Commonwealth Edison 8-K Reaffirms Full Year Operating Earnings Guidance Range

Earnings Conference Call

1

st

Quarter 2011

April 27, 2011

Exhibit 99.2

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 (to be filed on April 27, 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

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.

This presentation includes references to adjusted (non-GAAP) operating earnings and non-GAAP

cash flows that exclude the impact of certain factors. We believe that these adjusted operating

earnings and cash flows are representative of the underlying operational results of the Companies.

Please refer to the appendix to this presentation for a reconciliation of adjusted (non-GAAP) operating

earnings

to

GAAP

earnings.

Please

refer

to

the

footnotes

of

the

following

slides

for

a

reconciliation

of

non-GAAP cash flows to GAAP cash flows.

3

2011 Operating Earnings Guidance

2011 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)

Refer

to

Earnings

Release

Attachments

for

additional

details

and

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.

Strong operating and financial

results in first quarter

•

Higher than expected operating EPS of

$1.17 mainly driven by higher

Generation gross margin and PA bonus

depreciation

•

Nuclear capacity factor of 94.8%

Reaffirming 2011 operating earnings

guidance of $3.90 -

$4.20/share

(1)

4

Key Messages

EPA’s proposed Air Toxics and 316(b) rules largely as

expected

•

Expect final rules to be implemented on time

•

Impact to the industry is manageable

FERC ruling on PJM MOPR defends competitive markets

Exelon’s nuclear plants are safe

•

Continuing to work with NRC and other stakeholders to evaluate

lessons learned and respond to Fukushima event

Pursuing projects to increase value

•

Transmission projects near Clinton and Quad Cities will reduce

congestion

5

Key Financial Messages

1Q 2011 operating earnings of $1.17/share

(1)

•

Quarter results $0.17/share better than prior year 

•

Quarter earnings exceeded guidance as a result of:

Favorable market conditions in the South region driven by weather

Pennsylvania bonus depreciation

Lower O&M cost than expected, primarily timing

Expect to generate $4.3 billion cash from operations in 2011

Expect 2Q 2011 operating earnings of $0.90 -

$1.00/share

(1)

(1)    Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

6

Exelon Generation

Operating EPS Contribution

2010

2011

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2) Outage days exclude Salem. 

Outage Days

(2)

1Q10

1Q11

Refueling

101

44

Non-refueling

5

14

1Q

$0.66

$0.90

Note: PPA = Power Purchase Agreement

Key Drivers –

1Q11 vs. 1Q10

(1)

Higher margins due to expiration of

the PECO PPA: $0.19

Favorable capacity pricing: $0.06

Nuclear volume: $0.04

Increased depreciation expense:

$(0.02)

Higher nuclear fuel costs: $(0.01)

Higher interest expense: $(0.01)

Power Fundamentals & Hedging Update

8

Key Drivers –

1Q11 vs. 1Q10

(1)

2010 uncollectible expense rider: $(0.06)

Appellate Court ruling: $(0.01)

ComEd Operating EPS Contribution

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

2010

2011

1Q

$0.19

1Q11

Actual

Normal

% Change

Heating Degree-Days   3,332          3,208           3.9%

$0.11

9

9

9

ComEd Load Trends

10

PECO Operating EPS Contribution

Key Drivers –

1Q11 vs. 1Q10

(1)

Electric and gas distribution rates: $0.05

2010 CTC collections, net of

amortization expense: $(0.05)

Lower interest expense: $0.01

2010

2011

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

1Q

$0.17

1Q11

$0.19

Actual

Normal

% Change

Heating Degree-Days   2,506        2,510            (0.2)%

Note: CTC = Competitive Transition Charge

11

PECO Load Trends

12

2011 Projected Sources and Uses of Cash

(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 $450 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)

Excludes ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit (LOCs).  Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo.

PECO’s A/R Agreement was extended in accordance with its terms through September 6, 2011.

(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.

13

Exelon Generation Hedging Disclosures

(as of March 31, 2011)

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

14

14

Important Information

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

Exelon Generation and to serve as an aid for the purposes of modeling Exelon Generation’s gross

margin (operating revenues less purchased power and fuel expense). The information on the following

slides is not intended to represent earnings guidance or a forecast of future events.  In fact, many of the

factors that ultimately will determine Exelon Generation’s actual gross margin are based upon highly

variable market factors outside of our control.  The information on the following slides is as of March 31,

2011.  We update this information on a quarterly basis.

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

assumptions regarding future market conditions, including power and commodity prices, heat rates, and

demand conditions, in addition to operating performance and dispatch characteristics of our generating

fleet.  Our simulation model and the assumptions therein are subject to change.  For example, actual

market conditions and the dispatch profile of our generation fleet in future periods will likely differ – and

may differ significantly – from the assumptions underlying the simulation results included in the slides. 

In addition, the forward-looking information included in the following slides will likely change over time

due to continued refinement of our simulation model and changes in our views on future market

conditions.

15

15

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

16

16

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

17

17

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,250

$4,900

$5,500

Open gross margin assumes all expected generation is sold

at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT North ATC Spark Spread ($/MWh)

(3)

$4.47

$31.32

$44.23

$4.42

$5.06

$31.32

$46.19

$1.88

$5.41

$32.83

$48.10

$2.06

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on March 31, 2011 market conditions. 

(2)

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.

18

18

2011

2012

2013

Expected Generation

(GWh)

(1)

165,800

165,400

162,800

Midwest

99,000

97,800

96,100

Mid-Atlantic

56,300

57,200

56,400

South & West

10,500

10,400

10,300

Percentage of Expected Generation Hedged

(2)

93-96%

73-76%

38-41%

Midwest

93-96

75-78

35-38

Mid-Atlantic

94-97

72-75

42-45

South & West

76-79

59-62

40-43

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.00

$41.00

Mid-Atlantic

$56.50

$50.50

$50.50

South & West

$4.50

$0.00

($3.00)

Generation Profile

(1)

Expected generation represents the amount of energy estimated to

be generated or purchased through owned or contracted for capacity.  Expected generation is based upon a

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,

which

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options.

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

capacity factors of 93.0%, 93.6% and 93.1% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do not represent

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

(2)

Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation.  Includes all hedging products, such as wholesale and retail sales of power,

options  and swaps.  Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011.

(3)

Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by considering the energy

revenues

and

costs

associated

with

our

hedges

and

by

considering

the

fossil

fuel

that

has

been

purchased

to

lock

in

margin.

It

excludes

uranium

costs

and

RPM

capacity

revenue,

but

includes

the

mark-to-market

value

of

capacity

contracted

at

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

It

can

be

compared

with

the

reference

prices

used

to

calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.

19

19

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.

20

20

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

(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.

$6,900

$4,900

21

21

Midwest

Mid-Atlantic

South & West

Step 1

Start with fleetwide open gross margin 

$5.25 billion

Step 2

Determine the mark-to-market

value

of energy hedges

99,000GWh * 94% *

($43.00/MWh-$31.32MWh)

= $1.09 billion

56,300GWh * 95% *

($56.50/MWh-$44.23MWh)

= $0.66 billion

10,500GWh * 77% *

($4.50/MWh-$4.42/MWh)

= $0.00 billion

Step 3

Estimate hedged gross margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.25 billion

MTM value of energy hedges:              $1.09billion + $0.66billion + $0.00 billion

Estimated hedged gross margin:          $7.00 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

22

22

35

40

45

50

55

60

65

70

75

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

22

22

20

25

30

35

40

45

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

50

55

60

65

70

75

80

85

90

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

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

$5.26

2013  $5.54

Rolling 12 months, as of April 15th

2011. Source: OTC quotes and electronic trading system. Quotes

are daily.

Forward NYMEX Coal

2012

$77.69

2013

$81.53

2012 Ni-Hub  $40.67

2013 Ni-Hub

$42.74

2013 PJM-West  $54.38

2012 PJM-West

$52.35

2012 Ni-Hub

$25.20

2013 Ni-Hub

$27.30

2013 PJM-West

$40.85

2012 PJM-West

$38.94

23

23

23

23

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

35

40

45

50

55

60

65

70

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

2/11

3/11

4/11

Market Price Snapshot

2013

9.35

2012

9.21

2012

$47.30

2013

$50.61

2012

$5.14

2013

$5.42

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

$7.70

2013

$9.02

ERCOT North On Peak Spark Spread

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

Rolling 12 months, as of April 15th

2011. Source: OTC quotes and electronic trading system. Quotes

are daily.

24

Appendix

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

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25

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 due 5/2; results

by 5/17)

DST Rate Case Final

Order  (by 5/31)

EPA Final Toxics

Rule (November)

Retirement of Cromby

1 & Eddystone 1 units

(5/31)

Proposed Toxics Rule 

(3/16)

Procurement RFP

(bids due 9/19;

results by 10/19)

Retirement of

Cromby 2 unit

(12/31)

Proposed 316(b) EPA

Regulation (3/28)

For

definition

of

the

EPA

regulations

referred

to

on

this

slide,

please

see

the

EPA’s

Terms

of

Environment

(http://www.epa.gov/OCEPAterms/).

EPA Final Transport

Rule (June)

26

27

Exelon View on Proposed CWA Sec. 316(b) Rule

28

28

EPA Regulations Will Move Forward in 2011

2010

2011

2012

2013

2014

2015

2016

2017

2018

PJM RPM Auction

14/15

15/16

16/17

17/18

Hazardous Air

Pollutants

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

By-Products

Cooling Water

Effluents

Develop Toxics Rule

Develop ICI

MACT

Pre Compliance Period

Compliance With Toxics Rule

Pre Compliance Period

Compliance With ICI MACT

Develop

Transport Rule

Compliance With Transport Rule

Interim CAIR

Develop O3

Transport

Rule (TR 2)

Estimated Compliance

Develop Criteria

NSPS revision

Compliance with Revised Criteria NSPS

Develop Revised

NAAQS

SIP provisions developed in response to revised NAAQS

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

Compliance with Federal GHG Reporting Rule

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

Develop GHG NSPS

Pre Compliance Period

Compliance With GHG NSPS

Develop Coal Combustion

By-Products Rule

Pre Compliance Period

Compliance With Federal CCB Regulations

Develop 316(b) Regulations

Pre Compliance Period

Phase In Of Compliance

Develop Effluent Regulations

Pre Compliance Period

Phase In Of

Compliance

Notes: RPM auctions take place annually in May.

For

definition

of

the

EPA

regulations

referred

to

on

this

slide,

please

see

the

EPA’s

Terms

of

Environment

(http://www.epa.gov/OCEPAterms/).

29

Factors Influencing PJM RPM Capacity Auction

(Comparison of PY 14/15 and PY 13/14 Price Drivers)

Exelon

Price Impact

Cost

of

Environmental

Upgrades

(1)

Higher Net CONE

(2)

Higher

Net

ACRs

for

Coal

Units

(3)

Import Transmission Limits and Objectives 

(muted impact on portfolio revenues due to regional diversification)

NJ CCGT Proposal / PJM Minimum Offer Price Rules

Peak Load

(4)

Demand Response Growth

2014/15 PJM Capacity Auction: Expected

Changes Since Planning Year 2013/14

(1)  We expect generators to reflect cost of capital expenditures into their cost based offers at the upcoming auction.

(2)  Cost of new entry (CONE) increased by 7.6% (for RTO) and 5.3% to 6.5% (within Locational Deliverability Areas (LDAs)).

(3)  Replacing 2007 net revenues with significantly lower 2010 revenues in the Net ACR (avoidable cost rate) calculations for coal generators may increase offer caps for certain

coal

generators

in

the

next

auction.

However,

some

coal

units

may

not

be

affected

due

to

high

net

revenues

compared

to

avoidable

costs.

(4)  Peak load reduced by approx. 1% in RTO (excluding the impact from Duke Ohio integration).

Note:

RPM

=

Reliability

Pricing

Model;

CCGT

=

combined

cycle

gas

turbine

Expect overall results to be similar to last year’s auction

N/A

30

Exelon’s Nuclear Plants Are Designed to

Withstand Extreme Environmental Hazards

None of Exelon’s plants are in major earthquake zones

Designed

to

withstand

highest

level

of

seismic

activity

for

that

location,

with

additional margin

Regular seismic analyses are performed and the NRC reviews new

information on earthquake sources and ground motion models to

determine if changes are necessary

Emergency core cooling systems are protected from water incursion,

including water tight doors, elevation of equipment above potential flood

levels and/or special engineered flood barriers (on a site-specific basis)

Fuel tanks are buried underground or enclosed in buildings

Switchgear for emergency operations are elevated above flood levels

All but one of Exelon’s plants are in Illinois and Pennsylvania

Oyster

Creek

(in

NJ)

is

more

than

5

miles

inland,

behind

barrier

islands

•

Tsunamis are extremely rare in the mid-Atlantic

•

Oyster Creek is 23 feet above sea level, while the maximum recorded

high tide on the Barnegat Bay beachfront 5 miles away is 7 feet above

sea level

The NRC requires all nuclear plants in the US to be able to withstand the most

severe natural phenomena historically reported for each plant’s surrounding

area, with a significant margin for uncertainty

Tsunami

Flood

Earthquake

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 (Summer

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

(1)

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

(2)

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

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

Exelon

pursues

license

extensions

well

in

advance

of

expiration

to

ensure

adequate

time

for review by the NRC

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

Expect to file

application in 2011/

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

In process

(decision in 2011-

2012) / 2016, 2020

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

33

33

ComEd 2010 Rate Case Update

ComEd Reply Brief (2/23/11)

$343M increase requested

11.50% ROE / 47.28% equity ratio

Rate base $7,349M

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

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

$113M increase proposed

10.00% ROE / 47.11% equity ratio

Rate base $6,480M

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

ALJ Proposed Order (4/1/11)

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

10.50% ROE / 47.28% equity ratio

Rate base $6,629M

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

(ICC Docket No. 10-0467)

Illinois Commerce Commission Final Order will be issued by May 31

34

34

ComEd –

Proposed Infrastructure

Investment and Modernization Legislation

Proposed Grid Modernization

Legislation Key Concepts

Incremental investment of $2.6B of capital

over 10 years

•

$1.5B smart grid/smart meter

•

$1.1B infrastructure improvements

Incorporates an annual formula rate

proceeding, similar to FERC Transmission

rate

•

Protocols clarify treatment of several

significant items, including pension costs

and pension asset

•

ROE formula based on average 30-year

Treasury yield

Reduces proceeding timeframe from 11

months to less than 9 months

ComEd is driving innovative regulatory and legislative strategy to benefit customers,

improve the transparency of the ratemaking process and enable economic development 

35

PECO Procurement Plan

(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

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

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

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

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

Large

Commercial

and

Industrial

-

Hourly

36%

of

Hourly

Full

requirements

product

(Jun

2011-May

2012)

(3)

May 2, 2011 RFP -

Fifth in a series

of nine procurements for the PUC-

approved Default Service Plan

Spring 2011 RFP to be held on May 2, 2011, with results public 15 days thereafter 

36

36

ComEd Customer Usage Breakdown

37

PECO Customer Usage Breakdown

38

Sufficient Liquidity

(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 other corporate entities.

39

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 40 for reconciliations to GAAP.

(2)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of April 21, 2011.

(3)

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

Moody’s

Credit

Ratings

(2)

S&P

Credit

Ratings

(2)

Fitch

Credit

Ratings

(2)

FFO / Debt

Target

Range

(2)

Exelon:

Baa1

BBB-

BBB+

ComEd:

Baa1

A-

BBB+

15-18%

PECO:

A1

A-

A

15-18%

Generation:

A3

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)

40

Exelon Consolidated Metric Calculations and Ratios

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

(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)

$ in millions

(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)

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

41

1Q GAAP EPS Reconciliation

Three Months Ended March 31, 2011

ExGen

ComEd

PECO

Other

Exelon

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

$0.90

$0.11

$0.19

$(0.03)

$1.17

Mark-to-market impact of economic hedging activities

(0.14)

-

-

-

(0.14)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

0.04

Retirement of fossil generating units

(0.02)

-

-

-

(0.02)

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

-

-

(0.04)

1Q 2011 GAAP Earnings (Loss) Per Share

$0.75

$0.10

$0.19

$(0.03)

$1.01

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

Three Months Ended March 31, 2010

ExGen

ComEd

PECO

Other

Exelon

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

$0.66

$0.19

$0.17

$(0.02)

$1.00

Mark-to-market impact of economic hedging activities

0.21

-

-

-

0.21

Unrealized gains related to nuclear decommissioning trust funds

0.03

-

-

-

0.03

Retirement of fossil generating units

(0.01)

-

-

-

(0.01)

Non-cash charge resulting from health care legislation

(0.04)

(0.02)

(0.02)

(0.02)

(0.10)

1Q 2010 GAAP Earnings (Loss) Per Share

$0.85

$0.17

$0.15

$(0.04)

$1.13

42

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

•

Any 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

•

Other unusual items

•

Significant changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of

the

year