Earnings Conference Call

2

nd

Quarter 2010

July 22, 2010

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

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

Second

Quarter

2010

Quarterly

Report

on

Form

10-Q

(to

be

filed

on

July

22,

2010)

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

2017/

2018

2016/

2017

2015/

2016

2014/

2015

PJM RPM Auctions

Delivery Year

2010

2011

2012

2013

2014

2015

2016

2017

2018

Hazardous Air

Pollutants

(HAP)

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

By-Products

Compliance with Federal GHG Reporting Rule

Pre-Compliance Period

PSD/BACT and Title V Applies to GHG Emissions from New and Modified Sources

Develop GHG Cap and Trade

Legislation or EPA GHG

Regulations Under CAA

2015: Compliance with GHG

Cap and Trade Legislation or

EPA GHG Regs Under CAA

November 2014: Compliance with MACT

HAP ICR

Pre-Compliance Period

Develop Coal

and Oil MACT

Interim CAIR

Program

Develop Clean Air

Transport Rule

(CATR)

2012: Compliance with CATR (to replace CAIR)

SIP

provisions

developed

in

response

to

revised

NAAQS

(e.g.,

Ozone,

PM

2.5

,

SO2,

NO2)

Compliance

with

CATR

2

Develop Revised NAAQS

and CATR 2

Pre-Compliance Period

2015: Compliance with Federal CCB

Regulations

Develop Coal

Combustion By-

Products Rule

EPA Regulations Will Begin to Affect

Upcoming PJM RPM Auctions

Notes:

Reliability

Pricing

Model

(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/).

4

Signs of Power Market Recovery

Forward natural gas prices remain stable

•

In-line with our fundamental view

Heat rates in the spot market are improving

•

We

believe

forward

heat

rate

expansion

is

not

fully

reflected

in

the

market,

particularly

Ni-Hub

Positive results from recent PJM RPM capacity auction

•

Half of our capacity is in premium eastern zones

Exelon has the largest upside to a recovery of any of our merchant peers

5

Nuclear

Uprates

1,300–1,500 MW of new Exelon nuclear capacity by 2017, the

equivalent of a new nuclear plant at roughly half the cost of a

new plant and no incremental operating costs

Leveraging transmission expertise through utility companies,

Exelon Transmission Company and Exelon Generation

Executing regulatory recovery plans at ComEd and PECO with

three active distribution rate cases

Industry-leading energy efficiency and smart grid investments

over the coming years with a regulated return

Organic Growth Opportunities

Transmission

Rate Cases

Smart Grid

6

Key Financial Messages

Operating results for 2Q10

•

Operating earnings of $0.99/share

(1)

•

94.8% nuclear capacity factor

•

Continuing to manage O&M costs

Forward power price outlook improving

•

Upside in off-peak prices due to increased load

•

Continued signs of economic recovery in our service areas

Pursuing three rate cases at PECO and ComEd

•

ComEd filed electric distribution rate case on June 30, 2010

•

PECO electric and gas distribution rate cases on schedule

(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.

Raising 2010 operating earnings guidance to $3.80 -

$4.10/share

(1)

7

Operating EPS

(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.

Strong

performance

at

the

utilities

offset

by

lower

ExGen

margins

driving

quarter

over

quarter

earnings

lower;

however,

2Q10

earnings

exceeded

guidance

of

$0.80-$0.90/share

$0.82

$0.11

$0.69

$0.15

$0.13

$0.18

2009

2010

$1.74

$0.28

$1.35

$0.31

$0.37

$0.31

2009

2010

HoldCo/Other

ExGen

PECO

ComEd

2

nd

Quarter (2Q)

(1)

$0.99

$0.67

GAAP EPS

Year-to-Date (YTD)

(1)

$1.99

$2.24

$2.07

$1.80

$0.99

$1.03

8

Exelon Generation

Operating EPS Contribution

2010

2009

Key Drivers –

2Q10 vs. 2Q09

(1)

Lower energy prices under the PECO

PPA: $(0.04), including CTC offset at

PECO $(0.05) and other pricing of $0.01

Unfavorable market/portfolio conditions:

$(0.05)

Higher nuclear fuel costs: $(0.03)

Favorable RPM capacity pricing: $0.03

Higher O&M costs primarily driven by

inflation: $(0.02)

(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. 

44

57

Refueling

15

21

Non-refueling

2Q10

2Q09

Outage Days

(2)

2Q

YTD

$0.82

$1.74

$0.69

$1.35

Note: PPA = Power Purchase Agreement

9

Key Drivers –

2Q10 vs. 2Q09

(1)

IL distribution tax: $0.02

Weather: $0.02

Load growth:

$0.01

Increased storm costs: $(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

2009

2Q

YTD

$0.13

$0.31

2Q10

Actual

Normal

% Change

Heating Degree-Days      519            766            (32)%

Cooling Degree-Days      312            224              39%

$0.18

$0.37

10

PECO Operating EPS Contribution

Key Drivers –

2Q10 vs. 2Q09

(1)

Increased CTC revenue resulting

in lower energy prices paid to

Generation under the PPA, offset

at Generation: $0.05

Weather: $0.03

Increased storm costs: $(0.01)

CTC amortization $(0.04)

2010

2009

(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.

2Q

YTD

$0.11

$0.28

2Q10

$0.15

$0.31

Actual

Normal

% Change

Heating Degree-Days    299

458           (35)%

Cooling Degree-Days    586

332            77%

11

PECO Load Trends

Philadelphia

Unemployment rate

(1)

9.2%               

2010 annualized growth in

gross domestic/metro product

(2)

0.8%            

Note: C&I = Commercial & Industrial

2009

(3)

2Q10      2010E

Average Customer Growth

(0.2)%  

0.2%    

0.0%

Average Use-Per-Customer

(2.1)%

(2.5)%

0.3%

Total Residential

(2.3)%   

(2.3)%      0.2%

Small C&I

(2.7)%

(5.1)%     (1.8)%

Large C&I

(3.0)%  

2.6%       0.9%

All Customer Classes

(2.6)%   

(0.7)%      0.1%

(1)  Source: U.S Dept. of Labor Preliminary data (June 2010)

(2)

Source: PECO estimate

(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

2Q10

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

Weather-Normalized

Load

Year-over-Year

(3)

Key Economic Indicators

Weather-Normalized Load

12

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10

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

Note: C&I = Commercial & Industrial

Chicago

Unemployment rate

(1)

10.2%

2010 annualized growth in

gross domestic/metro product

(2)

2.9%

4/10 Home price index

(3)

(1.5)%

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

(2)

Source: Global Insight (June 2010)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

2009

(4)

2Q10      2010E

Average Customer Growth

(0.4)%  

0.2%      0.2%

Average Use-Per-Customer

(1.0)%

1.4%

0.5%

Total Residential

(1.4)%   

1.6%       0.7%

Small C&I

(2.2)%

(0.1)%     (0.6)%

Large C&I

(6.7)%  

4.3%       2.5%

All Customer Classes

(3.3)%   

1.8%       0.8%

Weather-Normalized

Load

Year-over-Year

(4)

Key Economic Indicators

Weather-Normalized Load

13

Off-Peak Energy Price Improvement

Both Powder River Basin and Northern Appalachian coal prices have

remained relatively stable over the past quarter

However, NiHub and PJMW Hub off-peak energy prices have increased over

the same period

13

Stabilizing coal prices and recovery in load are providing upside to

prices, particularly in the off-peak

NiHubOff-Peak and Powder River Basin (PRB) Coal

23.00

24.00

25.00

26.00

27.00

28.00

10.50

11.50

12.50

13.50

14.50

15.50

2011 NiHub

2012 NiHub

2011 PRB

2012 PRB

PJMW Hub Off-Peak and Northern Appalachian (NAPP) Coal

35.00

36.00

37.00

38.00

39.00

40.00

41.00

64.00

66.00

68.00

70.00

72.00

74.00

76.00

2011 PJMW

2012 PJMW

2011 NAPP

2012 NAPP

14

74.75

134.46

174.29

110.00

143.90

0

500

1,000

1,500

2009/2010

2010/2011

2011/2012

2012/2013

2013/2014

0

100

200

300

PJM RPM Capacity Auction

Note:

Data

contained

on

this

slide

is

rounded.

(1)

Weighted

average

$/MW-Day

would

apply

if

all

generation

cleared

in

the

highlighted

zone.

(2)

All

generation

values

are

approximate

and

not

inclusive

of

wholesale

transactions;

All

capacity

values

are

in

installed

capacity

terms

(summer

ratings)

located

in

the

areas.

(3)

Elwood

contract

expires

on

12/31/12

and

Kincaid

contract

expires

on

2/28/13.

(4)

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.

7%

42%

51%

RTO

EMACC

MACC

8,700 MW

1,500 MW

10,300 MW

(4)

~$400M

Increase

2013/14

RPM

capacity

prices

result

in

a

$400

million

revenue

increase

to

Exelon

over

the

prior

auction;

expect

2014/15

auction

to

result

in

blended

prices

at

least

as

high

(3)

Left axis

PJM RPM Capacity Prices and Auction ($MW-day)

Capacity by Region Eligible for 2014/15

RPM Base Residual Auction

(2)

15

2010 Projected Sources and Uses of Cash

($ millions)

Exelon

(9)

Beginning Cash Balance

(1)

$1,050

Cash Flow from Operations

(1)(2)

1,100

1,025

2,400

4,575

CapEx (excluding Nuclear Fuel, Nuclear

Uprates and Solar Project, Utility Growth

CapEx)

(700)

(400)

(800)

(1,950)

Nuclear Fuel

n/a

n/a

(850)

(850)

Dividend

(3)

(1,400)

Nuclear Uprates and Solar Project

n/a

n/a

(325)

(325)

Utility Growth CapEx

(4)

(225)

(100)

n/a

(325)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5)(6)

500

--

250

750

Planned Debt Retirements

(7)

(225)

(400)

--

(1,025)

Other

(8)

(50)

125

--

0

Ending Cash Balance

(1)

$500

(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. 

Cash Flow from Operations for PECO and Exelon includes $550 million for competitive transition charges.  

(3)

Assumes 2010 dividend of $2.10/share.  Dividends are subject to declaration by the Board of Directors.

(4)

Represents new business and smart grid/smart meter investment.

(5)

Excludes Exelon Generation’s $212 million and ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit.  Excludes PECO’s $225 million Accounts

Receivable (A/R) Agreement with Bank of Tokyo.  Assumes PECO’s A/R Agreement is extended in accordance with its terms beyond September 16, 2010. 

(6)

Exelon Generation’s financing includes $250 million of debt to refinance a portion of Exelon Corp’s $400 million maturity.

(7)

Excludes Exelon Generation’s and ComEd’s tax-exempt bonds.  PECO’s planned debt retirement of $400 million represents the final retirement of the PECO Energy

Transition Trust.

(8)

“Other” includes PECO Parent Receivable, proceeds from options and expected changes in short-term debt.

(9)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities. 

16

2010 Operating Earnings Guidance

2010 Revised

Guidance

2010 Prior

Guidance

$0.40 -

$0.50

$2.70 -

$2.90

$3.70 -

$4.00

(1)

ComEd

PECO

Exelon

Generation

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.60 -

$0.70

Exelon

$3.80 -

$4.10

(1)

$0.60 -

$0.70

$0.45 -

$0.55

$2.80 -

$2.95

(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.

Key Drivers of Guidance Revision

+

Favorable 2Q performance,

including ExGen revenue net fuel

+

Favorable weather YTD

+

Reaffirmed outlook for remainder of

the year

Revised 2010 operating earnings guidance to $3.80-$4.10/share –

expect 3Q10 results of $1.00 -

$1.10/share

(1)

17

Exelon Generation Hedging Disclosures

(as of June 30, 2010)

*

*

*

*

*

*

*

*

*

*

18

Important Information

The

following

slides

are

intended

to

provide

additional

information

regarding

the

hedging

program

at

Exelon

Generation

and

to

serve

as

an

aid

for

the

purposes

of

modeling

Exelon

Generation’s

gross

margin

(operating

revenues

less

purchased

power

and

fuel

expense).

The

information

on

the

following

slides

is

not

intended

to

represent

earnings

guidance

or

a

forecast

of

future

events.

In

fact,

many

of

the

factors

that

ultimately

will

determine

Exelon

Generation’s

actual

gross

margin

are

based

upon

highly

variable

market

factors

outside

of

our

control.

The

information

on

the

following

slides

is

as

of

June

30,

2010.

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.

19

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

20

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

21

2010

2011

2012

Estimated Open Gross Margin ($ millions)

(1)(2)

$5,700

$5,300

$5,100

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)

$4.77

$33.17

$44.76

$1.28

$5.34

$32.63

$45.54

$(0.02)

$5.68

$34.22

$46.86

$0.53

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on June 30, 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.

22

2010

2011

2012

Expected Generation

(GWh)

(1)

167,500

163,000

162,600

Midwest

100,000

98,700

97,500

Mid-Atlantic

58,900

57,000

57,000

South

8,600

7,300

8,100

Percentage of Expected Generation Hedged

(2)

96-99%

86-89%

57-60%

Midwest

96-99

86-89

54-57

Mid-Atlantic

96-99

90-93

59-62

South

97-100

66-69

51-54

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.00

$43.50

$44.50

Mid-Atlantic

$36.50

$57.50

$51.00

ERCOT North ATC Spark Spread

$0.00

$(2.00)

$(5.50)

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 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 94.1%, 93.2% and 92.9% 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.

(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. 

Current  RMR discussions do not impact metrics presented in the hedging disclosure.  

(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.

23

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

$20

$(15)

$10

$(5)

$5

$ -

+/-

$25

2011

$100

$(90)

$75

$(65)

$30

$(25)

+/-

$45

2012

$260

$(245)

$220

$(210)

$130

$(125)

+/-

$45

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1) 

Based on June 30, 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.

24

95% case

5% case

$6,600

$6,400

$5,100

$7,100

$6,500

$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 June 30, 2010.

25

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$5.70 billion

Step 2

Determine the mark-to-market value

of energy hedges

100,000GWh * 97% *

($46.00/MWh-$33.17/MWh)

= $1.24 billion

58,900GWh * 97% *

($36.50/MWh-$44.76/MWh)

= $(0.47 billion)

8,600GWh * 98% *

($0.00/MWh-$1.28/MWh)

= $(0.01) billion

Step 3

Estimate hedged gross margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.70 billion

MTM value of energy hedges:              $1.24 billion + $(0.47 billion) + $(0.01) billion

Estimated hedged gross margin:          $6.46 billion

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

26

20

25

30

35

40

45

50

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

50

55

60

65

70

75

80

85

90

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

35

40

45

50

55

60

65

70

75

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

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

$5.17

2012  $5.58

Rolling

12

months,

as

of

July

14

, 2010.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2011

$67.94

2012

$74.45

2011 Ni-Hub  $39.68

2012 Ni-Hub

$41.68

2012 PJM-West  $53.79

2011 PJM-West

$51.80

2011 Ni-Hub

$24.73

2012 Ni-Hub

$26.61

2012 PJM-West

$39.80

2011 PJM-West

$38.41

th

27

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

40

45

50

55

60

65

70

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

Market

Price

Snapshot

2012

$9.09

2011

$9.05

2011

$45.50

2012

$49.38

2011

$5.03

2012

$5.44

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

$6.73

2012

$7.67

ERCOT North On Peak Spark Spread

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

Rolling

12

months,

as

of

July

14  ,

2010.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

th

28

Appendix

*****************

*****************

*****************

*****************

29

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)

RPM Auction Results

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               

PJM

RPM

Auction

($MW-day)

Exelon

Generation

Eligible

Capacity

within

PJM

Reliability

Pricing

Model

(2)

30

ComEd Delivery Service

Rate Case Filing Summary

$396

Total

($2,337

million

revenue

requirement)

(6)

$45

Other adjustments

(5)

$22

Bad debt costs (resets base level of bad debt to 2009 test year)

$55

Pension and Post-retirement health care expenses

(4)

$95

Capital Structure

(3)

: ROE –

11.50% /

Common Equity –

47.33% / ROR –

8.99%

$179

(2)

Rate Base: $7,717 million

(1)

Requested Revenue 

Increase

($ in millions)

Primary drivers of rate request are new plant investment, pension/retiree

health care and cost of capital

(1)

Filed

June

30,

2010

based

on

2009

test

year,

including

pro

forma

capital

additions

through

June

2011,

and

certain

other

2010

pro

forma

adjustments.

(2)

Includes

increased

depreciation

expense.

(3)

Requested

capital

structure

does

not

include

goodwill;

ICC

docket

07-0566

allowed

10.3%

ROE,

45.04%

equity

ratio

and

8.36%

ROR.

ROE

includes

0.40%

adder

for

energy

efficiency

incentive.

(4)

Reflects

2010

expense

levels,

compared

to

2007

expense

levels

allowed

in

last

rate

case.

(5)

Includes

reductions

to

O&M

and

taxes

other

than

income,

offset

by

wage

increases,

normalization

of

storm

costs

and

the

Illinois

Electric

Distribution

Tax,

other

O&M

increases,

and

decreases

in

load.

(6)

Net

of

Other

Revenues.

Note:

ROE

=

Return

on

Equity,

ROR

=

Return

on

Rate

Base,

ICC

=

Illinois

Commerce

Commission.

31

ComEd Delivery Rate Case

Alternative Regulation (Alt Reg) Proposal

ComEd plans to make a companion Alt Reg filing proposing to recover the costs of smart

grid and other projects outside of the traditional rate case process

•

9-month statutory process

The proposal includes a “flow-through mechanism”

to recover capital carrying costs and

incremental O&M, as incurred

Costs

and

investments

will

be

rolled

in

to

future

rate

cases,

when

they

occur

Assured

savings

to

customers

–

$2

million

on

capped

O&M

costs

for

program

costs

(excluding CARE)

Includes

an

incentive/penalty

mechanism

for

performance

above

or

under

budget

Alt Reg Proposal is permitted under section 9-244 of the IL Public Utilities Act

$30

$15

Man-hole refurbishment and cable replacement

-

$10

Expanded funding for low income CARE programs

(1)

$5

-

Electric Vehicle Fleet Purchase

$55

$40

-

$10

-

$20

Accelerated Smart Grid Deployment

•

190,000 additional AMI Meters and Outage Management

System Interface

•

Accelerated deployment of Distribution Automation

•

Customer Applications

Capital

O&M

$ millions

(1)

Total CARE amount for two-year proposal is $20 million.

32

ComEd Residential Rate Design

Straight Fixed/Variable Proposal

Filing

includes

a

proposal

to

gradually

move

more

of

residential

delivery

bill

to

the

fixed

customer charge, rather than usage-based kwh component through three step phase-in

Current rate design:  37% fixed / 63% variable split

Proposed:  60%/40% split in June 2011, 70%/30% in June 2012, and

80%/20% in June 2013

Mitigates impact of weather and load fluctuations due to weather

and economy

Rate design reflects current cost structure and sends appropriate price signals

•

Fixed costs to be collected via fixed charges (i.e. Customer Charge, Meter Charge)

•

Variable costs to be collected via variable charges (i.e. per kWh)

Eliminates economic disincentive to promote energy efficiency

Proposed Straight Fixed/Variable rate design is consistent with ICC

orders in other recent cases

33

3.82

4.73

7.44

7.03

0.73

0.73

0.65

0.60

ComEd Delivery Rate Case

Residential Rate Impacts 2010 to 2011

(1)

(1)

Reflects

change

in

distribution

rates

only.

Assumes

Energy,

Transmission

and

all

other

components

remain

constant

as

of

June

2010,

except

as

noted

above.

(2)

"All

Other"

includes

impact

of

riders

that

are

applicable

to

residential

bills.

Unit rates: cents / kWh

All Other

(2)

Transmission

Energy

Distribution

Approximately

4% increase

July 1, 2010

July 1, 2011

Transmission: Subject to FERC

formula rate annual update

Comments

Energy: Reflects reduced PJM capacity

price that PJM has published for the

June 2011 –

May 2012 planning

period.  Energy component may vary

Distribution: As proposed

12.63

13.09

Note:  Amounts may not add due to rounding.

Proposed residential rate impact of 7% will be mitigated by impact

of lower capacity prices resulting in an increase of 4%

34

ComEd Delivery Service Rate Case

Tentative Schedule

Delivery

Service

Rate

Case

Filed

–

June

30,

2010

Alt

Reg

Proposal

Filed

–

August

/

September

2010

Intervenor

and

Rebuttal

Testimony

–

4Q

2010

Hearings

–

December

2010

/

January

2011

Administrative

Law

Judge

Order

–

February

2011

Final

Order

Expected

–

May

2011

New

Rates

Effective

–

June

2011

Note:

Dates

are

based

on

typical

approach

to

rate

cases

but

the

ICC

will

set

the

actual

schedule,

which

is

expected

in

3Q

2010.

35

6.4

6.9

2.0

2.1

6.7

7.2

2.2

1.9

Transmission

Distribution

ComEd Building Strength

~45%

~43%

8.5%

46.4%

Earned ROE

Equity

(2)

5.5%

45.4%

$8.4

$8.6

$9.4

2008

2009

2011

(Illustrative)

(1)

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. Amounts do not reflect pro forma adjustments that may be made to determine rate base for rate case filing.

(2)

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

Note: Amounts may not add due to rounding.

2010E

$9.0

>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

Filed electric distribution rate case on June 30,

2010

Benefiting from regular transmission updates

through a formula rate plan

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

ComEd executing on regulatory recovery plan resulting in healthy

increases in earned ROE

Producing

Results

with

Regulatory

Recovery

Plan

End

of

Year

Rate

Base

($

in

billions)

(1)

36

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 (~6% 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

37

ComEd Customer Usage Breakdown

Other

2%

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

3%

Leisure & Hospitality

9%

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Limited survey of select Large C&I customers has indicated an increase in

production via longer production runs and additional shifts due to improved

economic conditions for manufacturing-based customers, especially in the

steel and transportation sectors, along with data center expansions.

Customer Usage by Revenue Class

Top

380

Customer

Usage

by

Segment

38

PECO –

Electric & Gas Distribution

Rate Case Filing Summary

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-2010-2161592

R-2010-2161575

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

(1)    With pro forma adjustments.

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

Note: Electric and gas rate case filings available on PAPUC (Pennsylvania Public Utility Commission) website or www.peco.com/know.

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

reasonable returns on its distribution investment

39

PECO –

Timeline for Rate Cases

Electric

Gas

Filed:

March 31, 2010

March 31, 2010

Opposing Parties’

Testimony:

July 7, 2010

June 30, 2010

Rebuttal Testimony:

August 3, 2010

July 23, 2010

Hearings:

August 16-20, 2010

August 9-11, 2010

Administrative Law Judge Orders:

November 2, 2010

November 2, 2010

Final Orders Expected:

December 16, 2010

December 16, 2010

New Rates Effective:

January 1, 2011

January 1, 2011

PAPUC has a nine-month process for litigation of the rate case filings

40

5.03

6.26

6.23

0.51

0.70

2.57

8.57

PECO Electric Residential Rate

Increases 2010 to 2011

January 1, 2011

January 1, 2010

Total = 14.7¢

Unit Rates (¢/kWh)

Proposed Total Bill

Increase ~9 %

Total = 16.0¢

AEPS                                 ~0.6%

Smart Meter

~0.7%

Default Service surcharge       

mechanism                      ~(1.8)%

Transmission surcharge                           

mechanism                        ~1.3%

Energy / Capacity

Competitive Transition

Charge

Transmission

Distribution

Distribution Rate Case     ~8.2%

0.47

Energy Efficiency

Surcharge

Breakdown of 2010 to 2011

~9% Increase (On Total Bill)

Notes:

•

Assume results from final procurement in September 2010 are the same as May 2010 procurement.

•

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

•

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

0.29

41

2.7

3.0

3.3

3.5

0.5

0.6

0.6

1.1

1.1

1.1

1.1

0.6

1.7

0.9

Gas

Competitive Transition Charge (CTC)

Electric Transmission

Electric Distribution

PECO Executing on Transition Plan

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

11% post transition

Electric and gas rate cases filed on March

31, 2010

Selected as 1 of 6 companies to receive

maximum Federal stimulus award of $200

million for smart grid / smart meter

investment

PAPUC approved Smart Meter Plan under

Pennsylvania Act 129 in April 2010

Fixed price PPA with ExGen ends

December 31, 2010

Three of four procurement events for

electricity supply beginning January 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

2008

2009

2011

(Illustrative)

(2)

(1)

Rate base as determined for rate-making purposes. Amounts do not reflect pro forma adjustments that may be made to determine rate base for rate case filing

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

Actively Engaged in Transition

End of Year Rate Base ($ in billions)

(1)

42

PECO Procurement

(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 2011 fixed-priced full requirements product.

Large Commercial and Industrial

Average price of $77.55/MWh

(2)

100% of fixed-price full requirements procured in May ’10

(3)

Medium Commercial

Sept ’09 / May ’10 RFP aggregate result $77.89/MWh

(2)

Remaining 42% of full requirements to be procured in Sep ‘10

Residential

June ’09 RFP average price of $88.61/MWh

(2)

Sept ’09 RFP average price of $79.96/MWh

(2)

May ‘10 RFP average price of $69.38/MWh

(2)

Remaining 28% of full requirements to be procured in Sep ‘10

Small Commercial

Sept ’09 / May ’10 RFP aggregate result $77.65/MWh

(2)

Remaining 40% of full requirements to be procured in Sep ‘10

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

Next RFP to be held on September 20, 2010

43

PECO Customer Usage Breakdown

Other

3%

Other Large

C&I

24%

150 Large

C&I

17%

Small C&I

22%

Residential

34%

7%

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

2%

Retail Trade

9%

Finance, Insurance & Real Estate

12%

Pharmaceuticals

PECO’s load is relatively diversified by customer class and industry

Customer Usage by Revenue Class

Top 150 Customer Usage by Segment

44

ComEd and PECO Accounts Receivable

ComEd A/R

(1)

2Q08

2Q09

2Q10

PECO A/R

(1)

% of AR

$827M

$738M

$784M

(1)   Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and include, for PECO, pledged and

long-term receivables.

>60 days

31-60 days

0-30 days

Note: Data contained on this slide is rounded.

2Q08

2Q09

2Q10

$755M

$894M

$768M

45

Sufficient Liquidity

--

--

--

--

Outstanding Facility Draws

(434)

(231)

(3)

(195)

Outstanding Letters of Credit

$7,365

$4,834

$574

$1,000

Aggregate

Bank

Commitments

(1)

6,931

4,603

571

805

Available

Capacity

Under

Facilities

(2)

(187)

--

--

(187)

Outstanding Commercial Paper

$6,744

$4,603

$571

$618

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

Available Capacity Under Bank Facilities as of July 14, 2010

Exelon bank facilities are largely untapped

(1)  Excludes previous commitment from Lehman Brothers Bank and 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.

46

Projected 2010 Key Credit Measures

14.1x

9.6x

FFO / Interest

Generation /

Corp:

69%

39%

FFO / Debt

55%

70%

Rating Agency Debt Ratio

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB+

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa1

Baa1

Moody’s Credit

Ratings

(3)

3.3x

3.6x

FFO / Interest

ComEd:

17%

16%

FFO / Debt

43%

50%

Rating Agency Debt Ratio

4.2x

4.6x

FFO / Interest

PECO:

23%

21%

FFO / Debt

48%

50%

Rating Agency Debt Ratio

29%

47%

Rating Agency Debt Ratio

96%

47%

FFO / Debt

21.2x

11.8x

FFO / Interest

Generation:

48%

37%

6.7x

Without PPA &

Pension / OPEB

(2)

58%

Rating Agency Debt Ratio

27%

FFO / Debt

6.3x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes: Exelon and PECO metrics exclude securitization debt.  See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to

GAAP.

(1)

FFO/Debt metrics include the following standard adjustments: debt equivalents for PV of Operating Leases, PPAs, unfunded Pension and OPEB obligations (after-tax),

Capital Adequacy for Energy Trading, and other minor debt equivalents.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of July 15, 2010. 

47

FFO Calculation and Ratios

+

Other

Non-Cash

items

(1)

-

AFUDC/Cap. Interest

-

Decommissioning activity

+/-

Change in Working Capital

FFO

Calculation

= FFO

-

PECO Transition Bond Principal Paydown

Net Cash Flows provided by Operating Activities

Net Interest Expense

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ 6% interest on Present Value (PV) of Operating Leases

+ Interest on imputed debt related to PV of PPA

+ AFUDC & Capitalized interest

-

PECO Transition Bond Interest Expense

FFO

Interest

Coverage

FFO

= Adjusted Debt

+

Off-balance

sheet

debt

equivalents

(2)

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(3)

FFO

Debt

Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+

Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+

Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt

to

Total

Cap

(1)

Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB contribution normalization.

(2)

Metrics

are

calculated

in

presentation

unadjusted

and

adjusted

for

debt

equivalents

for

PV

of

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax),

Capital Adequacy for Energy Trading, and other minor debt equivalents.

(3)

Uses current year-end adjusted debt balance.

48

2Q GAAP EPS Reconciliation

NOTE:

All

amounts

shown

are

per

Exelon

share

and

represent

contributions

to

Exelon's

EPS.

Data

contained

on

this

slide

is

rounded.

(0.04)

-

-

(0.02)

(0.02)

2009 severance charges

0.10

-

-

-

0.10

Unrealized gains related to nuclear decommissioning trust funds

(0.01)

(0.01)

-

-

-

NRG acquisition costs

(0.03)

-

-

-

(0.03)

2007 Illinois electric rate settlement

(0.16)

-

-

-

(0.16)

Mark-to-market adjustments from economic hedging activities

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and reassessment

of state deferred income taxes

$0.99

$(0.06)

$0.11

$0.17

$0.77

2Q09 GAAP Earnings (Loss) Per Share

$1.03

$(0.03)

$0.11

$0.13

$0.82

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

Exelon

Other

PECO

ComEd

ExGen

Three

Months

Ended

June

30,

2009

(0.01)

-

-

-

(0.01)

2007 Illinois electric rate settlement

(0.02)

-

-

-

(0.02)

Retirement of fossil generating units

(0.08)

-

-

-

(0.08)

Unrealized losses related to nuclear decommissioning trust funds

(0.11)

-

-

-

(0.11)

Mark-to-market adjustments from economic hedging activities

(0.10)

(0.01)

(0.03)

(0.16)

0.10

Non-cash remeasurement of income tax uncertainties

$0.67

$(0.03)

$0.11

$0.02

$0.57

2Q10 GAAP Earnings (Loss) Per Share

$0.99

$(0.02)

$0.15

$0.18

$0.69

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

Exelon

Other

PECO

ComEd

ExGen

Three

Months

Ended

June

30,

2010

49

YTD GAAP EPS Reconciliation

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and reassessment

of state deferred income taxes

(0.04)

-

-

(0.02)

(0.02)

2009 severance charges

0.05

-

-

-

0.05

Unrealized gains related to nuclear decommissioning trust funds

(0.03)

(0.03)

-

-

-

NRG acquisition costs

(0.06)

-

-

-

(0.06)

2007 Illinois electric rate settlement

0.01

-

-

-

0.01

Mark-to-market adjustments from economic hedging activities

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

$2.07

$(0.14)

$0.28

$0.35

$1.58

YTD 2009 GAAP Earnings (Loss) Per Share

$2.24

$(0.09)

$0.28

$0.31

$1.74

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

Exelon

Other

PECO

ComEd

ExGen

Six

Months

Ended

June

30,

2009

(0.01)

-

-

-

(0.01)

2007 Illinois electric rate settlement

(0.10)

(0.01)

(0.03)

(0.16)

0.10

Non-cash remeasurement of income tax uncertainties

(0.03)

-

-

-

(0.03)

Retirement of fossil generating units

(0.05)

-

-

-

(0.05)

Unrealized losses related to nuclear decommissioning trust funds

0.10

-

-

-

0.10

Mark-to-market adjustments from economic hedging activities

(0.10)

(0.02)

(0.02)

(0.02)

(0.04)

Non-cash charge resulting from healthcare legislation

$1.80

$(0.07)

$0.26

$0.19

$1.42

YTD 2010 GAAP Earnings (Loss) Per Share

$1.99

$(0.04)

$0.31

$0.37

$1.35

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

Exelon

Other

PECO

ComEd

ExGen

Six

Months

Ended

June

30,

2010

NOTE:

All

amounts

shown

are

per

Exelon

share

and

represent

contributions

to

Exelon's

EPS.

Data

contained

on

this

slide

is

rounded.

50

2010 Earnings Outlook

Exelon’s

2010

adjusted

(non-GAAP)

operating

earnings

outlook

excludes

the

earnings

effects

of

the

following:

•

Mark-to-market

adjustments

from

economic

hedging

activities

•

Unrealized

gains

and

losses

from

nuclear

decommissioning

trust

fund

investments

to

the

extent

not

offset

by

contractual

accounting

as

described

in

the

notes

to

the

consolidated

financial

statements

•

Significant

impairments

of

assets,

including

goodwill

•

Changes

in

decommissioning

obligation

estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement

•

Costs

associated

with

ComEd’s

2007

settlement

with

the

City

of

Chicago

•

Costs

associated

with

the

retirement

of

fossil

generating

units

•

Non-cash

charge

resulting

from

passage

of

Federal

health

care

legislation

•

Non-cash

remeasurement

of

income

tax

uncertainties

•

Other

unusual

items

•

Significant

future

changes

to

GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of

the

year

Operating

O&M

target

excludes

the

following

items:

•

Exelon

Generation:

Decommissioning

accretion

expense

•

ComEd:

Impact

of

riders,

primarily

Rider

EDA

(Energy

Efficiency

and

Demand

Response Adjustment)

•

PECO:

Impact

of

energy

efficiency

and

smart

grid/meter

riders