(3)

Aggregate Bank Commitments

(1)

$1,000

$600

$5,600

$7,700

Outstanding Facility Draws

--

--

--

--

Outstanding Letters of Credit

(195)

(1)

(121)

(324)

Available Capacity Under Facilities

(2)

805

599

5,479

7,376

Outstanding Commercial Paper

--

--

--

(139)

Available Capacity Less Outstanding

Commercial Paper

$805

$599

$5,479

$7,237

Exelon bank facilities are largely untapped

(1)  Excludes commitments from Exelon’s Community and Minority Bank Credit Facility

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

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

(3)  Includes Exelon Corporate’s $500M credit facility, letters of credit and commercial paper outstanding.

Available Capacity Under Bank Facilities as of July 14, 2011

21

Key Credit Metrics

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

FFO / Debt

(1)

(1)

See slide 53 for reconciliations to GAAP.

(2)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of September 2, 2011.

(3)

FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp.

(4)

Moody’s placed Exelon and Generation under review for a possible downgrade after the proposed merger with Constellation Energy was announced.

Moody’s

Credit

Ratings

(2)

S&P

Credit

Ratings

(2)

Fitch

Credit

Ratings

(2)

FFO / Debt

Target

Range

(2)

Exelon:

Baa1

(4)

BBB-

BBB+

ComEd:

Baa1

A-

BBB+

15-18%

PECO:

A1

A-

A

15-18%

Generation:

A3

(4)

BBB

BBB+

30-35%

(3)

Interest Coverage

(1)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Exelon

Debt / Cap

(1)

22

EPA Regulations Are Moving Forward

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

Pre Compliance Period

Compliance With Toxics Rule

Compliance With Cross-State Air Pollution Rule (CSAPR)

Interim CAIR

Develop CSAPR (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/).

Develop Cross-

State Air Pollution

Rule

23

Rule encourages future development of transmission infrastructure in

the U.S.

Appropriately assigns the cost of new transmission lines to customers

benefitting from improved reliability

Maintains the ability of transmission providers like ComEd and PECO

to construct transmission upgrades in their service territories

PJM tariffs will require modifications to achieve goals of the final rule

FERC Transmission Ruling Supports

Competitive Markets

Exelon is committed to ensuring PJM’s tariff is modified to achieve the goals

of the FERC Order 

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.

24

Note: ETA = Electric Transmission America

RPS = Renewable Portfolio Standards

RTEP = Regional Transmission Expansion Planning

2014

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

Filing

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

25

26

Factors Influencing RPM

Auction (PY 14/15 vs. PY

13/14)

Expected

Exelon

Price

Impact

Actual

Price

Impact

Actual Auction Results and Supplier

Bidding Behavior

Cost of Environmental

Upgrades

and Higher Net

ACRs for Coal Units

•

3,237 MW reduction in offered capacity

(coal/oil/gas)

•

7,746 MW reduction in cleared capacity

(coal/oil/gas)

Import Transmission Limits

and Objectives 

(muted impact on portfolio

revenues due to regional

diversification)

•

Total revenue from PY 14/15 capacity

auction close to PY 13/14 revenues for

Exelon fleet

•

Balanced portfolio, split evenly between east

and west, reduces volatility in revenues due  

to transmission or demand changes.

Demand Response Growth

•

Increase in cleared DR (~4,836 MW) was

close to internal estimates. 

•

Limited DR was capped, causing price

separation for premium products

RPM Results: Favorable and As Expected

Auction results were in line with Exelon’s expectations with EPA

regulations being one of the primary drivers of bidding behavior

27

Exelon Generation Hedging Program

Q2 provided favorable 2013 sales

opportunities

•

Reflects successful participation in Illinois IPA

procurements in the first half of May

Price movements

•

Recovery in heat rates, especially at NI Hub

•

Upward move in NI Hub wrap

2015

PJM NI Hub ATC Heat Rates

2013 PJM West Hub & NI Hub ATC Prices

2013 Hedge % and Value Above Ratable

28

Diverse Generation and Sales Mix

Exelon’s diverse portfolio is well positioned to serve a variety of products

2011-2013 Sales as a Percentage

of Expected Generation

Current Owned & Contracted

Generation Capacity by Fuel Type

Matching Exelon’s favorable asset position with a diverse set of products is an important aspect of the

hedging program

•

Reduces and diversifies our collateral exposure 

•

Enables sales to be made closer to assets

•

Increases opportunities for margin via retail, utility solicitations and mid-marketing channels

•

Use of alternate channels and locations help minimize liquidity and congestion risks

Data as of 6/30/2011

(1) Reflects owned and contracted generation as of 6/30/2011. Excludes Cromby Station 1 & 2, Eddystone 1&2 and PPA with Tenaska Georgia Partners. Includes Wolf Hollow PPA 

volume only (350 MW).

(1)

Wolf Hollow Acquisition

29

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

•

$305M purchase price compares favorably to

cost of other recent transactions

•

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 closed on August 24, 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

30

NRC Near-Term Task Force Recommendations

Key Findings :

U.S nuclear plants are safe

No major changes to spent nuclear

fuel storage and licensing

Key Recommendations:

Clarifying regulatory framework

Ensuring protection and enhancing

mitigation

Strengthening emergency

preparedness

Improving efficiency of NRC programs

Report was first step in systematic review that NRC will conduct;

stakeholder input will be sought

31

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

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.

32

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

(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.

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

for review by the NRC

33

Exelon Generation Hedging Disclosures

(as of June 30, 2011)

34

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 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.

35

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

36

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

37

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

(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.

38

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

(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.

39

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)

(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.

40

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

(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.

41

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:                             

MTM

value

of

energy

hedges:     

Estimated hedged gross margin:

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

$0.93

billion

+

$0.60

billion

+

$0.00

billion

$5.45 billion

$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

42

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

43

Rolling 12 months, as of August 31    2011. Source: OTC quotes and electronic trading system. Quotes are daily.

st

44

ComEd 2010 Rate Case Final Order

(ICC Docket No. 10-0467)

On 5/24/11, the Illinois Commerce Commission (ICC) issued an order in ComEd’s

2010 distribution rate case

–

new rates went into effect in June 2011

Rate Case Details

ICC Order

(5/24/11)

ComEd Reply Brief

(2/23/11)

Revenue Requirement Increase

$143M

(1)

$343M

Rate Base

$6,549M

$7,349M

ROE

10.50%

11.30%

(2)

Equity Ratio

47.28%

47.28%

(1)

Reflects ~$(13)M adjustment to ICC Order

(2)

Included 40 bp adder for energy efficiency, not approved by ICC

45

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

2010 

2Q11      2011E

Average Customer Growth

0.2%  

0.4%    

0.4%

Average Use-Per-Customer

(1.4)%

(2.0)%

0.0%

Total Residential

(1.2)%   

(1.6)%       0.4%

Small C&I

(0.6)%

(0.2)%    

(0.3)%

Large C&I

2.6%  

(0.9)%     

0.0%

All Customer Classes

0.2%   

(0.8)%     

0.0%

(1)

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

Department of Security (June 2011)

(2)  Source: Global Insight (May 2011)

46

-

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

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

2.7%

Illinois Power Agency (IPA)

RFP Procurement

Note: Chart is for illustrative purposes only.

REC

=

Renewable

Energy

Credit;

RFP

=

request

for

proposal;

ATC

=

Around

the

Clock

June 2012

June 2013

June 2014

Financial Swap Agreement with ExGen

(ATC baseload energy –

notional quantity

3,000 MW)

Standard Products and Annual REC Procurement held in

May 2011

–

Effective ATC of $34.77/MWh for 9 winning Standard Product

suppliers for the 2011-12 plan-year

–

2.12

million

MWh

of

renewable

resources

for

the

2011-12

plan-year

from 12 winning suppliers

–

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

Delivery

Period

Peak

Off-Peak

June 2011 -

May 2012

5,118

4,001

June 2012 -

May 2013

1,129

358

June 2013 -

May 2014

6,494

6,062

Volume procured in the 2011 IPA

Procurement Event (GWh)

Term

Fixed Price

($/MWh)

1/1/11-12/31/11

$51.26

1/1/12-12/31/12

$52.37

1/13/13-5/31/13

$53.48

47

June 2011

Financial Swap

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2012 RFP

2013 RFP

2013 RFP

2014 RFP

48

49

PECO Load Trends

Philadelphia

U.S.

Unemployment rate

(1)

7.9%

9.2%               

2011 annualized growth in

gross domestic/metro product

(2)

2.4%

Note: C&I = Commercial & Industrial

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

Weather-Normalized Load Year-over-Year 

-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

2.7%

50

PECO Procurement Plan

Customer Class

Products

Residential

75% full requirements

20% block energy

5% energy only spot

Small Commercial

(peak demand <100 kW)

90% full requirements

10% full requirements spot

Medium Commercial

(peak demand >100 kW but

<= 500 kW)

85% full requirements

15% full requirements spot

Large Commercial &

Industrial

(peak demand

>500 kW)

Fixed-Priced full

requirements

(2)

Hourly full requirements

PECO

Procurement

Plan

(1)

Residential –

weighted average wholesale prices

80 MW of baseload (24x7) block energy product (for Jan-Dec 2012) –

$51.52/MWh

70 MW of Jun-Aug 2011 summer on-peak block energy product –

$67.24/MWh

40 MW of Dec 2011-Feb 2012 winter on-peak block energy product –

$63.05/MWh

Large Commercial and Industrial (Hourly) –

weighted average

wholesale price

36%

of

hourly

full

requirements

product

(for

Jun

2011-May

2012)

(3)

–

$4.97/MWh

(4) 

May

2,

2011

RFP

-

Fifth

in

a

series

of

nine

procurements for the PUC-approved

Default Service Plan

Next RFP to be held on September 19, 2011

(1)

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

(2)

For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product.

(3)

Large C&I tranches which were not fully subscribed in the fall 2010 procurement.

(4)

The price for the hourly

full requirements product includes only ancillary services/Alternative Energy Portfolio Standard (AEPS) and miscellaneous costs.  The price does not

include energy and capacity costs.  Energy costs will be based on the PECO Zone Day-Ahead locational marginal pricing (LMP) price, and capacity will be based on the

PJM RPM price per day.

51

Appendix

52

Exelon Consolidated Metric Calculations and Ratios

$ in millions

FFO / Debt Coverage =

FFO (a)

Adjusted Debt (b)

FFO Interest Coverage =

FFO (a) + Adjusted Interest (c)

Adjusted Interest (c)

Adjusted Capitalization (e) =

Adjusted Debt (b) + Adjusted Equity (d)

=

32,606

Rating Agency Debt Ratio =

Adjusted Debt (b)

Adjusted Capitalization (e)

32%

7.2x

58%

=

=

=

2010A Credit Metrics

(1)

Includes changes in A/R, Inventories, A/P and other accrued expenses, option premiums, 

counterparty collateral and income taxes.  Impact to FFO is opposite of impact to cash flow 

(2)

Reflects retirement of variable interest entity + change in restricted cash

(3)

Reflects net capacity payment – interest on PV of PPAs (using weighted average cost of debt)

(4)

Reflects employer contributions – (service costs + interest costs + expected return on assets), 

net of taxes at 35%

(5)

Reflects operating lease payments  – interest on PV of future operating lease payments (using

weighted average cost of debt)

(6)

Includes AFUDC / capitalized interest

(7)

Reflects PV of net capacity purchases (using weighted average cost of debt)

(8)

Reflects unfunded status, net of taxes at 35%

(9)

Reflects PV of minimum future operating lease payments (using weighted average cost of debt)

(10)

Nuclear decommissioning trust fund balance > asset retirement obligation.  No debt imputed

(11)

Includes accrued interest less securities qualifying for hybrid treatment (50% debt / 50% equity)

(12)

Reflects interest on PV of minimum future operating lease payments (using weighted average cost of

debt)

(13)

Reflects interest on PV of PPAs (using weighted average cost of debt)

(14)

Includes AFUDC / capitalized interest and interest on securities qualifying for hybrid treatment (50%

debt / 50% equity)

(15)

Includes interest on securities qualifying for hybrid treatment (50% debt / 50% equity)

Exelon 2010 YE Adjustments

FFO Calculation

2010 YE

Source -

2010 Form 10-K (.pdf version)

Net Cash Flows provided by Operating Activities

5,244

Pg 159 -

Stmt. of Cash Flows

+/-

Change in Working Capital

644

Pg

159

-

Stmt.

of

Cash

Flows

(1)

-

PECO Transition Bond Principal Paydown

(392)

Pg

174

-

Stmt.

of

Cash

Flows

(2)

+    PPA Depreciation Adjustment

207

Pg

295

-

Commitments

and

Contingencies

(3)

+/-

Pension/OPEB Contribution Normalization

448

Pg 268-269 -

Post-retirement Benefits

(4)

+    Operating Lease Depreciation Adjustment

35

Pg

299

-

Commitments

and

Contingencies

(5)

+/-

Decommissioning activity

(143)

Pg 159-

Stmt. of Cash Flows

+/-

Other Minor FFO Adjustments

(6)

(54)

= FFO (a)

5,989

Debt Calculation

Long-term Debt (incl. Current Maturities and A/R agreement)

12,828

Pg 161 -

Balance Sheet

Short-term debt (incl. Notes Payable / Commercial Paper)

-

Pg 161 -

Balance Sheet

-

PECO Transition Bond Principal Paydown

-

N/A -

no debt outstanding at year-end

+    PPA Imputed Debt

1,680

Pg

295

-

Commitments

and

Contingencies

(7)

+    Pension/OPEB Imputed Debt

3,825

Pg

268

-

Post-retirement

benefits

(8)

+    Operating Lease Imputed Debt

428

Pg

299

-

Commitments

and

Contingencies

(9)

+    Asset Retirement Obligation

-

Pg

261-267

-

Asset

Retirement

Obligations

(10)

+/-

Other Minor Debt Equivalents

(11)

84

= Adjusted Debt (b)

18,845

Interest Calculation

Net Interest Expense

817

Pg 158 -

Statement of Operations

-

PECO Transition Bond Interest Expense

(22)

Pg 182 -

Significant Accounting Policies

+   Interest  on Present Value (PV) of Operating Leases

29

Pg

299

-

Commitments

and

Contingencies

(12)

+   Interest  on PV of Purchased Power Agreements (PPAs)

99

Pg

295

-

Commitments

and

Contingencies

(13)

+/-

Other Minor Interest Adjustments

(14)

37

= Adjusted Interest (c)

960

Equity Calculation

Total Equity

13,563

Pg 161 -

Balance Sheet

+    Preferred Securities of Subsidaries

87

Pg 161 -

Balance Sheet

+/-

Other Minor Equity Equivalents

(15)

111

= Adjusted Equity (d)

13,761

53

YTD GAAP EPS Reconciliation

Six Months Ended June 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.69

$0.26

$0.32

$(0.04)

$2.22

Mark-to-market impact of economic hedging activities

(0.25)

-

-

-

(0.25)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

0.04

Retirement of fossil generating units

(0.04)

-

-

-

(0.04)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

-

-

(0.04)

Recovery of costs pursuant to distribution rate case order

-

0.03

-

-

0.03

Constellation merger costs

-

-

-

(0.02)

(0.02)

YTD 2011 GAAP Earnings (Loss) Per Share

$1.41

$0.28

$0.32

$(0.06)

$1.94

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

Six Months Ended June 30, 2010

ExGen

ComEd

PECO

Other

Exelon

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.35

$0.37

$0.31

$(0.04)

$1.99

2007 Illinois electric rate settlement

(0.01)

-

-

-

(0.01)

Mark-to-market impact of economic hedging activities

0.10

-

-

-

0.10

Unrealized losses related to nuclear decommissioning trust funds

(0.05)

-

-

-

(0.05)

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.02)

(0.02)

(0.10)

Non-cash charge remeasurement of income tax uncertainties

0.10

(0.16)

(0.03)

(0.01)

(0.10)

Retirement of fossil generating units

(0.03)

-

-

-

(0.03)

YTD 2010 GAAP Earnings (Loss) Per Share

$1.42

$0.19

$0.26

$(0.07)

$1.80

54

GAAP to Operating Adjustments

Exelon’s 2011 adjusted (non-GAAP) operating earnings outlook excludes the

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent

not offset by contractual accounting as described in the notes to the consolidated financial

statements

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates

•

Financial impacts associated with the planned retirement of fossil generating units

•

One-time benefits reflecting ComEd’s 2011 distribution rate case order for the recovery of

previously

incurred

costs

related

to

the

2009

restructuring

plan

and for the passage of Federal

health care legislation in 2010

•

Certain costs associated with Exelon’s proposed merger with Constellation

•

Other unusual items

•

Significant changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of the year

55

Exelon Investor Relations Contacts

Exelon Investor Relations

10 South Dearborn Street

Chicago, Illinois 60603

312-394-2345

312-394-4082 (Fax)

For copies of other presentations,

annual/quarterly reports, or to be added

to our email distribution list please

contact:

Martha Chavez, Executive Admin

Coordinator

312-394-4069

Martha.Chavez@ExelonCorp.com

Investor Relations Contacts:

Stacie Frank, Vice President

312-394-3094

Stacie.Frank@ExelonCorp.com

Melissa Sherrod, Director

312-394-8351

Melissa.Sherrod@ExelonCorp.com

Ishaan Kapoor, Manager

312-394-3657

Ishaan.Kapoor@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com

Sandeep Menon, Principal Analyst

312-394-7279

Sandeep.Menon@ExelonCorp.com