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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

March 6, 2008

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 March 6, 2008, Exelon Corporation (Exelon) will participate in the UBS Natural Gas, Electric Power and Coal Conference and will reaffirm its adjusted (non-GAAP) operating earnings guidance ranges for 2008 for Exelon, Exelon Generation Company, LLC (Generation), Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO). Exelon will also reaffirm its GAAP earnings guidance range for 2008 for Exelon. Attached as Exhibit 99.1 to this Current Report on Form 8-K is the investor handout to be used at the conference.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

 

(d) Exhibits.

 

Exhibit No.

   

Description

99.1    Investor handout

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Generation, ComEd and PECO (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 2007 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 19; and (2) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

 

EXELON CORPORATION
EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger
Senior Vice President and Chief Financial Officer
Exelon Corporation
COMMONWEALTH EDISON COMPANY

/s/ Robert K. McDonald

Robert K. McDonald

Senior Vice President, Chief Financial Officer,

Treasurer and Chief Risk Officer

Commonwealth Edison Company
PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett
Senior Vice President and Chief Financial Officer
PECO Energy Company

March 6, 2008

EXHIBIT INDEX

 

Exhibit No.

   

Description

99.1    Investor handout
Investor handout
UBS Natural Gas, Electric Power &
Coal Conference
Lost Pines, TX
March 6, 2008
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 2007 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 19; and (2) 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 Companies. Please refer to the appendix to the
presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings.

3
’07 Earnings:
$2,331M 
’08E Earnings:
$2,060 -
$2,260M
’07 EPS:
$3.45
’08E EPS:
$3.15 -
$3.45
Total Debt
(1)
:
$2.5B
Credit Rating
(2)
:
BBB+
The Exelon Companies
Nuclear, Fossil, Hydro & Renewable Generation
Power Marketing
‘07 Operating Earnings:
$2.9B
‘07 EPS:
$4.32
‘08E Operating Earnings:
$2.6
-
$2.9B
‘08 EPS Guidance:
$4.00
-
$4.40
Assets
(1)
:                        
$45.9B
Total Debt
(1)
:
$13.7B
Credit Rating
(2)
:                            BBB
Note: All estimates represent adjusted (Non-GAAP) Operating Earnings and EPS. Exelon Generation, ComEd and PECO estimates represent expected contribution to  
Exelon’s operating earnings EPS (per Exelon share). Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(1)
As of 12/31/07.
(2)
Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 2/29/08.
Pennsylvania
Utility
Illinois
Utility
’07 Earnings:
$200M
$507M
’08E Earnings:
$220 -
$260M
$360 -
$400M
’07 EPS:
$0.30
$0.75
’08E EPS:
$0.35 -
$0.40
$0.55 -
$0.60
Total Debt
(1)
:
$5.2B
$3.8B
Credit Ratings
(2)
:
BBB
A

4
Multi-Regional, Diverse Company
Note: Megawatts based on Generation’s ownership as of 12/31/07,
using annual mean ratings for nuclear units (excluding Salem) and
summer ratings for Salem and the fossil and hydro units.
Midwest Capacity
Owned:
11,388 MW
Contracted:
4,271 MW
Total:
15,659 MW
ERCOT/South Capacity
Owned:
2,222 MW
Contracted:
2,917 MW
Total:
5,139 MW
New England Capacity
Owned:
194MW
Total Capacity
Owned:
24,808 MW
Contracted:
7,524 MW
Total:
32,332 MW
Electricity Customers:
1.6M
Gas Customers: 
0.5M
Electricity Customers:  3.8M
Generating Plants             
Nuclear
Hydro
Coal/Oil/Gas Base-load
Intermediate
Peaker
Mid-Atlantic Capacity
Owned:
11,004 MW
Contracted:
336 MW
Total:
11,340 MW

5
2008 Outlook
2008
(1)
$0.55 -
$0.60
$3.15 -
$3.45
$4.00 -
$4.40
$0.35 -
$0.40
2008 EPS Guidance
(1)
Operating
EPS:
$4.00
-
$4.40
GAAP
EPS:
$3.70
-
$4.10
ComEd
PECO
Exelon Generation
HoldCo/Other ~$(0.10)
Exelon
(1)
Refer
to
Appendix
for
“Key
Assumptions”
slide
supporting
2008
earnings
guidance.
Operating
Company
ranges
do
not
add
to
Exelon
guidance
of
$4.00 -
$4.40/share due to rounding.
Key Drivers 2007 –
2008
Market conditions
Nuclear volume
Inflationary pressures
PECO CTC amortization
Weather
Load growth
ComEd transmission settlement
ComEd distribution rate case
26-29%
26-29%
21-24%
21-24%
4Q08
3Q08
2Q08
1Q08
Expected Quarterly EPS Distribution
We expect first quarter 2008 operating earnings to represent 21-24% of Exelon’s 2008
full year operating earnings.

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

7
3-4%
$1,000
$1,040
2-3%
$1,020
$1,083
1-2%
$390
$339
2-3%
$650
$630
Exelon
(1)
NM
(2)
NM
(2)
~15%
2008-2012 CAGR
$3,120
$870
$730
2008E
$2,674
$696
$573
2007
Other
Nuclear
Fuel
CapEx
2-3%
2-3%
2008-2012 CAGR
$4,270
$2,620
2008E
$4,203
$2,469
2007
Exelon
(1)
O&M
Note:  Reflects operating O&M data and excludes Decommissioning impact.
(1)  Includes eliminations and other corporate entities.
(2)  Due to varying capital investment for the period 2008-2012, the CAGR is not meaningful.
($ in Millions)
O&M and CapEx Expectations
($ in Millions)

8
Disciplined Financial Management
•
Announced a new Value Return Policy in December 2006
–
Established annual base dividend of $1.76/share; anticipated to grow
modestly over time
–
Returns excess cash and/or balance sheet capacity through share
repurchases
•
Executed a $1.25 billion accelerated share repurchase agreement in
September 2007
Announced in December 2007:
•
New share repurchase program of $500 million
–
Incremental to $1.25 billion buyback executed in September 2007
and to
any additional buybacks that may be authorized in 2008
•
Annual base dividend rate reset at $2.00/share
(up 14%); anticipated to
grow modestly over time
(1)
–
Higher base dividend reflects higher expected long-term earnings due to
improved market fundamentals
(1)
Future dividends are subject to declaration by the Board of Directors.
The
Value
Return
Policy
provides
flexibility
to
navigate
through
volatile
business
cycles, make prudent investments in our operations, and return value to investors

9
Balance Sheet Capacity
•
Growth opportunities
•
Future unfunded liabilities
•
Buffer against potentially lower
commodity prices
•
Share repurchases or other
value return options
(1)
Available
Cash
after
Dividend
=
Cash
Flow
from
Operations
-
CapEx
-
Dividends
+/-
Net
Financings.
Cash
Flow
from
Operations
=
Net
cash
flows
provided
by
operating
activities less net cash flows used in investing activities other than capital expenditures.  Net Financing (excluding Dividends) = Net cash flows used in financing activities
excluding dividends paid on common stock.  Assumes annualized dividend of $2.00 /share in 2008, growing 5% annually; actual amounts may vary, subject to board approval.
(2)
Available Cash after Dividend excludes any benefit from potential carbon impact .
(3)
See
“FFO
Calculation
and
Ratios”
definitions
slide
in
Appendix.
FFO
/
Debt
includes:
debt
equivalents
for
purchased
power
agreements,
unfunded
pension
and
other
postretirement
benefits
obligations,
capital
adequacy
for
energy
trading,
and
related
imputed
interest.
(4)
Provided solely to illustrate possible future outcomes that are based on a number of different assumptions, all of which are subject to uncertainties and should not be relied
upon as a forecast of future results.
2008
-
2012
Cumulative
Available
Cash
(Illustrative)
(4)
2008 -
2012 Potential Uses of
Available Cash
Exelon
expects
to
create
substantial
incremental
balance
sheet
capacity
over
the
next
five years, based on planning assumptions

10
ComEd and PECO
CTC
Electric Transmission
Electric Distribution
Gas
Numbers may not sum due to rounding
(1)
Illustrative.
Provided
solely
to
illustrate
possible
future
outcomes
that
are
based
on
a
number
of
different
assumptions,
all
of
which
are
subject
to
uncertainties
and
should
not
be
relied upon as a forecast of future results.
(2)
ComEd equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill).  Book equity ratio in 2007 was 58%.
(3)
ComEd 2008
estimated
operating
earnings
assume
full
$361M
revenue
increase
granted
in
current
distribution
rate
case.
6.0
6.6
8.0
1.8
2.0
2.2
$220 -
$260M
(3)
$200M
~5.5 -
6.5%
5.3%
45%
45%
7.8
8.6
~$460 -
$500M
~10 -
11%
~45%
2007E
2008E
2011
(1)
10.2
6.9
6.4
2007E
2008E
2011
(1)
4.9
~$245 -
$270M
~10 -
11%
~50%
$507M
Not applicable due to
transition rate structure
$360 -
$400M
Operating Earnings
ROE
Equity
(2)
2007A
2007A
2.6
2.8
3.1
0.5
0.5
0.6
2.7
2.0
1.1
1.1
1.2
Average Annual Rate Base
($ in Billions)

11

12
ComEd 2008 Operating EPS Contribution
ComEd’s operating earnings are expected to increase in 2008 primarily due to execution
of its Regulatory Recovery Plan
2007
$200M
RNF
O&M
Depreciation /
Amortization
Interest
Expense
Other
$0.35 -
$0.40
$0.30
$0.19
$0.04
($0.02)
$(0.03)
2008
(1)
$220M -
$260M
(2)
$(0.08)
Key Items:
Storms: $0.03
Uncollectible accounts: $0.02
($0.04)
Weather
$ / Share
NOTE:
Refer
to
“Key
Assumptions”
slide
in
Appendix.
(1)
Estimated contribution to Exelon’s operating earnings guidance.
(2)
Assumes full $361M revenue increase granted in current distribution rate case and effective 10/1/08.
Key Items:
Distribution
case
(2)
:
$0.09
Transmission revenue: $0.04
Load growth: $0.03
Key Items:
Income tax settlements: $(0.07)

13
(1) Based on 2006 test year, including pro forma capital additions through 3Q 2008; represents a $1,550 million increase from 2006 ICC order.
(2) Includes increased depreciation expense associated with capital additions.
(3)
Requested
cap
structure
does
not
include
goodwill;
ICC
docket
05-0597
allowed
10.045%
ROE,
42.86%
equity
ratio
and
8.01%
ROR
(return
on
rate
base).
(4) Primarily includes increases in pension and other post-retirement benefits costs and effects of a reclassification of rental revenue of $20 million, which is offset in “Other
adjustments”.
(5) Includes taxes other than income, regulatory expenses, and reductions for other revenues and load growth.
(6) Or approximately $359 million adjusted for normal weather.
ComEd Delivery Service Rate Case Filing
(Docket No. 07-566)
$361
(6)
Total ($2,049 revenue requirement)
$(51)
Other adjustments
(5)
$48
O&M expenses
$99
Administrative
&
General
expenses
(4)
$50
Capital
Structure
(3)
:
ROE
-
10.75%
/
Common
Equity
-
45.11%
/
ROR
-
8.55%
$215
(2)
Rate Base: $7,071
(1)
Requested Revenue
Requirement Increase
($ in millions)
Revenue increase needed to recover significant distribution system investment and
represents an important step in ComEd’s regulatory recovery plan

14
ComEd Delivery Service Rate Case –
Schedule
•
Filed: October 17, 2007
•
Staff
&
Intervenor
Direct
Testimony:
February
11,
2008
Staff proposal:
–
$112 million revenue increase
–
$5.7 billion rate base
–
Common equity ratio: 45.04%, ROE: 10.30%, ROR: 8.34%
•
ComEd Rebuttal Testimony: March 12
•
Staff
&
Intervenor
Rebuttal
Testimony:
April
8
•
ComEd Surrebuttal Testimony: April 21
•
Hearings: April 28 -
May 5
•
Initial Briefs: May 29
•
Reply Briefs: June 12
•
Administrative Law Judge (ALJ) Order expected: July
•
Final Illinois Commerce Commission (ICC) Order expected: September
2008

15
15
15
ComEd Transmission Rate Case
($ in millions)
FERC Filing
3/1/07
Preliminary Order
6/5/07
FERC Orders
1/08
(1)
Total Revenue Requirement (in year 1)
$415
$387
$390
(2)
Revenue Requirement increase (in year 1)
$146
$116
(3)
$120
Rate Base (in year 1)
$1,826
$1,744
$1,847
(4)
Common Equity Ratio
58%
58%
58%
(5)
Return on Equity (ROE)
(6)
12.20%
11.70% + 0.50% RTO adder
12.20%
11.70% + 0.50% RTO adder
11.50%
11.0% + 0.50% RTO adder
Return on Rate Base (ROR)
9.87%
9.87%
9.40%
(1) Settlement agreement filed 10/5/07, approved by FERC on 1/16/08.  Also, on 1/18/08
FERC granted request on rehearing for incentive on West Loop Phase II project.
(2) Includes settlement increase of $93 million + project incentives of $27 million, eff. 5/1/07.
(3) Rates under preliminary order effective 5/1/07, subject to refund. 
(4) Excludes pension asset; 6.51% debt return allowed in operating expenses,
includes $175 million construction work in progress (CWIP) for West Loop project.
(5) Equity cap of 58% for 2 years, declining to 55% by 2011.
(6) ROE is fixed and not subject to annual updating. 
RTO = Regional Transmission Organization
(Docket Nos. ER07-583-000 & EL07-41-000)
Rate settlement establishes reasonable framework for timely recovery of transmission
investment on an annual basis through formula rates

16
16
Formula Transmission Rate Annual
Update Process
•
Annual filing by May 15th will update the current year revenue
requirement and true-up prior year to actual:
–
Update current year
–
Estimate current year revenue requirement using updated costs based on prior year actual
data per FERC Form 1 plus projected plant additions for the current calendar year
–
True-up prior year
–
Perform a true-up of the prior year’s rates by comparing prior year actual data per FERC
Form 1 to the estimate used for that year; over/under-recoveries for the prior year are
collected in the current year
•
Rates take effect on June 1st
•
Interested parties have 180 days to submit information requests
and  raise concerns; unresolved concerns go before FERC for
resolution
The combination of annual updating and true-up virtually eliminates regulatory lag

17
Financial Swap Agreement
•
Financial Swap Agreement between ComEd and Exelon Generation
promotes price stability for residential and small business customers
•
Designed to dovetail with ComEd’s remaining auction contracts for energy,
increasing in volume as the auction contracts expire
–
Will cover about 60% of the energy that ComEd’s residential and small
business customers use
•
Includes ATC baseload
energy only
–
Does not include capacity, ancillary services or congestion
3,000
$53.48
January
1,
2013
-
May
31,
2013
3,000
$52.37
January
1,
2012
-
December
31,
2012
3,000
$51.26
January
1,
2011
-
December
31,
2011
3,000
$50.15
June
1,
2010
-
December
31,
2010
2,000
$50.15
January
1,
2010
-
May
31,
2010
2,000
$49.04
June
1,
2009
-
December
31,
2009
1,000
$49.04
January
1,
2009
-
May
31,
2009
1,000
$47.93
June
1,
2008
-
December
31,
2008
Notional Quantity (MW)
Fixed Price ($/MWH)
Portion of Term

18

19
PECO 2008 Operating EPS Contribution
PECO’s operating earnings are expected to decrease in 2008 primarily due to
increasing CTC amortization expense
2007
$507M
2008
(1)
$360M -
$400M
$0.75
($0.08)
$0.01
($0.03)
($0.06)
$0.55 -
$0.60
RNF
O&M
CTC
Amortization /
Depreciation
Other
NOTE:
Refer
to
“Key
Assumptions”
slide
in
Appendix.
(1)  Estimated contribution to Exelon’s operating earnings guidance.
($0.03)
Weather
$0.02
Interest
Expense
$ / Share
Key Items:
Tax settlements: $(0.08)

20
Pennsylvania Snapshot
•
Governor Rendell’s “Energy Independence Strategy”,
introduced in February 2007, continues to be focus of
legislative activity. 
Legislation aimed at reducing energy costs, increasing
clean energy resources, reducing reliance on foreign
fuels, expanding energy production in PA
Comprehensive bills dealing with procurement, and
rate mitigation remain in committee
Modest action on other key bills: Energy Fund bill
passed in Senate; House passed an Efficiency
/Demand-side Response bill.
•
Special Session on Energy runs concurrent with Regular
Session which continues thru Nov ’08.
Current State of Play
•
Governor continues to press for “Energy Independence
Fund”
and measures to mitigate energy prices
•
Legislators concerned with cost of Governor's initiatives, no
new taxes
•
Rate freeze bill being considered in House, but little
momentum
•
Industry coalition working together to develop a
comprehensive package
Positions of Stakeholders
•
Stakeholder outreach
•
Working with industry coalition
•
Negotiating legislative proposals with
Administration and legislative leadership
on key provisions:
Procurement rules
Rate increase phase-in/deferral
Smart meters and real time pricing
Energy efficiency and demand-side
management programs
•
Participating directly or through industry
associations in legislative hearings and
informational meetings
PECO Actions

21
Key Themes of Legislative Proposals
Competitive procurement process utilizing auctions, RFPs, spot purchases
and bilateral contracts, with provisions for long-term supply contracts
Full and current cost recovery for default service provider (DSP)
Largest industrial customers may negotiate terms and rates for retail supply
with DSP, subject to PUC review
DSP
must
offer
residential
and
small
commercial
customers
a
rate
that
changes
no
more
frequently
than
annually
with
reconciliation
for
under
or
over-recovery
Must file a rate phase-in plan for all customers; cap annual increases for
defined period and defer any excess for future recovery over additional
defined period
Phase-in
plans
-
both
pre
and
post
-
are
to
be
opt-in
for
customer,
provide
utility and/or customer with recovery of carrying costs on pre-pay and/or
deferred balance
Securitization of deferred balance and carrying charges authorized
Establish
minimum
usage
reduction
and
peak
load
reduction
targets
Competing legislative proposals call for either DSP-run programs or
State-wide
Program
Administrator
with
network
of
3
party
suppliers
Cost cap proposed, with DSP authorized to fully recover expenses
Full deployment of smart meters within 9-10 years
Full
recovery
for
net
costs
of
smart
meter
deployment
through
base
rates
or
through automatic recovery mechanism
Must submit a time-of-use rate plan with voluntary customer participation by
the end of rate cap period
Procurement
Smart Meters
Rate Phase-in
Program
Demand Side
Response & Energy
Efficiency (DSR/EE)

22
2.63
2.63
0.48
0.48
2.41
6.00
10.54
PECO Average Electric Rates
(1)
System
Average
Rates
based
upon
Restructuring
Settlement
Rate
Caps
on
Energy
and
Capacity
increased
from
original
settlement
by
1.6%
to
reflect
the
roll-in
of
increased
Gross
Receipts
Tax
and
$0.02/kWh
for
Universal
Service
Fund
Charge
and
Nuclear
Decommissioning
Cost
Adjustment.
System
Average
Rates
also
adjusted
for
sales
mix
based
on
current
sales
forecast.
Assumes
continuation
of
current
Transmission
and
Distribution
Rates.
(2)
Energy/Capacity
Price
is
an
average
of
the
results
for
residential
(10.51¢/kWh)
and
small
commercial
customers
(10.58¢/kWh)
from
the
second
round
of
PPL
Auction held 10/07.  Assumes continuation of current Transmission and Distribution Rates.
2011
2008 –
2010
Energy / Capacity
Competitive Transition
Charge (CTC)
Transmission
Distribution
11.52¢
(1)
Unit Rates (¢/kWh)
+18%
13.65¢
(2)
CTC terminates at year-end 2010
Energy / Capacity price expected
to increase; price will reflect
associated full requirements
costs
Using latest PPL auction for
2010 as a proxy (10.5¢/kWh)
results in a system average
rate increase of ~18%
PECO’s 2011 full requirements
price expected to differ from PPL
due, in part, to the timing of the
procurement and locational
differences
Rates will vary by customer class
and will depend on legislation and
approved procurement model
Post Transition
Electric Restructuring
Settlement
Projected Rate Increase
Based on PPL Auction
Results  (Illustrative)

23

24
Exelon Generation 2008 Operating EPS
Contribution
Exelon Generation’s 2008 earnings are impacted primarily by increased planned refueling
outages and higher nuclear fuel expense
2007
$2,331M
2008
(1)
$2,060M -
$2,260M
($0.09)
$(0.15)
$0.13
$3.15 -
$3.45
RNF
O&M
Other
(2)
$30M
+/-
500 Btu/KWh ATC Heat Rate
$5.5M
+/-
$1/mmBtu Gas
2008
Market Sensitivities  (After-Tax)
Depreciation
$(0.02)
$3.45
$ / Share
NOTE:
Refer
to
“Key
Assumptions”
slide
in
Appendix.
(1)  Estimated contribution to Exelon’s operating earnings guidance.
(2)  Primarily reflects the change in shares outstanding.
Key Items:
Nuclear volume: $(0.10)
Nuclear fuel expense: $(0.06)
State Line buyout: $(0.03)
Market / portfolio: $0.12
Interest
Expense
$(0.03)
Key Items:
Inflation: $(0.07)
Add’l
refueling outages: $(0.06)
Nuclear security: $(0.02)

25
•
Large, low-cost, low-emissions,
exceptionally well-run nuclear fleet
•
Complementary and flexible fossil and
hydro fleet
•
Improving power market fundamentals
(commodity prices, heat rates, and
capacity values)
•
End of below-market contracts in
Pennsylvania beginning 2011
•
Potential carbon restrictions
Value Proposition
Exelon Generation
•
Continue to focus on operating excellence,
cost management, and market discipline
•
Support competitive markets
•
Pursue nuclear & hydro plant license
extension and strategic investment in
material condition
•
Maintain industry-leading talent
Protect Value
•
Pursue nuclear plant uprates (~200MW by
2012) and investigate potential for more
•
Pursue nuclear Construction and
Operating License in Texas
•
Capture increased value of low-carbon
generation portfolio
Grow Value
Exelon
Generation
is
the
premier
unregulated
generation
company
–
positioned
to
capture market opportunities and manage risk

26
World-Class Nuclear Operator
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Exelon
Industry
Note: Exelon data prior to 2000 represent ComEd-only nuclear fleet.
Sources:
Platt’s,
Nuclear
News,
Nuclear
Energy
Institute
and
Energy
Information
Administration
(Department
of
Energy).
EXC 93.5%
(1)
(1) Exelon values represent 2003-2007 period.
Average Capacity Factor
Range of Fleet 2-Yr Avg Capacity Factor (2002-2006)
Sustained production excellence
65
70
75
80
85
90
95
100
Operator (# of Reactors)
Range
5-Year Average

27
-15%
-10%
-5%
0%
5%
10%
15%
20%
25%
30%
2007
2008
2009
2010
2011
2012
PJM-West
PJM-East
NI-Hub
ERCOT
NYMEX
(1)
Positively Exposed to Market Dynamics
Note:  Illustrative estimate. Overnight, all-in capital cost without interest during construction.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
0
5
10
15
20
25
30
35
40
45
0
5
10
15
20
25
30
Carbon Credit ($/Tonne)
Various
3rd
party
estimates
New Generation Installed Cost
Combined Cycle
Gas Turbine
Coal
Nuclear
0
500
1,000
1,500
2,000
2,500
3,000
2006
2007
2006
2007
2006
2007
(1)
As of 2/28/08.
Reserve Margins Declining
Natural Gas Prices Remaining High
Construction Costs Escalating
Carbon Legislation Progressing
Europe Carbon-Trading
2012: $36.10/tonne
Bingaman-Specter
2012: $12/tonne
EIA Carbon Case
2010: $31/tonne
Lieberman-Warner
Possible $20 to $40/tonne
$5
$6
$7
$8
$9
$10
2008
2010
2012
2014
2016
2018
2020

28
2008 “Open”
EBITDA
2008 EBITDA
2008 Un-hedged EBITDA
(No Carbon)
$ Millions
$4,119
~$3,900
2007 EBITDA
(1)
Un-hedged EBITDA assumes that existing hedges (including the PECO load, Illinois auction load, ComEd financial swap, and other sales) are priced at market prices as of 7/31/07.
(2)
1 tonne = 2,205 lbs.
Note: Refer to Appendix for EBITDA reconciliation slide.
~$5,350
169.10
Eastern MAAC Capacity Price ($/MW-day)
82.40
Rest-of-Market Capacity Price ($/MW-day)
5.60
NI-Hub Implied Heat Rate (mmBtu/MWh)
6.60
PJM W-Hub Implied Heat Rate (mmBtu/MWh)
47.00
NI-Hub ATC Price ($/MWh)
62.90
PJM W-Hub ATC Price ($/MWh)
8.50
Henry Hub Gas Price ($/mmBtu)
2008 Un-hedged EBITDA
(1)
Assumptions
~$1,000M
+ $10/Tonne Carbon Price
(2)
~$80M
+/-
$10/MW-Day Capacity Price
~$750M
+/-
500 Btu/KWh ATC Heat Rate
~$560M
+/-
$1/mmBtu Gas Price
(Pre-Tax Impact)
2008 Un-hedged EBITDA
(1)
Sensitivities
$2,060 -
$2,260
Operating
Earnings:
$2,331
Hedged –
2007A
Hedged –
2008E
Un-hedged –
2008E
(1)
Un-hedged (“Open”) EBITDA plus upside from energy, capacity, and carbon drives
Exelon Generation’s value

29
2009 –
2012 Earnings Drivers
End of PECO PPA (2011+)
Carbon (2012+)
Market conditions  
-
Heat rate
-
Capacity prices
-
New build costs
Nuclear uprates
Higher O&M costs
Higher nuclear fuel costs
Higher interest and
depreciation expense
2008 Earnings Drivers
Market conditions
-
Capacity prices
-
Marginal losses
More nuclear outages
Higher nuclear fuel costs
Higher O&M costs
State Line buyout
Higher interest and
depreciation expense
Exelon Generation Operating Earnings
2007
(1)
2012
2008E
(1)
(1) 2007 and estimated 2008 contribution to Exelon operating earnings; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
$2,331M
$2,060M -
$2,260M
Exelon Generation is poised for significant earnings growth driven by improving market
fundamentals, the end of the Pennsylvania transition period, and
carbon legislation

30
Hedging Targets
(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
5
percentile
/
expected
gross
margin.
Power Team employs commodity hedging
strategies to optimize Exelon
Generation’s earnings:
•
Maintain length for opportunistic sales
•
Use cross commodity option strategies to
enhance hedge activities
•
Time hedging around view of market
fundamentals
•
Supplement portfolio with load following
products
•
Use physical and financial fuel products to
manage variability in fossil generation output
Target Ranges
50% -
70%
70% -
90%
90% -
98%
Above the
range*
Current Position
Upper end
of range
Midpoint of
range
Financial Hedging Range 
(1)
* Due to ComEd financial swap
Prompt Year
(2008)
Second Year
(2009)
Flexibility in our targeted financial hedge ranges allows us to be opportunistic while
mitigating downside risk
Third Year
(2010)

31
125
127
129
131
133
135
137
139
141
143
145
2004
2005
2006
2007
2008
2009
2010
2011
2012
7
8
9
10
11
12
13
Note:  Net nuclear generation data based on ownership interest; includes Salem.
•
18 or 24 months
•
Duration: ~24 days
Nuclear Refueling Cycle
•
2008 is an exception:
–
Salem steam generator
replacement
–
3 more outages than 2007
•
~2,600 GWh less than 2007
•
$100-$110M negative after-tax impact
2008 Refueling Outage Impact
0
5
10
15
20
25
30
35
40
45
2000
2001
2002
2003
2004
2005
2006
2007
Exelon (excludes Salem)
Industry
Actual
Target
Impact of Refueling Outages
Refueling Outage Duration
Nuclear Output
Based on the refueling cycle, we
will conduct 12 refueling outages
in 2008, versus 9 in 2007, and
10 to 11 in a typical year

32
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
2008
2009
2010
2011
2012
Effectively Managing Nuclear Fuel Costs
Enrichment
39%
Fabrication
17%
Nuclear Waste
Fund
22%
Tax/Interest
2%
Conversion
3%
Uranium
17%
0
200
400
600
800
1,000
1,200
1,400
2008
2009
2010
2011
2012
Nuclear Fuel Expense (Amortization + Spent Fuel)
Nuclear Fuel Capex
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2008
2009
2010
2011
2012
Exelon Average Reload Price
Projected Market Price (Term)
Note: Excludes costs reimbursed under the settlement agreement with the DOE.
Market
source:
UxC
composite
forecasts.
2008 –
2011:
100% hedged in volume
2012:
~40% hedged in volume
All charts exclude Salem, except Projected Total Nuclear Fuel Spend.
Projected Exelon Uranium Demand
Components of Fuel Expense in 2008
Projected Exelon Average Uranium Cost vs. Market
Projected Total Nuclear Fuel Spend

33
Market Price Sensitivities
~$60M
+/-
500 Btu/KWh ATC Heat Rate
~$10M
+/-
$1/mmBtu Gas Price
(Pre-Tax Impact)
2008 EBITDA Sensitivities
($80M)
($40M)
($20M)
($5M)
-
Expense (Pre-Tax Impact)
($335M)
($160M)
($100M)
($60M)
-
Capital Expenditures
2012
2011
2010
2009
2008
-
$50/lb
$40M
$15M
$10M
$5M
-
Expense (Pre-Tax Impact)
$280M
$85M
$30M
$20M
-
Capital Expenditures
2012
2011
2010
2009
2008
+ $50/lb
(1)
Excludes Salem.
Note: Refer to Appendix for EBITDA reconciliation slide.
Uranium Sensitivity
(1)

34
Total Portfolio Characteristics
41,350
41,100
23,200
23,100
5,100
120,000
125,100
0
50,000
100,000
150,000
200,000
250,000
2007A
2008E
Actual Hedges & Open Position
ComEd Swap
IL Auction
PECO Load
189,300
189,650
140,400
138,100
31,800
33,800
17,450
17,400
0
50,000
100,000
150,000
200,000
250,000
2007A
2008E
Forward / Spot Purchases
Fossil & Hydro
Nuclear
189,300
189,650
Total Supply (GWh)
Total Sales (GWh)
The value of our portfolio resides in our nuclear fleet

35
35
Reliability Pricing Model Auction
40.80
197.67
111.92
174.29
174.29
148.80
102.04
191.32
191.32
Rest of Market
Eastern MAAC
        MAAC + APS
                              MAAC
2007/2008
2008/2009
2009/2010
2010/2011
2007 / 2008
2008 / 2009
2009 / 2010
2010 / 2011
in MW
Capacity
(2)
Obligation
Capacity
(2)
Obligation
Capacity
(2)
Obligation
Capacity
(2)
Obligation
Rest of Market
16,000
(4)
6,600-6,800
14,500
(5)
6,600-6,800
12,700
4,750-4,950
(6)
12,700
0
Eastern MAAC
9,500
9,500-9,800
(3)
9,500
9,550-9,850
(3)
9,500
9,750-9,950
(3)
MAAC + APS
(7)
1,500
0
MAAC
11,000
9,300-9,500
(3)(8)
(1)  All values are approximate and not inclusive of wholesale transactions.
(2)  All
capacity
values
are
in
installed
capacity
terms
(summer
ratings)
located
in
the
areas.
(3)  EMAAC
obligation
consists
of
load
obligations
from
PECO
and
BGS.
The
PPL
obligation (7) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System.
begins January 2010 and ends December 2010.
(4) Removing State Line from the supply in October 2007 reduces this by 515 MW.
(5) 08/09 Capacity supply decreased due to roll-off of several purchase power agreements (PPAs).
(6) In 09/10, obligation is reduced due to roll-off of part of ComEd auction load obligation in May 2009.
(8) PECO PPA expires December 2010.
Region not applicable for this auction period
PJM RPM Auction ($/MW-day)
Exelon Generation Participation within PJM Reliability Pricing Model
(1)

36
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
0
5
10
15
20
25
30
35
40
45
0
5
10
15
20
25
30
Carbon Value
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
Assumes
Open
Position
(1)
Carbon Credit ($/Tonne)
(1) Carbon sensitivity excludes ComEd SWAP and upside of Kincaid/Elwood due to contract expiration in 2012.  Assumes below $45/tonne carbon cost, no carbon
reduction technology (e.g., sequestration) is economical.
(2) As of 2/29/08.
(3) The
EIA
Carbon
Stabilization
Case
(Case
4)
dated
March
2006,
EIA
report
number
SR/OIAF/2006-1.
(4)
Low
Carbon
Economy
Act
initial
“Technology
Accelerator
Payment”
(TAP)
price
in
2012.
Allowance
price
increases
at
5%
above
the
rate
of
inflation
thereafter.
Carbon Value
Climate change legislation is expected to drive substantial gross margin expansion
at Exelon Generation
Europe Carbon Trading
2012: $36.10/tonne
(2)
EIA Carbon Case
(3)
2010: $31/tonne
Lieberman-Warner
Possible $20 to $40/tonne
Bingaman-Specter
(4)
2012: $12/tonne

37
Potential Nuclear New Build
•
Intend to file Construction and Operating License (COL) for plant in
Texas by end of 2008
–
Preserves option to participate in Energy Policy Act incentives
•
Long-lead material for dual unit ESBWR has been reserved
–
Will
use
GE
Hitachi
Nuclear
Energy
Americas’
new
generation
of
reactor
technology
•
Texas
is
attractive
market
for
new
nuclear
–
selected
site
in
Victoria
County
–
Growing demand for baseload power, robust market prices
–
State and local support for new nuclear
–
Existing Exelon presence in Texas
•
Exelon’s phased approach allows for go/no-go decisions at major
funding/commitment milestones
•
Exelon’s conditions for new build remain unchanged: the
economics must be right
Nuclear new build would capitalize on improving fundamentals, high gas prices,
and Exelon’s core strength in nuclear operations

38
Energy Policy Act –
Nuclear Incentives
•
$18 per MWh, 8 year PTC for first
6,000 MWe of new capacity
•
Cap of $125M per 1,000 MWe of
capacity per year
•
Protects against a decrease in
market prices and revenues earned
•
Benefit will be allocated/ prorated
among those who:
–
File COL by year-end 2008
–
Begin construction (first safety-
related concrete) by 1/1/2014
–
Place unit into service by
1/1/2021
Production Tax Credit (PTC)
•
Results in ability to obtain non-
recourse project financing
•
Up to 80% of the project cost,
repayment within 30 years or
90% of the project life
•
Timing of application subject to
DOE solicitations
•
Congress has granted authority
to issue guarantees totaling
$18.5B though 9/30/09
•
Cost of credit subsidy is still
uncertain
Government Loan
Guarantee
•
“Insurance”
protecting against
regulatory and litigation-related
delays in commissioning a
completed plant
•
Eligible costs include principal
and interest on debt coverage and
the incremental cost of
replacement power
–
First two reactors each
receive 100% of covered
costs up to $500M
–
The next four reactors each
receive 50% of covered costs
incurred after six months of
delay, up to $250M
Regulatory Delay
“Backstop”
Energy
Policy
Act
provides
financial
incentives
and
reduced
risk
by
way
of
production tax credits and loan guarantees

39
Current Market Prices
1.
2004, 2005, 2006 and 2007 are actual settled prices.
2.
Real Time LMP (Locational Marginal Price).
3.
Next day over-the-counter market.
4.
Average NYMEX settled prices.
5.
2008 information is a combination of actual prices through 2/29/08 and market prices for the balance of the year.
6.
2009 information is forward market prices as of 2/29/08.
Units
2004
1
2005
1
2006
1
2007
1
2008
5
2009
6
PRICES (as of February 29th, 2008)
PJM West Hub ATC
($/MWh)
42.35
2
60.92
2
51.07
59.76
74.29
75.06
PJM NiHub
ATC
($/MWh)
30.15
2
46.39
2
41.42
2
45.47
57.27
58.67
NEPOOL MASS Hub ATC
($/MWh)
52.13
2
76.65
2
59.68
2
66.72
84.37
85.17
ERCOT North On-Peak
($/MWh)
49.53
3
76.90
3
60.87
3
59.44
83.06
83.05
Henry Hub Natural Gas
($/MMBTU)
5.85
4
8.85
4
6.74
4
6.95
9.36
9.36
WTI Crude Oil
($/bbl)
41.48
4
56.62
4
66.38
4
69.72
98.80
98.37
PRB 8800
($/Ton)
5.97
8.06
13.04
9.67
15.82
17.01
NAPP 3.0
($/Ton)
60.25
52.42
43.87
47.54
76.44
77.06
ATC HEAT RATES (as of February 29th, 2008)
PJM West Hub / Tetco
M3
(MMBTU/MWh)
6.40
6.30
6.98
7.68
7.14
7.17
PJM NiHub
/ Chicago City Gate
(MMBTU/MWh)
5.52
5.52
6.32
6.65
6.10
6.25
ERCOT North / Houston Ship Channel
(MMBTU/MWh)
7.53
8.21
8.28
7.80
7.96
7.76
2

40
40
Market Price Snapshot
As of February 27, 2008. Source: OTC quotes and electronic trading system. Quotes are daily.  2008 prices are Mar-Dec.
Forward NYMEX Natural Gas
PJM-West and Ni-Hub On-Peak  Forward Prices
PJM-West On-Peak Implied Heat Rate
Ni-Hub On-Peak Implied Heat Rate
2008
2009
2009
2008
2008 PJM-West
2009 PJM-West
2009 Ni-Hub
2008 Ni-Hub
2008
2009
7.4
7.9
8.4
8.9
9.4
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08
8.84
9.04
9.24
9.44
9.64
9.84
10.04
10.24
10.44
10.64
10.84
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08
55
60
65
70
75
80
85
90
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08
7
7.2
7.4
7.6
7.8
8
8.2
8.4
8.6
8.8
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08

41
41
Market Price Snapshot
2008
2009
2008
2009
As of February 27, 2008. Source: OTC quotes and electronic trading system. Quotes are daily.  2008 prices are Mar-Dec.
2008
2009
Houston Ship Channel Natural Gas
Forward Prices
ERCOT North ATC Forward Prices
ERCOT North ATC v. Houston Ship Channel
Implied Heat Rate
7.1
7.6
8.1
8.6
9.1
9.6
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08
7.5
7.7
7.9
8.1
8.3
8.5
8.7
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08
58
60
62
64
66
68
70
72
74
Mar-
07
Apr-
07
May-
07
Jun-
07
Jul-
07
Aug-
07
Sep-
07
Oct-
07
Nov-
07
Dec-
07
Jan-
08
Feb-
08

42
Exelon –
Climate Change

43
Advancing Exelon’s Low-Carbon Strategy
•
Lobbying in favor of climate change legislation that is
national,
mandatory
and
economy-wide
•
Taking voluntary action to reduce our greenhouse gas (GHG)
emissions 8% from 2001 levels by 2008
•
Developing a comprehensive low-carbon energy strategy
–
Goal will be to reduce, displace or offset Exelon’s entire carbon footprint by 2020
–
Expanding our low-carbon resources
–
Providing customers with green products and services
–
Being a model of green operations

44
Recognized Environmental Leadership
•
Named
to
the
2006/2007
and
2007/2008
Dow
Jones Sustainability North America Index
•
Named to Climate Disclosure Leadership Index of the Carbon
Disclosure Project in 2005, 2006 and 2007
•
Signatory to the Global Roundtable on Climate Change and the
Ceres/Investor Network on Climate Risk statements
•
Member of the United States Climate Action Partnership (USCAP)
•
Corporate headquarters awarded Leadership in Energy and
Environmental
Design
(LEED
®
)
Platinum
Commercial
Interiors
certification by the U.S. Green Building Council

45
Exelon and Federal Climate
Change Legislation
•
Actively involved in the climate debate in Washington, D.C.
•
Lobbying in favor of enacting legislation that is national, mandatory
and
economy-wide
•
Favors a cap-and-trade system over a carbon tax
•
Believes that any allocation scheme should include allowances for
distribution companies to help offset the cost of carbon for the
end-user
•
To limit near-term economic impacts, supports a cost containment
mechanism
that
supports
a
market
price
for
carbon
that
increases
over
time

46
Reduction Goals

47
0
500
1000
1500
2000
2500
3000
3500
1990
1995
2000
2005
2010
2015
2020
2025
2030
Advanced Coal Generation
Distributed Energy Resources
Plug-In Hybrid Electric Vehicles
Carbon Capture & Storage
Nuclear Generation
Renewables
Efficiency
Technology
Source:  Electric Power Research Institute,  2007 Summer Seminar
CO2 Reductions Demand Multiple Generation
Technologies
EIA Base Case 2007
•
The technical potential exists
for the U.S. electricity sector
to significantly reduce CO2
emissions over the coming
decades
•
No one technology will be a
silver bullet –
a portfolio of
technologies will be needed
•
Much of the needed
technology is not available
yet –
substantial R&D,
demonstration, and
deployment are required
To
stabilize
emissions
at
1990
levels,
multiple
technologies
and
intensive
R&D
will be required

48
Status of Legislative Initiatives
•
Several pending Legislative proposals and vehicles are gaining support in
Washington:
–
Lieberman-Warner (S. 2191, America’s Climate Security Act of 2007)
•
Approved by U.S. Senate Environment and Public Works Committee
•
Slated for action by the full U.S. Senate in the Spring
•
Needs 60 votes to break expected filibuster and pass
•
Economy-wide:  All major GHG producing sectors
–
Seeks to reduce GHG to the 2005 level by 2012; phases to 70% below the 2005 level by 2050
–
Points
of
regulation:
Electric
power
sector
–
large
coal
generators;
Natural
gas
–
natural
gas
processors
and
importers;
Industrial
sector
–
large
facilities
emitting
more
than
10,000
tonnes
per
year
–
“Free”
allowances
include:
10%
to
states,
19%
to
generators
(phase
out
in
2031);
10%
to
industry;
9%
to
electric distribution companies, to benefit their customers; 2% to gas distribution companies, to benefit
their customers
–
Creates a Carbon Market Efficiency Board (“Carbon Fed”) with limited authority to oversee market
–
Dingell-Boucher White Papers
•
Scope of a Cap-and-Trade Program
•
Competitiveness Concerns/Engaging Developing Countries
•
Appropriate Roles for Different Levels of Government
•
More white papers in the works
•
Expect a draft bill sometime this summer
•
Dingell
has
characterized
the
issue
as
“the
hardest
thing
(he’s)
ever
dealt
with”
in
his
52+
years
in
Congress
•
Boucher says he is committed to enacting legislation this year
•
All the major Presidential contenders (McCain, Clinton and Obama) support
economy-wide, mandatory cap-and-trade legislation

49
Appendix

50
Key Assumptions
37.7
1.2
2.6
23.86
115.37
6.65
6.84
45.47
7.68
7.78
59.76
6.95
148,307
41,343
(5)
189,650
94.5
2007A
37.2
1.6
1.2
82.40
169.10
5.60
8.40
47.00
6.60
9.50
62.90
8.50
148,200
41,100
(5)
189,300
93.1
2008E
6.56
8.41
Chicago City Gate Gas Price ($/mmBtu)
7.31
9.67
Tetco M3 Gas Price ($/mmBtu)
37.0
37.5
Effective Tax Rate (%)
(4)
0.6
1.3
ComEd
1.2
0.9
PECO
Electric Delivery Growth (%)
(3)
1.75
0.13
PJM West Capacity Price ($/MW-day)
1.75
0.13
PJM East Capacity Price ($/MW-day)
6.32
5.52
NI Hub Implied ATC Heat Rate (mmbtu/MWh)
41.42
46.39
NI Hub ATC Price ($/MWh)
6.98
6.30
PJM West Hub Implied ATC Heat Rate (mmbtu/MWh)
51.07
60.92
PJM West Hub ATC Price ($/MWh)
6.74
8.85
Henry Hub Gas Price ($/mmBtu)
71,326
72,376
Total
Genco
Market
and
Retail
Sales
(GWhs)
(2)
119,354
121,961
Total Genco Sales to Energy Delivery (GWhs)
190,680
194,337
Total Genco Sales Excluding Trading (GWhs)
93.9
93.5
Nuclear Capacity Factor (%)
(1)
2006A
2005A
(1)
Excludes Salem.
(2)
2007 actual and 2008 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.
Note: 2005, 2006 and 2007 prices are average for the year; 2008 prices reflect observable prices as of 7/31/07.

51
FFO Calculation and Ratios
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
FFO + Adjusted Interest
= 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)
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
Rating Agency Capitalization
Rating Agency Debt
Total Adjusted Capitalization
Adjusted Book Debt
= 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
= Total Adjusted Capitalization
+ Adjusted Book Debt
+ Preferred Securities of Subsidiaries
+ Total Shareholders' Equity
Capitalization:
= Adjusted Book Debt
-
Transition Bond Principal Balance
+ STD
+ LTD
Debt:
Debt to Total Cap
Note: Reflects S&P guidelines and company forecast.  FFO and Debt related to non-recourse debt are excluded from the calculations.
(1) Uses 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.

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

53
GAAP Earnings Reconciliation
Year Ended December 31, 2007
(5)
-
-
-
(5)
Settlement of a Tax Matter at Generation Related to Sithe
72
-
-
-
72
Georgia Power Tolling Agreement
(130)
-
-
-
(130)
Termination of State Line PPA
14
-
-
14
-
City of Chicago Settlement
(11)
-
-
-
(11)
Sale of Generation’s investments in TEG and TEP
$(115)
(63)
-
-
(87)
-
$35
Other
$2,923
(29)
280
(18)
(87)
101
$2,736
Exelon
$507
-
-
-
-
-
$507
PECO
$200
-
24
-
-
(3)
$165
ComEd
ExGen
(in millions)
256
2007 Illinois Electric Rate Settlement
(18)
Nuclear decommissioning obligation reduction
$2,331
2007 Adjusted (non-GAAP) Operating Earnings (Loss)
34
Non-Cash Deferred Tax Items
-
Investments in synthetic fuel-producing facilities
104
Mark-to-market adjustments from economic hedging activities
$2,029
2007 GAAP Reported Earnings (Loss)
Note: Amounts may not add due to rounding.

54
(1)
Amounts shown per Exelon share and represent contributions to Exelon's EPS.
(0.01)
-
-
-
(0.01)
Settlement of a tax matter at Generation related to Sithe
(0.04)
(0.08)
-
-
0.04
Non-cash deferred tax items
(0.14)
(0.14)
-
-
-
Investments in synthetic fuel-producing facilities
0.41
-
-
0.03
0.38
2007 Illinois electric rate settlement
(0.19)
-
-
-
(0.19)
Termination of State Line PPA
0.11
-
-
-
0.11
Georgia Power tolling agreement
Exelon
Other
(1)
PECO
(1)
ComEd
(1)
ExGen
(1)
$4.32
$(0.18)
$0.75
$0.30
$3.45
2007 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share
(0.01)
-
-
-
(0.01)
Sale of Generation's investments in TEG and TEP
0.02
-
-
0.02
-
City of Chicago settlement
(0.03)
-
-
-
(0.03)
Nuclear decommissioning obligation reduction
0.15
-
-
-
0.15
Mark-to-market adjustments from economic hedging activities
$4.05
$0.04
$0.75
$0.25
$3.01
2007 GAAP Earnings Per Share
GAAP EPS Reconciliation
Year Ended December 31, 2007

55
2008 Earnings Outlook
•
Exelon’s outlook for 2008 adjusted (non-GAAP) operating earnings
excludes the earnings impacts of the following:
–
mark-to-market adjustments from economic hedging activities
–
unrealized gains and losses from nuclear decommissioning trust fund
investments
–
significant impairments of intangible assets, including goodwill
–
significant changes in decommissioning obligation estimates
–
costs associated with the Illinois electric rate settlement, including ComEd’s
previously announced customer rate relief programs
–
costs associated with ComEd’s settlement with the City of Chicago
–
other unusual items
–
significant future changes to GAAP
•
Both our operating earnings and GAAP earnings guidance are
based on the assumption of normal weather

56
Exelon Investor Relations Contacts
Inquiries concerning this presentation
should be directed to:
Exelon Investor Relations
10 South Dearborn Street
Chicago, Illinois 60603
312-394-2345
312-394-4082 (Fax)
For copies of other presentations,
annual/quarterly reports, or to be
added to our email distribution list
please contact:
Felicia McGowan, Executive Admin
Coordinator
312-394-4069
Felicia.McGowan@ExelonCorp.com
Investor Relations Contacts:
Chaka Patterson, Vice President
312-394-7234
Chaka.Patterson@ExelonCorp.com
Karie Anderson, Director
312-394-4255
Karie.Anderson@ExelonCorp.com
Marybeth Flater, Manager
312-394-8354
Marybeth.Flater@ExelonCorp.com
Len Epelbaum, Principal Analyst
312-394-7356
Len.Epelbaum@ExelonCorp.com