Earnings Conference Call •

1

st

Quarter 2009

April 23, 2009

EXHIBIT 99.2

2

Forward-Looking Statements

This presentation includes forward-looking statements.  There are a number of risks and

uncertainties that could cause actual results to differ materially from the forward-looking

statements made herein.   The factors that could cause actual results to differ materially from

these forward-looking statements include those discussed in (1) Exelon’s 2008 Annual Report

on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis

of

Financial

Condition

and

Results

of

Operations

and

(c)

ITEM

8.

Financial

Statements

and

Supplementary Data: Note 18; (2) Exelon’s First Quarter 2009 Quarterly Report on Form 10-Q

(to be filed on April 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part

I, Financial Information, ITEM 1. Financial Statements: Note 13 and (3) other factors discussed

in Exelon’s filings with the SEC.  Readers are cautioned not to place undue reliance on these

forward-looking statements, which apply only as of the date of this communication.  Exelon

does not undertake any obligation to publicly release any revision to its forward-looking

statements to reflect events or circumstances after the date of this communication, except as

required by law.

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

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

operating earnings and cash flows are representative of the underlying operational results of

the Companies. Please refer to the attachments to the earnings release and the appendix to

this presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP

earnings and non-GAAP cash flows to GAAP cash flows.

3

3

Our Sustainable Advantage Remains

4

Key Financial Messages

Q1 operating results of $1.20/share driven by:

Exceptional

nuclear

operations

–

96.2%

capacity

factor

Increased electric distribution revenues at ComEd and gas distribution revenues at

PECO due to 2008 rate case decisions

Benefit from Illinois tax ruling

Reduced load in ComEd and PECO service territories

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

91-94%

of

2009

expected

generation

hedged

(1)

On

track

to

keep

2009

operating

O&M

(2)

costs

flat

to

2008

at

$4.5

billion

Well-positioned in challenging economic times

Strong

cash

flow

from

operations

(3)

–

forecasted

at

$5.1

billion

for

2009,

an

increase

of $350 million over original planning assumptions

Completed

$250

million

PECO

bond

issuance

in

Q1

2009

and

limited

debt

maturities

in

2009

($29

million

total)

(4)

Refer

to

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

(1) As of February 28, 2009.

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

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

investing activities other than capital expenditures.

(4) Excludes securitization debt and includes capital leases.

5

$0.73

$0.91

$0.15

$0.17

$0.17

$0.07

2008

2009

Operating EPS

$1.20

HoldCo/Other

ExGen

PECO

ComEd

1st Quarter (Q1)

$0.93

All Exelon operating companies reported higher quarter over quarter earnings

Refer

to

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP EPS.

$0.88

$1.08

GAAP EPS

6

Exelon Generation                         

Operating EPS Contribution

2009

2008

Key Drivers –

Q1 ’09 vs. Q1 ’08

(1)

Higher nuclear volume due to fewer

nuclear refueling outages: +$0.07

Favorable portfolio/market conditions:

+$0.04

Higher nuclear fuel costs: ($0.01)

Lower O&M costs due to fewer nuclear

refueling outages, partially offset by

higher inflation and pension & OPEB

expense: +$0.03

Activity related to Nuclear

Decommissioning Trust Funds: +$0.01

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

operating EPS to GAAP EPS

Q1 2009

$0.73

$0.91

34

104

Refueling

13

26

Non-refueling

Q1 2009

Q1 2008

Outage Days

7

Key Drivers –

Q1 ’09 vs. Q1 ’08

(1)

Higher electric distribution rates:

+$0.06

Benefit from Illinois tax ruling: +$0.05

Reduced load: ($0.01)

Higher pension and OPEB expense

largely offset by cost savings

initiatives:

($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

Q1 2009

2009

2008

$0.07

$0.17

8

PECO Operating EPS Contribution

Key Drivers –

Q1 ’09 vs. Q1 ’08

(1)

Higher gas distribution rates: +$0.03

Weather: +$0.02

Competitive Transition Charge (CTC)

amortization:

($0.02)

Higher O&M costs primarily due to

bad debt expense: ($0.01)

Reduced

load:

($0.01)

2009

2008

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

operating EPS to GAAP EPS

Q1 2009

$0.15

$0.17

9

ComEd Load Trends

Weather-Normalized Load

Customer Usage by Revenue Class

Key Economic Indicators

Top 380 Customer Usage by Segment

Other

2%

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

3%

Leisure & Hospitality

9%

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Chicago

U.S.

Unemployment

rate

(1)

9.1%

8.5%

Q1 2009 annualized growth in

gross

domestic/metro

product

(2)

(5.2%)

(4.3%)

1/09

Home

price

index

(3)

(16.4%)

(19%)

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

(April 2009 reports)

(2)

Source:

Moody’s

Economy.com

(April

2009)

(3)

Source: S&P Case-Shiller Index

(4)

Adjusted for leap year impact

(5)

Not adjusted for leap year impact

Q4 2008      Q1 2009

(4)

Q1

2009

(5)

2009E

(5)

Customer Growth

0.1%

(0.2%)

(0.2%)         0.2%

Average Use-Per-Customer

(0.6%)

(1.0%)

(2.2%)

(1.0%)

Total Residential

(0.5%)

(1.2%)

(2.4%)       (0.8%)

Small C&I

(2.9%)

(1.3%)

(2.4%)       (0.7%)

Large C&I

(1.0%)

(5.3%)

(6.4%)       (2.6%)

All Customer Classes

(1.6%)

(2.5%)

(3.6%)       (1.3%)

Note: C&I = Commercial & Industrial

10

PECO Load Trends

Other

2%

Other Large

C&I

21%

150 Large

C&I

21%

Small C&I

22%

Residential

34%

Weather-Normalized Electric Load

Q4 2008

Q1

2009

(3)

Q1

2009

(4) 

2009E

(4)

Customer Growth

0.5%

0.1%

0.1%

0.2%

Average Use-Per-Customer

(0.9%)

0.1%

(1.1%)

(0.2%)

Total Residential

(0.4%)

0.2%          (1.0%)

0.0%

Small C&I

0.7%

0.0%          (1.2%)

(0.8%)

Large C&I

(2.4%)

(3.3%)         (4.4%)

(2.8%)

All Customer Classes

(1.1%)

(1.1%)         (2.2%)

(1.2%)

Customer Usage by Revenue Class

Philadelphia

U.S.

Unemployment

rate

(1)

7.6%

8.5%

Q1 2009 annualized growth in

gross

domestic/metro

product

(2)

(4.8%)

(4.3%)

Key Economic Indicators

Top 150 Customer Usage by Segment

18%

Health & Educational Services

19%

Manufacturing

21%

Petroleum

3%

Retail Trade

4%

Other

9%

Transportation, Communication

& Utilities

13%

Finance, Insurance & Real

Estate

13%

Pharmaceuticals

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

(April 2009)

(2)  Source:

Moody’s

Economy.com

(April

2009)

(3)  Adjusted for leap year impact

(4)  Not adjusted for leap year impact

11

Q1 07

Q1 08

Q1 09

ComEd and PECO Accounts Receivable

>60 days

31-60 days

0-30 days

ComEd Accounts

Receivable

(1)

Through the first quarter of 2009 ComEd has experienced limited deterioration in its

accounts receivable aging; PECO has experienced a slight improvement

% of AR

Q1 07

Q1 08

Q1 09

PECO Accounts

Receivable

(1)

% of AR

$785M

$821M

$723M

$811M

$846M

$831M

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

ComEd and PECO and long-term receivables at PECO.

>60 days

31-60 days

0-30 days

12

2009 Operating Earnings Guidance

2009E

2008A

$0.49

$3.46

$4.20

ComEd

PECO

Exelon

Generation

ComEd distribution revenue

PECO gas revenue

O&M and other

Pension/OPEB

Inflation

Cost reduction initiatives

Bad debt expense

Nuclear fuel costs

Depreciation and amortization

PECO CTC

2009 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.33

Exelon

$4.00 -

$4.30

(1)

$0.45

-

$0.55

$0.45

-

$0.55

$3.10

-

$3.35

(1)

Adjusted

(non-GAAP)

Operating

Earnings

Guidance.

Excludes

the

earnings

impact

of

certain

items

as

disclosed

in

the

Appendix.

Note: A = Actual; E = Estimate

Reaffirming

2009

operating

earnings

guidance

of

$4.00-$4.30/share

(1)

-

expect second quarter 2009 results between $0.95 to $1.05/share

13

Well-Positioned in Near-Term    

Economic Uncertainty

•

Hedging strategy provides near-term cash flow stability and protects

investment-grade balance sheet

•

91-94% and 81-84% of expected generation hedged in 2009 and

2010,

respectively

(1)

Risk management

•

Proven management team

•

Lowest-cost

nuclear

fleet

operator

with

~94%

annual

capacity

factor

Best-in-class management /

operations

•

Nuclear remains a low-cost generation source

•

Improving

utilities’

performance

and

regulatory

environment

Basics of business unchanged

•

Nation’s largest nuclear fleet ~140,000 GWhs of annual production

Market leader

•

Progress made on transition to competitive markets in PA -

PAPUC approved PECO's procurement settlement on April 16th;    

initial residential procurement will be held in June 2009

•

ComEd on path to financial recovery

•

Positively levered to long-term fundamentals

Long-term value in place

•

Strong

and

consistent

cash

flows

from

operations

(2)

–

$5.1

billion

estimated in 2009

•

~$6.9 billion of available credit facilities as of April 17, 2009

•

Completed $250 million PECO bond issuance in Q1 2009

•

Total

debt

maturities

of

$29

million

(3)

through

the

end

of

2009

Sufficient liquidity

Investment Criteria

Exelon Profile

(1)

As of February 28, 2009.

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

in investing activities other than capital expenditures.

(3) Excludes securitization debt and includes capital leases.

14

Appendix

15

Cost and Capital Management

•

Clearly define governance and oversight model

•

Optimize the Exelon operational structure to drive efficiency and accountability,

reducing complexity and cost

•

Provide better visibility on cost drivers and productivity

•

Process improvement and focus on high-value work

•

Continue to manage capital spending

Driving productivity and cost reduction while maintaining superior operations

We remain committed to holding 2009 O&M flat to 2008, which includes realizing      

$150 million of sustainable cost savings this year

$4,500

(2)

$4,500

Exelon Consolidated

(3)

$700

$750

PECO

$1,050

$1,100

ComEd

$2,750

$2,700

Exelon Generation

2009E

2008A

O&M Expense

(1)

(in millions)

(1)  Reflects operating O&M data and excludes Decommissioning impact. ComEd and PECO operating O&M exclude energy efficiency spend recoverable under a rider.

(2)  Reflects ~$175

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

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

$3,350

$3,200

Exelon Consolidated

(3)

$400

$400

PECO

$875

$950

ComEd

$2,000

$1,750

Exelon Generation

2009E

2008A

CapEx

(in millions)

16

2009 Pension and OPEB Expense and

Contributions

Pension

and

OPEB

Plans

Key

Metrics

–

12/31/08

($

in

millions)

Pension

Assets

$6,660

Obligations

$10,840

2009E

2008

$85

$210

$160

$210

$80

$90

$163

$155

2009E

2008

(1) 

Excludes settlement charges.

(2)

Contributions reflect the application of recently issued U.S. Treasury Department guidance and cover both the qualified and non-qualified plans.  Management has not yet

made a final decision regarding its 2009 pension contributions and may make additional discretionary contributions based upon final interpretations of the Worker, Retiree and

Employer Recovery Act of 2008.

(3)

Management has not yet made a decision regarding its 2009 OPEB contributions.  Approximately $100 million of the estimated 2009 OPEB contributions is discretionary. 

Contributions shown above include contributions paid out of corporate assets.

(4)    Assumes

a

20%

overall

capitalization

rate

for

pension

and

OPEB

costs.

Note: OPEB = other postretirement benefits; EROA = expected return on assets

(1)

(2)

(3)

OPEB

Assets

$1,220

Obligations

$3,340

Key Metrics

2008 asset return

-26%

12/31/08 discount rate

6.09%

Assumed

long-term

EROA

8.5%

YTD asset returns

through

3/31/09

-6%

Pre-Tax Expense

$0

$50

$100

$150

$200

$250

Pension

OPEB

(4)

Cash Contributions

$0

$50

$100

$150

$200

$250

Pension

OPEB

17

Illinois Power Agency Procurement Plan

•

On January 7, 2009, the Illinois

Commerce

Commission

approved

(1)

,

with

minor modifications, the Illinois Power

Agency’s (IPA) proposed procurement

plan filed in September 2008 

•

In April/May the remaining ComEd 2009-

2010 load (~29% of the total) and a

portion of its 2010-2011 load (~8% of the

total) will be procured through a

procurement event

ComEd files retail generation rates

By May 6

Procurement administrator submits 

confidential report

By April 30

Bidders qualified to submit bids for

procurement event

April 23

Potential bidders submit qualifying

proposals

April 15 –

20

2009 IPA Procurement Event –

Key Dates

Bids due

April 29

ICC decision on RFP results and public

release of wholesale energy prices

By May 4

NOTE:

Chart

is

for

illustrative

purposes

only.

Assumes

constant

load

profile

each

year.

Jun

2007

Jun

2008

Jun

2009

Jun

2010

Jun

2011

Jun

2012

Jun

2013

Future Procurement by Illinois

Power Agency

Auction

Contracts

Financial

Swap

3/08

RFP

4/09

RFP

2010

2010

2011

2012

2011

Estimated Volumes to Secure in

2009 IPA Procurement Event (GWh)

Off-Peak

Peak

Contract Period

2,461

7,673

983

June 2010 –

May 2011

5,712

June 2009 –

May 2010

The procurement event will include monthly

peak and off-peak standard wholesale block

energy products (in 50 MW blocks) to be

delivered to NiHub

(1) Reference: ICC Docket#08-0519

4/09

RFP

18

PECO Post-2010 Procurement Plan

PAPUC

approved

PECO's

procurement

settlement

on

April

16

th

;                             

initial residential procurement will be held in June 2009

Procurement plan

for obtaining default service includes a portfolio of full requirements

and spot products competitively procured through multiple RFP solicitations

Mitigation plan

includes early staggered procurement, voluntary post-rate cap phase-in,

gradual

phase-out

of

declining

block

rate

design,

customer

education,

enhanced

retail

choice program and low-income rate design changes

Default Service

Procurement and

Mitigation Filing

Early Phase-in

Filing

Procurement

Settlement

Early phase-in proposal

provides an opt-in program for customers to pre-pay

PAPUC approval in March 2009 allows for enrollment to begin as early as May 2009

80

3 Months

Winter On-Peak (5 X 16) (Dec., Jan., Feb.)

130

3 Months

Summer On-Peak (5 X 16) (June, July, Aug.)

160

100

50

12 months

24 months

60 months

Baseload (24 X 7)

MW

Duration

Residential Forward Energy Block Products

90% full requirements with 1-year (70%) and 2-year

(20%) terms; 10% full requirements spot

Small Commercial

(peak demand <100 kW)

Day-ahead hourly priced service; 1-year fixed price

optional service from 1/1/11 to 12/31/11

Large Commercial & Industrial

(peak demand >500 kW)

85% full requirements with 1-year term; 15% full

requirements spot

Medium Commercial

(peak demand >100 but <=500 kW)

75% full requirements with 1-year (30%) and 2-year

(45%) terms; 20% energy block and 5% spot

Residential

Products

Customer Class

19

2009 Projected Sources and Uses of Cash

5,100

2,900

950

1,250

Cash

Flow

from

Operations

(1)

(50)

0

250

(50)

Other

(550)

0

(250)

(50)

Net

Financing

(excluding

Dividend):

(2)

250

0

250

0

Planned

Debt

Issuances

(3)(4)

Net

Financing

(excluding

Dividend):

(2)

(750)

0

(750)

0

Planned

Debt

Retirements

(5)

$500

$400

$50

$50

Beginning Cash Balance

(3,350)

(2,000)

(400)

(875)

Capital Expenditures

$1,700

$1,300

$350

$375

Cash Available before Dividend

(1,400)

Dividend

(6)

$300

Cash Available after Dividend

Exelon

(7)

($ in Millions)

(1)

Cash Flow from Operations primarily includes net cash flows provided by operating activities (excluding counterparty collateral activity) and net cash flows used in investing activities other than capital expenditures.

PECO Cash Flow from Operations includes $500M for Competitive Transition Charges.

(2)

Net Financing (excluding Dividend) = Net cash flows used in financing activities excluding dividends paid on common and preferred stock.

(3)

Excludes

Exelon

Generation

and

ComEd

tax-exempt

bonds

that

are

backed

by

letters

of

credit

(LOCs),

which

expire

in

2009.

Generation

and

ComEd

are

currently

evaluating

whether

they

will

reissue

this

debt

in

the

variable

rate

mode

with

a

letter

of

credit

in

order

to

increase

the

value

and

marketability

of

the

debt,

or

reissue

the

debt

and

change

the

interest

rate

mode

of

the

bonds

into

a

put

mode

or

fixed

rate

to

maturity,

which

does not require a letter of credit.

(4)

Excludes PECO’s Accounts Receivable Agreement with Bank of Tokyo.  Assumes PECO’s A/R Agreement is extended in accordance with its terms beyond September 18, 2009.

(5)

Planned Debt Retirements are $17M, $728M, and $12M for ComEd, PECO, and ExGen, respectively.  Includes securitized debt.

(6)

Assumes

2009

Dividend

of

$2.10

per

share.

Dividends

are

subject

to

declaration

by

the

board

of

directors.

(7)

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

20

Sufficient Liquidity

(1)  Excludes previous commitment from Lehman Brothers Bank.

(2)  Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility

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

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

(50)

--

--

(50)

Outstanding Facility Draws

(288)

(127)

(15)

(141)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate

Bank

Commitments

(1)

6,979

4,707

559

761

Available

Capacity

Under

Facilities

(2)

(94)

--

--

--

Outstanding Commercial Paper

$6,885

$4,707

$559

$761

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ in Millions)

Exelon has minimal commercial paper outstanding and its bank facilities are largely untapped

Available Capacity Under Bank Facilities as of April 17, 2009

21

Projected 2009 Key Credit Measures

BBB

A-

BBB+

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa2

Baa1

Moody’s Credit

Ratings

(3)

3.9x

4.0x

FFO / Interest

ComEd:

20%

15%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

3.4x

3.2x

FFO / Interest

PECO:

15%

12%

FFO / Debt

48%

53%

Rating Agency Debt Ratio

23%

45%

Rating Agency Debt Ratio

128%

51%

FFO / Debt

30.3x

11.5x

FFO / Interest

Exelon

Generation:

49%

36%

7.2x

Without PPA &

Pension / OPEB

(2)

61%

Rating Agency Debt Ratio

24%

FFO / Debt

6.0x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

and

PECO

metrics

exclude

securitization

debt.

See

following

slide

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

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

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

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current

senior

unsecured

ratings

for

Exelon

and

Exelon

Generation

and

senior

secured

ratings

for

ComEd

and

PECO

as

of

April

17,

2009.

On

October

21,

2008,

S&P

put

Exelon, ComEd, PECO and Exelon Generation on CreditWatch with negative implications. On October 21, 2008, Fitch placed Exelon and Exelon Generation on rating watch

negative.

On

November

12,

2008,

Moody’s

placed

the

ratings

of

Exelon,

Exelon

Generation

and

PECO

under

review

for

possible

downgrade.

22

FFO Calculation and Ratios

FFO Calculation

= FFO

-

PECO Transition Bond Principal Paydown

+

Gain

on

Sale,

Extraordinary

Items

and

Other

Non-Cash

Items

(3)

+ Change in Deferred Taxes

+ Depreciation,

amortization

(including

nucl

fuel

amortization),

AFUDC/Cap.

Interest

Add back non-cash items:

Net Income

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

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

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

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

obligations,

and

Capital

Adequacy

for

Energy

Trading

(2)

,

as

applicable

-

PECO Transition Bond Interest Expense

Net Interest Expense (Before AFUDC & Cap. Interest)

FFO Interest Coverage

+

Capital

Adequacy

for

Energy

Trading

(2)

FFO

= Adjusted Debt

+ PV of Operating Leases

+

100%

of

PV

of

Purchased

Power

Agreements

(2)

+

Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(1)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+

Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

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

(1)

Uses current year-end adjusted debt balance.

(2)

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

Adequacy for Energy Trading.

(3)

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

23

Q1 GAAP EPS Reconciliation

0.08

0.02

-

-

0.06

Mark-to-market adjustments from economic hedging activities

(0.06)

-

-

-

(0.06)

Unrealized gains & losses related to nuclear decommissioning   

trust funds

$0.88

$0.00

$0.15

$0.07

$0.66

Q1 2008 GAAP Earnings Per Share

$0.93

$(0.02)

$0.15

$0.07

$0.73

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

(0.07)

-

-

-

(0.07)

2007 Illinois electric rate settlement

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended March 31, 2008

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

(0.05)

-

-

-

(0.05)

Unrealized gains & losses related to nuclear decommissioning   

trust funds

(0.01)

(0.01)

-

-

-

NRG acquisition costs

(0.03)

-

-

-

(0.03)

2007 Illinois electric rate settlement

0.17

-

-

-

0.17

Mark-to-market adjustments from economic hedging activities

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

$1.08

$(0.06)

$0.17

$0.17

$0.80

Q1 2009 GAAP Earnings (Loss) Per Share

$1.20

$(0.05)

$0.17

$0.17

$0.91

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

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended March 31, 2009

24

2009 Earnings Outlook

•

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

excludes the earnings impacts of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments

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

former AmerGen

Energy Company, LLC units)

•

Any significant impairments of assets, including goodwill

•

Any changes in decommissioning obligation estimates

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement,

including

ComEd’s previously announced customer rate relief programs

•

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

•

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

•

Other unusual items

•

Significant future changes to GAAP

•

Operating earnings guidance assumes normal weather for the remainder

of the year

25

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 February 28, 2009. The following

slides were originally filed via Form 8-K on April 14, 2009. Going forward, we plan to update the

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.

26

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio

–

sell

what

we

own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

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

while positioning us to participate in long-term upside potential

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

27

27

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

28

28

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

2009

2010

2011

Estimated

Open

Gross

Margin

(millions)

(1,2)

$5,450

$5,900

$6,350

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)

$4.71

$30.63

$45.08

($1.08)

$6.08

$31.64

$50.35

($0.99)

$6.69

$36.93

$54.18

$0.36

(1)

Based on February 28, 2009 market conditions. 

(2)

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

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

assumes

there

is

no

hedging

in

place

other

than

fixed

assumptions

for

capacity

cleared

in

the

RPM

auctions

and

uranium

costs

for

nuclear

power

plants.

Open

gross

margin

contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity payments.  The estimation of open gross margin

incorporates

management

discretion

and

modeling

assumptions

that

are

subject

to

change.

(3)

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

Exelon Generation Open Gross Margin and

Reference Prices

29

29

(1)

Expected

generation

represents

the

amount

of

energy

estimated

to

be

generated

or

purchased

through

owned

or

contracted

for

capacity.

Expected

generation

is

based

upon

a

simulated

dispatch

model

that

makes

assumptions

regarding

future

market

conditions,which

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options. 

Expected generation assumes 10 refueling outages in 2009 and 2010 and 11 refueling outages in 2011 at Exelon-operated nuclear plants and Salem.  Expected generation assumes

capacity factors of 93.3%, 92.7% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 do not represent

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

(2)

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

power, options, and swaps.  Uses expected value on options.

(3)

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

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

revenue,

but

includes

the

mark-to-market

value

of

capacity

contracted

at

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

It

can

be

compared

with

the

reference

prices

used

to

calculate

open

gross

margin

in

order

to

determine

the

mark-to-market

value

of

Exelon

Generation's

energy

hedges.

2009

2010

2011

Expected Generation

(GWh)

(1)

170,500

166,100

167,500

Midwest

99,400

96,900

98,500

Mid-Atlantic

57,500

58,500

58,100

South

13,600

10,700

10,900

Percentage

of

Expected

Generation

Hedged

(2)

91-94%

81-84%

40-43%

Midwest

93-96

79-82

49-52

Mid-Atlantic

93-96

91-94

27-30

South

67-70

39-42

14-17

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$48.00

$48.00

$47.25

Mid-Atlantic

$37.00

$37.50

$71.25

ERCOT North ATC Spark Spread

$3.75

$5.00

$7.00

Generation Profile

30

30

Gross

Margin

Sensitivities

with

Existing

Hedges

(millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2009

$18

($4)

$10

($9)

$20

($18)

+/-$40

2010

$70

($50)

$115

($115)

$30

($30)

+/-$50

2011

$420

($390)

$265

($265)

$230

($230)

+/-$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1) 

Based on February 28, 2009 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an

internal model that is updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs

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

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

31

31

95% case

5% case

$6,800

$6,500

$5,800

$6,900

$6,100

$8,900

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

$10,000

2009

2010

2011

(1) 

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

margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These

ranges of approximate gross margin in 2010 and 2011 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or

optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as

of February 28, 2009.

32

32

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin 

$5.45 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,400GWh * 94% *

($48.00/MWh-$30.63/MWh)

= $1.6 billion

57,500GWh * 94% *

($37.00/MWh-$45.08/MWh)

= ($0.4 billion)

13,600GWh * 68% *

($3.75/MWh-($1.08)/MWh)

= $0.0 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.45 billion

MTM

value

of

energy

hedges:

$1.6

billion

+

($0.4

billion)

+

$0.0

billion

Estimated hedged gross margin:          $6.65 billion

Illustrative Example

of Modeling Exelon Generation 2009 Gross Margin

(with Existing Hedges)

33

50

60

70

80

90

100

110

120

130

140

150

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

20

30

40

50

60

70

80

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

35

45

55

65

75

85

95

105

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5.5

6.5

7.5

8.5

9.5

10.5

11.5

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

33

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2010

2011

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

Forward NYMEX Coal

$6.07

$6.88

2010

2011

$58.56

$65.00

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

2010 Ni-Hub

2011 Ni-Hub

2011 PJM-West

2010 PJM-West

$59.04

$65.20

$41.66

$23.22

$47.21

$24.11

$40.50

$43.03

34

6

7

8

9

10

11

12

13

14

15

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

45

50

55

60

65

70

75

80

85

90

95

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

5

6

7

8

9

10

11

4/08

5/08

6/08

7/08

8/08

9/08

10/08

11/08

12/08

1/09

2/09

3/09

4/09

34

Market Price Snapshot

2011

2010

2010

2011

2010

2011

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2010

2011

ERCOT North On Peak Spark Spread

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

$5.75

$6.58

$59.74

$51.31

$8.92

$9.08

$7.32

$9.77

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