Clean in Competitive Markets

Chris Crane, President

Edison Electric Institute Financial Conference

November 1-2, 2010

Exhibit  99.1

2

Forward-Looking Statements

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

Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause

actual results to differ materially from these forward-looking statements include those discussed

herein as well as those discussed in (1) Exelon’s 2009 Annual Report on Form 10-K in (a) ITEM 1A.

Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results

of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s

Third Quarter 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A.  Risk

Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of

Financial Condition and Results of Operations and (c) Part I , Financial Information, ITEM 1. Financial

Statements: Note 13 and (3) other factors discussed in filings with the Securities and Exchange

Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy

Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place

undue reliance on these forward-looking statements, which apply only as of the date of this

presentation.

None

of

the

Companies

undertakes

any

obligation

to

publicly

release

any

revision

to

its

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

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

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

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

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

earnings

to

GAAP

earnings.

Please

refer

to

the

footnotes

of

the

following

slides

for

a

reconciliation

non-GAAP cash flows to GAAP cash flows.

3

Exelon’s Protect and Grow strategy considers

existing and potential energy policy to create

long-term value

Advocacy and generation

optimization

around

environmental regulations

Largest nuclear uprate

program

in the industry

Utility investment

and

regulated recovery

Renewables acquisition

at

attractive valuation

Transmission investment

across the business

Exelon 2020 identifies the most rational economic options to deliver shareholder value

as energy policy turns toward clean energy and affects competitive markets

4

None, 51%

SCR/SNCR,

20%

FGD &

SCR/SNCR,

15%

FGD Only,

14%

0

5,000

10,000

15,000

20,000

25,000

30,000

> 300 MW (54 GW)

< 300 MW (21 GW)

4

Older, smaller coal units are likely to retire as

EPA implementation dates approach

EPA regulations make retirement economically rational for approximately

11 GW of PJM coal plants, beginning the transition to clean energy

PJM Coal Capacity by Age

75 GW Total

Environmental Controls on PJM

units < 300 MW

(1)

(1)

Includes

flue

gas

desulfurization

(FGD),

selective

catalytic

reduction

(SCR),

and

selective

noncatalytic

reduction

(SNCR);

status

will

vary

based

on

data

source.

Sources:

Energy

Velocity,

Exelon

estimates

~11 GW

Year in Service

5

5

A shift in the PJM dispatch stack as coal

retires benefits Exelon’s clean nuclear fleet

Sources: CEMS, Energy Velocity, SNL, Exelon estimates

Note: PJM Supply Stack based on existing capacity and expected retirements.

Environmental costs and

coal retirements will shift

the dispatch stack

causing energy prices to

rise $5-7/MWh

6

$134

$74

$110

$174

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2010/2011

2011/2012

2012/2013

2013/2014

2014/2015E

0

50

100

150

200

250

300

PJM capacity auction will also send market price

signals to incent new, clean generation

RPM = Reliability Pricing Model, RTO = Regional Transmission Organization (i.e. Rest of Pool), MAAC = Mid-Atlantic Area Council, EMAAC = Eastern Mid-Atlantic Area Council

Note: Data contained on this slide is rounded.

PJM

RPM

Capacity

Prices

and

Revenues

(1)

Capacity by Region Eligible for 2014/15

RPM

Base

Residual

Auction

(2)

7%

42%

51%

RTO

EMAAC

MAAC

8,700 MW

1,500 MW

10,300 MW

(3)

While results are largely dependent on bidding behavior, Exelon expects increasing

capacity prices beginning in the 2014/15 planning year as coal generators evaluate

environmental compliance costs

~$400 –

$800M

Increase

Revenue

(Left axis)

$180 -

240

(1)

Weighted average $/MW-Day would apply if all owned generation cleared. Prices are rounded.

(2)

All generation values are approximate and not inclusive of wholesale transactions; All capacity values are in installed capacity terms (summer ratings) located in the areas

and adjusted for mid-year PPA roll-offs. John Deere Renewables’ capacity is not included.

(3)

Reflects decision in December 2009 to permanently retire Cromby Station and Eddystone Units 1&2 as of 5/31/11. None of these 933 MW cleared in the 2011/2012 or 2012/2013

auctions.

7

Post-MACT Real Required ATC Price (Energy + Capacity)

$0

$20

$40

$60

$80

$100

$120

$140

$160

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

TWh

Energy Efficiency

Uprates

Coal Retirement

CCGT

Coal-to-Gas Redispatch

Merchant Wind

New Nuclear

Solar

Clean Coal

Exelon 2020 Supply Curve shows how PJM

can clean the dispatch stack

Supply Curve shows

the increasing

energy and capacity

prices needed to

make clean energy

investments

economic

Exelon is focused on

the lowest cost

alternatives

The supply curve is guiding Exelon’s strategy and investment decisions, including

nuclear uprates, energy efficiency and coal retirements

1

1

2

3

3

Note: Represents a single economic and power market outlook, which is indicative of a range of scenarios.  See slide 40 for additional details.

CCGT = Combined Cycle Gas Turbine, HAPs MACT = Hazardous Air Pollutant Maximum Achievable Control Technology as designated by the EPA.

1

Energy efficiency

2

Exelon’s uprate investments

Exelon Investments

3

Coal retirements resulting from Transport

Rule and HAPs MACT, respectively;

includes Eddystone and Cromby

8

Post-MACT Real Required ATC Price (Energy + Capacity)

$0

$20

$40

$60

$80

$100

$120

$140

$160

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

TWh

Energy Efficiency

Uprates

Coal Retirement

CCGT

Coal-to-Gas Redispatch

Merchant Wind

New Nuclear

Solar

Clean Coal

Exelon’s nuclear uprate program is one of the most

economically attractive ways to add clean generation

in PJM

1,300 –

1,500

2015-17

325

2012

405

2013

430

2014

200

2011

Uprate MWs to be brought on

line (cumulative)

(1)

Year

Unique:

Size and scale of nuclear fleet is a competitive advantage

Economic:

IRRs meet hurdle rate under a number of gas and power price scenarios

Flexible:

A series of 19 separate projects across all but 1 of our nuclear plants

Low Risk:

Not contingent on loan guarantees to merchant plants

Earnings Accretive:

For EPUs only, annual EPS impact of $0.30 -

$0.50 per share

once all MW online

Exelon’s nuclear uprates are another example in Exelon’s long history of

effective capital stewardship

(1)

Includes TMI and Clinton Extended Power Uprates, which are currently under review.

9

ComEd and PECO play a key role in support of

clean, competitive markets

West Loop Phase II –

supporting

reliability

•

Ensures reliable service to the Chicago Central

Business District in the event that Fisk and Crawford

stations

(1)

become unavailable

•

Estimated cost of $178M

•

Late 2011 expected in-service date

•

Immediate benefits including redundancy

Electric Vehicles –

exploring

opportunities for infrastructure

investment

•

~$3M in Federal stimulus funds to expand green fleet

•

Deploy vehicle smart charging stations

•

Study vehicle performance, environmental and

electrical load effects

Upgrades related to ExGen’s Cromby and

Eddystone retirements

(2)

–

ensuring

reliability of the grid

•

Facilities identified and plans approved by PJM

•

Total estimated cost of $44M

•

All projects under construction or in engineering status

Smart Grid –

delivering customer-valued

services

•

~$200M in Federal stimulus funds for deployment

•

Operational improvements and efficiency gains will

allow continued cost savings

•

Programs will enable customers more control over

usage and rate structures

Our utilities are advancing regulatory recovery for Smart Grid investments

and investing in system improvements to protect and grow value

(1)

Crawford and Fisk generating stations are owned and operated by Midwest Generation, a subsidiary of Edison International.

(2)

Cromby Units 1 and 2 to retire effective 5/31/11 and 12/31/11, respectively.  Eddystone Units 1 and 2 to retire effective 5/31/11 and 6/01/12, respectively.

Investing in Transmission

Investing in New Technologies

10

RPS Requirements and Wind Projections

0

5,000

10,000

15,000

20,000

2010

2011

2012

2013

0

5,000

10,000

15,000

20,000

Wind Projection -

East MISO and PJM

Wind Projection -

West MISO and

ComEd

Existing Wind - East

MISO and PJM

Existing Wind - West

MISO and ComEd

Required Wind MW

of State RPS

10

Acquisition of John Deere Renewables (JDR) positions

Exelon as a key player in the US wind market

Exelon’s future development of our wind pipeline will be compatible with the price

signals

of

the

Exelon

2020

supply

curve

and

will

require

PPAs

to

be

in

place

$150M/year EBITDA run-rate from

JDR

(1)

Only moderate wind growth

expected through 2013

•

Additional 4 GW in PJM and

MISO from 2011-13

•

Renewable Portfolio Standards

(RPS) are met through 2013

Incremental development largely

dependent on transmission and cost

allocation

Federal RPS could accelerate

transmission development decisions

JDR Acquisition Key Dates:

Texas regulatory approval filed 9/17

FERC/HSR approval filed 9/30

Financing completed 9/30

Projected closing December 2010

(1) Including Production Tax Credits and Michigan development projects.

11

11

Exelon is pursuing backbone high-voltage

transmission investment in the Midwest

First anchor project from the

SMARTransmission Study

Memorandum of Understanding signed

with ETA (AEP & MidAmerican joint

venture company) to pursue the project

~420 miles of 765kV transmission

stretches from Northern Illinois to Ohio. 

The RITE Line will be built from the

existing 765kV system in Ohio in the East

to the West

Ensures reliability, enables states to meet

RPS standards, and supports the

integration of more renewables

Total Investment ~$1.6 billion

•

ComEd/Exelon ~$1.1 billion

•

AEP/ETA ~$500 million

FERC incentive rate joint filing anticipated

for 1Q 2011

Transmission

investment

via

the

“RITE

Line”

creates

value

for

Exelon

and

supports further clean energy development

Note: ETA = Electric Transmission America

12

Corporate

$100 , 1%

Regulated -

Base

Capital (incl. New

Business)

$5,725 , 45%

ExGen

Base Capex

(excl. Nuclear Fuel)

$3,225, 26%

Regulated -

Smart

Grid/Energy

Efficiency

$375 , 3%

Investment in 

Renewables

$1,400 , 11%

Uprates

$1,775, 14%

Exelon’s investments in clean energy and

competitive markets create value

Nearly 30% of total

non-fuel capital

expenditures

supports our goal

of being clean in

competitive

markets

When combined with proactive efforts to inform and shape policy,

Exelon has

allocated resources to the areas where its long-term value is maximized

Note: Uprates excludes TMI and Clinton Extended Power Uprates, which are under review.  Investment in Renewables includes $900 million acquisition of John Deere Renewables,

which is expected to close in 4Q10, and related development capital expenditures.

2010 –

2013 Exelon Investment

$ millions

•

IRRs range

from 11 –

16%

•

John Deere Renewables

contributing $150M run-

rate EBITDA

(1)

•

Regulated returns at

ComEd and PECO

(1) Including Production Tax Credits and Michigan development projects.

13

$1.76

$0.85

$0.88

$0.96

$1.26

$1.60

$1.60

$2.03

$2.10

$2.10

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010E

Strong, stable dividend remains a key

component of shareholder value return

Note: CAGR= Compound Annual Growth Rate. Chart represents dividends per share paid by Exelon for 2001-2009 and expected dividend for 2010, which is subject

to Board approval.

(1)

Dividend yield as of October 25, 2010. Competitive Integrated Yield average includes AYE, CEG, EIX, ETR, FE, NEE, PPL, and PEG.

Regulated Integrated Yield

average includes AEP, AEE, D, DTE, DUK, PCG, PGN, SO, WEC, and XEL.

(2)

2001 dividend excludes $0.065 per share pro-rata dividend related to the Unicom-PECO merger.

Exelon currently offers one of the highest yields among its peers

Dividend Yield

(1)

Exelon: 5.1%

Competitive Integrateds: 4.4%

Regulated Integrateds: 4.6%

Historical CAGR (2001-2010) ~10%

(2)

14

Financial and Operating Data

*

*

*

*

*

*

*

*

*

*

*

15

The Exelon Companies

’09 Earnings:

$2,092M 

’09 EPS:

$3.16

Total Debt:

(1)

$3.7B

Credit Rating:

(2)

BBB

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘09 Operating Earnings:

$2.7B

‘09 EPS:

$4.12

Assets:

(1)

$50.9B

Total Debt:

(1)

$12.9B

Credit Rating:

(2)

BBB-

Note: All ’09 income numbers represent adjusted (Non-GAAP) Operating Earnings and EPS. Refer to slide 91 for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(1)

As of September 30, 2010.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of October 26, 2010.

Pennsylvania

Utility

Illinois

Utility

’09 Earnings:

$356M

$354M

’09 EPS:

$0.54

$0.54

Total Debt:

(1)

$5.3B

$2.6B

Credit Ratings:

(2)

A-

A-

16

Mid-Atlantic Capacity

Owned:

11,034 MW

Contracted:

336 MW

Total:

11,370 MW

16

Multi-Regional, Diverse Company

Note: Owned megawatts as of December 31, 2009 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.

Does not include megawatts from acquisition of John Deere Renewables announced on August 31, 2010.

Midwest Capacity

Owned:

11,412 MW

Contracted:

2,900 MW

Total:

14,321 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

182 MW

Electricity Customers: 1.6M

Gas Customers:          0.5M

Electricity Customers: 3.8M

Generating Plants             

Nuclear

Hydro

Coal

Gas/Oil Intermediate

Peakers

Wind

Solar/Methane

Total Capacity

Owned:

24,850 MW

Contracted:

6,153 MW

Total:

31,003 MW

17

Operating Earnings Guidance

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$3.95 -

$4.10

(1)

$0.65 -

$0.70

$0.50 -

$0.55

$2.90 -

$3.00

(1) Refer to slide 92 for reconciliation of (non-GAAP) operating EPS to GAAP EPS.

2010

operating

earnings

guidance

is

$3.95-$4.10/share

(1)

;

2011 guidance to be provided in early 2011

Guidance to be provided in early

2011, which will include:

•

Operating EPS –

Consolidated and

by Operating Company

•

Key earnings drivers

•

O&M guidance, including pension

and OPEB expense

•

Cash flow and credit metrics outlook

•

Load forecast for ComEd and PECO

service territories

2011

2010

18

Capital Expenditures Expectations

(1)

Nuclear fuel shown at ownership, including Salem.

(2)

Excludes TMI and Clinton EPUs, which are under review.

(3)

Does not include $900 million related to acquisition of John Deere Renewables.

(4)

ComEd not plan to move forward with these Smart Grid/Meter investments unless appropriate cost recovery mechanisms are in place.

Note:  Capital investment related to RITE Transmission Line is not included.

$ millions

1,925

2,025

2,125

1,900

2,050

900

850

1,025

1,075

1,050

275

200

650

875

475

75

50

75

150

75

200

300

275

200

175

$0

$750

$1,500

$2,250

$3,000

$3,750

$4,500

2009

2010E

2011E

2012E

2013E

Base CapEx

Nuclear Fuel

Nuclear Uprates and Solar/Wind

Smart Grid

New Business at Utilities

Exelon

$3,275

$3,400

$4,075

$4,275

2009

2010E

2011E

2012E

2013E

Exelon Generation

Base CapEx

875

800

825

800

800

Nuclear Fuel

(1)

900

850

1,025

1,075

1,050

Nuclear Uprates

(2)

150

275

475

550

475

Solar / Wind

(3)

50

-

175

325

-

Total ExGen

1,975

1,925

2,500

2,750

2,325

ComEd

Base CapEx

650

775

850

650

800

Smart Grid/Meter

(4)

50

50

25

100

25

New Business

150

125

125

200

225

Total ComEd

850

950

1,000

950

1,050

PECO

Base CapEx

350

425

425

425

425

Smart Grid/Meter

-

25

50

50

50

New Business

50

50

75

75

75

Total PECO

400

500

550

550

550

Corporate

50

25

25

25

25

$3,950

Note: Data contained on this slide is rounded.

19

Credit Metric Outlook

Financing plans, including incremental debt, designed to maintain credit metrics and

investment grade rating, while funding growth projects and meeting future

obligations, including uprates, dividend and pension

Evaluated under a variety of economic scenarios, including a low

gas stress case

environment

Evaluate the credit of each company on a stand-alone basis

ExGen/Corp FFO/Debt credit metrics are expected to be within target range

through 2013 without an equity issuance, based on 9/30 forward prices

0%

10%

20%

30%

40%

2007

2008

2009

2010E

ExGen/Corp

ComEd

PECO

Base Case FFO / Debt

(3)

Company

FFO/Debt

Target Range

(1)

ExGen/Corp

(2)

30-35%

ComEd

15-18%

PECO

15-18%

(1)

See slide 28 for FFO/Debt reconciliations to GAAP. FFO/Debt metrics include the following standard adjustments: debt equivalents for PV of Operating Leases, PPAs, unfunded

Pension and OPEB obligations (after-tax) and other minor debt equivalents.  Debt is imputed for estimated pension and OPEB obligations by operating company.

(2)

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

(3)

Reflects impacts of preliminary agreement with IRS to settle involuntary conversion and Competitive Transition Charge (CTC) positions ($420M) at ComEd.  Expected to return to

target levels in 2011. For additional information see “Other Income Tax Matters” under Footnote 10 of the Q3 2010 Form 10-Q.

20

Projected 2010 Key Credit Measures

14.2x

9.5x

FFO / Interest

Generation /

Corp:

62%

35%

FFO / Debt

54%

69%

Rating Agency Debt Ratio

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB+

BBB+

Fitch Credit

Ratings

(3)

A3

A1

Baa1

Baa1

Moody’s Credit

Ratings

(3)

2.0x

2.4x

FFO / Interest

ComEd:

7%

(4)

8%

(4)

FFO / Debt

43%

52%

Rating Agency Debt Ratio

4.6x

5.1x

FFO / Interest

PECO:

25%

23%

FFO / Debt

47%

50%

Rating Agency Debt Ratio

31%

48%

Rating Agency Debt Ratio

85%

43%

FFO / Debt

21.3x

11.7x

FFO / Interest

Generation:

48%

32%

6.2x

Without PPA &

Pension / OPEB

(2)

59%

Rating Agency Debt Ratio

23%

FFO / Debt

5.9x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

and

PECO

metrics

exclude

securitization

debt.

See

slide

28

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

FFO/Debt

metrics

include

the

following

standard

adjustments:

debt

equivalents

for

PV

of

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax)

and

other

minor

debt

equivalents.

(2)

Excludes

items

listed

in

note

(1)

above.

(3)

Current

senior

unsecured

ratings

for

Exelon

and

Exelon

Generation

and

senior

secured

ratings

for

ComEd

and

PECO

as

of

October

26,

2010.

(4)

Reflects

impacts

of

preliminary

agreement

with

IRS

to

settle

involuntary

conversion

and

CTC

positions

($420M).

Expected

to

return

to

target

levels

in

2011.

For

additional

information

see

“Other

Income

Tax

Matters”

under

Footnote

10

of

the

Q3

2010

Form

10-Q.

21

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

Asset acquisitions

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 $7.4B)

Use of guarantees

(versus letters of credit)

to fulfill NRC

requirements for Nuclear

Decommissioning Trust

obligations

Business and

Financial

Flexibility

Reliable access to

long-term debt

markets to meet

sizeable capital

program

Lower cost and

ability to extend

debt maturity profile

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

22

Sufficient Liquidity

--

--

--

--

Outstanding Facility Draws

(430)

(226)

(1)

(196)

Outstanding Letters of Credit

$7,365

$4,834

$574

$1,000

Aggregate Bank Commitments

(1)

6,935

4,608

573

804

Available Capacity Under Facilities

(2)

--

--

--

--

Outstanding Commercial Paper

$6,935

$4,608

$573

$804

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

Available Capacity Under Bank Facilities as of October 25, 2010

Exelon bank facilities are largely untapped

(1)

Excludes previous commitment from Lehman Brothers Bank and commitments from Exelon’s Community and Minority Bank Credit Facility.

(2)

Available Capacity Under Facilities represents the unused bank commitments  under the borrower’s credit agreements net of outstanding  letters of credit and facility draws. The 

amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(3)

Includes other corporate entities.

23

23

23

Credit Facility Plans

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

the money pool

(1)

and cash on hand

Current total credit facility size is $7.4 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

Bank market continues to improve and facility costs are tightening

Exelon Corp + Exelon Generation

•

$5.8 billion facilities largely expire October 26, 2012 -

plan to extend/refinance the facilities in first half of 2011

•

Continued use of non-margining transactions and currently evaluating alternatives to reduce reliance on bank credit

PECO

•

$574 million facility largely expires on October 26, 2012 -

plan to extend/refinance the facility in first half of 2011

ComEd

•

Successfully executed $1 billion revolving credit facility agreement which will expire on March 25, 2013

Replaces previous $952 million facility that was due to expire on 2/16/11

•

Reflects strong relationships with large, diverse bank group

22 banks in facility –

none with exposure of more than 6%

Recently closed on a $94 million 364-day credit facility with a group of 29 community and

minority-owned banks

(1)  ComEd does not participate in the money pool.

24

Pension and OPEB Funding

Pension Protection Act of 2006

("PPA 2006") generally requires

funding of qualified pension plans

over a seven year period; OPEB

plans do not have a required funding

level

(1)

Pension unfunded amounts are

imputed as debt by S&P and

Moody’s in the FFO/Debt

calculation; S&P also imputes debt

for OPEB

Exelon monitors economic conditions, funding election options and pension

funding relief to ensure efficient funding policies are employed

$2,736

$4,460

Unfunded Status

$30 / $250

$5

OPEB

$85 / $950

$45

Sensitivities to a 50 basis point change

(3)

Discount rate (cost / obligation)

EROA (cost)

(4)

Pension

As of 9/30/10                   ($ millions)

Pension Framework

Exelon’s Position

Exelon’s estimated pension contributions

include the minimum amount required under

ERISA, including amounts necessary to avoid

benefit restrictions and at-risk status as defined

by PPA 2006

(2)

OPEB contributions are based on various

factors, including tax deductibility and levels of

benefit claims

Plan to fund obligations with combination of

cash and debt

(1)  PECO is subject to certain contribution requirements established by the PAPUC.

(2)  PPA 2006 requires attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits) and at-risk status (which triggers 

       higher minimum contribution requirements and participant notification).

(3)  Sensitivities are averages meant to provide directional guidance and are not necessarily symmetrical for increases and decreases in rates.  Cost sensitivities shown include ~25% 

       overall capitalization of pension costs.

(4)  EROA = Expected return on assets; represents impact on cost. The expected return on assets assumption for pension is 8.00% and 7.37% for OPEB for 2011 and 2012.

25

Potential Variability in Future Pension

Expense and Contributions

$1,330

$3,345

$355

$1,235

$4,595

$450

5.83% in 2010

4.22% in 2011

4.57% in 2012

4.00% in 2010

8.00% in 2011

12.59% in 2012

Alternative II

V-Shaped Recovery

Unfunded balance –

end of year

$835

$1,120

$220

$735

$2,180

$305

5.83% in 2010

5.38% in 2011

6.40% in 2012

4.00% in 2010

7.60% in 2011

5.22% in 2012

Alternative I

Mild Stagflation

Unfunded balance –

end of year

$900

$2,870

$320

$910

$3,800

$350

5.83% in 2010

5.01% in 2011

5.15% in 2012

4.00% in 2010

8.00% in 2011

8.00% in 2012

Baseline as of September 30,

2010

Unfunded balance –

end of year

Expected

contribution

Pre-tax

expense

Expected

contribution

Pre-tax

expense

Discount Rate

Asset Return

Experience

($ in millions)

Illustrative Scenario

Assumptions

2011

2012

2010: Exelon estimates pre-tax 2010 pension expense of $245 million and 2010 pension contributions of $765 million.

(1)  Pension expenses include settlement charges.

(2) The contributions shown above include estimated pension contributions required under ERISA, as amended, and contributions necessary to avoid benefit

restrictions and at-risk status, as defined by the Pension Protection Act of 2006. 

(3) The expected return on assets assumption for all scenarios above is 8.00% for 2011 and 2012.

Note: Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes ~25% overall capitalization of pension costs.

26

Potential Variability in Future OPEB

Expense and Contributions

2010:

Exelon

estimates

pre-tax

2010

OPEB

expense

of

$190

million

and

2010

OPEB

contributions

of

$190

million.

(1) Expense estimates do not include the impact of health care reform legislation (including excise tax).

(2) The contributions shown above are subject to change.

(3) The expected return on assets assumption for all scenarios above is 7.37% for 2011 and 2012.

Note:

Slide

provided

for

illustrative

purposes

and

not

intended

to

represent

a

forecast

of

future

outcomes.

Assumes

~25%

overall

capitalization

of

OPEB

costs.

$205

$2,820

$260

$200

$2,730

$265

5.83% in 2010

4.22% in 2011

4.57% in 2012

3.52% in 2010

7.37% in 2011

11.58% in 2012

Alternative II

V-Shaped Recovery

Unfunded

balance

–

end

of

year

$205

$1,755

$190

$200

$1,910

$210

5.83% in 2010

5.38% in 2011

6.40% in 2012

3.52% in 2010

6.99% in 2011

4.80% in 2012

Alternative I

Mild Stagflation

Unfunded

balance

–

end

of

year

$195

$2,430

$240

$190

$2,440

$230

5.83% in 2010

5.01% in 2011

5.15% in 2012

3.52% in 2010

7.37% in 2011

7.37% in 2012

Baseline as of September 30,

2010

Unfunded

balance

–

end

of

year

Expected

contribution

Pre-tax

expense

Expected

contribution

Pre-tax

expense

Discount Rate

Asset Return

Experience

($ in millions)

Illustrative Scenario

Assumptions

2011

2012

27

Debt Maturity Profile

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

Debt maturities over the next several years are manageable

Exelon Corp

Exelon Generation

ComEd

PECO

As of October 1, 2010

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

2031

2033

2035

2037

2039

2041

28

FFO Calculation and Ratios

+    Other Non-Cash items

(1)

-

AFUDC/Cap. Interest

-

Decommissioning activity

+/-

Change in Working Capital

FFO Calculation

= FFO

-

PECO Transition Bond Principal Paydown

Net Cash Flows provided by Operating Activities

Net Interest Expense

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ Interest on Present Value (PV) of Operating Leases

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

(PPA)

+ AFUDC & Capitalized interest

-

PECO Transition Bond Interest Expense

FFO Interest Coverage

FFO

= Adjusted Debt

+

Off-balance

sheet

debt

equivalents

(2)

-

PECO Transition Bond Principal Balance

+ Short-term Debt

+ Long-term Debt

Debt:

Adjusted Debt

(3)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+

Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+

Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ Short-term Debt

+ Long-term Debt

Debt:

Debt to Total Cap

(1)

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

(2)

Metrics are calculated in presentation unadjusted and adjusted for debt equivalents for PV of Operating Leases, PPAs, unfunded Pension and OPEB

obligations (after-tax), Capital Adequacy for Energy Trading and other minor debt equivalents.

(3)

Uses current year-end adjusted debt balance.

29

Environmental

*

*

*

*

*

*

*

*

*

*

*

*

30

Recognition for

Sustainability and

Environmental Leadership

Named to the 2010 Carbon

Disclosure Leadership Index

Included in the Dow Jones

Sustainability North America Index for

the fifth consecutive year

Exelon’s 2020 Plan: a low

carbon roadmap

Exelon continues to be recognized for our 2020 plan to reduce, offset or

displace our company’s 2001 carbon footprint by the year 2020

31

EPA Regulations –

Market Implications

Leading up to 2012 Compliance

Notes:

RPM

auctions

take

place

annually

in

May.

For

definition

of

the

EPA

regulations

referred

to

on

this

slide,

please

see

the

EPA’s

Terms

of

Environment

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

32

0

200

400

600

800

1,000

0

50

100

150

200

Source: M.J. Bradley & Associates (2010). Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States.

Bubble size represents sulfur dioxide intensity, expressed in

terms of metric tons of SO2 per TWh generated

2008 Gross Generation (TWh)

Clean, Efficient Fleet Well Positioned for

Environmental Regulations

SO2 Emissions of Largest U.S. Electricity Generators

Using SO2 emissions as a proxy for hazardous air pollutants, Exelon well

positioned for Hazardous Air Pollutant ruling in 2011

Exelon

Competitive Integrated / IPP

Regulated Integrated

33

Why EPA Regulations Will Not Be Delayed

Opposition will have a voice, but the framework and timetable have been set

Each NERC region has excess capacity,

totaling over 100 GW nationwide

Between 2001-2003, industry built over 160 GW

of new generation –

four times what is projected

will retire over next 5 years

EPA's modeling indicates that only 14 GW of

additional capacity would need to be retrofitted

with flue gas desulfurization (FGD) for Phase 2

of the Transport rule (2014)

Industry has already demonstrated ability to

schedule and sequence outages to comply

Well over half of existing units have already

installed pollution controls

EPA estimates in 2014 that the proposed

Transport Rule will have annual net benefits (in

2006$) of $120-290 billion using a 3% discount

rate

Up to 1 year extension by EPA only if necessary

for installation of controls

President has only used exemption two times in

history (only for national security interests)

Supporting Facts

Electric system reliability will not be

compromised if the industry and its

regulators manage the transition

Retirements will cause

reliability issues on the

grid

Recent industry trends suggest that it

is reasonable to install this quantity of

scrubbers according to the proposed

timeframe.

Timeline is too tight for

compliance

Proven technologies are commercially

available and have already been

installed demonstrating that the costs

can be managed

Total savings to consumer, including

healthcare impacts

Costs are prohibitive for

industry and consumer

Federal court would have to determine

that the rules are inconsistent with

applicable law, which is unlikely to

occur because the amended rules are

aligned with the court’s expectations

Courts will suspend the

rules or the President will

intervene

Reality

Opposing Argument

34

34

Providing Relief in Extreme Cases:

Statutory and Regulatory Safeguards

Override CAA-derived control requirements in limited emergency

circumstances.

Section 202(c) of the

Federal Power Act

U.S.

Department of

Energy

Agency

Source of Authority

Supporting Language

EPA

Section 112(i)(3)(B)

of

the Clean Air Act

The Administrator (or a State with a program approved under

subchapter V of this chapter) may issue a permit that grants an

extension

permitting

an

existing

source

up

to

1

additional

year

to

comply with standards under subsection (d) of this section if such

additional period is necessary for the installation of controls.

U.S. President

Section 112(i)(4) of

the Clean Air Act

The

President

may

exempt

any

stationary

source

from

compliance

with

any standard or limitation under this section for a period of not more

than 2 years if the President determines that the technology to

implement

such

standard

is

not

available

and

that

it

is

in

the

national

security

interests

of

the

United

States

to

do

so.

An

exemption under this paragraph may be extended for 1 or more

additional periods, each period not to exceed 2 years. The President

shall report to Congress with respect to each exemption (or extension

thereof) made under this paragraph.

Extensions for plants to comply will be on a plant-by-plant basis, for a

limited

time

period,

and

only

if

specific

“tests”

are

met

35

EPA Clean Air Standards Will Not Threaten

Electric System Reliability

(1) M.J. Bradley & Associates, LLC and Analysis Group

2010.  Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability.

Full study available at www.mjbradley.com/documents/MJBAandAnalysisGroupReliabilityReportAugust2010.pdf.

Proactive steps by EPA, the industry and other agencies will allow orderly plant

retirements without impacting system reliability

M.J. Bradley and Analysis Group report

(1)

in August 2010 concluded industry is

well-positioned to respond to proposed standards

•

System has >100 GW of excess capacity

•

Regulators have tools to address localized reliability concerns,

including appropriate

price signals from capacity markets

•

Industry has proven track record of adding generation capacity and transmission

solutions

New clean air standards will help modernize US power generation infrastructure

•

Proven technologies for controls are commercially available: >50% of coal units have

installed controls demonstrating that compliance costs can be managed

•

Pollution-intensive plant retirements will create room for cleaner, more efficient

generation

36

Retiring Cromby Station and

Eddystone Units 1&2

Agreed to delay deactivation of two units to maintain reliability

(1)

, provided receipt

of required environmental permits and adequate cost-based compensation

•

Maintained

scheduled

retirement

date

of

5/31/11

for

Cromby

1

and

Eddystone

1

•

Revised retirement dates for Cromby 2 to 12/31/11 and Eddystone 2 to 6/01/12

RMR filed with FERC in 2Q10

•

Establishes terms and conditions under which Cromby 2 and Eddystone 2 will operate during RMR

period

•

Allows Exelon to recover costs of operating and maintaining units under Cost of Service Recovery

Rate

–

Estimated at $2.6 million per RMR-month for Cromby Unit 2 and $8.8 million per RMR-month for

Eddystone Unit 2, plus recovery of project investment

•

In September 2010, FERC issued order accepting RMR filing, but set matter for hearing to review

additional information to justify Cost of Service mentioned above

•

Currently in settlement discussions with interveners; targeting final approval by 4Q10

RMR Unit Operating Limitations

•

Dispatched and operated solely for reliability purposes

•

Unable to bid into PJM RPM capacity auctions

(1)

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

Note: RMR = reliability must-run agreement.

Exelon’s experience with Cromby Station & Eddystone units 1 and 2 is an

example of how to work with stakeholders to reliably retire uneconomic coal

37

37

Exelon’s Exposure to EPA Regulations

Significant, primarily fossil

fuel-fired generation

None

None

(5)

GHG Tailoring

Rule

Compliance costs of up to

$2.8 billion / year

~$100 million

None anticipated

Keystone & Conemaugh

(3)

Fossil-fuel fired units >25 MW: ~4,000 MW

(4)

Criteria

Pollutants /

CATR

Significant, primarily fossil

fuel-fired generation

Included in CATR costs

Impact to be determined

Keystone & Conemaugh

(3)

Oil-Fired Units >25 MW: ~935 MW

Hazardous Air

Pollutants

Significant, impacts all fuel

types including large base

load and intermediate units

Compliance costs up to $20

billion

Industry Impact

(2)

EPA Regulation

Units Affected

Exelon Investment

Needed

(1)

Coal combustion

waste

Keystone & Conemaugh

(3)

Subtitle C: < $100 million

(6)

Subtitle D: no impact

316(b) or Cooling

Water

Facilities without closed-cycle recirculating

systems (e.g. cooling towers)

POWER:  Schuylkill, Eddystone 3 & 4,

Fairless Hills, Mountain Creek, Handley

NUCLEAR:  Clinton, Dresden, Quad Cities,

Oyster Creek, Peach Bottom, Salem

Impact to be determined

once rule is promulgated;

Cost to retrofit Oyster

Creek and Salem

estimated at $700-800

million and $500 million,

respectively

(3)

(1)

These

rules

are

in

the

proposed

or

pre-proposed

stage

and

estimates

are

based

on

published

cost

studies

used

as

inputs

to

IPM

modeling.

(2)

EPA’s estimated costs, where applicable.

(3)

Investment needed shown is Exelon’s share of the cost.  Exelon owns 21% share in Keystone and Conemaugh and 42.59% share in Salem.  Keystone & Conemaugh

units all have scrubbers and Keystone units have SCRs.  Oyster Creek and Salem investment estimates based on 2006 studies.

(4)

Exelon’s existing coal-fired units will be retired before this rule will take effect.

(5)

This rule applies only to new sources or major modifications of existing sources.

(6)

Excludes Eddystone 1 and 2 and Cromby, which are scheduled to retire in 2011 and 2012.

38

Clean Air Transport Rule

EPA proposed the Transport Rule on July 6, 2010 to

replace CAIR (Clean Air Interstate Rule)

•

Exelon filed comments in support of Transport

Rule on October 1

•

Final rule expected from EPA by June 2011

Would require 31 states and the District of Columbia

to significantly improve air quality by reducing power

plant emissions that contribute to ozone and fine

particle pollution in other states

•

Requires significant reductions in sulfur dioxide

(SO2) and nitrogen oxide (NOx)

EPA estimates annual compliance cost at $2.8 billion,

but would yield healthcare savings of $120 -

$290

billion in 2014

EPA has proposed three implementation alternatives

for public comment, but its preference is the "State

Budgets/Limited Trading" option that establishes state-

specific emission budgets and allows for intrastate and

limited interstate trading

Compliance set to begin on January 1, 2012

Source: EPA

39

Exelon’s View on FERC NOPR

On June 17, 2010, FERC issued a Notice of Proposed Rulemaking (NOPR) on

Transmission Planning and Cost Allocation.  NOPR proposals include:

•

Modify planning processes for public policy mandates, such as renewable energy

standards (RES)

•

Increase intra-

and inter-regional planning coordination

•

Eliminate existing preferences in FERC tariffs for incumbent transmission facility

developers to build needed transmission

•

Embrace broad application of “beneficiary pays”

standard for cost allocation

Exelon generally supports the NOPR and proposes the following:

•

Mandate stronger inter-regional planning requirements, such as PJM coordination with

MISO to accommodate new transmission

•

Maintain the right of first refusal by incumbent transmission owners for local reliability

projects

•

Require planning for enforceable state public policy mandates, as well as EPA rules

that affect capacity requirements

•

Allocate costs to loads that benefit

Exelon continues to advocate for fair and appropriate planning rules for new

transmission to address state and federal policy

40

Post-MACT Real Required ATC Price (Energy + Capacity)

$0

$20

$40

$60

$80

$100

$120

$140

$160

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

TWh

Energy Efficiency

Uprates

Coal Retirement

CCGT

Coal-to-Gas Redispatch

Merchant Wind

New Nuclear

Solar

Clean Coal

Exelon 2020 Supply Curve –

Supporting Details

Note: Represents a single economic and power market outlook, which is indicative of a range of scenarios.

Category

Explanation

Energy Efficiency (EE)

The first 1% of a 4.25% total EE target, which would be in line with a 17% RPS

target that allows up to a quarter of the target to be met with EE.

Uprates

Exelon's MURs and LP Turbines.

Coal Retirement

Capacity expected to retire due to power prices (based on low gas) and CATR. 

Eddy and Cromby are representative of this bucket.

Uprates

Exelon's EPUs

EE

The next 2% of a 4.25% total EE target.

Coal Retirement

Additional capacity that retires as a result of HAPs MACT regulation.  Total of

11 GW of coal expected to retire between this bar and the first coal retirement

bar.

CCGT

New CCGTs that get built in PJM by 2020 due to expected impact from MACT

and nominal demand growth.

Coal Retirement

Incremental retirements that would result from CATR + a carbon price (no MACT

assumed).

Coal-to-Gas Redispatch

Incremental gas-fired generation -- displacing generation that would otherwise

come from coal (not coal retirements)

EE

The last 1.25% of a 4.25% total EE target

Coal-to-Gas Redispatch

Incremental gas-fired generation resulting from a higher carbon price.

Uprates

Uprates at nuclear plants that are not currently planned.  Assumed to be

subsidized cost of a new nuclear plant.

Coal Retirement

Incremental retirements that would result from CATR + MACT + carbon price.

Coal-to-Gas Redispatch

Incremental gas-fired generation resulting from a higher carbon price.

Wind

Western PJM half of total new wind build of 13 GW resulting from 17% RPS

target (wind is assumed to meet this target, less the 25% contribution from EE).

Wind

Eastern PJM half of total new wind build of 13 GW resulting from 17% RPS

target (wind is assumed to meet this target, less the 25% contribution from EE).

New Nuclear

Estimate of constructing new nuclear unit

Clean Coal

Estimate of constructing a clean coal plant

Solar

Solar installation in the Pennsylvania market.

41

*

*

*

*

*

*

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

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

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

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

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

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

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

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

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

42

75

80

85

90

95

100

Range

5-Year Average

World-Class Nuclear Operator

Nuclear Production Cost ($/MWh)

(1)

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

lowest-cost producers of electricity in the nation

Range of Fleet 2-Yr Avg Capacity Factor (2005-2009)

(2)

EXC 93.8%

Operator

(1)

Source: 2009 Electric Utility Cost Group (EUCG) survey. Includes

Fuel Cost plus Direct O&M divided by net generation.

(2)

Source: Platts Nuclear News, Nuclear Energy Institute and Energy

Information Administration (Department of Energy).

$10.00

$12.00

$14.00

$16.00

$18.00

$20.00

$22.00

$24.00

$26.00

$28.00

$30.00

Range

5-Year Average

EXC

Operator

43

0

10

20

30

40

50

60

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Industry (w/o Exelon)

Exelon

Impact of Refueling Outages

Note:

Data

includes

Salem.

Net

nuclear

generation

data

based

on

ownership

interest.

All Exelon owned units on a 24 month cycle

except for Braidwood U1/U2, Byron U1/U2

and Salem U1/U2, which are on 18 month

cycles

Average Outage Duration (2008-9): ~29

days

(1)

Nuclear Refueling Cycle

11 planned refueling outages, including 2 at

Salem

6 refueling outages planned for the Spring

and 5 refueling outages planned for the Fall

2011 Refueling Outage Impact

10 planned refueling outages, including 1 at

Salem

Completed 6 refueling outages in the Spring

with an average duration of 25 days

4 planned Fall refueling outages (Peach

Bottom 2, Oyster Creek, Braidwood 1 and

Dresden 3)

2010 Refueling Outage Impact

(1)  Includes Salem and 23 days of TMI 2009 outage

that extended into 2010 reflecting steam generator

replacement.

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

7

8

9

10

11

12

13

Refueling Outage Duration

Nuclear Output

Actual

Target

# of Outages

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

extended into 2010 reflecting steam generator replacement.

44

Projected Total Nuclear Fuel Spend

$750

$850

$950

$1,000

$1,075

$1,150

0

200

400

600

800

1,000

1,200

1,400

2010

2011

2012

2013

2014

2015

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

Note:

At

100%,

excluding

Salem.

Excludes

costs

reimbursed

under

the

settlement

agreement

with

the

DOE.

Nuclear fuel expense is amortized over three refueling outage cycles

Nuclear fuel capital expenditures are recognized in the period of investment

Exelon Generation is the largest uranium user in the U.S. and uses diverse

sources and contract terms to manage supply

45

Effectively Managing Nuclear Fuel Costs

Uranium

29%

Conversion

3%

Tax/Interest

1%

Nuclear Waste

Fund

17%

Fabrication

16%

Enrichment

34%

Components of Fuel Expense in 2010

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

2010 –

2015:

100% hedged in volume

0.0

2.0

4.0

6.0

8.0

10.0

2010

2011

2012

2013

2014

2015

Exelon Nuclear’s uranium demand is 100%

physically hedged for 2010-2015

Contracted prices continue to be below market

prices

Uranium prices were volatile over last 5 years,

but have stabilized in the $40-$60/lb range

All charts exclude Salem

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010

2011

2012

2013

2014

2015

Exelon Average Reload Price

Projected Market Price

46

Nuclear Uprates Offer Sustainable Value

Key component of Exelon

2020 low carbon roadmap

Creates additional low-

carbon generation

capacity

Uprates equivalent in size

to a new nuclear plant but

significantly lower cost,

shorter timeline, and more

predictable expenditures

No ongoing incremental

O&M expense

Capitalizes on Exelon’s

proven track record of

uprate execution

Dedicated project

management team

Proven technology design

Allows us to adjust timing

to respond to market

conditions

Straightforward regulatory

and environmental

licenses, permits and

approvals

Potential for uprates to

meet state alternative

energy standards

Strategic Value

Regulatory Feasibility

Execution Feasibility

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

operation excellence

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

190–233 MW

$310M

2 years

899–1,015 MW

$2,550M

EPU (Extended Power Uprate)

(2)

•

Through a combination of more sophisticated analysis and

upgrades to plant equipment, uprates can increase output by as

much as 20% of original licensed power level

•

Requires NRC approval

3 -

6

years

239–260 MW

$790M

Megawatt Recovery and Component Upgrades

•

Replacement of major components in the plant occur in the normal

life cycle process –

with newer technology, replacements result in

increased efficiency

•

Equipment includes generators, turbines, motors and transformers

•

Megawatt Recovery and Component Upgrades must conform to

NRC standards, but do not require additional NRC approval

3-4 years

~1,300–1,500 MW

$3,650M

Project

Duration

(1)

In 2010 dollars. Overnight costs do not include financing costs or cost escalation.

(2)

Includes TMI and Clinton EPUs; which are currently under review.

Estimated

Internal Rate

of Return

12-14%

14-16%

11-14%

Refined

scenario

analysis

highlights

that

uprates

continue

to

be

economic,

although TMI and Clinton are under review

48

Multi-Regional Nuclear Uprate Program

94

2

19

12

61

MW Online

to Date

2011 / 2012

32

25

Peach Bottom

2011 / 2010

104

97

Quad Cities

2014

15

12

TMI

2014 / 2013

31

25

Dresden

2013 / 2013

23

19

Quad Cities

2012 / 2012

42

34

Byron

2012 / 2012

42

34

Braidwood

2011 / 2011

41

33

Limerick

2011 / 2011

39

35

LaSalle

2014 / 2015

3

3

Peach Bottom

MUR:

2012 / 2013

6

6

Limerick

2012 / 2013

110

103

Dresden

2011 / 2012

5

5

Dresden

EPU:

MW Recovery & Component Upgrades:

2016 / 2017

340

306

Limerick

1,508

1,331

Total

172

336

17

148

2

Max Potential

MW

2016

138

TMI

2016 / 2015

303

LaSalle

2016

17

Clinton

2015 / 2016

134

Peach Bottom

2010

2

Clinton

Year of Full

Operation

by Unit

Base Case

MW

Station

TMI

Limerick

Peach

Bottom

Total Midwest Uprates:

674-751 MW

Total Mid-Atlantic Uprates:

657-757 MW

Quad

Cities

Dresden

Byron

LaSalle

Clinton

Braidwood

Notes:  MW shown at ownership.  An additional 23 MW expected to come online by end of

2010 at Limerick 1 and Dresden 3.

Executing uprate projects across our

geographically diverse nuclear fleet

Under review

49

Phased Execution Lowers Risk

Note:

MW

shown

at

ownership.

Data

contained

in

this

slide

is

rounded.

(1)

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

(2)

Excludes TMI and Clinton EPUs, which are currently under review.

Exelon's Uprate Plan Expenditures

$0

$100

$200

$300

$400

$500

$600

$700

2008A

2009A

2010E

2011E

2012E

2013E

2014E

2015E

2016E

2017E

0

200

400

600

800

1,000

1,200

1,400

1,600

Megawatt Recovery

MUR

EPU

MW Online (Cumulative)

$150

$275

$475

$550

$475

$600

$625

$425

$200

$ millions

Highest return projects are being completed in the early years

Leverages Exelon’s substantial experience managing successful uprate projects –

1,100 MW completed between 1999 -

2008

$50

Approximately

117

MW

scheduled

to

be

completed

in

2009

and

2010;

total

expenditures

expected

to

be

$3,825

million

from

2008

–

2017

(1)(2)

50

Quad Cities Uprate Program

MW Recovery

•

Unit 2 Low Pressure Turbine Retrofit completed April 2010,

increase of 50 MW achieved

•

Unit 1 Low Pressure Retrofit planned for Spring 2011

•

Partial completion of Unit 1 work has resulted in an increase of

11 MW

MUR

•

Planned start date of project will be in 2011

•

Timing of uprate will be dependent on NRC approval of license

amendment

EPU

•

Completed in 2002

Scheduled start in 2011

1Q2013

9

2Q2013

9

MUR

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

In progress

2Q2010

50

3Q2011

47

MW Recovery (Low Pressure

Turbine Retrofit)

Status

Online

Date

MW

Increase*

Online

Date

MW

Increase*

Uprate Project

Unit 2

Unit 1

Quad Cities Uprate Projects are underway –

additional MWs will come

on line between 2010 and 2013

Capital Investment $M*

$0

$50

$100

2009

2010

2011

2012

2013

2014

2015

2016

MW Recovery and Component Upgrade

MUR

51

Peach Bottom Uprate Program

MW Recovery

•

Project in progress with Low Pressure Turbine Retrofit

installations expected in 2011 and 2012

•

Replace Reactor Recirculation Pump Motor Generator sets

with energy efficient Adjustable Speed Drives in 2014 and

2015

MUR

•

Completed in 2003

EPU

•

Funding approved for design work

•

Will review in 2011 before authorizing installation funding for

physical plant modifications and purchase of materials

Peach

Bottom

Uprate

Projects

are

underway

–

additional

MWs

will

come

online

between 2011 and 2016

Capital Investment $M*

$0

$50

$100

$150

2009

2010

2011

2012

2013

2014

2015

2016

2017

MW Recovery and Component Upgrade

EPU

* Capital investment and MW uprate numbers represent Exelon’s 50% ownership stake in Peach Bottom Station.

In progress

4Q2011

11

4Q2012

14

MW Recovery (Low Pressure

Turbine Retrofit)

Design phase in progress

1Q2016

67

1Q2015

67

EPU

Scheduled to start in 2012

4Q2015

2

4Q2014

2

MW Recovery (Adjustable

Speed Drives)

Status

Online

Date

MW

Increase*

Online

Date

MW

Increase*

Uprate Project

Unit 3

Unit 2

52

Dresden Uprate Program

MW Recovery

•

Project in progress with Low Pressure Turbine Retrofit

installations expected in 2011 and 2012

•

Partial completion of Unit 2 work has resulted in an increase of

12 MW

•

Replace Reactor Recirculation Pump Motor Generator sets

with energy efficient Adjustable Speed Drives in 2011 and

2012

MUR

•

Planned start date of project will be in 2011

•

Timing of uprate will be dependent on NRC approval of license

amendment

EPU

•

Completed in 2002

Dresden Uprate Projects are underway –

additional MWs will come online

between 2011 and 2014

Capital Investment $M

$0

$50

$100

$150

$200

2009

2010

2011

2012

2013

2014

2015

2016

2017

MW Recovery and Component Upgrade

MUR

In progress

4Q2012

3

4Q2011

3

MW Recovery (Adjustable

Speed Drives)

Scheduled start in 2011

1Q2013

12

1Q2014

12

MUR

In progress

1Q2013

51

1Q2012

52

MW Recovery (Low Pressure

Turbine Retrofit)

Status

Online

Date

MW

Increase

Online

Date

MW

Increase

Uprate Project

Unit 3

Unit 2

53

Zion Station Decommissioning

On September 1, 2010, Exelon transferred license to EnergySolutions, which will dismantle

the Zion Nuclear Generating Station

•

Located in Northeast Illinois, Zion ceased operations in 1998

•

Commercial

operations

began

in

1973

for

Unit

1

and

1974

for

Unit

2

$1 billion, 10-year project will be the largest nuclear dismantling ever undertaken in the U.S.

•

Entire cost of decommissioning will be funded through the station’s decommissioning trust fund

•

No operating income statement impact for Exelon

Approval received from Nuclear Regulatory Commission in

first-of-its kind agreement

Exelon will retain ownership of the plant’s

spent nuclear fuel, which must remain on the

property in a secure facility

Once decommissioning is completed,

responsibility for the site will be transferred

back to Exelon

54

Exelon Nuclear Fleet Overview

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

Average in-service time = 29 years

2011

42.6% Exelon, 57.4%

PSEG

In process

(decision in 2011-

2012):  2016, 2020

503, 500

(2)

W

PWR

2

Salem, NJ

2025

100%

Renewed: 2034

837

B&W

PWR

1

TMI-1, PA

Dry cask

100%

Renewed: 2029

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

574, 571

(2)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

655, 662

(2)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

869, 871

GE

BWR

2

Dresden, IL

2010

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask

100%

2024, 2029

1148, 1145

GE

BWR

2

Limerick, PA

2018

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

(3)

GE

W

W

Vendor

BWR

PWR

PWR

Type

1

2

2

Units

100%

2026

1065

Clinton, IL

100%

2024, 2026

1183, 1153

Byron, IL

100%

2026, 2027

1194, 1166

Braidwood, IL

Ownership

License Status /

Expiration

(1)

Net Annual

Mean Rating

MW 2009

Plant, Location

(1)

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

(2)

Capacity based on ownership interest.

(3)

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

core. Dry cask storage will be in operation at those sites prior

to the closing of their on-site storage pools.

License extensions will be pursued for all units not already renewed

55

John Deere Renewables Acquisition –

Transaction Summary

Deal Structure

735 MW operating portfolio spread across 36 projects located in eight states with 230

MW in Michigan in late stage development

$860M purchase price plus up to $40M for Michigan development projects, funded by

$900 million debt issuance at Exelon Generation

75% of the operating portfolio is sold under long-term power purchase arrangements;

86% of contracted portfolio has PPAs through 2026 or beyond

Additional 1,238 MW in development pipeline

EBITDA run-rate of ~$150M/year including Production Tax Credits (and including

Michigan development projects)

Strategic Rationale

Diversify with clean generation –

unique entry point into wind generation

Contracted portfolio with option for future growth

Attractive economics and good fit

Expect to close transaction in 4Q 2010

56

John Deere Renewables Acquisition

Asset Profile

Geographic Distribution

TX, 26%

MO,

22%

MI, 17%

ID, 12%

MN,

11%

OR,

10%

KS, 2%

IL, 1%

Note:

There is ongoing litigation with Southwest Public Service related to PURPA contracts which could affect the price at which the generation from these

units

is

sold.

Cracking

issues

experienced

by

Deere

on

certain

Suzlon

turbine

blades

have

been

addressed

to

our

satisfaction.

We

have

factored

both

items into our valuation.

Project State

MW

# of Wind

Projects

Ownership

Placed in

Service

Date

PPA End

Date

Federal

Incentive

Off-Taker

Idaho

88.2

3

100%

2009/2010

2028/2030

ITC Grant

Idaho Power

Illinois

8.4

1

99%

2008

2018

PTC

Wabash Valley Power

Kansas

12.5

1

100%

2010

2030

PTC

Kansas Power Pool

Michigan

121.8

2

100%

2008

2018/2028

PTC

Wolverine Power Supply

/ Consumers Energy

Minnesota

77.7

9

94%-100%

2003/2008

2018/2028

PTC

Various

Missouri

162.5

4

99%-100%

2008

2027

PTC

Associated Electric /

MO Joint Municipal

Oregon

74.5

4

99%-100%

2009

2029

ITC Grant

PacifiCorp

Texas

189.8

12

100%

2006/2009

N/A

PTC

Southwest Public Service

Total

735.4

36

Additional 1,238 MW development pipeline includes

wind projects ranging from 20 MW to 300 MW

Development of projects to be considered on a case-

by-case basis

Projects to be Developed by Exelon

230

Total

81

Blissfield (MW IV)

MI

59

Harvest II

MI

90

MW

Michigan Wind II

MI

Project Name

State

Operating Assets

57

Natural Gas Outlook

The economic recovery has increased natural gas

demand, but this has been met by sufficient supply

Shale gas has proven itself to be a low cost and

abundant resource, but not the only resource

•

Most production growth is expected to come from shale

resulting in a flatter gas supply curve

•

Non-core shale, tight sands and coal bed methane resources

are higher cost and will remain part of the total supply mix

A flatter supply curve provides market stability, but

increased drilling costs, environmental concerns and

uncertainty regarding shale decline rates could put

upward pressure on the marginal cost of gas and

therefore prices

Sources: Wood Mackenzie, PIRA, NYMEX

Current fundamentals support a forward natural gas price in the $5-$6.50/MMBtu range

Higher Cost Gas Resources

58

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2011

2012

2013

Underlying

Options

Q3 2010 Ratable

Exelon Generation Hedging Program

2012 hedging levels currently above

ratable

•

Increased rate of 2012 sales in 2nd

Quarter of 2010 to capture higher prices

in Mid-Atlantic, and slowed down in Q3

as prices fell

•

Participation in long-term procurements

Normal practice is to hedge commodity risk

on a ratable basis over three years

•

Maintain flexibility from quarter to quarter

•

Use of gas and power options to capture

potential upside while providing downside

price protection

Note: % values represent amount

above ratable plan

1%

8%

Exelon’s ratable hedging program provides flexibility to time sales based

on fundamental view of the market

(1) Data as of end of 3Q 2010.

2012 Historical Power & Gas Prices

Current

Hedge

Level

vs.

Ratable

Plan

(1)

9%

30.00

35.00

40.00

45.00

50.00

55.00

1/4/10

2/3/10

3/5/10

4/4/10

5/4/10

6/3/10

7/3/10

8/2/10

9/1/10

10/1/10

4.50

4.75

5.00

5.25

5.50

5.75

6.00

6.25

6.50

6.75

7.00

PJMW Hub

NiHub

Henry Hub Nat Gas

59

(1)

Represents values as of September 30, 2010.

A diverse set of customers and products is

important for Exelon Generation’s hedging

program

•

Reduces and diversifies our collateral

exposure 

•

Improves portfolio product fit (load following)

and sales closer to assets

•

Increases opportunities for margin via retail,

utility solicitations and mid–marketing

channels

•

Long term transactions provide extended

price certainty and monetize environmental

upside

•

Use of alternate channels and locations help

minimize liquidity constraints

Multiple sales channels to market enhances value and maximizes

liquidity and credit diversity

2011 - 2013 Sales as a Percentage of

Expected Generation

(1)

Open

Generation

37%

Options

8%

Retail

5%

Utility

Procurements

23%

Standard

Product Sales

27%

Multiple Channels To Market

60

Exelon Energy –

Competitive Retail

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

industrial customers in Illinois, Pennsylvania, Michigan and Ohio

Managed as a part of the overall Exelon Generation hedging strategy

•

Retail load profile complements generation portfolio

•

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

•

Projected sales growing from ~10% to 20% of expected generation over the next 3 years

Channel to build relationship with end-use

customers

•

Partner with customers to meet their energy supply

needs

•

Products support Exelon 2020 and provide access to

Exelon Generation’s low-emission generation fleet

–

Renewable Energy Credits (RECs), including John

Deere wind resources

–

Low Carbon Energy Certificates (EFECs)

Nuclear energy attributes transferred through

PJM Generation Attribute Tracking System

Exelon Energy complements Exelon Generation footprint by leveraging broad

experience in wholesale markets and asset management

Electric Volumes

-

5

10

15

20

25

30

35

2008

2009

2010E

2011E

2012E

2013E

MWh - Millions

COMED / Ameren

PECO/PPL

Other

61

61

Reliability Pricing Model (RPM) Auction

Note: Data contained on this slide is rounded.

(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 and capacity values have been adjusted for mid-year PPA roll-offs.

JDR assets are not included in the capacity position.

(3)

Obligation consists of load obligations from PECO. PECO PPA expires

December 2010.

(4)

Reflects decision in December 2009 to permanently retire Cromby Station and

Eddystone Units 1&2 as of 5/31/11. None of these 933 MW cleared in the 2011/2012

or 2012/2013 auctions.

(5)

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

zones.

2010/2011

2011/2012

2012/2013

2013/2014

in MW

Capacity

(2)

Obligation

Capacity

(2)

Capacity

(2)

Capacity

(2)

RTO

23,900

9,300 -

9,400

(3)

22,300

11,600 

10,300

$174.29

$110.00

$16.46

$27.73

EMAAC

8,700

(4)

8,700

(4)

$174.29

$110.00

$139.73

$245.00

MAAC

1,500

1,500

$174.29

$110.00

$133.37

$226.15

Avg ($/MW-Day)

(5)

$174.29

$110.00

$74.00               

$134.00         

Exelon

Generation

Eligible

Capacity

within

PJM

Reliability

Pricing

Model

(1)

62

PA Gross Receipts Tax (5.90%)

Distribution Losses (7.35%)

Full Requirements Cost

PJM Whub ATC Forward Energy Price

Estimated Build-Up of PECO Average

Residential

Full

Requirements

Price

–

Fall

2010

$76.50/MWh

$23.75 -

$26.25

$41.50 -

$42.50

Full Requirements Costs ($/MWh)

Average Full Requirements                          

Retail Sales Price

(1)

Load Shape &

Ancillary Services

$5.75 -

$6.25 

Capacity

$11.50 -

$12.00

Transmission &

Congestion

$3.50 -

$4.50

Renewable

Energy

Credits

$0.25

Migration,

Volumetric

Risk & Other

$2.75 -

$3.25

~$5.00

~$4.50

(1)

As provided by Exelon Generation.

(2)

On October 14, 2010 the Independent Evaluator (NERA) announced a

wholesale winning bid of $66.83/MWh for PECO’s Fall 2010 RFP Residential Price.

(1)

As provided by Exelon Generation.

(2)

On October 14, 2010 the Independent Evaluator (NERA) announced a

wholesale winning bid of $66.83/MWh for PECO’s Fall 2010 RFP Residential Price.

Average

Wholesale

Energy Price

$66.83

(2)

63

Exelon Generation Hedging Disclosures

(as of September 30, 2010)

*

*

*

*

*

*

*

******

******

******

******

******

******

******

******

64

64

Important Information

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

program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon

Generation’s

gross

margin

(operating

revenues

less

purchased

power

and

fuel

expense).

The

information

on

the

following

slides

is

not

intended

to

represent

earnings

guidance

or

a

forecast

of future events.  In fact, many of the factors that ultimately will determine Exelon Generation’s

actual gross margin are based upon highly variable market factors outside of our control.  The

information

on

the

following

slides

is

as

of

September

30,

2010.

We

update

this

information

on

a quarterly basis.

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

incorporates assumptions regarding future market conditions, including power and commodity

prices, heat rates, and demand conditions, in addition to operating performance and dispatch

characteristics of our generating fleet.  Our simulation model and the assumptions therein are

subject to change.  For example, actual market conditions and the dispatch profile of our

generation

fleet

in

future

periods

will

likely

differ

–

and

may

differ

significantly

–

from

the

assumptions underlying the simulation results included in the slides.  In addition, the forward-

looking

information

included

in

the

following

slides

will

likely

change

over

time

due

to

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

conditions.

65

65

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

66

66

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

67

67

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)

$4,800

$4,700

$5,300

Open gross margin assumes all expected generation is sold

at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT North ATC Spark Spread ($/MWh)

(3)

$4.44

$29.92

$41.07

$(0.37)

$5.07

$31.89

$43.10

$0.31

$5.29

$34.04

$45.02

$1.52

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on September 30, 2010 market conditions. 

(2)

Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental

revenues. Open gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and

fossil

fuel

prices.

Open

gross

margin

assumes

there

is

no

hedging

in

place

other

than

fixed

assumptions

for

capacity

cleared

in

the

RPM

auctions

and

uranium

costs for nuclear power plants.  Open gross margin contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and

costs and PPA capacity revenues and payments.  The estimation of

open gross margin incorporates management discretion and modeling assumptions that are

subject to change.

(3)

ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.

68

2011

2012

2013

Expected Generation

(GWh)

(1)

163,400

162,700

161,100

Midwest

99,100

96,900

95,300

Mid-Atlantic

56,500

57,100

56,400

South

7,800

8,700

9,400

Percentage

of

Expected

Generation

Hedged

(2)

87-90%

62-65%

31-34%

Midwest

86-89

61-64

28-31

Mid-Atlantic

93-96

66-69

36-39

South

62-65

49-52

35-38

Effective

Realized

Energy

Price

($/MWh)

(3)

Midwest

$44.00

$43.50

$43.00

Mid-Atlantic

$57.50

$50.50

$52.00

ERCOT North ATC Spark Spread

$(1.00)

$(4.50)

$(7.50)

Generation Profile

(1)

Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is based upon a simulated

dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options.  Expected

generation assumes 11 refueling outages in 2011 and 2012 and 9 refueling outages in 2013 at Exelon-operated nuclear plants and Salem.  Expected generation assumes capacity factors

of 93.3%,  93.1% and 93.3% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2011, 2012 and 2013 do not represent guidance or a

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

(2)

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

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

not impact metrics presented in the hedging disclosure.  

(3)

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

revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but

includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can be compared with the reference prices used 

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

69

69

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2011

$30

$(15)

$60

$(50)

$20

$(15)

+/-

$40

2012

$225

$(175)

$205

$(195)

$120

$(115)

+/-

$40

2013

$455

$(420)

$345

$(340)

$200

$(195)

+/-

$45

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on September 30, 2010 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived

from an

internal

model

that

is

updated

periodically.

Power

price

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.

70

70

95% case

5% case

$5,100

$7,200

$6,600

$6,400

Exelon

Generation

Gross

Margin

Upside

/

Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2011

2012

2013

$6,900

$4,700

(1)

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels

assuming all unhedged supply is sold into the spot market.  Approximate gross margin ranges are based upon an internal simulation model and are subject to

change based upon market inputs, future transactions and potential modeling changes. These ranges of approximate gross margin 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, 2010.

71

71

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$4.80 billion

Step 2

Determine the mark-to-market value

of

energy hedges

99,100GWh * 87% *

($44.00/MWh-$29.92MWh)

= $1.21 billion

56,500GWh * 94% *

($57.50/MWh-$41.07/MWh)

= $0.87 billion

7,800GWh * 63% *

($(1.00)/MWh-$(0.37)/MWh)

= $(0.00) billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $4.80 billion

MTM value of energy hedges:              $1.21billion + $0.87billion + $(0.00) billion

Estimated hedged gross margin:          $6.88 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

72

Current Market Prices

Units

2008

(1)

2009

(1)

2010

(5)

2011

(6)

2012

(6)

2013

(6)

PRICES (as of September 30, 2010)

PJM West Hub ATC

($/MWh)

68.52

(2)

38.30

(2)

44.38

41.06

43.09

45.01

PJM NiHub ATC

($/MWh)

49.00

(2)

28.86

(2)

32.82

29.91

31.88

34.05

NEPOOL MASS Hub ATC

($/MWh)

80.56

(2)

42.02

(2)

48.33

44.73

47.99

50.43

ERCOT North On-Peak

($/MWh)

73.36

(3)

33.50

(3)

40.13

39.21

45.23

48.19

Henry Hub Natural Gas

($/MMBTU)

8.85

(4)

3.94

(4)

4.42

4.44

5.07

5.29

WTI Crude Oil

($/bbl)

104.49

(4)

61.56

(4)

77.28

84.35

87.12

88.22

PRB 8800

($/Ton)

12.17

9.20

12.62

14.93

15.56

16

NAPP 3.0

($/Ton)

105.36

50.98

65.37

70

72

70

ATC HEAT RATES (as of September 30, 2010)

PJM West Hub / Tetco M3

(MMBTU/MWh)

6.97

8.26

10.15

8.33

7.83

7.92

PJM NiHub / Chicago City Gate

(MMBTU/MWh)

5.57

7.36

7.31

6.70

6.31

6.47

ERCOT North / Houston Ship Channel

(MMBTU/MWh)

7.42

7.95

7.23

7.69

7.77

7.98

(1)

2008 and 2009 are actual settled prices.

(2)

Real Time LMP (Locational Marginal Price).

(3)

Next day over-the-counter market.

(4)

Average NYMEX settled prices.

(5)

2010 information is a combination of actual prices through September 30, 2010 and market prices for the balance of the year.

(6)

2011, 2012 and 2013 are forward market prices as of September 30, 2010.

73

35

40

45

50

55

60

65

70

75

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

73

73

20

25

30

35

40

45

50

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

50

55

60

65

70

75

80

85

90

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2011

$5.55

2012  $5.93

Forward NYMEX Coal

2011

$67.29

2012

$74.50

2011 Ni-Hub  $40.83

2012 Ni-Hub

$42.55

2012 PJM-West  $55.20

2011 PJM-West

$53.61

2011 Ni-Hub

$24.76

2012 Ni-Hub

$26.25

2012 PJM-West

$39.57

2011 PJM-West

$38.26

Rolling 12 months, as of October 25th, 2010. Source: OTC quotes and electronic  trading system. Quotes are daily.

74

74

74

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

35

40

45

50

55

60

65

70

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

Market Price Snapshot

2012

9.07

2011

8.92

2011

$48.56

2012

$52.71

2011

$5.44

2012

$5.81

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$6.73

2012

$8.27

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 25th, 2010. Source: OTC quotes and electronic  trading system. Quotes are daily.

75

*

*

*

*

*

*

*********

*********

*********

*********

*********

*********

76

ComEd Load Trends

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(1)

A

gradually

improving

economy

is

expected

in

2011

as

incremental

improvements

in

the

labor

market

–

led

by

hiring

in

the

manufacturing

and

professional/business

services

sectors

–

build

economic

momentum

2011 will be more of a transition year than a recovery year as the inventory and fiscal stimulus boosts

are fading in late 2010 to be replaced by growth in 2011 from a cautious private sector.

Housing

conditions

will

weigh

on

the

economy.

There

is

little

reason

for

significant

increases

in

either

2011 housing starts or home prices.

2011 Outlook

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10

3Q10

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

(1) Not adjusted for leap year effect.

77

ComEd 2010 Delivery Service

Rate Case Filing Summary

$396

Total

($2,337

million

revenue

requirement)

(6)

$45

Other

adjustments

(5)

$22

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

$55

Pension

and

Post-retirement

health

care

expenses

(4)

$95

Capital

Structure

(3)

:

ROE

–

11.50%

/

Common Equity –

47.33% / ROR –

8.99%

$179

(1)(2)

Rate

Base:

$7,717

million

(1)

Requested Revenue 

Increase

($ in millions)

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

health care and cost of capital

(1)

Filed

June

30,

2010

based

on

2009

test

year,

including

pro

forma

capital

additions

through

June

2011,

and

certain

other

2010

pro

forma

adjustments.

Updating

the

depreciation

and

deferred

tax

reserves

to

June

2011

would

reduce

rate

base

by

an

estimated

$667

million

and

would

reduce

the

revenue

requirement

by

approximately

$85

million.

(2)

Includes increased depreciation expense.

(3)

Requested capital structure does not include goodwill; ICC docket 07-0566 allowed 10.3% ROE, 45.04% equity ratio and 8.36% ROR. ROE includes

0.40% adder for energy efficiency incentive.

(4)

Reflects 2010 expense levels, compared to 2007 expense levels allowed in last rate case.

(5)

Includes reductions to O&M and taxes other than income, offset by wage increases, normalization of storm costs and the Illinois Electric Distribution

Tax, other O&M increasess

and decreases in load.

(6)

Net of Other Revenues.

ICC Docket No. 10-0467

78

ComEd 2010 Rate Case Update

ComEd Request (6/30/10)

$396M increase requested

11.50% ROE / 47.33% equity ratio

Rate base $7,717M

2009 test year with pro forma plant

additions thru 6/30/11

ICC Staff Testimony (10/26/10)

$78M increase recommended

10.00% ROE / 47.11% equity ratio

Rate base $6,663M

Pro forma additions and depreciation

reserve thru 9/30/10

(ICC Docket No. 10-0467)

$ millions

ComEd Request

396

$       

Staff Adjustments:

Plant Additions / Depreciation Reserve

(122)

ROE / Capital Structure

(97)

Pension Asset

(33)

Incentive Compensation / Severance

(23)

Cash Working Capital

(9)

Amortization of Regulatory Assets

(8)

Pension and OPEB Expense

(4)

Other Items

(22)

ICC Staff Recommendation

78

$        

Reconciliation of ICC Staff to ComEd

79

3.82

4.73

7.44

7.03

0.73

0.73

0.65

0.60

ComEd Delivery Rate Case

Residential Rate Impacts 2010 to 2011

(1)

(1)

Reflects change in distribution rates only.  Assumes Energy, Transmission and all other components remain constant as of June 2010, except as noted above.

(2)

"All Other" includes impact of riders that are applicable to residential bills.

Unit rates: cents / kWh

All Other

(2)

Transmission

Energy

Distribution

Approximately

4% increase

July 1, 2010

July 1, 2011

Transmission: Subject to FERC

formula rate annual update

Comments

Energy: Reflects reduced PJM capacity

price that PJM has published for the

June

2011

–

May

2012

planning

period.  Energy component may vary

Distribution: As proposed

12.63

13.09

Note:  Amounts may not add due to rounding.

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

of lower capacity prices resulting in an increase of 4%

Straight Fixed/Variable Rate Design:

Move delivery bill from current 37%

fixed/ 63% variable to 80% fixed/ 20%

variable by 2013

80

ComEd Delivery Rate Case

Alternative Regulation (Alt Reg) Proposal

ComEd filed a companion Alt Reg filing on August 31, 2010 proposing to recover the costs of

pre-approved smart grid and other projects outside of the traditional rate case process

•

9-month statutory process

Proposal would allow for accelerated modernization of the distribution system, increased

assistance to low-income households and the purchase of electric vehicles

Initial series of proposed programs is $60 million, but would create a collaborative framework

for increased investments in the future implementation of ICC-approved Smart Grid

investments

The

proposal

includes

a

“flow-through

mechanism”

to

recover

capital

carrying

costs

and

incremental O&M, as incurred

Assured savings to customers –

$2 million on capped O&M costs for program costs

(excluding CARE)

Includes

an

incentive/penalty

mechanism

for

performance

above

or

under

budget

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

$30

$15

Man-hole refurbishment and cable replacement

-

$10

Expanded funding for low income CARE programs

(1)

$5

-

Electric Vehicle Fleet Purchase

Capital

O&M

$ millions

(1)

CARE = Customers’

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

81

ComEd Delivery Service Rate Case

Tentative Schedule

Delivery

Service

Rate

Case

Filed

–

June

30,

2010

Alt

Reg

Proposal

Filed

–

August

31,

2010

Staff

and

Intervenor

Direct

Testimony

–

October

26,

2010

(Rate

Case),

November

19

(Alt

Reg)

ComEd

Rebuttal

Testimony

–

November

22

(Rate

Case),

December

8

(Alt

Reg)

Staff

and

Intervenor

Rebuttal

Testimony

-

December

23,

2010

(Rate

Case),

December

30

(Alt

Reg)

ComEd

Surrebuttal

Testimony

–

January

3,

2011

(Rate

Case),

January

5

(Alt

Reg)

Hearings

–

January

2011

Administrative

Law

Judge

Order

–

March

31,

2011

Final

Order

Expected

–

May

2011

New

Rates

Effective

–

June

2011

82

6.7

7.7

1.9

2.0

6.7

1.9

Transmission

Distribution

ComEd Rate Base Growth

June 1, 2011

October 1, 2008

Rates Effective

47.33%

45.04%

Equity %

11.5%

10.3%

ROE

$7,717 million

$6,694 million

Rate Base

2009 pro forma

2006 pro forma

Test Year

Current Filing

6/30/2010

Prior Rate Case

ELECTRIC

DISTRIBUTION

June 1, 2010

Rates Effective

56%

Equity %

11.5%

ROE

$1,949 million

Rate Base

2009 pro forma

Test Year

FERC Formula rate

TRANSMISSION

Distribution rate

cases expected every

~2-3 years

Transmission: FERC

formula rate adjusted

every year on June 1

$8.6

$8.6

2009

2010E

2011E

$9.7

ComEd executing on regulatory recovery plan

Rate Base in Rates

End of Year ($ in billions)

(1)

Recent Rate Cases

8.5%

Earned ROE

~45%

Target

~46%

Equity

2009

(1)

Amounts include pro forma adjustments.  On September 30, 2010, the Illinois Appellate Court ruled with regard to ComEd’s 2007 distribution rate case and held that the ICC abused

its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including pro forma plant additions post-test year through

that period.  The Court remanded the case to the ICC.  For the 2007 rate case, the Court’s ruling would reduce the $6,694 million rate base by ~$500 - $670 million resulting in a

revenue reduction between $57 and $77 million.  For the current rate case, updating the depreciation and deferred tax reserves to June 2011 would reduce the $7,717 million rate

base by an estimated $667 million and would reduce the revenue requirement by approximately $85 million.

Note: Amounts may not add due to rounding.

10%

83

Illinois Power Agency (IPA)

RFP Procurement

Note: Chart is for illustrative purposes only.

REC = Renewable Energy Credit; RFP = request for proposal

Auction

Contract

June 2010

June 2011

June 2012

June 2013

June 2014

Financial Swap Agreement with ExGen

(ATC baseload energy only –

notional

quantity 3,000 MW)

Term

Fixed Price

6/1/10-12/31/10

$50.15/MWh

1/1/11-12/31/11

$51.26

1/1/12-12/31/12

$52.37

1/1/13-5/31/13

$53.48

Long-Term REC Procurement Scheduled for November 2010

•

1.4 million MWh of renewable resources annually beginning in June 2012 under 20-year contracts

•

RFP

bids

due

on

November

19

th

with

contracts

signed

early

December

Spring 2011 Procurement Plan

•

IPA proposal submitted with a number of issues to be resolved. Final ICC decision expected by

year end

•

Provisions that appear likely to continue:

Annual energy procurements over a three-year time frame

Target a 35%/35%/30% laddered procurement approach

•

Other items being discussed:

Additional energy efficiency, demand response purchases

More long-term contracts for renewables

2009 RFP

2010 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2013 RFP

2010 RFP

2011 RFP

Financial

Swap

84

*

*

*

*

*

*

85

PECO Load Trends

Weather-Normalized

Load

Year-over-Year

(1)

2011 Outlook

Economically driven load growth will be significantly offset by mandated energy efficiency

initiatives.

2011 GMP will show a gradual improvement over 2010, but not a robust recovery, where both non-

manufacturing employment and income see growth of less than 1.5%

Manufacturing employment is expected to remain nearly flat

The housing market will offer neither a real drag nor a real boost in 2011

(1) Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10

3Q10

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Cust. Classes

Large C&I

Residential

Gross Metro Product

Note: C&I = Commercial & Industrial

86

PECO –

Electric & Gas Distribution

Rate Case Settlements

Joint settlement filed with the PAPUC on August 31, 2010 for both electric and gas

rate cases

Settlements are subject to administrative law judges review and PAPUC approval by

mid-December 2010

$20 million

$225 million

Revenue Requirement Increase in

Settlement

(1)

R-2010-2161592

R-2010-2161575

Docket #

~7%

Electric

~4%

2011 Distribution Price Increase as %

of Overall Customer Bill for Residential

customers

Gas

Rate Case Details

(1)

Settlements

are

on

an

overall

revenue

requirement

basis,

meaning

no

details

are

provided

for

allowed

ROE,

rate

base

or

capital

structure.

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

New rates scheduled to go into effect on January 1, 2011

87

5.03

6.26

5.84

0.69

0.51

2.57

8.40

PECO Electric Residential Rate

Increases 2010 to 2011

January 1, 2011

January 1, 2010

Total = 14.7¢

Unit Rates (¢/kWh)

Proposed Total Bill

Increase ~5.1 %

Total = 15.4¢

AEPS                                 ~0.7%

Smart Meter

~0.6%

Default Service Surcharge       

Mechanism                      ~(2.9)%

Transmission and Distribution   ~7%

Transmission Surcharge                           

Mechanism                               ~1.2%

Distribution Rate Case             ~5.5%

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

0.47

Energy Efficiency

Surcharge

Breakdown of 2010 to 2011

~5.1% Increase (On Total Bill)

Notes:

•

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

•

Represents

average

of

all

residential

rates

including

the

effect

of

discounted

rates

provided

to

low

income

customers.

•

AEPS = Alternative Electric Portfolio Standard

0.29

88

3.0

3.3

3.5

0.6

0.6

0.6

1.1

1.1

1.1

0.9

Electric Distribution

Electric Transmission

CTC

Gas

PECO Executing on Transition Plan

$225 million

Revenue Increase

January 1, 2011

Rates Effective

2010

Test Year

Filing

3/31/2010

ELECTRIC

DISTRIBUTION

$20 million

Revenue Increase

January 1, 2011

Rates Effective

2010

Test Year

Filing

3/31/2010

GAS DELIVERY

14.8%

53%

2009

Target

51-53%

Earned ROE

Equity

(1)

$5.6

$5.0

2009

2010E

(1)

As determined for rate-making purposes. Amounts reflect pro forma adjustments that may be made to determine rate base for rate case filing purposes.

$5.2

2011E

PECO

is

managing

through

its

transition

period

and

is

positioned

for

continued strong financial performance post-2010

Rate Base in Rates

End of Year Balance ($ in billions)

(1)

Recent Rate Cases

(1)

Stated rate; no

recent rate cases

TRANSMISSION

Periodic rate

cases

going forward

10%

89

PECO Procurement

(1)

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

(2)

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

(3)

For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product.

(4)

Large Hourly price includes ancillary services and supplier-provided AEPS cost.

Large Commercial and Industrial

Large Fixed May ’10 RFP -

average price of $77.55/MWh

(2)(3)

Large Hourly Sept ‘10 RFP -

average price of $4.83/MWh

(4)

Medium Commercial

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

(2)

Sept ‘10 RFP average price of $70.36/MWh

(2)

Residential

June ’09 RFP average price of $88.61/MWh

(2)

Sept ’09 RFP average price of $79.96/MWh

(2)

May ‘10 RFP average price of $69.38/MWh

(2)

Sept ’10 RFP average price of $66.83/MWh

(2)

Small Commercial

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

(2)

Sept ‘10 RFP average price of $70.82/MWh

(2)

85% full requirements

15% full requirements

spot

Medium Commercial

(peak demand >100

kW but <= 500 kW)

Fixed-priced full

requirements

(3)

Hourly full requirements

Large Commercial &

Industrial (peak

demand >500 kW)

90% full requirements

10% full requirements

spot

75% full requirements

20% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100

kW)

Residential

Customer Class

PECO Procurement Plan

(1)

2011 Supply Procured

2011 supply procured, two procurement events per year moving forward

90

PECO Smart Grid/Smart Meter

($ millions pre-tax)

2010

2011

2012

2013

Total

Act 129 Smart Meter Expanded Initial Deployment

(1)

39

$       

86

$       

116

$     

59

$       

300

$     

Smart Grid Stimulus Case

40

45

15

100

Total Stimulus Case

79

131

131

59

400

Stimulus Grant

(40)

(66)

(66)

(30)

(200)

Total Expenditures net of Stimulus grant

40

$       

66

$       

66

$       

30

$       

200

$     

(1)  Includes approximately $20 million/yr of O&M in 2010-2012.

Data contained in this slide is rounded.

2010-

2013 Projected Expenditures

•

ACT 129 required Smart

Meter technology in 15 years

•

DOE $200M assistance

agreement completed in May

–

Accelerated Smart Meter 

deployment to 10 years

•

PA PUC Smart Meter Plan

approval received in April

•

PECO to spend $650M in

total (including stimulus grant)

–

$550M for Smart Meter

–

$100M for Smart Grid

•

Surcharge mechanism with

10% allowed return

•

Letters of Intent with vendors for

Automated Metering Infrastructure

(AMI) communications network,

smart meters and meter

installation; projects underway

•

Significant field work on Smart Grid

projects to enhance reliability in

progress

•

Implemented DOE compliance

reporting

•

Sub-applicant agreements signed

with Drexel and Liberty Partners

•

Dynamic Pricing Plan filing in

progress

•

Complete limited test of our Smart

Meter and communications system

technologies

•

Continue to integrate supporting

AMI systems (e.g., meter data

management, billing, middleware)

•

Continue Smart Grid Distribution

Automation and Intelligent

Substations Implementation

•

Complete Distribution Management

and Geographical Information

System Vendor Selections

•

Finalize communications and

customer experience plan

Background

Near-Term Focus

Key Accomplishments

91

2009 GAAP EPS Reconciliation

0.16

-

-

-

0.16

Mark-to-market adjustments from economic hedging activities

(0.05)

-

-

-

(0.05)

Retirement of fossil generating units

(0.01)

-

-

(0.01)

-

City of Chicago settlement with ComEd

(0.10)

-

-

(0.01)

(0.09)

2007 Illinois electric rate settlement

(0.11)

(0.04)

-

-

(0.07)

Costs associated with early debt retirements

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

(0.03)

-

(0.00)

(0.02)

(0.01)

2009 restructuring charges

0.05

-

-

-

0.05

Decommissioning obligation reduction

(0.03)

(0.03)

-

-

-

NRG Energy, Inc. acquisition costs

0.19

-

-

-

0.19

Unrealized gains related to nuclear decommissioning trust funds

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and reassessment

of state deferred income taxes

$4.09

$(0.21)

$0.53

$0.56

$3.21

FY 2009 GAAP Earnings (Loss) Per Share

$4.12

$(0.12)

$0.54

$0.54

$3.16

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

Exelon

Other

PECO

ComEd

ExGen

2009

GAAP

EPS

Reconciliation

(1)

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

Note:  Amounts may not add due to rounding.

92

2010 Earnings Outlook

Exelon’s 2010 adjusted (non-GAAP) operating earnings outlook excludes the

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not offset by

contractual accounting as described in the notes to the consolidated financial statements

•

Significant impairments of assets, including goodwill

•

Costs associated with the 2007 Illinois electric rate settlement

agreement

•

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

•

Costs associated with the retirement of fossil generating units

•

Non-cash charge resulting from passage of Federal health care legislation

•

Non-cash remeasurement of income tax uncertainties

•

External costs associated with Exelon’s proposed acquisition of John Deere Renewables

•

Impairment of certain emission allowances

•

Other unusual items

•

Significant future changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of

the

year

Operating O&M target excludes the following items:

•

Exelon Generation: Decommissioning accretion expense

•

ComEd and PECO: Impact of regulatory riders

93

Exelon Investor Relations Contacts

Exelon Investor Relations

10 South Dearborn Street

Chicago, Illinois 60603

312-394-2345

312-394-4082 (Fax)

For copies of other presentations,

annual/quarterly reports, or to be added

to our email distribution list please

contact:

Martha Chavez, Executive Admin

Coordinator

312-394-4069

Martha.Chavez@ExelonCorp.com

Investor Relations Contacts:

Stacie Frank, Vice President

312-394-3094

Stacie.Frank@ExelonCorp.com

Melissa Sherrod, Director

312-394-8351

Melissa.Sherrod@ExelonCorp.com

Paul Mountain, Manager

312-394-2407

Paul.Mountain@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com

Sandeep Menon, Principal Analyst

312-394-7279

Sandeep.Menon@ExelonCorp.com