Exelon (EXC) 8-K Macquarie Global Infrastructure Conference

1

Macquarie Global Infrastructure Conference

May 25, 2010

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

2009 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 2010 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 its forward-

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

3

Table of Contents

•

Exelon Generation

4

•

ComEd

32

•

PECO

37

4

5

Exelon Generation Consistently

Delivers Top-Tier Results

Exelon Generation has ability to replicate best practices on a large scale

2009

•

93.6%

capacity

factor

–

the

7

th

consecutive

year

exceeding 93%

•

Clinton

and

Quad

Cities

1

units

-

new

continuous

run

records of 596 and 594 days, respectively

•

TMI 1 unit set a new PWR world record for a 705-day

continuous run

2010 YTD

•

Limerick 1 unit set a new continuous run record of 727

days (second longest in the US)

•

Byron 2 unit –

new continuous run record of 541 days

Nuclear Fleet Achievements

•

Premier merchant generator of electricity

•

Largest nuclear operator in U.S. with 18% of nuclear

output; third largest in the world

•

Ownership interest in 19 operating nuclear reactors

•

Top quartile performance in capacity factors and

generating cost among nuclear fleets in U.S.

•

Geographically well-situated in competitive markets

and part of PJM, the largest RTO

Exelon Generation Highlights

0

200

400

600

800

Byron 2

Quad Cities 1

Clinton

Three Mile Island 1

Three Mile Island 1

LaSalle 2

Three Mile Island 1

LaSalle 1

Three Mile Island 1

Three Mile Island 1

Peach Bottom-3

Peach Bottom-3

LaSalle 2

Limerick 1

LaSalle 1

(Days)

Source: Platts News Flashes and Company Press Releases, 4/26/10

Nuclear Reliability

30 Longest Continuous U.S. Runs

6

Nuclear Uprates Offer Sustainable Value

Key component of Exelon

2020 low carbon roadmap

Creates additional low-

carbon generation

capacity

Uprates equivalent in size

to a new nuclear plant but

significantly lower cost,

shorter timeline, and more

predictable expenditures

No ongoing incremental

O&M expense

Capitalizes on Exelon’s

proven track record of

uprate execution

Dedicated project

management team

Proven technology design

Allows us to adjust timing

to respond to market

conditions

Straightforward regulatory

and environmental

licenses, permits and

approvals

Potential for uprates to

meet state alternative

energy standards

Uprate projects enable cost-effective growth and leverage Exelon’s

operational excellence

Strategic Value

Regulatory Feasibility

Execution Feasibility

7

Three Major Categories of Exelon Uprates

Uprates

Overnight

Cost

(1)

MUR (Measurement Uncertainty Recapture)

•

Through the use of advanced techniques and more precise

instrumentation, reactor power can be more accurately calculated

•

Can achieve up to 1.7% additional output

•

Requires NRC approval

187–234 MW

$300M

2 years

899–1,016 MW

$2,400M

EPU (Extended Power Uprate)

•

Through a combination of more sophisticated analysis and

upgrades to plant equipment, uprates can increase output by as

much as 20% of original licensed power level

•

Requires NRC approval

3 -

6

years

237–266 MW

$800M

Megawatt Recovery and Component Upgrades

•

Replacement of major components in the plant occur in the normal

life cycle process –

with newer technology, replacements result in

increased efficiency

•

Equipment includes generators, turbines, motors and transformers

•

Megawatt Recovery and Component Upgrades must conform to

NRC standards, but do not require additional NRC approval

3-4 years

~1,300–1,500 MW

$3,500M

Project

Duration

Refined

scenario

analysis

highlights

that

uprates

continue

to

be

economic

(1) In 2007 dollars. Overnight costs do not include financing costs or cost escalation.

Estimated

Internal Rate

of Return

11-13%

14-16%

11-14%

8

Multi-Regional Nuclear Uprate Program

73

2

12

59

MW

Online to

Date

2011 / 2012

32

25

Peach Bottom

2011 / 2010

110

95

Quad Cities

2014

15

12

TMI

2014 / 2013

31

25

Dresden

2013 / 2013

23

19

Quad Cities

2012 / 2012

42

34

Byron

2012 / 2012

42

34

Braidwood

2011 / 2011

41

33

Limerick

2011 / 2011

40

32

LaSalle

2014 / 2015

3

3

Peach Bottom

MUR:

2012 / 2013

6

6

Limerick

2012 / 2013

110

103

Dresden

2011 / 2012

5

5

Dresden

EPU:

MW Recovery & Component Upgrades:

2016 / 2017

340

306

Limerick

1,516

1,323

Total

172

336

17

148

3

Max

Potential

MW

2016

138

TMI

2016 / 2015

303

LaSalle

2016

17

Clinton

2015 / 2016

134

Peach Bottom

2010

2

Clinton

Year of Full

Operation

by Unit

Base

Case

MW

Station

Executing uprate projects across our

geographically diverse nuclear fleet

TMI

Limerick

Peach

Bottom

Total Midwest Uprates:

666-759 MW

Total Mid-Atlantic Uprates:

657-757 MW

Quad

Cities

Dresden

Byron

LaSalle

Clinton

Braidwood

Notes:  MW shown at ownership.

9

Phased Execution Lowers Risk

Approximately 80 MW scheduled to be completed in 2009 and 2010; total

expenditures

expected

to

be

$4,400

million

from

2008

–

2017

(1)

(1) Dollars shown are nominal, reflecting 6% escalation, in millions. 

$150

$350

$550

$675

$625

$725

$725

$400

$150

$ millions

•

Highest return projects are being completed in the early years

•

Leverages Exelon’s substantial experience managing successful uprate projects –

1,100

MW

completed

between

1999

-

2008

$50

Exelon's

Uprate

Plan

Expenditures

$0

$100

$200

$300

$400

$500

$600

$700

$800

2008A

2009A

2010E

2011E

2012E

2013E

2014E

2015E

2016E

2017E

0

200

400

600

800

1,000

1,200

1,400

1,600

Megawatt Recovery

MUR

EPU

MW Online (Cumulative)

Note: MW shown at ownership. Data contained in this slide is rounded.

10

Quad Cities Uprate Program

•

MW Recovery

–

Unit 2 Low Pressure Turbine Retrofit completed April

2010, increase of 48 MW achieved

–

Unit 1 Low Pressure Retrofit planned for Spring 2011

–

Partial completion of Unit 1 work has resulted in an

increase of 11 MW

•

MUR

–

Planned start date of project will be in 2011

–

Timing of uprate will be dependent on NRC approval

of license amendment

•

EPU

–

Completed in 2002

Scheduled start in 2011

1Q2013

9

2Q2013

9

MUR

* Capital investment and MW uprate numbers represent Exelon’s 75% ownership stake in Quad Cities Station.

In progress

2Q2010

48

3Q2011

47

MW Recovery (Low Pressure

Turbine Retrofit)

Status

Online

Date

MW

Increase*

Online

Date

MW

Increase*

Uprate Project

Unit 2

Unit 1

Quad

Cities

Uprate

Projects

are

underway

–

additional

MWs

will

come

on

line

between 2010 and 2013

Capital Investment $M*

$0

$50

$100

2009

2010

2011

2012

2013

2014

2015

2016

MW Recovery and Component Upgrade

MUR

11

Peach Bottom Uprate Program

•

MW Recovery

–

Project in progress with Low Pressure Turbine Retrofit

installations expected in 2011 and 2012

–

Replace Reactor Recirculation Pump Motor Generator

sets with energy efficient Adjustable Speed Drives in

2014 and 2015

•

MUR

–

Completed in 2003

•

EPU

–

Funding approved for design work

–

Will review in 2011 before authorizing installation

funding for  physical plant modifications and purchase

of materials

Peach

Bottom

Uprate

Projects

are

underway

–

additional

MWs

will

come

online

between

2011 and 2016

Capital Investment $M*

$0

$50

$100

$150

2009

2010

2011

2012

2013

2014

2015

2016

2017

MW Recovery and Component Upgrade

EPU

* Capital

investment

and

MW

uprate

numbers

represent

Exelon’s

50%

ownership

stake

in

Peach

Bottom

Station.

In progress

4Q2011

11

4Q2012

14

MW Recovery (Low Pressure

Turbine Retrofit)

Design phase in progress

1Q2016

67

1Q2015

67

EPU

Scheduled to start in 2012

4Q2015

2

4Q2014

2

MW Recovery (Adjustable

Speed Drives)

Status

Online

Date

MW

Increase*

Online

Date

MW

Increase*

Uprate Project

Unit 3

Unit 2

12

Dresden Uprate Program

•

MW Recovery

–

Project in progress with Low Pressure Turbine

Retrofit installations expected in 2011 and 2012

–

Partial completion of Unit 2 work has resulted in an

increase of 12 MW

–

Replace Reactor Recirculation Pump Motor

Generator sets with energy efficient Adjustable

Speed Drives in 2011 and 2012

•

MUR

–

Planned start date of project will be in 2011

–

Timing of uprate will be dependent on NRC approval

of license amendment

•

EPU

–

Completed in 2002

Dresden

Uprate

Projects

are

underway

–

additional

MWs

will

come

online            

between 2011 and 2014

Capital Investment $M

$0

$50

$100

$150

$200

2009

2010

2011

2012

2013

2014

2015

2016

2017

MW Recovery and Component Upgrade

MUR

In progress

4Q2012

3

4Q2011

3

MW Recovery (Adjustable

Speed Drives)

Scheduled start in 2011

1Q2013

12

1Q2014

12

MUR

In progress

1Q2013

51

1Q2012

52

MW Recovery (Low Pressure

Turbine Retrofit)

Status

Online

Date

MW

Increase

Online

Date

MW

Increase

Uprate Project

Unit 3

Unit 2

13

13

13

13

13

13

13

13

13

Nuclear Assets Levered to Economic

Recovery –

2011 & Beyond

Exelon

uniquely

captures

any

margin

upside

from

increasing

power

prices

given

our

low-cost nuclear generation

(1) Both supply and demand include effects of First Energy’s generation and forecasted load, respectively, joining PJM.  Illustrated unit costs are of existing PJM generation using 2011 fuel prices as of 4/30/2010.

Sources: CEMS, Energy Velocity, SNL,

Exelon Proprietary Information

2009 –

Exelon

Generation Owned

Output

(MWh)

Nuclear

93%

Coal

5%

Oil

<1%

Gas

1%

Renewables

1%

PJM Supply Curve

(1)

14

111.91

148.80

102.04

191.32

174.29

110.00

16.46

133.37

139.73

27.73

226.15

245.00

2008/2009

2009/2010

2010/2011

2011/2012

2012/2013

2013/2014

RTO

MAAC + APS

MAAC

Eastern MAAC

Only shown

if cleared

at separate

price and

generation

is located

in that zone

(1)

Reliability Pricing Model (RPM) Auction

PJM RPM Auction ($/MW-day)

Exelon Generation Eligible Capacity within PJM Reliability Pricing Model

(2)

Note: Data contained on this slide is rounded.

(1)

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

(2)

All generation values are approximate and not inclusive of wholesale transactions.

(3)

All capacity values are in installed capacity terms (summer ratings) located in the areas.

(4)

Obligation represents the remainder of the ComEd auction load that ends in May 2010.

(5)

Obligation consists of load obligations from PECO. PECO PPA expires December 2010.

(6)

Elwood

contract

expires

on

12/31/12

and

Kincaid

contract

expires

on

2/28/13.

(7)

Reflects decision in December 2010 to permanently retire Cromby Station and Eddystone Units

1&2

as

of

5/31/11.

None

of

these

933

MW

cleared

in

the

2011/2012

or

2012/2013

auctions.

(8)

Weighted average $/MW-Day would apply if all generation cleared in the highlighted zones.

$134.46        

1,500

8,700

(7)

10,300

(6)

Capacity

(3)

2013/2014

2009/2010

2010/2011

2011/2012

2012/2013

in MW

Capacity

(3)

Obligation

Capacity

(3)

Obligation

Capacity

(3)

Capacity

(3)

RTO

12,800

3,800 -

4,100

(5)

23,900

9,300 -

9,400

(4)

23,200

12,100

(6)

EMAAC

9,500

MAAC + APS

11,100 

9,300 –

9,400

(5)

MAAC

1,500

Avg ($/MW-Day)

(8)

$143.90

$174.29

$110.00

$74.75               

15

Retiring Cromby Station and

Eddystone Units 1&2

•

Agreed to delay deactivation of two units

to maintain reliability

(1)

, provided receipt

of required environmental permits and

adequate cost-based compensation

–

Maintained scheduled retirement date of 5/31/11

for Cromby 1 and Eddystone 1

–

Revised retirement dates for Cromby 2 to

12/31/11 and Eddystone 2 to 12/31/12

•

RMR to be filed with FERC in 2Q10 to compensate for cost of maintaining and

operating units beyond 5/31/11

–

Reimburses

Exelon

for

costs

to

keep

units

running

and

allows

for

a

reasonable

rate

of

return

on

investment, which is estimated at $2.6 million per RMR-month for Cromby Unit 2 and $8.0 million per

RMR-month for Eddystone Unit 2, plus $19.3 million in project investment

–

Targeting final approval by 4Q10

•

Retirements yield ~$165-200 million incremental NPV vs. continuing to operate the

units

–

Avoids ongoing operating and capital costs on aging units

–

Cromby and Eddystone have not cleared in the past two RPM capacity auctions (2011/12 and 2012/13)

–

Anticipates more stringent environmental regulations and avoids related capital investment

$80

$85

$40

Capital Expenditure

Reduction

$40

$18

$24

Incremental Pre-Tax

Operating Income

45

22

0

Depreciation Savings

75

46

24

Operating O&M Savings

$(80)

$(50)

$0

Revenue Net Fuel

2012

2011

2010

($ in millions)

Smaller, less efficient coal plants are challenged by economic and

environmental considerations

Ongoing Savings Impact

(1)

See PJM’s website (http://www.pjm.com/planning/generation-retirements/gr-study-results.aspx) for additional details regarding PJM’s Deactivation Study and Exelon’s response.

Note: RMR = reliability must-run agreement

16

Effectively Managing Nuclear Fuel Costs

Components of Fuel Expense in 2009

Projected Total Nuclear Fuel Spend

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

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

with the DOE.

2010–2012, 2014: 100% hedged in volume

2013:

~92% hedged in volume

All charts exclude Salem

0.0

2.0

4.0

6.0

8.0

10.0

2009A

2010

2011

2012

2013

2014

0

200

400

600

800

1,000

1,200

1,400

2009A

2010

2011

2012

2013

2014

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010

2011

2012

2013

2014

Exelon Average Reload Price

Projected Market Price (Spot)

Enrichment

38%

Fabrication

16%

Nuclear Waste

Fund

19%

Tax/Interest

1%

Conversion

3%

Uranium

23%

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

17

0

10

20

30

40

50

60

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Industry (w/o Exelon)

Exelon

Impact of Refueling Outages

Note:

Data

includes

Salem.

Net

nuclear

generation

data

based

on

ownership

interest.

•

Generally, every 18 months (PWRs) or

24 months (BWRs)

•

Average

Outage

Duration:

~28

days

(1)

Nuclear Refueling Cycle

•

Based on the refueling cycle, we will

conduct 10 refueling outages in 2010,

the same number of refueling

outages conducted in 2009

2010 Refueling Outage Impact

•

Output reflected TMI extended steam

generator replacement outage

•

Based on the refueling cycle, we

conducted 10 refueling outages in

2009, versus 12 in 2008

2009 Refueling Outage Impact

(1)  Average Outage Duration for refueling outages

from 2008 –

2009, excluding Salem.

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

7

8

9

10

11

12

13

Refueling Outage Duration

Nuclear Output

Actual

Target

# of Outages

Note: Exelon data includes Salem.  2009 average includes 23 days of TMI outage that

extended into 2010 reflecting steam generator replacement.

18

18

Total Portfolio Characteristics

101,700

102,441

40,500

39,897

5,500

16,830

22,700

13,897

0

50,000

100,000

150,000

200,000

2009A

2010E

ComEd Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

Expected Total Supply (GWh)

Expected Total Sales

(GWh)

91,800

91,804

48,000

47,866

24,800

29,840

5,800

3,555

0

50,000

100,000

150,000

200,000

2009A

2010E

Forward / Spot Purchases

Fossil & Hydro

Mid-Atlantic Nuclear

Midwest Nuclear

173,065

173,065

170,400

170,400

(1)  As of March 31, 2010.

(1)

(1)

19

Exelon Nuclear Fleet Overview

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

Average in-service time = 29 years

2011

42.6% Exelon, 57.4%

PSEG

In process

(decision in 2011-

2012):  2016, 2020

503, 500

(2)

W

PWR

2

Salem, NJ

2025

100%

Renewed: 2034

837

B&W

PWR

1

TMI-1, PA

Dry cask

100%

Renewed: 2029

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

574, 571

(2)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

655, 662

(2)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

869, 871

GE

BWR

2

Dresden, IL

2010

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask

100%

2024, 2029

1148, 1145

GE

BWR

2

Limerick, PA

2018

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

(3)

GE

W

W

Vendor

BWR

PWR

PWR

Type

1

2

2

Units

100%

2026

1065

Clinton, IL

100%

2024, 2026

1183, 1153

Byron, IL

100%

2026, 2027

1194, 1166

Braidwood, IL

Ownership

License Status /

Expiration

(1)

Net Annual

Mean Rating

MW 2009

Plant, Location

License extensions will be pursued for all units not already renewed

(1)

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

(2)

Capacity based on ownership interest.

(3)

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 the closing of their on-site storage pools.

20

20

20

Exelon Generation Hedging Disclosures

(As disclosed on April 23, 2010)

21

21

21

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, 2010. Going forward, we plan to update the

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.

22

22

22

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

23

23

23

23

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

24

24

24

24

2010

2011

2012

Estimated Open Gross Margin ($ millions)

(1,2)

$5,050

$4,900

$4,750

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)

$4.48

$29.73

$39.69

$0.43

$5.34

$30.71

$42.04

$(0.42)

$5.79

$32.19

$43.47

$0.14

(1)

Based on March 31, 2010 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.

Exelon Generation Open Gross Margin and

Reference Prices

25

25

25

25

(1)

2010

2011

2012

Expected Generation

(GWh)

(1)

164,600

161,700

161,200

Midwest

98,600

98,100

97,000

Mid-Atlantic

58,000

56,600

56,600

South

8,000

7,000

7,600

Percentage of Expected Generation Hedged

(2)

95-98%

79-82%

48-51%

Midwest

92-95

79-82

52-55

Mid-Atlantic

96-99

81-84

44-47

South

97-100

68-71

41-44

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.50

$44.50

$44.50

Mid-Atlantic

$36.00

$58.00

$51.50

ERCOT North ATC Spark Spread

$0.50

$0.50

$(6.50)

Generation Profile

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 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem. Expected

generation assumes capacity factors of 93.5%, 92.8% and 92.8% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected generation in

2011 and 2012 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

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. 

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.

(2)

(3)

26

26

26

26

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%

2010

$40

$(20)

$20

$(15)

$5

$ -

+/-

$30

2011

$125

$(110)

$125

$(115)

$75

$(70)

+/-

$40

2012

$320

$(315)

$235

$(225)

$175

$(170)

+/-

$45

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1) 

Based on March 31, 2010 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.

27

27

27

27

95% case

5% case

$6,500

$6,200

$4,800

$7,200

$6,300

$6,600

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2010

2011

2012

(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 2011 and 2012 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, 2010.

28

28

28

28

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin 

$5.05 billion

Step 2

Determine the mark-to-market value

of energy hedges

98,600GWh * 93% *

($46.50/MWh-$29.73/MWh)

= $1.54 billion

58,000GWh * 97% *

($36.00/MWh-$39.69/MWh)

= $(0.21 billion)

8,000GWh * 98% *

($0.50/MWh-$0.43/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:                           $5.05 billion

MTM value of energy hedges:           $1.54

billion

+

$(0.21

billion)

+

$0.00

billion

Estimated hedged gross margin:       $6.38 billion

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

29

29

29

Market Price Snapshots

Rolling 12 Months as of May 17, 2010

30

30

30

30

30

30

30

50

55

60

65

70

75

80

85

90

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

20

25

30

35

40

45

50

55

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

35

40

45

50

55

60

65

70

75

80

85

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

5

5.5

6

6.5

7

7.5

8

8.5

9

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

30

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2011

$5.57

2012  $5.98

Rolling 12 months, as of May 17, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$66.66

2012

$73.55

2011 Ni-Hub  $41.01

2012 Ni-Hub

$42.45

2012 PJM-West  $55.88

2011 PJM-West

$54.09

2011 Ni-Hub

$24.25

2012 Ni-Hub

$25.73

2012 PJM-West

$40.56

2011 PJM-West

$39.38

31

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

40

45

50

55

60

65

70

75

80

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

5

5.5

6

6.5

7

7.5

8

8.5

9

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

Market Price Snapshot

2012

$9.06

2011

$8.89

2011

$48.70

2012

$53.22

2011

$5.48

2012

$5.87

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$6.68

2012

$8.34

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 17, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

32

33

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10E

3Q10E

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

Unemployment rate

(1)

10.9%

2010 annualized growth in

gross domestic/metro product

(2)

2.9%

1/10 Home price index

(3)

(4.4)%

(1)  Source: Illinois Dept. of Employment Security (February 2010)

(2)

Source: Global Insight (March 2010)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

2009

(4)

1Q10       2010E

Average Customer Growth

(0.4)%     (0.1)%       0.1%

Average Use-Per-Customer

(1.0)%

0.2%

0.1%

Total Residential

(1.4)%       0.1%        0.2%

Small C&I

(2.2)%    (1.7)%        0.4%

Large C&I

(6.7)%    (1.1)%        1.7%

All Customer Classes

(3.3)%    (0.8)%        0.8%

34

6.1

6.9

2.0

2.0

7.3

6.4

2.0

2.2

Transmission

Distribution

ComEd Building Strength

Producing Results with

Regulatory Recovery Plan

~46%

~47%

8.5%

46.4%

Earned ROE

Equity

(1)

5.5%

45.4%

$8.1

$8.4

$9.4

2008

2009

2011

(Illustrative)

(2)

Average Annual Rate Base

($ in billions)

(1)

Equity based on definition provided in most recent Illinois Commerce Commission (ICC) distribution rate case order (book equity less goodwill).

(2)

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, including an ROE target, all of which are subject to

uncertainties and should not be relied upon as a forecast of future results.

Note: Amounts may not add due to rounding.

2010E

$8.9

ComEd executing on regulatory recovery plan resulting in healthy

increases in earned ROE

10%

10%

•

Significant improvement in earned ROE, from

5.5% in 2008 to 8.5% in 2009, targeting at least

10% in 2010

•

Continued strong operational performance

•

Anticipate electric distribution rate filing in 2Q10

•

Benefiting from regular transmission updates

through a formula rate plan, filed formula rate

update on May 14, 2010

•

Illinois Power Agency’s 2010 procurement

approved by the ICC on April 30

•

Uncollectibles expense rider tariff approved by

ICC in February 2010

•

Smart Meter pilot program and rider approved

by ICC and underway

•

Standard & Poor’s raised credit ratings in

3Q09 and Fitch in 1Q10

35

Illinois Power Agency (IPA)

RFP Procurement

•

On April 30, 2010, the ICC approved the bids from the RFP Procurement

held on April 28, 2010, for the remaining ComEd 2010-2011 load (~25% of

the total) and a portion of its 2011-2012 load (~7% of the total)

–

Contracts were awarded to 12 successful bidders

–

$32.54

Around-the-Clock (ATC) price for 2010-2011 planning year, in addition to:

•

Financial

Swap

price

(ATC

baseload

energy

only)

of

$50.15

for

June

2010

–

December

2010

and

$51.26

for

January

2011

–

December

2011;

increase

in

notional

quantity

to

3,000

MW

on

June 1, 2010

Delivery

Period

Peak

Off-Peak

June 2010 -

May 2011

5,528

4,344

June 2011 -

May 2012

1,980

549

Volume procured in the 2010 IPA

Procurement Event (GWh)

Note: Chart is for illustrative purposes only.  Data on this slide is rounded.

2009 RFP

2009 RFP

2010 RFP

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2013 RFP

Financial

Swap

Auction

Contract

June 2009

June 2010

June 2011

June 2012

June 2013

June 2014

36

Financial Swap Agreement with

Exelon Generation

3,000

$53.48

January 1, 2013 -

May 31, 2013

3,000

$52.37

January 1, 2012 -

December 31, 2012

3,000

$51.26

January 1, 2011 -

December 31, 2011

3,000

$50.15

June 1, 2010 -

December 31, 2010

2,000

$50.15

January 1, 2010 -

May 31, 2010

2,000

$49.04

June 1, 2009 -

December 31, 2009

1,000

$49.04

January 1, 2009 -

May 31, 2009

1,000

$47.93

June 1, 2008 -

December 31, 2008

Notional Quantity (MW)

Fixed Price ($/MWH)

Portion of Term

•

Market-based contract for ATC baseload energy only

–

Does not include capacity, ancillary services, or congestion

•

Supplies ~67% of ComEd’s Residential/Small C&I load for 2010/11

•

Represents long-term contract with stable pricing for ComEd’s customers

Note: C&I = Commercial & Industrial

37

38

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

Unemployment rate

(1)

9.2%               

2010 annualized growth in

gross domestic/metro product

(2)

0.8%

(1)  Source: U.S Dept. of Labor (PHL -

February 2010)

(2)  Source: Moody’s Economy.com (March 2010)

(3)  Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10E

3Q10E

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

Note: C&I = Commercial & Industrial

2009

(3)

1Q10        2010E

Average Customer Growth

(0.2)%       (0.2)%       (0.0)%

Average Use-Per-Customer

(2.1)%

2.1%

1.2%

Total Residential

(2.3)%         1.8%          1.1%

Small C&I

(2.7)%       (0.9)%       (0.2)%

Large C&I

(3.0)%         0.1%        (0.3)%

All Customer Classes

(2.6)%         0.5%         0.3%

39

2.7

2.8

3.0

3.2

0.5

0.5

0.5

1.1

1.1

1.1

1.2

0.6

2.0

1.3

0.5

Gas

Competitive Transition Charge (CTC)

Electric Transmission

Electric Distribution

PECO Executing on Transition Plan

Actively Engaged in Transition

•

Targeted earned ROE of ~11% in 2010; 9-

11% post transition

•

Electric and gas rate cases filed on 3/31/10

•

Selected as 1 of 6 companies to receive

maximum Federal stimulus award of $200

million for smart grid / smart meter

investment

•

PA Public Utility Commission approved

Smart Meter Plan under Pennsylvania Act

129 in April 2010

•

Fixed price Power Purchase Agreement

(PPA) with ExGen ends 12/31/10

•

Three of four procurement events for

electricity supply beginning Jan. 1, 2011

have been conducted, including 72% of

2011 residential load

~9 –

11%

Not applicable due to

transition rate structure

Rate Making ROE

Equity

~50-53%

$6.3

$5.7

$5.0

Average Annual

Rate

Base

(1)

($ in billions)

2008

2009

2011

(Illustrative)

(2)

(1)

Rate base as determined for rate-making purposes.

(2)

Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to uncertainties and should not be

relied upon as a forecast of future results.

$5.1

2010E

PECO is

managing

through

its

transition

period

and

is

positioned

for

continued strong financial performance post-2010

40

PECO Procurement

RFP being held on May 24, 2010, results will be public 30 days

thereafter; next RFP to be held on September 20, 2010

(1)

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

(2)

Wholesale prices; no Small/Medium Commercial products were procured in the June 2009 RFP.

(3)

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

Residential

Sept ’09 RFP average price of

$79.96/MWh

(2)

June ’09 RFP average price of

$88.61/MWh

(2)

49% of full requirements product

procured

80 MW of block energy procured

Small and Medium Commercial

Sept ’09 RFP average blended

price of $85.85/MWh

(2)

24% of Small Commercial full

requirements product procured

16% of Medium Commercial full

requirements product procured

85% full requirements

15% full requirements spot

Medium Commercial

(peak demand >100 kW

but <= 500 kW)

fixed-priced full

requirements

(3)

Hourly full requirements

Large Commercial &

Industrial

(peak

demand

>500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

PECO Procurement Plan

(1)

2011 Supply procured to

date (including June and

September 2009 RFPs)

Large Commercial and Industrial

100% of planned fixed -

price full

requirements contracts (12-mo.

term)

Residential

23% of planned full requirements

contracts (17 and 29-mo. terms)

140 MW of baseload (24x7)

block energy products (12, 24

and 60-mo. duration)

40 MW of Jan-Feb 2011 on-peak

block energy

Small Commercial

36% of planned full requirements

contracts (17 and 29-mo. term)

Medium Commercial

42% of planned full requirements

contracts (17-mo. term)

May 24, 2010 RFP

41

PECO –

Electric & Gas Distribution

Rate Case Filings

On March 31, PECO filed electric and gas distribution rate cases

•

First electric distribution rate case since 1989

–

Act 129 energy efficiency and smart meter costs recovered separately through rider

•

Last gas delivery rate case in 2008

53.18%

53.18%

Common Equity Ratio

R-2010-216-1592

R-2010-216-1575

Docket #

2010

(1)

2010

(1)

Test Year

ROE: 11.75%

ROR: 8.95%

ROE: 11.75%

ROR: 8.95%

Requested Returns

$1,100 million

$3,236 million

Rate Base

6.94%

(2)

$316 million

Electric

$44 million

Revenue Requirement Increase

5.28%

2011 Proposed Distribution Price

Increase as % of Overall Customer Bill

Gas

Rate Case Request

PECO executing its post-transition regulatory plan to secure fair and

reasonable returns on its distribution investment

(1) With pro forma adjustments.

(2) Excluding Alternative Energy Portfolio Standards (AEPS) and default service surcharge.

Note:

Electric

and

gas

rate

case

filings

available

on

Pennsylvania

Public

Utility

Commission

(PAPUC)

website

or

www.peco.com/know.

42

PECO –

Timeline for Rate Cases

•

Filed: March 31, 2010

•

Opposing Parties’

Testimony: June 2010

•

Rebuttal Testimony: July 2010

•

Hearings: August 2010

•

Administrative Law Judge (ALJ) Orders: October 2010

•

Final Orders Expected: December 2010

•

New Rates Effective: January 1, 2011

Note:

Dates

are

based

on

typical

approach

to

rate

cases

but

the

PAPUC

will

set

the

actual

schedule.

Expect

schedule

to

be

set at pre-hearing with ALJ in early June.

The PAPUC has a nine-month process for litigation of the

rate case filings

43

5.03

6.26

6.23

0.51

0.70

2.57

9.01

PECO Electric Residential Rate

Increases 2010 to 2011

January 1, 2011

January 1, 2010

Total = 14.7¢

Unit Rates (¢/kWh)

Proposed Total Bill

Increase ~11 %

Total = 16.3¢

AEPS 

~0.6%

Default Service Surcharge       

Mechanism based on results of

first two procurements      ~1.2%

Transmission surcharge                           

mechanism                        ~1.3%

Energy / Capacity

Competitive Transition

Charge

Transmission

Distribution

Distribution rate case     ~8.2%

0.38

Energy Efficiency

Surcharge

Breakdown of 2010 to 2011

~11% Increase (On Total Bill)

Notes:

•

Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%.

•

A Smart

Meter

surcharge,

which

will

likely

be

effective

3Q10,

is

expected

to

be

less

than

1%

and

is

not

expected

to

increase

until

2Q/3Q

of

2011.  As a

result, the Smart Meter surcharge will have a minimal impact on rate increases effective January 1, 2011.

•

Low income discounted rates were subsidized in the PPA in 2010 and will be recovered through distribution rates in 2011. 

0.29

44

PECO Smart Grid/Smart Meter

•

PECO

intends

to

spend

up

to

$650

million

on

its

Smart

Grid/Smart

Meter

Infrastructure

–

$550

million

Advanced

Metering

Infrastructure

over

10

–

15

years

–

~$300 million in 2010-2012 period

–

$100 million for Smart Grid over 3 years with stimulus funding

•

Awarded $200 million Federal Stimulus Grant in October 2009, contract with DOE was

finalized on April 12, 2010

•

Smart Meter Plan was approved by the PAPUC on April 22, 2010

•

Smart Meter investment required by Act 129, which provides for recovery through

surcharge including a return on capital investment

•

Smart Grid investment to be recovered through transmission and distribution rates

($ millions pre-tax)

2010

2011

2012

Total

Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012)

40

$    

150

$  

100

$  

290

$       

Smart Grid Stimulus Case

50

45

15

110

Total Stimulus Case

90

195

115

400

Stimulus Grant Request

(45)

(100)

(55)

(200)

Total Expenditures net of Stimulus grant

45

$    

95

$    

60

$    

200

$       

(1)

Timing of expenditures may vary as project plans are refined

Data contained in this slide is rounded.

2010-2012

Expenditures

With

Federal

Stimulus

Grant

(1)

:

45

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

Paul Mountain, Manager

312-394-2407

Paul.Mountain@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com

Sandeep Menon, Principal Analyst

312-394-7279

Sandeep.Menon@ExelonCorp.com