Exelon 8K Results of Operations and Financial Condition | EXC 22 Jan 10

Earnings Conference Call •

Quarter 2009

January 22, 2010

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 2008 Annual Report

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

Financial

Condition

and

Results

Operations

and

(c)

ITEM

Financial

Statements

and

Supplementary

Data:

Note

18;

(2)

Exelon’s

Third

Quarter

2009

Quarterly

Report

Form

10-Q

(a)

Part

II,

Other

Information,

ITEM

1A.

Risk

Factors

and

(b)

Part

Financial

Information,

ITEM 1. Financial Statements: Note 14 and (3) other factors discussed in filings with the

Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison

Company,

PECO

Energy

Company

and

Exelon

Generation

Company,

LLC

(Companies).

Readers are cautioned not to place undue reliance on these forward-looking statements, which

apply only as of the date of this presentation. None of the Companies undertakes any

obligation to publicly release any revision to its forward-looking statements to reflect events or

circumstances after the date of this presentation.

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

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

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

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

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

earnings.

Please

refer

the

footnotes

the

following

slides

for

reconciliation

non-GAAP

cash flows to GAAP cash flows.

Nuclear

Uprates

Deploying Capital for Shareholder Value

Smart Grid

Carbon

Price

Recovery

Transmission

1,300–1,500 MW of new Exelon nuclear capacity by 2017, the

equivalent of a new nuclear plant at roughly half the cost of a

new plant and no incremental operating costs

Approximately $725 million in investments to build smart grid

infrastructure over the coming years with a regulated return on

investment

Lowest carbon intensity in the sector, significant upside if and

when legislation enacted or regulations promulgated, and

enhancing industry-leading position with Exelon 2020

Positioned to benefit from our fundamental view of recovery in

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

Leveraging transmission expertise to build Exelon

Transmission Company with the goal of improving reliability,

reducing congestion and moving renewable energy to

population centers

Key Financial Messages

Operating results

•

Operating

earnings

$0.92/share

for

4Q09

and

$4.12/share

for

2009

(1)

•

93.6% nuclear capacity factor for 2009

•

2009

cash

flow

from

operations

(2)

$5.78

billion,

billion

over

original

plan

Far exceeded cost savings expectations in 2009 to offset

unfavorable drivers

•

Realized an additional $200 million of cost savings over plan

Reaffirming 2010 operating earnings guidance of $3.60 -

$4.00/share

(1)

•

Committed to 2010 O&M target of $4.35 billion, offsetting inflation and $35 million

of higher pension and OPEB expense with additional cost savings

•

Initial signs that load stabilization will begin in 2010

•

91-94%

2010

expected

generation

hedged

(3)

(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) 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) As of December 31, 2009.

Note: Data contained on this slide is rounded.

$0.80

$0.12

$0.66

$0.12

$0.16

2008

2009

Operating EPS

$3.46

$3.16

$0.49

$0.54

$0.33

$0.54

2008

2009

HoldCo/Other

ExGen

PECO

ComEd

Quarter (4Q)

(1)

Exceeding cost savings target allowed Exelon to deliver results well within our

original

guidance

range

$4.00

$4.30/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.

$1.07

$0.88

GAAP EPS

Full Year (FY)

(1)

$4.12

$4.20

$4.13

$4.09

$0.92

$1.07

Exelon Generation

Operating EPS Contribution

2009

2008

Key Drivers –

4Q09 vs. 4Q08

(1)

Lower nuclear volume: $(0.04)

Unfavorable market/portfolio

conditions: $(0.03)

Higher nuclear fuel costs: $(0.02)

Higher O&M due to pension and

OPEB expense and 2008 nuclear

insurance credit, partially offset by

cost savings initiatives: $(0.02)

(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

4Q09

4Q08

Outage Days

(2)

$0.80

$0.66

$3.16

$3.46

2010

2011

2012

Hedging Update

2010

2011

2012

Percentage of Expected

Generation

Hedged

(1)

91-94%

69-72%

37-40%

Midwest

89-92

71-74

43-46

Mid-Atlantic

93-96

65-68

25-28

South

97-100

66-69

39-42

95% case

5% case

$6,500

$6,100

$4,800

$7,800

$6,200

$8,000

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

conditions, while positioning us to participate in long-term upside potential

Exelon

Generation

Gross

Margin

Upside/Risk

(2)

Expected Generation Hedged

(1)

Percent of expected generation hedged represents how many equivalent MW have been hedged at forward market prices as of December 31, 2009; all hedge products used

are converted to an equivalent average MW volume and the calculation considers whether hedges are power sales or financial products. Reflects decision to permanently

retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011, pending PJM approval.

(2)

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 in 2011 and 2012 do not represent earnings guidance or a forecast of future

results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for

power, fuel, load following products, and options as of December 31, 2009.

($ millions)

Key Drivers –

4Q09 vs. 4Q08

(1)

Lower O&M due to cost savings

initiatives, partially offset by higher

pension and OPEB expense:

+$0.03

Reduced load: $(0.01)

Weather: $(0.01)

’08 tax method change: $(0.02)

ComEd Operating EPS Contribution

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

2009

2008

$0.16

$0.54

$0.33

4Q09

Actual

Normal

Heating Degree Days 2,264

2,278

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

U.S.

Unemployment

rate

(1)

10.9%

10.0%

2009 annualized growth in

gross

domestic/metro

product

(2)

(3.1)%

(2.5)%

10/09

Home

price

index

(3)

(10.1)%

(7.3)%

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

Dept. of Labor (December 2009)

(2)

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

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

4Q09 2009

(4)

2010E

Customer Growth

(0.5)%

(0.4)%

0.1%

Average Use-Per-Customer

(1.1)%

(1.0)%

0.0%

Total Residential

(1.6)%

(1.4)%

0.0%

Small C&I

0.1%

(2.2)%

0.8%

Large C&I

(4.0)%

(6.7)%

1.5%

All Customer Classes

(1.6)%

(3.3)%

0.8%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10E

2Q10E

3Q10E

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

PECO Operating EPS Contribution

Key Drivers –

4Q09 vs. 4Q08

(1)

Higher other revenue net fuel, including

gas distribution revenues: +$0.02

Lower bad debt expense: +$0.02

Reduced load: $(0.01)

Weather: $(0.01)

Competitive Transition Charge (CTC)

amortization: $(0.02)

2009

2008

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

$0.12

$0.54

$0.49

4Q09

Actual

Normal

Heating Degree Days 1,567

1,634

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

U.S.

Unemployment rate

(1)

8.5% 10.0%

2009 annualized growth in

gross domestic/metro product

(2)

(3.6)% (2.5)%

(1) Source:

U.S

Dept.

Labor

(PHL

November

2009,

–

December

2009)

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

(3) Not adjusted for leap year effect

Note: C&I = Commercial & Industrial

4Q09 2009

(3)

2010E

Customer Growth

(0.4)%

(0.2)%

(0.1)%

Average Use-Per-Customer

0.2%

(2.1)%

(1.2)%

Total Residential

(0.2)%

(2.3)%

(1.3)%

Small C&I

(2.5)%

(2.7)%

(0.7)%

Large C&I

(1.4)%

(3.0)%

(2.4)%

All Customer Classes

(1.3)%

(2.6)%

(1.5)%

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10E

2Q10E

3Q10E

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

Pension and OPEB Expense and Contributions

Pension

Assets

$7,840

Obligations

$11,480

2010E

2009

$210

$250

$205

$200

$440

$260

$155

2010E

2009

(1)

(2)

(3)

OPEB

Assets

$1,475

Obligations

$3,660

Key Metrics

2009 asset return

12/31/09 discount rate

Assumed long-term EROA

Pension and OPEB expense is

increasing by $35 million pre-tax

Pre-Tax Expense

(4)

$50

$100

$150

$200

$250

$300

Pension

OPEB

Pension and OPEB Plans Key Metrics – 12/31/09E ($ in millions)

(1)

Includes settlement charges.

(2)

Contributions reflect the application of recently issued U.S. Treasury Department guidance and cover both the qualified and non-qualified plans. 2009 contributions include a

$350 million discretionary contribution. 2010 pension contributions are based on minimum regulatory requirements and additional amounts required to avoid benefit

restrictions. Management may elect to make additional discretionary contributions.

(3)

Approximately $100 million of the 2009/2010 OPEB contributions is discretionary. Management has not yet made a decision regarding its 2010 OPEB contributions.

Contributions shown above include amounts paid out of corporate assets.

(4)

Assumes an ~20% overall capitalization rate for pension and OPEB costs.

Note: OPEB = other postretirement benefits; EROA = expected return on assets. Data contained on this slide is rounded.

21%

5.83%

8.50%

Cash Contributions

$100

$200

$300

$400

Pension

OPEB

Delivering on Cost Savings Commitments

Holding O&M below 2008 levels for second consecutive year

Committed to 2010 O&M target of $4.35 billion, offsetting inflation and $35 million of higher

pension and OPEB expense with additional cost savings

•

Reduced positions by 500 (400 in corporate support and 100 at ComEd) in 2009

•

Freezing executive salaries and reducing other compensation benefits for 2010

Note: Data contained on this slide is rounded.

($ millions)

$0.7

$0.6

PECO

(1)

$1.0

ComEd

(1)

$2.7

Generation

2010E

2009A

$ billions

(2)

O&M Expense

(1)

Reflects operating O&M data and excludes decommissioning effect. ComEd and PECO operating O&M exclude energy efficiency and smart

meter costs recoverable under a rider.

(2)

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

$4,500

$4,300

$4,350

$450

$415

$245

2008A

2009A

2010E

Total O&M

Pension/OPEB Expense

2010 Operating Earnings Guidance

2010E

2009A

$0.54

$3.16

$4.12

(1)

ComEd

PECO

Exelon

Generation

2010 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Exelon

$0.54

Exelon

$3.60 -

$4.00

(1)

$0.60 -

$0.70

$0.40 -

$0.50

$2.55 -

$2.80

Reaffirming

2010

operating

earnings

guidance

$3.60

–

$4.00/share

(1)

–

expect

1Q10

results

between

$0.85

–

$0.95/share

(1)

Depreciation and Amortization

O&M

Cost Savings Initiative

Inflation

Pension/OPEB

ComEd

RNF

PECO RNF

Generation RNF

(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.

Appendix

2010 Projected Sources and Uses of Cash

(325)

n/a

(100)

(225)

Utility Growth CapEx

(4)

($ millions)

Exelon

(9)

Beginning Cash Balance

(1)

$1,050

Cash Flow from Operations

(1)(2)

1,025

900

2,325

4,250

CapEx (excluding Nuclear Fuel, Nuclear

Uprates and Solar Project, Utility Growth

CapEx)

(625)

(400)

(750)

(1,825)

Nuclear Fuel

n/a

(850)

Dividend

(3)

(1,400)

Nuclear Uprates and Solar Project

n/a

(375)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5,6)

250

300

550

Planned Debt Retirements

(7)

(225)

(400)

(1,025)

Other

(8)

175

125

Ending Cash Balance

(1)

$175

(1)

Excludes counterparty collateral activity.

(2)

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

Operations for PECO and Exelon includes $572 million for competitive transition charges. Net cash flow from operations includes $225 million of timing differences from 2009.

(3)

Assumes 2010 dividend of $2.10/share. Dividends are subject to declaration by the Board of Directors.

(4)

Represents new business and smart grid/smart meter investment.

(5)

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

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

(6)

Exelon

Generation’s

$300

million

financing

includes

$50

million

DOE

loan

for

the

City

Solar

Project

and

$250

million

debt

refinance

portion

Exelon

Corp’s

$400

million

maturity.

(7)

PECO’s planned debt retirement of $400 million represents the final retirement of the PECO Energy Transition Trust.

(8)

“Other”

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

(9)

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

Sufficient Liquidity

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

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

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

(3) Includes other corporate entities.

(45)

Outstanding Facility Draws

(447)

(171)

(10)

(261)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,825

4,663

564

646

Available Capacity Under Facilities

(2)

Outstanding Commercial Paper

$6,825

$4,663

$564

$646

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

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

Available Capacity Under Bank Facilities as of January 14, 2010

Projected 2010 Key Credit Measures

13.8x

8.1x

FFO / Interest

Generation /

Corp:

62%

34%

FFO / Debt

53%

68%

Rating Agency Debt Ratio

BBB

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

BBB

BBB+

Fitch Credit

Ratings

(3)

Baa1

Moody’s Credit

Ratings

(3)

3.7x

3.8x

FFO / Interest

ComEd:

18%

14%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

5.2x

5.0x

FFO / Interest

PECO:

28%

23%

FFO / Debt

46%

50%

Rating Agency Debt Ratio

29%

47%

Rating Agency Debt Ratio

87%

44%

FFO / Debt

18.6x

9.9x

FFO / Interest

Generation:

46%

37%

7.2x

Without PPA &

Pension / OPEB

(2)

57%

Rating Agency Debt Ratio

25%

FFO / Debt

6.0x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

and

PECO

metrics

exclude

securitization

debt.

See

following

slide

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

GAAP.

(1)

FFO/Debt metrics include the following standard adjustments: imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement

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

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of January 20, 2010.

FFO Calculation and Ratios

FFO Calculation

= FFO

PECO Transition Bond Principal Paydown

+ Gain

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)

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%

Purchased

Power

Agreements

(2)

+ Unfunded

Pension

and

OPEB

obligations

(2)

+ A/R Financing

Add off-balance sheet debt equivalents:

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(1)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+ Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+ ComEd Transition Bond Principal Balance

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

(1)

Uses current year-end adjusted debt balance.

(2)

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

Adequacy for Energy Trading.

(3)

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

Q4 GAAP EPS Reconciliation

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

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

0.03

Settlement of tax matter at Generation related to Sithe

(0.02)

City of Chicago settlement with ComEd

(0.02)

NRG acquisition costs

$1.07

$(0.03)

$0.12

$0.14

$0.84

4Q 2008 GAAP Earnings (Loss) Per Share

$1.07

$(0.01)

$0.12

$0.16

$0.80

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

(0.04)

2007 Illinois electric rate settlement

0.15

Mark-to-market adjustments from economic hedging activities

(0.10)

Unrealized losses related

to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended December 31, 2008

YTD GAAP EPS Reconciliation

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

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

(0.02)

City of Chicago settlement with ComEd

(0.02)

NRG acquisition costs

0.03

Settlement of tax matter at Generation related to Sithe

0.02

Decommissioning obligation reduction

$4.13

$(0.10)

$0.49

$0.30

$3.44

YTD 2008 GAAP Earnings (Loss) Per Share

$4.20

$(0.08)

$0.49

$0.33

$3.46

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

(0.22)

(0.01)

(0.21)

2007 Illinois electric

rate

settlement

0.41

Mark-to-market adjustments from economic hedging activities

(0.27)

Unrealized losses related

to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Twelve Months Ended December 31, 2008

Exelon Generation 2010 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

$ / Share

$(0.32)

$0.06

RNF

O&M

Other

Depreciation &

Amortization

$(0.09)

Key Items:

Inflation $(0.05)

Pension/OPEB $(0.03)

Cost Savings Initiative $0.11

2009A

2010E

(1)

$2.55 -

$2.80

$3.16

Key Items:

Market/Portfolio

Conditions/Generation $(0.29)

Nuclear Fuel Expense $(0.12)

PECO CTC

$(0.11)

Capacity Market Prices $0.19

$(0.01)

$(0.04)

Interest

Expense

ComEd 2010 EPS Contribution

(1)

Estimated contribution to Exelon’s operating earnings guidance.

(2)

Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response Adjustment) of $0.05/share and Rider AMI (Advanced Metering Infrastructure) of $0.01/share in 2010.

(3)

Primarily recovery of 2008 and 2009 uncollectible expense. Approximately $0.06/share we anticipate will be included in 1Q10 earnings.

2009A

Depreciation &

Amortization

Interest

Expense

$0.60 -

$0.70

$0.54

$0.15

$0.04

$(0.02)

2010E

(1)

$ / Share

$(0.02)

$(0.03)

Other

RNF

(2)

O&M

(2)

Key Items:

Uncollectible Rider

(3)

$0.05

Weather $0.04

Key Items:

Cost Savings Initiative $0.05

Bad Debt

(3)

$0.05

Inflation $(0.02)

Pension/OPEB $(0.01)

PECO 2010 EPS Contribution

$ / Share

RNF

$(0.12)

$0.54

(1)

Depreciation &

Amortization

2010E

(2)

Key Items:

CTC $0.11

Weather $0.04

Load $(0.03)

Key Items:

Inflation $(0.02)

Bad Debt $(0.02)

$0.08

O&M

(3)

$0.04

$0.40 -

$0.50

(1)

Key Items:

CTC Amortization $(0.11)

Interest

$(0.09)

Key Items:

CTC Interest Expense $0.06

2009A

(1)

Excludes preferred dividends.

(2)

Estimated contribution to Exelon’s operating earnings guidance.

(3)

Excludes estimated impact of energy efficiency and smart meter costs recoverable under a rider of $0.10/share.

Key Assumptions for 2010

Earnings Guidance

(1)

2008 Actual

2009 Actual

2010 Est.

Nuclear

Capacity

Factor

(%)

(2)

93.9

93.6

93.5

Total Generation Sales Excluding Trading (GWh)

176,174

173,065

171,400

Total Generation Sales to PECO (GWh)

40,966

39,897

39,900

Total

Generation

Market

and

Retail

Sales

(GWh)

(3)

135,208

133,168

131,500

Henry Hub Gas Price ($/mmBtu)

8.85

3.92

6.21

PJM West Hub ATC Price ($/MWh)

68.52

38.30

48.40

Tetco M3 Gas Price ($/mmBtu)

9.83

4.64

6.95

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

6.97

8.25

6.96

NI Hub ATC Price ($/MWh)

49.00

28.85

32.57

Chicago City Gate Gas Price ($/mmBtu)

8.79

3.92

6.23

NI Hub Implied ATC Heat Rate (mmbtu/MWh)

5.57

7.36

5.22

PJM East Capacity Price ($/MW-day)

169.09

173.73

181.34

PJM West Capacity Price ($/MW-day)

82.39

106.13

144.40

Electric

Delivery

Growth

(%)

(4)

PECO

0.6

(2.6)

(1.3)

ComEd

(0.1)

(3.3)

0.8

Effective Tax Rate (%)

(5)

36.1

37.2

35.8

(1)

Reflects assumptions used in original 2010 Earnings Guidance provided on November 2, 2009; 2010 prices reflect observable prices as of September 30, 2009.

(2)

Excludes Salem.

(3)

Includes Illinois auction sales and ComEd swap.

(4)

Weather-normalized retail load growth.

(5)

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

4Q07

4Q08

4Q09

ComEd and PECO Accounts Receivable

ComEd Accounts

Receivable

(1)

Both ComEd and PECO have experienced an improvement in accounts receivable aging

4Q07

4Q08

4Q09

PECO Accounts

Receivable

(1)

% of AR

$755M

$749M

$850M

$832M

$864M

$759M

(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

ComEd Customer Usage Breakdown

Customer Usage by Revenue Class

Top 380 Customer Usage by Segment

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

ComEd’s

territory

largely

manufacturing

focused,

which

beginning

see

increases

production due to improved economic conditions

PECO Customer Usage Breakdown

Other

Other Large

C&I

24%

150 Large

C&I

17%

Small C&I

22%

Residential

34%

Customer Usage by Revenue Class

Top 150 Customer Usage by Segment

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

Retail Trade

Finance, Insurance & Real Estate

12%

Pharmaceuticals

PECO’s

load

relatively

diversified

customer

class

and

industry,

slow

recovery

the

second half of 2010 is expected

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

•

Significant impairments of assets, including goodwill

•

Changes in decommissioning obligation estimates

•

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

•

Other

unusual

items

•

Significant future changes to GAAP

•

Operating earnings guidance assumes normal weather for the

year

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 December 31, 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.

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

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

2010

2011

2012

Estimated

Open

Gross

Margin

millions)

(1,2)

$5,900

$5,800

$5,750

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)

$5.79

$33.83

$48.04

$(0.53)

$6.33

$34.75

$49.42

$(0.44)

$6.53

$36.13

$50.43

$0.89

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on December 31, 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 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.

2010

2011

2012

Expected Generation

(GWh)

(1)

167,100

163,000

162,600

Midwest

99,000

98,400

97,400

Mid-Atlantic

59,600

57,200

56,600

South

8,500

7,400

8,600

Percentage of Expected Generation Hedged

(2)

91-94%

69-72%

37-40%

Midwest

89-92

71-74

43-46

Mid-Atlantic

93-96

65-68

25-28

South

97-100

66-69

39-42

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.50

$45.00

$46.00

Mid-Atlantic

$35.50

$60.00

$53.50

ERCOT North ATC Spark Spread

$(1.00)

$(0.50)

$(7.00)

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 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem.

Expected generation assumes capacity factors of 93.5%, 92.8% and 92.8% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected

generation in 2011 and 2012 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

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

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

pending PJM approval.

(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.

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2010

$40

$(40)

$30

$(25)

$20

$(15)

+/-

$50

2011

$190

$(160)

$165

$(155)

$135

$(130)

+/-

$50

2012

$395

$(395)

$275

$(270)

$230

$(230)

+/-

$50

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on December 31, 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.

95% case

5% case

$6,500

$6,100

$4,800

$7,800

$6,200

$8,000

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2010

2011

2012

(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 in 2011 and 2012 do not represent earnings guidance or a forecast of future results as

Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel,

load following products, and options as of December 31, 2009.

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin

$5.90 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,000GWh * 90% *

($46.50/MWh-$33.83/MWh)

= $1.13 billion

59,600GWh * 94% *

($35.50/MWh-$48.04/MWh)

= $(0.70 billion)

8,500GWh * 98% *

($(1.00)/MWh-

$(0.53)/MWh)

= $0.00 billion

Step 3

Estimate

hedged

gross

margin

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:

MTM value of energy hedges:

Estimated hedged gross margin:

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

$1.13

billion

$(0.70

billion)

$0.00

billion

$5.90 billion

$6.33 billion

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

5.5

6.5

7.5

8.5

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

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

$6.41

2012 $6.54

Rolling 12 months, as of January 14, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$68.00

2012

$75.45

2011

Ni-Hub

$44.27

2012 Ni-Hub

$44.58

2012 PJM-West $59.90

2011 PJM-West

$59.57

2011 Ni-Hub

$25.95

2012 Ni-Hub

$27.87

2012 PJM-West

$41.99

2011 PJM-West

$41.17

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

8.2

8.4

8.6

8.8

9.2

9.4

9.6

9.8

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

5.5

6.5

7.5

8.5

1/09

2/09

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

Market Price Snapshot

2012

$9.10

2011

$8.73

2011

$54.83

2012

$58.40

2011

$6.28

2012

$6.43

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

$7.02

2012

$9.64

ERCOT North On Peak Spark Spread

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

Rolling 12 months, as of January 14, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Exelon (EXC) 8-KResults of Operations and Financial Condition