Commonwealth Edison 8-K This presentation includes forward-looking statements within the meaning of the Private Securities

Investor Meetings

June 2011

Exhibit 99.1

2

Forward-Looking Statements

This presentation includes forward-looking statements within the meaning of the Private Securities

Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause

actual results to differ materially from these forward-looking statements include those discussed

herein as well as those discussed in (1) Exelon’s 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

First Quarter 2011 Quarterly Report on Form 10-Q 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 12 and (3) other factors discussed in filings with the Securities and Exchange

Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy

Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place

undue reliance on these forward-looking statements, which apply only as of the date of this

presentation.

None

of

the

Companies

undertakes

any

obligation

to

publicly

release

any

revision

to

it

s forward-looking statements to reflect events or circumstances after the date of this presentation.

PJM RPM Auction Results

3

Base Auction Clearing Prices ($ / MW –

Day)

LDA

RTO

MAAC

EMAAC

SWMAAC

PY 12/13

Single Product

$16.46

$133.37

$139.73

$133.37

PY 13/14

Single Product

$27.73

$226.15

$245

$226.15

PY 14/15

Limited DR

$125.47

$125.47

$125.47

$125.47

Extended Summer DR and

Annual Resources

$125.99

$136.50

$136.50

$136.50

Increased quantities of uncleared generation in RTO reflect changed bidding behavior

by some generators to include the cost of environmental compliance

Note: RPM = Reliability Pricing Model; PY = Planning year; LDA = Locational Deliverability Area; DR = Demand response

Wolf Hollow Acquisition

4

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

5

ComEd Load Trends

Chicago

U.S.

Unemployment rate

(1)

8.5%

8.8%

2011 annualized growth in

gross domestic/metro product

(2)

2.5%                   3.2%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

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%

(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

Weather-Normalized Load

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 scheduled to go 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%

11.50%

(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

6

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 –

notional quantity

3,000 MW)

2011 RFP

2012 RFP

2012 RFP

2013 RFP

2013 RFP

2014 RFP

Financial Swap

2010 RFP

2011 RFP

2011 RFP

2012 RFP

ICC has approved 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

7

8

PECO Load Trends

Philadelphia

U.S.

Unemployment rate

(1)

8.4%

8.8%               

2010 annualized growth in

gross domestic/metro product

(2)

3.0%                   3.2%

Note: C&I = Commercial & Industrial

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%       2.1%

Small C&I

(1.9)%

(1.1)%      0.1%

Large C&I

0.8%  

(2.7)%      (1.6)%

All Customer Classes

0.1%   

(1.1)%       0.1%

(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

Weather-Normalized Load Year-over-Year 

Key Economic Indicators

Weather-Normalized Load

9

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

Spring

2011

RFP

was

held

on

May

2,

2011,

with

results

announced

on

May

18th

(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. 

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

10

EPA Regulations Will Move Forward in 2011

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

Phase In Of

Compliance

Develop Effluent Regulations

Pre Compliance Period

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/).

11

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  (5/24)

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/).

12

Exelon Generation Hedging Disclosures

(as of March 31, 2011)

Important Information

13

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

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

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

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

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

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

information on the following slides is as of 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.

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

Power Team utilizes several product types

and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

Consider market, credit, operational risk

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio

–

sell

what

we

own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

14

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

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

over the three years leading to the spot market

•

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

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

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

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

quarter to quarter

Exelon Generation Hedging Program

15

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,250

$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

16

(1)

Based on March 31, 2011 market conditions.  

(2)

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

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

Open gross margin assumes there is no hedging in place other than fixed assumptions for capacity cleared in the RPM auctions and uranium costs for nuclear power plants.

Open gross margin contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and

payments.  The estimation of open gross margin incorporates management discretion and modeling assumptions that are subject to change.

(3)

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

2011

2012

2013

Expected Generation

(GWh)

(1)

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

17

(1)

Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is based

upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products,

and options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem. 

Expected generation assumes capacity factors of 93.0%, 93.6% 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.

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.

18

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

19

(1)

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

unhedged supply is sold into the spot market.  Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market

inputs, future transactions and potential modeling changes. These ranges of approximate gross margin in 2012 and 2013 do not represent earnings guidance or a forecast of

future results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market

quotes for power, fuel, load following products, and options as of March 31, 2011.

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin 

$5.25 billion

Step 2

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

Open gross margin:                             

MTM

value

of

energy

hedges:

Estimated hedged gross margin:         

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

20

Determine the mark-to-market value of

energy hedges

Estimate hedged gross margin by

adding open gross margin to mark-to-

market value of energy hedges

$5.25 billion

$1.09billion

+

$0.66billion

+

$0.00

billion

$7.00 billion

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

$5.21

2013  $5.49

Forward NYMEX Coal

2012

$78.21

2013

$82.04

2012 Ni-Hub  $40.60

2013 Ni-Hub

$42.66

2013 PJM-West  $54.37

2012 PJM-West

$52.35

2012 Ni-Hub

$25.18

2013 Ni-Hub

$27.24

2013 PJM-West

$40.97

2012 PJM-West

$39.03

21

Rolling

12

months,

as

of

May

6th

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

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

6th

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

22