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Form 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

August 28, 2007

Date of Report (Date of earliest event reported)

 

Commission File
Number

   

Exact Name of Registrant as Specified in Its Charter;

State of Incorporation; Address of Principal Executive

Offices; and Telephone Number

    IRS Employer
Identification Number
1-16169   

EXELON CORPORATION

(a Pennsylvania corporation)

10 South Dearborn Street

P.O. Box 805379

Chicago, Illinois 60680-5379

(312) 394-7398

    23-2990190
333-85496   

EXELON GENERATION COMPANY, LLC

(a Pennsylvania limited liability company)

300 Exelon Way

Kennett Square, Pennsylvania 19348-2473

(610) 765-5959

    23-3064219
1-1839   

COMMONWEALTH EDISON COMPANY

(an Illinois corporation)

440 South LaSalle Street

Chicago, Illinois 60605-1028

(312) 394-4321

    36-0938600
000-16844   

PECO ENERGY COMPANY

(a Pennsylvania corporation)

P.O. Box 8699

2301 Market Street

Philadelphia, Pennsylvania 19101-8699

(215) 841-4000

    23-0970240

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

Section 7 – Regulation FD

 

Item 7.01. Regulation FD Disclosure.

On September 4, 2007, Exelon Corporation (Exelon) will participate in the Lehman Brothers 2007 CEO Energy/Power Conference and will revise its adjusted (non-GAAP) operating earnings guidance range for 2007 for Exelon, Exelon Generation Company, LLC (Generation), Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) (the Registrants) to $4.15 to $4.30, $3.45 to $3.55, $0.20 to $0.25 and $0.65 to $0.70, respectively. Exelon will also reaffirm its GAAP earnings guidance range for 2007 for Exelon of $3.70 to $4.00. Attached as Exhibits 99.1 and 99.2 to this Current Report on Form 8-K are the slides and 2006-2007 Exelon Fact Book to be used at the conference, respectively.

Section 8 – Other Events

 

Item 8.01 Other Events.

Share Repurchase Program

On September 4, 2007, Exelon issued a press release announcing that the Exelon board of directors had approved a share repurchase program for up to $1.25 billion of Exelon’s outstanding stock. A copy of the press release announcing approval of the share repurchase program is attached as Exhibit 99.3 to this Current Report on Form 8-K. The board of directors approved the share repurchase program on August 31, 2007.

Swap Agreement

On July 24, and 25, 2007, Exelon, Generation and ComEd filed Current Reports on Form 8-K disclosing the material terms of a settlement agreement to address concerns about higher electric bills in Illinois without a rate freeze, generation tax or other legislation that would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois (the Settlement). The Settlement would be effective only upon enactment of legislation (the Legislation), the language of which was disclosed in the Current Report on Form 8-K filed by the Registrants (other than PECO) on July 27, 2007.

On August 28, 2007, the Legislation was enacted upon its signature by the Governor of Illinois, and accordingly the Settlement is effective.

The Legislation provides, in part, that utilities must enter into multi-year financial swap contract or contracts with a generation company or marketing company to be effective upon the effective date of the Legislation. The goal of these contracts is to promote price stability for residential and small business customers. The contracts will be included in the utilities’ procurement plans as pre-existing contracts.

To fulfill this requirement, ComEd has entered into a financial swap contract with Generation that covers around-the-clock baseload energy only, not capacity or ancillary services or congestion (the Swap Agreement). Information concerning the Swap Agreement was provided in previous Current Reports on Form 8-K. The Swap Agreement is designed to dovetail with ComEd’s remaining auction contracts for energy, increasing in volume as the auction contracts expire. By June 1, 2010, the Swap Agreement will cover about 60% of the energy that ComEd’s residential and small business customers use. The Swap Agreement spans a five-year period from June 1, 2008 through May 31, 2013.

The pricing and volumes of the Swap Agreement are set forth in the table below:

 

Portion of Term

    Fixed Price ($/MWH)    Notional Quantity (MW)

June 1, 2008 - December 31, 2008

    $ 47.93    1,000

January 1, 2009 - May 31, 2009

    $ 49.04    1,000

June 1, 2009 - December 31, 2009

    $ 49.04    2,000

January 1, 2010 - May 31, 2010

    $ 50.15    2,000

June 1, 2010 - December 31, 2010

    $ 50.15    3,000

January 1, 2011 - December 31, 2011

    $ 51.26    3,000

January 1, 2012 - December 31, 2012

    $ 52.37    3,000

January 1, 2013 - May 31, 2013

    $ 53.48    3,000

The Swap Agreement includes no riders or contingencies that would allow for price increases or decreases beyond those specified, regardless of market conditions, or environmental restrictions including the enactment of carbon emission legislation. The Swap Agreement provides a hedge against future volatility.

Section 9 – Financial Statements and Exhibits

 

Item 9.01. Financial Statements and Exhibits.

 

(d) Exhibits.

 

Exhibit No.   

Description

99.1    Presentation Slides
99.2    2006-2007 Exelon Fact Book
99.3    Press Release

* * * * *

This combined Form 8-K is being furnished separately by each of the Registrants. Information contained herein relating to any individual registrant has been furnished by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2006 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 2007 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

EXELON CORPORATION
EXELON GENERATION COMPANY, LLC
PECO ENERGY COMPANY
/s/ John F. Young
John F. Young
Executive Vice President, Finance and Markets
and Chief Financial Officer
Exelon Corporation
COMMONWEALTH EDISON COMPANY
/s/ Robert K. McDonald
Robert K. McDonald
Senior Vice President, Chief Financial Officer,
Treasurer and Chief Risk Officer
Commonwealth Edison Company

September 4, 2007

EXHIBIT INDEX

 

Exhibit No.   

Description

99.1    Presentation Slides
99.2    2006-2007 Exelon Fact Book
99.3    Press Release
Presentation Slides
Exelon –
Unique Value
Lehman Brothers
2007 CEO Energy/Power Conference
New York City
September 4, 2007
John W. Rowe
Chairman, President & CEO
Exhibit 99.1

2
Forward-Looking Statements
This
presentation
includes
forward-looking
statements
within
the
meaning
of
the
Private
Securities
Litigation
Reform
Act
of
1995,
that
are
subject
to
risks
and
uncertainties.
The
factors
that
could
cause
actual
results
to
differ
materially
from
these
forward-looking
statements
include
those
discussed
herein
as
well
as
those
discussed
in
(1)
Exelon’s
2006
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
2007
Quarterly
Report
on
Form
10-Q
in
(a)
Part
II,
Other
Information,
ITEM
1A.
Risk
Factors
and
(b)
Part
I,
Financial
Information,
ITEM
1.
Financial
Statements:
Note
13;
and
(3)
other
factors
discussed
in
filings
with
the
Securities
and
Exchange
Commission
by
Exelon
Corporation,
Exelon
Generation
Company,
LLC,
Commonwealth
Edison
Company,
and
PECO
Energy
Company
(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 that exclude the
impact of certain factors. We believe that these adjusted operating earnings are representative of the
underlying operational results of the company. Please refer to the appendix to the presentation for a
reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings.

3
  $3.22
$3.10
$2.78
$2.61
$2.41
$2.24
$1.93
2000
2001
2002
2003
2004
2005
2006
2007E
Oct-
00
Apr-
01
Oct-
01
Apr-
02
Oct-
02
Apr-
03
Oct-
03
Apr-
04
Oct-
04
Apr-
05
Oct-
05
Apr-
06
Oct-
06
Apr-
07
Strong Financial Performance
10/20/00 –
8/24/07
Assumes dividend reinvestment
Source: Bloomberg
EXC
206%
UTY
88%
Total Shareholder Return
Adjusted (non-GAAP) Operating EPS
Operating
EPS
Guidance
for
2007
revised
to
$4.15
-
$4.30
or
upper
half
of
original
guidance
range
(1)
7-year
growth
rate
through
2007;
calculated
using
midpoint
of
2007
Operating
EPS
guidance
range
and
2000
Operating
EPS
of
$1.93/share
as
base
year
$4.15 -
$4.30

4
Premier Nuclear Operator
40
50
60
70
80
90
100
Exelon
Industry
Average Capacity Factor
Note: Exelon data prior to 2000 represents ComEd-only nuclear fleet
Average Capacity Factor
Note: Exelon data prior to 2000 represents ComEd-only nuclear fleet
65
70
75
80
85
90
95
100
Operator (# of Reactors)
Range
5-Year Average
Range of Fleet 2-Yr Avg Capacity Factor (2002-2006)
EXC 93.2%
Sources:
Platt’s,
Nuclear
News,
Nuclear
Energy
Institute
and
Energy
Information
Administration
(Department
of
Energy)

5
Unique Competitive Position
Note:
Megawatts
based
on
Exelon
Generation’s
ownership
as
of
12/31/06.
Midwest Capacity
Owned:
11,389 MW
Contracted:
4,791 MW
Total:
16,180 MW
ERCOT/South Capacity
Owned:
2,299 MW
Contracted:
2,900 MW
Total:
5,199 MW
New England Capacity
Owned:
622MW
Mid-Atlantic Capacity
Owned:
11,233MW
Total Capacity
Owned:
25,543 MW
Contracted:
7,691 MW
Total:
33,234 MW
Generating Plants              %MW
Nuclear
Hydro
Coal/Oil/Gas Base-load
Intermediate
Peaker
51
5
10
10
24
Large, low-cost, low-emissions,
exceptionally well-run nuclear
fleet
Complementary and flexible
fossil and hydro fleet
Improving power market
fundamentals (heat rates and
capacity values)
Potential carbon restrictions

6
Disciplined Financial Management
We have an increasingly strong balance sheet that will be deployed both
to protect and
grow shareholder value
•
In December, the Exelon Board approved a new “Value Return Policy”
•
The Policy:
–
Established a base dividend at $1.76/share, growing modestly over time
–
Returns excess cash and/or balance sheet capacity through share
repurchases
After funding maintenance capital and committed dividend
In absence of higher value-added growth opportunities
–
Maintains adequate credit metrics on a prospective basis
•
Consistent with the Policy, the Exelon Board approved a share repurchase
program for up to $1.25 billion of Exelon’s outstanding common stock
–
Expect to complete within the next six months

7
Our Strategic Direction
Protect Today’s Value
•
Deliver superior operating performance
–
Keep the lights on
–
Continue nuclear excellence
•
Support competitive markets
–
Maintain/bolster PJM
–
Step up advocacy
–
Encourage market-based new entry
•
Protect the value of our generation
–
Optimize the generation portfolio
–
Hedge market risk appropriately
•
Build healthy, self-sustaining delivery 
companies
–
ComEd –
drive path to financial health
–
PECO –
maintain performance and
prepare for 2011 transition to market
Grow Long-Term Value
•
Take the organization to the next level of
performance
–
Foster positive employee relations
–
Require accountability for results and values
–
Acquire, develop and retain key talent
–
Continuously improve productivity
•
Align our financial management policies with the
changing profile of our company
•
Rigorously evaluate new growth opportunities
–
Generation
–
Transmission
–
Distribution
•
Advance an environmental strategy that
leverages our carbon position
–
Provide environmental benefits that also
make good business sense
–
Build a low-carbon resource portfolio
+

8
Financial Swap Agreement
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
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
•
By June 1, 2010, 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

9
Underlying Policy Challenges
Support competitive markets
Support nuclear energy
Address climate change

10

11
Appendix –
Other Information

12
Revised 2007 Operating
EPS Guidance
(1)
$3.22
$0.78
$0.67
$1.88
$0.65 -
$0.70
$3.45 -
$3.55
$4.15 -
$4.30
$0.20 -
$0.25
2006 Operating
EPS Actual
$ / Share
HoldCo/Other
ExGen
PECO
ComEd
$0.60 -
$0.63
Note:
See
“Key
Assumptions”
slide
in
Appendix.
(1)
Earnings
Guidance;
Operating
EPS
Guidance
revised
from
previous
range
of
$4.00
-
$4.30
per
share.
(2)
GAAP
Guidance
revised
on
7/25/07
from
previous
range
of
$4.10
-
$4.40
per
share.
2007 and Beyond
Exelon Generation
ComEd
PECO
Exelon expects to see robust earnings growth over next five years driven by
Exelon Generation and ComEd’s recovery
Operating EPS
(1)
:
$4.15 -
$4.30 per share
GAAP EPS
(2)
:
$3.70 -
$4.00 per share
Revised 2007 Operating Earnings
Guidance
ComEd regulatory recovery plan
Improving market fundamentals
Gas prices
Capacity values
Heat rates
End of IL and PA transition periods
Carbon regulation
Earnings Drivers

13

14
Exelon Generation Operating
Earnings Drivers: Next Five Years
Exelon Generation is poised for earnings growth over the next five years driven by the
end of the IL and PA transition periods and its unique competitive position
Revised 2007 Guidance
(2)
Note:  See “Key Assumptions”
slide in Appendix.
(1)
Differences
in
sensitivities
are
largely
due
to
differences
in
the
amount
hedged
in
2007
vs.
2011.
(2)
Operating
Earnings
Guidance
revised
from
previous
range
of
$2,280M
-
$2,420M.
$2,320M -
$2,385M
$660
N/A
+ $10/Ton Carbon
$340
$25
+/-
500 Btu/KWh ATC Heat rate
$50
$10
+/-
$10/MW-Day Capacity
$390
$25
+/-
$1/mmBtu Gas
2011
2007
Market
Sensitivities
(1)
As of 12/31/06
(After-Tax $M)
Exelon Generation’s
Competitive Position
Large, low-cost, low-emissions,
exceptionally well-run nuclear fleet
Complementary and flexible fossil
and hydro fleet
Improving power market
fundamentals (heat rates and
capacity values)
Potential carbon restrictions

15
Valuing Exelon Generation
$ Millions
Revenue Net Fuel
(2)
O&M and
Other Expenses
EBITDA
(3)
–
Hedged
EBITDA
(3)
–
Un-Hedged
Hedged –
2007
Un-Hedged –
2007
(1)
Mid-
Atlantic
$2,650
$6,700
Midwest
$4,050
($2,600)
$4,100
$4,700
Un-hedged (“Open”) EBITDA plus upside from unique competitive position drives
Exelon Generation’s value
(1)
Exelon Generation’s Un-hedged EBITDA assumes that the PECO load is priced at current market prices and removes the impact of
“in-the-money”
hedges (prices as of 9/14/06).
(2)
Exelon Generation’s estimated total Revenue Net Fuel of $6,700M reflects the Midwest, Mid-Atlantic, South and Other.
(3)
Includes Nuclear Fuel Amortization; refer to last page of Appendix for a reconciliation of Net Income to EBITDA.

16
Nuclear Performance –
Fuel Costs
Uranium market prices have increased, but
Exelon is managing its portfolio
•
Reduced uranium demand by 25%
•
Contracting strategy protects us and ensures
we are significantly below current spot market
prices through 2011
•
Uranium is small component of total
production cost
•
Expect long-term market price to decrease
due to increasing supply; stabilize based on
cost of production
Exelon Nuclear is managing fuel costs
Components of Exelon Nuclear's Fuel Cost in 2006
Uranium
21%
Conversion
4%
Fabrication
16%
Tax/Interest
1%
Nuclear Waste
Fund
18%
Enrichment
40%
Exelon Projected Uranium Portfolio
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2005
2006
2007
2008
2009
2010
2011
Contracted Supply
2003 Demand Projection
Current Demand Projection
Exelon Uranium Cost vs. Market
0
10
20
30
40
50
60
70
80
90
100
2007
2008
2009
2010
2011
Exelon average re-load price
Projected market price

17
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
Significantly improves EPS
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
Need clarification of
implementation specifics
Availability of funds to
nuclear projects at risk given
latest program guidelines
Government Loan
Guarantee
“Insurance”
protecting against
regulatory delays in
commissioning a completed
plant
•
First two reactors would
receive immediate
“standby interest coverage”
including replacement
power up to $500M
•
The next four reactors
would be covered up to
$250M after six months of
delay
Regulatory Delay “Backstop”
Energy Policy Act provides financial incentives and
reduced risk by way of production tax credits and
loan guarantees

18
% Hedged
Low End of Profit
High End of Profit
Portfolio Management
Flexibility in our targeted financial hedge ranges allows us to be opportunistic while
mitigating downside risk
90% -
98%
Prompt Year
(2008)
Target Financial Hedge
(1)
Range
50% -
70%
70% -
90%
Third Year
(2010)
Second Year
(2009)
(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

19
The transition to competitive power procurement allows Exelon Generation to
capture the full market value of its generation portfolio and places more
emphasis on hedging and risk management
37,500
Fossil & Hydro
139,750
Nuclear
184,550
Total
7,300
Forward & Spot Purchases
2007 Expected Total Supply (GWh)
PECO PPA
22%
Other Midwest
Sales
42%
Other Mid-
Atlantic Sales
13%
IL Auction
15%
Other South
Sales
8%
Portfolio Characteristics
2007 Expected Total Sales (GWh)

20
Fundamentals
The overbuild is ending in the
Eastern Interconnect
New build costs are increasing
rapidly and are difficult to project with
precision due to limited active construction
Cost
of
New
Build
Generation
Construction
(1)
2,123
1,581
1,316
615
428
EIA ($/KW)
S&P ($/KW)
700
CCGT
4,000
Nuclear
2,795 –
2,925
IGCC
2,438
Pulverized Coal
Gas CT
Technology
(1) Notes:
•
EIA estimates from Annual Energy Outlook 2007; capital costs converted to
2006 dollars.
•
S&P costs from Commodity Report, "Which Power Generation Technologies
Will Take the Lead in Response to Carbon Controls," May 11, 2007.
•
Cost
estimates
from
EIA
and
S&P
are
generic
and
do
not
take
into
account
site-specific issues such as transmission and fuels access.
2007
2008
2009
2010
2011
2012
2013
Source: WoodMackenzie
Year New Capacity is Needed
VACAR
MRO
MAAC
NY
ERCOT
SPP
ECAR
NEPOOL
MAIN

21
$12.40
$10.30
$15.50
$1.50
$1.00
$102.51/MWh
(36-Month Price)
2006 Auction
2007 Auction
~ $35
$67.20 -
$67.50
~ $41
$98.88/MWh
(36-Month Price)
$57.70 -
$58.45
$102.51/MWh
(36-Month Price)
2006 Auction
2007 Auction
~ $35
$67.20 -
$67.50
~ $41
$98.88/MWh
(36-Month Price)
$57.70 -
$58.45
Full Requirements Cost
New Jersey BGS Auction for PSEG
ATC
Forward
Energy
Price
(1)
Full-Requirements Costs ($/MWh):
The higher full-requirements component is due to increases in costs associated with
capacity and congestion
(1) Range
of
forward
market
prices
that
traded
during
the
2006
and
2007
auctions.
The
2006
auction
occurred
on
Feb.
6-7,
2006,
and
the
2007
auction
occurred
on
Feb.
5-7,
2007.
$140/MW-Day
Transmission and Congestion
Migration Risk
and Volumetric
Risk
Capacity
Renewable
Energy
Load Shape and
Ancillary Services

22
PJM RPM 2007/2008 & 2008/2009
RPM will have limited impact on Exelon’s 2007 earnings due to current contracts and
forward sales commitments
Eastern MACC
•
2007/2008 RPM auction:
$197.67/MW-day
•
2008/2009 RPM auction:
$148.80/MW-day
Rest of Market
•
2007/2008 RPM auction:
$40.80/MW-day
•
2008/2009 RPM auction:
$111.92/MW-day
Southwest MAAC
•
2007/2008 RPM auction:
$188.54/MW-day
•
2008/2009 RPM auction:
$210.11/MW-day
2007/2008 System
Total CTR Value = 4,599 MW
2008/2009 System
Total CTR Value = 5,128 MW
2007/2008 System Total
CTR Value = 5,134 MW
2008/2009 System Total
CTR Value = 4,717 MW
0 MW
0 MW
N/A
0 MW
Southwest MAAC
480 -
525 MW
480 -
525 MW
NJ BGS
9,000 -
9,300 MW
9,000 -
9,300 MW
PECO PPA
9,500 MW
Eastern MAAC
6,600 -
6,800 MW
6,600 -
6,800 MW
IL Auction
16,000 MW
(3)
Rest of Market
2008/09
2007/08
Obligation
Exelon Generation Capacity Obligation
(2)
ExGen
Capacity
(1)
RPM = Reliability Pricing Model
CTR = Capacity Transfer Rights
(1)  All values are approximate.   (2) Not inclusive of all wholesale transactions.
(3) 2008/2009 ExGen Rest of Market Capacity decreases to 15,100 MW due to the roll-off of several PPAs.

23
-
500
1,000
1,500
2,000
2,500
3,000
0
5
10
15
20
25
30
35
40
45
Carbon Credit ($/Ton)
0
5
10
15
20
25
30
35
40
Carbon Value
Climate change legislation is expected to drive substantial gross margin expansion
at Exelon Generation
(1) As of 7/23/07.
(2) The
EIA
Carbon
Stabilization
Case
(Case
4)
dated
March
2006,
EIA
report
number
SR/OIAF/2006-1.
(3) The
Energy
Information
Administration
(EIA)
valuation
of
the
McCain
Lieberman
Bill,
EIA
report
number
SR/OIAF/2003-02.
(4) Low
Carbon
Economy
Act
initial
“Technology
Accelerator
Payment”
(TAP)
price
in
2012.
Allowance
price
increases
at
5%
above
the
rate
of
inflation
thereafter.
Note: Assumes below $45/ton carbon cost, no carbon reduction technology (e.g., sequestration) is economical.
EXC Market Sensitivity
2011: $10/ton
Europe Carbon Trading
2011: $28.20/ton
(1)
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
(2011 Assumptions)
McCain Lieberman Bill
(3)
2010-11: $22/ton
Assumes Open Position at Exelon Generation
EIA Carbon Case
(2)
2010: $31/ton
Bingaman Specter
(4)
: $12/ton

24
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 August 29, 2007 and market prices for the balance of the year
6.
2008 and 2009 are forward market prices as of August 29, 2007.
PRICES (as of August 29th, 2007)
Units
2004
1
2005
1
2006
1
2007
5
2008
6
2009
6
PJM West Hub ATC
($/MWh)
42.35
60.92
51.07
2
55.28
59.18
62.02
PJM NiHub
ATC
($/MWh)
30.15
46.39
41.42
43.09
44.63
46.25
NEPOOL MASS Hub ATC
($/MWh)
52.13
76.65
59.68
63.36
71.69
74.36
ERCOT North On-Peak
($/MWh)
49.53
3
76.90
3
60.87
3
57.56
67.68
71.02
Henry Hub Natural Gas
($/MMBTU)
5.85
4
8.85
4
6.74
4
6.81
7.73
8.14
WTI Crude Oil
($/bbl)
41.48
4
56.62
4
66.38
4
66.04
70.24
69.00
PRB 8800
($/Ton)
5.97
8.06
13.04
9.70
10.75
11.50
NAPP 3.0
($/Ton)
60.25
52.42
43.87
46.10
47.75
49.00
ATC HEAT RATES (as of August 29th, 2007)
PJM West Hub / Tetco
M3
(MMBTU/MWh)
6.40
6.30
6.98
7.25
6.81
6.80
PJM NiHub
/ Chicago City Gate
(MMBTU/MWh)
5.52
5.52
6.32
6.44
5.84
5.67
ERCOT North / Houston Ship Channel
(MMBTU/MWh)
7.53
8.21
8.28
7.84
8.00
7.91
2
2
2
2
2
2
2
2

25
7.4
7.6
7.8
8
8.2
8.4
8.6
8.8
9
9.2
9.4
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
Market Price Snapshot
As
of
August
29,
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
8.84
8.94
9.04
9.14
9.24
9.34
9.44
9.54
9.64
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
2008
2009
2009
2008
2008 PJM-West
2009 PJM-West
2009 Ni-Hub
2008 Ni-Hub
2008
2009
55
60
65
70
75
80
85
90
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07

26
25
27
29
31
33
35
37
39
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
40
42
44
46
48
50
52
54
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
40
42
44
46
48
50
52
54
56
58
60
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
50
52
54
56
58
60
62
64
66
68
70
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
Market Price Snapshot
As
of
August
29,
2007.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
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

27
49
51
53
55
57
59
61
63
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
7.7
7.75
7.8
7.85
7.9
7.95
8
8.05
8.1
8.15
8.2
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
57
59
61
63
65
67
69
71
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07
Market Price Snapshot
2008
2009
2009
2008
2008
2009
As
of
August
29,
2007.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
2008
2009
Houston Ship Channel Natural Gas
Forward Prices
ERCOT ATC Forward Prices
ERCOT ATC v. Houston Ship Channel
Implied Heat Rate
ERCOT Wrap Forward Prices
7
7.5
8
8.5
9
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07

28
Market Price Snapshot
ERCOT On-Peak Forward Prices
2008
2009
As
of
August
29,
2007.
Source:
OTC
quotes
and
electronic
trading
system.
Quotes
are
daily.
65
67
69
71
73
75
77
79
81
83
1/2/07
2/2/07
3/2/07
4/2/07
5/2/07
6/2/07
7/2/07
8/2/07

29

30
ComEd Operating Earnings:
Next Five Years
2011
(1)
2011 Assumptions
(1)
Rate base:
~$9.6B
Equity
(2)
:
~45%
ROE:
~10%
Revised 2007 Guidance
(3)
Note:  See “Key Assumptions”
slide in Appendix.
(1) Provided solely for illustrative purposes, not intended as earnings guidance. The earnings figure represents a possible scenario that is based on the assumptions shown above as
well as assumptions about other factors, including, but not limited to, judgments about changes in load growth, spending and ratemaking proceedings, as well as future economic,
competitive and financial market conditions, and the absence of adverse regulatory and legislative developments, all of which are subject to uncertainties and have not been subject
to the same degree of analysis as we apply to 2007 forecasts. The scenario should not be relied upon as being necessarily indicative of future results.
(2) Reflects equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill). Projected book equity ratio in 2007 is 58%.
(3) Original
Earnings
Guidance
of
$65M
-
$125M
included
anticipated
IL
Settlement
cost,
which
is
now
excluded
from
Operating
Earnings.
After 2007, ComEd’s earnings are expected to increase as regulatory lag is reduced
over time
through regular rate requests, putting ComEd on a path toward appropriate returns
$130M -
$165M
~$430M
2006 Actual
$528M
2007 Assumptions
Rate Base:
~$8.1B
Equity
(2)
:
~44%
ROE:
~3.5 –
4.5%
ComEd Highlights
Roll-out of customer rate relief
programs per the IL Settlement
IPA and new procurement
process
Regulatory recovery plan
-
Transmission formula rate approved
by FERC, effective May 1, 2007
(subject to hearing and potential
refund)
-
Distribution rate case filing planned
for late 3Q07; decision expected 11
months after filing

31

32
PECO Operating Earnings:
Next Five Years
2011
(1)
2011 Assumptions
(1)
Rate Base:
~$4.7B
Equity:
~50%
ROE:
~10%
Revised 2007 Guidance
(2)
$435M -
$470M
PECO is expected to provide a predictable source of earnings to Exelon through the
remainder of the transition period
~$235M
Note:  See
“Key
Assumptions”
slide
in
Appendix.
(1)
Provided
solely
for
illustrative
purposes,
not
intended
as
earnings
guidance.
The
earnings
figure
represents
a
possible
scenario
that
is
based
on
the
assumptions
shown
above
aswell
as
assumptions
about
other
factors,
including,
but
not
limited
to,
judgments
about
changes
in
load
growth,
spending
and
ratemaking
proceedings,
aswell
as
future economic, competitive and financial market conditions, and the absence of adverse regulatory and legislative developments, all of which are subject to uncertainties
and have not been subject to the same degree of analysis as we apply to 2007 forecasts. The scenario should not be relied upon as being necessarily indicative of future
results.
(2)
Operating
Earnings
Guidance
revised
from
previous
range
of
$400M
-
$420M.
PECO Highlights
Legislative activity:
HB 1203 and HB 1530 signed by governor on
7/17/07
Other energy issues are expected to be
addressed in a special legislative session
scheduled for 9/17/07
PAPUC:
Issued POLR rules on 5/10/07
-
PUC’s Final Default Service rules provide
competitive procurement framework with full
cost recovery
-
PUC’s Price Mitigation Order focuses on
customer education to prepare customers for
potential rate increase
AEPS Act –
PECO expects a recommendation
from the ALJ by the end of 3Q07 with a PUC
decision in 4Q07 on its early procurement filing of
3/07

33
Legislative Overview
The Pennsylvania General Assembly introduced four bills that would
enable elements of Governor Rendell’s Energy Independence Plan
One of the four bills, HB 1203, was passed by the General Assembly
and was signed into law on July 17, 2007
•
HB 1203 amends the Alternative Energy Portfolio Standards (AEPS)
Act
by increasing solar obligations and modifying standards that utilities must
meet in order to obtain “force majeure”
waiver from PAPUC
A bill not originally part of the Governor’s Energy Initiative, HB 1530,
was passed by the General Assembly and signed into law on July 17,
2007
•
Supported by Duquesne Energy, US Steel and ATI
•
Allows all distribution companies to provide long-term, fixed price
contracts for customers with peak demands of 15 MW or greater
•
Allows Duquesne to own generation to serve customers with peak
demands of 20 MW or greater (3-year window to enter into a contract or
acquire generation)
Legislature agreed to hold a Special Session on Energy Policy set to
begin on September 17, 2007

34
Special Session Agenda
Senate has agreed to take up the following topics in the Special
Session:
•
Investment in clean and renewable energy and incentives for conservation
without new taxes
•
Legislation to set standards for liquid fuels
Additional legislation supporting the Governor’s Energy Independence
Strategy is still under consideration in the Legislature; elements of
those bills may be considered in the Special Session:
•
Procurement
•
Conservation and renewable power
•
Rate increase phase-in plan
•
System benefits charge to support $850M bond initiative
•
Smart meters and time-of-use pilot
•
Micro-grids
•
Pennsylvania Energy Development Authority (PEDA) energy procurement
authority
•
Alternative fuels

35
Governor’s Energy Independence
Strategy –
Legislative Package
HB 1200 –
PEDA
Authorization
HB 1203 –
Renewable
Portfolio Standards
Amendment
HB 1202 –
Liquid
Fuels Bill
•
Procurement using the portfolio model with “lowest reasonable
rates”
and prioritizes demand side management and
alternative energy resources
•
Allows for long-term, cost-based rates for larger energy users
•
Provides for 3-year phase-in of rate increases for all customers
•
Establishes system benefits charge of 0.5 mills/KWh
•
Mandates time-of-use pilot for all customers and full
deployment of “smart meter”
program in 6 years
•
Authorizes Pennsylvania Energy Development Authority
(PEDA) to spend the $850M of proceeds from securitization of
systems benefit charge
•
Provides PEDA right to “acquire, buy and sell electric power”
•
Accelerates the minimum thresholds for the acquisition of
Solar/Photovoltaic as Tier-1 Resource 
•
Force Majeure language modified to consider “good faith
effort”
by utilities to procure renewable energy
•
Sets standards for ethanol content in transportation fuels
•
Sets standards for bio-diesel content of diesel fuel
HB 1201 –
PAPUC
Statute Bill

36
Summary of PAPUC Rulemakings
It will likely be effective
immediately, as it is a
policy statement
Expected in the Fall
2007
Will address the
benefits of DSR/EE and
requirements for utilities
to implement such
programs
Demand Side Response
Energy Efficiency
(DSR/EE)
May 17, 2007
Issued May 10, 2007
Discusses consumer
education, conservation
and energy efficiency,
impact on low income
customers
Mitigation of Rate
Increases
May 10, 2007
Issued May 10, 2007
Reflects the PAPUC’s
current thinking on
application of the
regulations
Default Service
Policy Statement
Expected in September
2007
Issued May 10, 2007
Addresses issues
around procurement,
rate design, cost
recovery, filing
requirements
Default Service
Regulations
Effective Date
Final Order
Description
Rulemaking

37
Default Service Provider
Regulations/Policy
Procurement
•
Competitive process but no statewide auction
•
Utility run RFPs
or auctions are preferred; portfolio approach is
allowed
•
Staggered
auctions/RFPs
to
avoid
high
market
risk
•
Long term contracts limited to renewable resources
•
Non-renewable contracts limited to 1-3 years
•
Encourages spot market purchases for a portion of supply
Cost Recovery
•
Full cost recovery, no prudence review
•
Reconciliation not required but is mandatory for AEPS
Rate Design
•
Preference for a single price for each rate class
•
Eliminates declining block rates and demand charges
•
Frequent
rate
changes
–
quarterly
or
monthly,
to
better
track
the market
•
Hourly or monthly pricing for large customers
Mitigation
•
Provides for an opt-in phase-in for increases of >25% for
customers <25 KW; must be competitively neutral
•
Transition period of up to 3 years for rate design changes
•
Statewide education program
•
Utility specific education plans to be filed by 12/31/2007
•
Encourages energy efficiency and demand response

38
PECO Post-2010 Strategy
•
PECO to propose an auction approach to conduct multiple
procurements prior to 2011
•
May offer 1-year fixed rate for large energy users
•
Requirement for some spot market purchases
•
PECO will file its individual Customer Education Plan with
PAPUC by 12/31/07
•
Participate in PAPUC Working Group to develop effective
statewide campaign
•
Expect
PAPUC
action
on
DSR/EE
in
4
th
quarter
2007
•
PECO to begin real-time pricing pilot for 300 customers
in 2008
•
Plan to expand current offerings and add new programs,
based upon PAPUC rules and cost recovery
Procurement
Rate Stabilization
Consumer Education
Demand Side
Response & Energy
Efficiency (DSR/EE)
•
Procurement plan will include early, staggered procurement
•
Rate increase phase-in for residential & small commercial
customers offered on an opt-in basis if rate increase > 25%
•
Three-year phase-out to minimize impact of rate design
changes

39
2011
PECO Average Electric Rates
(1)  Rates
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.
2.59
2.59
2.59
0.46
0.46
0.46
2.70
2.70
2.70
4.92
5.43
5.43
2006
2007
2008 -
2010
Energy / Capacity
Competitive
Transition Charge
Transmission
Distribution
10.67¢
11.18¢
11.18¢
Unit Rates (¢/kWh)
(1)
Electric Restructuring Settlement
+4.8%
CTC terminates at year-end 2010
Energy / Capacity price is expected to
increase; price will reflect associated
full requirements costs (including
capacity, load shaping, ancillary
services, line losses, transmission
congestion and gross receipts tax)  
PECO’s 2011 full requirements price is
expected
to
differ
from
PPL’s
first
auction price 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
Post-Transition Factors

40
Appendix –
Key Assumptions, Projected
2007 Credit Measures &
GAAP Reconciliation

41
Key Assumptions
7.60
6.56
8.41
Chicago City Gate Gas Price ($/mmBtu)
9.00
7.31
9.67
Tetco M3 Gas Price ($/mmBtu)
37.0
37.0
37.5
Effective Tax Rate (%)
(4)
0.9
0.6
1.3
ComEd
0.6
1.2
0.9
PECO
Electric Delivery Growth (%)
(3)
53
77
79
ComEd
98
98
95
PECO
Electric Volume Retention (%)
16.60
1.75
0.13
PJM West Capacity Price ($/MW-day)
44.30
1.75
0.13
PJM East Capacity Price ($/MW-day)
5.80
6.32
5.52
NI Hub Implied ATC Heat Rate (mmbtu/MWh)
44.00
41.42
46.39
NI Hub ATC Price ($/MWh)
6.60
6.98
6.30
PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)
59.50
51.07
60.92
PJM West Hub ATC Price ($/MWh)
8.00
6.74
8.85
Henry Hub Gas Price ($/mmBtu)
144,000
71,326
72,376
Total Genco Market and Retail Sales (GWhs)
(2)
40,500
(5)
119,354
121,961
Total Genco Sales to Energy Delivery (GWhs)
184,500
190,680
194,337
Total Genco Sales Excluding Trading (GWhs)
94.0
93.9
93.5
Nuclear Capacity Factor (%)
(1)
2007 Est.
2006 Actual
2005 Actual
(1)
Excludes Salem.
(2)
2007 estimate includes Illinois Auction Sales.
(3)
Weather-normalized retail load growth.
(4)
Excludes results related to investments in synthetic fuel-producing facilities.
(5)
Sales to PECO only.
Notes:  2005 and 2006 prices are average for the year.
2007 prices reflect observable prices as of 9/14/06.

42
Projected 2007 Key Credit Measures
62% –
52%
52%
53%
Rating Agency Debt Ratio
Adjusted Book Debt Ratio: 49%
12% –
20%
18%
17%
FFO / Debt
2.5x –
3.5x
A-
4.4x
4.4x
FFO / Interest
PECO:
52% –
42%
58%
61%
Rating Agency Debt Ratio
Adjusted Book Debt Ratio: 43%
25% –
40%
12%
10%
FFO / Debt
3.5x –
5.5x
BBB-
3.0x
3.0x
FFO / Interest
ComEd:
52% –
42%
40%
58%
Rating Agency Debt Ratio
Adjusted Book Debt Ratio: 38%
25% –
40%
79%
41%
FFO / Debt
3.5x –
5.5x
BBB+
12.4x
6.5x
FFO / Interest
Generation:
63%
28%
5.6x
Without PPA &
Pension / OPEB
55% –
45%
70%
Rating Agency Debt Ratio
Adjusted Book Debt Ratio: 54%
20% –
30%
22%
FFO / Debt
3.2x –
4.5x
BBB
4.6x
FFO / Interest
Exelon Cons:
“BBB”
Target
Range
(3)
S&P Credit
Ratings
(2)
With PPA &
Pension / OPEB
(1)
Notes: Projected credit measures reflect impact of Illinois electric rates and policy settlement.  Exelon, ComEd 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)
Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits
(OPEB) obligations, and capital adequacy for energy trading.  Debt is imputed for estimated pension and OPEB obligations by operating company.
(2)
Current senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO as of 8/31/07.
(3)
Based on S&P Business Profiles: 7 for Exelon, 8 for Generation and ComEd, and 4 for PECO.
Exelon’s balance sheet is strong

43
FFO Calculation and Ratios (updated)
FFO Calculation
= FFO
-
PECO Transition Bond Principal Paydown
+ Gain
on
Sale,
Extraordinary
Items
and
Other
Non-Cash
Items
(3)
+ Change in Deferred Taxes
+ Depreciation,
amortization
(including
nucl
fuel
amortization),
AFUDC/Cap.
Interest
Add back non-cash items:
Net Income
= Adjusted Interest
+ 7% of Present Value (PV) of Operating Leases
+ Interest on imputed debt related to PV of Purchased Power Agreements
(PPA), unfunded Pension and Other Postretirement Benefits (OPEB)
obligations,
and
Capital
Adequacy
for
Energy
Trading
(2)
,
as
applicable
-
PECO Transition Bond Interest Expense
Net Interest Expense (Before AFUDC & Cap. Interest)
Adjusted Interest
FFO + Adjusted Interest
FFO Interest Coverage
+ Capital Adequacy for Energy Trading
(2)
FFO
= Adjusted Debt
+ PV of Operating Leases
+ 100% of PV of Purchased Power Agreements
(2)
+ Unfunded Pension and OPEB obligations
(2)
+ A/R Financing
Add off-balance sheet debt equivalents:
-
PECO Transition Bond Principal Balance
+ STD
+ LTD
Debt:
Adjusted Debt
(1)
FFO Debt Coverage
= Total Rating Agency Capitalization
+ Off-balance
sheet
debt
equivalents
(2)
-
Goodwill
Total Adjusted Capitalization
= Rating Agency Debt
+ ComEd Transition Bond Principal
Balance
+ Off-balance
sheet
debt
equivalents
(2)
Adjusted Book Debt
Rating Agency Capitalization
Rating Agency 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:
Total Adjusted Capitalization
Adjusted Book Debt
Debt to Total Cap
Note: Updated to reflect revised S&P guidelines and company forecast.  FFO and Debt related to non-recourse debt are excluded from the calculations.
(1) Use current year-end adjusted debt balance.
(2) Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital
Adequacy for Energy Trading.
(3) Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions.

44
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

45
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

46
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

47
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

48
2007 Earnings Outlook
Exelon’s outlook for 2007 adjusted (non-GAAP) operating earnings
excludes the earnings impacts of the following:
•
costs associated with the Illinois electric rate settlement, including ComEd’s
previously announced customer Rate Relief and Assistance Initiative
•
mark-to-market adjustments from economic hedging activities
•
investments in synthetic fuel-producing facilities
•
significant impairments of intangible assets, including goodwill
•
significant changes in decommissioning obligation estimates
•
other unusual items
•
any future changes to GAAP
GAAP guidance excludes the impact of unusual items which the Company
is unable to forecast, including any future changes to GAAP
Both our operating earnings and GAAP earnings guidance are based
on the
assumption of normal weather

49
Net income (loss)
+/-
Cumulative effect of changes in accounting principle
+/-
Discontinued operations
+/-
Minority interest
+   Income taxes
Income (loss) from continuing operations before income taxes and
minority
interest
+  Interest expense
+  Interest expense to affiliates
-
Interest income from affiliates
+  Depreciation and amortization
Earnings before interest, taxes, depreciation and amortization (EBITDA)
Reconciliation of Net Income to
EBITDA

50
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
JaCee Burnes, Director
312-394-2948
JaCee.Burnes@ExelonCorp.com
Marybeth Flater, Manager
312-394-8354
Marybeth.Flater@ExelonCorp.com
Len Epelbaum, Principal Analyst
312-394-7356
Len.Epelbaum@ExelonCorp.com
2006-2007 Exelon Fact Book

Exhibit 99.2

LOGO

Table of Contents

 

Introduction

    1

Exelon at a Glance

   

Profile, Vision and Quick Facts

    2

Company Overview

   

Corporate Structure and Operating Company Summary

    3

State Regulation

   

Illinois Commerce Commission and ComEd Electric Distribution Rate Case

    4

Pennsylvania Public Utility Commission, PECO Electric Transition Plan and System Average Electric Rates

    5

Federal Regulation

   

Federal Energy Regulatory Commission and ComEd Electric Transmission Rate Case

    6

Exelon – Financial and Operating Highlights

    7

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP

   

Consolidated Statements of Operations

   

Exelon Corporation

    8

Exelon Generation Company

    10

Commonwealth Edison Company (ComEd)

    11

PECO Energy Company (PECO)

    12

Exelon and Operating Companies

   

Capital Structure, Capitalization Ratios and Credit Ratings

    13

Long-Term Debt Outstanding

   

Exelon Corporation

    14

Exelon Generation

    14

ComEd

    15

PECO

    16

Map of Exelon Service Area and Selected Generating Assets

    17

Exelon Generation

   

Generating Resources – Sources of Electric Supply, Type of Capacity and Long-Term Contracts

    18

Nuclear Generating Capacity

    19

Total Electric Generating Capacity

    20

Fossil Emissions Reduction Summary

    22

Annual Electric Supply and Sales Statistics

    24

Electric Supply and Sales Statistics by Quarter

    25

Electric Sales Statistics, Revenue and Customer Detail

   

ComEd

    26

PECO

    28

Gas Sales Statistics, Revenue and Customer Detail – PECO

    30

To the Financial Community,

The Exelon Fact Book is intended to provide historical financial and operating information to assist in the analysis of Exelon and its operating companies. Please refer to the SEC filings of Exelon and its subsidiaries, including the annual Form 10-K and quarterly Form 10-Q, for more comprehensive financial statements and information.

For more information about Exelon and to send e-mail inquiries, visit our website at www.exeloncorp.com.

 

Investor Information    Stock Symbol: EXC
Exelon Corporation    Common stock is listed on the
Investor Relations    New York, Chicago and Philadelphia stock exchanges.
10 South Dearborn Street   
Chicago, IL 60603   
312.394.2345   
312.394.4082 (fax)   

Information in this Fact Book is current as of August 31, 2007 unless otherwise noted.

This publication 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 2006 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 2007 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Exelon Generation Company LLC, Commonwealth Edison Company, and PECO Energy Company (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this publication. 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 publication.

Exelon at a Glance

Company Profile

Exelon Corporation, headquartered in Chicago, Illinois, is one of the largest electric utilities in the U.S. with approximately 5.4 million customers and more than $15 billion in annual revenues. The company has one of the largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic.

Our Vision

Exelon will be the best group of electric generation and electric and gas delivery companies in the United States – providing superior value for our customers, employees, investors and the communities we serve.

Our Goals

 

•  

Keep the lights on and the gas flowing

 

•  

Run the nuclear fleet at world-class levels

 

•  

Capitalize on environmental leadership and clean nuclear energy

 

•  

Create a challenging and rewarding workplace

 

•  

Enhance the value of our generation

 

•  

Build value through disciplined financial management

Our Values

Safety – for our employees, our customers and our communities

Integrity – the highest ethical standards in what we say and what we do

Diversity – in ethnicity, gender, experience and thought

Respect – trust and teamwork through open and honest communication

Accountability – for our commitments, actions and results

Continuous improvement – stretch goals and measured results

 

Exelon Quick Facts at year-end 2006         Market Highlights
$15.7    6,765    670 million
billion in revenues    circuit miles of electric transmission lines    common shares outstanding
$44.3    12,052    $1.76
billion in assets    miles of gas pipelines    current annual dividend rate per share(a)
5.4    33,234    50%
million electric customers    MWs total U.S. generating resources    2006 dividend payout ratio(b)
0.5    17,200    2.8%
million gas customers    employees    dividend yield
106,149      
circuit miles of electric distribution lines      

 

(a) Dividend rate increased in December 2006. Dividends are subject to declaration by the board of directors each quarter.

 

(b) Based on $1.60 dividend per share paid in 2006.

 

2

Company Overview

LOGO

 

Nuclear Generation    Illinois Utility    Pennsylvania Utility
Fossil Generation   

 

2006

   

 

2006

Renewable/Hydro Generation    (in millions)    (in millions)
Power Marketing    Revenues: $6,101    Revenues: $5,168

 

2006

    Assets: $17,774    Assets: $9,773
(in millions)      
Revenues: $9,143      
Assets: $18,909      

Operating Companies

      

Exelon Generation

    Commonwealth Edison Company    PECO Energy Company
Exelon Generation engages in competitive electric generation operations, including owned and contracted-for generating facilities, and power marketing activities through Power Team.    Commonwealth Edison (ComEd) is a regulated electricity transmission and distribution company with a service area in northern Illinois, including the City of Chicago, of approximately 11,300 square miles and an estimated population of 8 million. ComEd has approximately 3.8 million customers.    PECO Energy (PECO) is a regulated electricity transmission and distribution company and natural gas distribution company with a service area in southeastern Pennsylvania, including the City of Philadelphia, of approximately 2,100 square miles and an estimated population of 3.8 million. PECO has approximately 1.6 million electric customers and 480,000 natural gas customers.

 

3

State Regulation

Illinois Commerce Commission (ICC)

(www.icc.illinois.gov)

The ICC has five full-time members, each appointed by the Governor (Rod Blagojevich, Democrat; term began in January 2003 and ends in January 2011) and confirmed by the Illinois State Senate. The Commissioners serve for five-year, staggered terms. Under Illinois law, no more than three Commissioners may belong to the same political party. The Chairman is designated by the Governor.

 

Commissioner

    Party Affiliation    Service Began    Term Ends   

Professional Experience

Charles E. Box (Chairman)

    Democrat    1/06    1/09    Attorney; mayor of Rockford, IL; city administrator and legal director

Lula M. Ford

    Democrat    1/03    1/08    Assistant superintendent, Chicago Public Schools; teacher; assistant director, Central Management Service

Erin O’Connell-Diaz

    Republican    4/03    1/08    Attorney; ICC Administrative Law Judge; assistant attorney general

Robert F. Lieberman

    Democrat    2/05    1/10    CEO, Center for Neighborhood Technology; positions at Illinois Department of Natural Resources and Office of Coal Development

Vacant

            

ComEd Electric Distribution Rate Case

 

($ in millions)

    Date    Revenue
Increase		    Test Year    Rate Base    Overall Rate
of Return		     Return on
Equity		     Equity Ratio  

ComEd Request

    8/31/05    $ 317    2004    $ 6,187    8.94 %   11.00 %   54.20 %

ICC Order(a)

    12/20/06    $ 83    2004    $ 5,521    8.01 %   10.045 %   42.86 %

 

(a) The ICC issued an order on rehearing that increased the amount previously approved on July 26, 2006 by approximately $74 million. ComEd and other parties appealed the rate order; the timing of a court ruling is uncertain.

 

4

State Regulation

Pennsylvania Public Utility Commission (PUC)

(www.puc.state.pa.us)

The PUC has five full-time members, each appointed by the Governor (Ed Rendell, Democrat; term began in January 2003 and ends in January 2011) and confirmed by the Pennsylvania State Senate. The Commissioners serve for five-year, staggered terms. Under Pennsylvania law, no more than three Commissioners may belong to the same political party as the Governor. The Chairman and Vice Chairman are designated by the Governor.

 

Commissioner

    Party Affiliation    Service Began    Term Ends   

Professional Experience

Wendell F. Holland (Chairman)

    Democrat    9/03    4/08    Attorney; retired judge; executive at American Water Works Company

James H. Cawley (Vice Chairman)

    Democrat    6/05    4/10    Attorney; majority counsel to the Pennsylvania Senate Consumer Affairs Committee

Kim Pizzingrilli

    Republican    2/02    4/12    Secretary of the Commonwealth; positions at the Department of State and Treasury Department

Terrance J. Fitzpatrick

    Republican    6/05    4/09    Attorney; PUC Commissioner 1999–2004 and former Chairman; PUC assistant counsel; member of the state Environmental Hearing Board

Tyrone Christy

    Democrat    7/07    4/11    Executive at Americas Power Partners/ Armstrong Services; board member of Pennsylvania Energy Development Authority; vice chairman of PUC’s Independent Power Committee

PECO Energy – Electric Transition Plan

The PUC authorized recovery in PECO’s 1998 settlement of $5.3 billion of stranded costs, or competitive transition charges (CTC) regulatory asset, with a return on the unamortized balance of 10.75%, through 2010. The PUC authorized amortization of the regulatory asset through 2010.

 

($ in millions)

Year

   

Estimated

CTC Revenue

    Estimated Stranded
Cost Amortization

2007

    $ 910    $ 619

2008

      917      697

2009

      924      783

2010

      932      883

PECO Energy – Schedule of System Average Electric Rates

Transmission rates are regulated by the Federal Energy Regulatory Commission. The CTC rate is subject to annual reconciliation for actual retail sales. Rates increased from the original PUC settlement to reflect the roll-in of increased gross receipts tax and Universal Service Fund charge and nuclear decommissioning cost adjustment.

 

(¢/kWh)

Effective Date

    Transmission    Distribution    CTC    Energy and
Capacity		    Total

1/1/2006

    0.46    2.59    2.70    4.92    10.67

1/1/2007

    0.46    2.59    2.70    5.43    11.18

1/1/2008

    0.46    2.59    2.70    5.43    11.18

1/1/2009

    0.46    2.59    2.70    5.43    11.18

1/1/2010

    0.46    2.59    2.70    5.43    11.18

 

5

Federal Regulation

Federal Energy Regulatory Commission (FERC)

(www.ferc.gov)

The FERC has five full-time members, each appointed by the President of the United States and confirmed by the U.S. Senate. The Commissioners serve for five-year, staggered terms. No more than three Commissioners may belong to the same political party. The Chairman is designated by the President.

 

Commissioner

    Party Affiliation    Service Began    Term Ends  

Professional Experience

Joseph T. Kelliher (Chairman)

    Republican    11/03    6/07(a)   Attorney; senior policy advisor to Secretary of Energy; majority counsel to House Committee on Commerce for energy legislation

Suedeen G. Kelly

    Democrat    11/03    6/09   Attorney; professor of law; Chair of the New Mexico Public Service Commission; counsel to the California Independent System Operator

Philip D. Moeller

    Republican    7/06    6/10   Energy policy advisor to former U.S. Senator Slade Gorton (WA); staff coordinator for the WA State Senate Committee on Energy, Utilities and Telecommunications; Alliant Energy Corporation

Marc Spitzer

    Republican    7/06    6/11   Attorney; Chair of the Arizona Corporation Commission; Arizona State Senator and Chair of the Judiciary and Finance Committees

Jon Wellinghoff

    Democrat    7/06    6/08   Attorney, practice focused on energy law and utility regulation; staff advisor to several state utility commissions; Nevada State Consumer Advocate

 

(a) Chairman Kelliher has been renominated by the President for a new term, subject to Senate confirmation.

ComEd Electric Transmission Rate Case

 

($ in millions)

    Date    Revenue
Increase		    Test Year    Rate Base    Overall Rate
of Return		     Return on
Equity		     Equity Ratio  

ComEd Request

    3/1/07    $ 147    2005
pro forma		    $ 1,898    9.87 %   12.20 %(a)   58.3 %

FERC Order (b)

    6/5/07    $ 116    2005    $ 1,745    9.87 %   12.20 %(c)   58.3 %

 

(a) Reflects base ROE of 11.70% plus requested 0.50% adder for participation in a Regional Transmission Organization (RTO). Additionally, an incentive adder of 1.50% on major new projects was requested.

 

(b) FERC issued an order that conditionally approved ComEd’s proposal to implement a formula-based transmission rate, effective May 1, 2007, subject to refund. FERC denied ComEd’s request for incentives on major projects. The FERC order provides that further hearing and settlement procedures be conducted on certain issues; the timing of completion is uncertain. Revenue requirement aspects of the order are subject to change pending these procedures.

 

(c) FERC approved the 0.50% RTO adder; the base ROE and other items were set for hearing.

 

6

Exelon Corporation – Financial and Operating Highlights

 

     For the Years ended December 31,  

(in millions, except per share data and where indicated)

    2006     2005     2004  

Operating revenues

    $ 15,655     $ 15,357     $ 14,133  

Net income

    $ 1,592     $ 923     $ 1,864  

Electric deliveries (in GWhs)(a)

      128,748       131,021       124,861  

Gas deliveries (in million cubic feet (mmcf))

      76,105       85,061       87,097  

Total available electric supply resources (MWs)

      33,464       33,520       34,687  

Capital expenditures

    $ 2,418     $ 2,165     $ 1,921  

Common Stock Data

       

Average common shares outstanding – diluted (in millions)

      676       676       669  

GAAP earnings per share (diluted)

    $ 2.35     $ 1.36     $ 2.78  

Adjusted (non-GAAP) operating earnings per share (diluted)

    $ 3.22     $ 3.10     $ 2.78  

Dividends paid per common share

    $ 1.60     $ 1.60     $ 1.26  

New York Stock Exchange common stock price (per share)

       

High

    $ 63.62     $ 57.46     $ 44.90  

Low

    $ 51.13     $ 41.77     $ 30.92  

Year end

    $ 61.89     $ 53.14     $ 44.07  

Book value per share

    $ 14.89     $ 13.69     $ 14.29  

Total market capitalization (year end)

    $ 41,460     $ 35,412     $ 29,271  

Common shares outstanding (year end)

      669.9       666.4       664.2  

(a)    One GWh is the equivalent of one million kilowatthours (kWh).

       
Reconciliation of Adjusted (non-GAAP) Operating Earnings Per Share to GAAP       
      2006     2005     2004  

GAAP Earnings per Diluted Share

    $ 2.35     $ 1.36     $ 2.78  

Impairment of ComEd’s goodwill

      1.15       1.78    

Investments in synthetic fuel-producing facilities

      0.04       (0.10 )     (0.10 )

Mark-to-market adjustments from economic hedging activities

      (0.09 )    

Nuclear decommissioning obligation reduction

      (0.13 )    

Recovery of debt costs at ComEd

      (0.08 )    

Recovery of severance costs at ComEd

      (0.14 )    

Cumulative effect of adopting FIN 47

        0.06    

Charges related to the now-terminated merger with Public Service Enterprise Group Incorporated (PSEG)

      0.09       0.03       0.01  

Financial impact of Generation’s investment in Sithe Energies, Inc. (Sithe)

        (0.03 )     0.02  

Charges associated with debt repurchases

          0.12  

Severance charges

      0.03         0.07  

Cumulative effect of adopting FIN 46-R

          (0.05 )

Settlement associated with the storage of spent nuclear fuel

          (0.04 )

Financial impact of Boston Generating investment

          (0.03 )
                        

Adjusted (non-GAAP) Operating Earnings per Diluted Share

    $ 3.22     $ 3.10     $ 2.78  

 

7

Exelon Corporation – Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

 

     Twelve Months Ended December 31, 2006     Twelve Months Ended December 31, 2005  

(in millions, except per share date)

    GAAP(a)     Adjustments     Adjusted
Non-GAAP		     GAAP(a)     Adjustments     Adjusted
Non-GAAP		  

Operating revenues

    $ 15,655     $ 5 (b)   $ 15,660     $ 15,357     $ —       $ 15,357  

Operating expenses

             

Purchased power

      2,683       179 (b)     2,862       3,162       (12 )(b)     3,150  

Fuel

      2,549       (77 )(b)     2,472       2,508       (4 )(b)     2,504  

Operating and maintenance

      3,868       23 (b),(c),(d),(e),(f),(g)     3,891       3,694       (82 )(c),(d),(f)     3,612  

Impairment of goodwill

      776       (776 )(j)     —         1,207       (1,207 )(j)     —    

Depreciation and amortization

      1,487       (37 )(c),(d)     1,450       1,334       (77 )(c),(d)     1,257  

Taxes other than income

      771       —         771       728       —         728  
                                                

Total operating expenses

      12,134       (688 )     11,446       12,633       (1,382 )     11,251  
                                                

Operating income

      3,521       693       4,214       2,724       1,382       4,106  
                                                

Other income and deductions

             

Interest expense, net

      (880 )     16 (c),(m)     (864 )     (829 )     14 (c)     (815 )

Equity in losses of unconsolidated affiliates

      (111 )     83 (c)     (28 )     (134 )     104 (c)     (30 )

Other, net

      266       (151 )(b),(c),(d),(i),(l)     115       134       —         134  
                                                

Total other income and deductions

      (725 )     (52 )     (777 )     (829 )     118       (711 )
                                                

Income from continuing operations before income taxes

      2,796       641       3,437       1,895       1,500       3,395  

Income taxes

      1,206       54 (b),(c),(d),(e),(f),(g),(i),(l),(m)     1,260       944       350 (b),(c),(d),(f)     1,294  
                                                

Income from continuing operations

      1,590       587       2,177       951       1,150       2,101  

Income (loss) from discontinued operations

      2       (4 )(h)     (2 )     14       (18 )(h)     (4 )
                                                

Income before cumulative effect of changes in accounting principles

      1,592       583       2,175       965       1,132       2,097  

Cumulative effect of changes in accounting principles, net of

      —         —         —         (42 )     42 (k)     —    
                                                

Net income

    $ 1,592     $ 583     $ 2,175     $ 923     $ 1,174     $ 2,097  
                                                

 

(a) Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

 

(b) Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

 

(c) Adjustment to exclude the financial impact of Exelon’s investments in synthetic fuel-producing facilities, including the impact of mark-to-market gains (losses) associated with the related derivatives.

 

(d) Adjustment to exclude certain costs associated with Exelon’s merger with PSEG which was terminated in September 2006.

 

(e) Adjustment to exclude the decrease in Generation’s nuclear decommissioning obligation liability related to the AmerGen Energy Company, LLC nuclear plants.

 

(f) Adjustment to exclude severance charges.

 

(g) Adjustment to exclude a one-time benefit to recover previously incurred severance costs approved by the December 2006 amended ICC rate order.

 

(h) Adjustment to exclude the financial impact of Generation’s prior investment in Sithe (sold in January 2005).

 

(i) Adjustment to exclude a one-time benefit to recover previously incurred debt costs approved by the July 2006 ICC rate order.

 

(j) Adjustment to exclude the impairments of ComEd’s goodwill.

 

(k) Adjustment for the cumulative effect of adopting FIN 47.

 

(l) Adjustment to exclude an impairment charge related to Generation’s investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), the sale of which closed on February 9, 2007.

 

(m) Adjustment to exclude the settlement of a tax matter at Generation related to Sithe.

 

8

Exelon Corporation – Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

 

    

Twelve Months Ended December 31, 2006

   

Twelve Months Ended December 31, 2005

  

(in millions, except per share date)

    GAAP(a)    Adjustments    Adjusted
Non-GAAP		    GAAP(a)     Adjustments     Adjusted
Non-GAAP		  

Earnings per average common share

                

Basic:

                

Income from continuing operations

    $ 2.37    $ 0.88    $ 3.25    $ 1.42     $ 1.73     $ 3.15  

Income (loss) from discontinued operations

      —        —        —        0.02       (0.03 )     (0.01 )
                                             

Income before cumulative effect of changes in accounting principles

    $ 2.37    $ 0.88    $ 3.25    $ 1.44     $ 1.70     $ 3.14  

Cumulative effect of changes in accounting principles, net of income taxes

      —        —        —        (0.06 )     0.06       —    
                                             

Net income

    $ 2.37    $ 0.88    $ 3.25    $ 1.38     $ 1.76     $ 3.14  
                                             

Diluted:

                

Income from continuing operations

    $ 2.35    $ 0.87    $ 3.22    $ 1.40     $ 1.71     $ 3.11  

Income (loss) from discontinued operations

      —        —        —        0.02       (0.03 )     (0.01 )
                                             

Income before cumulative effect of changes in accounting principles

      2.35      0.87      3.22      1.42       1.68       3.10  

Cumulative effect of changes in accounting principles, net of income taxes

      —        —        —        (0.06 )     0.06       —    
                                             

Net income

    $ 2.35    $ 0.87    $ 3.22    $ 1.36     $ 1.74     $ 3.10  
                                             

Average common shares outstanding

                

Basic

      670         670      669         669  

Diluted

      676         676      676         676  

 

(a) Results reported in accordance with GAAP.

 

9

Exelon Generation Company – Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Consolidated Statements of Operations (unaudited)

 

     Twelve Months Ended December 31, 2006     Twelve Months Ended December 31, 2005  

(in millions)

    GAAP(a)     Adjustments     Adjusted
Non-GAAP		     GAAP(a)     Adjustments     Adjusted
Non-GAAP		  

Operating revenues

    $ 9,143     $ —       $ 9,143     $ 9,046     $ —       $ 9,046  

Operating expenses

             

Purchased power

      2,027       179 (b)     2,206       2,569       (12 )(b)     2,557  

Fuel

      1,951       (77 )(b)     1,874       1,913       (4 )(b)     1,909  

Operating and maintenance

      2,305       121 (b),(c),(d),(h)     2,426       2,288       (9 )(c),(d)     2,279  

Depreciation and amortization

      279       —         279       254       —         254  

Taxes other than income

      185       —         185       170       —         170  
                                                

Total operating expenses

      6,747       223       6,970       7,194       (25 )     7,169  
                                                

Operating income

      2,396       (223 )     2,173       1,852       25       1,877  
                                                

Other income and deductions

             

Interest expense, net

      (159 )     7 (i)     (152 )     (128 )     —         (128 )

Equity in losses of unconsolidated affiliates

      (9 )     —         (9 )     (1 )     —         (1 )

Other, net

      41       9 (b),(c),(g)     50       95       —         95  
                                                

Total other income and deductions

      (127 )     16       (111 )     (34 )     —         (34 )
                                                

Income from continuing operations before income taxes

      2,269       (207 )     2,062       1,818       25       1,843  

Income taxes

      866       (79 )(b),(c),(d),(e),(f),(g),(h)     787       709       10 (b),(c),(d)     719  
                                                

Income from continuing operations

      1,403       (128 )     1,275       1,109       15       1,124  

Income from discontinued operations

      4       (4 )(f)     —         19       (18 )(f)     1  
                                                

Income before cumulative effect of a change in accounting principle

      1,407       (132 )     1,275       1,128       (3 )     1,125  

Cumulative effect of a change in accounting principle, net of income taxes

      —         —         —         (30 )     30 (e)     —    
                                                

Net income

    $ 1,407     $ (132 )   $ 1,275     $ 1,098     $ 27     $ 1,125  
                                                

 

(a) Results reported in accordance with GAAP.

 

(b) Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities.

 

(c) Adjustment to exclude certain costs associated with Exelon’s merger with PSEG, which was terminated in September 2006.

 

(d) Adjustment to exclude severance charges.

 

(e) Adjustment for the cumulative effect of adopting FIN 47.

 

(f) Adjustment to exclude the financial impact of Generation’s investment in Sithe (sold in January 2005).

 

(g) Reflects an impairment charge related to Generation’s investments in TEG and TEP, the sale of which closed on February 9, 2007.

 

(h) Adjustment to exclude the decrease in Generation’s nuclear decommissioning obligation liability related to the AmerGen nuclear plants.

 

(i) Adjustment to exclude the settlement of a tax matter at Generation related to Sithe.

 

10

Commonwealth Edison Company – Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

 

     Twelve Months Ended December 31, 2006     Twelve Months Ended December 31, 2005  

(in millions)

    GAAP(a)     Adjustments     Adjusted
Non-GAAP		     GAAP(a)     Adjustments     Adjusted
Non-GAAP		  
Operating revenues    $ 6,101       5 (f)   $ 6,106     $ 6,264     $ —       $ 6,264  
Operating expenses             

Purchased power

      3,292       —         3,292       3,520       —         3,520  

Operating and maintenance

      745       145 (b),(c),(h)     890       833       6 (b),(c)     839  

Impairment of goodwill

      776       (776 )(d)     —         1,207       (1,207 )(d)     —    

Depreciation and amortization

      430       —         430       413       —         413  

Taxes other than income

      303       —         303       303       —         303  
                                                

Total operating expenses

      5,546       (631 )     4,915       6,276       (1,201 )     5,075  
                                                
Operating income (loss)      555       636       1,191       (12 )     1,201       1,189  
                                                
Other income and deductions             

Interest expense, net

      (308 )     —         (308 )     (291 )     —         (291 )

Equity in losses of unconsolidated affiliates

      (10 )     —         (10 )     (14 )     —         (14 )

Other, net

      96       (87 )(g)     9       4       —         4  
                                                

Total other income and deductions

      (222 )     (87 )     (309 )     (301 )     —         (301 )
                                                
Income (loss) before income taxes      333       549       882       (313 )     1,201       888  
Income taxes      445       (91 )(b),(c),(f),(g),(h)     354       363       (2 )(b),(c)     361  
                                                
Income (loss) before cumulative effect of a change in accounting principle      (112 )     640       528       (676 )     1,203       527  
Cumulative effect of a change in accounting principle, net of income taxes      —         —         —         (9 )     9 (e)     —    
                                                
Net income (loss)    $ (112 )   $ 640     $ 528     $ (685 )   $ 1,212     $ 527  
                                                

 

(a) Results reported in accordance with GAAP.

 

(b) Adjustment to exclude certain costs associated with Exelon’s merger with PSEG, which was terminated in September 2006.

 

(c) Adjustment to exclude severance charges.

 

(d) Adjustment to exclude the impairment of ComEd’s goodwill.

 

(e) Adjustment for the cumulative effect of adopting FIN 47.

 

(f) Adjustment to exclude the mark-to-market impact of one wholesale contract at ComEd.

 

(g) Adjustment to exclude a one-time benefit approved by the July 2006 ICC rate order to recover previously incurred debt expenses to retire debt early.

 

(h) Adjustment to exclude a one-time benefit approved by the December 2006 amended ICC rate order to recover previously incurred severance costs.

 

11

PECO Energy Company – Reconciliation of Adjusted (non-GAAP) Operating Earnings

to GAAP Consolidated Statements of Operations (unaudited)

 

     Twelve Months Ended December 31, 2006     Twelve Months Ended December 31, 2005  

(in millions)

    GAAP(a)     Adjustments     Adjusted
Non-GAAP		     GAAP(a)     Adjustments     Adjusted
Non-GAAP		  
Operating revenues    $ 5,168     $ —       $ 5,168     $ 4,910     $ —       $ 4,910  
Operating expenses             

Purchased power

      2,104       —         2,104       1,918       —         1,918  

Fuel

      598       —         598       597         597  

Operating and maintenance

      628       (13 )(b),(c)     615       549       (7 )(b),(c)     542  

Depreciation and amortization

      710       (9 )(b)     701       566       (13 )(b)     553  

Taxes other than income

      262       —         262       231       —         231  
                                                

Total operating expenses

      4,302       (22 )     4,280       3,861       (20 )     3,841  
                                                
Operating income      866       22       888       1,049       20       1,069  
                                                
Other income and deductions             

Interest expense, net

      (266 )     —         (266 )     (279 )     —         (279 )

Equity in losses of unconsolidated affiliates

      (9 )     —         (9 )     (16 )     —         (16 )

Other, net

      30       —         30       13       —         13  
                                                

Total other income and deductions

      (245 )     —         (245 )     (282 )     —         (282 )
                                                
Income before income taxes      621       22       643       767       20       787  
Income taxes      180       8 (b),(c)     188       247       7 (b),(c)     254  
                                                
Income before cumulative effect of a change in accounting principle      441       14       455       520       13       533  
Cumulative effect of a change in accounting principle, net of income taxes      —         —         —         (3 )     3 (d)     —    
                                                
Net income    $ 441     $ 14     $ 455     $ 517     $ 16     $ 533  
                                                

 

(a) Results reported in accordance with GAAP.

 

(b) Adjustment to exclude certain costs associated with Exelon’s merger with PSEG, which was terminated in September 2006.

 

(c) Adjustment to exclude severance charges.

 

(d) Adjustment for the cumulative effect of adopting FIN 47.

 

12

Exelon and Operating Companies – Capital Structure and Capitalization Ratios

 

(at December 31)

   2006   2005   2004
    (in millions)     (in percent)   (in percent)(a)   (in millions)     (in percent)   (in percent)(a)   (in millions)   (in percent)   (in percent)(a)

Exelon (consolidated)

                  

Total Debt

   $ 13,045     56.5   49.8   $ 13,964     60.3   52.1   $ 13,551   58.6   47.8

Preferred Securities of Subsidiaries

     87     0.4   0.4     87     0.4   0.5     87   0.4   0.5

Total Shareholders’ Equity

     9,973 (d)   43.2   49.7     9,125 (c)   39.4   47.5     9,489   41.0   51.8
                                 

Total Capitalization

     23,105           23,176           23,127    
                                 

Transition Debt

   $ 3,051         $ 3,963         $ 4,797    

Exelon Generation

                  

Total Debt(b)

   $ 1,790     24.6     $ 2,203     35.6     $ 2,913   48.9  

Total Members’ Equity

     5,480     75.4       3,980     64.4       3,039   51.1  
                                 

Total Capitalization

   $ 7,270         $ 6,183         $ 5,952    
                                 

ComEd

                  

Total Debt(b)

   $ 4,648     42.5   38.8   $ 4,775     42.7   37.2   $ 4,875   42.0   34.4

Total Shareholders’ Equity

     6,298 (d)   57.5   61.2     6,396 (c)   57.3   62.8     6,740   58.0   65.6
                                 

Total Capitalization

     10,946           11,171           11,615    
                                 

Transition Debt(e)

   $ 648         $ 987         $ 1,341    

PECO Energy

                  

Total Debt(b)

   $ 4,197     69.9   49.8   $ 4,562     72.8   48.2   $ 4,839   77.6   49.7

Total Shareholders’ Equity

     1,809     30.1   50.2     1,704     27.2   51.8     1,398   22.4   50.3
                                 

Total Capitalization

     6,006           6,266           6,237    
                                 

Transition Debt(f)

   $ 2,404         $ 2,975         $ 3,456    

 

(a) Excluding ComEd and PECO transition debt.

 

(b) Debt includes borrowings from intercompany money pool; as of January 10, 2006, ComEd suspended participation in the intercompany money pool.

 

(c) Reflects $1,207 million charge related to the impairment of ComEd’s goodwill in 2005; goodwill balance totaled $3,475 million at December 31, 2005.

 

(d) Reflects $776 million charge related to the impairment of ComEd’s goodwill in 2006; goodwill balance totaled $2,694 million at December 31, 2006.

 

(e) ComEd transition debt maturities (in millions): 2007 - $308, 2008 - $340.

 

(f) PECO transition debt maturities (in millions): 2007 - $273, 2008 - $625, 2009 - $700, 2010 - $806.

 

  Note: Numbers may not add due to rounding.

Credit Ratings as of August 31, 2007

 

     Moody’s Investors
Service(a)		    Standard & Poor’s
Corporation(b)		    Fitch Ratings(c)

Exelon Corporation

         

Senior Unsecured Debt

    Baa2    BBB    BBB+

Commercial Paper

    P2    A2    F2

Exelon Generation

         

Senior Unsecured Debt

    Baa1    BBB+    BBB+

Commercial Paper

    P2    A2    F2

ComEd

         

Senior Secured Debt

    Baa2    BBB-    BBB

Senior Unsecured Debt

    Ba1    B+    BBB-

Commercial Paper

    Not Prime    B    B

PECO Energy

         

Senior Secured Debt

    A2    A-    A

Senior Unsecured Debt

    A3    BBB    A-

Commercial Paper

    P1    A2    F2

 

(a) ComEd and PECO ratings outlooks are stable; Exelon, and Generation ratings are under review for possible upgrade.

 

(b) Exelon, PECO and Generation ratings outlooks are stable; ComEd ratings outlook is positive.

 

(c) Exelon, ComEd, PECO and Generation ratings outlooks are stable.

 

13

Exelon Corporation – Long-Term Debt Outstanding as of December 31, 2006

 

Series

    Interest
Rate		     Date
Issued		    Maturity
Date		    Total Debt
Outstanding		     Current
Portion		    Long-Term
Debt		  
(in millions)                                  
Senior Notes Payable                

2005 Senior Notes Payable

    4.45 %   6/9/05    6/15/10    $ 400     $ 0    $ 400  

2005 Senior Notes Payable

    4.90 %   6/9/05    6/15/15      800       0      800  

2005 Senior Notes Payable

    5.625 %   6/9/05    6/15/35      500       0      500  

2001 Senior Notes Payable

    6.75 %   5/8/01    5/1/11      500       0      500  
                               

Total Senior Notes Payable

            $ 2,200     $ 0    $ 2,200  
                               

Unamortized Debt Discount

            $ (3 )   $ 0    $ (3 )
                               

Total Long-Term Debt

            $ 2,197     $ 0    $ 2,197  
                               

 

Maturities

     

2007

    $ 0

2008

      0

2009

      0

2010

      400

2011

    $ 500

Exelon Generation – Long-Term Debt Outstanding as of December 31, 2006

 

Series

    Interest
Rate		     Date
Issued		    Maturity
Date		    Total Debt
Outstanding		     Current
Portion		    Long-Term
Debt		  
(in millions)                                  
Senior Notes                

2001 Senior Unsecured Notes

    6.95 %   6/14/01    6/15/11    $ 700     $ 0    $ 700  

2003 Senior Unsecured Notes

    5.35 %   12/16/03    1/15/14      500       0      500  
                               

Total Senior Unsecured Notes

            $ 1,200     $ 0    $ 1,200  
                               
Unsecured Pollution Control Notes                

Montgomery Co. 2001 Ser. B

    var. rate     9/5/01    10/1/30      69       0      69  

Delaware Co. 2001 Ser. A

    var. rate     4/25/01    4/1/21      39       0      39  

Montgomery Co. 2001 Ser. A

    var. rate     4/25/01    10/1/34      13       0      13  

Delaware Co. 1993 Ser. A

    var. rate     8/24/93    8/1/16      24       0      24  

Salem Co. 1993 Ser. A

    var. rate     9/9/93    3/1/25      23       0      23  

Montgomery Co. 1994 Ser. A

    var. rate     2/14/95    6/1/29      83       0      83  

Montgomery Co. 1994 Ser. B

    var. rate     7/2/95    6/1/29      13       0      13  

York County 1993 Ser. A

    var. rate     8/24/93    8/1/16      18       0      18  

Montgomery Co. 1996 Ser. A

    var. rate     3/27/96    3/1/34      34       0      34  

Montgomery Co. 2002 Ser. A

    var. rate     7/24/02    12/1/29      30       0      30  

Indiana Co. 2003 A

    var. rate     6/3/03    6/1/27      17       0      17  

Delaware Co. 1999 Ser. A

    var. rate     10/1/04    4/1/21      51       0      51  

Montgomery Co. 1999 Ser. A

    var. rate     10/1/04    10/1/30      92       0      92  

Montgomery Co. 1999 Ser. B

    var. rate     10/1/04    10/1/34      14       0      14  
                               

Total Unsec. Pollution Control Notes

            $ 520     $ 0    $ 520  
                               
AmerGen Notes Payable - Oyster Creek    6.33 %      8/8/09    $ 29     $ 10    $ 19  
Capital Leases            $ 44     $ 2    $ 42  
                               

Unamortized Debt Discount

            $ (3 )   $ 0    $ (3 )
                               

Total Long-Term Debt

            $ 1,790     $ 12    $ 1,778  
                               

 

Maturities

     

2007

    $ 12

2008

      12

2009

      11

2010

      2

2011

    $ 702

 

14

ComEd – Long-Term Debt Outstanding as of December 31, 2006

 

Series

    Interest
Rate		     Date
Issued		    Maturity
Date		    Total Debt
Outstanding		     Current
Portion		    Long-Term
Debt		  
(in millions)                                  

First Mortgage Bonds

                

99

    3.70 %   1/22/03    2/1/08    $ 295     $ 0    $ 295  

83

    8.00 %   5/15/92    5/15/08      120       0      120  

Pollution Control-1994B

    5.70 %   1/15/94    1/15/09      16       0      16  

102

    4.74 %   8/25/03    8/15/10      212       0      212  

105

    5.40 %   12/19/06    12/15/11      345       0      345  

98

    6.15 %   3/13/02    3/15/12      450       0      450  

92

    7.625 %   4/15/93    4/15/13      125       0      125  

IL Dev. Fin. Authority-2002 A

    var. rate     6/4/02    4/15/13      100       0      100  

94

    7.50 %   7/1/93    7/1/13      127       0      127  

IL Dev. Fin. Authority-2003 D

    var. rate     12/23/03    1/15/14      20       0      20  

Pollution Control-1994C

    5.85 %   1/15/94    1/15/14      17       0      17  

101

    4.70 %   4/7/03    4/15/15      260       0      260  

104

    5.95 %   8/28/06    8/15/16      415       0      415  

IL Fin. Authority-2005

    var. rate     3/17/05    3/1/17      91       0      91  

IL Dev. Fin. Authority-2003 A

    var. rate     5/8/03    5/15/17      40       0      40  

IL Dev. Fin. Authority-2003 B

    var. rate     9/24/03    11/1/19      42       0      42  

IL Dev. Fin. Authority-2003 C

    var. rate     11/19/03    3/1/20      50       0      50  

100

    5.875 %   1/22/03    2/1/33      254       0      254  

103

    5.90 %   3/6/06    3/15/36      325       0      325  
                               

Total First Mortgage Bonds

            $ 3,304     $ 0    $ 3,304  
                               

Sinking Fund Debentures

                

Sinking Fund Debenture

    3.875 %   1/1/58    1/1/08      2       1      1  

Sinking Fund Debenture

    4.625 %   1/1/59    1/1/09      1       0      1  

Sinking Fund Debenture

    4.75 %   12/1/61    12/1/11      5       1      4  
                               

Total Sinking Fund Debentures

            $ 8     $ 2    $ 6  
                               

Notes Payable

                

Notes Payable

    7.625 %   1/9/97    1/15/07      145       145      0  

Notes Payable

    6.95 %   7/16/98    7/15/18      140       0      140  
                               

Total Notes Payable

            $ 285     $ 145    $ 140  
                               

Long-Term Debt To Financing Trusts

                

Class A-6 Transitional Funding Trust Notes, Series 1998

    5.63 %   12/16/98    6/25/07      138       138      0  

Class A-7 Transitional Funding Trust Notes, Series 1998

    5.74 %   12/16/98    12/25/08      510       170      340  

Subordinated Debentures to ComEd Financing II

    6.35 %   3/17/03    3/15/33      206       0      206  

Subordinated Debentures to ComEd Financing III

    8.50 %   1/24/97    1/15/27      155       0      155  
                               

Total Long-Term Debt to Financing Trusts

            $ 1,009     $ 308    $ 701  
                               

Unamortized Debt Discount

            $ (17 )   $ 0    $ (17 )
                               

Total Long-Term Debt

            $ 4,588     $ 455    $ 4,133  
                               

 

Maturities

     

2007

    $ 455

2008

      757

2009

      17

2010

      213

2011

    $ 347

 

15

PECO Energy – Long-Term Debt Outstanding as of December 31, 2006

 

Series

    Interest
Rate		     Date
Issued		    Maturity
Date		    Total Debt
Outstanding		     Current
Portion		    Long-Term
Debt		  
(in millions)                                  

First Mortgage Bonds

                

FMB

    5.90 %   4/23/04    5/1/34    $ 75     $ 0    $ 75  

FMB

    3.50 %   4/28/03    5/1/08      450       0      450  

FMB

    5.95 %   11/1/01    11/1/11      250       0      250  

FMB

    4.75 %   9/23/02    10/1/12      225       0      225  

FMB

    5.95 %   9/25/06    10/1/36      300       0      300  
                               

Total First Mortgage Bonds

            $ 1,300     $ 0    $ 1,300  
                               

Mortgage-Backed Pollution Control Notes

                

Delaware Co. 1988 Ser. A

    var. rate     4/1/93    12/1/12      50       0      50  

Delaware Co. 1988 Ser. B

    var. rate     4/1/93    12/1/12      50       0      50  

Delaware Co. 1988 Ser. C

    var. rate     4/1/93    12/1/12      50       0      50  

Salem Co. 1988 Ser. A

    var. rate     4/1/93    12/1/12      4       0      4  
                               

Total Mortgage-Backed Pollution Control Notes

            $ 154     $ 0    $ 154  
                               

Notes Payable - Accounts Receivable Agreement

    variable        11/12/10    $ 17     $ 0    $ 17  
                               

Long-Term Debt to PETT(a) and Other Financing Trusts

                

1999 A-7

    6.13 %   3/26/99    9/1/08      848       273      575  

2000 A-3

    7.625 %   5/2/00    3/1/09      399       0      399  

2000 A-4

    7.65 %   5/2/00    9/1/09      351       0      351  

2001 A-1

    6.52 %   3/1/01    9/1/10      805       0      805  

PECO Energy Capital Trust III

    7.38 %   4/6/98    4/6/28      81       0      81  

PECO Energy Capital Trust IV

    5.75 %   6/24/03    6/15/33      103       0      103  
                               

Total Long-Term Debt to PETT and Other Financing Trusts

            $ 2,588     $ 273    $ 2,315  
                               

Unamortized Debt Discount

            $ (2 )   $ 0    $ (2 )
                               

Total Long-Term Debt

            $ 4,057     $ 273    $ 3,784  
                               

 

(a) PETT = PECO Energy Transition Trust

 

Maturities

     

2007

    $ 273

2008

      1,075

2009

      700

2010

      823

2011

    $ 250

 

16

Exelon Service Area and Selected Generating Assets*

LOGO

Illinois

 

A Exelon Corporate HQ
A ComEd HQ
B Exelon Nuclear HQ
1 Braidwood (N)
2 Byron (N)
3 Clinton (N)
4 Dresden (N)
5 LaSalle (N)
6 Quad Cities (N)
7 Southeast Chicago (F)

Maine

 

8 Wyman (F)

Maryland

 

9 Conowingo (R)

Massachusetts

 

10 Framingham (F)
11 New Boston (F)
12 West Medway (F)

New Jersey

 

13 Oyster Creek (N)
14 Salem (N)

Pennsylvania

 

C Exelon Power Team HQ
C Exelon Power HQ
C Exelon Generation HQ
D PECO HQ
15 Conemaugh (F)
16 Cromby (F)
17 Eddystone (F)
18 Fairless Hills (R)
19 Keystone (F)
20 Limerick (N)
21 Muddy Run (R)
22 Peach Bottom (N)
23 Schuylkill (F)
24 Three Mile Island (N)

Texas

 

25 Handley (F)
26 LaPorte (F)
27 Mountain Creek (F)

2006 Exelon Generation – Ownership Equity

     Output Mix
in Megawatt
Hours (MWh)		     Capacity in
Megawatts (MW)		  

Nuclear

    92 %   66 %

Coal

    6 %   6 %

Oil

    <1 %   10 %

Gas

    <1 %   12 %

Renewables

    1 %   6 %

 

* Map does not show 8 sites in the Philadelphia area where Exelon has peaking combustion turbines.

 

17

Exelon Generation – Generating Resources

Sources of Electric Supply

 

(GWhs)

    2006    2005    2004

Nuclear units

    139,610    137,936    136,621

Purchases – non-trading portfolio

    38,297    42,623    48,968

Fossil and hydroelectric units

    12,773    13,778    17,010
              

Total supply

    190,680    194,337    202,599
Type of Capacity         

(MWs) At December 31,

    2006    2005    2004

Owned generation assets

         

Nuclear

    16,945    16,856    16,751

Fossil

    6,992    6,636    6,709

Hydroelectric

    1,606    1,607    1,633
              

Owned generation assets

    25,543    25,099    25,093

Long-term contracts

    7,691    8,191    8,701

TEG and TEP(a)

    230    230    230

Sithe(b)

    —      —      663
              

Total generating resources

    33,464    33,520    34,687

 

(a) Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owned a 49.5% interest in two facilities in Mexico, each with a capacity of 230 MWs. On February 9, 2007, Generation sold its ownership interests in TEG and TEP.

 

(b) Based on Generation’s 50% ownership of Sithe Energies, Inc; Sithe investment was sold on January 31, 2005.

Long-Term Contracts

(At August 31, 2007)

 

ISO Region

   

Dispatch Type

   

Location

   

Seller

   

Fuel Type

    Delivery Term    Capacity (MW)
PJM    Base-load    Kincaid, IL   

Kincaid Generation, LLC

    Coal    1998 – 2013    1,108
SERC    Peaking    Franklin, GA   

Tenaska Georgia Partners, LP(a)

    Oil/Gas    2001 – 2030    925
ERCOT    Base-load    Shiro, TX   

Tenaska Frontier Partners, LLP

    Oil/Gas    2000 – 2020    830
SPP    Peaking    Jenks, OK   

Green Country Energy, LLC

    Oil/Gas    2002 – 2022    795
PJM    Peaking    Elwood, IL   

Elwood Energy, LLC

    Oil/Gas    2001 – 2012    775
PJM    Peaking    Manhattan, IL   

Lincoln Generating Facility, LLC

    Oil/Gas    2003 – 2011    664
PJM    Peaking    Aurora, IL   

Reliant Energy Wholesale Generation, LLC

    Oil/Gas    2003 – 2008    600
PJM    Base-load    Hammond, IN   

State Line Energy, LLC

    Coal    1997 – 2012    515
ERCOT    Intermediate    Granbury, TX   

Wolf Hollow, LP

    Oil/Gas    2003 – 2023    350
PJM    Peaking    Lee County, IL   

Duke Energy Trading Inc.

    Oil/Gas    2001 – 2008    344
PJM    Peaking    East Dundee, IL   

Dynegy Inc.

(Rocky Road Plant)

    Oil/Gas    2001 – 2009    330
PJM    Peaking    Crete, IL   

DTE Energy Trading and Marketing, LLC

    Oil/Gas    2003 – 2008    294
PJM    Peaking    Morris, IL   

Morris Cogeneration, LLC

    Oil/Gas    2001 – 2011    100
PJM    Peaking    Kincaid, IL   

Kincaid Generation, LLC

    Coal    2001 – 2013    50
                   
Total                   7,680
                   

ISO = Independent System Operator

 

(a) On April 4, 2007, Exelon Generation agreed to sell its rights to all of the capacity, energy and ancillary services supplied from this contract through a tolling agreement with Georgia Power, commencing June 1, 2010 and lasting for 15–20 years, subject to regulatory approval.

 

18

Exelon Generation – Nuclear Generating Capacity

Exelon Nuclear Fleet(a)

(At December 31, 2006)

 

Station

    Number
of Units		    Plant
Type		    NSSS
Vendor		    Net Annual
Mean Rating (MW)		    Start Date    License
Expires		   Ownership   Last Refueling
Completed by Unit		    Refueling
Cycle
Braidwood    2    PWR    W    1,194/1,166    1988    2026/2027   100%   May-06/Nov-06    18 mos.
Byron    2    PWR    W    1,183/1,153    1985/1987    2024/2026   100%   Oct-06/May-07    18 mos.
Clinton    1    BWR    GE    1,048    1987    2026   100%(b)   Feb-06    24 mos.
Dresden    2    BWR    GE    871/871    1970/1971    2029/2031   100%   Nov-05/Nov-06    24 mos.
LaSalle    2    BWR    GE    1,138/1,150    1984    2022/2023   100%   Mar-06/Mar-07    24 mos.
Limerick    2    BWR    GE    1,151/1,151    1986/1990    2024/2029   100%   Mar-06/Apr-07    24 mos.
Oyster Creek    1    BWR    GE    625    1969    2009(c)   100%(b)   Nov-06    24 mos.
Peach Bottom    2    BWR    GE    1,138/1,131    1974    2033/2034   50% Exelon,   Oct-06/Oct-05    24 mos.
                    50% PSEG Nuclear     
Quad Cities    2    BWR    GE    866/871    1973    2032/2032   75% Exelon,   May-07/Apr-06    24 mos.
                    25% Mid-American     
                    Energy Holdings     
Three Mile Island    1    PWR    B&W    837    1974    2014   100%(b)   Nov-05    24 mos.
                              

Total

    17          17,544         15,976 MW owned     
                              

 

(a) Does not include Exelon Generation’s 42.59%, 969 MW, interest in Salem Units 1 and 2 (PWRs). Last refueling outages: Salem Unit 1 completed April 2007 and Unit 2 completed November 2006.

 

(b) Clinton, Oyster Creek and Three Mile Island are operated by AmerGen, wholly owned by Generation.

 

(c) A December 2004 order permits Oyster Creek to operate beyond its license expiration if the NRC has not completed its renewal application review.

 

Notes:  PWR = pressurized water reactor; BWR = boiling water reactor

NSSS Vendor = Nuclear Steam Supply System Vendor

Nuclear Operating Data

 

     2006     2005     2004  

Fleet capacity factor (a)

      93.9 %(b)     93.5 %     93.5 %

Fleet production cost per MWh(a)

    $ 13.85     $ 13.03     $ 12.43  

Refueling Outage Days(a) – 2006

– Conducted ten refueling outages

– Average refueling outage duration: 24 days

– U.S. average refueling duration: ~39 days

Net Generation – 2006

– 131,385 GWhs, excluding Salem

– 139,610 GWhs, including Salem

Refueling Outages (including Salem)

2006: 11 actual

2007: 9 planned

2008: 12 planned

 

(a) Excludes Salem; Salem Unit 1 and Unit 2 capacity factors in 2006 were 100.7% and 93.6%, respectively.

 

(b) vs. industry average of 89.3%.

Source for industry averages: Exelon Nuclear 2007 Benchmarking Report

 

19

Exelon Generation – Total Electric Generating Capacity

Owned net electric generating capacity by station at December 31, 2006; does not include properties held by equity method investments:

Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system, and consequently produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours, and consequently produce electricity by cycling on and off daily. Peaking units are plants that usually house low-efficiency, quick response steam units, gas turbines, diesels, or pumped-storage hydroelectric equipment normally used during the maximum load periods.

 

Station

    Location    Number
of Units		    Percent
Owned(a)		    Primary
Fuel Type		    Primary
Dispatch
Type		    Net
Generation
Capacity(b)
(MW)		  

Nuclear (c)

                  

Braidwood

    Braidwood, IL    2       Uranium    Base-load    2,360  

Byron

    Byron, IL    2       Uranium    Base-load    2,336  

Clinton

    Clinton, IL    1       Uranium    Base-load    1,048  

Dresden

    Morris, IL    2       Uranium    Base-load    1,742  

LaSalle

    Seneca, IL    2       Uranium    Base-load    2,288  

Limerick

    Limerick Twp., PA    2       Uranium    Base-load    2,302  

Oyster Creek

    Forked River, NJ    1       Uranium    Base-load    625  

Peach Bottom

    Peach Bottom Twp., PA    2    50.00    Uranium    Base-load    1,135 (d)

Quad Cities

    Cordova, IL    2    75.00    Uranium    Base-load    1,303 (d)

Salem

    Hancock’s Bridge, NJ    2    42.59    Uranium    Base-load    969 (d)

Three Mile Island

    Londonderry Twp, PA    1       Uranium    Base-load    837  
                     
                  16,945  

Fossil (Steam Turbines)

                  

Conemaugh

    New Florence, PA    2    20.72    Coal    Base-load    352 (d)

Cromby 1

    Phoenixville, PA    1       Coal    Intermediate    147  

Cromby 2

    Phoenixville, PA    1       Oil/Gas    Intermediate    211  

Eddystone 1, 2

    Eddystone, PA    2       Coal    Intermediate    599  

Eddystone 3, 4

    Eddystone, PA    2       Oil/Gas    Intermediate    760  

Fairless Hills

    Falls Twp, PA    2       Landfill Gas    Peaking    60  

Handley 4, 5

    Fort Worth, TX    2       Gas    Peaking    916  

Handley 3

    Fort Worth, TX    1       Gas    Intermediate    400  

Keystone

    Shelocta, PA    2    20.99    Coal    Base-load    357 (d)

Mountain Creek 2, 6, 7

    Dallas, TX    3       Gas    Peaking    273  

Mountain Creek 8

    Dallas, TX    1       Gas    Intermediate    550  

New Boston 1

    South Boston, MA    1       Gas    Intermediate    355  

Schuylkill

    Philadelphia, PA    1       Oil    Peaking    175  

Wyman

    Yarmouth, ME    1    5.89    Oil    Intermediate    36 (d)
                     
                  5,191  

Fossil (Combustion Turbines)

                  

Chester

    Chester, PA    3       Oil    Peaking    54  

Croydon

    Bristol Twp., PA    8       Oil    Peaking    497  

Delaware

    Philadelphia, PA    4       Oil    Peaking    74  

Eddystone

    Eddystone, PA    4       Oil    Peaking    76  

Falls

    Falls Twp., PA    3       Oil    Peaking    60  

Framingham

    Framingham, MA    3       Oil    Peaking    41  

LaPorte

    Laporte, TX    4       Gas    Peaking    160  

Medway

    West Medway, MA    3       Oil    Peaking    172  

Moser

    Lower Pottsgrove Twp., PA    3       Oil    Peaking    60  

New Boston

    South Boston, MA    1       Gas    Peaking    18  

Pennsbury

    Falls Twp., PA    2       Landfill Gas    Peaking    6  

Richmond

    Philadelphia, PA    2       Oil    Peaking    132  

Salem

    Hancock’s Bridge, NJ    1    42.59    Oil    Peaking    16 (d)

Schuylkill

    Philadelphia, PA    2       Oil    Peaking    38  

Southeast Chicago

    Chicago, IL    8       Gas    Peaking    312  

Southwark

    Philadelphia, PA    4       Oil    Peaking    72  
                     
                  1,788  

 

20

Exelon Generation – Total Electric Generating Supply

(continued)

Owned net electric generating capacity by station at December 31, 2005; does not include properties held by equity method investments:

 

Station

    Location    Number
of Units		    Percent
Owned(a)		    Primary
Fuel Type		    Primary
Dispatch
Type		    Net
Generation
Capacity(b)
(MW)		  

Fossil (Internal Combustion/Diesel)

                  

Conemaugh

    New Florence, PA    4    20.72    Oil    Peaking    2 (d)

Cromby

    Phoenixville, PA    1       Oil    Peaking    3  

Delaware

    Philadelphia, PA    1       Oil    Peaking    3  

Keystone

    Shelocta, PA    4    20.99    Oil    Peaking    2 (d)

Schuylkill

    Philadelphia, PA    1       Oil    Peaking    3  
                     
                  13  

Hydroelectric

                  

Conowingo

    Harford Co. MD    11       Hydroelectric    Base-load    536  

Muddy Run

    Lancaster, PA    8       Hydroelectric    Intermediate    1,070  
                     
                  1,606  
                       

Total

       126             25,543  
                       

 

(a) 100%, unless otherwise indicated.

 

(b) For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating.

 

(c) All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors.

 

(d) Net generation capacity is stated at proportionate ownership share.

 

21

Fossil Emissions Reduction Summary

Owned generation as of December 31, 2006. Table does not include station auxiliary equipment, peaking combustion turbines or plants where Exelon owns less than 100 MW.

 

          Net Generation Available for Sale (MWh)

Fossil Station

    Capacity
(MW, Summer Rating)		    2006    2005    2004
Conemaugh (New Florence, PA)    352    2,960,319    2,681,176    2,698,520

Units: 2 coal units (baseload)

            

Reduction Technology: SO2 scrubbed

            

Data reflects Exelon Generation’s 20.72% plant ownership.

            
Cromby (Phoenixville, PA)    358    733,272    1,010,799    928,105

Units: 1 coal unit (intermediate), 1 oil/gas steam unit (intermediate)

            

Reduction Technology: SO2 scrubbed (coal unit) and SNCR NOx

            
Eddystone (Eddystone, PA)    1,359    2,925,962    3,748,334    3,205,674

Units: 2 coal units (intermediate), 2 oil/gas steam units (intermediate)

            

Reduction Technology: SO2 scrubbed (coal units), SNCR NOx, and low NOx burners with separate overfire air

            
Handley(a) (Ft. Worth, TX)    1,316    715,028    803,986    1,017,590

Units: 3 gas steam units (peaking/intermediate)

            

Reduction Technology: SCR NOx (Units 3,4, and 5)

            
Keystone (Shelocta, PA)    357    2,671,192    2,827,950    2,578,620

Units: 2 coal units (baseload)

            

Reduction Technology: SCR NOx

            

Data reflects Exelon Generation’s 20.99% plant ownership.

            

SO2 scrubbers planned for 2009.

            
Mountain Creek(a) (Dallas, TX)    823    530,147    660,123    459,909

Units: 4 gas steam units (peaking/intermediate)

            

Reduction Technology: Induced flue gas recirculation (Units 6 and 7) and SCR NOx (Unit 8)

            
New Boston (South Boston, MA)    355    211,461    246,860    160,563

Units: 1 gas steam unit (intermediate)

            

Reduction Technology: None

            
Schuylkill (Philadelphia, PA)    175    27,204    129,260    70,782

Units: 1 oil steam unit (peaking)

            

Reduction Technology: None

            

 

(a) Handley Units 1 and 2 and Mountain Creek Unit 3 were removed from service in 2005. These units represented a combined 195 MW of capacity.

 

22

Fossil Emissions Reduction Summary

 

Emissions (tons)

   

Reduction Technology

Type

    2006    2005    2004   

SO2
Scrubbed

   

SCR/SNCR
NOx

    Low NOx
burners with
separate
overfire air		   

Induced
flue gas
recirculation

Conemaugh                     
SO2    1,665    1,487    1,493    X         
NOx    4,842    4,074    4,091            
CO2    2,898,948    2,612,601    2,556,113            
Cromby                     
SO2    3,613    4,990    6,873    X (Coal Unit)         
NOx    1,693    2,105    2,057       X      
CO2    970,953    1,221,416    1,249,773            
Eddystone                     
SO2    6,494    8,675    8,242    X (Coal Units)         
NOx    5,409    6,378    5,276       X    X   
CO2    3,720,295    4,617,722    4,172,765            
Handley                     
SO2    3    3    4            
NOx    57    56    206       X (Units 3, 4, 5)      
CO2    564,301    654,284    825,199            
Keystone                     
SO2    34,497    37,523    35,958            
NOx    2,684    2,938    2,850       X      
CO2    2,575,707    2,718,347    2,467,692            
Mountain Creek                     
SO2    2    2    4            
NOx    82    97    78       X (Unit 8)       X (Units 6, 7)
CO2    377,003    489,586    353,462            
New Boston                     
SO2    1    1    1            
NOx    115    132    93            
CO2    138,129    163,798    110,507            
Schuylkill                     
SO2    95    359    407            
NOx    43    180    82            
CO2    32,445    140,475    74,517            

 

23

Exelon Generation – Annual Electric Supply and Sales Statistics

 

     Twelve Months Ended December 31,  

(in GWhs)

    2006     2005     2004  

Supply

       

Nuclear

      139,610       137,936       136,621  

Purchased Power - Generation(a)

      38,297       42,623       48,968  

Fossil and Hydro

      12,773       13,778       17,010  
                        

Power Team Supply

      190,680       194,337       202,599  

Purchased Power - Other

      1,413       878       585  
                        

Total Electric Supply Available for Sale

      192,093       195,215       203,184  

Less: Line Loss and Company Use

      (10,300 )     (10,368 )     (9,264 )
                        

Total Supply

      181,793       184,847       193,920  

Energy Sales

       

Retail Sales

      135,273       137,348       130,945  

Power Team Market Sales(a)

      64,800       66,049       86,049  

Interchange Sales and Sales to Other Utilities

      3,274       2,854       2,470  
                        
     203,347       206,251       219,464  

Less: Delivery Only Sales

      (21,554 )     (21,404 )     (25,544 )
                        

Total Energy Sales

      181,793       184,847       193,920  

(a)    Purchased power and market sales do not include trading volume of 31,692 GWhs, 26,924 GWhs and 24,001 GWhs for the twelve months ended December 31, 2006, 2005 and 2004, respectively.

       

     Twelve Months Ended December 31,  

(in GWhs)

    2006     2005     2004  

Electric Sales

       

ComEd

      79,733       82,798       75,092  

PECO

      39,621       39,163       35,373  

Market(a)

      71,326       72,376       92,134  
                        

Total Electric Sales(b),(c)

      190,680       194,337       202,599  
                        

Average Margin ($/MWh)

       

Average Realized Revenue

       

ComEd

    $ 35.89     $ 37.50     $ 30.66  

PECO

      45.73       42.64       40.91  

Market(d)

      51.03       46.16       35.03  

Total Electric Sales

      43.60       41.76       34.43  

Average Purchased Power and Fuel Cost(e)

   $ 18.02     $ 20.11     $ 17.60  

Average Margin(e)

    $ 25.58     $ 21.65     $ 16.83  

Around-the-clock Market Prices ($/MWh)(f)

      

PJM West Hub

    $ 51.07     $ 60.92     $ 42.34  

NIHUB

      41.42       46.39       31.15  

 

(a) Represents wholesale and retail sales.

 

(b) Excludes retail gas sales, trading portfolio and other operating revenue.

 

(c) Total sales do not include trading volume of 31,692 GWhs, 26,924 GWhs and 24,001 GWhs for the twelve months ended December 31, 2006, 2005 and 2004, respectively.

 

(d) Market and retail sales exclude revenues related to tolling agreements of $86 million, $86 million and $97 million for the twelve months ended December 31, 2006, 2005 and 2004, respectively.

 

(e) Excludes the mark-to-market impact of Generation’s economic hedging activities.

 

(f) Represents the average for the year.

 

24

Exelon Generation – Electric Supply and Sales Statistics by Quarter

 

     Three Months Ended

(in GWhs)

    June 30,
2007		    March 31,
2007		    December 31,
2006		    September 30,
2006		    June 30,
2006		    March 31,
2006		    December 31,
2005		    September 30,
2005

Supply

                        

Nuclear

      34,350      35,357      34,810      35,867      35,442      33,491      34,887      35,584

Purchased Power – Generation

      8,579      8,683      9,085      13,341      8,101      7,770      8,623      15,393

Fossil and Hydro

      2,859      2,994      2,860      3,794      3,148      2,971      3,074      4,321
                                                       

Power Team Supply

      45,788      47,034      46,755      53,002      46,691      44,232      46,584      55,298
                                                       
     Three Months Ended

(in GWhs)

    June 30,
2007		    March 31,
2007		    December 31,
2006		    September 30,
2006		    June 30,
2006		    March 31,
2006		    December 31,
2005		    September 30,
2005

Electric Sales

                        

ComEd

      5,146      5,926      18,173      22,566      18,685      20,309      19,749      24,331

PECO

      9,732      10,279      9,383      11,361      9,262      9,615      9,404      11,442

Market(a)

      30,910      30,829      19,199      19,075      18,744      14,308      17,431      19,525
                                                       

Total Electric Sales(b),(c)

      45,788      47,034      46,755      53,002      46,691      44,232      46,584      55,298
                                                       

Average Margin ($/MWh)

                        

Average Realized Revenue

                        

ComEd

    $ 64.13    $ 64.12    $ 30.26    $ 39.31    $ 35.80    $ 37.22    $ 32.56    $ 39.87

PECO

      51.07      46.70      45.29      47.71      46.32      43.27      42.32      44.84

Market(d)

      54.38      53.07      47.76      54.21      50.31      52.14      49.34      53.16

Total Electric Sales

      54.77      53.07      40.47      46.47      43.71      43.36      40.81      45.61

Average Purchased Power and Fuel Cost(e)

   $ 18.80    $ 16.46    $ 15.66    $ 24.38    $ 17.28    $ 15.94    $ 18.78    $ 27.09

Average Margin(e)

    $ 35.97    $ 36.61    $ 24.81    $ 22.09    $ 26.43    $ 27.42    $ 22.03    $ 18.52

Around-the-clock Market Prices ($/MWh)(f)

                       

PJM West Hub

    $ 57.61    $ 59.82    $ 41.66    $ 58.15    $ 48.07    $ 56.42    $ 73.87    $ 75.33

NIHUB

      44.39      44.80      37.77      46.15      39.28      42.48      52.81      54.75

 

(a) Represents wholesale and retail sales.

 

(b) Excludes retail gas sales, trading portfolio and other operating revenue.

 

(c) Total sales do not include trading volume of 4,775 GWhs, 5,101 GWhs, 8,029 GWhs, 8,909 GWhs, 7,769 GWhs, 6,985 GWhs, 8,756 GWhs and 6,757 GWhs for the three months ended June 30, 2007, March 31, 2007, December 31, 2006, September 30, 2006, June 30, 2006, March 31, 2006, December 31, 2005 and September 30, 2005, respectively.

 

(d) Represents wholesale and retail sales that exclude revenues related to tolling agreements of $52 million, $34 million and $52 million for the three months ended September 30, 2006, June 30, 2006 and September 30, 2005, respectively.

 

(e) Excludes the mark-to-market impact of Generation’s economic hedging activities.

 

(f) Represents the average for the quarter.

 

25

ComEd

Electric Sales Statistics and Revenue Detail

Full service reflects deliveries to customers taking electric service under tariffed rates. The power purchase option (PPO) allows the purchase of electricity from ComEd at market-based prices. Delivery only service reflects customers electing to receive generation service from an alternative supplier. Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

 

     2006     2005    2004

Retail Deliveries (in GWhs)

        

Full service

        

Residential

      28,330       30,042      26,463

Small Commercial & Industrial

      24,122       21,378      21,662

Large Commercial & Industrial

      10,336       7,904      6,913

Public Authorities & Electric Railroads

      2,254       2,133      1,893
                     

Total Full Service

      65,042       61,457      56,931
                     

PPO

        

Small Commercial & Industrial

      2,475       5,591      4,110

Large Commercial & Industrial

      2,259       6,004      5,377
                     

Total PPO

      4,734       11,595      9,487
                     

Delivery Only

        

Small Commercial & Industrial

      5,505       5,677      6,305

Large Commercial & Industrial

      15,282       13,633      14,634
                     

Total Delivery Only

      20,787       19,310      20,939
                     

Total Retail Deliveries

      90,563       92,362      87,357

Electric Revenue (in millions)

        

Full Service

        

Residential

    $ 2,453     $ 2,584    $ 2,295

Small Commercial & Industrial

      1,882       1,671      1,649

Large Commercial & Industrial

      563       408      380

Public Authorities & Electric Railroads

      137       132      126
                     

Total Full Service

      5,035       4,795      4,450
                     

PPO

        

Small Commercial & Industrial

      178       385      274

Large Commercial & Industrial

      137       345      304
                     

Total PPO

      315       730      578
                     

Delivery Only

        

Small Commercial & Industrial

      85       95      128

Large Commercial & Industrial

      155       156      204
                     

Total Delivery Only

      240       251      332
                     

Total Electric Retail Revenues

      5,590       5,776      5,360
                     

Wholesale and Miscellaneous Revenues

      516       488      443

Mark-to-market Contracts

      (5 )     —        —  
                     

Total Operating Revenues

    $ 6,101     $ 6,264    $ 5,803

Electric Revenue ($ / MWh)

        

Full Service

        

Residential

    $ 86.59     $ 86.01    $ 86.72

Small Commercial & Industrial

      78.02       78.16      76.12

Large Commercial & Industrial

      54.47       51.62      54.97

Public Authorities & Electric Railroads

      60.78       61.88      66.56
                     

Total Full Service

      77.41       78.02      78.16
                     

PPO

        

Small Commercial & Industrial

      71.92       68.86      66.67

Large Commercial & Industrial

      60.65       57.46      56.54
                     

Total PPO

      66.54       62.96      60.93
                     

Delivery Only

        

Small Commercial & Industrial

      15.44       16.73      20.30

Large Commercial & Industrial

      10.14       11.44      13.94
                     

Total Delivery Only

      11.55       13.00      15.86
                     

Total Electric Retail Revenues

    $ 61.72     $ 62.54    $ 61.36

 

26

ComEd

Customers at Year End

 

      2006    2005    2004

Retail Delivery Customers

         
Full service         

Residential

    3,406,239    3,358,596    3,330,778

Small Commercial & Industrial

    333,577    324,984    321,994

Large Commercial & Industrial

    654    643    490

Public Authorities & Electric Railroads

    1,071    1,293    1,267

Street & Highway Lighting

    4,773    3,933    3,824

Wholesale

    4    4    4
              

Total Full Service Customers

    3,746,318    3,689,453    3,658,357
              
PPO         

Small Commercial & Industrial

    667    15,078    9,413

Large Commercial & Industrial

    45    614    598

Public Authorities

    0    0    0

Street & Highway Lighting

    0    1    1
              

Total PPO Customers

    712    15,693    10,012
              
Delivery Only         

Small Commercial & Industrial

    18,374    4,954    11,249

Large Commercial & Industrial

    1,226    629    900

Public Authorities

    0    0    0

Street & Highway Lighting

    3    0    0
              

Total Delivery Only

    19,603    5,583    12,149
              

Total Retail Delivery Customers

    3,766,633    3,710,729    3,680,518
Heating and Cooling Degree Days         
     2006    2005    2004

Heating Degree Days (normal=6,498)

    5,589    6,083    6,053
              

Cooling Degree Days (normal=830)

    931    1,166    615
              
Peak System Load         
     2006    2005    2004
Summer         

Highest Peak Load (MW)

    23,613    21,635    19,794
              
Winter         

Highest Peak Load (MW)

    16,207    16,081    15,222
              

 

27

PECO

Electric Sales Statistics and Revenue Detail

Full service reflects deliveries to customers taking electric service under tariffed rates. Delivery only service reflects customers electing to receive generation service from an alternative supplier. Wholesale and miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

 

     2006    2005    2004

Retail Deliveries (in GWhs)

         

Full Service

         

Residential

      12,796      13,135      10,349

Small Commercial & Industrial

      7,818      7,263      6,728

Large Commercial & Industrial

      15,898      15,205      14,908

Public Authorities & Electric Railroads

      906      962      914
                    

Total Full Service

      37,418      36,565      32,899
                    

Delivery Only

         

Residential

      61      334      2,158

Small Commercial & Industrial

      671      1,257      1,687

Large Commercial & Industrial

      35      503      760
                    

Total Delivery Only

      767      2,094      4,605
                    

Total Retail Deliveries

      38,185      38,659      37,504

Electric Revenue (in millions)

         

Full Service

         

Residential

    $ 1,780    $ 1,705    $ 1,317

Small Commercial & Industrial

      943      818      756

Large Commercial & Industrial

      1,286      1,173      1,113

Public Authorities & Electric Railroads

      83      84      80
                    

Total Full Service

      4,092      3,780      3,266
                    

Delivery Only

         

Residential

      5      25      164

Small Commercial & Industrial

      36      63      86

Large Commercial & Industrial

      1      13      20
                    

Total Delivery Only

      42      101      270
                    

Total Electric Retail Revenues

      4,134      3,881      3,536
                    

Wholesale and Miscellaneous Revenues

      238      212      203
                    

Total Operating Revenues

    $ 4,372    $ 4,093    $ 3,739

Electric Revenue ($ / MWh)

         

Full Service

         

Residential

    $ 139.11    $ 129.81    $ 127.26

Small Commercial & Industrial

      120.62      112.63      112.37

Large Commercial & Industrial

      80.89      77.15      74.66

Public Authorities & Electric Railroads

      91.61      87.32      87.53
                    

Total Full Service

      109.36      103.38      99.27
                    

Delivery Only

         

Residential

      81.97      74.85      76.00

Small Commercial & Industrial

      53.65      50.12      50.98

Large Commercial & Industrial

      28.57      25.84      26.32
                    

Total Delivery Only

      54.76      48.23      58.63
                    

Total Electric Retail Revenues

    $ 108.26    $ 100.39    $ 94.28

 

28

PECO

Customers at Year End

 

      2006    2005    2004

Retail Delivery Customers

         

Full service

         

Residential

    1,386,554    1,381,426    1,334,169

Small Commercial & Industrial

    124,801    117,663    100,631

Large Commercial & Industrial

    3,092    3,087    2,863

Public Authorities & Electric Railroads

    1,024    1,006    995
              

Total Full Service Customers

    1,515,471    1,503,182    1,438,658
              

Delivery Only

         

Residential

    5,096    8,687    49,134

Small Commercial & Industrial

    29,252    35,735    52,057

Large Commercial & Industrial

    7    32    259
              

Total Delivery Only Customers

    34,355    44,454    101,450
              

Total Retail Delivery Customers

    1,549,826    1,547,636    1,540,108
Heating and Cooling Degree Days         
     2006    2005    2004

Heating Degree Days (normal=4,759)

    3,924    4,758    4,661
              

Cooling Degree Days (normal=1,235)

    1,314    1,539    1,272
              
Peak System Load         
     2006    2005    2004

Summer

         

Highest Peak Load (MW)

    8,932    8,626    7,567
              

Winter

         

Highest Peak Load (MW)

    6,056    6,550    6,838
              

 

29

PECO

Gas Sales Statistics, Revenue and Customer Detail

 

     2006    2005    2004

Deliveries to Customers (in mmcf)

         

Retail Sales

      50,578      59,751      59,949

Transportation

      25,527      25,310      27,148
                    

Total Retail Deliveries

      76,105      85,061      87,097
                    

Gas Revenue (in millions)

         

Retail Sales

    $ 770    $ 783    $ 702

Transportation

      16      16      18

Resales and Other

      10      18      28
                    

Total Gas Revenue

    $ 796    $ 817    $ 748
                    
Gas Customers at Year End         
     2006    2005    2004

Customers

         

Residential

      434,119      430,753      423,858

Small Commercial & Industrial

      40,519      40,293      39,803

Large Commercial & Industrial

      400      379      371

Transportation

      518      561      585
                    

Total Customers

      475,556      471,986      464,617
                    
Gas Maximum Day Sendout         
     2006    2005    2004

Winter

         

Maximum Day Sendout (in thousand cubic feet (mcf))

      553,083      712,704      699,494
                    

 

30

Press Release

Exhibit 99.3

LOGO

 

Contact:

    Chaka Patterson    FOR IMMEDIATE RELEASE
   Investor Relations   
   312-394-7234   
   Jennifer Medley   
   Corporate Communications   
   312-394-7189   

Exelon Announces Share Buyback;

Revises Full Year 2007 Operating Earnings Guidance

CHICAGO (September 4, 2007) – Exelon Corporation today announced that its board of directors has approved a share repurchase program for up to $1.25 billion of its outstanding common stock. Exelon expects to complete the share repurchase program within the next six months.

“We have robust cash flows and an increasingly strong balance sheet. We remain committed to returning cash to shareholders through our value return policy, while maintaining appropriate financial flexibility to make sound investments in our businesses and take advantage of opportunities that may arise,” said John W. Rowe, Exelon’s chairman, president and CEO.

The Exelon board of directors approved Exelon’s value return policy on December 5, 2006. This policy established a base dividend that Exelon expects will grow modestly over time. It also contemplates the use of share repurchases from time to time, when authorized by the board of directors, to return cash or balance sheet capacity to Exelon shareholders after funding maintenance capital and other commitments and in the absence of higher value-added growth opportunities.

The Board authorization permits the company to effect the repurchases from time to time through a variety of methods including open market repurchases, privately negotiated transactions and/or accelerated share repurchase transactions. There can be no assurance as to the amount, timing or prices of repurchases. The specific timing and amount of repurchases will vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the board of directors at any time.

2007 Earnings Outlook

Exelon revised its adjusted (non-GAAP) operating earnings guidance range for 2007 to $4.15 to $4.30 per share. Exelon’s original operating earnings guidance range was $4.00 to $4.30.

 

1

“With half a year of strong performance behind us, we are revising our 2007 operating earnings guidance to the upper half of our original guidance range,” said Rowe.

The following table indicates revised guidance ranges by operating company contribution to 2007 adjusted (non-GAAP) operating earnings per Exelon share, excluding Exelon holding company:

 

Generation:

    $ 3.45 to $3.55

ComEd:

    $ 0.20 to $0.25

PECO:

    $ 0.65 to $0.70

The outlook for 2007 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items included in GAAP earnings:

 

  •  

costs associated with the Illinois electric rate settlement, including ComEd’s previously announced customer Rate Relief and Assistance Initiatives;

 

  •  

mark-to-market adjustments from economic hedging activities

 

  •  

investments in synthetic fuel-producing facilities

 

  •  

significant impairments of intangible assets, including goodwill

 

  •  

significant changes in decommissioning obligation estimates

 

  •  

other unusual items

 

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any future changes to GAAP

In consideration of these factors, Exelon reaffirmed 2007 GAAP earnings guidance of $3.70 to $4.00 per share. Both Exelon’s adjusted (non-GAAP) operating earnings and GAAP earnings guidance are based on the assumption of normal weather.

Rowe will discuss the share buyback and 2007 earnings guidance today at the Lehman Brothers CEO Energy/Power Conference in New York City. His presentation will be Web cast live at 2:25 p.m. Eastern time. To view the Web cast, go to www.exeloncorp.com and select the Investor Relations page.

This news release 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 2006 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 2007 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this news release. None of the Companies undertakes any obligation

 

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to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this news release.

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Exelon Corporation is one of the nation’s largest electric utilities with approximately 5.4 million customers and more than $15 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in Illinois and Pennsylvania and natural gas to more than 480,000 customers in southeastern Pennsylvania. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

 

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