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Form 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

September 9, 2009

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 September 9, 2009, Exelon Corporation (Exelon) will participate in the Barclays Capital CEO Energy/Power Conference. Attached as Exhibit 99.1 to this Current Report on Form 8-K are the presentation slides to be used at the conference.

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 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 Second 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 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

September 9, 2009

EXHIBIT INDEX

 

Exhibit No.

  

Description

99.1   Presentation slides
Presentation slides
1
Barclays Capital CEO Energy/Power Conference
William A. Von Hoene, Jr., EVP Finance and Legal
September 9, 2009
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 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 Second 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
Key Messages
•
Consistently operating the largest nuclear fleet in the U.S. at
world-class levels
•
Executing hedging program to protect the value of our assets
•
Achieving constructive financial and regulatory results at
ComEd and PECO
•
Delivering on cost savings commitments
•
Pursuing financially disciplined organic growth across the
business
•
Improving long-term financial flexibility, including a discretionary
pension contribution

4
70%
75%
80%
85%
90%
95%
Range
5 Year Average
Operational Excellence Across the Fleet
Nuclear Capacity Factor
Production Cost ($/MWh)
Exelon Power Fleet Availability
$10.00
$11.00
$12.00
$13.00
$14.00
$15.00
$16.00
$17.00
$18.00
$19.00
$20.00
2003
2004
2005
2006
2007
2008
Exelon
Industry (excl. Exelon)
EXC: 93.8%
90.7%
93.5%
91.2%
89.1%
96.9%
92.9%
93.8%
94.8%
95.8%
96.6%
80%
85%
90%
95%
100%
2005
2006
2007
2008
2009 YTD
through 6/30
Fossil Fleet Commercial Availability
Hydro Equivalent Availability

5
(1)
Percent
of
expected
generation
hedged
represents
how
many
equivalent
MW
have
been
hedged
at
forward
market
prices
as
of
June
30,
2009;
all
hedge
products
used
are
converted
to
an
equivalent
average
MW
volume
and
the
calculation
considers
whether
hedges
are
power
sales
or
financial
products.
(2)
Represents
an
approximate
range
of
expected
gross
margin,
taking
into
account
hedges
in
place,
between
the
5th
and
95th
percentile
confidence
levels.
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
2010
and
2011
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
June
30,
2009.
Hedging program objectives:
•
Manage market risks and protect the value of our generation and investment-grade balance sheet
•
Preserve our ability to participate in improving long-term market fundamentals
2009
2010
2011
Percentage of Expected
Generation Hedged
(1)
95-98%
87-90%
59-62%
Midwest
96-99
87-90
63-66
Mid-Atlantic
95-98
91-94
56-59
South
90-93
68-71
34-37
95% case
5% case
$6,700
$6,500
$6,100
$6,700
$6,100
$8,400
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
$10,000
2009
2010
2011
Protecting the Long-Term Value of Our Assets
By design, our hedging program allows us to weather short-term, adverse market
conditions, while positioning us to participate in long-term upside potential

6
Well-Positioned Delivery Companies
•
Targeting earned ROEs of ~8% in
2009 and 9-10% in 2010
•
Rate structure and customer
diversity in Large Commercial &
Industrial customer class lessens
the impact of declining load
•
Legislation passed to enable
recovery of uncollectible expense
through a rider
•
Annual Illinois Power Authority
procurement events progressing
as expected
•
Anticipate filing electric distribution
rate case in 2010
•
Targeting earned ROEs in excess of
11% in 2009-2010; 9-11.5% post-
transition
•
Solid credit coverage ratios and
balance sheet strength
•
First procurement event for post-2010
supply held in June, second this month
•
Act 129 Energy Efficiency and Demand
Reduction Plan filed on 7/1
•
Anticipate filing electric and gas
distribution rate cases in 2010
Financial
Regulatory/Legislative
ComEd and PECO continue to deliver on financial targets and build constructive
regulatory and legislative relationships

7
Delivering on Cost Savings Commitments
•
Exelon is delivering on promise to hold 2009 O&M spending flat to 2008 and is
committed to savings of $350 million in 2010 from original planning assumptions,
including the following changes:
–
Reduced positions by 500 (400 in corporate support and 100 at ComEd)
–
Freezing executive salaries and reducing other compensation benefits in 2010
Exelon is responding to today’s challenging environment by driving productivity and
cost reductions while maintaining superior operations
(1)  Reflects operating O&M data and excludes decommissioning impact. ComEd and PECO operating O&M exclude energy efficiency costs recoverable under a rider.
(2)  Exelon Consolidated includes operating O&M expense from Holding Company.
(3)  Reflects ~$175 million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense.
Note: Data contained on this slide is rounded.
ExGen
PECO
ComEd
$4.5B
(2)(3)
$4.5B
(2)
$4.35B
(2)
$4.7B
(2)
+4%
O&M Expense
(1)
$2.7
$2.8
$2.7
$0.8
$0.7
$0.7
$1.1
$1.1
$1.0
2008A
2009E
2010 (Original Est)
2010 (Revised Est)

8
Nuclear
Uprates
-
ComEd and PECO have filed plans to make up to $1 billion in
investments to build smart grid infrastructure over the coming
years, providing for a regulated return on investment
-
1,300–1,500 MW in Exelon nuclear uprates by 2017, the equivalent
of a new nuclear plant at roughly half the cost of building a new
plant and no incremental operating costs
Exelon’s Long-Term Growth Proposition
Smart Grid
Today’s Highlights
Other Key Growth Initiatives
Carbon
PA
Procurement
-
Lowest carbon intensity in the sector –
$1.1 billion
(2)
and growing
annual upside to Exelon revenues if Waxman-Markey legislation is
enacted
-
$101.30/MWh
(1)
result in June PECO power procurement suggests
higher margins at Exelon Generation in 2011 and beyond
-
Developing business plan for transmission company to improve
reliability, reduce congestion, mitigate oversupply and allow our
Midwest fleet to maintain its baseload value
Transmission
(1)    Reflects retail price including line losses and gross receipts tax.
(2)    Assumes $15/tonne carbon pricing.

9
9
Nuclear Uprates Offer Long-Term Growth
at Low Cost and Low Risk
1400
Year Uprates Become Operational
Exelon’s Uprate Plan: 1,300 –
1,500 MW
0
200
400
600
800
1000
1200
1600
1999-
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2009-
2017
1,100 MW
1,300 –
1,500  MW
Average Overnight Cost
Estimate: $2,200 -
2,500/KW
Exelon has proven experience in safe and economical nuclear uprates to improve
efficiency and output at substantially lower cost than building a new nuclear plant
•
Equivalent size of a new nuclear unit
•
Low Cost
–
About half the cost of a new nuclear unit
–
No incremental O&M expense
•
Low Risk
–
Compared to the potential delays
and
cost
overruns
of
building
a
new
plant
–
Able to phase in based on market
and
economic
conditions
–
provides
flexibility to ensure appropriate
returns for shareholders
•
Proven Experience
–
1,100 MW of nuclear uprates on Exelon
fleet already successfully executed
–
Leverages competitive advantage in
operating the nation’s largest nuclear fleet

10
ComEd Smart Grid/Smart Meter
•
Smart Meter (or Advanced Metering Infrastructure -
AMI) Pilot
–
Filed with ICC for approval on June 1, 2009
–
Decision expected in November 2009
–
1-year pilot program for 141,000 smart meters and related programs
–
Recovery with regulated return for capital investment expected to begin in 2010 through a rider
•
Federal Stimulus Funding
–
Request for $175 million in matching funds made on August 4, 2009
–
Investment would occur through 2011
Projected Spend
$ millions
$350
$23
$78
$107
$139
Total
$92
$6
--
$84
--
Transmission
$78
Distribution Automation
$23
Communication Support Systems
$139
AMI & Customer Applications
$258
$17
Distribution
TOTAL
Intelligent Substation
Project
Note: Totals may not add due to rounding.  ComEd includes approximately $4 million of unallocated contract expense
that will be distributed to specific projects upon finalization of scope.
ComEd’s Smart Grid project expands the AMI pilot and provides for
regulated returns on our investments

11
PECO Smart Grid/Smart Meter
PECO Smart Grid project provides strong returns with low recovery risk
•
PECO intends to invest up to $750M in its Smart Grid Infrastructure
–
$650M
for
Advanced
Metering
Infrastructure/Smart
Meter
investment
over
10
–
15
years
and
$100M
for Smart Grid over next 3 years
–
Requested $200M Federal Stimulus Grant on August 6, 2009
–
Amount and timing of spending will depend on Federal Stimulus Grant and RFPs with suppliers
•
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 rate
cases, with approximately half the costs in each.
•
Smart Meter rate increase starts at 0.5% in 2010 and peaks at a cumulative 2.5% in
2012; with awarded stimulus grant, increase begins at 1% and peaks at 2.1% in 2012.
$ Millions
2010
2011
2012
Total
Act 129 Smart Meter Initial Deployment (without Stimulus Grant)
37
$    
149
$  
30
$    
215
$  
With Federal Stimulus Grant Filing:
Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012)
37
$    
155
$  
99
$    
291
$  
Smart Grid Stimulus Case
45
      
52
      
10
      
107
    
Total Stimulus Case
82
      
207
    
109
    
398
    
Stimulus Grant Request
(41)
     
(103)
   
(53)
     
(197)
   
Total Expenditures net of Stimulus grant
41
$    
103
$  
56
$    
201
$  

12
Value Return Framework
Less
Equals
Maintenance Capital and Committed Dividends
Free Cash Flow before Dividends and CapEx
Strengthen Balance Sheet /
Increase Financial Flexibility
Invest in Growth
Available Cash and Balance Sheet Capacity
Return Value via
Share Repurchases,
Dividends
Monetize

13
Discretionary Pension Contribution
Investing in pension plan with $350M cash on hand is estimated to
create $1 billion of financial flexibility in 2011
(1) 
Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, which allows for a 24-month
average of plan assets reflecting
expected asset returns over the averaging period.
•
Taking advantage of federal relief provided by the Worker, Retiree and
Employer Recovery Act of 2008, election and contribution required by 9/15/09
to impact 2008 plan year
• 
Making $350 million discretionary 2008 pension contribution with smoothing
election
(1)
–
$1 billion reduction in forecasted contribution in 2011
–
Smoothing election reduces present value of estimated future contributions by ~$300M
compared to status quo, over the next 10 years
–
Lowers volatility in future contributions, as smoothing election uses 24-month average of
asset returns
•
Evaluated within our Value Return Framework:
–
Funded with $350 million cash on hand – from $700 million generated in excess of original
2009 plan
–
Increases future financial flexibility with excess cash “today”

14
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
growth opportunities and
advancements in clean technology
•
Build the premier, enduring
competitive generation company
+
Exelon’s Strategic Direction
Exelon remains focused on creating shareholder value

15
Appendix
15

16
Climate Change Legislation Status
Exelon’s advocacy efforts working to advance climate change legislation
•
Key Dates
–
June 26:  House passage of H.R. 2454, American Clean Energy and Security Act
–
September 28:  Deadline for Senate Committees to report out climate change
legislation –
but will slide due to postponement of bill introduction
–
December 7-18:  UN Climate Conference in Copenhagen
•
Exelon Advocacy
–
Grassroots:  Mobilizing our employees, retirees, and shareholders
–
Media:  Working with a diverse group of stakeholders on earned and paid media
opportunities in favor of climate legislation
–
Direct Lobbying:  Exelon executives are meeting with key Senators and staff
–
Coalitions:  Working with United States Climate Action Partnership (USCAP),
Edison Electric Institute and Clean Energy Group to advance climate legislation

17
•
Acquired 198 MW of wind farm output, 4.8 MW of landfill gas output and 4.5 MW of
solar output, bringing Exelon’s renewables portfolio to more than 2,000 MW
•
Unveiled plans to develop the nation’s largest urban solar power plant in Chicago
•
Completed a 38-MW nuclear uprate at Quad Cities Station, launching a series of
planned uprates that will generate 1,300-1,500 MW of additional nuclear capacity
Exelon 2020 –
Progress Update for 2009
Offer more low
carbon electricity in
the marketplace
Help our customers
and the communities
we serve reduce their
GHG emissions
Reduce or offset our
footprint by greening
our operations
Exelon’s strategy to reduce, offset or displace more than 15 million metric
tons of GHG emissions per year by 2020
•
Retired less efficient and higher-emitting fossil fuel power plants in Massachusetts,
Pennsylvania and Texas
•
Reduced energy use across Exelon’s facilities by 16%
•
Earned LEED certification for three Exelon buildings
•
Greened Exelon’s vehicle fleet to include 1,900 hybrid-electric and alternative-fuel
vehicles at ComEd and a 57% environmentally friendly fleet at PECO
•
Unveiled plans to spend more than $350 million through 2011 on energy efficiency and
demand
response
programs
to
reduce
customers’
energy
consumption
by
1.6
million
MWh and reduce peak load by 226 MW
•
Building
on
its
residential
real-time
pricing
program,
ComEd
introduced
a
“smart”
meter
pilot program that will provide advanced automated meters to up to 141,000 customers
•
PECO is investing $342 million in customer programs to reduce overall electricity
consumption by 3% and peak load by 4.5% by 2013
3
2
1

18
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 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

19
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 percent additional output
•
Requires NRC approval
187–234 MW
$300M
2 years
899–1016 MW
$2,400M
EPU (Extended Power Uprate)
•
Through a combination of more sophisticated analysis and upgrades
to plant equipment, uprates can be obtained for as much as 20
percent 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.

20
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.
Uprates 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. 

21
Uprates Across the Exelon Fleet
Base
Maximum
Station
Case
Potential
MW
MW
Braidwood - MUR
34
-
42
2012
Byron - MUR
34
-
42
2012
Clinton - EPU
17
-
17
2016
Clinton - EPU
2
-
3
2010
Dresden - MW Recovery & Component Upgrades
103
-
110
2012
Dresden - MW Recovery & Component Upgrades
5
-
5
2011
Dresden - MUR
25
-
31
2014
LaSalle - MUR
32
-
40
2011
LaSalle - EPU
303
-
336
2016
Limerick - MUR
33
-
41
2011
Limerick - MW Recovery & Component Upgrades
6
-
6
2012
Limerick - EPU
306
-
340
2017
Peach Bottom - MW Recovery & Component Upgrades
25
-
32
2012
Peach Bottom - EPU
134
-
148
2015
Peach Bottom - MW Recovery & Component Upgrades
3
-
3
2014
Quad Cities - MUR
19
-
23
2013
Quad Cities - MW Recovery & Component Upgrades
95
-
110
2011
TMI - EPU
138
-
172
2016
TMI - MUR
12
-
15
2014
Total
1,323
-
1,516
Year of
Operation
Uprates will largely be completed during scheduled refueling outages

22
PECO Procurement
With a successful residential procurement in June, PECO has made
progress toward
purchasing the power needed to serve customers beginning in 2011
On June 17, 2009, the PAPUC approved the bids from the Spring RFP held on June 15,
2009, which included 21% of PECO’s residential default service load for 2011 and a portion
of its load obligation for 2012 and 2013
Contracts were awarded to two bidders out of eleven total bidders
RFP for full requirements
(1)
resulted in average wholesale price of $88.61($/MWh)
Fall RFP bids due September 21, 2009
(1) Full requirements product includes load following energy, capacity, ancillary transmission services and Alternative Energy Portfolio Standard requirements.
(2) See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s procurement plan and RFP results.
Residential
23% of planned full requirements
contracts (17 and 29-mo. terms)
40MW of baseload (24x7) energy
block products (12-mo. duration)
Small Commercial
24% of planned full requirements
contracts (17-mo. term)
Medium Commercial & Industrial
16% of planned full requirements
contracts (17-mo. term)
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% energy block
5% energy only spot
Products
Small Commercial
(peak demand <100 kW)
Residential
Customer Class
Residential
26% of planned full requirements   
contracts
•
17 month (Jan 2011 -
May 2012)
•
29 month (Jan 2011 -
May 2013)
40MW of baseload (24x7) energy
block products
•
12 month (Jan 2011 -
Dec 2011)
PECO
Procurement
Plan
(2)
Fall 2009 RFP
Spring 2009 RFP

23
Potential Variability in Future Pension
Expense and Contributions
$159
$4,055
$305
$251
$4,058
$270
6.09% for 2009
5.92% for 2010
6.10% for 2011
8.5% in 2009-2011
B -
Asset returns at long-term rate
Unfunded balance –
end of year
$144
$3,687
$289
$207
$3,705
$260
6.09% for 2009
5.92% for 2010
6.10% for 2011
14.15% in 2009
8.5% in 2010
8.5% in 2011
A –
Current baseline
Unfunded balance –
end of year
$134
$2,802
$243
$182
$2,670
$196
6.09% for 2009
7.00% for 2010
7.00% for 2011
8.5% in
2009
15% in 2010
8.5% in 2011
C –
Accelerated equity recovery
Unfunded balance –
end of year
$723
$4,611
$327
$326
$5,111
$285
6.09% for 2009
5.92% for 2010
6.10% for 2011
0% in
2009
0% in 2010
8.5% in 2011
D -
Equity recovery in 2 years
Unfunded balance –
end of year
Required
contribution
(1)
Pre-tax
expense
Required
contribution
(1)
Pre-tax
expense
Discount Rate
Actual Asset
Returns
2011
2010
Assumptions
Illustrative Scenario
($ in millions)
Other
Postretirement
Benefits
(OPEB)
2010
Expense:
Exelon
estimates
pre-tax
2010
OPEB
expense
of
~$226
million,
$240
million,
$193
million,
and
$254
million
under
Scenarios
A-D,
respectively.
2010
Contributions:
Exelon
estimates
roughly
$150
million
of
contributions
to
its
OPEB
plans
in
2010,
which
is
subject
to
change,
with
an
additional
approximately
$6
million
paid
out
of corporate assets.
(1)
The contributions shown above include estimated pension contributions required under ERISA and the Pension Protection Act of 2006, as well as certain discretionary contributions
necessary to avoid benefit restrictions. Also included within these amounts are expected payments to Exelon’s non-qualified plans of approximately $18 million and $6 million in 2010
and 2011, respectively.  Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, as well
as a discretionary $350 million contribution allocated to the 2008 plan year.
Note: Slide provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes 20% overall capitalization rate of pension and OPEB costs.

24
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

25
25
25
Exelon Generation Hedging Disclosures
(As disclosed on July 24, 2009)

26
26
26
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

27
27
27
27
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 MW 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

28
28
28
28
2009
2010
2011
Estimated Open Gross Margin (millions)
(1,2)
$5,100
$6,000
$6,150
Open gross margin assumes all expected generation is
sold at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)    
ERCOT
North
ATC
Spark
Spread
($/MWh)
(3)
$4.26
$29.42
$40.30
($0.09)
$6.06
$33.38
$48.64
($2.17)
$6.89
$35.12
$52.21
($0.77)
(1)
Based on June 30, 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
RPMT
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 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

29
29
29
29
(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 2009 and 2010 and 11 refueling outages in 2011 at Exelon-operated nuclear plants and Salem.  Expected generation assumes
capacity factors of 93.6%, 92.8% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 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.
(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.
2009
2010
2011
Expected Generation
(GWh)
(1)
169,800
165,500
164,700
Midwest
99,600
97,700
97,700
Mid-Atlantic
57,500
58,500
58,100
South
12,700
9,300
8,900
Percentage
of
Expected
Generation
Hedged
(2)
95-98%
87-90%
59-62%
Midwest
96-99
87-90
63-66
Mid-Atlantic
95-98
91-94
56-59
South
90-93
68-71
34-37
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$47.00
$46.75
$45.00
Mid-Atlantic
$36.25
$34.50
$62.00
ERCOT North ATC Spark Spread
$5.25
$3.50
$4.75
Generation Profile

30
30
30
30
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%
2009
$8
$0
$6
($3)
$8
($2)
+/-$20
2010
$40
($30)
$55
($50)
$25
($20)
+/-$50
2011
$280
($240)
$205
($195)
$170
($165)
+/-$55
(1)
Based on June 30, 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)

31
31
31
31
95% case
5% case
$6,700
$6,500
$6,100
$6,700
$6,100
$8,400
Exelon Generation Gross Margin
Upside / Risk (with Existing Hedges)
$4,000
$5,000
$6,000
$7,000
$8,000
$9,000
$10,000
2009
2010
2011
(1)
Represents
an
approximate
range
of
expected
gross
margin,
taking
into
account
hedges
in
place,
between
the
5th
and
95th
percentile
confidence
levels.
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
2010
and
2011
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
June
30, 2009.

32
32
32
32
Midwest
Mid-Atlantic
ERCOT
Step 1
Start
with
fleetwide
open
gross
margin
$5.10 billion
Step 2
Determine the mark-to-market value
of energy hedges
99,600GWh * 97% *
($47.00/MWh-$29.42/MWh)
= $1.70 billion
57,500GWh * 96% *
($36.25/MWh-$40.30/MWh)
= ($0.22 billion)
12,700GWh * 91% *
($5.25/MWh-($0.09)/MWh)
= $0.06 billion
Step 3
Estimate hedged gross margin
by
adding open gross margin to mark-to-
market value of energy hedges
Open gross margin:                              $5.10 billion
MTM value of energy hedges:              $1.70 billion + ($0.22 billion) + $0.06 billion
Estimated hedged gross margin:          $6.64 billion
Illustrative Example of Modeling Exelon Generation
2009 Gross Margin
(with Existing Hedges)

33
33
33
50
60
70
80
90
100
110
120
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
20
25
30
35
40
45
50
55
60
65
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
35
45
55
65
75
85
95
105
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
5.5
6.5
7.5
8.5
9.5
10.5
11.5
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
33
Market Price Snapshot
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak Forward Prices
PJM-West and Ni-Hub Wrap Forward Prices
2010
2011
Rolling
12
months,
as
of
August
31,
2009.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
$5.57
$6.57
2010
2011
$51.20
$63.34
2010 Ni-Hub
2011 Ni-Hub
2011 PJM-West
2010 PJM-West
2010 Ni-Hub
2011 Ni-Hub
2011 PJM-West
2010 PJM-West
$53.18
$59.86
$39.56
$24.05
$39.38
$21.89
$43.85
$36.28

34
34
34
4.5
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
14.5
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
8
8.2
8.4
8.6
8.8
9
9.2
9.4
9.6
9.8
10
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
45
50
55
60
65
70
75
80
85
90
95
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
5
6
7
8
9
10
11
8/08
9/08
10/08
11/08
12/08
1/09
2/09
3/09
4/09
5/09
6/09
7/09
8/09
34
Market Price Snapshot
2011
2010
2010
2011
2010
2011
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North On-Peak Forward Prices
ERCOT North On-Peak v. Houston Ship Channel
Implied Heat Rate
2010
2011
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
$5.38
$6.36
$55.39
$47.02
$8.74
$8.70
$5.70
$6.98
Rolling
12
months,
as
of
August
31,
2009.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.