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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