Commonwealth Edison 8-K Regulation FD Disclosure

1

Exhibit 99.1

William A. Von Hoene, Jr., EVP Finance and Legal

Credit Suisse 2010 Energy Summit

February 3, 2010

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 of Financial Condition and Results of Operations and (c) ITEM 8.

Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2009

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

and (b) Part I, 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.

3

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

4

Exelon Generation Consistently

Delivers Top-Tier Results

Nuclear Reliability

30 Longest Continuous US Runs

Exelon Power Fleet Availability

Exelon Generation’s nuclear fleet has 16 of the

30 longest continuous US runs…evidence of its

ability to replicate best practices on a large scale

Source: Platts

News Flashes and Company Press Releases, 11/3/09

90.7%

93.5%

91.2%

89.1%

93.7%

92.9%

94.8%

95.8%

97.5%

93.8%

80%

85%

90%

95%

100%

2005

2006

2007

2008

2009

Fossil Fleet Commercial Availability

Hydro Equivalent Availability

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)

5

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

•

Working with PJM to ensure reliability is maintained when units are retired

$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

6

ComEd Building Strength

Earned ROE

4%

6%

8%

10%

2008

2009

2010E

ComEd executing on regulatory recovery plan resulting in healthy

increases in earned ROE

•

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

•

Significant improvement in earned

ROE, from 5.5% in 2008 to 8.5% in

2009, targeting at least 10% in 2010

•

Uncollectibles

expense rider tariff

approved by ALJ on January 14,

with ICC approval expected in

February 2010

7

PECO Executing on Transition Plan

•

Targeting earned ROE of approximately 11% in 2010; 9-11% post-

transition

•

Anticipate electric and gas distribution rate filings by end of 1Q10

•

Selected as 1 of 6 utilities to receive maximum Federal stimulus

award of $200 million for smart grid/smart meter investment

•

Act 129 Smart Meter Plan approved by the ALJ in January, approval

expected by the PA PUC in 1Q10

•

Two procurement events for post-2010 have been conducted,

including 49% of residential 2011 load; next procurement in May 2010

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 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

Deploying Capital for Shareholder Value

Smart Grid

Environmental

Price

Recovery

Transmission

9

Midwest Price Recovery Update

9

•

Last fall, we saw about $3-6/MWh of upside over NiHub ATC forward prices

•

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

slightly despite small declines in 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

NiHub Market Implied Heat Rate

4.75

5.00

5.25

5.50

5.75

6.00

6/30/09

7/30/09

8/30/09

9/30/09

10/30/09

11/30/09

12/30/09

Cal 2011

Cal 2012

Cal 2013

AEP-Dayton / NiHub

ATC Energy Basis

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

2007

2008

2009

2010

2011

2012

2013

2014

Actuals

PJM Oct '09 FTR Auction

6/30/2009

9/30/2009

12/31/2009

10

2010 Events of Interest

Q1

Q2

Q3

Q4

RPM Auction (May)

Uncollectibles rider

tariff (March)

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)

11

Appendix

(As disclosed on January 22, 2010)

12

-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: 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%

13

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, US –

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

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)%

14

(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

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.

$0.7

$0.6

PECO

(1)

$1.0

$1.0

ComEd

(1)

$2.7

$2.7

Generation

2010E

2009A

$ billions

($ millions)

(2)

(2)

(2)

O&M Expense

(1)

15

15

15

Exelon Generation Hedging Disclosures

(As disclosed on January 22, 2010)

16

16

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.

17

17

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

18

18

18

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

19

19

19

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

20

20

20

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.

21

21

21

Gross Margin Sensitivities with Existing Hedges ($ millions)

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.

(1)

22

22

22

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.

23

23

23

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)

24

24

24

24

24

24

50

55

60

65

70

75

80

85

90

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

20

25

30

35

40

45

50

55

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

35

40

45

50

55

60

65

70

75

80

85

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

5.5

6

6.5

7

7.5

8

8.5

9

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

24

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

$6.14

2012  $6.33

Rolling 12 months, as of January 28, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$65.24

2012

$72.30

2011 Ni-Hub  $42.77

2012 Ni-Hub

$43.25

2012 PJM-West  $57.40

2011 PJM-West

$56.92

2011 Ni-Hub

$24.01

2012 Ni-Hub

$26.25

2012 PJM-West

$40.64

2011 PJM-West

$39.95

25

25

25

25

25

25

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

8.2

8.4

8.6

8.8

9

9.2

9.4

9.6

9.8

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

40

45

50

55

60

65

70

75

80

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

5.5

6

6.5

7

7.5

8

8.5

9

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

25

Market Price Snapshot

2012

$9.00

2011

$8.71

2011

$52.44

2012

$55.98

2011

$6.02

2012

$6.22

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

$6.49

2012

$8.62

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 28, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

26

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