Exelon 8K Introduces Guidance Range for Full Year 2011 Earnings | EXC 26 Jan 11

Earnings Conference Call

Quarter 2010

January 26, 2011

Exhibit 99.2

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

the

Companies

undertakes

any

obligation

publicly

release

any

revision

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

GAAP

earnings.

Please

refer

the

footnotes

the

following

slides

for

reconciliation

non-GAAP cash flows to GAAP cash flows.

2010: Another Strong Year for Exelon

Exemplary year of financial

and operational performance

•

Operating earnings of

$4.06/share

(1)

•

2010 Cash from operations

of $5.3 billion

(2)

•

Returned $1.4 billion in cash

to shareholders through

dividends

Continuing to position Exelon

for cleaner energy future

Strong reliability scores despite significant storm

activity

Highest customer satisfaction scores in > 5 yrs

Completed electric and gas distribution rate cases

Best

customer

satisfaction

scores

PECO

history

Eighth consecutive year with nuclear capacity

factor above 93%

59 MW added through nuclear uprate program

Acquired John Deere Renewables

Announced early retirement of Oyster Creek

RITE line project announced

(1)

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

(2)

2010 Cash from operations excludes counterparty collateral and includes net cash from investing activities other than capital expenditures, acquisition of Exelon Wind and change in

restricted cash.

2011 Operating Earnings Guidance

2011E

(2)

2010A

$0.54

$2.91

$4.06

(1)

ComEd

PECO

Exelon

Generation

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$0.68

Exelon

$3.90 -

$4.20

(1)

$0.55 -

$0.65

$0.50 -

$0.55

$2.85 -

$3.05

Key Drivers of FY Guidance

Generation margins driven by PECO

PPA roll-off, partially offset by lower

capacity revenues

Higher PECO gross margin driven by

new distribution rates effective 1/1/11

Higher O&M expense

Higher depreciation & amortization

expense

Introducing

2011

operating

earnings

guidance

$3.90

–

$4.20/share

and

2011

guidance

$1.00

–

$1.10/share

(1)

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

(2)

Earnings guidance for OpCos may not add up to consolidated EPS guidance.

2017/

2018

2016/

2017

2015/

2016

2014/

2015

PJM RPM Auctions

Delivery Year

2010

2011

2012

2013

2014

2015

2016

2017

2018

EPA Regulations Will Move Forward in 2011

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/).

Key Financial Messages

2010

operating

earnings

$4.06/share

(1)

line

with

expectations

•

Higher capacity and energy (PECO PPA) revenues at ExGen

•

Higher earnings (vs. 2009) at ComEd

2011

earnings

guidance

$3.90

$4.20/share

(1)

•

Expiration

PECO

PPA

allows

ExGen

sell

additional

energy

market

prices,

offset by lower RPM capacity prices and higher costs

•

New distribution rates effective 1/1/11 at PECO

Strong cash flows in 2011

•

Expect to generate $4.3 billion cash from operations in 2011

•

Increasing investment in growth projects at ExGen and Utilities

Efficient use of cash benefits from bonus depreciation

•

$2.1 billion pension contribution proactively reduces pension costs and future

contributions while improving pension funding status

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

Exelon Generation

Operating EPS Contribution

2010

2009

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

(2) Outage days exclude Salem.

136

Refueling

Non-refueling

4Q10

4Q09

Outage Days

(2)

YTD

$0.66

$3.16

$0.81

$2.91

Note: PPA = Power Purchase Agreement

Key Drivers –

4Q10 vs. 4Q09

(1)

Higher energy prices under the PECO

PPA, offset at PECO: $0.10

Favorable RPM capacity pricing: $0.07

Higher nuclear volume: $0.04

Higher nuclear fuel costs: $(0.02)

Higher depreciation expense: $(0.03)

10%

20%

30%

40%

50%

60%

70%

80%

Q1 2010

Q2 2010

Q3 2010

Q4 2010

Underlying

Options

Ratable

Power Fundamentals & Hedging Update

Using our perspective on the markets to time

sales, thereby adding value

•

PJMW energy prices increased in 4Q 2010, driven by

higher eastern coal prices

•

NiHub energy prices and Henry Hub natural gas prices

remained relatively stable in 4Q 2010

•

Slowed down pace of hedging in Q3 & Q4 to recognize

future upside from environmental regulations and

economic recovery

Normal practice is to hedge commodity risk

on a ratable basis over three years

•

Maintain flexibility from quarter to quarter

•

Use gas and power put options to capture potential

upside while providing downside price protection

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

on fundamental view of the market

2012 Historical Energy & Gas Prices

31.00

33.00

35.00

37.00

39.00

41.00

43.00

45.00

47.00

49.00

51.00

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

10/31/10

11/30/10

12/30/10

4.80

5.00

5.20

5.40

5.60

5.80

6.00

6.20

6.40

6.60

6.80

PJMWHub

NiHub

Henry Hub Nat Gas

2012 Quarterly Hedge Level vs. Ratable Plan

Note: % values represent amount

above ratable plan

10%

11%

Key Drivers –

4Q10 vs. 4Q09

(1)

Appellate Court ruling: $(0.02)

Higher O&M expense: $(0.01)

ComEd Operating EPS Contribution

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

2010

2009

YTD

$0.16

$0.54

4Q10

Actual

Normal

% Change

Heating Degree-Days 2,292 2,278 0.6%

Cooling Degree-Days 15

7 114%

$0.13

$0.68

ComEd Load Trends

Chicago

U.S.

Unemployment rate

(1)

9.3%

9.4%

2010 annualized growth in

gross

domestic/metro

product

(2)

1.6% 2.8%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

Key Economic Indicators

Weather-Normalized Load

4Q10

2010 2011E

Average Customer Growth

0.4%

0.2%

0.5%

Average Use-Per-Customer

(4.5)%

(1.4)%

0.0%

Total Residential

(4.1)%

(1.2)% 0.5%

Small C&I

(1.5)%

(0.6)% (0.3)%

Large C&I

1.9%

2.6% (0.2)%

All Customer Classes

(1.2)%

0.2% 0.0%

(1)

Source: U.S. Dept. of Labor (December 2010) and Illinois

Department of Security (December 2010)

(2) Source: Global Insight December 2010

-6.0%

-3.0%

0.0%

3.0%

6.0%

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

-6.0%

-3.0%

0.0%

3.0%

6.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

PECO Operating EPS Contribution

Key Drivers –

4Q10 vs. 4Q09

(1)

Decreased CTC revenue resulting

in higher energy prices paid to

Generation under the PPA, offset

at Generation: $(0.10)

Weather: $0.01

CTC amortization $0.02

2010

2009

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

YTD

$0.12

$0.54

4Q10

$0.03

$0.54

Actual

Normal

% Change

Heating Degree-Days 1,686 1,634 3.2%

Cooling Degree-Days 19 21 (9.5)%

Note: CTC = Competitive Transition Charge

(1)

Source: U.S Dept. of Labor (PHL – November 2010 preliminary data, US –

December 2010)

(2)

Source: Global Insight December 2010

PECO Load Trends

Philadelphia

U.S.

Unemployment rate

(1)

8.4% 9.4%

2010 annualized growth in

gross

domestic/metro

product

(2)

2.8% 2.8%

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

Key Economic Indicators

Weather-Normalized Load

4Q10

2010 2011E

Average Customer Growth

0.5%

0.3%

0.4%

Average Use-Per-Customer

(1.2)%

0.3%

(0.3)%

Total Residential

(0.7)%

0.5% 0.1%

Small C&I

(2.0)%

(1.9)% (0.5)%

Large C&I

1.5%

0.8% 0.1%

All Customer Classes

0.0%

0.1% 0.0%

-5.0%

-2.5%

0.0%

2.5%

5.0%

1Q10

2Q10

3Q10

4Q10

1Q11E

2Q11E

3Q11E

4Q11E

-5.0%

-2.5%

0.0%

2.5%

5.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

$0.98

$0.68

$2.74

$2.91

$1.07

$0.71

2010A

2011E

PECO

ComEd

ExGen

Operating O&M Outlook

2010 to 2011 Drivers (per share)

Inflation $(0.08)

Full year of Exelon Wind $(0.05)

Two additional nuclear refueling

outages $(0.05)

ComEd uncollectibles

$(0.04)

Estimated

2011

O&M

represents

new

“base”

level

for

operating

O&M

$4.39B

$4.68B

2010 Operating O&M below 2008 levels for second consecutive year

One-time savings in 2010 included executive salary freezes and reduced

compensation benefits

Anticipate annual O&M growth rate of ~2% for 2011-2013

(1)

(1) Amounts may not add due to rounding. Refer to slide 44 for a reconciliation of GAAP O&M to Operating O&M.

Pension and OPEB Expense and

Contributions –

As of 12/31/10

(1)

Pension expense amounts exclude settlement charges.

(2)

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

$190

$240

Pre-tax

expense

$205

$1,655

$3,875

$2,220

$765

$8,860

$12,525

$3,665

Actual

contribution

$210

$2,140

$225

$185

$2,180

$210

5.83% in 2010

5.30% in 2011

5.52% in 2012

11.6% in 2010

7.08% in 2011

7.08% in 2012

OPEB

Assets

Obligations

Unfunded balance –

end of year

$110

$1,015

$240

$2,100

$1,305

$200

5.83% in 2010

5.26% in 2011

5.48% in 2012

11.9% in 2010

8.0% in 2011

7.5% in 2012

Pension

Assets

Obligations

Unfunded balance –

end of year

Expected

contribution

Pre-tax

expense

Expected

contribution

Pre-tax

expense

Discount Rate

(used for

expense)

Asset Returns

(actual for 2010 and

expected for

2011 and 2012)

($ in millions)

Assumptions

2011

2012

2010

The decrease in pension expense in 2011 is primarily due to the $2.1 billion pension

contribution, partially offset by the impacts of lower discount rates and a decrease in EROA

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions

required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications.

The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status

(which triggers higher minimum contribution requirements and participant notification).

2011 Pension Contribution

$2.1 billion contribution to pension in 2011

•

Timing:

~$850

million

funded

the

accelerated cash benefits generated as a

result of bonus depreciation

•

Tax

efficient:

Income

tax

deduction

pension contribution creates $750 million

of cash benefit

•

Economic:

Reduces

estimated

future

pension expense, lowers future minimum

funding requirements and reduces volatility

Improves financial flexibility

•

Creates debt capacity for future growth

•

Improves ability to weather commodity

cycle in 2012 and 2013 and maintain the

dividend

Contributes to improved pension funded

status of 71% at 12/31/10, projected to be

89% at 12/31/11

Pension Contributions

615

2,100

765

110

175

160

195

780

790

170

485

2010

2011

2012

2013

2014

2015

With $2.1B

Original Plan*

Pre-Tax Pension Expense

(1)

240

300

265

200

240

2010

2011

2012

(1) Assumes an ~25% capitalization rate.

$ millions

Original Plan reflects preliminary 2010 underlying assumptions (including

discount rate and asset returns)

2011 Projected Sources and Uses of Cash

(1)

Excludes counterparty collateral activity.

(2)

Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures.

(3)

Assumes 2011 dividend of $2.10/share. Dividends are subject to declaration by the Board of Directors.

(4)

Includes $475 million in Nuclear Uprates and $225 million for Exelon Wind spend.

(5)

Represents new business, smart grid/smart meter investment and transmission growth projects.

(6)

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

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

(7)

“Other”

includes proceeds from options and expected changes in short-term debt.

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

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$800

Cash Flow from Operations

(2)

425

775

3,150

4,325

CapEx (excluding Nuclear Fuel, Nuclear

Uprates, Exelon Wind, Utility Growth CapEx)

(700)

(325)

(850)

(1,875)

Nuclear Fuel

n/a

(1,025)

Dividend

(3)

(1,400)

Nuclear Uprates and Exelon Wind

(4)

n/a

(700)

Utility Growth CapEx

(5)

(325)

(125)

n/a

(450)

Net Financing (excluding Dividend):

Planned Debt Issuances

(6)

1,000

Planned Debt Retirements

(350)

(250)

(600)

Other

(7)

250

300

Ending Cash Balance

(1)

$375

2011 Events of Interest

RPM Auction results

(5/13)

Illinois Power Agency

RFP (April)

ALJ Proposed Order

–

DST Rate Case

(3/31)

Procurement RFP

(bids due 5/23;

results by 6/23)

DST Rate Case Final

Order (by 5/31)

EPA Final HAP

Rule (November)

Retirement of Cromby

1 & Eddystone 1 units

(5/31)

Proposed HAP EPA

Regulation (by 3/16)

Procurement RFP

(bids due 9/19;

results by 10/19)

Retirement of

Cromby 2 unit

(12/31)

Proposed 316(b) EPA

Regulation (by 3/14)

EPA Final Transport

Rule (June)

For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/).

Exelon Generation Hedging Disclosures

(as of December 31, 2010)

***********

Important Information

The

following

slides

are

intended

provide

additional

information

regarding

the

hedging

program

Exelon

Generation

and

serve

aid

for

the

purposes

modeling

Exelon

Generation’s

gross

margin

(operating

revenues

less

purchased

power

and

fuel

expense).

The

information

the

following

slides

not

intended

represent

earnings

guidance

forecast

future

events.

fact,

many

the

factors

that

ultimately

will

determine

Exelon

Generation’s

actual

gross

margin

are

based

upon

highly

variable

market

factors

outside

our

control.

The

information

the

following

slides

December

31,

2010.

update

this

information

a quarterly basis.

Certain

information

the

following

slides

based

upon

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

our

generating

fleet.

Our

simulation

model

and

the

assumptions

therein

are

subject

change.

For

example,

actual

market

conditions

and

the

dispatch

profile

our

generation

fleet

future

periods

will

likely

differ

–

and

may

differ

significantly

–

from

the

assumptions

underlying

the

simulation

results

included

the

slides.

addition,

the

forward-

looking

information

included

the

following

slides

will

likely

change

over

time

due

continued

refinement

our

simulation

model

and

changes

our

views

future

market

conditions.

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

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

•

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

2011

2012

2013

Estimated Open Gross Margin ($ millions)

(1)(2)(3)

$5,200

$5,050

$5,700

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)

(4)

$4.56

$30.69

$45.45

$1.12

$5.08

$32.38

$46.41

$0.82

$5.33

$35.09

$48.25

$1.84

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on December 31, 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

hedging

place

other

than

fixed

assumptions

for

capacity

cleared

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)

As of December 31, 2010 disclosure, Exelon Wind included. Assets in IL, MI and MN are in Midwest region and assets in ID, KS, MO, OR and TX are in South and West region.

(4)

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

2011

2012

2013

Expected Generation

(GWh)

(1)

165,900

165,800

163,300

Midwest

99,600

98,500

96,200

Mid-Atlantic

56,800

57,200

56,500

South & West

9,500

10,100

10,600

Percentage

Expected

Generation

Hedged

(2)

90-93%

67-70%

32-35%

Midwest

91-94

69-72

31-34

Mid-Atlantic

93-96

67-70

36-39

South & West

70-73

51-54

39-42

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$43.00

$41.50

$43.50

Mid-Atlantic

$57.00

$50.50

$51.50

South & West

$2.50

$(1.00)

$(3.50)

Generation Profile

(1)

Expected

generation

represents

the

amount

energy

estimated

generated

purchased

through

owned

contracted

for

capacity.

Expected

generation

based

upon

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,which

are

calibrated

market

quotes

for

power,

fuel,

load

following

products,

and

options.

Expected

generation

assumes

refueling

outages

2011

and

refueling

outages

2012

and

2013

Exelon-operated

nuclear

plants

and

Salem.

Expected

generation

assumes

capacity

factors

93.0%,

93.6%

and

93.1%

2011,

2012

and

2013

Exelon-operated

nuclear

plants.

These

estimates

expected

generation

2012

and

2013

not

represent guidance or a

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

(2)

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

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

(3)

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

revenues

and

costs

associated

with

our

hedges

and

considering

the

fossil

fuel

that

has

been

purchased

lock

margin.

excludes

uranium

costs

and

RPM

capacity

revenue,

but

includes

the

mark-to-market

value

capacity

contracted

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

can

compared

with

the

reference

prices

used

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

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2011

$(5)

$30

$(20)

$15

$(10)

+/-

$40

2012

$175

$(95)

$185

$(165)

$115

$(110)

+/-

$45

2013

$495

$(445)

$340

$(335)

$200

$(195)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on December 31, 2010 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an

internal model that is updated periodically.

Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs

constant. Due to correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the

hedged gross margin impact calculated when correlations between the various assumptions are also considered.

95% case

5% case

$5,400

$7,100

$6,800

$6,300

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

(1)

Represents

approximate

range

expected

gross

margin,

taking

into

account

hedges

place,

between

the

5th

and

95th

percent

confidence

levels

assuming

all

unhedged

supply

sold

into

the

spot

market.

Approximate

gross

margin

ranges

are

based

upon

internal

simulation

model

and

are

subject

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

approximate

gross

margin

2012

and

2013

not

represent

earnings

guidance

forecast

future

results

Exelon

has

not

completed

its

planning

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

market

quotes

for

power,

fuel,

load

following

products,

and

options

December

31,

2010.

$7,200

$5,000

2013

Midwest

Mid-Atlantic

South & West

Step 1

Start

with

fleetwide

open

gross

margin

$5.20 billion

Step 2

Determine the mark-to-market value

energy hedges

99,600GWh * 92% *

($43.00/MWh-$30.69MWh)

= $1.13 billion

56,800GWh * 94% *

($57.00/MWh-$45.45MWh)

= $0.62 billion

9,500GWh * 71% *

($2.50/MWh-$1.12/MWh)

= $0.01 billion

Step 3

Estimate

hedged

gross

margin

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin: $5.20 billion

MTM value of energy hedges: $1.13billion + $0.62billion + $0.01 billion

Estimated hedged gross margin: $6.96 billion

Illustrative Example

of Modeling Exelon Generation 2011 Gross Margin

(with Existing Hedges)

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2012

$5.54

2013 $5.79

Rolling

months,

January

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2012

$75.61

2013

$79.57

2012 Ni-Hub $41.35

2013 Ni-Hub

$43.48

2013 PJM-West $55.12

2012 PJM-West

$53.08

2012 Ni-Hub

$25.78

2013 Ni-Hub

$28.06

2013 PJM-West

$40.79

2012 PJM-West

$38.84

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

11/10

12/10

1/11

Market Price Snapshot

2013

9.29

2012

9.10

2012

$49.40

2013

$52.75

2012

$5.43

2013

$5.67

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2012

$7.72

2013

$9.30

ERCOT North On Peak Spark Spread

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

Rolling

months,

January

2011.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Appendix

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

Exelon Generation 2011 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

$ / Share

$0.35

$(0.03)

RNF

O&M

Other

Depreciation &

Amortization

$(0.08)

Key Items:

Inflation

Exelon Wind

Nuclear Outages

2010A

2011E

(1)

$2.85 -

$3.05

$2.91

Key Items:

PECO CTC $0.62

Exelon Wind

$0.08

Capacity Market Prices $(0.29)

Nuclear Fuel

$(0.09)

Market/portfolio conditions

and Exelon Energy $0.07

$(0.17)

$(0.03)

Interest

Expense

Note: Drivers add up to mid-point of 2011 EPS range.

$(0.05)

ComEd 2011 EPS Contribution

2010A

Depreciation &

Amortization

Interest

Expense

$0.55 -

$0.65

$0.03

$(0.08)

$(0.03)

2011E

(3)

$ / Share

$(0.02)

$0.02

Other

RNF

(1)

O&M

(1)

Key Items:

Weather

Uncollectibles

Appellate Court ruling

Distribution revenue

(2)

Key Items:

Uncollectibles

$(0.04)

Inflation $(0.02)

Note: Drivers add up to mid-point of 2011 EPS range.

$0.68

$(0.04)

$(0.02)

$(0.01)

$0.08

(1)

Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of +/-$0.05/share. 2010 net income includes a one-time benefit for

collections of under-recovered 2008 and 2009 bad debt costs, as provided by the uncollectible expense rider approved by the ICC in February 2010. Going forward, the

rider provides for full recovery of all bad debt costs.

(2)

Distribution rate case currently pending, new rates will be effective in June 2011. Earnings guidance assumes mid-point of ComEd’s requested revenue increase.

(3)

Estimated contribution to Exelon’s operating earnings guidance.

PECO 2011 EPS Contribution

$ / Share

RNF

(2)

$(0.03)

$0.54

(1)

CTC,net

2011E

(3)

Key Items:

Electric & Gas

Distribution Rate

$0.19

Weather $(0.05)

Key Items:

Inflation $(0.01)

Bad Debt $(0.01)

$0.14

O&M

(2)

$0.50 -

$0.55

(1)

$(0.04)

2010A

(1)

Excludes preferred dividends.

(2)

Excludes items that are income statement neutral and estimated impact of energy efficiency and smart meter costs recoverable under a rider of $0.10/share.

(3)

Estimated contribution to Exelon’s operating earnings guidance.

Note: Drivers add up to mid-point of 2011 EPS range.

$(0.03)

Depreciation

$(0.05)

Income Taxes

Key Items:

Revenue net $(0.06)

of amortization

Interest on PECO

transition bonds $0.02

Key Assumptions

38.0

31.1

29.5

PECO

40.8

39.7

37.9

ComEd

37.1

37.5

38.3

Exelon Generation

38.1

36.7

37.2

Effective Tax Rate -

Operating (%)

136.59

144.40

106.13

RTO Capacity Price ($/MW-day)

2009 Actual

2010 Actual

2011 Est.

(3)

Nuclear Capacity Factor (%)

(1)

93.6

93.9

93.0

Total Generation Sales Excluding Trading (GWh)

173,065

171,789

168,700

Henry Hub Gas Price ($/mmBtu)

3.92

4.37

4.56

PJM West Hub ATC Price ($/MWh)

38.30

45.93

45.45

Tetco M3 Gas Price ($/mmBtu)

4.64

5.10

5.32

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

8.25

9.01

8.54

NI Hub ATC Price ($/MWh)

28.85

33.09

30.69

Chicago City Gate Gas Price ($/mmBtu)

3.92

4.46

4.61

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

7.36

7.42

6.66

MAAC Capacity Price ($/MW-day)

158.48

181.34

136.59

EMAAC Capacity Price ($/MW-day)

173.73

181.34

136.59

Electric Delivery Growth (%)

(2)

PECO

0.6

0.1

0.0

ComEd

(0.1)

0.2

0.0

(1)

Excludes Salem.

(2)

Weather-normalized retail load growth.

(3)

Reflects forward market prices as of December 31, 2010.

Note:

The

estimates

planned

generation

not

represent

guidance

forecast

future

results

Exelon

has

not

completed

its

planning

optimization

processes.

Total Portfolio Characteristics

110,594

142,400

42,003

5,295

13,897

26,300

50,000

100,000

150,000

200,000

2010

2011E

ComEd Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

Expected Total Supply (GWh)

Expected Total Sales

(GWh)

92,493

91,300

47,517

48,100

27,090

26,500

4,689

2,800

50,000

100,000

150,000

200,000

2010

2011E

Forward / Spot Purchases

Fossil and Renewables

Mid-Atlantic Nuclear

Midwest Nuclear

171,789

168,700

Note:

The

estimates

planned

generation

not

represent

guidance

forecast

future

results

Exelon

has

not

completed

its

planning

optimization

processes.

Refueling Outage Schedule

Note:

Data

includes

Salem.

Net

nuclear

generation

data

based

ownership

interest.

The

estimates

planned

generation

not

represent

guidance

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

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 (2009-10):

~29 days

(1)

Nuclear Refueling Cycle

12 planned refueling outages,

including 2 at Salem; Clinton outage

was moved from spring 2012 to fall

2011

6 refueling outages planned for the

Spring and 6 refueling outages

planned for the Fall

2011 Refueling Outage Impact

(1)

Excludes Salem.

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Nuclear Output

Actual

Plan

# of Outages

ComEd 2010 Rate Case Update

ComEd Surrebuttal (1/3/11)

$326M increase requested

11.50% ROE / 47.28% equity ratio

Rate base $7,349M

2009 test year with pro forma plant

additions through 6/30/11

ICC Staff Position

$116M increase proposed in Dec 2010

rebuttal testimony

10.00% ROE / 47.11% equity ratio

Rate base $6,602M

Pro forma plant additions and

depreciation reserve through 12/31/10

(ICC Docket No. 10-0467)

$ millions

ComEd Original Request (6/30/10)

396

Adjustments:

Bonus Depreciation

(14)

Pro forma plant adds/O&M update

(4)

Errata in Initial Filing

(12)

Reduction to Reg Asset Amortization

(8)

Other Items

(4)

ComEd Rebuttal (11/22/10)

354

Adjustments:

New Bonus Depreciation

(22)

Pro forma plant adds/O&M update

(4)

Reduction to AMI/Other

(2)

ComEd Surrebuttal (1/3/2011)

326

Reconciliation of ComEd Request to ComEd Surrebuttal

Note: See slide 17 for ComEd rate case key dates

* ComEd request does not reflect Appellate Court decision relating to

depreciation reserve, which we estimate would have a $85M reduction

to revenue requirement

ComEd Customer Usage Breakdown

Other

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

Leisure & Hospitality

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Customer Usage by Revenue Class

Top 380 Customer Usage by Segment

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

production via longer production runs and additional shifts due to improved

economic conditions for manufacturing-based customers, especially in the

steel and transportation sectors, along with data center expansions.

PECO Customer Usage Breakdown

Other

Other Large

C&I

24%

150 Large

C&I

17%

Small C&I

22%

Residential

34%

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

Retail Trade

Finance, Insurance & Real Estate

12%

Pharmaceuticals

Customer Usage by Revenue Class

Top 150 Customer Usage by Segment

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

Sufficient Liquidity

Outstanding Facility Draws

(338)

(134)

(1)

(196)

Outstanding Letters of Credit

$7,365

$4,834

$574

$1,000

Aggregate Bank Commitments

(1)

7,027

4,700

573

804

Available Capacity Under Facilities

(2)

Outstanding Commercial Paper

$7,027

$4,700

$573

$804

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

Available Capacity Under Bank Facilities as of January 14, 2011

(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.

Plan

extend/refinance

Exelon

Generation,

PECO

and

Exelon

Corp

credit

facilities in first half of 2011

Key Credit Metrics

0.0x

2.0x

4.0x

6.0x

8.0x

10.0x

12.0x

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

10%

15%

20%

25%

30%

35%

40%

45%

50%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

FFO / Debt

(1)

Reflects FFO / Debt, Interest Coverage and Debt / Cap ratios as calculated by S&P.

(2)

Reflects S&P Target Range. See slide 41 for reconciliations to GAAP.

(3)

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

(4)

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

30-35%

(3)

15-18%

FFO / Debt

Target

Range

(2)

BBB+

Fitch

Credit

Ratings

(4)

BBB

A-

BBB-

S&P

Credit

Ratings

(4)

Baa1

Moody’s

Credit

Ratings

(4)

ComEd:

PECO:

Generation:

Exelon:

Interest Coverage

(1)

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010A

2011E

ExGen/Corp

ComEd

PECO

Debt / Cap

(1)

Metric Calculations 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

Adjusted Interest:

Net Interest Expense

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ AFUDC & Capitalized interest

+ Interest on Present Value (PV) of Operating Leases

+ Interest on Imputed Debt Related to PV of Power Purchase Agreements (PPA)

PECO Transition Bond Interest Expense

Interest Coverage:

FFO

= Adjusted Debt

+ Off-balance sheet debt equivalents

(3)

PECO Transition Bond Principal Balance

+ STD

LTD

Adjusted Debt:

Adjusted Debt

(2)

FFO / Debt:

(1)

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

(2)

Uses current year-end adjusted debt balance.

(3)

Metrics

are

calculated

presentation

adjusted

for

debt

equivalents

for

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax)

and

other

minor

debt equivalents.

+ Adjusted Debt

(3)

Debt / Cap:

= Adjusted Capitalization

Adjusted Debt

(2)

Adjusted Capitalization

Adjusted Capitalization:

Total shareholder’s equity

+ Preferred Securities of Subsidiaries

4Q GAAP EPS Reconciliation

(0.01)

2007 Illinois electric rate settlement

(0.01)

John Deere Renewables acquisition costs

0.01

Asset Retirement Obligation reduction

(0.03)

Retirements of fossil generation units / plant retirements

(0.17)

Mark-to-market adjustments from economic hedging activities

$0.79

$(0.01)

$0.03

$0.14

$0.63

4Q 2010 GAAP Earnings (Loss) Per Share

$0.96

$(0.01)

$0.03

$0.13

$0.81

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

0.04

Unrealized gains related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended December 31, 2010

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

0.04

Mark-to-market adjustments from economic hedging activities

(0.01)

City of Chicago settlement with ComEd

(0.02)

(0.01)

Costs associated with early debt retirements

(0.02)

2007 Illinois electric rate settlement

(0.05)

Retirement of fossil generating units

0.02

Unrealized gains related to nuclear decommissioning trust funds

$0.88

$(0.03)

$0.12

$0.15

$0.64

4Q 2009 GAAP Earnings (Loss) Per Share

$0.92

$(0.02)

$0.12

$0.16

$0.66

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

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended December 31, 2009

YTD GAAP EPS Reconciliation

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

(0.01)

John Deere Renewables acquisition costs

0.01

Asset Retirement Obligation reduction

(0.10)

(0.01)

(0.03)

(0.16)

0.10

Non-cash remeasurement of income tax uncertainties

(0.10)

(0.02)

(0.04)

Non-cash charge resulting from health care legislation

(0.05)

Impact of certain emission allowances

0.08

Mark-to-market adjustments from economic hedging activities

(0.08)

Retirement of fossil generating units

$3.87

$(0.10)

$0.49

$0.51

$2.97

FY 2010 GAAP Earnings (Loss) Per Share

$4.06

$(0.07)

$0.54

$0.68

$2.91

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

(0.02)

2007 Illinois electric rate settlement

0.08

Unrealized gains related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Twelve Months Ended December 31, 2010

0.16

Mark-to-market adjustments from economic hedging activities

(0.05)

Retirement of fossil generating units

(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)

Impairment of certain generating assets

(0.03)

(0.00)

(0.02)

(0.01)

2009 severance charges

0.05

Nuclear decommissioning obligation reduction

(0.03)

NRG acquisition costs

0.19

Unrealized gains related to nuclear decommissioning trust funds

0.10

(0.02)

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

$3.16

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

Exelon

Other

PECO

ComEd

ExGen

Twelve Months Ended December 31, 2009

GAAP to Operating Adjustments

Exelon’s 2011 adjusted (non-GAAP) operating earnings outlook excludes the

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

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

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

•

Significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

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

•

Financial impacts associated with the planned retirement of fossil generating units

•

Other unusual items

•

Significant changes to GAAP

Operating earnings guidance assumes normal weather for full year

O&M reconciliation:

2010

2011

ExGen

ComEd

PECO

Other

Exelon

ExGen

ComEd

PECO

Other

Exelon

Operating and maintenance (GAAP)

2,812

1,069

733

(14)

4,600

3,010

1,220

820

(10)

5,040

JDR acquisition costs

(11)

Retirement of Fossil Generating Units

(3)

(30)

Non-cash charge resulting from health care legislation

(4)

(3)

(2)

(1)

Asset Retirement Obligation reduction

Adjusted Non-GAAP O&M

2,794

1,076

732

(6)

4,596

2,980

1,220

820

(10)

5,010

Decommissioning accretion

(57)

(70)

Regulatory required programs

(94)

(53)

(147)

(150)

(110)

(260)

Operating O&M (as shown on slide 13)

2,737

982

679

(6)

4,392

2,910

1,070

710

(10)

4,680

($ millions)

Exelon (EXC) 8-KIntroduces Guidance Range for Full Year 2011 Earnings