Earnings Conference Call •

2

nd

Quarter 2009

July 24, 2009

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 2008 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 2009 Quarterly Report on Form 

10-Q (to be filed on July 24, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b)

Part I, Financial  Information, ITEM 1. Financial Statements: Note 14 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 attachments to the earnings  release and 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 non-GAAP 

cash flows to GAAP cash flows.

3

Carbon

Cost

Reductions

PA

Procurement

Nuclear

Uprates

-

Lowest

carbon

intensity

in

the

sector

-

$1.1

billion

(2)

and

growing

annual

upside

to

Exelon revenues from implementation of Waxman-Markey legislation

-

Developing business plan for transmission company to improve reliability, reduce

congestion, mitigate oversupply and allow our Midwest fleet to maintain its

baseload value

-

$350 million in announced O&M reductions for 2010, more than half of which is

sustainable

-

1,300 MW -

1,500 MW in Exelon nuclear uprates by 2017, the equivalent of a

new nuclear plant at roughly ½

the cost of new build and no incremental

operating costs

-

$101.30/MWh

(1)

result

in

June

PECO

power

procurement

suggests

higher

margins at Exelon Generation in 2011 and beyond

-

ComEd

and

PECO

plan

to

make

up to

$1

billion

in

investments

to

build

smart

grid infrastructure over the coming years, providing for a regulated return on

investment

(1)    Reflects retail price including line losses and gross receipts tax

(2)    Assumes $15/tonne carbon pricing.

Exelon’s Long-Term Growth Proposition

Remains the Best in the Industry

Transmission

Smart Grid

4

Key Financial Messages

Q2 operating results of $1.03/share driven by:

Exceptional nuclear operations –

93.9% capacity factor

Increased electric distribution rates at ComEd effective September 2008 and gas

distribution revenues at PECO effective January 2009

Reduction in O&M expenses of over $50 million in second quarter reflecting the impact of

Exelon’s cost management initiatives

Reaffirming 2009 operating earnings guidance of $4.00-$4.30/share

95-98% of 2009 expected generation hedged

(1)

On track to keep 2009 operating O&M

(2)

costs flat to 2008 at $4.5 billion

Well-positioned for continued financial strength going forward

Strong

cash

flow

from

operations

(3)

–

forecasted

at

$5.4

billion

for

2009,

an

increase

of

$700 million over original guidance assumptions

Committed

to

an

additional

$350

million

reduction

in

operating

O&M

(2)

expense

in

2010,

a

nearly

3.5%

decline

from

2009

levels

(4)

Refer

to

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

(1) As of June 30, 2009.

(2) Operating O&M excludes Decommissioning impact. ComEd and PECO operating O&M excludes energy efficiency spend recoverable under a rider.

(3) Cash Flow from Operations primarily includes net cash flows provided by operating activities (excluding counterparty collateral activity) and net cash flows used in

investing activities other than capital expenditures.

(4)

Exelon projects a nearly 3.5% decrease in year-over-year O&M spending, from approximately $4.5 billion in 2009 to $4.35 billion in 2010. These reductions represent

over $350 million of O&M savings in 2010, as Exelon anticipated a 4% increase in O&M absent these actions.

Note: Information contained on this slide is rounded.

5

$1.01

$0.09

$0.82

$0.11

$0.05

$0.13

2008

2009

Operating EPS

$1.74

$0.23

$1.74

$0.28

$0.12

$0.31

2008

2009

HoldCo/Other

ExGen

PECO

ComEd

2

nd

Quarter (Q2)

(1)

As expected, second quarter results were driven by higher quarter-over-quarter earnings at

ComEd and PECO, offset by lower operating earnings at Exelon Generation

(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.

$1.13

$0.99

GAAP EPS

Year-to-Date (YTD)

(1)

$2.24

$2.06

$2.01

$2.07

$1.03

$1.13

6

Exelon Generation                         

Operating EPS Contribution

2009

2008

Key Drivers –

Q2 ’09 vs. Q2 ’08

(1)

‘08

Proprietary

trading

gains:

($0.07)

‘08 Uranium contract settlement:

($0.04)

Unfavorable portfolio/market

conditions:

($0.02)

Higher

nuclear

fuel

costs:

($0.02)

Higher O&M primarily due to pension

and OPEB expense and inflation

partially offset by cost savings

initiatives:

($0.01)

Income taxes:

($0.01)

(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. 

57

40

Refueling

21

3

Non-refueling

Q2 2009

Q2 2008

Outage

Days

(2)

2Q

YTD

$1.01

$0.82

$1.74

$1.74

7

Key Drivers –

Q2 ’09 vs. Q2 ’08

(1)

Higher electric distribution rates:

+$0.06

Lower O&M due to cost savings

initiatives and decreased storm costs

partially offset by higher pension and

OPEB expense and inflation:

$0.02

Reduced load:

($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

2009

2008

2Q

YTD

$0.05

$0.13

$0.31

$0.12

8

PECO Operating EPS Contribution

Key Drivers –

Q2 ’09 vs. Q2 ’08

(1)

Lower bad debt expense:

+$0.05

Higher distribution revenues

(2)

:

+$0.03

Competitive Transition Charge (CTC)

amortization:

($0.02)

Reduced load:

($0.02)

Weather:

($0.02)

2009

2008

(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) Includes the impact of higher gas distribution rates effective January 2009 of $0.01.

2Q

YTD

$0.09

$0.11

$0.28

$0.23

9

ComEd Load Trends

Weather-Normalized Load

Customer Usage by Revenue Class

Key Economic Indicators

Top 380 Customer Usage by Segment

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

Chicago

U.S.

Unemployment rate

(1)

10.6%  

9.5%

Q2 2009 annualized growth in

gross domestic/metro product

(2)

(3.5)%           (1.8)%

4/09 Home price index

(3)

(18.7)%          (18.1)%

(1)  Source: Illinois Dept. of Employment Security and U.S. Dept. of Labor

(July 2009 reports)

(2)

Source: Moody’s Economy.com

(3)

Source: S&P Case-Shiller Index

(4)

Adjusted for leap year impact

(5)

Not adjusted for leap year impact

Q1 2009

(4)

Q2

2009    

2009E

(5)

Customer Growth

(0.2)%

(0.4)%       (0.4)%

Average Use-Per-Customer

(1.0)%

(0.9)%

(1.0)%

Total Residential

(1.2)%

(1.3)%       (1.4)%

Small C&I

(1.3)%

(3.7)%       (2.0)%

Large C&I

(5.3)%

(7.5)%       (5.9)%

All Customer Classes

(2.5)%

(4.1)%       (3.0)%

Note: C&I = Commercial & Industrial

10

PECO Load Trends

Other

2%

Other Large

C&I

21%

150 Large

C&I

21%

Small C&I

22%

Residential

34%

Weather-Normalized Electric Load

Q1

2009

(3)

Q2

2009   

2009E

(4)

Customer Growth

0.1%

(0.3)%

0.1%

Average Use-Per-Customer

0.1%

(1.7)%

(0.5)%

Total Residential

0.2%           (2.0)%

(0.4)%

Small C&I

0.0%           (0.7)%

(1.1)%

Large C&I

(3.3)%           (4.0)%      (3.5)%

All Customer Classes

(1.1)%           (2.6)%

(1.8)%

Customer Usage by Revenue Class

Philadelphia

U.S.

Unemployment rate

(1)

8.4%                   9.5%

Q2 2009 annualized growth in

gross domestic/metro product

(2)

(2.8)%                (1.8)%

Key Economic Indicators

Top 150 Customer Usage by Segment

18%

Health & Educational Services

19%

Manufacturing

21%

Petroleum

3%

Retail Trade

4%

Other

9%

Transportation, Communication

& Utilities

13%

Finance, Insurance & Real

Estate

13%

Pharmaceuticals

(1)  Source: Moody's Economy.com (June 2009) and U.S Dept. of Labor (July

2009)

(2)  Source: Moody’s Economy.com

(3)  Adjusted for leap year impact

(4)  Not adjusted for leap year impact

11

(1)

Represents

an

approximate

range

of

expected

gross

margin,

taking

into

account

hedges

in

place,

between

the

5th

and

95th

percent

confidence

levels.

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

2010

and

2011

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,

2009.

(2)

Percent

of

expected

generation

hedged

represents

how

many

equivalent

MW

have

been

hedged

at

forward

market

prices

as

of

June

30,

2009;

all

hedge

products

used

are

converted

to

an

equivalent

average

MW

volume

and

the

calculation

considers

whether

hedges

are

power

sales

or

financial

products.

Hedging Update

The primary objective of Exelon’s hedging program is to manage market risks and protect

the value of our generation and our investment-grade balance sheet while preserving our

ability to participate in improving long-term market fundamentals

•

We typically follow a 36-month ratable

hedging program.

•

As we execute our hedging program, our

percent of expected generation hedged

increases and our potential range of

earnings outcomes narrows as we move

closer to the delivery year

2009

2010

2011

Percentage of Expected

Generation Hedged

(2)

95-98%

87-90%

59-62%

Midwest

96-99

87-90

63-66

Mid-Atlantic

95-98

91-94

56-59

South

90-93

68-71

34-37

•

For 2011, we are above our targeted

hedge ratio primarily due to additional

natural gas and power put options within

the portfolio.

•

Put options allow us to reduce market risk

while preserving upside potential

95% case

5% case

$6,700

$6,500

$6,100

$6,700

$6,100

$8,400

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

12

2009 Operating Earnings Guidance

2009E

2008A

$0.49

$3.46

$4.20

ComEd

PECO

Exelon

Generation

ComEd distribution revenue

PECO gas revenue

O&M and other

Pension/OPEB

Inflation

Cost reduction initiatives

Bad debt expense

Nuclear fuel costs

Depreciation and amortization

PECO CTC

2009 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.33

Exelon

$4.00 -

$4.30

(1)

$0.45 -

$0.55

$0.45 -

$0.55

$3.10 -

$3.35

(1)

Adjusted

(non-GAAP)

Operating

Earnings

Guidance.

Excludes

the

earnings

impact

of

certain

items

as

disclosed

in

the

Appendix.

Note:

A

=

Actual;

E

=

Estimate

Reaffirming

2009

operating

earnings

guidance

of

$4.00-$4.30/share

(1)

–

expect third quarter 2009 results between $0.90

to $1.00/share

13

Cost Management

Exelon remains committed to holding 2009 O&M spending flat to 2008, which includes realizing

$150 million of cost savings this year

•

Year-to-date Exelon has realized $68 million of cost savings across the company, or 45% of our 2009

commitment

•

100% of our remaining 2009 commitment has been identified

Exelon

also

announced

spending

cuts

which

will

save

$350

million

in

2010

from

original

planning

assumptions,

resulting

in

a

nearly

3.5%

reduction

in

total

spending

from

2009

levels

(1)

•

Clearly defining our governance and oversight structure and streamlining corporate functions will result in

the elimination of 400 positions across Exelon. Separately, and continuing its efforts to enhance operating

efficiencies, ComEd will eliminate 100 management level positions

•

Additional

costs

savings

will

be

achieved

through

changes

to

the

company’s

compensation

program and

other reductions in spending across each operating company 

•

Exelon expects that half of the total O&M savings in 2010, or $175 million, will be sustainable

Exelon is responding to today’s challenging environment by driving productivity and cost

reductions while maintaining superior operations

$4,500

$700

$1,050

$2,750

2009E

$4,350

$4,500

Exelon Consolidated

(3)

$700

$750

PECO

$1,000

$1,100

ComEd

$2,700

$2,700

Exelon Generation

2010E

2008A

O&M Expense

(2)

(in millions)

(1)  Exelon projects a nearly 3.5% decrease in year-over-year O&M spending, from approximately $4.5 billion in 2009 to $4.35 billion in 2010. These reductions represent

over $350 million of O&M savings in 2010, as Exelon anticipated a 4% increase in O&M absent these actions.

(2)  Reflects

operating

O&M

data

and

excludes

Decommissioning

impact.

ComEd

and

PECO

operating

O&M

exclude

energy

efficiency

spend

recoverable

under

a

rider.

(3)  Exelon Consolidated includes operating O&M expense from Holding Company.

(4)  Reflects ~$175

million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense.

Note: Information contained on this slide is rounded.

(4)

14

Appendix

15

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

Project plan includes off-ramps to defer or cancel as needed. 

MW Recovery and Component  Upgrades are the replacement of major components in the plant that occur in the normal life cycle process – with

newer  technology, replacements result in increased efficiency. Equipment includes generators, turbines, motors and transformers. MW Recovery

and Component Upgrades must conform to NRC standards, but do not require additional NRC approval.

MUR (Measurement Uncertainty Recapture). Through the use of advanced techniques and more precise instrumentation, reactor power can be

more accurately calculated. These uprates achieve up to 1.7 percent additional output. MUR uprates require NRC approval.

EPU (Extended Power Uprate). Through a combination of more sophisticated analysis and upgrades to plant equipment, uprates can be obtained

for as much as 20 percent of original licensed power level. EPU uprates require NRC approval.

Exelon Nuclear Uprate

Plan

Year Uprates

Become Operational

•

Incremental 1,300 –

1,500 MWs

of nuclear uprates

are safe, economical and proven methods to

improve efficiency and output

•

Exelon has substantial experience managing successful uprate

projects with 1,100 MWs

of

increased nuclear capacity over the past 10 years

•

Exelon’s $2,200 –

2,500 / kW overnight cost for its uprate

projects is better value than the cost for a

nuclear new build that has been estimated as high as $4,500 / kW

(2007 dollars)

Exelon’s Uprate

Plan

(2)

EPUs

(5)

MURs

(4)

MW Recovery and         

Component Upgrades

(3)

Maximum                        

Potential MWs

0

200

400

600

800

1000

1200

1400

1600

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

1,100 MWs

1,300 –

1,500  MW

Average Overnight Cost

Estimate: $2,200 -

2,500/KW

Planned Capital

Spend

(1)

($ millions)

$150

2017

$625

2013

$675

2012

$550

2011

$350

2010

$725

2015

$725

2014

$400

2016

$4,425

2008 -

2017

$225

2008 -

2009                                           

Note: Information contained on this slide is rounded.

(1)

(2)

(3)

(5)

(4)

16

16

Reliability Pricing Model Auction

PJM RPM Auction ($/MW-day)

(1) 

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

(2) 

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

(3) 

EMAAC and MAAC obligation consists of load obligations from PECO. PECO PPA

expires December 2010.

(4)

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

(5)

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

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

2009/2010

2010/2011

2011/2012

2012/2013

in MW

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Capacity

(2)

RTO

12,800

3,800 -

4,100

(4)

12,800

23,200

12,100

EMAAC

9,800

9,300 -

9,400

(3)

9,500

MAAC + APS

1,500

MAAC

11,100

9,300 -

9,400

(3)

1,500

40.80

197.67

148.80

111.92

191.32

191.32

102.04

174.29

174.29

110.00

110.00

110.00

133.37

139.73

16.46

RTO

Eastern MAAC

        MAAC + APS

MAAC

2007/2008

2008/2009

2009/2010

2010/2011

2011/2012

2012-2013

(5)

Note: Information contained on this slide is rounded.

17

Illinois Power Agency RFP Procurement

•

On May 1, 2009, the Illinois Commerce Commission approved the bids from the RFP

Procurement held on April 29, 2009, for the remaining ComEd 2009-2010 load (~29% of the

total) and a portion of its 2010-2011 load (~8% of the total)

–

Contracts were awarded to 10 successful bidders

–

$33.23 average ATC price for 2009-2010 planning year, in addition to:

•

Financial

Swap

price

(ATC

baseload

energy

only)

of

$49.04

for

June

2009

–

December

2009

and

$50.15

for

January 2010 –

May 2010,

•

Auction clearing price of $63.33

(1)

(fixed price contract, which includes energy, ancillary, load shape, etc.)

NOTE: Chart is for illustrative purposes only.  Information on this slide is rounded

Jun

2007

Jun

2008

Jun

2009

Jun

2010

Jun

2011

Jun

2012

Jun

2013

Future Procurement by

Illinois Power Agency

Auction

Contracts

Financial

Swap

4/09

RFP

2010

2010

2011

2012

2011

Volumes secured in 2009 IPA

Procurement Event (GWh)

Off-Peak

Peak

Contract Period

2,461

7,673

983

June 2010 –

May 2011

5,712

June 2009 –

May 2010

The procurement event included monthly peak and

off-peak standard wholesale block energy products

(in 50 MW blocks) to be delivered to NiHub

4/09

RFP

3/08

RFP

Next RFP to be held in Spring 2010

(1)

CPP

B

-41-Month

Auction

Product

for

period

Jan.

1,

2007

–

May

31,

2010.

18

PECO Procurement Results

With a successful residential procurement in June, PECO has made

progress toward

purchasing the power needed to serve customers beginning in 2011

On June 17, 2009, the PAPUC approved the bids from the RFP held on June 15, 2009, which

included

21%

of

PECO’s

residential

default

service

load

for

2011

and

a

portion

of

its

load

obligation for 2012 and 2013

Contracts were awarded to two bidders out of eleven total bidders

RFP

for

full

requirements

(1)

resulted

in

average

wholesale

price

of

$88.61($/MWh)

Based on the results of its initial RFP, PECO estimates the average residential bill would increase by 9%              

beginning Jan.1, 2011

(1) Full requirements product includes load following energy, capacity, ancillary transmission services and Alternative Energy Portfolio Standard requirements.

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

Residential

23% of planned full requirements

contracts (17 and 29-mo terms)

40MW of baseload (24x7) energy

block products (12-mo duration)

Small Commercial

24% of planned full requirements

contracts (17-mo term)

Medium Commercial & Industrial

16% of planned full requirements

contracts (17-mo term)

85% full requirements

15% full requirements spot

Medium Commercial &

Industrial

(peak demand >100 kW

but <= 500 kW)

100% full requirements spot

Large Commercial &

Industrial

(peak demand >500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% energy block

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

Residential

26% of planned full requirements   

contracts

•

17 month (Jan 2011 –

May 2012)

•

29 month (Jan 2011-

May 2013)

40MW of baseload (24x7) energy

block products

•

12 month (Jan 2011-

Dec 2011)

PECO

Procurement

Plan

(2)

Fall 2009 RFP

Spring 2009 RFP

19

5.03

5.03

0.51

0.51

6.26

2.57

10.13

PECO Average Residential Electric Rates

(1)

Average of PECO’s residential rates

(2)

Provided for illustration only.  Only represents 21% of PECO’s residential procurement for 2011.

(3)

Average wholesale price for full requirements products.

2011

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

14.37¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~9%

15.67¢

Assumptions

Illustrative Rate Increase Based on

Average PECO Residential Full-

Requirements Procurement Results

(2)

•

2011 illustrative residential rate based on

Spring 2009 RFP full requirements

product prices

•

2011 default service residential rate will

reflect associated full requirements costs,

block energy costs, and spot market

purchases, all of which will be acquired

through multiple procurements

•

Rates will vary by customer class

•

Retail rate components include line losses

and gross receipts taxes

Residential

Spring 2009

$88.61 / MWH

PECO Procurement Results

(3)

Impact of Spring 2009 Procurement

20

$0

$20

$40

$60

$80

$100

$120

PA Gross Receipts Tax (5.90%)

Distribution Losses (7.35%)

Full Requirements Cost

PJM Whub ATC Forward Energy Price

Average PECO Full Requirements

Residential Price

$101.30/MWh

(2)

$31.00 -

$32.00

$56.00 -

$57.00

Full Requirements Costs ($/MWh)

Average Full-Requirements                          

Retail

Sales

Price

(1)

Load Shape &

Ancillary Services

$9.00

Capacity

$12.00

Transmission &

Congestion

$8.00 -

$9.00

Renewable

Energy

Credits

$1.00

Migration &

Volumetric

Risk & Other

$1.00

~$7.00

~$6.00

(1)   Term of sale is January 1, 2011 to May 31, 2013.

(2)

On

June

17,

2009

Generation

disclosed

an

estimated

retail

price

of

$100-102/MWh.

On

July

15,

2009

PECO

disclosed

an

average

full-requirements

retail

sales

price

of

$101.30/MWh

for

its Spring 2009 RFP (i.e., inclusive of Pennsylvania Gross Receipts Tax and adjustment for PECO distribution losses, but not Network Transmission Service).

(3)    On July 15, 2009 the Independent Evaluator (NERA) announced an average wholesale winning bid price of $88.61/MWh for PECO’s Spring 2009 RFP (reflecting residential full-

requirements products only with delivery beginning January 1, 2011). 

(1)   Term of sale is January 1, 2011 to May 31, 2013.

(2)

On

June

17,

2009

Generation

disclosed

an

estimated

retail

price

of

$100-102/MWh.

On

July

15,

2009

PECO

disclosed

an

average

full-requirements

retail

sales

price

of

$101.30/MWh

for

its Spring 2009 RFP (i.e., inclusive of Pennsylvania Gross Receipts Tax and adjustment for PECO distribution losses, but not Network Transmission Service).

(3)    On July 15, 2009 the Independent Evaluator (NERA) announced an average wholesale winning bid price of $88.61/MWh for PECO’s Spring 2009 RFP (reflecting residential full-

requirements products only with delivery beginning January 1, 2011). 

Average

Wholesale

Energy Price

(3)

$88.61

21

Q2 07

Q2 08

Q2 09

ComEd and PECO Accounts Receivable

>60 days

31-60 days

0-30 days

ComEd Accounts

Receivable

(1)

Through the second quarter of 2009, ComEd has experienced only slight deterioration in

its accounts receivable aging; PECO has experienced some improvement

% of AR

Q2 07

Q2 08

Q2 09

PECO Accounts

Receivable

(1)

% of AR

$781M

$768M

$755M

$761M

$827M

$740M

(1)   Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and long-term receivables at PECO.

>60 days

31-60 days

0-30 days

Note: Information contained on this slide is rounded.

22

2009 Projected Sources and Uses of Cash

5,450

3,300

950

1,200

Cash Flow from Operations

(1)

(100)

0

250

(50)

Other

(600)

0

(250)

(50)

Net Financing (excluding Dividend):

(2)

250

0

250

0

Planned Debt Issuances

(3)(4)

Net Financing (excluding Dividend):

(2)

(750)

0

(750)

0

Planned Debt Retirements

(5)

$500

$400

$50

$50

Beginning Cash Balance

(3,400)

(2,050)

(400)

(875)

Capital Expenditures

$1,950

$1,650

$350

$325

Cash Available before Dividend

(1,400)

Dividend

(6)

$550

Cash Available after Dividend

Exelon

(7)

($ in Millions)

(1)

Cash

Flow

from

Operations

primarily

includes

net

cash

flows

provided

by

operating

activities

(excluding

counterparty

collateral

activity)

and

net

cash

flows

used

in

investing

activities

other

than

capital

expenditures.

PECO

Cash

Flow

from

Operations

includes

$500M

for

Competitive

Transition

Charges.

(2)

Net

Financing

(excluding

Dividend)

=

Net

cash

flows

used

in

financing

activities

excluding

dividends

paid

on

common

and

preferred

stock.

(3)

Excludes

Exelon

Generation

and

ComEd

tax-exempt

bonds

that

are

backed

by

letters

of

credit

(LOCs).

ComEd

reissued

$191M

of

tax

exempt

debt

in

May

backed

by

LOCs.

Generation

plans

to

remarket

their

bonds

into

a

different

interest

rate

mode

and

refinance

with

new

tax-exempt

bonds,

both

not

expected

to

utilize

credit

enhancement

(4)

Excludes

PECO’s

Accounts

Receivable

Agreement

with

Bank

of

Tokyo.

Assumes

PECO’s

A/R

Agreement

is

extended

in

accordance

with

its

terms

beyond

September

18,

2009.

(5)

Planned

Debt

Retirements

are

$17M,

$721M,

and

$12M

for

ComEd,

PECO,

and

ExGen,

respectively.

Includes

securitized

debt.

(6)

Assumes

2009

Dividend

of

$2.10

per

share.

Dividends

are

subject

to

declaration

by

the

board

of

directors.

(7)

Includes

cash

flow

activity

from

Holding

Company,

eliminations,

and

other

corporate

entities.

Note: Information contained on this slide is rounded.

23

Sufficient Liquidity

(1)  Excludes previous commitment from Lehman Brothers Bank.

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

(0)

--

--

--

Outstanding Facility Draws

(513)

(160)

(10)

(337)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,804

4,674

564

615

Available

Capacity

Under

Facilities

(2)

(0)

--

--

--

Outstanding Commercial Paper

$6,804

$4,674

$564

$615

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ in Millions)

Exelon has no commercial paper outstanding and its bank facilities are largely untapped

Available Capacity Under Bank Facilities as of July 17, 2009

24

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)

Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits

(OPEB) obligations, capital adequacy for energy trading, operating lease obligations, and other off-balance sheet debt.  Debt is imputed for estimated pension and OPEB

obligations by operating company.

(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 23, 2009. On July 21, 2009, 

following the termination of Exelon’s offer to acquire NRG, Fitch removed Exelon and Exelon Generation from Rating Watch Negative and assigned their rating’s 

outlook as stable.  On July 22, 2009, S&P removed Exelon, ComEd, PECO and Exelon Generation rating’s outlook from CreditWatch with negative  implications to

stable for all entities. On July 23, 2009, Moody’s confirmed the ratings of Exelon and Exelon Generation and assigned their rating outlook as stable. Moody’s also confirmed

PECO’s long-term debt rating but changed the outlook to negative.

Projected 2009 Key Credit Measures

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa2

Baa1

Moody’s Credit

Ratings

(3)

4.3x

4.3x

FFO / Interest

ComEd:

21%

16%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

3.4x

3.3x

FFO / Interest

PECO:

15%

12%

FFO / Debt

48%

53%

Rating Agency Debt Ratio

25%

47%

Rating Agency Debt Ratio

128%

51%

FFO / Debt

31.2x

11.2x

FFO / Interest

Exelon

Generation:

50%

36%

7.4x

Without PPA &

Pension / OPEB

(2)

61%

Rating Agency Debt Ratio

25%

FFO / Debt

6.0x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

25

FFO Calculation and Ratios

FFO

Calculation

= FFO

-

PECO Transition Bond Principal Paydown

+

Gain

on

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

+

Depreciation,

amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ 7% of Present Value (PV) of Operating Leases

+ Interest on imputed debt related to PV of Purchased Power Agreements

(PPA), unfunded Pension and Other Postretirement Benefits (OPEB)

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

,

as

applicable

-

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

FFO Interest Coverage

+

Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

+

100%

of

PV

of

Purchased

Power

Agreements

(2)

+

Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted

Debt

(1)

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

Note: Reflects S&P guidelines and company forecast.  FFO and Debt related to non-recourse debt are excluded from the calculations.

(1)

Uses current year-end adjusted debt balance.

(2)

Includes debt equivalents for A/R Financings, operating lease obligations, imputed debt related to PV of PPAs, underfunded Pension and OPEB obligations, and Capital

Adequacy for Energy Trading.

(3)

Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions.

26

Q2 GAAP EPS Reconciliation

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.

(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

Q2 2009 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

$1.13

-

$0.09

$0.05

$0.99

Q2 2008 GAAP Earnings Per Share

$1.13

$(0.02)

$0.09

$0.05

$1.01

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.07)

-

-

-

(0.07)

2007 Illinois Electric Rate Settlement

0.09

0.02

-

-

0.07

Mark-to-market adjustments from economic hedging activities

(0.02)

-

-

-

(0.02)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended June 30, 2008

27

YTD GAAP EPS Reconciliation

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.

$2.01

$0.01

$0.23

$0.12

$1.65

YTD 2008 GAAP Earnings Per Share

2.06

$(0.03)

$0.23

$0.12

$1.74

2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.14)

-

-

-

(0.14)

2007 Illinois Electric Rate Settlement

0.17

0.04

-

-

0.13

Mark-to-market adjustments from economic hedging activities

(0.08)

-

-

-

(0.08)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Six Months Ended June 30, 2008

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

(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

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and reassessment of

state deferred income taxes

$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

28

2009 Earnings Outlook

•

Exelon’s 2009 adjusted (non-GAAP) operating earnings

outlook excludes the earnings impacts of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments

primarily related to the Clinton, Oyster Creek, and Three Mile Island nuclear plants (the

former AmerGen Energy Company, LLC units)

•

Any significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement,

including

ComEd’s previously announced customer rate relief programs

•

Costs associated with ComEd’s 2007 settlement with the City of Chicago

•

Costs incurred for employee severance related to the cost reduction program announced in

June 2009

•

Certain costs associated with the proposed offer to acquire NRG Energy, Inc.

•

Non-cash remeasurement of income tax uncertainties and reassessment of state deferred

income taxes

•

Other unusual items

•

Significant future changes to GAAP

•

Operating earnings guidance assumes normal weather for the remainder

of the year

29

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, 2009. Exelon plans to update these

hedging disclosures 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.

30

30

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

By design, our hedging program allows us to weather short-term, adverse market conditions 

while positioning us to participate in long-term upside potential

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

31

31

31

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

32

32

32

2009

2010

2011

Estimated

Open

Gross

Margin

(millions)

(1,2)

$5,100

$6,000

$6,150

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)

$4.26

$29.42

$40.30

($0.09)

$6.06

$33.38

$48.64

($2.17)

$6.89

$35.12

$52.21

($0.77)

(1)

Based on June 30, 2009 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 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

33

33

33

(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 2009 and 2010 and 11 refueling outages in 2011 at Exelon-operated nuclear plants and Salem.  Expected generation assumes

capacity factors of 93.6%, 92.8% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 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.

(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.

2009

2010

2011

Expected Generation

(GWh)

(1)

169,800

165,500

164,700

Midwest

99,600

97,700

97,700

Mid-Atlantic

57,500

58,500

58,100

South

12,700

9,300

8,900

Percentage of Expected Generation Hedged

(2)

95-98%

87-90%

59-62%

Midwest

96-99

87-90

63-66

Mid-Atlantic

95-98

91-94

56-59

South

90-93

68-71

34-37

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$47.00

$46.75

$45.00

Mid-Atlantic

$36.25

$34.50

$62.00

ERCOT North ATC Spark Spread

$5.25

$3.50

$4.75

Generation Profile

34

34

34

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%

2009

$8

$0

$6

($3)

$8

($2)

+/-$20

2010

$40

($30)

$55

($50)

$25

($20)

+/-$50

2011

$280

($240)

$205

($195)

$170

($165)

+/-$55

(1)

Based on June 30, 2009 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.

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

35

35

35

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

(1)

Represents

an

approximate

range

of

expected

gross

margin,

taking

into

account

hedges

in

place,

between

the

5th

and

95th

percent

confidence

levels.

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 2010 and 2011 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,

2009.

95% case

5% case

$6,700

$6,500

$6,100

$6,700

$6,100

$8,400

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

36

36

36

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$5.10 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,600GWh * 97% *

($47.00/MWh-$29.42/MWh)

= $1.70 billion

57,500GWh * 96% *

($36.25/MWh-$40.30/MWh)

= ($0.22 billion)

12,700GWh * 91% *

($5.25/MWh-($0.09)/MWh)

= $0.06 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.10 billion

MTM value of energy hedges:              $1.70

billion

+

($0.22

billion)

+

$0.06

billion

Estimated hedged gross margin:          $6.64 billion

Illustrative Example

of Modeling Exelon Generation 2009 Gross Margin

(with Existing Hedges)

37

37

50

60

70

80

90

100

110

120

130

140

150

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

20

30

40

50

60

70

80

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

35

45

55

65

75

85

95

105

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

5.5

6.5

7.5

8.5

9.5

10.5

11.5

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

37

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2010

2011

Rolling 12 months, as of July 17, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

$5.81

$6.59

2010

2011

$54.96

$65.90

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

$53.90

$59.30

$40.45

$24.48

$39.48

$22.81

$42.75

$37.43

38

38

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

14.5

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

45

50

55

60

65

70

75

80

85

90

95

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

5

6

7

8

9

10

11

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

38

Market Price Snapshot

2011

2010

2010

2011

2010

2011

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2010

2011

ERCOT North On Peak Spark Spread

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

$5.54

$6.34

$55.31

$47.77

$8.62

$8.73

$5.28

$7.10

Rolling 12 months, as of July 17, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.