8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

March 10, 2010

Date of Report (Date of earliest event reported)

Commission File       Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 7 — Regulation FD

Item 7.01. Regulation FD Disclosure.

On March 11, 2010, Exelon Corporation (Exelon) will participate in the Morgan Stanley Utilities Conference, and on March 15, 2010, Exelon will participate in the Edison Electric Institute International Utilities Conference. Attached as Exhibit 99.1 to this Current Report on Form 8-K are the presentation slides to be used at the conferences.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Presentation slides

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This Current Report 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; and (2) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/    MATTHEW F. HILZINGER      

Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

Exelon Corporation

COMMONWEALTH EDISON COMPANY

/s/    JOSEPH R. TRPIK, JR.        

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/    PHILLIP S. BARNETT        

Phillip S. Barnett

Senior Vice President and Chief Financial Officer

PECO Energy Company

March 10, 2010

EXHIBIT INDEX

Exhibit No.	Description
99.1	Presentation slides

EX-99.1

Investor Meetings

March 2010

Exhibit 99.1

2

Forward-Looking Statements

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

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

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

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

2009 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7.

Management’s Discussion and Analysis of Financial Condition and Results of

Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18;

and (2) other factors discussed in filings with the Securities and Exchange Commission

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

Company and Exelon Generation Company, LLC (Companies). Readers are cautioned

not to place undue reliance on these forward-looking statements, which apply only as of

the date of this presentation. None of the Companies undertakes any obligation to

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

circumstances after the date of this presentation.

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

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

adjusted operating earnings and cash flows are representative of

the underlying

operational results of the Companies. Please refer to the appendix to this presentation

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

Please refer to the footnotes of the following slides for a reconciliation non-GAAP cash

flows to GAAP cash flows.

3

Leader in the U.S. Electric Power Industry

Leading market cap in the sector at ~$30 billion, investment grade balance sheet

Experienced management team with track record of creating and returning

shareholder value

•

Exelon formed through combination of ComEd and PECO Energy in 2000

•

Total shareholder return

(1)

of 108% since October 2000, compared to 58% for the

Philadelphia Utility Index, and a negative 3% for the S&P 500

•

~4.5% dividend yield

Largest, best operated merchant generator of electricity in the U.S.

•

Ownership interest in 19 operating nuclear reactors

•

Largest nuclear operator in U.S. with 18% of nuclear output; third largest in the world

•

Industry-leading capacity factors and generating cost among nuclear fleets in the U.S.

•

Geographically well-situated in competitive markets and part of PJM, the largest RTO

Two stable utility companies operating in large metropolitan markets

Best positioned in the industry for upside from carbon legislation or regulation

•

In addition to positive leverage to upside from natural gas, coal and capacity prices

Exelon’s asset base, operational performance and presence in

competitive markets enable us to capture and create value

(1)  Total shareholder return from October 20, 2000 through March 5, 2010.

4

Multi-Regional, Diverse Company

(1)  Standard & Poor’s senior unsecured debt rating as of February 28, 2010.

Note: Owned megawatts as of December 31, 2009 based on Generation’s ownership,

using annual mean ratings for nuclear units (excluding Salem) and summer ratings for

Salem and the fossil and hydro units.

Midwest Capacity

Owned:

11,412 MW

Contracted:

2,900 MW

Total:

14,312 MW

ERCOT/South Capacity

Owned:

2,222 MW

Contracted:

2,917 MW

Total:

5,139 MW

New England Capacity

Owned:

182 MW

Total Capacity

Owned:

24,850 MW

Contracted:

6,153 MW

Total:

31,003 MW

Electricity Customers:

1.6M

Gas Customers: 

0.5M

Electricity Customers:  3.8M

Generating Plants             

Nuclear

Hydro

Coal/Oil/Gas Base-load

Intermediate

Peaker

Mid-Atlantic Capacity

Owned:

11,034 MW

Contracted:

336 MW

Total:

11,370 MW

Exelon Financial Highlights

2009 Operating Earnings:

$2.7B

2009 EPS:

$4.12

Assets at 12/31/09:                $49.2B

Total Debt at 12/31/09:

$12.6B

Credit Rating:

(1)

BBB-

5

0

10

20

30

40

50

60

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Industry (w/o Exelon)

Exelon

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

outage that extended into 2010 reflecting steam generator replacement.

Exelon Generation Consistently

Delivers Top-Tier Results

Exelon Generation has ability to replicate best practices on a large scale

Source: Platts News Flashes and Company Press Releases, 11/3/09

Refueling Outage Duration

•

93.6%

capacity

factor

–

the

7

consecutive

year exceeding 93%

•

Clinton and Quad Cities 1 units established

new continuous run records of 596 and 594

days, respectively

•

TMI 1 unit set a new PWR world record for a

705-day continuous run

•

Equipment upgrades and power uprates

added 70 MW of nuclear capacity

0

200

400

600

800

Byron 1

Limerick 2

Byron 2

Braidwood 2

Quad Cities 1

Clinton 

Three Mile Island 1

Three Mile Island 1

Three Mile Island 1

LaSalle 1

Three Mile Island 1

Three Mile Island 1

Peach Bottom-3

Peach Bottom-3

LaSalle 2

LaSalle 1

(Days)

th

2009 Nuclear Fleet Achievements

Nuclear Reliability

30 Longest Continuous U.S. Runs

6

6.1

6.9

2.0

2.0

7.3

6.4

2.0

2.2

Transmission

Distribution

ComEd Building Strength

Producing Results with

Regulatory Recovery Plan

~46%

~47%

8.5%

46.4%

Earned ROE

Equity

(1)

5.5%

45.4%

$8.1

$8.4

$9.4

2008

2009

2011

(Illustrative)

(2)

Average Annual Rate Base

($ in billions)

(1)

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

(2)

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

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

Note: Amounts may not add due to rounding.

2010E

$8.9

ComEd executing on regulatory recovery plan resulting in healthy

increases in earned ROE

10%

10%

•

Significant improvement in earned ROE, from

5.5% in 2008 to 8.5% in 2009, targeting at

least 10% in 2010

•

Continued strong operational performance

•

Benefiting from regular transmission updates

through a formula rate plan

•

Uncollectibles expense rider tariff approved by

ICC in February 2010

•

Anticipate electric distribution rate filing in

2010

•

ICC approved Illinois Power Agency’s 2010

procurement plan order; annual procurement

event expected to take place in Spring 2010

•

ICC approved Smart Meter pilot program and

rider

•

Standard & Poor’s raised credit ratings in

3Q09 and Fitch in 1Q10

7

2.7

2.8

3.0

3.2

0.5

0.5

0.5

1.1

1.1

1.1

1.2

0.6

2.0

1.3

0.5

Gas

Competitive Transition Charge (CTC)

Electric Transmission

Electric Distribution

PECO Executing on Transition Plan

Actively Engaged in Transition

•

Targeted earned ROE of ~11% in 2010; 9-11%

post transition

•

Anticipate electric and gas rate filings by end

of 1Q10

•

Selected as 1 of 6 companies to receive

maximum Federal stimulus award of $200

million for smart grid / smart meter investment

•

PA Public Utility Commission approval

expected in 1Q10 to implement Smart Meter

Plan of Pennsylvania Act 129

•

Fixed price PPA with ExGen ends 12/31/10

•

Two procurement events for electricity supply

post-2010 were conducted, including 49% of

2011 residential load; next procurement in

May 2010

~9 –

11%

Not applicable due to

transition rate structure

Rate Making ROE

Equity

~50-53%

$6.3

$5.7

$5.0

Average Annual Rate Base

(1)

($ in billions)

2008

2009

2011

(Illustrative)

(2)

(1)

Rate base as determined for rate-making purposes.

(2)

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

relied upon as a forecast of future results.

$5.1

2010E

PECO is managing through its transition period and is positioned

for

continued strong financial performance post-2010

8

Nuclear

Uprates

-

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

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

new plant and no incremental operating costs

-

Approximately $725 million in investments to build smart grid

infrastructure over the coming years with a regulated return on

investment

-

Lowest carbon intensity in the sector, significant upside if and

when legislation enacted or regulations promulgated, and

enhancing industry-leading position with Exelon 2020

-

Positioned to benefit from increases in natural gas and coal

prices, heat rates, and demand growth

-

Leveraging transmission expertise across the company and in

developing Exelon Transmission Company with the goal of

improving reliability, reducing congestion and moving

renewable energy to population centers

Deploying Capital for Shareholder Value

Smart Grid

Environmental

Commodity

Leveraged

Transmission

9

Source: Ventyx Velocity Suite Database

Bubble size represents carbon

intensity, expressed in terms of metric

tons of CO2 per MWh generated

0

50

100

150

50

100

150

200

2008 Gross Generation (TWh)

Exelon

AEP

Southern

Duke

TVA

FPL

Entergy

Dominion

Berkshire

Hathaway

Calpine

NRG

First

Energy

Xcel

Ameren

Progress

250

Lowest CO2 Intensity of Large Generators

15

Berkshire Hathaway

0.84

14

Ameren Corp

0.81

13

NRG Energy

0.78

12

AEP

0.77

11

Xcel Energy

0.74

10

Southern

0.69

9

Duke Energy

0.63

8

Progress Energy

0.61

7

TVA

0.60

6

FirstEnergy

0.55

5

Dominion

0.49

4

Calpine

0.39

3

FPL Group

0.33

2

Entergy

0.27

1

Exelon

0.06

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

Exelon 2020

(1)

will ensure that Exelon maintains and extends its

position as the nation’s top low-carbon power generator

Lowest Carbon Intensity of the

Largest U.S. Generators

CO2 Emissions of Largest U.S. Electricity Generators

10

Protect Today’s Value

•

Deliver superior operating

performance

•

Advance competitive markets

•

Exercise financial discipline and

maintain financial flexibility

•

Build healthy, self-sustaining delivery

companies

Grow Long-Term Value

•

Drive the organization to the next

level of performance

•

Adapt and advance Exelon 2020

•

Rigorously evaluate and pursue new

growth opportunities in clean

technologies and transmission

•

Build the premier, enduring

competitive generation company

+

Exelon’s Strategic Direction

Excel in managing the elements of our business we can control, while being

strategic, thoughtful and disciplined with the elements we cannot control

11

Appendix

12

The Exelon Companies

’09 Earnings:

$2,092M 

’09 EPS:

$3.16

Total Debt:

(1)

$3.0B

Credit Rating:

(2)

BBB

Nuclear, Fossil, Hydro & Renewable Generation

Power Marketing

‘09 Operating Earnings:

$2.7B

‘09 EPS:

$4.12

Assets:

(1)

$49.2B

Total Debt:

(1)

$12.6B

Credit Rating:

(2)

BBB-

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

(1)

As of December 31, 2009.

(2)

Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of February 28, 2010.

Pennsylvania

Utility

Illinois

Utility

’09 Earnings:

$356M

$354M

’09 EPS:

$0.54

$0.54

Total Debt:

(1)

$5.1B

$2.8B

Credit Ratings:

(2)

A-

A-

13

2010 Events of Interest

Q1

Q2

Q3

Q4

RPM Auction (May)

Uncollectibles rider

tariff (2/2)

Illinois Power Agency

RFP (spring)

Illinois Primaries

(2/2)

Pennsylvania

Primaries (5/18)

Electric and gas

distribution rate

case filings (March)

Procurement RFP

(May, results in June)

Procurement RFP

(Sep., results in Oct.)

Electric distribution rate case filing (TBD)

Illinois Elections

(11/2)

Pennsylvania

Elections (11/2)

14

O&M

Cost Savings Initiative

Inflation

Pension/OPEB

2010 Operating Earnings Guidance

(1)

2010E

2009A

$0.54

$3.16

$4.12

(1)

ComEd

PECO

Exelon

Generation

ComEd RNF

PECO RNF

Generation RNF

Depreciation and Amortization

2010 Earnings Drivers

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.54

Exelon

$3.60 -

$4.00

(1)

$0.60 -

$0.70

$0.40 -

$0.50

$2.55 -

$2.80

(1)

We

reaffirmed

2010

earnings

guidance

on

January

22,

2010,

and

we

are

not

updating

earnings

guidance

at

this

time.

Earnings

guidance

is

only

reviewed

in

connection with our quarterly earnings announcements or if we expressly indicate that we are updating the guidance.  Refer to the Appendix for a reconciliation

of adjusted (non-GAAP) operating earnings

to GAAP earnings.

Note: A = Actual; E = Estimate

2010

operating

earnings

guidance

of

$3.60

to

$4.00/share

–

1Q10

earnings

expectations between $0.85 to $0.95/share

(1)

15

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

Notes: The information on this slide is the same as disclosed on January 22, 2010 and has not been updated to reflect any changes that may

have occurred since that date.

Data contained on this slide is rounded.

($ millions)

$0.7

$0.6

PECO

(1)

$1.0

$1.0

ComEd

(1)

$2.7

$2.7

Generation

2010E

2009A

$ billions

(2)

(2)

(2)

O&M Expense

(1)

$4,500

$4,300

$4,350

$450

$415

$245

2008A

2009A

2010E

Total O&M

Pension/OPEB 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.

16

Cash Contributions

$0

$100

$200

$300

$400

Pension

OPEB

Pension

and

OPEB

Plans

Key

Metrics

–

12/31/09E

($

in

millions)

Pension

Assets

$7,840

Obligations

$11,480

2010E

2009

$210

$250

$205

$200

$440

$260

$155

$155

2010E

2009

(1)

(2)

(3)

OPEB

Assets

$1,475

Obligations

$3,660

Key Metrics

2009 asset return

21%

12/31/09 discount rate

5.83%

Assumed long-term EROA               8.50%

Pension and OPEB expense is

increasing by $35 million pre-tax

Pension and OPEB Expense and

Contributions

Pre-Tax Expense

(4)

$0

$50

$100

$150

$200

$250

$300

Pension

OPEB

(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.

Notes: OPEB = other postretirement benefits; EROA = expected return on assets.  The information on this slide is the same as disclosed on January 22, 2010 and has not been

updated to reflect any changes that may have occurred since that date.  Data contained on this slide is rounded.

17

Capital Expenditures Expectations

1,975

1,925

1,825

1,950

1,950

775

900

850

1,125

1,150

200

50

375

550

675

50

25

100

150

75

300

300

275

225

200

$0

$750

$1,500

$2,250

$3,000

$3,750

$4,500

2008A

2009A

2010E

2011E

2012E

Base CapEx

Nuclear Fuel

Nuclear Uprates and Solar

Smart Grid

New Business at Utilities

Exelon

$3,125

$3,275

$3,375

(1)

$4,050

$4,150

Note: Data contained on this slide is rounded.

$ millions

(1) Does not include $85M increase in ComEd CapEx reflected in Exelon’s 2009 Annual

Report on Form 10-K, of which approximately $65M related to Smart Grid/Utility Growth.

2008A

2009A

2010E

2011E

2012E

Exelon Generation

Base CapEx

875

875

750

900

900

Nuclear Fuel

775

900

850

1,125

1,150

Nuclear Uprates

50

150

350

550

675

Solar

-

50

25

-

-

Total ExGen

1,700

1,975

1,975

2,575

2,725

ComEd

Base CapEx

675

650

625

625

625

Smart Grid/Meter

25

50

50

25

25

New Business

250

150

175

200

225

Total ComEd

(1)

950

850

850

850

875

PECO

Base CapEx

350

350

400

400

400

Smart Grid/Meter

-

-

50

125

50

New Business

50

50

50

75

75

Total PECO

400

400

500

600

525

Corporate

75

50

50

25

25

18

2010 Projected Sources and Uses of Cash

(325)

n/a

(100)

(225)

Utility Growth CapEx

(5)

($ millions)

Exelon

(10)

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)

(3)

(625)

(400)

(750)

(1,825)

Nuclear Fuel

n/a

n/a

(850)

(850)

Dividend

(4)

(1,400)

Nuclear Uprates and Solar Project

n/a

n/a

(375)

(375)

Net Financing (excluding Dividend):

Planned Debt Issuances

(6,7)

250

--

300

550

Planned Debt Retirements

(8)

(225)

(400)

--

(1,025)

Other

(9)

25

175

--

125

Ending Cash Balance

(1)

$175

Note: The information on this slide is the same as disclosed on January 22, 2010 and has not been updated to reflect any changes that may have occurred since that date.

(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)

Does not include $20M increase in ComEd CapEx reflected in Exelon’s 2009 Annual Report on Form 10-K.

(4)

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

(5)

Represents new business and smart grid/smart meter investment.  Does not include $65M increase in ComEd CapEx related to Smart Grid/Utility Growth reflected in Exelon’s 2009

Annual Report on Form 10-K.

(6)

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. 

(7)

Exelon Generation’s $300 million financing assumes a $50 million DOE loan for the City Solar Project and $250 million of debt to refinance a portion of Exelon Corp’s $400 million

maturity.

(8)

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

(9)

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

(10)

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

19

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.

(120)

--

--

(120)

Outstanding Facility Draws

(439)

(163)

(10)

(261)

Outstanding Letters of Credit

$7,317

$4,834

$574

$952

Aggregate Bank Commitments

(1)

6,758

4,671

564

571

Available Capacity Under Facilities

(2)

(85)

--

--

(85)

Outstanding Commercial Paper

$6,673

$4,671

$564

$486

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

At February 28, 2010, Exelon had $6.8B of available capacity through

its credit facilities and $85M of commercial paper outstanding

Available Capacity Under Bank Facilities as of February 28, 2010

20

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

Exelon Corp

Exelon Generation

ComEd

PECO

Debt Maturity Profile

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

Refinancing in 3Q 2009 of Exelon Generation and Exelon 2011 maturities decreased average

cost of debt, extended average maturities and reduced refinancing risk

21

Projected 2010 Key Credit Measures

13.8x

8.1x

FFO / Interest

Generation /

Corp:

62%

34%

FFO / Debt

53%

68%

Rating Agency Debt Ratio

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB+

BBB+

Fitch Credit

Ratings

(3)

A3

A2

Baa1

Baa1

Moody’s Credit

Ratings

(3)

3.7x

3.8x

FFO / Interest

ComEd:

18%

14%

FFO / Debt

42%

49%

Rating Agency Debt Ratio

5.2x

5.0x

FFO / Interest

PECO:

28%

23%

FFO / Debt

46%

50%

Rating Agency Debt Ratio

29%

47%

Rating Agency Debt Ratio

87%

44%

FFO / Debt

18.6x

9.9x

FFO / Interest

Generation:

46%

37%

7.2x

Without PPA &

Pension / OPEB

(2)

57%

Rating Agency Debt Ratio

25%

FFO / Debt

6.0x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

and

PECO

metrics

exclude

securitization

debt.

See

following

slide

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

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

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

obligations by operating company.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of February 28, 2010.

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

+ 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.

23

Value Return Framework

Less

Equals

Maintenance Capital and Committed Dividends

Cash Flow from Operations before Dividends and CapEx

Strengthen Balance Sheet /

Increase Financial Flexibility

Invest in Growth

Available Cash and Balance Sheet Capacity

Return Value via

Share Repurchases,

Additional Dividends

24

Focusing on the Transmission Grid

Across Exelon

ComEd and PECO

•

Continued transmission

investments focused in their

service territories as

required for reliability

Exelon

Transmission

Company

•

Evaluating needed

upgrades of the existing

system to reduce

constraints and improve

power flow from our assets

•

Projects would include

short-term modifications to

existing infrastructure

Exelon Generation

•

Invest in shovel ready

projects with utilities

•

Pursue Extra High Voltage

(EHV) development

opportunities in and around

our existing footprint

including partnerships with

Exelon utilities and regional

developers

•

Expand focus beyond our

footprint and evaluate

partnering with renewable

developers including

merchant transmission

25

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

***********

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

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

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

********

26

•

Large, low-cost, low-emissions,

exceptionally well-run nuclear fleet

•

Complementary and flexible fossil and

hydro fleet

•

Leveraged to improving power market

fundamentals (commodity prices, heat

rates, and capacity values)

•

Below-market contract in Pennsylvania

ends at year-end 2010

•

Potential carbon restrictions

Value Proposition

Exelon Generation Value Proposition

•

Continue to focus on operating excellence,

cost management, and market discipline

•

Execute on power and fuel hedging

programs

•

Support competitive markets

•

Pursue nuclear & hydro plant relicensing

and strategic investment in material

condition

•

Maintain industry-leading talent

Protect Value

•

Pursuing 1,300-1,500 MW nuclear uprate

plan

•

Rigorously evaluate generation

development opportunities

•

Capture increased value of low-carbon

generation portfolio

Grow Value

Exelon

Generation

is

a

premier

unregulated

generation

company

–

positioned

to

capture market opportunities and manage risk

27

A Leading Nuclear Fleet Operator in Cost

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

producers of electricity in the nation

0

5

10

15

20

25

1   Quartile

2    Quartile

3    Quartile

4    Quartile

2004-2008 Average Production Cost

for Major Nuclear Operators

(1)

Average

(1)

Source:

2008

Electric

Utility

Cost

Group

(EUCG)

survey.

Includes

Fuel

Cost

plus

Direct

O&M

divided

by

net

generation.

st

nd

rd

th

28

Effectively Managing Nuclear Fuel Costs

Components of Fuel Expense in 2009

Projected Total Nuclear Fuel Spend

Projected Exelon Average Uranium Cost vs. Market

Projected Exelon Uranium Demand

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

with the DOE.

2010–2012, 2014: 100% hedged in volume

2013:

~92% hedged in volume

All charts exclude Salem

0.0

2.0

4.0

6.0

8.0

10.0

2009A

2010

2011

2012

2013

2014

0

200

400

600

800

1,000

1,200

1,400

2009A

2010

2011

2012

2013

2014

Nuclear Fuel Expense (Amortization + Spent Fuel)

Nuclear Fuel Capex

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009A

2010

2011

2012

2013

2014

Exelon Average Reload Price

Projected Market Price (Spot)

Enrichment

38%

Fabrication

16%

Nuclear Waste

Fund

19%

Tax/Interest

1%

Conversion

3%

Uranium

23%

29

Uranium Price Volatility

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

Short-term

Uranium Price Trend

Long-term Uranium Price Trend

Spring 2003

McArthur

River flood

December 2003

GNSS/Tenex

termination;

ConverDyn UF6 release

and shutdown

Early 2004

ERA / Ranger

water problems

Early 2006

First Cigar Lake flood;

Cyclone Monica halts 

ERA /  Ranger

operations for

approximately two

weeks

October 2006

Second Cigar

Lake flood

March 2007

ERA / Ranger flooding

(cyclone George)

30

35

40

45

50

55

60

65

70

75

80

0

20

40

60

80

100

120

140

160

30

World-Class Nuclear Operator

Average Capacity Factor

Sustained production excellence

40%

50%

60%

70%

80%

90%

100%

Exelon

Industry

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

Sources: Platt’s, Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy).

31

0

10

20

30

40

50

60

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Industry (w/o Exelon)

Exelon

Impact of Refueling Outages

Notes:  Data includes Salem.  Net nuclear generation data based on ownership interest.

PWR = pressurized water reactor; BWR = boiling water reactor

•

Every 18 months (most PWRs) or 24

months (BWRs

& TMI)

•

Average

outage

duration:

~28

days

(1)

Nuclear Refueling Cycle

•

Based on the refueling cycle, we will

conduct 10 refueling outages in 2010,

the same number of refueling

outages conducted in 2009

2010 Refueling Outage Impact

•

Output reflected TMI extended steam

generator replacement outage

•

Based on the refueling cycle, we

conducted 10 refueling outages in

2009, versus 12 in 2008

2009 Refueling Outage Impact

(1)  Average outage duration for refueling outages from

2008 –

2009, excluding Salem.

125

127

129

131

133

135

137

139

141

143

145

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

7

8

9

10

11

12

13

Refueling Outage Duration

Nuclear Output

Actual

Target

# of Outages

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

extended into 2010 reflecting steam generator replacement.

32

Nuclear Uprates Offer Sustainable Value

Key component of Exelon 2020 low carbon roadmap

Creates additional low-carbon generation capacity

Capitalizes on Exelon’s proven track record of uprate execution

Dedicated project management team

Proven technology design

No ongoing incremental O&M expense

Creates long-term value over extended license lives

Uprates equivalent in size to a new nuclear plant but significantly

lower cost, shorter timeline, and more predictable spend

Straightforward regulatory and environmental licenses, permits

and approvals

Potential for uprates to meet state alternative energy standards

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

operational excellence

Strategic

Value

Grow

Value

Regulatory

Feasibility

Execution

Feasibility

33

Three Major Categories of Exelon Uprates

Uprates

Overnight

Cost

(1)

MUR (Measurement Uncertainty Recapture)

•

Through the use of advanced techniques and more precise

instrumentation, reactor power can be more accurately calculated

•

Can achieve up to 1.7% additional output

•

Requires NRC approval

187–234 MW

$300M

2 years

899–1,016 MW

$2,400M

EPU (Extended Power Uprate)

•

Through a combination of more sophisticated analysis and

upgrades to plant equipment, uprates can increase output by as

much as 20% of original licensed power level

•

Requires NRC approval

3 -

5

years

237–266 MW

$800M

Megawatt Recovery and Component Upgrades

•

Replacement of major components in the plant occur in the normal

life cycle process –

with newer technology, replacements result in

increased efficiency

•

Equipment includes generators, turbines, motors and transformers

•

Megawatt Recovery and Component Upgrades must conform to

NRC standards, but do not require additional NRC approval

2 -

3

years

~1,300–1,500 MW

$3,500M

Project

Duration

Exelon’s $2,200 –

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

advantageous deployment of capital relative to other generation options

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

Estimated

Internal Rate

of Return

12-15%

14-18%

9-12%

34

Phased Execution Lowers Risk

•

Safe, economical and proven methods to improve efficiency and output

•

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

past 10 years

Note: Data contained in this slide is rounded.

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

EPUs

MURs

MW Recovery and         

Component Upgrades

Maximum                        

Potential MW

Year Uprates Become Operational

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

Exelon’s Uprate Plan

1,100 MW

1,300 –

1,500  MW

Average Overnight Cost

Estimate: $2,200 -

2,500/KW

0

200

400

600

800

1,000

1,200

1,400

1,600

Planned Capital

Spend

(1)

$150

2017

$625

2013

$675

2012

$550

2011

$350

2010

$725

2015

$725

2014

$400

2016

$4,425

2008 -

2017

$225

2008 -

2009                                           

(1)

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

35

Multi-Regional Nuclear Uprate Program

2012

32

25

Peach Bottom

2011

110

95

Quad Cities

2014

15

12

TMI

2014

31

25

Dresden

2013

23

19

Quad Cities

2012

42

34

Byron

2012

42

34

Braidwood

2011

41

33

Limerick

2011

40

32

LaSalle

2014

3

3

Peach Bottom

Measurement Uncertainty Recapture (MUR):

2013

6

6

Limerick

2013

110

103

Dresden

2012

5

5

Dresden

Extended Power Uprate (EPU):

MW Recovery & Component Upgrades:

2017

340

306

Limerick

172

336

17

148

3

Max

Potential

MW

2016

138

TMI

2016

303

LaSalle

2016

17

Clinton

2015

134

Peach Bottom

2010

2

Clinton

Year of

Operation

Base

Case

MW

Station

Executing 1,300-1,500 MW of uprate projects

across our geographically diverse nuclear fleet

TMI

Limerick

Peach

Bottom

Total Midwest Uprates:

669-759 MW

Total Mid-Atlantic Uprates:

657-757 MW

Quad

Cities

Dresden

Byron

LaSalle

Clinton

Braidwood

Notes:

MW

shown

at

ownership.

Year

of

Operation

indicates

when

the

uprate

project

is

planned

to

be

completed. 

Uprates totaling approximately 50 MW are expected to come on line in 2010.

36

Exelon Nuclear Fleet Overview

Fleet

also

includes

4

shutdown

units:

Peach

Bottom

1,

Dresden

1,

Zion

1

&

2.

Average in-service time = 28 years

2011

42.6% Exelon, 57.4%

PSEG

In process

(decision in 2011-

2012):  2016, 2020

503, 500

(2)

W

PWR

2

Salem, NJ

2025

100%

Renewed: 2034

837

B&W

PWR

1

TMI-1, PA

Dry cask

100%

Renewed: 2029

625

GE

BWR

1

Oyster Creek, NJ

Dry cask

50% Exelon, 50%

PSEG

Renewed: 2033,

2034

574, 571

(2)

GE

BWR

2

Peach Bottom, PA

Dry cask

75% Exelon, 25% Mid-

American Holdings

Renewed: 2032

655, 662

(2)

GE

BWR

2

Quad Cities, IL

Dry cask

100%

Renewed: 2029,

2031

869, 871

GE

BWR

2

Dresden, IL

2010

100%

2022, 2023

1138, 1150

GE

BWR

2

LaSalle, IL

Dry cask

100%

2024, 2029

1148, 1145

GE

BWR

2

Limerick, PA

2018

2011

2013

Spent Fuel Storage/

Date to lose full core

discharge capacity

GE

W

W

Vendor

BWR

PWR

PWR

Type

1

2

2

Units

100%

2026

1065

Clinton, IL

100%

2024, 2026

1183, 1153

Byron, IL

100%

2026, 2027

1194, 1166

Braidwood, IL

Ownership

License Status /

Expiration

(1)

Net Annual

Mean Rating

MW 2009

Plant, Location

(1)

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

(2)

Capacity based on ownership interest.

Uprates + license extensions = long-term value creation

37

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

2000

2001

2002

2003

2004

2005

2006

2007

2008

Basics of Business Unchanged

Nuclear remains one of the lowest cost options for electricity production

Petroleum

Gas

Coal

Nuclear

1.87

U.S. Electricity Production Costs

(2000-2008)

(1)

(1)

In

2008

cents

per

kilowatt-hour.

Source:

NEI,

Ventyx

Velocity

Suite

May

2009.

Production

Cost

=

O&M

plus

fuel. 

2.75

8.09

17.26

38

38

Total Portfolio Characteristics

104,400

102,441

39,800

39,897

5,500

16,830

22,700

13,897

0

50,000

100,000

150,000

200,000

2009A

2010E

ComEd Swap

IL Auction

PECO Load

Actual Forward Hedges & Open Position

Expected

Total

Supply

(GWh)

Expected

Total

Sales

(GWh)

91,804

91,600

47,866

48,100

29,840

27,400

3,555

5,300

0

50,000

100,000

150,000

200,000

2009A

2010E

Forward / Spot Purchases

Fossil & Hydro

Mid-Atlantic Nuclear

Midwest Nuclear

173,065

173,065

172,400

172,400

39

Retiring Cromby Station and

Eddystone Units 1&2

•

Cromby Station

–

Placed in service in 1954-55

–

144 MW coal and 201 MW oil/gas

•

Eddystone Station Units 1&2

–

Placed in service in 1960

–

588 MW of coal capacity at units 1&2

–

Units 3&4 (760 MW oil/gas) and 4 peaking

units (60 MW) will continue to operate

•

Retirements yield ~$165-200 million incremental NPV vs. continuing to operate the units

–

Avoids ongoing operating and capital costs on aging units

–

Cromby and Eddystone have not cleared in the past two RPM capacity auctions (2011/12

and 2012/13)

–

Anticipates more stringent environmental regulations and avoids related capital investment

•

Agreed to delay deactivation of two units to maintain reliability, provided receipt of required

environmental permits and adequate cost-based compensation

–

Pursuing RMR to compensate for cost of maintaining and operating

units beyond 5/31/11

–

Maintaining scheduled retirement date of 5/31/11 for Cromby 1 and Eddystone 1; delaying

Cromby 2 to 5/31/12 and Eddystone 2 to 12/31/13

$80

$85

$40

Capital Expenditure

Reduction

$40

$18

$24

Incremental Pre-Tax

Operating Income

45

22

0

Depreciation Savings

75

46

24

Operating O&M Savings

$(80)

$(50)

$0

Revenue Net Fuel

2012

2011

2010

($ in millions)

Smaller, less efficient coal plants are challenged by economic and

environmental considerations

Ongoing Savings Impact

Note: RMR = reliability must-run agreement 

40

40

Reliability Pricing Model (RPM) Auction

PJM RPM Auction ($/MW-day)

Exelon Generation Participation within PJM Reliability Pricing Model

(1)

–

next RPM auction in May 2010 

Note: Data contained on this slide is rounded.

(1) 

All generation values are approximate and not inclusive of wholesale transactions.

(2) 

All capacity values are in installed capacity terms (summer ratings) located in the areas.

(3) 

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

(4)

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

(5)

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

(6)

Elwood contract expires in 12/31/12 and Kincaid contract expires

in

2/28/13.

(7)

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

2009/2010

2010/2011

2011/2012

2012/2013

in MW

Capacity

(2)

Obligation

Capacity

(2)

Obligation

Capacity

(2)

Capacity

(2)

RTO

12,800

3,800 -

4,100

(4)

23,900

9,300 -

9,400

(3)

23,200

12,100

(6)

EMAAC

9,500

MAAC + APS

11,100 

9,300 –

9,400

(3)

MAAC

1,500

Avg ($/MW-Day)

(7)

$143.90

$174.29

$110.00

$74.75               

40.80

197.67

111.91

148.80

102.04

191.32

174.29

110.00

16.46

133.37

139.73

2007/2008

2008/2009

2009/2010

2010/2011

2011/2012

2012/2013

RTO

MAAC + APS

MAAC

Eastern MAAC

Only shown

if cleared

at separate

price and

generation

is located

in that zone

(5)

41

Estimated Build-Up of PECO Average

Residential Full Requirements Price

$91.60/MWh

$28.50-

$29.50

$50.50 -

$51.50

Full Requirements Costs ($/MWh)

Average Full Requirements                          

Retail Sales Price

(1)

Load Shape &

Ancillary Services

$7.50 

Capacity

$12.00

Transmission &

Congestion

$7.00 -

$8.00

Renewable

Energy

Credits

$1.00

Migration,

Volumetric

Risk & Other

$1.00

~$6.50

~$5.50

(1)

As provided by Exelon Generation.

(2)

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

full requirements’

products with delivery beginning Jan 1, 2011).

(1)

As provided by Exelon Generation.

(2)

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

full requirements’

products with delivery beginning Jan 1, 2011).

Average

Wholesale

Energy Price

$79.96

(2)

41

42

42

Midwest Price Recovery Update

42

•

Last fall, we saw approximately $5/MWh of upside over NiHub ATC forward prices

•

Since then, we have seen an expansion in market implied heat rates, with NiHub prices

declining proportionally less than forward gas prices

–

We have also seen a reduction in the NiHub-ADHub

spread

•

Holding natural gas prices at current levels, we expect some additional increase in NiHub ATC

forward prices as the economy/load recovers and transmission enhancements are completed

Exelon will benefit as Midwest prices increase, moving closer to

our fundamental view...

2012 gross margin increases by ~$275 million for a $5/MWh increase in NiHub ATC

43

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

***********

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

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

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

***********

44

-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

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: The information on this slide is the same as disclosed on January 22, 2010 and

has not been updated to reflect any changes that may have occurred since that date.

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%

45

ComEd Customer Usage Breakdown

Customer Usage by Revenue Class

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

ComEd’s territory is largely manufacturing focused, which is beginning

to see increases in

production due to improved economic conditions

Note: The information on this slide is the same as disclosed on January 22, 2010 and has not been updated to reflect

any changes that may have occurred since that date.

46

Illinois Power Agency (IPA) RFP Procurement

•

On December 28, 2009, the Illinois Commerce Commission approved the IPA’s

Updated Procurement Plan for the 2010/11 planning period, which includes

the

procurement of:

–

monthly peak and off-peak standard wholesale block energy products

–

1,887,014 MWh of Renewable Energy Credits

–

1,400,000 MWh/year of renewable energy and associated RECs through 20

year contracts beginning delivery in June 2012

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

Next RFP expected in Spring 2010

2009 RFP

2009 RFP

2010 RFP

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2013 RFP

Financial

Swap

Auction

Contract

Jun 2009

Jun 2010

Jun 2011

Jun 2012

Jun 2013

Jun 2014

Delivery

Period

Peak

Off-Peak

June 2010 -

May 2011

5,528

4,344

June 2011 -

May 2012

1,980

549

Volume to be procured in the 2010

IPA Procurement Event (GWh)

47

Financial Swap Agreement with

Exelon Generation

3,000

$53.48

January 1, 2013 -

May 31, 2013

3,000

$52.37

January 1, 2012 -

December 31, 2012

3,000

$51.26

January 1, 2011 -

December 31, 2011

3,000

$50.15

June 1, 2010 -

December 31, 2010

2,000

$50.15

January 1, 2010 -

May 31, 2010

2,000

$49.04

June 1, 2009 -

December 31, 2009

1,000

$49.04

January 1, 2009 -

May 31, 2009

1,000

$47.93

June 1, 2008 -

December 31, 2008

Notional Quantity (MW)

Fixed Price ($/MWH)

Portion of Term

•

Market-based contract for ATC baseload energy only

–

Does not include capacity, ancillary services, or congestion

•

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

•

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

Note: C&I = Commercial & Industrial

Financial swap increases to 3,000 MW on June 1, 2010

48

Smart Meter/Smart Grid

•

Smart Meter Pilot

(or Advanced Metering Infrastructure -

AMI)

–

ICC approved on October 14, 2009

–

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

–

Expected

to

be

implemented

in

early

summer

2010

–

over

80,000

smart

meters

installed

to

date

–

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

a rider

•

Smart Grid Solar Pilot Project

–

Negotiating with DOE to obtain $5 million in stimulus funds for Smart Grid Solar Pilot

–

Pilot group of ~100 residential customers will receive roof-top solar systems and be placed on

real-time pricing and net metering programs

–

Solar systems will be deployed at customers within the smart meter pilot footprint

–

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

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

customer acceptance of new technologies

•

Green Vehicle Fleet

–

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

on Electric Grid

–

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

–

Will

deploy

vehicle

smart

charging

stations

and

evaluate

impacts

of

vehicle

charging

while

managing the electric load

ComEd is pursuing a number of smart grid investments with regulated

returns and stimulus funding

49

*********

*********

***********

***********

********

50

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.

of

Labor

(PHL

-

November

2009,

U.S.

–

December

2009)

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

(3)  Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

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

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)%

Note: The information on this slide is the same as disclosed on January 22, 2010 and

has not been updated to reflect any changes that may have occurred since that date.

C&I = Commercial & Industrial

51

PECO Customer Usage Breakdown

Other

3%

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

7%

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

2%

Retail Trade

9%

Finance, Insurance & Real Estate

12%

Pharmaceuticals

PECO’s

load

is

relatively

diversified

by

customer

class

and

industry,

a

slow

recovery

in

the

second half of 2010 is expected

Note: The information on this slide is the same as disclosed on January 22, 2010 and has not been updated to reflect

any changes that may have occurred since that date.

52

PECO Procurement Results

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

residential customers beginning in 2011

•

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

(1)

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

(2)

Wholesale prices; no Small/Medium Commercial products were procured in the June RFP.

Residential

Sept RFP average price of

$79.96/MWh

(2)

June RFP average price of

$88.61/MWh

(2)

49% of full requirements product

procured

80 MW of block energy procured

Small and Medium Commercial

Sept RFP average blended price

of $85.85/MWh

(2)

24% of Small Commercial full

requirements product procured

16% of Medium Commercial full

requirements product procured

85% full requirements

15% full requirements spot

Medium Commercial &

Industrial

(peak demand >100 kW

but <= 500 kW)

100% full requirements spot

Large Commercial &

Industrial

(peak demand >500 kW)

90% full requirements

10% full requirements spot

75% full requirements

20% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100 kW)

Residential

Customer Class

PECO Procurement Plan

(1)

Total Procured (including

June and September RFPs)

Residential

23% of planned full requirements

contracts (17 and 29-mo terms)

140 MW of baseload (24x7)

block energy products (12, 24

and 60-mo duration)

40 MW of Jan-Feb 2011 on-peak

block energy

Small Commercial

36% of planned full requirements

contracts (17 and 29-mo term)

Medium Commercial & Industrial

42% of planned full requirements

contracts (17-mo term)

May 24, 2010 RFP

53

5.03

5.03

0.51

0.51

6.26

2.57

9.41

PECO Average Residential Electric Rates

(1)

Average of PECO’s residential rates.

(2)

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

(3)

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

Alternative Energy Portfolio Standard requirements.

(4)

Does not include energy efficiency or changes in distribution rates.

2011

2010

Energy / Capacity

Competitive Transition

Charge (CTC)

Transmission

Distribution

14.37¢

(1)

Unit Rates (¢/kWh)

Electric Restructuring

Settlement

~4%

(4)

14.95¢

(1)

Assumptions

Illustrative Rate Increase Based on

PECO Residential Full Requirements

Procurement Results

(2)

•

2011 illustrative residential rate based

on a weighting of 26% on Spring 2009

Retail results, 23% on Fall 2009 Retail

results, and future supply

procurement estimated at Fall 2009

Results

•

Actual 2011 default service residential

rate will reflect associated full

requirements costs, block energy

costs, and spot market purchases, all

of which will be acquired through

multiple procurements

•

Rates will vary by customer class

•

Retail rate components include line

losses and gross receipts taxes

Spring 2009

10.13¢/kWh

PECO Residential

Procurement Results

(3)

Effect of Spring and Fall 2009 Procurements

Fall 2009

9.16¢/kWh

Retail Results

54

PECO Smart Grid/Smart Meter

•

PECO

intends

to

spend

up

to

$650

million

on

its

Smart

Grid/Smart

Meter

Infrastructure

(1)

–

$550

million

Advanced

Metering

Infrastructure

over

10

–

15

years

–

~$300 million in 2010-2012 period

–

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

•

Awarded $200 million Federal Stimulus Grant on October 27, 2009

–

Working with DOE to agree on terms and conditions

•

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

surcharge including a return on capital investment

•

Smart Grid investment to be recovered through transmission and distribution rates

2010-2012

Spend

With

Federal

Stimulus

Grant

(2)

:

($ millions pre-tax)

2010

2011

2012

Total

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

(3)

40

$   

150

$ 

100

$ 

290

$      

Smart Grid Stimulus Case

50

45

15

110

Total Stimulus Case

90

195

115

400

Stimulus Grant Request

(45)

(100)

(55)

(200)

Total Expenditures net of Stimulus grant

45

$   

95

$   

60

$   

200

$      

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

(2)

Assumes 100% of matching funds requested by DOE.

(3)

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

Data contained in this slide is rounded.

55

55

55

Exelon Generation Hedging Disclosures

(As disclosed on January 22, 2010)

56

56

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.

57

57

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

58

58

58

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

59

59

59

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

(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.

Exelon Generation Open Gross Margin and

Reference Prices

60

60

60

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.

61

61

61

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

(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.

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

62

62

62

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.

63

63

63

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

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.90 billion

MTM value of energy hedges:              $1.13 billion + $(0.70 billion) + $0.00 billion

Estimated hedged gross margin:          $6.33 billion

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

64

64

64

64

64

64

64

50

55

60

65

70

75

80

85

90

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

20

25

30

35

40

45

50

55

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

35

40

45

50

55

60

65

70

75

80

85

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

5

5.5

6

6.5

7

7.5

8

8.5

9

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

64

Market Price Snapshot

Forward NYMEX Natural Gas

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

PJM-West and Ni-Hub Wrap Forward Prices

2011

$5.87

2012  $6.13

Rolling 12 months, as of February 26, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$70.26

2012

$74.15

2011 Ni-Hub  $39.78

2012 Ni-Hub

$40.88

2012 PJM-West  $54.85

2011 PJM-West

$53.70

2011 Ni-Hub

$24.37

2012 Ni-Hub

$25.63

2012 PJM-West

$38.05

2011 PJM-West

$37.51

65

65

65

65

65

65

65

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

8

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

10

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

40

45

50

55

60

65

70

75

80

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

5

5.5

6

6.5

7

7.5

8

8.5

9

3/09

4/09

5/09

6/09

7/09

8/09

9/09

10/09

11/09

12/09

1/10

2/10

65

Market Price Snapshot

2012

$8.99

2011

$8.77

2011

$50.68

2012

$54.26

2011

$5.78

2012

$6.03

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$6.79

2012

$8.34

ERCOT North On Peak Spark Spread

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

Rolling 12 months, as of February 26, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

66

Key Assumptions and GAAP Reconciliation

67

67

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.

68

2009 GAAP Reconciliation

Note:  Amounts may not add due to rounding.

110

-

-

-

110

Mark-to-market adjustments from economic hedging activities

(34)

-

-

-

(34)

Retirement of fossil generating units

(5)

-

-

(5)

-

City of Chicago settlement with ComEd

(66)

-

-

(4)

(62)

2007 Illinois electric rate settlement

(74)

(30)

-

-

(44)

Costs associated with early debt retirements

(135)

-

-

-

(135)

Impairment of certain generating assets

(22)

(1)

(1)

(13)

(7)

2009 restructuring charges

32

-

-

-

32

Decommissioning obligation reduction

(20)

(20)

-

-

-

NRG Energy, Inc. acquisition costs

132

-

-

-

132

Unrealized gains related

to nuclear decommissioning trust

funds

66

(12)

-

40

38

Non-cash remeasurement of income tax uncertainties and

reassessment of state deferred income taxes

$2,707

$(142)

$353

$374

$2,122

FY 2009 GAAP Earnings (Loss)

$2,723

$(79)

$354

$356

$2,092

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

Exelon

Other

PECO

ComEd

ExGen

2009 GAAP Reconciliation (in millions)

69

2009 GAAP EPS Reconciliation

0.16

-

-

-

0.16

Mark-to-market adjustments from economic hedging activities

(0.05)

-

-

-

(0.05)

Retirement of fossil generating units

(0.01)

-

-

(0.01)

-

City of Chicago settlement with ComEd

(0.10)

-

-

(0.01)

(0.09)

2007 Illinois electric rate settlement

(0.11)

(0.04)

-

-

(0.07)

Costs associated with early debt retirements

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

(0.03)

-

(0.00)

(0.02)

(0.01)

2009 restructuring charges

0.05

-

-

-

0.05

Decommissioning obligation reduction

(0.03)

(0.03)

-

-

-

NRG Energy, Inc. acquisition costs

0.19

-

-

-

0.19

Unrealized gains related

to nuclear decommissioning trust

funds

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and

reassessment of state deferred income taxes

$4.09

$(0.21)

$0.53

$0.56

$3.21

FY 2009 GAAP Earnings (Loss) Per Share

$4.12

$(0.12)

$0.54

$0.54

$3.16

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

Share

Exelon

Other

PECO

ComEd

ExGen

2009 GAAP EPS Reconciliation

(1)

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

Note:  Amounts may not add due to rounding.

70

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

71

Exelon Investor Relations Contacts

Exelon Investor Relations

10 South Dearborn Street

Chicago, Illinois 60603

312-394-2345

312-394-4082 (Fax)

For copies of other presentations,

annual/quarterly reports, or to be

added to our email distribution list

please contact:

Martha Chavez, Executive Admin

Coordinator

312-394-4069

Martha.Chavez@ExelonCorp.com

Investor Relations Contacts:

Karie Anderson, Vice President

312-394-4255

Karie.Anderson@ExelonCorp.com

Stacie Frank, Director

312-394-3094

Stacie.Frank@ExelonCorp.com

Paul Mountain, Manager

312-394-2407

Paul.Mountain@ExelonCorp.com

Marybeth Flater, Manager

312-394-8354

Marybeth.Flater@ExelonCorp.com