EX-99.1 2 dex991.htm PRESENTATION SLIDES Presentation Slides
1
Macquarie Global Infrastructure Conference
May 25, 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; (2) Exelon’s
First Quarter 2010 Quarterly Report on Form 10-Q in (a) Part II, Other Information, Item
1A.  Risk Factors, (b) Part 1, Financial Information, Item 2. Management’s Discussion and
Analysis of Financial Condition and Results of Operations and (c) Part I , Financial
Information,
Item
1.
Financial
Statements:
Note
12
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
Table of Contents
•
Exelon Generation
4
•
ComEd
32
•
PECO
37

4

5
Exelon Generation Consistently
Delivers Top-Tier Results
Exelon Generation has ability to replicate best practices on a large scale
2009
•
93.6%
capacity
factor
–
the
7
th
consecutive
year
exceeding 93%
•
Clinton
and
Quad
Cities
1
units
-
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
2010 YTD
•
Limerick 1 unit set a new continuous run record of 727
days (second longest in the US)
•
Byron 2 unit –
new continuous run record of 541 days
Nuclear Fleet Achievements
•
Premier merchant generator of electricity
•
Largest nuclear operator in U.S. with 18% of nuclear
output; third largest in the world
•
Ownership interest in 19 operating nuclear reactors
•
Top quartile performance in capacity factors and
generating cost among nuclear fleets in U.S.
•
Geographically well-situated in competitive markets
and part of PJM, the largest RTO
Exelon Generation Highlights
0
200
400
600
800
Byron 2
Quad Cities 1
Clinton
Three Mile Island 1
Three Mile Island 1
LaSalle 2
Three Mile Island 1
LaSalle 1
Three Mile Island 1
Three Mile Island 1
Peach Bottom-3
Peach Bottom-3
LaSalle 2
Limerick 1
LaSalle 1
(Days)
Source: Platts News Flashes and Company Press Releases, 4/26/10
Nuclear Reliability
30 Longest Continuous U.S. Runs

6
Nuclear Uprates Offer Sustainable Value
Key component of Exelon
2020 low carbon roadmap
Creates additional low-
carbon generation
capacity
Uprates equivalent in size
to a new nuclear plant but
significantly lower cost,
shorter timeline, and more
predictable expenditures
No ongoing incremental
O&M expense
Capitalizes on Exelon’s
proven track record of
uprate execution
Dedicated project
management team
Proven technology design
Allows us to adjust timing
to respond to market
conditions
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
Regulatory Feasibility
Execution Feasibility

7
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 -
6
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
3-4 years
~1,300–1,500 MW
$3,500M
Project
Duration
Refined
scenario
analysis
highlights
that
uprates
continue
to
be
economic
(1) In 2007 dollars. Overnight costs do not include financing costs or cost escalation.
Estimated
Internal Rate
of Return
11-13%
14-16%
11-14%

8
Multi-Regional Nuclear Uprate Program
73
2
12
59
MW
Online to
Date
2011 / 2012
32
25
Peach Bottom
2011 / 2010
110
95
Quad Cities
2014
15
12
TMI
2014 / 2013
31
25
Dresden
2013 / 2013
23
19
Quad Cities
2012 / 2012
42
34
Byron
2012 / 2012
42
34
Braidwood
2011 / 2011
41
33
Limerick
2011 / 2011
40
32
LaSalle
2014 / 2015
3
3
Peach Bottom
MUR:
2012 / 2013
6
6
Limerick
2012 / 2013
110
103
Dresden
2011 / 2012
5
5
Dresden
EPU:
MW Recovery & Component Upgrades:
2016 / 2017
340
306
Limerick
1,516
1,323
Total
172
336
17
148
3
Max
Potential
MW
2016
138
TMI
2016 / 2015
303
LaSalle
2016
17
Clinton
2015 / 2016
134
Peach Bottom
2010
2
Clinton
Year of Full
Operation
by Unit
Base
Case
MW
Station
Executing uprate projects across our
geographically diverse nuclear fleet
TMI
Limerick
Peach
Bottom
Total Midwest Uprates:
666-759 MW
Total Mid-Atlantic Uprates:
657-757 MW
Quad
Cities
Dresden
Byron
LaSalle
Clinton
Braidwood
Notes:  MW shown at ownership.

9
Phased Execution Lowers Risk
Approximately 80 MW scheduled to be completed in 2009 and 2010; total
expenditures
expected
to
be
$4,400
million
from
2008
–
2017
(1)
(1) Dollars shown are nominal, reflecting 6% escalation, in millions. 
$150
$350
$550
$675
$625
$725
$725
$400
$150
$ millions
•
Highest return projects are being completed in the early years
•
Leverages Exelon’s substantial experience managing successful uprate projects –
1,100
MW
completed
between
1999
-
2008
$50
Exelon's
Uprate
Plan
Expenditures
$0
$100
$200
$300
$400
$500
$600
$700
$800
2008A
2009A
2010E
2011E
2012E
2013E
2014E
2015E
2016E
2017E
0
200
400
600
800
1,000
1,200
1,400
1,600
Megawatt Recovery
MUR
EPU
MW Online (Cumulative)
Note: MW shown at ownership. Data contained in this slide is rounded.

10
Quad Cities Uprate Program
•
MW Recovery
–
Unit 2 Low Pressure Turbine Retrofit completed April
2010, increase of 48 MW achieved
–
Unit 1 Low Pressure Retrofit planned for Spring 2011
–
Partial completion of Unit 1 work has resulted in an
increase of 11 MW
•
MUR
–
Planned start date of project will be in 2011
–
Timing of uprate will be dependent on NRC approval
of license amendment
•
EPU
–
Completed in 2002
Scheduled start in 2011
1Q2013
9
2Q2013
9
MUR
* Capital investment and MW uprate numbers represent Exelon’s 75% ownership stake in Quad Cities Station.
In progress
2Q2010
48
3Q2011
47
MW Recovery (Low Pressure
Turbine Retrofit)
Status
Online
Date
MW
Increase*
Online
Date
MW
Increase*
Uprate Project
Unit 2
Unit 1
Quad
Cities
Uprate
Projects
are
underway
–
additional
MWs
will
come
on
line
between 2010 and 2013
Capital Investment $M*
$0
$50
$100
2009
2010
2011
2012
2013
2014
2015
2016
MW Recovery and Component Upgrade
MUR

11
Peach Bottom Uprate Program
•
MW Recovery
–
Project in progress with Low Pressure Turbine Retrofit
installations expected in 2011 and 2012
–
Replace Reactor Recirculation Pump Motor Generator
sets with energy efficient Adjustable Speed Drives in
2014 and 2015
•
MUR
–
Completed in 2003
•
EPU
–
Funding approved for design work
–
Will review in 2011 before authorizing installation
funding for  physical plant modifications and purchase
of materials
Peach
Bottom
Uprate
Projects
are
underway
–
additional
MWs
will
come
online
between
2011 and 2016
Capital Investment $M*
$0
$50
$100
$150
2009
2010
2011
2012
2013
2014
2015
2016
2017
MW Recovery and Component Upgrade
EPU
* Capital
investment
and
MW
uprate
numbers
represent
Exelon’s
50%
ownership
stake
in
Peach
Bottom
Station.
In progress
4Q2011
11
4Q2012
14
MW Recovery (Low Pressure
Turbine Retrofit)
Design phase in progress
1Q2016
67
1Q2015
67
EPU
Scheduled to start in 2012
4Q2015
2
4Q2014
2
MW Recovery (Adjustable
Speed Drives)
Status
Online
Date
MW
Increase*
Online
Date
MW
Increase*
Uprate Project
Unit 3
Unit 2

12
Dresden Uprate Program
•
MW Recovery
–
Project in progress with Low Pressure Turbine
Retrofit installations expected in 2011 and 2012
–
Partial completion of Unit 2 work has resulted in an
increase of 12 MW
–
Replace Reactor Recirculation Pump Motor
Generator sets with energy efficient Adjustable
Speed Drives in 2011 and 2012
•
MUR
–
Planned start date of project will be in 2011
–
Timing of uprate will be dependent on NRC approval
of license amendment
•
EPU
–
Completed in 2002
Dresden
Uprate
Projects
are
underway
–
additional
MWs
will
come
online            
between 2011 and 2014
Capital Investment $M
$0
$50
$100
$150
$200
2009
2010
2011
2012
2013
2014
2015
2016
2017
MW Recovery and Component Upgrade
MUR
In progress
4Q2012
3
4Q2011
3
MW Recovery (Adjustable
Speed Drives)
Scheduled start in 2011
1Q2013
12
1Q2014
12
MUR
In progress
1Q2013
51
1Q2012
52
MW Recovery (Low Pressure
Turbine Retrofit)
Status
Online
Date
MW
Increase
Online
Date
MW
Increase
Uprate Project
Unit 3
Unit 2

13
13
13
13
13
13
13
13
13
Nuclear Assets Levered to Economic
Recovery –
2011 & Beyond
Exelon
uniquely
captures
any
margin
upside
from
increasing
power
prices
given
our
low-cost nuclear generation
(1) Both supply and demand include effects of First Energy’s generation and forecasted load, respectively, joining PJM.  Illustrated unit costs are of existing PJM generation using 2011 fuel prices as of 4/30/2010.
Sources: CEMS, Energy Velocity, SNL,
Exelon Proprietary Information
2009 –
Exelon
Generation Owned
Output
(MWh)
Nuclear
93%
Coal
5%
Oil
<1%
Gas
1%
Renewables
1%
PJM Supply Curve
(1)

14
111.91
148.80
102.04
191.32
174.29
110.00
16.46
133.37
139.73
27.73
226.15
245.00
2008/2009
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
RTO
MAAC + APS
MAAC
Eastern MAAC
Only shown
if cleared
at separate
price and
generation
is located
in that zone
(1)
Reliability Pricing Model (RPM) Auction
PJM RPM Auction ($/MW-day)
Exelon Generation Eligible Capacity within PJM Reliability Pricing Model
(2)
Note: Data contained on this slide is rounded.
(1)
MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.
(2)
All generation values are approximate and not inclusive of wholesale transactions.
(3)
All capacity values are in installed capacity terms (summer ratings) located in the areas.
(4)
Obligation represents the remainder of the ComEd auction load that ends in May 2010.
(5)
Obligation consists of load obligations from PECO. PECO PPA expires December 2010.
(6)
Elwood
contract
expires
on
12/31/12
and
Kincaid
contract
expires
on
2/28/13.
(7)
Reflects decision in December 2010 to permanently retire Cromby Station and Eddystone Units
1&2
as
of
5/31/11.
None
of
these
933
MW
cleared
in
the
2011/2012
or
2012/2013
auctions.
(8)
Weighted average $/MW-Day would apply if all generation cleared in the highlighted zones.
$134.46        
1,500
8,700
(7)
10,300
(6)
Capacity
(3)
2013/2014
2009/2010
2010/2011
2011/2012
2012/2013
in MW
Capacity
(3)
Obligation
Capacity
(3)
Obligation
Capacity
(3)
Capacity
(3)
RTO
12,800
3,800 -
4,100
(5)
23,900
9,300 -
9,400
(4)
23,200
12,100
(6)
EMAAC
9,500
MAAC + APS
11,100 
9,300 –
9,400
(5)
MAAC
1,500
Avg ($/MW-Day)
(8)
$143.90
$174.29
$110.00
$74.75               

15
Retiring Cromby Station and
Eddystone Units 1&2
•
Agreed to delay deactivation of two units
to maintain reliability
(1)
, provided receipt
of required environmental permits and
adequate cost-based compensation
–
Maintained scheduled retirement date of 5/31/11
for Cromby 1 and Eddystone 1
–
Revised retirement dates for Cromby 2 to
12/31/11 and Eddystone 2 to 12/31/12
•
RMR to be filed with FERC in 2Q10 to compensate for cost of maintaining and
operating units beyond 5/31/11
–
Reimburses
Exelon
for
costs
to
keep
units
running
and
allows
for
a
reasonable
rate
of
return
on
investment, which is estimated at $2.6 million per RMR-month for Cromby Unit 2 and $8.0 million per
RMR-month for Eddystone Unit 2, plus $19.3 million in project investment
–
Targeting final approval by 4Q10
•
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
$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
(1)
See PJM’s website (http://www.pjm.com/planning/generation-retirements/gr-study-results.aspx) for additional details regarding PJM’s Deactivation Study and Exelon’s response.
Note: RMR = reliability must-run agreement

16
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%
Long-term equilibrium price expected to be $40-$60/lb

17
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
Note:
Data
includes
Salem.
Net
nuclear
generation
data
based
on
ownership
interest.
•
Generally, every 18 months (PWRs) or
24 months (BWRs)
•
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.

18
18
Total Portfolio Characteristics
101,700
102,441
40,500
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)
91,800
91,804
48,000
47,866
24,800
29,840
5,800
3,555
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
170,400
170,400
(1)  As of March 31, 2010.
(1)
(1)

19
Exelon Nuclear Fleet Overview
Note: Fleet also includes 4 shutdown units: Peach Bottom 1, Dresden 1, Zion 1 & 2.
Average in-service time = 29 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
(3)
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
License extensions will be pursued for all units not already renewed
(1)
Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review.
(2)
Capacity based on ownership interest.
(3)
The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from
the reactor core. Dry cask storage will be in operation at those sites prior to the closing of their on-site storage pools.

20
20
20
Exelon Generation Hedging Disclosures
(As disclosed on April 23, 2010)

21
21
21
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 March 31, 2010. 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.

22
22
22
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

23
23
23
23
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

24
24
24
24
2010
2011
2012
Estimated Open Gross Margin ($ millions)
(1,2)
$5,050
$4,900
$4,750
Open gross margin assumes all expected generation is
sold at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)    
ERCOT North ATC Spark Spread ($/MWh)
(3)
$4.48
$29.73
$39.69
$0.43
$5.34
$30.71
$42.04
$(0.42)
$5.79
$32.19
$43.47
$0.14
(1)
Based on March 31, 2010 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

25
25
25
25
(1)
2010
2011
2012
Expected Generation
(GWh)
(1)
164,600
161,700
161,200
Midwest
98,600
98,100
97,000
Mid-Atlantic
58,000
56,600
56,600
South
8,000
7,000
7,600
Percentage of Expected Generation Hedged
(2)
95-98%
79-82%
48-51%
Midwest
92-95
79-82
52-55
Mid-Atlantic
96-99
81-84
44-47
South
97-100
68-71
41-44
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$46.50
$44.50
$44.50
Mid-Atlantic
$36.00
$58.00
$51.50
ERCOT North ATC Spark Spread
$0.50
$0.50
$(6.50)
Generation Profile
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.
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. 
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.
(2)
(3)

26
26
26
26
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
$(20)
$20
$(15)
$5
$ -
+/-
$30
2011
$125
$(110)
$125
$(115)
$75
$(70)
+/-
$40
2012
$320
$(315)
$235
$(225)
$175
$(170)
+/-
$45
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1) 
Based on March 31, 2010 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.

27
27
27
27
95% case
5% case
$6,500
$6,200
$4,800
$7,200
$6,300
$6,600
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 March 31, 2010.

28
28
28
28
Midwest
Mid-Atlantic
ERCOT
Step 1
Start
with
fleetwide
open
gross
margin 
$5.05 billion
Step 2
Determine the mark-to-market value
of energy hedges
98,600GWh * 93% *
($46.50/MWh-$29.73/MWh)
= $1.54 billion
58,000GWh * 97% *
($36.00/MWh-$39.69/MWh)
= $(0.21 billion)
8,000GWh * 98% *
($0.50/MWh-$0.43/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:                           $5.05 billion
MTM value of energy hedges:           $1.54
billion
+
$(0.21
billion)
+
$0.00
billion
Estimated hedged gross margin:       $6.38 billion
Illustrative Example
of Modeling Exelon Generation 2010 Gross Margin
(with Existing Hedges)

29
29
29
Market Price Snapshots
Rolling 12 Months as of May 17, 2010

30
30
30
30
30
30
30
50
55
60
65
70
75
80
85
90
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
20
25
30
35
40
45
50
55
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
35
40
45
50
55
60
65
70
75
80
85
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
5
5.5
6
6.5
7
7.5
8
8.5
9
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
30
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
$5.57
2012  $5.98
Rolling 12 months, as of May 17, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.
Forward NYMEX Coal
2011
$66.66
2012
$73.55
2011 Ni-Hub  $41.01
2012 Ni-Hub
$42.45
2012 PJM-West  $55.88
2011 PJM-West
$54.09
2011 Ni-Hub
$24.25
2012 Ni-Hub
$25.73
2012 PJM-West
$40.56
2011 PJM-West
$39.38

31
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
8
8.2
8.4
8.6
8.8
9
9.2
9.4
9.6
9.8
10
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
40
45
50
55
60
65
70
75
80
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
5
5.5
6
6.5
7
7.5
8
8.5
9
5/09
6/09
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
Market Price Snapshot
2012
$9.06
2011
$8.89
2011
$48.70
2012
$53.22
2011
$5.48
2012
$5.87
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
$6.68
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 May 17, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

32

33
-10.0%
-7.5%
-5.0%
-2.5%
0.0%
2.5%
5.0%
7.5%
10.0%
1Q09
2Q09
3Q09
4Q09
1Q10
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
Unemployment rate
(1)
10.9%
2010 annualized growth in
gross domestic/metro product
(2)
2.9%
1/10 Home price index
(3)
(4.4)%
(1)  Source: Illinois Dept. of Employment Security (February 2010)
(2)
Source: Global Insight (March 2010)
(3)
Source: S&P Case-Shiller Index
(4)
Not adjusted for leap year effect
2009
(4)
1Q10       2010E
Average Customer Growth
(0.4)%     (0.1)%       0.1%
Average Use-Per-Customer
(1.0)%
0.2%
0.1%
Total Residential
(1.4)%       0.1%        0.2%
Small C&I
(2.2)%    (1.7)%        0.4%
Large C&I
(6.7)%    (1.1)%        1.7%
All Customer Classes
(3.3)%    (0.8)%        0.8%

34
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
•
Anticipate electric distribution rate filing in 2Q10
•
Benefiting from regular transmission updates
through a formula rate plan, filed formula rate
update on May 14, 2010
•
Illinois Power Agency’s 2010 procurement
approved by the ICC on April 30
•
Uncollectibles expense rider tariff approved by
ICC in February 2010
•
Smart Meter pilot program and rider approved
by ICC and underway
•
Standard & Poor’s raised credit ratings in
3Q09 and Fitch in 1Q10

35
Illinois Power Agency (IPA)
RFP Procurement
•
On April 30, 2010, the ICC approved the bids from the RFP Procurement
held on April 28, 2010, for the remaining ComEd 2010-2011 load (~25% of
the total) and a portion of its 2011-2012 load (~7% of the total)
–
Contracts were awarded to 12 successful bidders
–
$32.54
Around-the-Clock (ATC) price for 2010-2011 planning year, in addition to:
•
Financial
Swap
price
(ATC
baseload
energy
only)
of
$50.15
for
June
2010
–
December
2010
and
$51.26
for
January
2011
–
December
2011;
increase
in
notional
quantity
to
3,000
MW
on
June 1, 2010
Delivery
Period
Peak
Off-Peak
June 2010 -
May 2011
5,528
4,344
June 2011 -
May 2012
1,980
549
Volume procured in the 2010 IPA
Procurement Event (GWh)
Note: Chart is for illustrative purposes only.  Data on this slide is rounded.
2009 RFP
2009 RFP
2010 RFP
2010 RFP
2011 RFP
2011 RFP
2011 RFP
2012 RFP
2012 RFP
2013 RFP
Financial
Swap
Auction
Contract
June 2009
June 2010
June 2011
June 2012
June 2013
June 2014

36
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

37

38
PECO Load Trends
Weather-Normalized Electric Load
Key Economic Indicators
Weather-Normalized Load Year-over-Year
(3)
Philadelphia
Unemployment rate
(1)
9.2%               
2010 annualized growth in
gross domestic/metro product
(2)
0.8%
(1)  Source: U.S Dept. of Labor (PHL -
February 2010)
(2)  Source: Moody’s Economy.com (March 2010)
(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
1Q10
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
2009
(3)
1Q10        2010E
Average Customer Growth
(0.2)%       (0.2)%       (0.0)%
Average Use-Per-Customer
(2.1)%
2.1%
1.2%
Total Residential
(2.3)%         1.8%          1.1%
Small C&I
(2.7)%       (0.9)%       (0.2)%
Large C&I
(3.0)%         0.1%        (0.3)%
All Customer Classes
(2.6)%         0.5%         0.3%

39
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
•
Electric and gas rate cases filed on 3/31/10
•
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 approved
Smart Meter Plan under Pennsylvania Act
129 in April 2010
•
Fixed price Power Purchase Agreement
(PPA) with ExGen ends 12/31/10
•
Three of four procurement events for
electricity supply beginning Jan. 1, 2011
have been conducted, including 72% of
2011 residential load
~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

40
PECO Procurement
RFP being held on May 24, 2010, results will be public 30 days
thereafter; next RFP to be held on September 20, 2010
(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 2009 RFP.
(3)
For Large C&I customers who have opted to participate in the fixed-priced full requirements product.
Residential
Sept ’09 RFP average price of
$79.96/MWh
(2)
June ’09 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 ’09 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
(peak demand >100 kW
but <= 500 kW)
fixed-priced full
requirements
(3)
Hourly full requirements
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)
2011 Supply procured to
date (including June and
September 2009 RFPs)
Large Commercial and Industrial
100% of planned fixed -
price full
requirements contracts (12-mo.
term)
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
42% of planned full requirements
contracts (17-mo. term)
May 24, 2010 RFP

41
PECO –
Electric & Gas Distribution
Rate Case Filings
On March 31, PECO filed electric and gas distribution rate cases
•
First electric distribution rate case since 1989
–
Act 129 energy efficiency and smart meter costs recovered separately through rider
•
Last gas delivery rate case in 2008
53.18%
53.18%
Common Equity Ratio
R-2010-216-1592
R-2010-216-1575
Docket #
2010
(1)
2010
(1)
Test Year
ROE: 11.75%
ROR: 8.95%
ROE: 11.75%
ROR: 8.95%
Requested Returns
$1,100 million
$3,236 million
Rate Base
6.94%
(2)
$316 million
Electric
$44 million
Revenue Requirement Increase
5.28%
2011 Proposed Distribution Price
Increase as % of Overall Customer Bill
Gas
Rate Case Request
PECO executing its post-transition regulatory plan to secure fair and
reasonable returns on its distribution investment
(1) With pro forma adjustments.
(2) Excluding Alternative Energy Portfolio Standards (AEPS) and default service surcharge.
Note:
Electric
and
gas
rate
case
filings
available
on
Pennsylvania
Public
Utility
Commission
(PAPUC)
website
or
www.peco.com/know.

42
PECO –
Timeline for Rate Cases
•
Filed: March 31, 2010
•
Opposing Parties’
Testimony: June 2010
•
Rebuttal Testimony: July 2010
•
Hearings: August 2010
•
Administrative Law Judge (ALJ) Orders: October 2010
•
Final Orders Expected: December 2010
•
New Rates Effective: January 1, 2011
Note:
Dates
are
based
on
typical
approach
to
rate
cases
but
the
PAPUC
will
set
the
actual
schedule.
Expect
schedule
to
be
set at pre-hearing with ALJ in early June.
The PAPUC has a nine-month process for litigation of the
rate case filings

43
5.03
6.26
6.23
0.51
0.70
2.57
9.01
PECO Electric Residential Rate
Increases 2010 to 2011
January 1, 2011
January 1, 2010
Total = 14.7¢
Unit Rates (¢/kWh)
Proposed Total Bill
Increase ~11 %
Total = 16.3¢
AEPS 
~0.6%
Default Service Surcharge       
Mechanism based on results of
first two procurements      ~1.2%
Transmission surcharge                           
mechanism                        ~1.3%
Energy / Capacity
Competitive Transition
Charge
Transmission
Distribution
Distribution rate case     ~8.2%
0.38
Energy Efficiency
Surcharge
Breakdown of 2010 to 2011
~11% Increase (On Total Bill)
Notes:
•
Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%.
•
A Smart
Meter
surcharge,
which
will
likely
be
effective
3Q10,
is
expected
to
be
less
than
1%
and
is
not
expected
to
increase
until
2Q/3Q
of
2011.  As a
result, the Smart Meter surcharge will have a minimal impact on rate increases effective January 1, 2011.
•
Low income discounted rates were subsidized in the PPA in 2010 and will be recovered through distribution rates in 2011. 
0.29

44
PECO Smart Grid/Smart Meter
•
PECO
intends
to
spend
up
to
$650
million
on
its
Smart
Grid/Smart
Meter
Infrastructure
–
$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 $200 million Federal Stimulus Grant in October 2009, contract with DOE was
finalized on April 12, 2010
•
Smart Meter Plan was approved by the PAPUC on April 22, 2010
•
Smart Meter investment required by Act 129, which provides for recovery through
surcharge including a return on capital investment
•
Smart Grid investment to be recovered through transmission and distribution rates
($ millions pre-tax)
2010
2011
2012
Total
Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012)
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)
Timing of expenditures may vary as project plans are refined
Data contained in this slide is rounded.
2010-2012
Expenditures
With
Federal
Stimulus
Grant
(1)
:

45
Exelon Investor Relations Contacts
Exelon Investor Relations
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312-394-2345
312-394-4082 (Fax)
For copies of other presentations,
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please contact:
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312-394-4069
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Investor Relations Contacts:
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312-394-3094
Stacie.Frank@ExelonCorp.com
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312-394-2407
Paul.Mountain@ExelonCorp.com
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312-394-8354
Marybeth.Flater@ExelonCorp.com
Sandeep Menon, Principal Analyst
312-394-7279
Sandeep.Menon@ExelonCorp.com