EX-99.3 4 dex993.htm SUPPLEMENTAL INFORMATION Supplemental Information
Supplemental Information
2007 Exelon Investor Conference
December 19, 2007
Exhibit 99.3

2

3
’07E Earnings:
$2,320 -
$2,385M 
’08E Earnings:
$2,060 -
$2,260M
’07 EPS:
$3.45 -
$3.55
‘08 EPS:
$3.15 -
$3.45
Total Debt
(1)
:
$1.8B
Credit Rating
(2)
:
BBB+
The Exelon Companies
Nuclear, Fossil, Hydro & Renewable Generation
Power Marketing
‘07E Operating Earnings:
$2.8 -
$2.9B
‘07 EPS Guidance:
$4.15 -
$4.30
‘08E Operating Earnings:
$2.6 -
$2.9B
‘08 EPS Guidance:
$4.00 -
$4.40
Assets
(1)
:                        
$44.3B
Total Debt
(1)
:
$13.0B
Credit Rating
(2)
:                            BBB
Note: All estimates represent adjusted (Non-GAAP) Operating Earnings and EPS. Exelon Generation, ComEd and PECO estimates represent expected contribution to  
Exelon’s operating earnings EPS (per Exelon share). Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(1)
As of 12/31/06.
(2)
Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 12/14/07.
Pennsylvania
Utility
Illinois
Utility
’07E Earnings:
$130 -
$165M
$435 -
$470M
’08E Earnings:
$220 -
$260M
$360 -
$400M
’07 EPS:
$0.20 -
$0.25
$0.65 -
$0.70
’08 EPS:
$0.35 -
$0.40
$0.55 -
$0.60
Total
Debt
(1)
:
$4.6B
$4.2B
Credit
Ratings
(2)
:
BBB
A

4
Multi-Regional, Diverse Company
Note: Megawatts based on Generation’s ownership as of
10/1/07, using annual mean ratings for nuclear units (excluding
Salem) and summer ratings for Salem and the fossil and hydro
units; capacity excludes New Boston Unit 1 and State Line PPA. 
Mid-Atlantic contracts include wind and cogeneration projects.
Midwest Capacity
Owned:
11,373 MW
Contracted:
4,271 MW
Total:
15,644 MW
ERCOT/South Capacity
Owned:
2,222 MW
Contracted:
2,917 MW
Total:
5,139 MW
New England Capacity
Owned:
181MW
Total Capacity
Owned:
24,746 MW
Contracted:
7,524 MW
Total:
32,270 MW
Electricity Customers:
1.6M
Gas Customers: 
0.5M
Electricity Customers:  3.8M
Generating Plants             
Nuclear
Hydro
Coal/Oil/Gas Base-load
Intermediate
Peaker
Mid-Atlantic Capacity
Owned:
10,970 MW
Contracted:
336 MW
Total:
11,306 MW

5
Illinois Settlement
•
Continued ComEd membership in PJM
•
Competitive procurement for supply
•
Filed competitive declaration for 100 -
400 kW customers
•
Statute mandates cost recovery for purchased power
•
Reduced uncertainty around conditions for ICC approval
for strategic transactions such as reorganizations or
mergers
•
Immediate rate relief for customers
•
Provisions to help stabilize rates
•
Energy efficiency and demand response programs and
renewable portfolio standards
Protects Competitive
Markets
Protects Value of
Generation
Provides Strategic
Flexibility
Customer Focused
•
Eliminated the IL Attorney General’s challenges to the
2006 auction
•
Financial swap at market prices
•
No generation tax

6
$4,450
$2,740
$920
$700
Cash Flow from Operations
(1)
($3,120)
($1,600)
($390)
($1,000)
Capital Expenditures
$1,220
$1,240
($50)
$300
Net Financing (excluding Dividend)
(2)
$2,550
$2,380
$480
$0
Cash available before Dividend
($1,310)
Dividend
(3)
$1,240
Cash available after Dividend
Exelon
(1)
($ in Millions)
2008 Projected Sources and Uses of Cash
(1)
Cash
Flow
from
Operations
=
Net
cash
flows
provided
by
operating
activities
less
net
cash
flows
used
in
investing
activities
other
than
capital
expenditures.
(2)
Net Financing (excluding Dividend) = Net cash flows used in financing activities excluding dividends paid on common and preferred stock.
(3)
Assumes 2008 Dividend of $2.00 per share.
(4)
Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

7
3-4%
$1,000
$1,060
2-3%
$1,020
$1,030
1-2%
$390
$350
2-3%
$650
$620
Exelon
(1)
NM
(2)
NM
(2)
~15%
2008-2012 CAGR
$3,120
$870
$730
2008E
$2,740
$720
$580
2007E
Other
Nuclear
Fuel
CapEx
2-3%
2-3%
2008-2012 CAGR
$4,250
$2,620
2008E
$4,090
$2,450
2007E
Exelon
(1)
O&M
Note:  Reflects operating O&M data and excludes Decommissioning Trust Fund impact.
(1)  Includes eliminations and other corporate entities.
(2)  Due to varying capital investment for the period 2008-2012, the CAGR is not meaningful.
($ in Millions)
O&M and CapEx Expectations
($ in Millions)

8
Industry Is Facing a Capital
Investment Challenge
Source: Cambridge Energy Research Associates
Current Industry Market Cap ($B)
~$750B
Generation for 230+ GWs
Transmission
Distribution
$50B Conservation & Energy Efficiency
$50B (excl. Carbon) Environmental Retrofits
CapEx Spend Next 15 Years ($B)
Investment required over the next 15 years exceeds the current
market capitalization of the entire electric industry
$300B
$350B
$150B
~$900B

9

10
10
ComEd Transmission Case Settlement
(1)
($ in millions)
FERC Filing
3/1/07
Preliminary Order
6/5/07
Settlement Filing
10/5/07
(1)
Total Revenue Requirement (in year 1)
(2)
$415
$387
$364
Revenue Requirement increase (in year 1)
$146
$116
(3)
$93
Rate Base (in year 1)
$1,826
$1,744
$1,672
(4)
Common Equity Ratio
58%
58%
58%
(5)
Return on Equity (ROE)
(6)
12.20%
11.70% + 0.50% RTO adder
12.20%
11.70% + 0.50% RTO adder
11.50%
11.0% + 0.50% RTO adder
Return on Rate Base (ROR)
9.87%
9.87%
9.40%
Rate settlement establishes reasonable framework for timely recovery of transmission
investment on an annual basis through formula rates
(1) Subject to final FERC approval.
(2) Included a request for project incentives of $16 million.
(3) Rates effective 5/1/07, subject to refund.
(4) Excludes pension asset; 6.51% debt return allowed in operating expenses.
(5) Equity cap of 58% for 2 years, declining to 55% by 2011.
(6) ROE is fixed and not subject to annual updating. 
RTO = Regional Transmission Organization
(Docket Nos. ER07-583-000 & EL07-41-000)

11
11
Formula Transmission Rate Annual
Update Process
(1)
•
Annual filing by May 15th will update the current year revenue
requirement and true-up prior year to actual:
–
Update current year
–
Estimate current year revenue requirement using updated costs based on prior year actual
data per FERC Form 1 plus projected plant additions for the current calendar year
–
True-up prior year
–
Perform a true-up of the prior year’s rates by comparing prior year actual data per FERC
Form 1 to the estimate used for that year; over/under-recoveries for the prior year are
collected in the current year
•
Rates take effect on June 1st
•
Interested parties have 180 days to submit information requests
and  raise concerns; unresolved concerns go before FERC for
resolution
The combination of annual updating and true-up virtually eliminates regulatory lag
(1) Subject to final FERC approval.

12
Revenue increase needed to recover significant distribution system investment and
represents an important step in ComEd’s regulatory recovery plan
(1) Based on 2006 test year, including pro forma capital additions through 3Q 2008; represents a $1,550 million increase from 2006 ICC order.
(2) Includes increased depreciation expense associated with capital additions.
(3) Requested cap structure does not include goodwill; ICC docket 05-0597 allowed 10.045% ROE, 42.86% equity ratio and 8.01% ROR (return on rate base).
(4) Primarily includes increases in pension and other post-retirement benefits costs and effects of a reclassification of rental revenue of $20 million, which is offset in “Other
adjustments”.
(5) Includes taxes other than income, regulatory expenses, and reductions for other revenues and load growth.
(6) Or approximately $359 million adjusted for normal weather.
ComEd Delivery Service Rate Case Filing
(Docket No. 07-566)
$361
(6)
Total ($2,049 revenue requirement)
$(51)
Other adjustments
(5)
$48
O&M expenses
$99
Administrative & General expenses
(4)
$50
Capital Structure
(3)
: ROE -
10.75% /
Common Equity -
45.11% / ROR -
8.55%
$215
(2)
Rate Base: $7,071
(1)
Requested Revenue
Requirement Increase
$ in millions)

13
ComEd Delivery Service Rate Case –
Schedule
•
Filed: October 17, 2007
•
Staff & Intervenor Direct Testimony: February 11, 2008
•
ComEd Rebuttal Testimony: March 12
•
Staff & Intervenor Rebuttal Testimony: April 8
•
ComEd Surrebuttal Testimony: April 21
•
Hearings: April 28 -
May 5
•
Initial Briefs: May 29
•
Reply Briefs: June 12
•
Administrative Law Judge (ALJ) Order expected: July
•
Final Illinois Commerce Commission (ICC) Order expected:
September 2008

14
Financial Swap Agreement
•
Financial Swap Agreement between ComEd and Exelon Generation
promotes price stability for residential and small business customers
•
Designed to dovetail with ComEd’s remaining auction contracts for energy,
increasing in volume as the auction contracts expire
–
Will cover about 60% of the energy that ComEd’s residential and small
business customers use
•
Includes ATC baseload
energy only
–
Does not include capacity, ancillary services or congestion
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

15

16
Pennsylvania Snapshot
•
Governor Rendell proposed an Energy
Independence Strategy (EIS) in February 2007
Aimed at reducing energy costs, increasing
clean energy sources, reducing reliance on
foreign fuels and expanding energy production
in PA 
Funded through a systems benefit charge
•
Special legislation session on Energy Policy
began
September
17
th
Runs through mid-December
Current State of Play
•
Legislators concerned with cost of funding
Governor's initiatives, no new taxes
•
Rate freeze and/or generation tax legislation being
considered
•
Industry coalition working together to develop a
comprehensive package
Position of Stakeholders
•
Stakeholder outreach
•
Working with industry coalition
•
Negotiating legislative proposals with
Administration and legislative leadership
Smart meters and real time pricing
Energy efficiency and demand side
management programs
Procurement
Contracts for large industrials
Utilities owning generation
Rate increase deferral/phase-in
•
Participating directly or through industry
associations in legislative hearings and
informational meetings
•
Evaluating alternative proposals
PECO Actions

17
Key Themes of Legislative Proposals
Competitive procurement process utilizing auctions, RFPs, spot purchases
and bilateral contracts
Full and current cost recovery for default service provider (DSP)
DSP must offer residential and small commercial customers a rate
that
changes no more frequently than annually with reconciliation for
under or
over-recovery
Must file a rate phase-in plan for all customers with the option to phase-in
rate increase if class average total rate increases by more than
15%
Phase-in plans are to be opt-in for customer, provide utility with full
recovery of carrying costs with return on deferred balance
Securitization of deferred balance and carrying charges authorized
Utility may propose an early phase-in plan
Energy efficiency goal of usage reduction of 2% by 2013
Peak demand reduction goal of 3% by 2012
Utilities may file for cost recovery
Procurement
Smart Meters
Rate Phase-in
Program
Demand Side
Response & Energy
Efficiency (DSR/EE)
Full deployment of smart meters within 6-10 years
Full recovery for net costs of smart meter deployment through base rates or
on full and current basis through automatic recovery mechanism
Must submit a time-of-use rate plan with voluntary customer participation by
the end of rate cap period

18
2.63
2.63
0.48
0.48
2.41
6.00
10.54
PECO Average Electric Rates
(1) System
Average
Rates
based
upon
Restructuring
Settlement
Rate
Caps
on
Energy
and
Capacity
increased
from
original
settlement
by
1.6%
to
reflect
the
roll-in
of
increased
Gross
Receipts
Tax
and
$0.02/kWh
for
Universal
Service
Fund
Charge
and
Nuclear
Decommissioning
Cost
Adjustment.
System
Average
Rates
also
adjusted
for
sales
mix
based
on
current
sales
forecast.
Assumes
continuation
of
current
Transmission
and
Distribution
Rates.
(2) Energy/Capacity
Price
is
an
average
of
the
results
for
residential
(10.51¢/kWh)
and
small
commercial
customers
(10.58¢/kWh)
from
the
second
round
of
PPL
Auction
held
10/07.
Assumes
continuation
of
current
Transmission
and
Distribution
Rates.
2011
2008 –
2010
Energy / Capacity
Competitive Transition
Charge (CTC)
Transmission
Distribution
11.52¢
(1)
Unit Rates (¢/kWh)
Electric Restructuring
Settlement
+18%
13.65¢
(2)
Post Transition
Post Transition
Projected Rate Increase
Based on PPL Auction
Results  (Illustrative)
CTC terminates at year-end 2010
Energy / Capacity price expected
to increase; price will reflect
associated full requirements
costs
Using latest PPL auction for
2010 as a proxy (10.5¢/kWh)
results in a system average
rate increase of ~18%
PECO’s 2011 full requirements
price expected to differ from PPL
due, in part, to the timing of the
procurement and locational
differences
Rates will vary by customer class
and will depend on legislation and
approved procurement model

19
PECO Average Annual Rate Base
2.6
2.8
2.9
3.0
3.1
3.3
2.7
2.0
1.3
1.1
1.1
1.1
1.1
1.2
1.2
0.6
0.6
0.6
0.6
0.5
0.5
0.5
2007E
2008E
2009E
2010E
2011E
2012E
Gas
CTC
Electric Transmission
Electric Distribution
6.9
6.4
5.9
5.2
4.9
5.1
($ in Billions)

20

21
Exelon Generation Operating Earnings
Exelon Generation is poised for significant earnings growth driven by improving market
fundamentals, the end of the Pennsylvania transition period, and
carbon legislation
2007E
(1)
2012
2008E
(1)
(1) 2007 and 2008 estimated contribution to Exelon operating earnings; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
$2,320M -
$2,385M
2009 –
2012 Earnings Drivers
End of PECO PPA (2011+)
Carbon (2012+)
Market conditions  
-
Heat rate
-
Capacity prices
-
New build costs
Nuclear uprates
Higher O&M costs
Higher nuclear fuel costs
Higher interest and
depreciation expense
2008 Earnings Drivers
Market conditions
-
Capacity prices
-
Marginal losses
More nuclear outages
Higher nuclear fuel costs
Higher O&M costs
State Line buyout
Higher interest and
depreciation expense
$2,060M -
$2,260M

22
Long-Run Marginal Cost of Electricity
IGCC –
No CO2
Recapture
Pulverized Coal
CCGT
Nuclear
Excluding energy efficiency, nuclear is the least expensive generation option
in a carbon-constrained environment
CCGT = Combined Cycle Gas Turbine; IGCC = Integrated Gasification Combined Cycle
0
20
40
60
80
100
120
140
0
5
10
15
20
25
30
35
40
45
50
CO2 Price ($/Metric Ton)

23
Hedging Targets
Flexibility in our targeted financial hedge ranges allows us to be opportunistic while
mitigating downside risk
(1) Percent
financially
hedged
is
our
estimate
of
the
gross
margin
that
is
not
at
risk
due
to
a
market
price
drop
and
assuming
normal
generation
operating
conditions.
The
formula
is:
gross
margin
at
the
5th
percentile
/
expected
gross
margin.
Power Team employs commodity hedging
strategies to optimize Exelon
Generation’s earnings:
•
Maintain length for opportunistic sales
•
Use cross commodity option strategies to
enhance hedge activities
•
Time hedging around view of market
fundamentals
•
Supplement portfolio with load following
products
•
Use physical and financial fuel products to
manage variability in fossil generation output
Target Ranges
50% -
70%
70% -
90%
90% -
98%
Above the
range*
Current Position
Upper end
of range
Midpoint of
range
Prompt Year
(2008)
Second Year
(2009)
Third Year
(2010)
Financial Hedging Range
(1)
* Due to ComEd financial swap

24
125
127
129
131
133
135
137
139
141
143
145
2004
2005
2006
2007
2008
2009
2010
2011
2012
7
8
9
10
11
12
13
Based on the refueling cycle, we
will conduct 12 refueling outages
in 2008, versus 9 in 2007, and
10 to 11 in a typical year
Note:  Net nuclear generation data based on ownership interest; includes Salem.
•
18 or 24 months
•
Duration: ~24 days
Nuclear Refueling Cycle
•
2008 is an exception:
–
Salem steam generator
replacement
–
3 more outages than 2007
•
~2,600 GWh less than 2007
•
$100-$110M negative after-tax impact
2008 Refueling Outage Impact
Refueling Outage Duration
Nuclear Output
0
5
10
15
20
25
30
35
40
45
2000
2001
2002
2003
2004
2005
2006
2007
Exelon (excludes Salem)
Industry
Actual
Target
Estimate
2007 Industry data
is spring only
Impact of Refueling Outages

25
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
2007
2008
2009
2010
2011
2012
Effectively Managing Nuclear Fuel Costs
Enrichment
38%
Fabrication
17%
Nuclear Waste
Fund
23%
Tax/Interest
2%
Conversion
3%
Uranium
17%
Components of Fuel Expense in 2007
0
200
400
600
800
1,000
1,200
1,400
2007
2008
2009
2010
2011
2012
Nuclear Fuel Expense (Amortization + Spent Fuel)
Nuclear Fuel Capex
Projected Total Nuclear Fuel Spend
Projected Exelon Average Uranium Cost vs. Market
Projected Exelon Uranium Demand
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2007
2008
2009
2010
2011
2012
Exelon Average Reload Price
Projected Market Price (Term)
Note: Excludes costs reimbursed under the settlement agreement with the DOE.
Market source: UxC
composite forecasts.
2007 –
2011:
100% hedged in volume
2012:
~40% hedged in volume
All charts exclude Salem, except Projected Total Nuclear Fuel Spend.

26
Market Price Sensitivities
~$80M
+/-
500 Btu/KWh ATC Heat Rate
~$10M
+/-
$1/mmBtu Gas Price
(Pre-Tax Impact)
2008 EBITDA Sensitivities
($80M)
($40M)
($20M)
($5M)
-
Expense (Pre-Tax Impact)
($335M)
($160M)
($100M)
($60M)
-
Capital Expenditures
2012
2011
2010
2009
2008
-
$50/lb
$40M
$15M
$10M
$5M
-
Expense (Pre-Tax Impact)
$280M
$85M
$30M
$20M
-
Capital Expenditures
2012
2011
2010
2009
2008
+ $50/lb
Uranium Sensitivity
(1)
(1) Excludes Salem.

27
Total Portfolio Characteristics
The value of our portfolio resides in our nuclear fleet
The value of our portfolio resides in our nuclear fleet
40,900
41,100
23,300
23,100
5,100
126,500
120,000
0
50,000
100,000
150,000
200,000
250,000
2007
2008
Actual Hedges & Open Position
ComEd Swap
IL Auction
PECO Load
189,300
190,700
Expected Total Supply (GWh)
Expected Total Supply (GWh)
Expected Total Sales (GWh)
140,600
138,100
31,600
33,800
18,500
17,400
0
50,000
100,000
150,000
200,000
250,000
2007
2008
Forward / Spot Purchases
Fossil & Hydro
Nuclear
189,300
190,700

28
Financial Swap Agreement
•
Market-based contract for ATC baseload
energy only
–
Does not include capacity, ancillary services or congestion
•
Preserves competitive markets
•
Fits with Exelon Generation’s hedging policy and strategy
•
Small portion of Exelon Generation’s supply
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

29
Reliability Pricing Model Auction
40.80
197.67
111.92
148.80
102.04
191.32
191.32
Rest of Market
Eastern MAAC
                                    MAAC + APS
2007/2008
2008/2009
2009/2010
0
1,500 MW
N/A
N/A
N/A
N/A
MAAC + APS
(7)
9,750 -
9,950 MW
(3)
9,500 MW
9,550 -
9,850 MW
(3)
9,500 MW
9,500 -
9,800 MW
(3)
9,500 MW
Eastern MAAC
4,750 -
4,950 MW
(6)
12,700 MW
6,600 -
6,800 MW
14,500 MW
(5)
6,600 -
6,800 MW
16,000 MW
(4)
Rest of Market
Obligation
Capacity
(2)
Obligation
Capacity
(2)
Obligation
Capacity
(2)
2009 / 2010
2008 / 2009
2007 / 2008
Exelon Generation Participation within PJM Reliability Pricing Model
(1)
PJM RPM Auction Results ($/MW-day)
(6) In 09/10, obligation is reduced due to roll-off of part of ComEd auction load obligation in May 2009.
(3)  EMAAC obligation consists of load from PECO and BGS commitments.
(7) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.
(5) 08/09 Capacity supply decreased due to roll-off of several purchase power agreements (PPAs).
(4) Removing State Line from the supply in October 2007 reduces this by 515 MW.
(2)  All
capacity
values
are
in
installed
capacity
terms
(summer
ratings).
(1)  All values are approximate and not inclusive of wholesale transactions.

30
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
0
5
10
15
20
25
30
35
40
45
0
5
10
15
20
25
30
Carbon Value
Climate change legislation is expected to drive substantial gross margin expansion
at Exelon Generation
Midwest
•
~90,000 GWhs in Midwest
nuclear portfolio
•
~55% of time coal on the margin
•
~40% of time gas on the margin
Mid-Atlantic
•
~50,000 GWhs in Mid-Atlantic
nuclear portfolio
•
~45% of time coal on the margin
•
~50% of time gas on the margin
Carbon Value
Assumes Open Position
(1)
Lieberman-Warner
Possible $20 to $40/tonne
EIA Carbon Case
(3)
2010: $31/tonne
Bingaman-Specter
(4)
2012: $12/tonne
Carbon Credit ($/Tonne)
(1) Carbon sensitivity excludes ComEd SWAP and upside of Kincaid/Elwood due to contract expiration in 2012.  Assumes below $45/tonne carbon cost, no carbon
reduction technology (e.g., sequestration) is economical.
(2) As of 12/11/07.
(3) The
EIA
Carbon
Stabilization
Case
(Case
4)
dated
March
2006,
EIA
report
number
SR/OIAF/2006-1.
(4)
Low
Carbon
Economy
Act
initial
“Technology
Accelerator
Payment”
(TAP)
price
in
2012.
Allowance
price
increases
at
5%
above
the
rate
of
inflation
thereafter.
Europe Carbon Trading
2012: $36.50/tonne
(2)

31
Potential Nuclear New Build
•
Intend to file Construction and Operating License (COL) for
plant in Texas by end of 2008
–
Preserves option to participate in Energy Policy Act incentives
•
Long-lead material for dual unit ESBWR has been reserved
•
Texas is attractive market for new nuclear
–
Growing demand for baseload power, robust market prices
–
State and local support for new nuclear
–
Existing Exelon presence in Texas
•
Exelon’s phased approach allows for go/no-go decisions at
major funding/commitment milestones
•
Exelon’s conditions for new build remain unchanged: the
economics must be right
Nuclear new build would capitalize on improving fundamentals, high gas prices,
and Exelon’s core strength in nuclear operations

32
Exelon Nuclear Fleet Overview
2011
42.6% Exelon, 56.4 %
PSEG
2016, 2020
969
(1)
W
PWR
2
Salem, NJ
Life of plant capacity
100% AmerGen
2014; renewal to be
filed 2008
837
B&W
PWR
1
TMI-1, PA
Dry cask
100% AmerGen
2009; renewal filed
2005
625
GE
BWR
1
Oyster Creek, NJ
Dry cask
50% Exelon, 50% PSEG
Renewed: 2033,
2034
1135
(1)
GE
BWR
2
Peach Bottom, PA
Dry cask
75% Exelon, 25% Mid-
American Holdings
Renewed: 2032
1303
(1)
GE
BWR
2
Quad Cities, IL
Dry cask
100%
Renewed: 2029,
2031
871, 871
GE
BWR
2
Dresden, IL
2012
100%
2022, 2023
1138, 1150
GE
BWR
2
LaSalle, IL
Dry cask in process
100%
2024, 2029
1151, 1151
GE
BWR
2
Limerick, PA
Re-rack completed
2011
2013
Spent Fuel Storage/
Date to lose full core
discharge capacity
GE
W
W
Vendor
BWR
PWR
PWR
Type
1
2
2
Units
100% AmerGen
2026
1048
Clinton, IL
100%
2024, 2026
1183, 1153
Byron, IL
100%
2026, 2027
1194, 1166
Braidwood, IL
Ownership
License Expiration /
Status
Net Annual
Mean Rating
MW
Plant, Location
Fleet also includes 4 shutdown units:  Peach Bottom 1, Dresden 1, Zion 1 & 2.
(1) Capacity based on ownership interest.

33
Energy Policy Act –
Nuclear Incentives
•
$18 per MWh, 8 year PTC for first
6,000 MWe of new capacity
•
Cap of $125M per 1,000 MWe of
capacity per year
•
Protects against a decrease in
market prices and revenues earned
•
Benefit will be allocated/ prorated
among those who:
–
File COL by year-end 2008
–
Begin construction (first safety-
related concrete) by 1/1/2014
–
Place unit into service by
1/1/2021
Production Tax Credit (PTC)
•
Results in ability to obtain non-
recourse project financing
•
Up to 80% of the project cost,
repayment within 30 years or
90% of the project life
•
Timing of application subject to
DOE solicitations
•
Loan guarantee volume
dependent upon congressional
appropriations action
•
Cost of credit subsidy is still
uncertain
Government Loan
Guarantee
•
“Insurance”
protecting against
regulatory and litigation-related
delays in commissioning a
completed plant
•
Eligible costs include principal
and interest on debt coverage and
the incremental cost of
replacement power
–
First two reactors each
receive 100% of covered
costs up to $500M
–
The next four reactors each
receive 50% of covered costs
incurred after six months of
delay, up to $250M
Regulatory Delay
“Backstop”
Energy Policy Act provides financial incentives and reduced risk
by way of
production tax credits and loan guarantees

34
Announced Nuclear Projects
22 projects totaling ~40,000 MWs have been announced
Letter of intent
Greenfield
western Idaho
TBD
TBD
Mid-American Nuclear
Announced intent
Greenfield
San Joaquin Valley  CA
EPR
1
Fresno Nuclear Energy
Announced intent
Greenfield
Bruneau
ID
EPR
1
Alternative Energy Hldings
Letter of intent
Operating
Turkey Pt   FL
TBD
TBD
FPL
Letter of intent
Operating
Susquehanna  PA
EPR
1
PPL
Letter of intent
Operating
Fermi  MI
TBD
1
DTE Energy
Letter of intent
Greenfield
Victoria
TX
ESBWR
2
Exelon
Letter of intent
Operating
Comanche Peak TX
APWR
2
TXU
Letter of intent
Operating
Callaway  MO
EPR
1
Unistar/Ameren
Letter of intent
Operating
Nine Mile Pt  NY
EPR
1
Unistar
COL submitted Sept 2007
Operating
South Texas Project  TX
ABWR
2
NRG Energy
Letter of intent
Greenfield
Amarillo  TX
EPR
2
Amarillo Power
COL Jan 2008
Operating
Harris  NC
AP1000
2
Progress
COL 2008
Operating
Vogtle
GA
AP1000
2
Southern
COL May 2008
Operating
River Bend  LA
ESBWR
1
Entergy
COL submitted December 2007
Characterized
Lee  SC
AP1000
2
Duke
COL July 2008
Greenfield
Levy Co.  FL
AP1000
2
Progress
Letter of intent
Operating
Summer  SC
AP1000
2
South Carolina E&G
ESP approved; COL February 2008
Operating
Grand Gulf  MS
ESBWR
1
Entergy/NuStart
COL submitted Oct 2007.  Reference plant for AP1000
Characterized
Bellefonte  AL
AP1000
2
TVA/NuStart
Reference plant for ESBWR COL application; submitted
November 2007; ESP approved
Operating
North Anna  VA
ESBWR
1
Dominion
Partial COL submitted; remainder expected in 2007
Operating
Calvert Cliffs  MD
EPR
1
Unistar
Status
Type of site
Site
Technology
Units
Applicant

35
Advanced Nuclear Designs –
U.S. Market
•Luminant
(formerly TXU)
Will apply for design
certification in 2008
1700 MW
Mitsubishi
APWR
(Advanced PWR)
•NRG
Evolutionary improvement
from current BWR.  Design
certification in 1997.  In
operation in Japan since 1996.
1350 MW
GE-Hitachi
ABWR
(Advanced BWR)
•UniStar
•PPL
•Ameren
•Alternate Energy Holdings
Design certification submitted
to NRC.  AREVA in UniStar
joint venture with Constellation
to deploy EPR in US.  Under
construction in Finland, France
1600 MW
AREVA
EPR 
(Evolutionary PWR)
•TVA/NuStart
•SCE&G
•Progress
•Duke
•Southern
PWR, passive safety features, 
Design certification received
December 2005
1150 MW
Westinghouse
AP1000  (Advanced
Passive 1000)
•Dominion
•Entergy/NuStart at Grand Gulf
•Entergy at River Bend
•Exelon
Passive safety features,
simplified from ABWR design. 
NRC design certification
expected 2010
1500 MW
GE-Hitachi
ESBWR (Economic
Simplified Boiling
Water Reactor)
Selected in US by:
Status
Capacity
Vendor
Reactor
Sources:  World Nuclear Association; Nuclear Fuel Cycle Monitor,
September 17, 2007.

36
0
1
2
3
4
5
6
7
8
9
10
Building a new nuclear plant is not a one-step process or
decision:  It is a sequence of 3 successive decisions
Years (estimates)
1
2
3
First Decision: File an application for a COL
Second Decision: Procure major long-lead
procurement components and commodities
Third Decision: Proceed
with construction
Source: Exelon estimates.
Roadmap to Nuclear Commercial
Operation

37
0
20
40
60
80
100
120
140
160
Uranium Price Volatility
Long-term equilibrium price expected to be $40-$60/lb
0
20
40
60
80
100
120
140
160
Seven-Month Uranium Price Trend
Long-term Uranium Price Trend
Spring 2003
McArthur River
flood
December 2003
GNSS/Tenex
termination;
ConverDyn
UF6 release
and shutdown
Early 2004
ERA / Ranger
water problems
Early 2006
First Cigar Lake flood;
Cyclone Monica halts 
ERA /  Ranger
operations for
approximately two
weeks
October 2006
Second Cigar
Lake flood
March 2007
ERA / Ranger flooding
(cyclone George)

38
Current Market Prices
1.
2004, 2005 and 2006 are actual settled prices.
2.
Real Time LMP (Locational Marginal Price).
3.
Next day over-the-counter market.
4.
Average NYMEX settled prices.
5.
2007 information is a combination of actual prices through 12/14/07 and market prices for the balance of the year.
6.
2008 and 2009 are forward market prices as of 12/14/07.
PRICES (as of December 14, 2007)
Units
2004
1
2005 1
2006 1
2007
5
2008
6
2009
6
PJM West Hub ATC
($/MWh)
42.35 2
60.92 ²
51.07
2
60.52
59.36
57.91
PJM NiHub
ATC
($/MWh)
30.15 2
46.39 ²
41.42 2
46.20
44.92
44.75
NEPOOL MASS Hub ATC
($/MWh)
52.13 2
76.65 ²
59.68 2
68.03
75.08
72.20
ERCOT North On-Peak
($/MWh)
49.53 3
76.90 ³
60.87
3
59.53
75.85
73.19
Henry Hub Natural Gas
($/MMBTU)
5.85
4
8.85
4
6.74
4
6.97
8.25
7.95
WTI Crude Oil
($/bbl)
41.48
4
56.62
4
66.38
4
69.72
90.50
87.48
PRB 8800
($/Ton)
5.97
8.06
13.04
9.67
12.03
12.18
NAPP 3.0
($/Ton)
60.25
52.42
43.87
47.54
57.62
55.08
ATC HEAT RATES (as of December 14, 2007)
PJM West Hub / Tetco
M3
(MMBTU/MWh)
6.40
6.30
6.98
7.77
7.04
6.31
PJM NiHub
/ Chicago City Gate
(MMBTU/MWh)
5.52
5.52
6.32
6.74
6.02
5.43
ERCOT North / Houston Ship Channel
(MMBTU/MWh)
7.53
8.21
8.28
8.97
9.19
9.46

39
8.84
9.04
9.24
9.44
9.64
9.84
10.04
10.24
10.44
10.64
10.84
1-07
2-07
3-07
4-07
5-07
6-07
7-07
8-07
9-07
10-07
11-07
12-07
39
7
7.2
7.4
7.6
7.8
8
8.2
8.4
8.6
8.8
1-07
2-07
3-07
4-07
5-07
6-07
7-07
8-07
9-07
10-07
11-07
12-07
55
60
65
70
75
80
85
90
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
7.4
7.6
7.8
8
8.2
8.4
8.6
8.8
9
9.2
9.4
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
Market Price Snapshot
As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak  Forward Prices
PJM-West On-Peak Implied Heat Rate
Ni-Hub On-Peak Implied Heat Rate
2008
2009
2009
2008
2008 PJM-West
2009 PJM-West
2009 Ni-Hub
2008 Ni-Hub
2008
2009

40
25
27
29
31
33
35
37
39
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
40
42
44
46
48
50
52
54
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
40
42
44
46
48
50
52
54
56
58
60
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
50
52
54
56
58
60
62
64
66
68
70
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
Market Price Snapshot
PJM-West ATC Forward Prices
2008
2009
PJM-West Wrap Forward Prices
2008
2009
NIHUB ATC Forward Prices
NIHUB Wrap Forward Prices
2009
2008
2009
2008
As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

41
47
49
51
53
55
57
59
61
63
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
7.7
7.8
7.9
8
8.1
8.2
8.3
8.4
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
56
58
60
62
64
66
68
70
72
74
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
7
7.5
8
8.5
9
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
Market Price Snapshot
2008
2009
2009
2008
2008
2009
2008
2009
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North ATC Forward Prices
ERCOT North ATC v. Houston Ship Channel
Implied Heat Rate
ERCOT North Wrap Forward Prices
As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

42
42
65
67
69
71
73
75
77
79
81
83
85
1/07
2/07
3/07
4/07
5/07
6/07
7/07
8/07
9/07
10/07
11/07
12/07
Market Price Snapshot
ERCOT North On-Peak Forward Prices
2008
2009
As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily.

43
Exelon –
Climate Change

44
Advancing Exelon’s Low-Carbon Strategy
•
Lobbying in favor of climate change legislation that is
national, mandatory
and economy-wide
•
Taking voluntary action to reduce our greenhouse gas
(GHG) emissions 8% from 2001 levels by 2008
•
Continuing to invest in our low-carbon generation portfolio
•
Developing a comprehensive low-carbon energy strategy
–
Expanding our low-carbon resources
–
Providing customers with green products and services
–
Being a model of green operations

45
Recognized Environmental Leadership
•
Named to the 2006/2007 and 2007/2008
Dow
Jones Sustainability North America Index
•
Named to Climate Disclosure Leadership Index of the Carbon
Disclosure Project in 2005, 2006 and 2007
•
Signatory to the Global Roundtable on Climate Change and the
Ceres/Investor Network on Climate Risk statements
•
Member of the United States Climate Action Partnership (USCAP)
•
Corporate headquarters awarded Leadership in Energy and
Environmental
Design
(LEED
®
)
Platinum
Commercial
Interiors
certification by the U.S. Green Building Council

46
Exelon’s Climate Actions
•
Achieved SF6 leak rate of under 10% for 2006
•
Provides customer-based energy-efficiency
programs (compact fluorescent light bulbs, demand
response programs) –
ramping up to one of the
country’s leading programs in four years
•
ComEd is the largest private user of biodiesel in
Illinois thereby helping to create a healthy
biodiesel market
•
First utility in PA to file to meet Tier 1
requirements under Alternative Energy Portfolio
Standards (AEPS)
•
Achieved SF6 leak rate of under 10% for 2006
•
Supporting implementation of smart meters
system-wide and time-of-use programs
•
Nation’s largest low-carbon generation fleet
•
Retired older, inefficient plant
•
Invested in landfill gas power generation
expansion
Committed to going beyond world-class nuclear performance and compliance with
regulations, Exelon is taking voluntary action to address climate change
•
Largest marketer of wind power east of the
Mississippi River
•
Signed 20-year deal to purchase output from
largest solar photovoltaic installation in PJM
region

47
Exelon and Federal Climate
Change Legislation
•
Actively involved in the climate debate in Washington, D.C.
•
Lobbying in favor of enacting legislation that is national, mandatory
and economy-wide
•
Favors a cap-and-trade system over a carbon tax
•
Believes that any allocation scheme should include allowances for
distribution
companies
to
help
offset
the
cost
of
carbon
for
the
end-
user
•
To limit near-term economic impacts, supports a cost containment
mechanism, such as a safety valve, that supports a market price for
carbon that increases over time

48
Reduction Goals
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
1990
1995
2000
2005
2010
2015
2020
2025
2030
2035
2040
2045
2050
Historical U.S. emissions (EPA, 1990-2005)
Business-as-usual projection (AEO2007)
Sanders-Boxer / Waxman
Kerry-Snowe
McCain-Lieberman
Bingaman-Specter assuming "safety valve" not hit
Lieberman-Warner draft principles
Olver-Gilchrest
Comparison of Economy-wide Cap-and-Trade Emissions Targets
Includes Legislation Introduced in the 110th Congress as of September 2007
Bingaman-Specter assumes multiple low-carbon
policies, including:
•Car & light truck fuel economy of 41 mpg by 2027
•Federal RPS of 15% by 2020
•Optimistic assumptions about new technologies
coming online
Under these policies, the safety valve is not triggered.
Without these policies the safety valve is expected to
be reached in the early years and the target will be
exceeded. The program ends in 2030 unless the
President sets additional long-term targets.

49
0
500
1000
1500
2000
2500
3000
3500
1990
1995
2000
2005
2010
2015
2020
2025
2030
Advanced Coal Generation
Distributed Energy Resources
Plug-In Hybrid Electric Vehicles
Carbon Capture & Storage
Nuclear Generation
Renewables
Efficiency
Technology
Source:  Electric Power Research Institute
To stabilize emissions at 1990 levels, multiple technologies and
intensive R&D
will be required
CO2 Reductions Demand Multiple Generation
Technologies
EIA Base Case 2007
•
The technical potential exists
for the U.S. electricity sector
to significantly reduce CO2
emissions over the coming
decades
•
No one technology will be a
silver bullet –
a portfolio of
technologies will be needed
•
Much of the needed
technology is not available
yet –
substantial R&D,
demonstration, and
deployment are required

50
Key Climate Bills
•
Several bills and white papers and drafts are gaining support in
Washington:
–
Bingaman-Specter (S. 1766, the Low Carbon Economy Act of 2007)
•
Economy-wide: All major GHG producing sectors
–
Point of regulation: Oil and natural gas refineries and coal-fired generators
•
Increasing auction of allowances
–
Allowance allocations include: 9% to states, 53% to industry declining 2% per year starting in 2017, 5%
set aside for agricultural
–
Safety Valve: Price of allowances capped at $12/tonne of CO2 (“technology accelerator payment”)
starting in 2012 and increasing 5% per year above inflation rate
–
Lieberman-Warner (S. 2191, America’s Climate Security Act of 2007)
•
Approved by U.S. Senate Environment and Public Works Committee
•
Slated for action by the full U.S. Senate in the Spring
•
Needs 60 votes to break expected filibuster and pass
•
Economy-wide:  All major GHG producing sectors
–
Seeks to reduce GHG to the 2005 level by 2012; phases to 70% below the 2005 level by 2050
–
Points of regulation: Electric power sector –
large coal generators; Natural gas –
natural gas processors
and importers; Industrial sector –
large facilities emitting more than 10,000 tonnes per year
–
“Free”
allowances include: 10% to states, 19% to generators (phase out
in 2031); 10% to industry; 9% to
electric distribution companies, to benefit their customers; 2% to gas distribution companies, to benefit
their customers
–
Creates a Carbon Market Efficiency Board (“Carbon Fed”) with limited authority to oversee market
–
Dingell-Boucher White Paper
•
Seeks to reduce emissions by 60% to 80% by 2050
•
Best achieved by a cap-and-trade system

51
GAAP Reconciliation

52
Reconciliation of Net Income to EBITDA
GAAP net income (loss)
+/-
Impact of certain non-operating items
Adjusted non-GAAP net income (loss)
+/-
Cumulative effect of changes in accounting principle
+/-
Discontinued operations
+/-
Minority interest
+   Income taxes
Adjusted non-GAAP income (loss) from continuing operations
before income taxes and minority interest
+  Interest expense
+  Interest expense to affiliates
-
Interest income from affiliates
+  Depreciation and amortization
Adjusted non-GAAP earnings before interest, taxes,
depreciation and amortization (adjusted non-GAAP EBITDA)

53
GAAP EPS Reconciliation 2000-2002
2000 GAAP Reported EPS
$1.44
Change in common shares
(0.53)
Extraordinary items
(0.04)
Cumulative effect of accounting change
--
Unicom pre-merger results
0.79
Merger-related costs
0.34
Pro forma merger accounting adjustments
(0.07)
2000 Adjusted (non-GAAP) Operating EPS
$1.93
2001 GAAP Reported EPS
$2.21
Cumulative effect of adopting SFAS No. 133
(0.02)
Employee severance costs
0.05
Litigation reserves
0.01
Net loss on investments
0.01
CTC prepayment
(0.01)
Wholesale rate settlement
(0.01)
Settlement of transition bond swap
--
2001 Adjusted (non-GAAP) Operating EPS
$2.24
2002 GAAP Reported EPS
$2.22
Cumulative effect of adopting SFAS No. 141 and No. 142
0.35
Gain on sale of investment in AT&T Wireless
(0.18)
Employee severance costs
0.02
2002 Adjusted (non-GAAP) Operating EPS
$2.41

54
2004 GAAP Reported EPS
$2.78
Charges associated with debt repurchases
0.12
Investments in synthetic fuel-producing facilities
(0.10)
Employee severance costs
0.07
Cumulative effect of adopting FIN 46-R
(0.05)
Settlement associated with the storage of spent nuclear fuel
(0.04)
Boston Generating 2004 impact
(0.03)
Charges associated with investment in Sithe Energies, Inc.
0.02
Charges related to the now terminated merger with PSEG
0.01
2004 Adjusted (non-GAAP) Operating EPS
$2.78
2003 GAAP Reported EPS
$1.38
Boston Generating impairment
0.87
Charges associated with investment in Sithe Energies, Inc.
0.27
Employee severance costs
0.24
Cumulative effect of adopting SFAS No. 143
(0.17)
Property tax accrual reductions
(0.07)
Enterprises’
Services goodwill impairment
0.03
Enterprises’
impairments due to anticipated sale
0.03
March 3 ComEd Settlement Agreement
0.03
2003 Adjusted (non-GAAP) Operating EPS
$2.61
GAAP EPS Reconciliation 2003-2005
2005 GAAP Reported EPS
$1.36
Investments in synthetic fuel-producing facilities
(0.10)
Charges related to the now terminated merger with PSEG
0.03
Impairment of ComEd’s goodwill
1.78
2005 financial impact of Generation’s investment in Sithe
(0.03)
Cumulative effect of adopting FIN 47
2005 Adjusted (non-GAAP) Operating EPS
0.06
$3.10

55
GAAP Earnings Reconciliation
Year Ended December 31, 2006
776
-
-
776
-
Impairment of ComEd’s goodwill
(52)
-
-
(52)
-
Recovery of debt costs at ComEd
(89)
-
-
-
(89)
Nuclear decommissioning obligation reduction
(95)
-
-
(95)
-
Recovery of severance costs at ComEd
$(83)
-
1
36
24
-
$(144)
Other
$2,175
1
18
58
24
(58)
$1,592
Exelon
$455
-
4
10
-
-
$441
PECO
$528
-
4
4
-
3
$(112)
ComEd
ExGen
(in millions)
9
Severance charges
8
Charges related to now terminated merger with PSEG
$1,275
2006 Adjusted (non-GAAP) Operating Earnings (Loss)
1
Impairment of Generation’s investments in TEG and TEP
-
Investments in synthetic fuel-producing facilities
(61)
Mark-to-market adjustments from economic hedging activities
$1,407
2006 GAAP Reported Earnings (Loss)
Note: Amounts may not add due to rounding.

56
GAAP EPS Reconciliation
Year Ended December 31, 2006
$3.22
(0.11)
0.67
$0.78
$1.88
2006 Adjusted (non-GAAP) Operating EPS
$2.35
(0.21)
0.65
(0.17)
$2.08
2006 GAAP Reported EPS
-
-
-
-
-
0.05
0.04
-
Other
(1)
(0.14)
1.15
(0.08)
-
0.01
0.01
-
-
ComEd
(1)
-
-
-
(0.13)
0.01
0.01
-
(0.09)
ExGen
(1)
-
-
-
-
0.01
0.01
-
-
PECO
(1)
Exelon
1.15
Impairment of ComEd’s goodwill
(0.08)
Recovery of debt costs at ComEd
0.03
Severance charges
(0.13)
Nuclear decommissioning obligation reduction
(0.14)
Recovery of severance costs at ComEd
0.09
Charges related to now terminated merger with PSEG
0.04
Investments in synthetic fuel-producing facilities
(0.09)
Mark-to-market adjustments from economic hedging activities
Note: Amounts may not add due to rounding.
(1) Amounts shown per Exelon share and represent contributions to Exelon's EPS.

57
GAAP EPS Reconciliation
Nine Months Ended September 30, 2006
$2.50
Q3 2006 YTD Adjusted (non-GAAP) Operating EPS
(0.08)
Recovery of debt costs at ComEd
1.15
Impairment of ComEd's goodwill
0.02
Severance charges
(0.13)
Nuclear decommissioning obligation reduction
0.09
Charges related to now terminated merger with PSEG
0.08
Investments in synthetic fuel-producing facilities
(0.11)
Mark-to-market adjustments from economic hedging activities
$1.48
Q3 2006 YTD GAAP Reported EPS

58
GAAP EPS Reconciliation
Nine Months Ended September 30, 2007
$3.31
Q3 2007 YTD Adjusted (non-GAAP) Operating EPS
(0.01)
Sale of Generation's investments in TEG and TEP
0.14
2007 Illinois electric rate settlement
(0.01)
Settlement of a tax matter at Generation related to Sithe
(0.03)
Nuclear decommissioning obligation reduction
(0.10)
Investments in synthetic fuel-producing facilities
0.12
Mark-to-market adjustments from economic hedging activities
$3.20
Q3 2007 YTD GAAP Reported EPS

59
2007/2008 Earnings Outlook
•
Exelon’s outlook for 2007/2008 adjusted (non-GAAP)
operating earnings excludes the earnings impacts of the
following:
–
mark-to-market adjustments from economic hedging activities
–
significant impairments of intangible assets, including goodwill
–
significant changes in decommissioning obligation estimates
–
investments in synthetic fuel-producing facilities (2007 only)
–
costs associated with the Illinois electric rate settlement, including ComEd’s
previously announced customer rate relief programs
–
gains or losses on the State Line Energy, L.L.C. and Tenaska Georgia
Partners, LP transactions (2007 only)
–
other unusual items which the Company is unable to forecast
–
significant future changes to GAAP
•
Both our operating earnings and GAAP earnings guidance
are based on the assumption of normal weather

60
Exelon Investor Relations Contacts
Inquiries concerning this presentation
should be directed to:
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:
Felicia McGowan, Executive Admin
Coordinator
312-394-4069
Felicia.McGowan@ExelonCorp.com
Investor Relations Contacts:
Chaka Patterson, Vice President
312-394-7234
Chaka.Patterson@ExelonCorp.com
Karie Anderson, Director
312-394-4255
Karie.Anderson@ExelonCorp.com
Marybeth Flater, Manager
312-394-8354
Marybeth.Flater@ExelonCorp.com
Len Epelbaum, Principal Analyst
312-394-7356
Len.Epelbaum@ExelonCorp.com