EXELON GENERATION CO LLC - FORM 8-K - EX-99.2 - EARNINGS CONFERENCE CALL PRESENTATION SLIDES - July 22, 2010

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Earnings Conference Call
2
nd
Quarter 2010
July 22, 2010
Exhibit 99.2

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
Second
Quarter
2010
Quarterly
Report
on
Form
10-Q
(to
be
filed
on
July
22,
2010)
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.
This
presentation
includes
references
to
adjusted
(non-GAAP)
operating
earnings
and
non-GAAP
cash
flows
that
exclude
the
impact
of
certain
factors.
We
believe
that
these
adjusted
operating
earnings
and
cash
flows
are
representative
of
the
underlying
operational
results
of
the
Companies.
Please
refer
to
the
appendix
to
this
presentation
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
earnings
to
GAAP
earnings.
Please
refer
to
the
footnotes
of
the
following
slides
for
a
reconciliation of non-
GAAP
cash
flows
to
GAAP
cash
flows.

3
2017/
2018
2016/
2017
2015/
2016
2014/
2015
PJM RPM Auctions
Delivery Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
Hazardous Air
Pollutants
(HAP)
Criteria
Pollutants
Greenhouse
Gases
Coal
Combustion
By-Products
Compliance with Federal GHG Reporting Rule
Pre-Compliance Period
PSD/BACT and Title V Applies to GHG Emissions from New and Modified Sources
Develop GHG Cap and Trade
Legislation or EPA GHG
Regulations Under CAA
2015: Compliance with GHG
Cap and Trade Legislation or
EPA GHG Regs Under CAA
November 2014: Compliance with MACT
HAP ICR
Pre-Compliance Period
Develop Coal
and Oil MACT
Interim CAIR
Program
Develop Clean Air
Transport Rule
(CATR)
2012: Compliance with CATR (to replace CAIR)
SIP
provisions
developed
in
response
to
revised
NAAQS
(e.g.,
Ozone,
PM
2.5
,
SO2,
NO2)
Compliance
with
CATR
2
Develop Revised NAAQS
and CATR 2
Pre-Compliance Period
2015: Compliance with Federal CCB
Regulations
Develop Coal
Combustion By-
Products Rule
EPA Regulations Will Begin to Affect
Upcoming PJM RPM Auctions
Notes:
Reliability
Pricing
Model
(RPM)
auctions
take
place
annually
in
May.
For
definition
of
the
EPA
regulations
referred
to
on
this
slide,
please
see
the
EPA’s
Terms
of
Environment
(http://www.epa.gov/OCEPAterms/).

4
Signs of Power Market Recovery
Forward natural gas prices remain stable
•
In-line with our fundamental view
Heat rates in the spot market are improving
•
We
believe
forward
heat
rate
expansion
is
not
fully
reflected
in
the
market,
particularly
Ni-Hub
Positive results from recent PJM RPM capacity auction
•
Half of our capacity is in premium eastern zones
Exelon has the largest upside to a recovery of any of our merchant peers

5
Nuclear
Uprates
1,300–1,500 MW of new Exelon nuclear capacity by 2017, the
equivalent of a new nuclear plant at roughly half the cost of a
new plant and no incremental operating costs
Leveraging transmission expertise through utility companies,
Exelon Transmission Company and Exelon Generation
Executing regulatory recovery plans at ComEd and PECO with
three active distribution rate cases
Industry-leading energy efficiency and smart grid investments
over the coming years with a regulated return
Organic Growth Opportunities
Transmission
Rate Cases
Smart Grid

6
Key Financial Messages
Operating results for 2Q10
•
Operating earnings of $0.99/share
(1)
•
94.8% nuclear capacity factor
•
Continuing to manage O&M costs
Forward power price outlook improving
•
Upside in off-peak prices due to increased load
•
Continued signs of economic recovery in our service areas
Pursuing three rate cases at PECO and ComEd
•
ComEd filed electric distribution rate case on June 30, 2010
•
PECO electric and gas distribution rate cases on schedule
(1)
Refer
to
Earnings
Release
Attachments
for
additional
details
and
to
the
Appendix
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
to
GAAP
EPS.
Raising 2010 operating earnings guidance to $3.80 -
$4.10/share
(1)

7
Operating EPS
(1)
Refer
to
Earnings
Release
Attachments
for
additional
details
and
to
the
Appendix
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
to
GAAP
EPS.
Strong
performance
at
the
utilities
offset
by
lower
ExGen
margins
driving
quarter
over
quarter
earnings
lower;
however,
2Q10
earnings
exceeded
guidance
of
$0.80-$0.90/share
$0.82
$0.11
$0.69
$0.15
$0.13
$0.18
2009
2010
$1.74
$0.28
$1.35
$0.31
$0.37
$0.31
2009
2010
HoldCo/Other
ExGen
PECO
ComEd
2
nd
Quarter (2Q)
(1)
$0.99
$0.67
GAAP EPS
Year-to-Date (YTD)
(1)
$1.99
$2.24
$2.07
$1.80
$0.99
$1.03

8
Exelon Generation
Operating EPS Contribution
2010
2009
Key Drivers –
2Q10 vs. 2Q09
(1)
Lower energy prices under the PECO
PPA: $(0.04), including CTC offset at
PECO $(0.05) and other pricing of $0.01
Unfavorable market/portfolio conditions:
$(0.05)
Higher nuclear fuel costs: $(0.03)
Favorable RPM capacity pricing: $0.03
Higher O&M costs primarily driven by
inflation: $(0.02)
(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2) Outage days exclude Salem. 
44
57
Refueling
15
21
Non-refueling
2Q10
2Q09
Outage Days
(2)
2Q
YTD
$0.82
$1.74
$0.69
$1.35
Note: PPA = Power Purchase Agreement

9
Key Drivers –
2Q10 vs. 2Q09
(1)
IL distribution tax: $0.02
Weather: $0.02
Load growth:
$0.01
Increased storm costs: $(0.01)
ComEd Operating EPS Contribution
(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
2010
2009
2Q
YTD
$0.13
$0.31
2Q10
Actual
Normal
% Change
Heating Degree-Days      519            766            (32)%
Cooling Degree-Days      312            224              39%
$0.18
$0.37

10
PECO Operating EPS Contribution
Key Drivers –
2Q10 vs. 2Q09
(1)
Increased CTC revenue resulting
in lower energy prices paid to
Generation under the PPA, offset
at Generation: $0.05
Weather: $0.03
Increased storm costs: $(0.01)
CTC amortization $(0.04)
2010
2009
(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
2Q
YTD
$0.11
$0.28
2Q10
$0.15
$0.31
Actual
Normal
% Change
Heating Degree-Days    299
458           (35)%
Cooling Degree-Days    586
332            77%

11
PECO Load Trends
Philadelphia
Unemployment rate
(1)
9.2%               
2010 annualized growth in
gross domestic/metro product
(2)
0.8%            
Note: C&I = Commercial & Industrial
2009
(3)
2Q10      2010E
Average Customer Growth
(0.2)%  
0.2%    
0.0%
Average Use-Per-Customer
(2.1)%
(2.5)%
0.3%
Total Residential
(2.3)%   
(2.3)%      0.2%
Small C&I
(2.7)%
(5.1)%     (1.8)%
Large C&I
(3.0)%  
2.6%       0.9%
All Customer Classes
(2.6)%   
(0.7)%      0.1%
(1)  Source: U.S Dept. of Labor Preliminary data (June 2010)
(2)
Source: PECO estimate
(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
2Q10
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
Weather-Normalized
Load
Year-over-Year
(3)
Key Economic Indicators
Weather-Normalized Load

12
-10.0%
-7.5%
-5.0%
-2.5%
0.0%
2.5%
5.0%
7.5%
10.0%
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
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
Note: C&I = Commercial & Industrial
Chicago
Unemployment rate
(1)
10.2%
2010 annualized growth in
gross domestic/metro product
(2)
2.9%
4/10 Home price index
(3)
(1.5)%
(1)  Source: Illinois Dept. of Employment Security (June 2010)
(2)
Source: Global Insight (June 2010)
(3)
Source: S&P Case-Shiller Index
(4)
Not adjusted for leap year effect
2009
(4)
2Q10      2010E
Average Customer Growth
(0.4)%  
0.2%      0.2%
Average Use-Per-Customer
(1.0)%
1.4%
0.5%
Total Residential
(1.4)%   
1.6%       0.7%
Small C&I
(2.2)%
(0.1)%     (0.6)%
Large C&I
(6.7)%  
4.3%       2.5%
All Customer Classes
(3.3)%   
1.8%       0.8%
Weather-Normalized
Load
Year-over-Year
(4)
Key Economic Indicators
Weather-Normalized Load

13
Off-Peak Energy Price Improvement
Both Powder River Basin and Northern Appalachian coal prices have
remained relatively stable over the past quarter
However, NiHub and PJMW Hub off-peak energy prices have increased over
the same period
13
Stabilizing coal prices and recovery in load are providing upside to
prices, particularly in the off-peak
NiHubOff-Peak and Powder River Basin (PRB) Coal
23.00
24.00
25.00
26.00
27.00
28.00
10.50
11.50
12.50
13.50
14.50
15.50
2011 NiHub
2012 NiHub
2011 PRB
2012 PRB
PJMW Hub Off-Peak and Northern Appalachian (NAPP) Coal
35.00
36.00
37.00
38.00
39.00
40.00
41.00
64.00
66.00
68.00
70.00
72.00
74.00
76.00
2011 PJMW
2012 PJMW
2011 NAPP
2012 NAPP

14
74.75
134.46
174.29
110.00
143.90
0
500
1,000
1,500
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
0
100
200
300
PJM RPM Capacity Auction
Note:
Data
contained
on
this
slide
is
rounded.
(1)
Weighted
average
$/MW-Day
would
apply
if
all
generation
cleared
in
the
highlighted
zone.
(2)
All
generation
values
are
approximate
and
not
inclusive
of
wholesale
transactions;
All
capacity
values
are
in
installed
capacity
terms
(summer
ratings)
located
in
the
areas.
(3)
Elwood
contract
expires
on
12/31/12
and
Kincaid
contract
expires
on
2/28/13.
(4)
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.
7%
42%
51%
RTO
EMACC
MACC
8,700 MW
1,500 MW
10,300 MW
(4)
~$400M
Increase
2013/14
RPM
capacity
prices
result
in
a
$400
million
revenue
increase
to
Exelon
over
the
prior
auction;
expect
2014/15
auction
to
result
in
blended
prices
at
least
as
high
(3)
Left axis
PJM RPM Capacity Prices and Auction ($MW-day)
Capacity by Region Eligible for 2014/15
RPM Base Residual Auction
(2)

15
2010 Projected Sources and Uses of Cash
($ millions)
Exelon
(9)
Beginning Cash Balance
(1)
$1,050
Cash Flow from Operations
(1)(2)
1,100
1,025
2,400
4,575
CapEx (excluding Nuclear Fuel, Nuclear
Uprates and Solar Project, Utility Growth
CapEx)
(700)
(400)
(800)
(1,950)
Nuclear Fuel
n/a
n/a
(850)
(850)
Dividend
(3)
(1,400)
Nuclear Uprates and Solar Project
n/a
n/a
(325)
(325)
Utility Growth CapEx
(4)
(225)
(100)
n/a
(325)
Net Financing (excluding Dividend):
Planned Debt Issuances
(5)(6)
500
--
250
750
Planned Debt Retirements
(7)
(225)
(400)
--
(1,025)
Other
(8)
(50)
125
--
0
Ending Cash Balance
(1)
$500
(1)
Excludes counterparty collateral activity. 
(2)
Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures. 
Cash Flow from Operations for PECO and Exelon includes $550 million for competitive transition charges.  
(3)
Assumes 2010 dividend of $2.10/share.  Dividends are subject to declaration by the Board of Directors.
(4)
Represents new business and smart grid/smart meter investment.
(5)
Excludes Exelon Generation’s $212 million and ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit.  Excludes PECO’s $225 million Accounts
Receivable (A/R) Agreement with Bank of Tokyo.  Assumes PECO’s A/R Agreement is extended in accordance with its terms beyond September 16, 2010. 
(6)
Exelon Generation’s financing includes $250 million of debt to refinance a portion of Exelon Corp’s $400 million maturity.
(7)
Excludes Exelon Generation’s and ComEd’s tax-exempt bonds.  PECO’s planned debt retirement of $400 million represents the final retirement of the PECO Energy
Transition Trust.
(8)
“Other” includes PECO Parent Receivable, proceeds from options and expected changes in short-term debt.
(9)
Includes cash flow activity from Holding Company, eliminations, and other corporate entities. 

16
2010 Operating Earnings Guidance
2010 Revised
Guidance
2010 Prior
Guidance
$0.40 -
$0.50
$2.70 -
$2.90
$3.70 -
$4.00
(1)
ComEd
PECO
Exelon
Generation
ComEd
PECO
Exelon
Generation
Holdco
Holdco
Exelon
$0.60 -
$0.70
Exelon
$3.80 -
$4.10
(1)
$0.60 -
$0.70
$0.45 -
$0.55
$2.80 -
$2.95
(1)
Refer
to
Earnings
Release
Attachments
for
additional
details
and
to
the
Appendix
for
a
reconciliation
of
adjusted
(non-GAAP)
operating
EPS
to
GAAP
EPS.
Key Drivers of Guidance Revision
+
Favorable 2Q performance,
including ExGen revenue net fuel
+
Favorable weather YTD
+
Reaffirmed outlook for remainder of
the year
Revised 2010 operating earnings guidance to $3.80-$4.10/share –
expect 3Q10 results of $1.00 -
$1.10/share
(1)

17
Exelon Generation Hedging Disclosures
(as of June 30, 2010)
*
*
*
*
*
*
*
*
*
*

18
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
June
30,
2010.
We
update
this
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.

19
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

20
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

21
2010
2011
2012
Estimated Open Gross Margin ($ millions)
(1)(2)
$5,700
$5,300
$5,100
Open gross margin assumes all expected generation is
sold at the Reference Prices listed below
Reference Prices
(1)
Henry Hub Natural Gas ($/MMBtu)
NI-Hub ATC Energy Price ($/MWh)
PJM-W ATC Energy Price ($/MWh)    
ERCOT North ATC Spark Spread ($/MWh)
(3)
$4.77
$33.17
$44.76
$1.28
$5.34
$32.63
$45.54
$(0.02)
$5.68
$34.22
$46.86
$0.53
Exelon Generation Open Gross Margin and
Reference Prices
(1)
Based on June 30, 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.

22
2010
2011
2012
Expected Generation
(GWh)
(1)
167,500
163,000
162,600
Midwest
100,000
98,700
97,500
Mid-Atlantic
58,900
57,000
57,000
South
8,600
7,300
8,100
Percentage of Expected Generation Hedged
(2)
96-99%
86-89%
57-60%
Midwest
96-99
86-89
54-57
Mid-Atlantic
96-99
90-93
59-62
South
97-100
66-69
51-54
Effective Realized Energy Price
($/MWh)
(3)
Midwest
$46.00
$43.50
$44.50
Mid-Atlantic
$36.50
$57.50
$51.00
ERCOT North ATC Spark Spread
$0.00
$(2.00)
$(5.50)
Generation Profile
(1)
Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is based
upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products,
and options.  Expected generation assumes 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem. 
Expected generation assumes capacity factors of 94.1%, 93.2% and 92.9% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected
generation in 2011 and 2012 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.
(2)
Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation.  Includes all hedging products, such as wholesale and retail
sales of power, options, and swaps.  Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. 
Current  RMR discussions do not impact metrics presented in the hedging disclosure.  
(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.

23
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
$20
$(15)
$10
$(5)
$5
$ -
+/-
$25
2011
$100
$(90)
$75
$(65)
$30
$(25)
+/-
$45
2012
$260
$(245)
$220
$(210)
$130
$(125)
+/-
$45
Exelon Generation Gross Margin Sensitivities
(with Existing Hedges)
(1) 
Based on June 30, 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.

24
95% case
5% case
$6,600
$6,400
$5,100
$7,100
$6,500
$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 June 30, 2010.

25
Midwest
Mid-Atlantic
ERCOT
Step 1
Start
with
fleetwide
open
gross
margin
$5.70 billion
Step 2
Determine the mark-to-market value
of energy hedges
100,000GWh * 97% *
($46.00/MWh-$33.17/MWh)
= $1.24 billion
58,900GWh * 97% *
($36.50/MWh-$44.76/MWh)
= $(0.47 billion)
8,600GWh * 98% *
($0.00/MWh-$1.28/MWh)
= $(0.01) billion
Step 3
Estimate hedged gross margin
by
adding open gross margin to mark-to-
market value of energy hedges
Open gross margin:                              $5.70 billion
MTM value of energy hedges:              $1.24 billion + $(0.47 billion) + $(0.01) billion
Estimated hedged gross margin:          $6.46 billion
Illustrative Example
of Modeling Exelon Generation 2010 Gross Margin
(with Existing Hedges)

26
20
25
30
35
40
45
50
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
50
55
60
65
70
75
80
85
90
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
35
40
45
50
55
60
65
70
75
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
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
$5.17
2012  $5.58
Rolling
12
months,
as
of
July
14
, 2010.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
Forward NYMEX Coal
2011
$67.94
2012
$74.45
2011 Ni-Hub  $39.68
2012 Ni-Hub
$41.68
2012 PJM-West  $53.79
2011 PJM-West
$51.80
2011 Ni-Hub
$24.73
2012 Ni-Hub
$26.61
2012 PJM-West
$39.80
2011 PJM-West
$38.41
th

27
5.5
6.5
7.5
8.5
9.5
10.5
11.5
12.5
13.5
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
8.0
8.2
8.4
8.6
8.8
9.0
9.2
9.4
9.6
9.8
10.0
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
40
45
50
55
60
65
70
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
7/09
8/09
9/09
10/09
11/09
12/09
1/10
2/10
3/10
4/10
5/10
6/10
7/10
Market
Price
Snapshot
2012
$9.09
2011
$9.05
2011
$45.50
2012
$49.38
2011
$5.03
2012
$5.44
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
$6.73
2012
$7.67
ERCOT North On Peak Spark Spread
Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder
Rolling
12
months,
as
of
July
14  ,
2010.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
th

28
Appendix
*****************
*****************
*****************
*****************

29
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)
RPM Auction Results
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
$74.75               
PJM
RPM
Auction
($MW-day)
Exelon
Generation
Eligible
Capacity
within
PJM
Reliability
Pricing
Model
(2)

30
ComEd Delivery Service
Rate Case Filing Summary
$396
Total
($2,337
million
revenue
requirement)
(6)
$45
Other adjustments
(5)
$22
Bad debt costs (resets base level of bad debt to 2009 test year)
$55
Pension and Post-retirement health care expenses
(4)
$95
Capital Structure
(3)
: ROE –
11.50% /
Common Equity –
47.33% / ROR –
8.99%
$179
(2)
Rate Base: $7,717 million
(1)
Requested Revenue 
Increase
($ in millions)
Primary drivers of rate request are new plant investment, pension/retiree
health care and cost of capital
(1)
Filed
June
30,
2010
based
on
2009
test
year,
including
pro
forma
capital
additions
through
June
2011,
and
certain
other
2010
pro
forma
adjustments.
(2)
Includes
increased
depreciation
expense.
(3)
Requested
capital
structure
does
not
include
goodwill;
ICC
docket
07-0566
allowed
10.3%
ROE,
45.04%
equity
ratio
and
8.36%
ROR.
ROE
includes
0.40%
adder
for
energy
efficiency
incentive.
(4)
Reflects
2010
expense
levels,
compared
to
2007
expense
levels
allowed
in
last
rate
case.
(5)
Includes
reductions
to
O&M
and
taxes
other
than
income,
offset
by
wage
increases,
normalization
of
storm
costs
and
the
Illinois
Electric
Distribution
Tax,
other
O&M
increases,
and
decreases
in
load.
(6)
Net
of
Other
Revenues.
Note:
ROE
=
Return
on
Equity,
ROR
=
Return
on
Rate
Base,
ICC
=
Illinois
Commerce
Commission.

31
ComEd Delivery Rate Case
Alternative Regulation (Alt Reg) Proposal
ComEd plans to make a companion Alt Reg filing proposing to recover the costs of smart
grid and other projects outside of the traditional rate case process
•
9-month statutory process
The proposal includes a “flow-through mechanism”
to recover capital carrying costs and
incremental O&M, as incurred
Costs
and
investments
will
be
rolled
in
to
future
rate
cases,
when
they
occur
Assured
savings
to
customers
–
$2
million
on
capped
O&M
costs
for
program
costs
(excluding CARE)
Includes
an
incentive/penalty
mechanism
for
performance
above
or
under
budget
Alt Reg Proposal is permitted under section 9-244 of the IL Public Utilities Act
$30
$15
Man-hole refurbishment and cable replacement
-
$10
Expanded funding for low income CARE programs
(1)
$5
-
Electric Vehicle Fleet Purchase
$55
$40
-
$10
-
$20
Accelerated Smart Grid Deployment
•
190,000 additional AMI Meters and Outage Management
System Interface
•
Accelerated deployment of Distribution Automation
•
Customer Applications
Capital
O&M
$ millions
(1)
Total CARE amount for two-year proposal is $20 million.

32
ComEd Residential Rate Design
Straight Fixed/Variable Proposal
Filing
includes
a
proposal
to
gradually
move
more
of
residential
delivery
bill
to
the
fixed
customer charge, rather than usage-based kwh component through three step phase-in
Current rate design:  37% fixed / 63% variable split
Proposed:  60%/40% split in June 2011, 70%/30% in June 2012, and
80%/20% in June 2013
Mitigates impact of weather and load fluctuations due to weather
and economy
Rate design reflects current cost structure and sends appropriate price signals
•
Fixed costs to be collected via fixed charges (i.e. Customer Charge, Meter Charge)
•
Variable costs to be collected via variable charges (i.e. per kWh)
Eliminates economic disincentive to promote energy efficiency
Proposed Straight Fixed/Variable rate design is consistent with ICC
orders in other recent cases

33
3.82
4.73
7.44
7.03
0.73
0.73
0.65
0.60
ComEd Delivery Rate Case
Residential Rate Impacts 2010 to 2011
(1)
(1)
Reflects
change
in
distribution
rates
only.
Assumes
Energy,
Transmission
and
all
other
components
remain
constant
as
of
June
2010,
except
as
noted
above.
(2)
"All
Other"
includes
impact
of
riders
that
are
applicable
to
residential
bills.
Unit rates: cents / kWh
All Other
(2)
Transmission
Energy
Distribution
Approximately
4% increase
July 1, 2010
July 1, 2011
Transmission: Subject to FERC
formula rate annual update
Comments
Energy: Reflects reduced PJM capacity
price that PJM has published for the
June 2011 –
May 2012 planning
period.  Energy component may vary
Distribution: As proposed
12.63
13.09
Note:  Amounts may not add due to rounding.
Proposed residential rate impact of 7% will be mitigated by impact
of lower capacity prices resulting in an increase of 4%

34
ComEd Delivery Service Rate Case
Tentative Schedule
Delivery
Service
Rate
Case
Filed
–
June
30,
2010
Alt
Reg
Proposal
Filed
–
August
/
September
2010
Intervenor
and
Rebuttal
Testimony
–
4Q
2010
Hearings
–
December
2010
/
January
2011
Administrative
Law
Judge
Order
–
February
2011
Final
Order
Expected
–
May
2011
New
Rates
Effective
–
June
2011
Note:
Dates
are
based
on
typical
approach
to
rate
cases
but
the
ICC
will
set
the
actual
schedule,
which
is
expected
in
3Q
2010.

35
6.4
6.9
2.0
2.1
6.7
7.2
2.2
1.9
Transmission
Distribution
ComEd Building Strength
~45%
~43%
8.5%
46.4%
Earned ROE
Equity
(2)
5.5%
45.4%
$8.4
$8.6
$9.4
2008
2009
2011
(Illustrative)
(1)
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. Amounts do not reflect pro forma adjustments that may be made to determine rate base for rate case filing.
(2)
Equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill).
Note: Amounts may not add due to rounding.
2010E
$9.0
>10%
>10%
Significant improvement in earned ROE, from
5.5% in 2008 to 8.5% in 2009, targeting at least
10% in 2010
Continued strong operational performance
Filed electric distribution rate case on June 30,
2010
Benefiting from regular transmission updates
through a formula rate plan
Illinois Power Agency’s 2010 procurement
approved by the ICC on April 30
Uncollectibles expense rider tariff approved by
ICC in February 2010
Smart Meter pilot program and rider approved
by ICC and underway
Standard & Poor’s raised credit ratings in
3Q09 and Fitch in 1Q10
ComEd executing on regulatory recovery plan resulting in healthy
increases in earned ROE
Producing
Results
with
Regulatory
Recovery
Plan
End
of
Year
Rate
Base
($
in
billions)
(1)

36
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 (~6% 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

37
ComEd Customer Usage Breakdown
Other
2%
Residential
31%
Small C&I
36%
380 Large
C&I
18%
Other Large
C&I
13%
3%
Leisure & Hospitality
9%
Trade, Transportation & Utilities
11%
Finance, Professional &
Business Services
12%
Health & Educational Services
13%
Government
52%
Manufacturing
Limited survey of select Large C&I customers has indicated an increase in
production via longer production runs and additional shifts due to improved
economic conditions for manufacturing-based customers, especially in the
steel and transportation sectors, along with data center expansions.
Customer Usage by Revenue Class
Top
380
Customer
Usage
by
Segment

38
PECO –
Electric & Gas Distribution
Rate Case Filing Summary
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-2010-2161592
R-2010-2161575
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
(1)    With pro forma adjustments.
(2)    Excluding Alternative Energy Portfolio Standards and default service surcharge.
Note: Electric and gas rate case filings available on PAPUC (Pennsylvania Public Utility Commission) website or www.peco.com/know.
PECO executing its post-transition regulatory plan to secure fair and
reasonable returns on its distribution investment

39
PECO –
Timeline for Rate Cases
Electric
Gas
Filed:
March 31, 2010
March 31, 2010
Opposing Parties’
Testimony:
July 7, 2010
June 30, 2010
Rebuttal Testimony:
August 3, 2010
July 23, 2010
Hearings:
August 16-20, 2010
August 9-11, 2010
Administrative Law Judge Orders:
November 2, 2010
November 2, 2010
Final Orders Expected:
December 16, 2010
December 16, 2010
New Rates Effective:
January 1, 2011
January 1, 2011
PAPUC has a nine-month process for litigation of the rate case filings

40
5.03
6.26
6.23
0.51
0.70
2.57
8.57
PECO Electric Residential Rate
Increases 2010 to 2011
January 1, 2011
January 1, 2010
Total = 14.7¢
Unit Rates (¢/kWh)
Proposed Total Bill
Increase ~9 %
Total = 16.0¢
AEPS                                 ~0.6%
Smart Meter
~0.7%
Default Service surcharge       
mechanism                      ~(1.8)%
Transmission surcharge                           
mechanism                        ~1.3%
Energy / Capacity
Competitive Transition
Charge
Transmission
Distribution
Distribution Rate Case     ~8.2%
0.47
Energy Efficiency
Surcharge
Breakdown of 2010 to 2011
~9% Increase (On Total Bill)
Notes:
•
Assume results from final procurement in September 2010 are the same as May 2010 procurement.
•
Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%.
•
Low income discounted rates were subsidized in the PPA in 2010 and will be recovered through distribution rates in 2011.
0.29

41
2.7
3.0
3.3
3.5
0.5
0.6
0.6
1.1
1.1
1.1
1.1
0.6
1.7
0.9
Gas
Competitive Transition Charge (CTC)
Electric Transmission
Electric Distribution
PECO Executing on Transition Plan
Targeted earned ROE of ~11% in 2010; 9-
11% post transition
Electric and gas rate cases filed on March
31, 2010
Selected as 1 of 6 companies to receive
maximum Federal stimulus award of $200
million for smart grid / smart meter
investment
PAPUC approved Smart Meter Plan under
Pennsylvania Act 129 in April 2010
Fixed price PPA with ExGen ends
December 31, 2010
Three of four procurement events for
electricity supply beginning January 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
2008
2009
2011
(Illustrative)
(2)
(1)
Rate base as determined for rate-making purposes. Amounts do not reflect pro forma adjustments that may be made to determine rate base for rate case filing
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.
$5.1
2010E
PECO is managing through its transition period and is positioned
for
continued strong financial performance post-2010
Actively Engaged in Transition
End of Year Rate Base ($ in billions)
(1)

42
PECO Procurement
(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 2011 fixed-priced full requirements product.
Large Commercial and Industrial
Average price of $77.55/MWh
(2)
100% of fixed-price full requirements procured in May ’10
(3)
Medium Commercial
Sept ’09 / May ’10 RFP aggregate result $77.89/MWh
(2)
Remaining 42% of full requirements to be procured in Sep ‘10
Residential
June ’09 RFP average price of $88.61/MWh
(2)
Sept ’09 RFP average price of $79.96/MWh
(2)
May ‘10 RFP average price of $69.38/MWh
(2)
Remaining 28% of full requirements to be procured in Sep ‘10
Small Commercial
Sept ’09 / May ’10 RFP aggregate result $77.65/MWh
(2)
Remaining 40% of full requirements to be procured in Sep ‘10
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
Next RFP to be held on September 20, 2010

43
PECO Customer Usage Breakdown
Other
3%
Other Large
C&I
24%
150 Large
C&I
17%
Small C&I
22%
Residential
34%
7%
Other
13%
Transportation, Communication &
Utilities
18%
Health & Educational Services
18%
Manufacturing
22%
Petroleum
2%
Retail Trade
9%
Finance, Insurance & Real Estate
12%
Pharmaceuticals
PECO’s load is relatively diversified by customer class and industry
Customer Usage by Revenue Class
Top 150 Customer Usage by Segment

44
ComEd and PECO Accounts Receivable
ComEd A/R
(1)
2Q08
2Q09
2Q10
PECO A/R
(1)
% of AR
$827M
$738M
$784M
(1)   Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and include, for PECO, pledged and
long-term receivables.
>60 days
31-60 days
0-30 days
Note: Data contained on this slide is rounded.
2Q08
2Q09
2Q10
$755M
$894M
$768M

45
Sufficient Liquidity
--
--
--
--
Outstanding Facility Draws
(434)
(231)
(3)
(195)
Outstanding Letters of Credit
$7,365
$4,834
$574
$1,000
Aggregate
Bank
Commitments
(1)
6,931
4,603
571
805
Available
Capacity
Under
Facilities
(2)
(187)
--
--
(187)
Outstanding Commercial Paper
$6,744
$4,603
$571
$618
Available Capacity Less Outstanding
Commercial Paper
Exelon
(3)
($ millions)
Available Capacity Under Bank Facilities as of July 14, 2010
Exelon bank facilities are largely untapped
(1)  Excludes previous commitment from Lehman Brothers Bank and commitments from Exelon’s Community and Minority Bank Credit Facility.
(2)  Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws.  The
amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.
(3)  Includes other corporate entities.

46
Projected 2010 Key Credit Measures
14.1x
9.6x
FFO / Interest
Generation /
Corp:
69%
39%
FFO / Debt
55%
70%
Rating Agency Debt Ratio
BBB
A-
A-
BBB-
S&P Credit
Ratings
(3)
BBB+
A
BBB+
BBB+
Fitch Credit
Ratings
(3)
A3
A2
Baa1
Baa1
Moody’s Credit
Ratings
(3)
3.3x
3.6x
FFO / Interest
ComEd:
17%
16%
FFO / Debt
43%
50%
Rating Agency Debt Ratio
4.2x
4.6x
FFO / Interest
PECO:
23%
21%
FFO / Debt
48%
50%
Rating Agency Debt Ratio
29%
47%
Rating Agency Debt Ratio
96%
47%
FFO / Debt
21.2x
11.8x
FFO / Interest
Generation:
48%
37%
6.7x
Without PPA &
Pension / OPEB
(2)
58%
Rating Agency Debt Ratio
27%
FFO / Debt
6.3x
FFO / Interest
Exelon
Consolidated:
With PPA & Pension /
OPEB
(1)
Notes: Exelon and PECO metrics exclude securitization debt.  See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to
GAAP.
(1)
FFO/Debt metrics include the following standard adjustments: debt equivalents for PV of Operating Leases, PPAs, unfunded Pension and OPEB obligations (after-tax),
Capital Adequacy for Energy Trading, and other minor debt equivalents.
(2)
Excludes items listed in note (1) above.
(3)
Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of July 15, 2010. 

47
FFO Calculation and Ratios
+
Other
Non-Cash
items
(1)
-
AFUDC/Cap. Interest
-
Decommissioning activity
+/-
Change in Working Capital
FFO
Calculation
= FFO
-
PECO Transition Bond Principal Paydown
Net Cash Flows provided by Operating Activities
Net Interest Expense
Adjusted Interest
FFO + Adjusted Interest
= Adjusted Interest
+ 6% interest on Present Value (PV) of Operating Leases
+ Interest on imputed debt related to PV of PPA
+ AFUDC & Capitalized interest
-
PECO Transition Bond Interest Expense
FFO
Interest
Coverage
FFO
= Adjusted Debt
+
Off-balance
sheet
debt
equivalents
(2)
-
PECO Transition Bond Principal Balance
+ STD
+ LTD
Debt:
Adjusted Debt
(3)
FFO
Debt
Coverage
Rating Agency Capitalization
Rating Agency Debt
Total Adjusted Capitalization
Adjusted Book Debt
= Total Rating Agency Capitalization
+
Off-balance
sheet
debt
equivalents
(2)
Total Adjusted Capitalization
= Rating Agency Debt
+
Off-balance
sheet
debt
equivalents
(2)
Adjusted Book Debt
= Total Adjusted Capitalization
+ Adjusted Book Debt
+ Preferred Securities of Subsidiaries
+ Total Shareholders' Equity
Capitalization:
= Adjusted Book Debt
-
Transition Bond Principal Balance
+ STD
+ LTD
Debt:
Debt
to
Total
Cap
(1)
Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB contribution normalization.
(2)
Metrics
are
calculated
in
presentation
unadjusted
and
adjusted
for
debt
equivalents
for
PV
of
Operating
Leases,
PPAs,
unfunded
Pension
and
OPEB
obligations
(after-tax),
Capital Adequacy for Energy Trading, and other minor debt equivalents.
(3)
Uses current year-end adjusted debt balance.

48
2Q GAAP EPS Reconciliation
NOTE:
All
amounts
shown
are
per
Exelon
share
and
represent
contributions
to
Exelon's
EPS.
Data
contained
on
this
slide
is
rounded.
(0.04)
-
-
(0.02)
(0.02)
2009 severance charges
0.10
-
-
-
0.10
Unrealized gains related to nuclear decommissioning trust funds
(0.01)
(0.01)
-
-
-
NRG acquisition costs
(0.03)
-
-
-
(0.03)
2007 Illinois electric rate settlement
(0.16)
-
-
-
(0.16)
Mark-to-market adjustments from economic hedging activities
0.10
(0.02)
-
0.06
0.06
Non-cash remeasurement of income tax uncertainties and reassessment
of state deferred income taxes
$0.99
$(0.06)
$0.11
$0.17
$0.77
2Q09 GAAP Earnings (Loss) Per Share
$1.03
$(0.03)
$0.11
$0.13
$0.82
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Three
Months
Ended
June
30,
2009
(0.01)
-
-
-
(0.01)
2007 Illinois electric rate settlement
(0.02)
-
-
-
(0.02)
Retirement of fossil generating units
(0.08)
-
-
-
(0.08)
Unrealized losses related to nuclear decommissioning trust funds
(0.11)
-
-
-
(0.11)
Mark-to-market adjustments from economic hedging activities
(0.10)
(0.01)
(0.03)
(0.16)
0.10
Non-cash remeasurement of income tax uncertainties
$0.67
$(0.03)
$0.11
$0.02
$0.57
2Q10 GAAP Earnings (Loss) Per Share
$0.99
$(0.02)
$0.15
$0.18
$0.69
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Three
Months
Ended
June
30,
2010

49
YTD GAAP EPS Reconciliation
0.10
(0.02)
-
0.06
0.06
Non-cash remeasurement of income tax uncertainties and reassessment
of state deferred income taxes
(0.04)
-
-
(0.02)
(0.02)
2009 severance charges
0.05
-
-
-
0.05
Unrealized gains related to nuclear decommissioning trust funds
(0.03)
(0.03)
-
-
-
NRG acquisition costs
(0.06)
-
-
-
(0.06)
2007 Illinois electric rate settlement
0.01
-
-
-
0.01
Mark-to-market adjustments from economic hedging activities
(0.20)
-
-
-
(0.20)
Impairment of certain generating assets
$2.07
$(0.14)
$0.28
$0.35
$1.58
YTD 2009 GAAP Earnings (Loss) Per Share
$2.24
$(0.09)
$0.28
$0.31
$1.74
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Six
Months
Ended
June
30,
2009
(0.01)
-
-
-
(0.01)
2007 Illinois electric rate settlement
(0.10)
(0.01)
(0.03)
(0.16)
0.10
Non-cash remeasurement of income tax uncertainties
(0.03)
-
-
-
(0.03)
Retirement of fossil generating units
(0.05)
-
-
-
(0.05)
Unrealized losses related to nuclear decommissioning trust funds
0.10
-
-
-
0.10
Mark-to-market adjustments from economic hedging activities
(0.10)
(0.02)
(0.02)
(0.02)
(0.04)
Non-cash charge resulting from healthcare legislation
$1.80
$(0.07)
$0.26
$0.19
$1.42
YTD 2010 GAAP Earnings (Loss) Per Share
$1.99
$(0.04)
$0.31
$0.37
$1.35
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
Exelon
Other
PECO
ComEd
ExGen
Six
Months
Ended
June
30,
2010
NOTE:
All
amounts
shown
are
per
Exelon
share
and
represent
contributions
to
Exelon's
EPS.
Data
contained
on
this
slide
is
rounded.

50
2010 Earnings Outlook
Exelon’s
2010
adjusted
(non-GAAP)
operating
earnings
outlook
excludes
the
earnings
effects
of
the
following:
•
Mark-to-market
adjustments
from
economic
hedging
activities
•
Unrealized
gains
and
losses
from
nuclear
decommissioning
trust
fund
investments
to
the
extent
not
offset
by
contractual
accounting
as
described
in
the
notes
to
the
consolidated
financial
statements
•
Significant
impairments
of
assets,
including
goodwill
•
Changes
in
decommissioning
obligation
estimates
•
Costs
associated
with
the
2007
Illinois
electric
rate
settlement
agreement
•
Costs
associated
with
ComEd’s
2007
settlement
with
the
City
of
Chicago
•
Costs
associated
with
the
retirement
of
fossil
generating
units
•
Non-cash
charge
resulting
from
passage
of
Federal
health
care
legislation
•
Non-cash
remeasurement
of
income
tax
uncertainties
•
Other
unusual
items
•
Significant
future
changes
to
GAAP
Operating
earnings
guidance
assumes
normal
weather
for
remainder
of
the
year
Operating
O&M
target
excludes
the
following
items:
•
Exelon
Generation:
Decommissioning
accretion
expense
•
ComEd:
Impact
of
riders,
primarily
Rider
EDA
(Energy
Efficiency
and
Demand
Response Adjustment)
•
PECO:
Impact
of
energy
efficiency
and
smart
grid/meter
riders

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