Commonwealth Edison 8-K Edison Electric Institute Financial Conference

John W. Rowe, Chairman and CEO

Edison Electric Institute Financial Conference

November 2-3, 2009

Positioned for Sustained Value

Exhibit 99.1

2

Forward-Looking Statements

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

Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The

factors that could cause actual results to differ materially from these forward-looking

statements include those discussed herein as well as those discussed in (1) Exelon’s 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 Third Quarter 2009

Quarterly Report on Form 10-Q 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 appendix to this presentation for

a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings and non-

GAAP cash flows to GAAP cash flows.

3

Protect Today’s Value

•

Deliver superior operating

performance

•

Advance competitive markets

•

Exercise financial discipline and

maintain financial flexibility

•

Build healthy, self-sustaining delivery

companies

Grow Long-Term Value

•

Drive the organization to the next

level of performance

•

Adapt and advance Exelon 2020

•

Rigorously evaluate and pursue new

growth opportunities in clean

technologies and transmission

•

Build the premier, enduring

competitive generation company

+

Exelon’s Strategic Direction

Exelon

remains

focused

on

preserving

and

creating

shareholder

value

4

75%

80%

85%

90%

95%

Range

5 Year Average

Delivering High-Performing Operating

Results

•

CAIDI:

(1)

1

st

quartile performance

–

YTD performance is the best on record

•

SAIFI:

(1)

1

st

quartile performance

–

YTD performance is the best on record

•

Targeting earned ROEs of ~8% in

2009, 9-10% in 2010

Nuclear

Capacity

Factor

Exelon

Power

Fleet

Availability

93.8%

90.7%

93.5%

91.2%

89.1%

94.1%

92.9%

93.8%

94.8%

95.8%

96.8%

80%

85%

90%

95%

100%

2005

2006

2007

2008

2009 YTD

through 9/30

Fossil Fleet Commercial Availability

Hydro Equivalent Availability

•

CAIDI:

(1)

1

st

quartile performance

•

SAIFI:

(1)

1

st

quartile performance

–

Improving trend since 2002

•

Targeting earned ROEs > 11% in 2009-

2010, 9-11% starting in 2011, post

transition to market-based electric prices

94.9% -

EXC YTD through September 30, 2009

Operator (# of reactors as of 2008)

(1) CAIDI (Customer Average Interruption Duration Index) and SAIFI (System Average Interruption Frequency Index) quartile data is as of 2008, using IEEE 2.5 Beta method.

5

2008A

2009E

2010 (Original Est)

2010 (Revised Est)

Announcing 2010 Guidance…

And Maintaining Financial Commitments

Streamlined

O&M

Expenses

(1)

(1) Reflects operating O&M data and excludes Decommissioning effect. ComEd and

PECO operating O&M exclude energy efficiency spend recoverable under a rider.

(1)   Operating Earnings Guidance. Excludes the earnings

effect of certain items as disclosed in the Appendix.

2010 Operating EPS Guidance

(1)

•

Generating 2010 cash flow from

operations of $4.5 billion

•

Maintaining annual dividend of

$2.10/share

$2.55 -

$2.80

$3.60 -

$4.00

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$0.60 -

$0.70

$0.40 -

$0.50

$4.4B

$4.5B

$4.35B

$4.7B

0%

20%

40%

60%

80%

100%

2010

2011

2012

Exelon

Midwest

Mid-Atlantic

South

Executing on 36-month Ratable Hedging Program

6

$440

$280

$155

2009E

2010E

2011E

Enhancing Financial Flexibility

Lowered Cost of Debt

Increased Future Cash Flexibility

•

$350 million contribution reduced estimated

2011 required contribution by over $1 billion

•

Reduced present value of contributions over

10 years by $300 million

•

Elected smoothing, which lowers volatility of

future contributions

•

Executed $1.5 billion tender/make

whole and refinancing

•

Expect ~$12 million in annual

interest savings

•

Extends average maturity by 6.6 yrs

$ millions

Note:  Chart reflects peers issuing Holding company and Generation company debt.

Estimated Pension Contributions

ETR

AYE

PEG

FPL

EXC

Prior

PPL

EXC

Current

4%

5%

6%

7%

8%

0.0

2.0

6.0

8.0

10.0

12.0

14.0

Average Tenor (Yrs)

4.0

16.0

CEG

EIX

FE

7

•

Focus: leverage our core

competencies

•

Vision: pursue long-term

value, analyzing

opportunities across

multiple scenarios

•

Discipline: invest only in

projects / opportunities that

create long-term value

Exelon’s asset base, scope and operating excellence uniquely position us to pursue

value-enhancing opportunities

Creating Consistent Value for Shareholders

Exelon’s Value Creation

Philosophy…

...Has Consistently Yielded Returns in

Excess of Our Peers

Three-year Average of ROIC less WACC

Source: Company filings, Wall Street research and Exelon estimates.  Peer group includes AYE, CEG, EIX, ETR, FE, FPL, PPL and PSEG.

6%

3%

EXC

Peer Group

8

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

-

Approximately $725 million in investments to build smart grid

infrastructure over the coming years with a regulated return on

investment

-

Lowest carbon intensity in the sector, greatest upside when

legislation enacted and enhancing industry-leading position

with Exelon 2020

-

Positioned to benefit from our fundamental view of recovery in

natural gas and coal prices, heat rates, and demand growth

-

Leveraging transmission expertise to create Exelon

Transmission Company with the goal of improving reliability,

reducing congestion and moving renewable energy to

population centers

Deploying Capital for Shareholder Value

Smart Grid

Carbon

Price

Recovery

Transmission

9

Positioning for Market Recovery

•

Wind: Only 3 GW of wind will

come on line by 2012, less

than $1/MWh price impact

•

Transmission: Constraints in

the Midwest will be reduced

Our View

•

Employing flexibility within our

hedging program

•

Evaluating needed upgrades of

the existing system to reduce

constraints and improve power

flow

•

Pursuing bilateral contracts, such

as the recently announced 10-

year contract with ODEC

•

NiHub forward ATC is 16% below

historical spot prices which is

inconsistent with movements in key

price drivers:

(1)

–

Chicago gas ($/MMBtu)  +2%

–

PRB coal ($/ton)             +6%

–

ComEd load                 +0.8%

Positioned to Benefit

Current Midwest Price Curve

Midwest power markets

have upside…2012

gross margin increases

by ~$300 million for

each $5/MWh increase

in NiHub ATC

(1)

Reflects premium/(discount) of 2007-2009 average as compared to 2010-2012 average forward prices as of September 30, 2009.  Reflects ComEd’s load growth estimate in 2010.

30

35

40

45

50

55

2010

2011

2012

2013

2014

9/30/09 Forward Prices

NiHub ATC Prices

Current opportunity

Carbon opportunity

assuming a $15/tonne

price and Waxman-

Markey allocations

10

Meeting Industry-Best Exelon 2020

Climate Commitments

Note: Emissions abatement estimates for new generation capacity represents emissions reduced in the market as a result of the project less emissions introduced due to the project (if any).

Executable 2020 plan further enhances industry-leading position in a

carbon constrained world

Reduce or offset Exelon’s GHG emissions

Help our customers reduce their GHG emissions

Offer more low-carbon electricity in the

marketplace

Potential options to reach 2020 goal

Approx.

Total:

7.0-7.5

Additional Internal GHG Reductions

Customer Energy Efficiency Programs

PECO Alternative Energy Credits

MW Recovery & Component Upgrades and

Measurement Uncertainty Recapture Uprates

Renewables

15.7

9.7

6.0

2.3

0.6

1.6

1.5

0.5

4.8

1.0-2.0

1.0

3.5

0.2

-2.5

0.0

2.5

5.0

7.5

10.0

12.5

15.0

17.5

2001 Carbon

Footprint

Reductions

Achieved

through 2008

Remaining

Target

Economic

Projects

Under All

Price

Scenarios

Extended

Power

Uprates

Wind

New Natural

Gas Plants

Retire Coal

Plants

Offsets

11

11

Leading Advocate for Carbon Legislation

12

2010 Financial Outlook and

Operating Data

13

The Exelon Companies

’08 Earnings:

$2,293M 

’08 EPS:

$3.46

Total Debt:

(1)

$3.1B

Credit Rating:

(2)

BBB

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘08 Operating Earnings:

$2.8B

‘08 EPS:

$4.20

Assets:

(1)

$49.5B

Total Debt:

(1)

$13.0B

Credit Rating:

(2)

BBB-

Note: All ’08 income numbers represent adjusted (Non-GAAP) Operating Earnings and EPS. Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(1)

As of September 30, 2009.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of October 23, 2009.

Pennsylvania

Utility

Illinois

Utility

’08 Earnings:

$219M

$325M

’08 EPS:

$0.33

$0.49

Total Debt:

(1)

$5.1B

$3.0B

Credit Ratings:

(2)

A-

A-

14

Multi-Regional, Diverse Company

Note: Owned megawatts based on Generation’s ownership,

using annual mean ratings for nuclear units (excluding Salem)

and summer ratings for Salem and the fossil and hydro units. 

As of September 30, 2009.

Midwest Capacity

Owned:

11,388 MW

Contracted:

3,230 MW

Total:

14,618 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

182 MW

Total Capacity

Owned:

24,809 MW

Contracted:

6,483 MW

Total:

31,292 MW

Electricity Customers:

1.6M

Gas Customers: 

0.5M

Electricity Customers:  3.8M

Generating Plants             

Nuclear

Hydro

Coal/Oil/Gas Base-load

Intermediate

Peaker

Mid-Atlantic Capacity

Owned:

11,017 MW

Contracted:

336 MW

Total:

11,353 MW

15

2010 Operating Earnings Guidance

2010E

2009E

$0.45 -

$0.50

$3.10 -

$3.15

$4.00 -

$4.10

(1)

ComEd

PECO

Exelon

Generation

2010 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.50 -

$0.55

Exelon

$3.60 -

$4.00

(1)

$0.60 -

$0.70

$0.40 -

$0.50

$2.55 -

$2.80

NOTE:  See

“Key

Assumptions”

slide

in

Appendix.

(1)  Operating Earnings Guidance.  Excludes the earnings effect of certain items as disclosed in the Appendix.

Issuing 2010 operating earnings guidance of $3.60

–

$4.00/share

(1)

ComEd

RNF

PECO RNF

Generation RNF

O&M

Cost Savings Initiative

Inflation

Pension/OPEB

Depreciation and amortization

16

Delivering on Cost Savings Commitments

•

Exelon is committed to $350 million of savings in 2010 from original

planning assumptions

–

Half of the total O&M savings in 2010, or $175 million, will be sustainable

–

Reduced positions by 500 (400 in corporate support and 100 at ComEd)

–

Freezing executive salaries and reducing other compensation benefits in 2010

–

2010 estimated O&M spend of $4.35 billion reflects $235 million and $190

million

of

pre-tax

pension

and

OPEB

expense,

respectively

(3)

Exelon is driving productivity and cost reductions while maintaining superior operations

(1)  Reflects operating O&M data and excludes decommissioning effect. ComEd and PECO operating O&M exclude energy efficiency costs recoverable under a rider.

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

(3)  See slides 25 and 26 for additional information regarding potential variability of 2010 pension and OPEB expense.

(4)

2010-2014

O&M

is

expected

to

grow

at

a

compound

annual

growth

rate

of

~3%

for

ComEd,

~4%

for

PECO

and

~5%

for

Exelon

Generation.

Note: Data contained on this slide is rounded.

O&M Expense

(1)

2008A

2009E

2010 (Original Plan)

2010 (Est.)

$4.4B

(2)

$4.5B

(2)

$4.35B

(2)(3)

$4.7B

(2)

$2,700

Exelon Generation

$700

PECO

$1,000

ComEd

2010 O&M ($millions)

(4)

17

Capital Expenditures Expectations

1,975

2,000

1,825

1,950

1,950

775

925

850

1,125

1,150

200

50

375

550

675

50

25

100

150

75

300

300

275

225

200

$0

$750

$1,500

$2,250

$3,000

$3,750

$4,500

2008A

2009E

2010E

2011E

2012E

Base CapEx

Nuclear Fuel

Nuclear Uprates and Solar

Smart Grid

New Business at Utilities

Exelon

$3,125

$3,375

$3,375

$4,050

$4,150

2008A

2009E

2010E

2011E

2012E

Exelon Generation

Base CapEx

875

925

750

900

900

Nuclear Fuel

775

925

850

1,125

1,150

Nuclear Uprates

50

150

350

550

675

Solar

-

50

25

-

-

Total ExGen

1,700

2,050

1,975

2,575

2,725

ComEd

Base CapEx

675

675

625

625

625

Smart Grid/Meter

25

50

50

25

25

New Business

250

150

175

200

225

Total ComEd

950

875

850

850

875

PECO

Base CapEx

350

350

400

400

400

Smart Grid/Meter

-

-

50

125

50

New Business

50

50

50

75

75

Total PECO

400

400

500

600

525

Corporate

75

50

50

25

25

Note: Data contained on this slide is rounded.

$ millions

18

2010 Projected Sources and Uses of Cash

(325)

n/a

(100)

(225)

Utility Growth CapEx

(4)

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$725

Cash Flow from Operations

(1)(2)

1,075

950

2,450

4,475

CapEx (excluding Nuclear Fuel, Nuclear

Uprates and Solar Project, Utility Growth

CapEx)

(625)

(400)

(750)

(1,825)

Nuclear Fuel

n/a

n/a

(850)

(850)

Dividend

(3)

(1,400)

Nuclear Uprates and Solar Project

n/a

n/a

(375)

(375)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5,6)

250

0

300

550

Planned Debt Retirements

(225)

(400)

0

(1,025)

Other

(7)

25

175

0

125

Ending Cash Balance

(1)

$75

(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 $572 million for competitive transition charges.

(3)

Assumes

2010

dividend

of

$2.10

per

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 $213 million and ComEd’s $191 million tax-exempt bonds that are backed by letters of credit (LOCs).  Excludes PECO’s $225 million Accounts Receivable

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

(6)

Exelon

Generation’s

$300

million

financing

includes

a

$50

million

DOE

loan

for

the

City

Solar

Project

and

$250

million

of

debt

to

refinance

a

portion

of

Exelon

Corp’s

$400

million

maturity.

(7)

“Other”

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

(8)

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

19

Committed to Investment Grade Ratings

Exelon

believes

that

solid

investment

grade

ratings

are

critical

for

managing

and

operating both regulated utilities and a commodity-based generation company

Our investment grade rating increases the pool of lenders, provides access to a

broad range of trading counterparties, and enhances our strategic options

Commercial

Business

Opportunities

•

Ability to participate in

or to bid competitively

for PPAs and long-

term transactions

•

Increased liquidity for

energy trading: 

counterparties’

costs

would increase for

non-investment grade

transactions, thereby

reducing market

participation

Manageable

Liquidity

Requirements

•

Lower collateral

requirements for energy

trading

•

Ability to secure sizeable

and sufficient bank credit

facilities (currently $7.3B)

•

Use of guarantees (versus

letters of credit) to fulfill

NRC requirements for

shortfalls in Nuclear

Decommissioning Trust

obligations

Business and

Financial

Flexibility

•

Reliable access to

long-term debt

markets to meet

sizeable capital needs

•

Lower cost and ability

to extend maturity

profile of debt

(Generation’s recent

$1.5B debt offering)

•

Access to commercial

paper market

Efficient

Capital Markets

Access

•

Avoid prepayments on

long-term contracts

(such as uranium),

which reduce working

capital requirements

•

Avoid restrictive bond

covenants and

secured financing

transactions

•

Limits regulatory

friction

20

Credit Ratings and Metrics

0%

10%

20%

30%

40%

50%

2007

2008

2009E

2010E

Exelon

ExGen/Corp

ComEd

PECO

FFO / Debt

(2)

2

4

6

8

10

2007

2008

2009E

2010E

Exelon

ExGen/Corp

ComEd

PECO

FFO / Interest

(2)

(1)

Current senior unsecured ratings for Exelon Corp and Generation and senior secured ratings for ComEd and PECO as of October 23, 2009.

(2)

FFO/Debt metrics include the following standard adjustments:  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.

(3)

Indicated ratings are for Generation, whereas the FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp.

Strong credit metrics for each company

Evaluate the

credit of each

company on a

stand-alone basis

Company

Moody's

(1)

S&P

(1)

Fitch

(1)

FFO/Debt

Target Range

(2)

Exelon Corp

Baa1

BBB-

BBB+

ExGen/Corp

(3)

A3

BBB

BBB+

30-35%

ComEd

Baa1

A-

BBB

15-18%

PECO

A2

A-

A

15-18%

21

21

21

Credit Facility Plans

•

Exelon’s primary sources of short-term liquidity include credit facilities, commercial paper,

the money pool (excluding ComEd) and cash on hand

•

Current total credit facility size is $7.3 billion, the largest in the power sector

•

Large

and

diverse

bank

group

–

23

banks

committed

to

the

facilities

with

each

bank

having less than 10% of the aggregate commitments

•

Recently closed on a $67 million 364-day credit facility with a group of 26 community and

minority-owned banks

Currently do not foresee increased liquidity needs post-2010 from PECO PPA roll-off

Exelon

Corp

+

Exelon

Generation

–

$5.8

billion

facilities

largely

expire

October

26,

2012

-

plan

to

extend/refinance

the

facilities

in

2010-2011 and currently do not foresee increased liquidity needs post-2010 from PECO PPA

roll-off

(1)

–

Continued use of non-margining transactions and currently evaluating alternatives to reduce

reliance on bank credit

ComEd

–

$952 million facility expires on February 16, 2011

–

Plan to extend/refinance the facility in 2010

PECO

–

$574 million facility largely expires on October 26, 2012

–

Plan to extend/refinance the facility in 2010-2011

(1)

Assumes that the Exelon Corp credit facility will be used for Generation’s liquidity needs and the continued use of non-margin transactions.   

22

Sufficient Liquidity

(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.

(35)

--

--

(35)

Outstanding Facility Draws

(409)

(154)

(10)

(241)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate

Bank

Commitments

(1)

6,873

4,680

564

676

Available

Capacity

Under

Facilities

(2)

--

--

--

--

Outstanding Commercial Paper

$6,873

$4,680

$564

$676

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

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

Available Capacity Under Bank Facilities as of October 15, 2009

23

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2009

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

2031

2033

2035

2037

2039

2041

Exelon Corp

Exelon Generation

ComEd

PECO

Debt Maturity Profile

Note: Balances shown exclude securitized debt and includes capital leases.

Recent refinancing of Exelon Generation and Exelon 2011 maturities decreased average cost

of debt, extended average maturities, and reduced refinancing risk

24

Discretionary Pension Contribution

Investing in pension plan with $350 million cash on hand is estimated to

create $1 billion of financial flexibility in 2011

•

Took

advantage

of

federal

relief

provided

by

the

Worker,

Retiree

and

Employer Recovery Act of 2008 by making smoothing election and

contribution in September to impact 2008 plan year

•

Made $350 million discretionary pension contribution with smoothing

election

(1) 

for the 2008 Plan Year.

–

$1 billion reduction in forecasted contribution in 2011

–

Smoothing election reduces present value of estimated future contributions by ~$300M

over the next 10 years compared to status quo

–

Lowers

volatility

in

future

contributions,

as

smoothing

election

uses

24-month

average of

asset returns

•

Evaluated within our Value Return Framework:

–

Funded with $350 million of cash on hand generated in excess of original 2009 plan

–

Increases future financial flexibility with excess cash “today”

(1)  

Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, which allows the use of average

assets, including expected returns (subject to certain limitations) for a 24-month period prior to the measurement date, in the determination of funding requirements.

25

Potential Variability in Future Pension

Expense and Contributions

$155

$3,845

$295

$280

$3,925

$285

6.09% for 2009

5.45% for 2010

5.63% for 2011

20.05% in 2009

8.50% in 2010

8.50% in 2011

B –

Forecast as of September 30

Unfunded

balance

–

end

of

year

$670

$3,400

$280

$115

$3,810

$235

6.09% for 2009

6.81% for 2010

6.91% for 2011

6.55% in 2009

8.50% in 2010

8.50% in 2011

A –

Baseline

Unfunded

balance

–

end

of

year

$140

$2,805

$240

$260

$2,680

$195

6.09% for 2009

7.00% for 2010

7.00% for 2011

8.50% in

2009

15.00% in 2010

8.50% in 2011

C –

Accelerated equity recovery

Unfunded

balance

–

end

of

year

$715

$5,190

$350

$445

$5,700

$315

6.09% for 2009

5.45% for 2010

5.63% for 2011

0% in

2009

0% in 2010

8.50% in 2011

D –

Equity recovery in 2 years

Unfunded

balance

–

end

of

year

Required

contribution (1)

Pre-tax

expense

Required

contribution (1)

Pre-tax

expense

Discount Rate

Actual Asset

Returns

2011

2010

Assumptions

Illustrative Scenario

($ in millions)

(1)

The contributions shown above include estimated pension contributions required under ERISA and the Pension Protection Act of 2006, as well as certain discretionary contributions

necessary to avoid benefit restrictions. Also included within these amounts are expected payments to Exelon’s non-qualified plans of approximately $5 million under Scenario A in both

2010

and

2011,

and

$15

million

and

$5

million

under

Scenarios

B-D

in

2010

and

2011,

respectively.

In

Scenarios

B-D,

contributions

reflect

the

impact

of

electing

the

option

to

smooth

asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, as well as a $350 million contribution discretionary made in the third quarter of 2009.

Note: Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes ~20% overall capitalization rate of pension costs.

2009 Expense:

Exelon estimates pre-tax 2009 pension expense of $210 million and 2009 pension contributions of $440 million.

26

Potential Variability in Future OPEB

Expense and Contributions

$155

$2,535

$235

$155

$2,485

$230

6.09% for 2009

5.45% for 2010

5.63% for 2011

21.15% in 2009

8.50% in 2010

8.50% in 2011

B –

Forecast as of September 30

Unfunded

balance

–

end

of

year

$155

$2,115

$205

$155

$2,050

$190

6.09% for 2009

6.81% for 2010

6.91% for 2011

6.50% in 2009

8.50% in 2010

8.50% in 2011

A –

Baseline

Unfunded

balance

–

end

of

year

$155

$2,065

$190

$155

$1,975

$185

6.09% for 2009

7.00% for 2010

7.00% for 2011

8.50% in

2009

15.00% in 2010

8.50% in 2011

C –

Accelerated equity recovery

Unfunded

balance

–

end

of

year

$155

$2,915

$285

$155

$2,840

$265

6.09% for 2009

5.45% for 2010

5.63% for 2011

0% in

2009

0% in 2010

8.50% in 2011

D –

Equity recovery in 2 years

Unfunded

balance

–

end

of

year

Estimated

contribution (1)

Pre-tax

expense

Estimated

contribution (1)

Pre-tax

expense

Discount Rate

Actual Asset

Returns

2011

2010

Assumptions

Illustrative Scenario

($ in millions)

2009

Expense:

Exelon

estimates

pre-tax

2009

OPEB

expense

of

$210

million

and

2009

OPEB

contributions

of

$155

million.

(1) The contributions shown above are subject to change and include approximately $5 million that is expected to be paid out of corporate assets.

Note: Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes ~20% overall capitalization rate of OPEB costs.

27

Climate Legislation Has 4 Key Components

•

Washington Advocacy:

Exelon’s

lobbyists, and key executives, are

meeting with key senators and staff to

drive toward comprehensive legislation

•

Coalitions:

Working with United States

Climate Action Partnership (USCAP),

Edison Electric Institute, and Clean

Energy Group to advance climate

legislation

•

Grassroots:

Mobilizing our employees,

retirees, and shareholders

•

Media:

Working with a diverse group of

stakeholders on media opportunities in

favor of climate legislation

Exelon Advocacy Efforts

Exelon continues to lead in advancing climate change legislation

Price Collar

Renewables/

Efficiency

Allowances to

LDCs

Cap and Trade

Note:

LDCs

=

Local

Distribution

Companies

28

Source: Ventyx Velocity Suite Database

Bubble size represents carbon

intensity,

expressed

in

terms

of

metric

tons of CO2 per MWh generated

0

50

100

150

50

100

150

200

2008 Gross Generation (TWh)

Exelon

AEP

Southern

Duke

TVA

FPL

Entergy

Dominion

Berkshire

Hathaway

Calpine

NRG

First

Energy

Xcel

Ameren

Progress

250

CO2 Intensity of Large Generators

15

Berkshire Hathaway

0.84

14

Ameren Corp

0.81

13

NRG Energy

0.78

12

AEP

0.77

11

Xcel Energy

0.74

10

Southern

0.69

9

Duke Energy

0.63

8

Progress Energy

0.61

7

TVA

0.60

6

FirstEnergy

0.55

5

Dominion

0.49

4

Calpine

0.39

3

FPL Group

0.33

2

Entergy

0.27

1

Exelon

0.06

(1)  Exelon 2020 is Exelon’s comprehensive plan to reduce, displace or offset 15 million metric tons of greenhouse gas emissions each year by 2020.

Exelon 2020

(1)

will ensure that Exelon maintains and extends its position as

the nation’s top low-carbon power generator

Lowest Carbon Intensity of the

Largest U.S. Generators

CO2 Emissions of Largest US Electricity Generators

29

Value Return Framework

Less

Equals

Maintenance Capital and Committed Dividends

Cash Flow from Operations before Dividends and CapEx

Strengthen Balance Sheet /

Increase Financial Flexibility

Invest in Growth

Available Cash and Balance Sheet Capacity

Return Value via

Share Repurchases,

Additional Dividends

30

Focusing on the Transmission Grid

Across Exelon

ComEd and PECO

•

Continued transmission

investments focused in their

service territories as

required for reliability

Exelon

Transmission

Company

•

Evaluating needed

upgrades of the existing

system to reduce

constraints and improve

power flow from our assets

•

Projects would include

short-term modifications to

existing infrastructure

Exelon Generation

•

Invest in shovel ready

projects with utilities

•

Pursue Extra High Voltage

(EHV) development

opportunities in and around

our existing footprint

including partnerships with

Exelon utilities and regional

developers

•

Expand focus beyond our

footprint and evaluate

partnering with renewable

developers including

merchant transmission

31

32

Capitalizing on Market Opportunity and

Exelon Expertise

•

$60-100 billion expected investment in U.S.

over next 10 years

•

Opportunity for FERC-regulated returns and

Construction Work in Progress incentives

•

Minimal required initial investment prior to

regulatory approvals

•

Benefits of investment:

–

Improve reliability

–

Facilitate movement of renewable

energy to population centers

–

Reduce congestion costs to customers

•

Separate LLC lends transparency to an eventual

development and investment portfolio

•

Specialized expertise through dedicated

management team

•

Leverage corporate experience and understanding

of regulatory process

•

2010 O&M start-up costs funded by Exelon,

investments/development funded via project

finance, as appropriate

•

Opportunity to invest in projects with traditional

regulated frameworks and consider merchant

transmission

Market Opportunity

Exelon Business Plan

Investment in capital

constrained projects

with regulatory approvals

Investments within

existing footprint and

partnerships

Partnerships with

renewable developers

Merchant transmission

investment

Exelon Transmission Company (ETC) leverages existing capabilities and offers a

phased approach to disciplined, high-return growth

Close-In

Traditional Risk Profile

Test and Learn

Longer Cycle Time

Change in Risk Profile

Competitive Mind Set

33

Balanced Portfolio Investment Framework

The Exelon Transmission Company portfolio will evolve over time

Act as

Transmission

Investment Arm

Transmission

Options Tied to

Footprint

Partnerships with

Transmission

Developers

Partnerships with

Renewables

Developers

Pursue

Merchant

Transmission

•

Increasing number of utility sponsors are capital constrained

•

Early participation in projects at advanced development stage and relatively fast   

participation in attractive FERC-regulated incentive rate structures

•

Insiders’

view of development challenges outside our footprint

•

Assess existing investment model and opportunities in ComEd and PECO footprint to

address known, regional congestion issues and improve transmission reliability

•

Decision to proceed as a stand-alone transmission company project, utility project or

joint venture to be made on case-by-case basis

•

Assess existing regional and national opportunities

•

Leverage participation in SMART Transmission study

•

Focus on markets with attractive fundamentals in 4 areas:  regulatory,

supply/demand, structural/RTO opportunities, local dynamics

•

Emerging opportunity to address transmission bottlenecks being

experienced by developers

•

Identify and value merchant transmission opportunities in major

markets

•

Creates competition to construct most efficient and lowest cost

addition to the transmission grid

34

The New Crossroads of our Energy Future

Illinois positioned to facilitate the movement of renewable energy to population

centers beyond Chicago

35

•

Create extra-high voltage (EHV)

overlay alternatives that ensure

reliable service for our

communities and are

environmentally friendly

•

Find technically sound solutions

for integrating renewables and

new transmission into the existing

system

•

Identify economic solutions that

show the numerous benefits of

transmission expansion

American Transmission Company (ATC)

American

Electric

Power

(AEP)

–

via

ETA

MidAmerican

Energy

Holdings

Company

–

via

ETA

Exelon Corporation

MidAmerican Energy Company

NorthWestern

Energy

Xcel

Study Partners

SMART Transmission Study

SMART Transmission Study

Collaborating with Partners

Note:  ETA = Electric Transmission America

36

Transmission Investment Is Attractive

•

Potential for attractive returns

(1)

–

FERC granted ROEs (including incentives) historically range from

11.5% to 14.3%

•

Financing structures

–

Cash flows attractive to lenders and rating agencies

•

EPS accretive immediately

–

Rate base capitalization and Construction Work in Progress (CWIP)

recovery begins prior to project completion

(1)

•

Limited up-front investment required

–

Significant capital expenditures and equity injection does not occur

until all required approvals are obtained and recovery is highly

certain

–

ETC would not invest until cost allocation (“who pays”) is clear

Attractive returns, accretive, and relatively low equity contribution

requirements for a growth business

(1)  Subject to FERC approval.

37

Exelon’s recent success with the unique urban-based challenges of the West

Loop project provides us with the experience, resources, and technology to be

successful in long-haul EHV development

Exelon Is Experienced in Transmission

Investment

•

Own, operate and maintain >6,400 miles of transmission, including 90

miles of 765kV

•

$1 billion in high-voltage transmission system investment since 2003

•

$5 billion in T&D investment since 2001

•

Success with large and complex urban projects such as the ComEd

Chicago West Loop Substation project

–

Completed in 2008, this $350 million initiative installed additional

network capacity as part of the Chicago conversion from "hub and

spoke" to a network design

38

39

•

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

•

Complementary and flexible fossil and

hydro fleet

•

Leveraged to improving power market

fundamentals (commodity prices, heat

rates, and capacity values)

•

Below-market contract in Pennsylvania

ends at year-end 2010

•

Potential carbon restrictions

Value Proposition

Exelon Generation Value Proposition

•

Continue to focus on operating excellence,

cost management, and market discipline

•

Execute on power and fuel hedging

programs

•

Support competitive markets

•

Pursue nuclear & hydro plant relicensing

and strategic investment in material

condition

•

Maintain industry-leading talent

Protect Value

•

Pursuing 1,300-1,500 MW nuclear uprate

plan

•

Rigorously evaluate generation

development opportunities

•

Capture increased value of low-carbon

generation portfolio

Grow Value

Exelon

Generation

is

the

premier

unregulated

generation

company

–

positioned

to

capture market opportunities and manage risk

40

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

2000

2001

2002

2003

2004

2005

2006

2007

2008

Basics of Business Unchanged

Nuclear remains one of the lowest cost options for electricity production

Petroleum

Gas

Coal

Nuclear

1.87

U.S. Electricity Production Costs

(2000-2008)

(1)

(1)

In

2008

cents

per

kilowatt-hour.

Source:

NEI,

Ventyx

Velocity

Suite

May

2009.

Production

Cost

=

O&M

plus

fuel. 

2.75

8.09

17.26

41

A Leading Nuclear Fleet Operator in Cost

Among major nuclear plant fleet operators, Exelon is consistently one of the lowest-cost

producers of electricity in the nation

0

5

10

15

20

25

1

st

Quartile

2

nd

Quartile

3

rd

Quartile

4

th

Quartile

2004-2008 Average Production Cost

for Major Nuclear Operators

(1)

Average

(1)

Source: 2008

Electric

Utility

Cost

Group

(EUCG)

survey.

Includes

Fuel

Cost

plus

Direct

O&M

divided

by

net

generation.

42

Effectively Managing Nuclear Fuel Costs

Components of Fuel Expense in 2009

Projected Total Nuclear Fuel Spend

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

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

with the DOE.

2009

–

2013:

100% hedged in volume

2014:

~93% hedged in volume

All charts exclude Salem

0.0

2.0

4.0

6.0

8.0

10.0

2009

2010

2011

2012

2013

2014

0

200

400

600

800

1,000

1,200

1,400

2009

2010

2011

2012

2013

2014

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009

2010

2011

2012

2013

2014

Exelon Average Reload Price

Projected Market Price (Spot)

Enrichment

38%

Fabrication

16%

Nuclear Waste

Fund

19%

Tax/Interest

1%

Conversion

3%

Uranium

23%

43

0

20

40

60

80

100

120

140

160

Uranium Price Volatility

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

Short-term

Uranium Price Trend

Long-term Uranium Price Trend

Spring 2003

McArthur River

flood

December 2003

GNSS/Tenex

termination;

ConverDyn UF6 release

and shutdown

Early 2004

ERA / Ranger

water problems

Early 2006

First Cigar Lake flood;

Cyclone Monica halts 

ERA /  Ranger

operations for

approximately two

weeks

October 2006

Second Cigar

Lake flood

March 2007

ERA / Ranger flooding

(cyclone George)

30

35

40

45

50

55

60

65

70

75

80

44

World-Class Nuclear Operator

Average Capacity Factor

Note: Exelon data prior to 2000 represent ComEd-only nuclear fleet.

# of Reactors per Operator represents as of 2008.

Sources:

Platt’s,

Nuclear

News,

Nuclear

Energy

Institute

and

Energy

Information

Administration

(Department

of

Energy).

65

70

75

80

85

90

95

100

Operator (# of Reactors as of 2008)

Range

5-Year Average

Range of Fleet 2-Yr Avg Capacity Factor (2004-2008)

EXC 93.8%

Sustained production excellence

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

45

Impact of Refueling Outages

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

7

8

9

10

11

12

13

Note:  Data includes Salem. Net nuclear generation data based on

ownership interest.

•

Every 18 months (PWRs) or 24

months (BWRs)

•

Average

Outage

Duration:

~24

days

(1)

Nuclear Refueling Cycle

•

Based on the refueling cycle, we will

conduct 10 refueling outages in 2010,

the same number of refueling

outages conducted in 2009

2010 Refueling Outage Impact

Refueling Outage Duration

Nuclear Output

0

10

20

30

40

50

60

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

YTD

Exelon

Industry (w/o Exelon)

•

Estimated output reflects TMI

extended steam generator

replacement outage

•

Based on the refueling cycle, we are

conducting 10 refueling outages in

2009, versus 12 in 2008

2009 Refueling Outage Impact

Actual

Target

Estimate

# of Outages

(1)  Average Outage Duration for refueling outages

from 2007 –

2008, excluding Salem.

Note:  Exelon data includes Salem. YTD includes completed refueling outages

through September 2009.

46

Nuclear Uprates Offer Sustainable Value

Key component of Exelon 2020 low carbon roadmap

Creates additional low-carbon generation capacity

Capitalizes on Exelon’s proven track record of uprate execution

Dedicated project management team

Proven technology design

No ongoing incremental O&M expense

Creates long-term value over extended license lives

Uprates equivalent in size to a new nuclear plant but significantly

lower cost, shorter timeline, and more predictable spend

Straightforward regulatory and environmental licenses, permits

and

approvals

Potential for uprates to meet state alternative energy standards

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

operational excellence

Strategic

Value

Grow

Value

Regulatory

Feasibility

Execution

Feasibility

47

Three Major Categories of Exelon Uprates

Uprates

Overnight

Cost

(1)

MUR (Measurement Uncertainty Recapture)

•

Through the use of advanced techniques and more precise

instrumentation, reactor power can be more accurately calculated

•

Can achieve up to 1.7% additional output

•

Requires NRC approval

187–234 MW

$300M

2 years

899–1,016 MW

$2,400M

EPU (Extended Power Uprate)

•

Through a combination of more sophisticated analysis and

upgrades to plant equipment, uprates can increase output by as

much as 20% of original licensed power level

•

Requires NRC approval

3 -

5

years

237–266 MW

$800M

Megawatt Recovery and Component Upgrades

•

Replacement of major components in the plant occur in the normal

life

cycle

process

–

with

newer

technology,

replacements

result

in

increased efficiency

•

Equipment includes generators, turbines, motors and transformers

•

Megawatt Recovery and Component Upgrades must conform to

NRC standards, but do not require additional NRC approval

2 -

3

years

~1,300–1,500 MW

$3,500M

Project

Duration

Exelon’s $2,200 –

$2,500 / kW overnight cost for its MUR and EPU projects is an

advantageous deployment of capital relative to other generation options

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

Estimated

Internal Rate

of Return

12-15%

14-18%

9-12%

48

Phased Execution Lowers Risk

•

Safe, economical and proven methods to improve efficiency and output

•

Leverages Exelon’s substantial experience managing successful uprate projects over the

past 10 years

Note: Data contained in this slide is rounded.

Uprate program allows us to adjust timing to respond to market conditions

EPUs

MURs

MW Recovery and         

Component Upgrades

Maximum                        

Potential MW

Year Uprates Become Operational

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

Exelon’s Uprate Plan

1,100 MW

1,300 –

1,500  MW

Average Overnight Cost

Estimate: $2,200 -

2,500/KW

0

200

400

600

800

1,000

1,200

1,400

1,600

Planned Capital

Spend

(1)

$150

2017

$625

2013

$675

2012

$550

2011

$350

2010

$725

2015

$725

2014

$400

2016

$4,425

2008 -

2017

$225

2008 -

2009                                           

(1)

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

49

Uprates Across the Exelon Fleet

Base

Maximum

Station

Case

Potential

MW

MW

Braidwood - MUR

34

-

42

2012

Byron - MUR

34

-

42

2012

Clinton - EPU

17

-

17

2016

Clinton - EPU

2

-

3

2010

Dresden - MW Recovery & Component Upgrades

103

-

110

2012

Dresden - MW Recovery & Component Upgrades

5

-

5

2011

Dresden - MUR

25

-

31

2014

LaSalle - MUR

32

-

40

2011

LaSalle - EPU

303

-

336

2016

Limerick - MUR

33

-

41

2011

Limerick - MW Recovery & Component Upgrades

6

-

6

2012

Limerick - EPU

306

-

340

2017

Peach Bottom - MW Recovery & Component Upgrades

25

-

32

2012

Peach Bottom - EPU

134

-

148

2015

Peach Bottom - MW Recovery & Component Upgrades

3

-

3

2014

Quad Cities - MUR

19

-

23

2013

Quad Cities - MW Recovery & Component Upgrades

95

-

110

2011

TMI - EPU

138

-

172

2016

TMI - MUR

12

-

15

2014

Total

1,323

-

1,516

Year of

Operation

Uprates will largely be completed during scheduled refueling outages

Note:  MW shown at ownership. 

50

Exelon Nuclear Fleet Overview

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

Average in-service time = 28 years

2011

42.6% Exelon, 56.4%

PSEG

In process

(decision in 2011-

2012):  2016, 2020

503, 500

(2)

W

PWR

2

Salem, NJ

Life of plant capacity

100%

Renewed: 2034

837

B&W

PWR

1

TMI-1, PA

Dry cask

100%

Renewed: 2029

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

574, 571

(2)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

655, 662

(2)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

869, 871

GE

BWR

2

Dresden, IL

2010

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask

100%

2024, 2029

1148, 1145

GE

BWR

2

Limerick, PA

Re-rack completed

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

GE

W

W

Vendor

BWR

PWR

PWR

Type

1

2

2

Units

100%

2026

1065

Clinton, IL

100%

2024, 2026

1183, 1153

Byron, IL

100%

2026, 2027

1194, 1166

Braidwood, IL

Ownership

License Status /

Expiration

(1)

Net Annual

Mean Rating

MW 2009

Plant, Location

(1)

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

(2)

Capacity based on ownership interest.

Uprates + license extensions = long term value creation

TMI license

extension received

in October 2009

51

51

Total Portfolio Characteristics

Expected Total Supply (GWh)

Expected Total Sales

(GWh)

92,000

91,400

47,700

48,400

29,200

27,100

4,500

4,500

0

50,000

100,000

150,000

200,000

2009E

2010E

Forward / Spot Purchases

Fossil & Hydro

Mid-Atlantic Nuclear

Midwest Nuclear

173,400

173,400

171,400

171,400

103,200

102,700

39,900

39,900

5,600

16,900

22,700

13,900

0

50,000

100,000

150,000

200,000

2009E

2010E

ComEd

Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

52

Energy Prices Are Driven by Fuel, but

Influenced by Other Factors

•

Forward market prices suggest that

natural gas will set the price about 15%

of the time

•

PRB or eastern coal sets the price about

85% of the time

Gas/coal prices are the primary price driver, but other factors such as demand, supply

and transmission constraints influence the portion of the time that gas versus coal

sets the market clearing price

•

Forward market prices suggest that

natural gas will set the price about

40% of the time

•

Eastern coal sets the price about

60% of the time

Midwest Energy & Fuel

$0

$10

$20

$30

$40

$50

2007

2008

2009

2010

2011

2012

$0

$2

$4

$6

$8

Eastern Energy & Fuel

$0

$10

$20

$30

$40

$50

$60

$70

2007

2008

2009

2010

2011

2012

$0

$2

$4

$6

$8

$10

Chicago Gas

NiHub ATC

PRB Coal

Historical

Forward Market

PA Gas

PJMW ATC

NAPP Coal

Forward Market

Historical

53

Fuel and Demand Do Not Explain

Midwest Forward Energy Prices

•

Forward markets suggest that gas and western coal prices over the next three years will

be slightly higher than over the past three years

•

Demand is also expected to be slightly higher

•

Yet Midwest forward prices are significantly lower than historical average spot prices

$34.26

$61.33

$10.95

$6.71

2010-2012

Average Forward

(1)

(16%)

$40.68

NiHub ATC Price ($/MWh)

+0.8%

(3)

ComEd Load (GWh)

(10%)

$68.30

NAPP

Coal

Price

($/ton)

(2)

+6%

$10.30

PRB

Coal

Price

($/ton)

(2)

+2%

$6.55

Chicago

Gas

Prices

($/MMBtu)

(2)

Forward

Premium

(Discount)

2007-2009

Average Spot

Midwest forward market price is not consistent with fuel price and demand increases

(1)

Forward prices as of September 30, 2009.

(2)

Fuel price effect on NiHub ATC price vary and assume all other price inputs constant.

(3)

Reflects ComEd’s load growth in 2010.

54

Near-Term Wind Build Out Will Be Limited

•

Wind under construction (plus existing wind) is sufficient to meet state RPS requirements

through 2012 and other projects in the interconnection queue have stalled

•

Based on bids we have received from developers, new wind needs roughly $50/MWh

above current Midwest market prices to be economic and very few buyers are willing to

pay such a price

We expect no more than 3,000 MW of new wind to come online in west MISO and ComEd

over

the

next

three

years,

impacting

NiHub

prices

by

less

than

$1/MWh

(1)

(1)

Price impact will depend on location of new wind, as wind in west MISO will tend to have less of an impact than wind in ComEd.

Note:  Graph includes MidAmerican in MISO as of September 2009.

55

(1) Price impact will depend on location of new wind, as wind in west MISO will tend to have less of an impact than wind in ComEd.

Long-Term Wind Impact Will Be Moderate

•

Impact on Midwest prices will be moderate under most plausible scenarios for federal and

state mandates.

–

No Federal RPS

•

Full compliance with current state RPS would result in an additional 10 to 15 GW of wind in

west MISO/ComEd by 2020 which could reduce prices by $1/MWh to $2/MWh in NiHub

•

Because

of

current

economics

of

wind,

partial

compliance

(either

through

purchase

from

other

states or payment of price cap) is possible and this would result in impact at the lower end of

this range

–

Federal RPS and Carbon Legislation (similar to Waxman-Markey)

•

Without a significant transmission build out, 20 to 25 GW of wind in west MISO/ComEd could

materialize translating to a price impact in the $2/MWh to $3/MWh range

•

With a transmission build out, price impact would only be above this range if it is exclusively

west of NiHub:

–

Transmission

build

out

would

increase

wind

in

west

MISO/ComEd

to

25

to

30

GW

–

If build out west of NiHub continues east into AEP, then price impact would remain in

$2/MWh to $3/MWh range

–

If build out is west of NiHub only, despite favorable economics of east line, then price

impact could approach double this amount

Based on our modeling of plausible wind scenarios, the long-term impact of Midwest wind on

NiHub

prices

is

likely

to

be

in

the

$2/MWh

to

$3/MWh

range

(1)

56

Implied Transmission Constraints

Appear Overstated

•

Historically, NiHub prices have traded at a discount to AEP prices of $5/MWh or less

•

Financial Transmission Rights (FTR) auction prices translate to a price discount of

about $6/MWh (including an assumption for marginal losses)

–

The FTR price represents a market-based view of the price difference between two locations

•

But forward energy market suggests that NiHub discount will increase to $10/MWh

–

This

discount

appears

overstated

given

the

anticipated

return

to

service

of

the

Cook

nuclear

station and the joint project between NIPSCO and Edison to address congestion issues on

NIPSCO’s

transmission system

Contrary to the current forward energy market, we believe that the NiHub discount relative

to AEP will not increase significantly in the next few years

(1)  Forward prices as of September 30, 2009.

(2)  Reflects results of October 2009 PJM long-term FTR auction.

AEP-Dayton / NI Hub ATC Energy Basis

0

2

4

6

8

10

12

2006

2008

2010

2012

2014

Historical Spot Prices

FTR Auction Prices

(2)

Forward Energy Prices

(1)

57

30

35

40

45

50

55

2010

2011

2012

2013

2014

We See Upside Potential in Midwest

Forward Energy Markets

•

Increasing gas, coal, and demand will place upward pressure on Midwest energy prices

•

New wind supply will have minimal impact in the next few years

•

Transmission constraints are unlikely to be more severe than over the past year

Midwest power markets have upside…2012 gross margin increases by ~$300 million

for each $5/MWh increase in NiHub ATC

9/30/09 Forward Prices

NiHub ATC Prices

Current opportunity

Carbon opportunity

assuming a $15/tonne

price and Waxman-

Markey allocations

58

Exelon Generation Is Capitalizing on

the Opportunity

•

Hedging actions

–

Maintain ratable hedging philosophy, while utilizing flexibility:

•

Participate in Pennsylvania wholesale load solicitations

•

Explore bilateral transaction opportunities (e.g. ODEC)

•

Utilize power and natural gas put options

•

Transact retail sales through Exelon Energy

–

Allocate a portion of hedges to locations to take advantage of market views

•

Reduce congestion between Midwest generation and load centers/trading hubs

–

Working with the stakeholders in PJM and MISO to validate the market to market

coordination between PJM and MISO

•

Specifically, participating in the Wisconsin market to market study request to review and

determine validity of the PJM to MISO coordinated energy dispatch

•

Working with several industry consultants (CRA and NorthBridge) to assist in the review

–

Identify, analyze and value the limiting constraints on the transmission system that

directly impact the baseload value of our fleet

•

Focus areas include the Illinois / Indiana interface (Ni-Hub to AD Hub), central Illinois

(Clinton to Cinergy Hub) and Western Illinois (Quad Cities/Byron

to Ni-Hub)

•

Evaluate near-term impacts of Cook nuclear station returning to service and the joint project

between NIPSCO and Edison to address congestion issues on the Illinois / Indiana interface

–

Prioritize

economic

transmission

upgrades

(that

can

be

completed

in

the

next

five

years) based on historical constraints and our fundamental view of the market

59

Reliability Pricing Model Auction

PJM RPM Auction ($/MW-day)

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

Note: Data contained on this slide is rounded.

40.80

197.67

111.91

148.80

102.04

191.32

174.29

110.00

16.46

133.37

139.73

2007/2008

2008/2009

2009/2010

2010/2011

2011/2012

2012/2013

RTO

MAAC + APS

MAAC

Eastern MAAC

Only shown

if cleared

at separate

price and

generation

is located

in that zone

(5)

(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) 

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

(4)

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

(5)

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

(6)

Elwood

contract

expires

in

12/31/12

and

Kincaid

contract

expires

in

2/28/13.

(7)

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

highlighted zones.

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)

23,900

9,300 -

9,400

(3)

23,200

12,100

(6)

EMAAC

9,500

MAAC + APS

11,100 

9,300 –

9,400

(3)

MAAC

1,500

Avg ($/MW-Day)

(7)

$143.90

$174.29

$110.00

$74.75               

60

Capacity Prices Should Start to

Recover in Next Auction

•

Several factors will place upward pressure on capacity prices, particularly at the RTO level:

–

Rule

change

pending

at

FERC

allowing

existing

demand

response

to

bid

above

$0

–

Addition of FirstEnergy Ohio to PJM (FE Ohio peak load exceeds capacity obligation by roughly

2,000 MW)

(1)

–

Increase in coal plant costs and supply bids due to required environmental CapEx

Increasing capacity prices will provide Exelon with additional growth starting in 2013

0

25

50

75

100

125

150

175

200

2007-08

2008-09

2009-10

2010-11

2011-12

2012-13

2013-14

RTO

EMAAC

PJM RPM Auction Results

(1)   Based on FirstEnergy FERC filing which states that 2008 load was 12,972 MW (translates to a capacity obligation of 15,073 MW at a 16.2% reserve margin) compared to

generation of 12,910 MW.

61

~$5.50

$50.50 -

$51.50

$28.50-

$29.50

Estimated Build-Up of PECO Average

Residential Full Requirements Price

$91.60/MWh

Full Requirements Costs ($/MWh)

Average Full Requirements                          

Retail Sales Price

(1)

Load Shape &

Ancillary Services

$7.50 

Capacity

$12.00

Transmission &

Congestion

$7.00 -

$8.00

Renewable

Energy

Credits

$1.00

Migration,

Volumetric

Risk & Other

$1.00

~$6.50

(1)

As provided by Exelon Generation.

(2)

On Oct 21, 2009 the Independent Evaluator (NERA) announced a wholesale winning bid average price of $79.96/MWh for PECO’s Fall 2009 RFP (reflecting 17 & 29-month residential

full

requirements’

products

with

delivery

beginning

Jan

1,

2011).

(1)

As provided by Exelon Generation.

(2)

On Oct 21, 2009 the Independent Evaluator (NERA) announced a wholesale winning bid average price of $79.96/MWh for PECO’s Fall 2009 RFP (reflecting 17 & 29-month residential

full

requirements’

products

with

delivery

beginning

Jan

1,

2011).

Average

Wholesale

Energy Price

$79.96

(2)

61

62

62

Exelon Energy

•

Channel to market to execute Power Team hedging strategy

–

Exelon Energy retail aggregate load profile complements generation portfolio

–

Long term sales agreements with creditworthy customers reduce portfolio price and earnings risk

•

Advocate for competitive markets

–

Provides customer benefits from competitively priced energy offerings

•

Channel to build relationship with end-use customers

–

Provides insight related to trends in demand and expectations for product and services

–

Channel to provide products that support Exelon 2020 Plan and demand reduction programs

–

Renewable Energy Credits (RECs)

–

Low Carbon Energy Certificates (EFECs)

–

Nuclear energy attributes transferred through PJM Generation Attribute Tracking System

–

Demand Side Management Programs

•

Growth vehicle in regions that complement Exelon Generation footprint

–

Expansion opportunities into additional eastern PJM and ERCOT markets are under evaluation

•

Supplies a wide range of energy and natural gas products directly to industrial

and commercial customers in Illinois, Pennsylvania, Michigan and

Ohio

Leveraging broad experience in wholesale markets and asset management through

integration with Power Team

63

Exelon Generation 2010 EPS Contribution

Generation’s 2010 earnings are driven lower by market and portfolio conditions

(1) 

Estimated contribution to Exelon’s operating earnings guidance.

$ / Share

2009

RNF

O&M

CTC/A/D

Interest Expense

Other

2010

$(0.32)

$0.06

RNF

O&M

Other

Depreciation &

Amortization

$(0.09)

Key Items:

Inflation                                      $(0.05)

Pension/OPEB                           $(0.06)

Cost Savings Initiative               $0.04

2009E

(1)

2010E

(1)

$2.55 -

$2.80

$3.10 -

$3.15

Key Items:

Market/Portfolio

Conditions/Generation     $(0.29)

Nuclear Fuel Expense     $(0.12)

PECO CTC                      $(0.11)

Capacity Market Prices     $0.19

$(0.05)

$(0.04)

Interest

Expense

64

64

Current Market Prices

Units

2007

1

2008

1

2009

5

2010

6

2011

6

2012

6

PRICES (as of September 30, 2009)

PJM West Hub ATC

($/MWh)

59.76

(2)

68.52

(2)

38.23

48.40

51.50

52.84

PJM NiHub ATC

($/MWh)

45.47

(2)

49.00

(2)

28.06

32.57

34.36

35.86

NEPOOL MASS Hub ATC

($/MWh)

66.72

(2)

80.56

(2)

41.69

58.22

62.91

64.50

ERCOT North On-Peak

($/MWh)

59.44

(3)

73.36

(3)

33.32

51.94

57.38

60.82

Henry Hub Natural Gas

($/MMBTU)

6.95

(4)

8.85

(4)

4.04

6.21

6.87

7.00

WTI Crude Oil

($/bbl)

69.72

(4)

104.49

(4)

57.26

73.86

77.16

79.11

PRB 8800

($/Ton)

9.67

12.17

9.04

8.91

10.96

13.00

NAPP 3.0

($/Ton)

47.54

105.36

52.03

55.03

63.00

66.00

ATC HEAT RATES (as of September 30, 2009)

PJM West Hub / Tetco M3

(MMBTU/MWh)

7.68

6.97

8.04

6.96

6.76

6.83

PJM NiHub / Chicago City Gate

(MMBTU/MWh)

6.65

5.57

6.99

5.22

5.00

5.12

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.80

7.42

7.79

7.36

7.28

7.54

(1)

2007 and 2008 are actual settled prices.

(2)

Real Time LMP (Locational Marginal Price).

(3)

Next day over-the-counter market.

(4)

Average NYMEX settled prices.

(5)

2009 information is a combination of actual prices through September 30, 2009 and market prices for the balance of the year.

(6)

2010, 2011 and 2012 are forward market prices as of September 30, 2009.

65

65

65

65

45

55

65

75

85

95

105

115

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

20

25

30

35

40

45

50

55

60

65

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

35

45

55

65

75

85

95

105

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

5

6

7

8

9

10

11

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

65

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

$6.04

2011

$6.82

Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2010

$53.25

2011

$65.26

2010 Ni-Hub

$43.06

2011 Ni-Hub

$45.29

2011 PJM-West  $63.88

2010 PJM-West

$59.37

2010 Ni-Hub

$24.40

2011 Ni-Hub

$26.00

2011 PJM-West

$42.28

2010 PJM-West

$39.79

66

66

66

66

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

14.5

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

35

40

45

50

55

60

65

70

75

80

85

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

5

6

7

8

9

10

11

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

66

Market Price Snapshot

2011

$8.66

2010

$8.65

2010

$50.68

2011

$57.42

2010

$5.86

2011

$6.63

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

$5.91

2011

$7.10

ERCOT North On Peak Spark Spread

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

Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading system. Quotes are daily.

67

Exelon Generation Hedging Disclosures

68

68

68

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

69

69

69

69

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

70

70

70

2010

2011

2012

Estimated Open Gross Margin (millions)

(1)

$5,850

$5,950

$5,850

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

Reference Prices

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT North ATC Spark Spread ($/MWh)

(2)

$6.21

$32.57

$48.40

$(1.51)

$6.87

$34.36

$51.50

$(1.94)

$7.00

$35.86

$52.84

$(0.17)

(1)    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.

(2)    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

Based on September 30, 2009 market conditions

71

71

71

(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 93.5%, 92.8% and 92.8% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected generation in 2011 and 2012 do not represent

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

(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.

2010

2011

2012

Expected Generation

(GWh)

(1)

166,800

164,900

165,100

Midwest

98,600

98,200

97,000

Mid-Atlantic

59,900

59,100

59,800

South

8,300

7,600

8,300

Percentage of Expected Generation Hedged

(2)

88-91%

63-66%

32-35%

Midwest

88-91

67-70

41-44

Mid-Atlantic

91-94

56-59

20-23

South

90-93

52-55

22-25

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.50

$44.50

$46.00

Mid-Atlantic

$33.75

$60.50

$52.75

ERCOT North ATC Spark Spread

$3.00

$4.25

$5.75

Generation Profile

72

72

72

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

$45

$(40)

$40

$(35)

$30

$(25)

+/-$50

2011

$265

$(225)

$185

$(175)

$165

$(160)

+/-$50

2012

$525

$(500)

$285

$(280)

$270

$(260)

+/-$55

(1)

Based on September 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)

73

73

73

95% case

5% case

$6,100

$6,500

$6,000

$8,200

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2010

2011

2012

$4,600

$8,300

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 percentile 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 ransactions 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 September 30, 2009.

74

74

74

Midwest

Mid-Atlantic

ERCOT

Step 1

Start with

fleetwide open gross margin 

$5.85 billion

Step 2

Determine the mark-to-market value

of energy hedges

98,600GWh * 89% *

($46.50/MWh-$32.57/MWh)

= $1.22 billion

59,900GWh * 92% *

($33.75/MWh-$48.40/MWh)

= $(0.81 billion)

8,300GWh * 91% *

($3.00/MWh-($1.51)/MWh)

= $0.03 billion

Step 3

Estimate hedged gross margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                             

MTM value of energy hedges:         

Estimated

hedged

gross

margin:

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

$5.85 billion

$1.22

billion

+

$(0.81

billion)

+

$0.03

billion

$6.29 billion

75

76

6.1

6.9

2.0

2.0

7.2

6.5

2.0

2.1

Transmission

Distribution

ComEd Regulatory Plan

Executing Regulatory

Recovery Plan

~9-10%

~47%

~10%

~ 48%

~8%

~46%

Earned ROE

Equity

(1)

5.5%

45.4%

$8.1

$8.5

$9.3

2008

2009E

2011

(Illustrative)

(2)

Average Annual Rate Base

($ in billions)

ComEd’s

earnings

are

expected

to

increase

as

regulatory

lag

is

reduced

over

time

through cost savings, the uncollectible rider and regular rate requests

(1)

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

(2)

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

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

•

Driving efficiencies to reduce and control

O&M costs and capital spending

•

Legislation passed to enable recovery of

uncollectibles expense through a rider

anticipated in Q1 2010 (retroactive to 2008)

•

Anticipate filing electric

distribution rate case

in 2010

•

Benefiting from regular transmission

updates through a formula rate plan

•

ICC approved Smart Meter pilot program

and rider

•

Standard & Poor’s and Moody’s raised

credit ratings in 3Q 2009

2010E

$8.9

77

Illinois Power Agency (IPA) RFP Procurement

•

On September 30, 2009, the IPA submitted an Updated Procurement Plan for the

2010/11 planning period

•

Similar to 2009, the Procurement Plan for the 2010/11 planning period includes the

procurement of monthly peak and off-peak standard wholesale block energy products

•

The IPA’s Plan also calls for the procurement of 1,887,014 MWh of Renewable Energy

Credits

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

Next RFP to be held in Spring 2010

2009 RFP

2009 RFP

2010 RFP

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2013 RFP

Financial

Swap

Auction

Contract

Delivery

Period

Peak

Off-Peak

June 2010 -

May 2011

5,390

4,538

June 2011 -

May 2012

1,858

668

Volumes to be secured in 2010

IPA Procurement Event (GWh)

Jun 2009

Jun 2010

Jun 2011

Jun 2012

Jun 2013

Jun 2014

78

Financial Swap Agreement with

Exelon Generation

3,000

$53.48

January 1, 2013 -

May 31, 2013

3,000

$52.37

January 1, 2012 -

December 31, 2012

3,000

$51.26

January 1, 2011 -

December 31, 2011

3,000

$50.15

June 1, 2010 -

December 31, 2010

2,000

$50.15

January 1, 2010 -

May 31, 2010

2,000

$49.04

June 1, 2009 -

December 31, 2009

1,000

$49.04

January 1, 2009 -

May 31, 2009

1,000

$47.93

June 1, 2008 -

December 31, 2008

Notional Quantity (MW)

Fixed Price ($/MWH)

Portion of Term

•

Market-based contract for ATC baseload energy only

–

Does not include capacity, ancillary services, or congestion

•

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

•

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

Note: C&I = Commercial & Industrial

79

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

09Q1

09Q2

09Q3

09Q4E

10Q1E

10Q2E

10Q3E

10Q4E

-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 (right axis)

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

U.S.

Unemployment rate

(1)

10.5%

9.8%

2009 annualized growth in

gross domestic/metro product

(2)

(3.7)%

(2.6)%

7/09 Home price index

(3)

(14.2)%

(13.3)%

(1)  Source: Illinois Dept. of Employment Security (October 2009) and U.S.

Dept. of Labor (October 2009)

(2)

Source: Moody’s Economy.com (September 2009)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect.

Q309

Q409E       2009E

(4)

2010E

Customer Growth

(0.5)%

(0.6)%

(0.4)%

0.1%

Average Use-Per-Customer

0.1%

(0.7)%

(0.9)%

(0.1)%

Total Residential

(0.4)%

(1.3)%

(1.3)%

0.0%

Small C&I

(2.9)%

(0.8)%

(2.4)%

1.0%

Large C&I

(8.6)%

(4.1)%

(6.7)%

1.5%

All Customer Classes

(3.8)%

(1.9)%

(3.4)%

0.8%

80

ComEd Smart Meter Pilot and Stimulus Funding

•

Smart

Meter

Pilot

(or

Advanced

Metering

Infrastructure

-

AMI)

–

ICC approved on October 14, 2009

–

1-year pilot program for 131,000 smart meters and related programs

–

~$70 million spend in 2009-2010 with recovery with regulated return for capital

investment expected to begin in 2010 through a rider

•

Smart Grid Solar Pilot Project

–

$5 million in stimulus funds for Smart Grid Solar Pilot

–

Pilot group of ~100 customers will receive solar systems and be placed on real-time

pricing and net metering programs

–

Goals are (1) to study how photovoltaic panels and energy storage affect reliability of

the distribution system, (2) to evaluate consumer response to price signals and (3) to

assess customer acceptance of new technologies

•

Green Vehicle Fleet

–

$4 million in stimulus funding awarded to ComEd to expand Green Vehicle Fleet and

Test Impact on Electric Grid

–

Will add up to 14 new hybrid and plug-in electric vehicles to fleet

–

Will

deploy

vehicle

smart

charging

stations

and

evaluate

impacts

of

vehicle

charging

while managing the electric load

ComEd is pursuing a number of smart grid investments with regulated

returns and stimulus funding

81

ComEd 2010 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

(2)

Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of $0.05 per share in 2010.

(3)

Primarily recovery of 2008 and 2009 uncollectible expense, of which approximately $0.07 per share will be included in Q1 2010 earnings.

ComEd’s operating earnings are expected to increase in 2010 primarily due to continued

execution of its Regulatory Recovery Plan

2009E

(1)

Depreciation &

Amortization

Interest

Expense

$0.60 -

$0.70

$0.50 –

$0.55

$0.13

$0.07

$(0.02)

2010E

(1)

$ / Share

$(0.01)

$(0.03)

Other

RNF

(2)

O&M

(2)

Key Items:

Uncollectible Rider

(3)

Weather                           

Key Items:

Cost

Savings

Initiative

$0.07        

Bad

debt

(3)

$0.05                       

Inflation

$(0.02)                            

Pension/OPEB

$(0.02)            

$0.04

$0.05

82

83

2.7

2.8

3.0

3.2

0.5

0.5

0.5

1.1

1.1

1.1

1.2

0.6

2.0

1.3

0.4

Gas

Competitive Transition Charge (CTC)

Electric Transmission

Electric Distribution

PECO Regulatory Plan

Actively Engaged in Transition

•

One of six companies to receive

maximum federal stimulus award of

$200 million for smart grid / smart meter

program

•

Anticipate filing electric and gas rate

cases in 2010

•

Filed plans and programs with PAPUC

to implement energy efficiency, demand

response and smart meter provisions of

Pennsylvania Act 129 (HB2200)

•

Transitioning through an orderly

structure to market-based electric rates

–

Completed 2 of 4 planned power

procurements to address post-transition

supply beginning in 2011

~9 –

11%

Not applicable due to

transition rate structure

Rate Making ROE

Equity

~50-53%

$6.3

$5.7

$5.0

Average Annual Rate Base

(1)

($ in billions)

2008

2009E

2011

(Illustrative)

(2)

PECO provides a solid ROE with a strong capital structure

(1)

Rate base as determined for rate-making purposes.

(2)

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

relied upon as a forecast of future results.

$5.1

2010E

84

PECO Procurement Results

PECO has completed two of the four procurements for the power needed to serve its

residential customers beginning in 2011

•

On September 23, 2009, the PAPUC approved the bids from PECO’s second RFP

Residential

Sept RFP average price of

$79.96/MWh

(2)

June RFP average price of

$88.61/MWh

(2)

49% of full requirements product

procured

80 MW of block energy procured

Small and Medium Commercial

Sept RFP average blended price

of $85.85/MWh

(2)

24% of Small Commercial full

requirements product procured

16% of Medium Commercial full

requirements product procured

85% full requirements

15% full requirements spot

Medium Commercial &

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% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

PECO Procurement Plan

(1)

Total Procured (including

June and September RFPs)

Residential

23% of planned full requirements

contracts (17 and 29-mo terms)

140 MW of baseload (24x7)

block energy products (12, 24

and 60-mo duration)

40 MW of Jan-Feb 2011 on-peak

block energy

Small Commercial

36% of planned full requirements

contracts (17 and 29-mo term)

Medium Commercial & Industrial

42% of planned full requirements

contracts (17-mo term)

May 24, 2010 RFP

(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 RFP.

85

5.03

5.03

0.51

0.51

6.26

2.57

9.41

PECO Average Residential Electric Rates

(1)

Average of PECO’s residential rates.

(2)

Provided for illustration only.  Represents 49% of PECO’s full requirements residential procurement for 2011.

(3)

Average retail price for full requirements products. Full requirements product includes load following energy, capacity, ancillary transmission services and

Alternative Energy Portfolio Standard requirements.

(4)

Does not include energy efficiency or changes in distribution rates.

2011

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

14.37¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~4%

(4)

14.95¢

(1)

Assumptions

Illustrative Rate Increase Based on

PECO Residential Full Requirements

Procurement Results

(2)

•

2011 illustrative residential rate based

on a weighting of 26% on Spring 2009

Retail results, 23% on Fall 2009 Retail

results, and future supply

procurement estimated at Fall 2009

Results

•

Actual 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

Spring 2009

10.13¢/kWh

PECO Residential

Procurement Results

(3)

Effect of Spring and Fall 2009 Procurements

Fall 2009

9.16¢/kWh

Retail Results

86

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

U.S.

Unemployment rate

(1)

8.5%                   9.8%

2009 annualized growth in

gross domestic/metro product

(2)

(3.4)%              (2.6)%

(1)  Source:  U.S

Dept.

of

Labor

(PHL

August

2009,

US

–

October

2009)

(2)  Source: Moody’s Economy.com (September 2009)

(3)  Not adjusted for leap year effect.

Note: C&I = Commercial & Industrial

Q309

Q409E      2009E

(3)

2010E

Customer Growth

(0.4)%

(0.4)%

(0.3)%

0.0%

Average Use-Per-Customer

(5.1)%

(0.4)%

(2.2)%

(0.5)%

Total Residential

(5.5)%

(0.8)%

(2.5)%

(0.6)%

Small C&I

(5.1)%

(3.4)%

(2.7)%

(0.8)%

Large C&I

(2.2)%

(1.7)%

(3.0)%

(2.3)%

All Customer Classes

(3.9)%

(1.8)%

(2.7)%

(1.3)%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

09Q1

09Q2

09Q3

09Q4E

10Q1E

10Q2E

10Q3E

10Q4E

-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 (right axis)

87

PECO Smart Grid/Smart Meter

•

PECO

intends

to

spend

up

to

$650

million

on

its

Smart

Grid/Smart

Meter

Infrastructure

(1)

–

$550

million

Advanced

Metering

Infrastructure

over

10

–

15

years

–

~$300 million in 2010-2012 period

–

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

•

Awarded $200 million Federal Stimulus Grant on October 27

•

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

surcharge including a return on capital investment

•

Smart Grid investment to be recovered through transmission and distribution rates

($ millions pre-tax)

2010

2011

2012

Total

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

40

$    

150

$  

100

$  

290

$       

Smart Grid Stimulus Case

50

45

15

110

Total Stimulus Case

90

195

115

400

Stimulus Grant Request

(45)

(100)

(55)

(200)

Total Expenditures net of Stimulus grant

45

$    

95

$    

60

$    

200

$       

2010-2012

Spend

With

Federal

Stimulus

Grant

(2)

:

(3)

(1)

Does not include $100 million for potential replacement of gas meters and wind-down of legacy Automated Meter Reading system.

(2)

Assumes 100% of matching funds requested by DOE.

(3)

Includes approximately $10 million, $15 million, and $25 million of O&M in 2010-2012, respectively.

Data contained in this slide is rounded.

88

PECO 2010 EPS Contribution

PECO’s 2010 EPS contribution remains relatively flat to 2009

$ / Share

RNF

$(0.12)

$0.45 -

$0.50

(1)

Depreciation &

Amortization

2010E

(2)

Key Items:

CTC

$0.11

Weather

$0.04

Load

$(0.03) 

Key Items:

Inflation

$(0.02)

Pension/OPEB

$(0.01)

$0.08

O&M

$0.03

$0.40 -

$0.50

(1)

Key Items:

CTC Amortization  $(0.11)

Interest

$(0.03)

Key Items:

CTC Interest Expense    $0.06

2009E

(2)

(1)

Excludes preferred dividends.

(2)

Estimated contribution to Exelon’s operating earnings guidance.

89

Key Assumptions, Projected 2010 Credit

Measures &

GAAP Reconciliation

90

90

Key Assumptions

2008 Actual

2009 Est.

(5)

2010 Est.

(6)

Nuclear Capacity Factor (%)

(1)

93.9

93.6

93.5

Total Generation Sales Excluding Trading (GWh)

176,174

173,400

171,400

Total Generation Sales to PECO (GWh)

40,966

39,900

39,900

Total Generation Market and Retail Sales (GWh)

(2)

135,208

133,500

131,500

Henry Hub Gas Price ($/mmBtu)

8.85

4.04

6.21

PJM West Hub ATC Price ($/MWh)

68.52

38.23

48.40

Tetco M3 Gas Price ($/mmBtu)

9.83

4.76

6.95

PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)

6.97

8.04

6.96

NI Hub ATC Price ($/MWh)

49.00

28.06

32.57

Chicago City Gate Gas Price ($/mmBtu)

8.79

4.02

6.23

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

5.57

6.99

5.22

PJM East Capacity Price ($/MW-day)

169.09

173.73

181.34

PJM West Capacity Price ($/MW-day)

82.39

106.13

144.40

Electric Delivery Growth (%)

(3)

PECO

0.6

(1.8)

(1.3)

ComEd

(0.1)

(3.4)

0.8

Effective Tax Rate (%)

(4)

36.1

37.5

35.8

(1)

Excludes Salem.

.

(2)

Includes Illinois Auction sales and ComEd swap.

(3)

Weather-normalized retail load growth.

(4)

Starting on January 1, 2011, effective tax rate is expected to increase to 37.1% due to lower tax benefit related to the PECO PPA roll off.

(5)    2009 information is a combination of actual prices through September 30, 2009 and market prices for the balance of the year.

(6)    Reflects forward market prices as of September 30, 2009.

91

Projected 2010 Key Credit Measures

13.8x

8.1x

FFO / Interest

Generation /

Corp:

62%

34%

FFO / Debt

53%

68%

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)

3.7x

3.8x

FFO / Interest

ComEd:

18%

14%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

5.2x

5.0x

FFO / Interest

PECO:

28%

23%

FFO / Debt

46%

50%

Rating Agency Debt Ratio

29%

47%

Rating Agency Debt Ratio

87%

44%

FFO / Debt

18.6x

9.9x

FFO / Interest

Generation:

46%

37%

7.2x

Without PPA &

Pension / OPEB

(2)

57%

Rating Agency Debt Ratio

25%

FFO / Debt

6.0x

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:  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 October 23, 2009.

92

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

+ ComEd Transition Bond Principal Balance

+ 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)

Uses current year-end adjusted debt balance.

(2)

Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital

Adequacy for Energy Trading.

(3)

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

93

2008 GAAP Reconciliation

(0.22)

-

-

(0.01)

(0.21)

2007 Illinois electric rate settlement

(0.02)

-

-

(0.02)

-

City of Chicago settlement with ComEd

(0.02)

(0.02)

-

-

-

NRG acquisition costs

0.03

-

-

-

0.03

Resolution of tax matters at Generation related to Sithe

0.02

-

-

-

0.02

Decommissioning obligation reduction

$4.13

$(0.10)

$0.49

$0.30

$3.44

2008 GAAP Earnings (Loss) Per Share

$4.20

$(0.08)

$0.49

$0.33

$3.46

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

0.41

-

-

-

0.41

Mark-to-market adjustments from economic hedging activities

(0.27)

-

-

-

(0.27)

Unrealized losses related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

Generation

2008 GAAP EPS Reconciliation

(1)

(1)  Amounts shown are per Exelon share and represent contributions to Exelon's EPS.

Note: Amounts may not add due to rounding.

(145)

-

-

(7)

(138)

2007 Illinois electric rate settlement

20

-

-

-

20

Resolution of tax matters at Generation related to Sithe

272

-

-

-

272

Mark-to-market adjustments from economic hedging activities

15

-

-

-

15

Decommissioning obligation reduction

(11)

(11)

-

-

-

NRG acquisition costs

$(67)

-

-

$(56)

Other

$2,737

(11)

(184)

$2,781

Exelon

$325

-

-

$325

PECO

$201

(11)

-

$219

ComEd

Generation

2008 GAAP Earnings Reconciliation (in millions)

-

City of Chicago settlement with ComEd

$2,278

2008 GAAP Earnings (Loss)

(184)

Unrealized losses related to nuclear decommissioning trust funds

$2,293

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

94

2009/2010 Earnings Outlook

•

Exelon’s outlook for 2009/2010 adjusted (non-GAAP)

operating earnings 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 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

•

Costs associated with early debt retirements

•

External costs associated with the terminated 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

•

Both our operating earnings and GAAP earnings guidance

are based on the assumption of normal weather

95

Exelon Investor Relations Contacts

Exelon Investor Relations

10 South Dearborn Street

Chicago, Illinois 60603

312-394-2345

312-394-4082 (Fax)

For copies of other presentations,

annual/quarterly reports, or to be

added to our email distribution list

please contact:

Martha Chavez, Executive Admin

Coordinator

312-394-4069

Martha.Chavez@ExelonCorp.com

Investor Relations Contacts:

Karie Anderson, Vice President

312-394-4255

Karie.Anderson@ExelonCorp.com

Stacie Frank, Director

312-394-3094

Stacie.Frank@ExelonCorp.com

Paul Mountain, Manager

312-394-2407

Paul.Mountain@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com