Exelon Corporation
Public Service Enterprise Group
European Investor Meetings
May 9-13, 2005
This presentation includes “forward-looking statements” within the meaning of the Private
Securities Litigation Reform Act of 1995. These forward-looking statements include, for example,
statements regarding benefits of the proposed merger of Exelon and PSEG, integration plans,
and expected synergies, anticipated future financial and operating performance and results,
including estimates for growth. There are a number of risks and uncertainties that could cause
actual results to differ materially from the forward-looking statements made herein. A discussion
of some of these risks and uncertainties, as well as other risks associated with the proposed
merger, is included in the preliminary joint proxy statement/prospectus contained in the
Registration Statement on Form S-4 (Registration No. 333-122704) that Exelon has filed with the
Securities and Exchange Commission. Additional factors that cause actual results to differ
materially from the forward-looking statements made herein are included in “Management’s
Discussion and Analysis of Financial Condition and Results of Operations – Business Outlook and
the Challenges in Managing the Business” in Exelon’s 2004 Annual Report on Form 10-K.
Readers are cautioned not to place undue reliance on these forward-looking statements, which
speak only as of the date of this presentation. Neither Exelon nor PSEG undertakes any
obligation to publicly release any revision to its forward-looking statements to reflect events or
circumstances after the date of this presentation.
Safe Harbor Language
2
This presentation is not a solicitation of a proxy from any security holder of Exelon or PSEG. The above-
referenced Registration Statement on Form S-4 contains a preliminary joint proxy statement/prospectus and
other relevant documents regarding the proposed merger of Exelon and PSEG. WE URGE INVESTORS
AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS
REGARDING THE PROPOSED TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS WHEN
THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT
EXELON, PSEG AND THE PROPOSED MERGER. Investors and security holders will be able to obtain
these materials (when they are available) and other documents filed with the SEC free of charge at the
SEC's website, http://www.sec.gov. In addition, a copy of the definitive joint proxy statement/prospectus
(when it becomes available) may be obtained free of charge from Exelon Corporation, Shareholder
Services, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Public Service
Enterprise Group Incorporated, Investor Relations, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey
07101-1171.
Additional Information
3
The respective directors and executive officers of Exelon and PSEG and other persons may be deemed to
be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding
Exelon’s and PSEG’s directors and executive officers and other participants in the solicitation and a
description of their direct and indirect interests, by security holdings or otherwise, is available in the
preliminary joint proxy statement/prospectus contained in the above-referenced Registration Statement on
Form S-4.
Exelon Overview & Update
4
Exelon Overview - 2004
Earnings $1.86B
EPS $2.78
ROE 21%
Assets $42.8B
Nuclear
Fossil
Power Team
EPS $1.00
ROE 22%
Assets $16.4B
Illinois
Utility
Pennsylvania
Utility
5
(1) Reflects parent company receivable added back to PECO Shareholders’ Equity.
EPS
$1.69
ROE(1)
12%
Assets
$27.6B
2004 Financial Summary
$2.78 Operating Earnings (+6.5% over 2003)
Core growth in retail volumes
Higher generation margins
Acquisition of the second half of AmerGen
Exelon Way cost savings
Reduced losses at Enterprises
Lower interest expense
Dividend increases totaling 60% in 2004
(current annual rate $1.60/share)
Free cash flow of $1.4 billion
Note: See presentation appendix for GAAP EPS and cash flow reconciliation
6
Exelon had 9.6% average annual earnings per
share growth driven by:
PECO / Unicom merger
Cost management initiatives
Debt reduction and refinancings
Effective commodity risk management
Despite:
Retail rate freeze
Merchant power overbuild
Volatile wholesale prices
Note: See presentation appendix for GAAP EPS reconciliation
7
Looking Back: 2000 - 2004
$3.10
$3.00
$2.90
$2.80
$2.70
$2.60
$2.50
$2.40
$2.30
$2.20
$2.10
$2.00
$2.78
$0.11
2004A
($0.03)
($0.05)
($0.05)
$0.05
$0.10
$0.05
$0.09
$2.90 - $3.10
Weather
ComEd
CTC
Amort.&
Depr./
PECO
CTC Amort.
Nuclear
Refueling
Outages
O&M
Expense/
Other
Load
Growth
Other
Revenue
Net Fuel
Growth
Interest
Expected EPS Drivers
Other Risks and
Opportunities
+/- CTC Reset
+/- Weather
+/- Economy
+/- Natural Gas Prices
Note: See presentation appendix for GAAP EPS reconciliation
CTC = competitive transition charges
2005 Adjusted (non-GAAP) Operating EPS
Guidance: $2.90 - $3.10
2005E
8
PSEG Overview & Update
9
Traditional T&D
Regional
Wholesale Energy
Domestic/Int’l
Energy
Leveraged
Leases
* From continuing operations, includes Parent impact of $(49)M, or $(0.20) per share
PSEG Overview - 2004
10
2004 Earnings
$726M*
2004 EPS
$3.03*
ROE
13%
Assets
$29B
EPS
$1.44
ROE
13%
Assets
$13.6B
EPS
$1.29
ROE
11%
Assets
$8.6B
EPS
$0.50
ROE
7%
Assets
$7.2B
PSEG 2004 Financial Review
$3.03 operating earnings includes impact of:
Hope Creek Extended Outage ($0.34)
Replacement Power Costs at Fossil and Salem ($0.15)
Strengthening of Polish Zloty ($0.06)
Increased annual dividend to $2.20 per share in 2004
2005 indicative annual dividend of $2.24
Energy Holdings returned $475M of capital
Leverage ratio at 57%
Retired $300M of debt at Energy Holdings
Replaced $800M of non-recourse debt at PSEG Power with $500M at
favorable rates
Mandatory convert in late 2005
11
2004 Actual
Power
PSE&G
Energy
Holdings
Other
2005 Estimate
+ Improved
Nuclear &
Fossil
Operations
- NDT
- O&M
+ Currency
Impacts
- Preferred
Dividend from
Holdings
- Additional
Shares
NDT = Nuclear Decommissioning Trust Funds
$3.03
$3.15 - $3.35
PSEG 2005 Operating EPS Guidance
12
Merger Overview & Update
13
Offer Price:
Ownership:
Timing:
Governance:
Nuclear Agreement:
Approvals:
1.225 shares of Exelon per PSEG share
68% Exelon shareholders
32% PSEG shareholders
John W. Rowe to be CEO
E. James Ferland to be non-executive Chairman
18 Board members
— 12 nominated by Exelon
— 6 nominated by PSEG
Expected to close within 12-16 months from
12/20/04 announcement
Operating Services Contract started 1/05
Shareholders, Federal and State Regulatory
Key Transaction Terms
14
Three urban utilities, with a low-cost, low-emissions generation
fleet, in an integrated Regional Transmission Organization.
Generation
(MWs)
Nuclear
TOTAL MW’s
Elec. Customers
Gas Customers
Exelon
PSEG
EE&G
U.S. Rank
16,751
3,484
20,235
1
34,457
17,018
51,475
5,200,000
2,100,000
7,300,000
460,000
1,700,000
2,160,000
1
1
7
(1) Year-end 2004; Generation numbers include long-term contracts.
15
Premier U.S. Utility Company
PEG:
EXC:
(1)
Enhanced earnings
Combined Company
Regulatory and market diversity
Increased operating flexibility
Experienced management team
Strong, stable cash flow with commitment
to solid investment grade ratings
PSEG Brings
Excellence in transmission and
distribution operations
Expertise in BGS auction
development and participation
Strong gas LDC experience
Exelon Brings
Premier nuclear operation
expertise
Broad platform for earnings
and cash flow growth
Large merger integration success
BGS = Basic Generation Service
LDC = local distribution company
A “Win-Win”Combination
16
Strong Generation Platform
17
Premier nuclear operator, based on
consistent top quartile performance
Balanced and diverse generation portfolio
Reliable and commercially responsive fossil
operations
Experienced leader in wholesale power
marketing and risk management
Complementary Generation Portfolio Positions New
Company for Success
Opportunity for Improved Nuclear
Performance
18
Exelon has proven track record of improving and sustaining safety,
operating and cost performance
Significant opportunity to improve PSEG fleet performance under
Nuclear Operating Services Contract, started January 2005
Every 1% increase in capacity factor for PSEG’s nuclear fleet generates
pre-tax income of about $12 million
100.0%
90.0%
60.0%
70.0%
80.0%
$14.00
$12.00
$4.00
$8.00
$10.00
$6.00
$2.00
$0.00
1999
2000
2001
2002
2003
1999
2000
2001
2002
2003
2004
Exelon-operated
Capacity Factor
PSEG-operated
Capacity Factor
Exelon Non-Fuel
Production Cost ($/MWh)
PSEG Non-Fuel
Production Cost ($/MWh)
Opportunity for Improved T&D Reliability
19
Reliability – Outage Frequency (SAIFI)
Customer Satisfaction (ACSI)
Safety (OSHA Recordables Rate)
Total T&D $/Customer
PSE&G has proven track record for reliable, cost effective T&D operations
Exelon reliability has improved -- committed to further improvements
Focus on customer satisfaction
SAIFI = System Average Interruption Frequency Index
ACSI = American Customer Satisfaction Index
OSHA = Occupational Safety & Health Administration
2003 Key Performance Indicators
Exelon
PSE&G
Performance
1.09
70
2.40
$235
Quartile
2nd
4th
2nd
3rd
Performance
0.63
76
2.88
$191
Quartile
1st
2nd
2nd
1st
Financial Benefits
20
Stronger platform to achieve consistent
earnings growth
Annual synergies of approximately $400 million
in year 1 growing to $500 million by year 2
Earnings accretion for both companies’
shareholders in year 1
Nuclear contract provides earnings benefit for
both companies starting in 2005
Secure and growing dividend
Strong balance sheet
$500 Million of Synergies in Year 2
21
By Business
Nuclear
Trading
Genco Corp/
Fossil
T&D
Corporate,
Business
Services
34%
9%
7%
11%
39%
Supply
Corporate
Programs
Info
Technology
Nuclear
Outage
Costs
Nuclear
Production
Improvements
Staffing
16%
15%
9%
43%
3%
14%
(1) Includes cost and production improvement
By Category
(1)
Solid Balance Sheet
Exelon and PSEG believe they will retain solid
investment-grade ratings on a combined basis
Pro Forma Key Ratios (1)
Year 1
Year 2
Funds from Operations /
Average Total Debt
28%
31%
Funds from Operations
Interest Coverage
5.8x
6.2x
EBITDA
Interest Coverage
Debt / Capital
7.0x
7.1x
41%
41%
(1) Ratios exclude securitized debt and PSEG Energy Holdings
22
Strong Cash Flow
($ in Billions)
EXC
2007
PEG
2007
Merger Adj
2007
EEG
2007
Estimated Net Income (1)
2.2
1.0
0.3
3.5
Depreciation & Amortization
1.9
1.0
-
(2)
2.9
CapEx
(2.0)
(0.9)
(0.1)
(3)
(3.0)
Dividends
(1.2)
(0.6)
-
(1.8)
Cash Before Debt Maturities
0.9
0.5
0.2
1.6
Securitized Debt Retired
(0.6)
(0.2)
-
(0.8)
Available Cash
0.3
0.3
0.2
0.8
Note: Illustrative only; not intended to provide guidance
(1) Estimated net income using Thomson First Call consensus EPS estimates/growth times projected shares
(2) $500m synergies reduced for taxes and assumed regulatory sharing
(3) Merger costs to achieve capital investment
23
Anticipated Timeline - Update
Dec 2004
Q1 2005
Q2 2005
Q3 2005
Q4 2005
Q1 2006
Q2 2006
Announce
Transaction
12/20/04
FERC,
NJBPU, ICC
Regulatory
Filings
2/4/05
File Joint
Proxy
Statement
2/10/05
1/17/05
Implement Nuclear Operating Services Agreement
Develop Transition Implementation Plans
Work to Secure Regulatory Approvals
(FERC, SEC, NRC, DOJ, NJBPU, NJDEP*, PAPUC, ICC*, NYPSC and others)
Exelon &
PSEG
Shareholder
Meetings
Receive Regulatory
Approvals
Close Transaction
* Notice filing only
24
Solid Delivery Business
Stable growth
Improving operations
Constructive regulatory processes in IL, NJ and PA
Geographic diversity
Exceptional Generation Business
Large, low cost, low emissions generation fleet in competitive
markets with strengthening wholesale prices
Fuel, dispatch and locational diversity
Strong operating performance and results-oriented culture
Experienced power marketing/risk management team
Experienced management team
Strong balance sheet and financial discipline
History of delivering on commitments
EE&G Value Proposition
25
Appendix
26
U.S. Electric Value Chain
Fuel
Production
Trading
Transmission
Distribution
Other
NATURAL GAS
4,688 Bcf
21% of US Market
($30 Billion)
OIL
176 Million Barrels
2% of US Market
($5 Billion)
COAL
1,002 MM Short Tons
92% of US Market
($26 Billion)
NUCLEAR
($4 Billion)
$7 Billion
$298 Billion
$5 Billion
$73 Billion
$202 Billion
$53 Billion
$65 Billion
$100 Billion
$2 Billion
$22 Billion
$65 Billion
$5 Billion
452 GW
(summer capacity)
Fossil Fuel
Steam Turbines
312 GW
Combined-cycle/
Combustion Turbine
98 GW
Nuclear
109 GW
Hydro and Other
970 GW
Total
6,659
TWh
720,000
Circuit
Miles
of
22 kV
and
Above
Customers
(millions)
117 Residential
16 Commercial
and Industrial
1 Other
Annual
Revenues:
$259 Billion
Annual
Consumption:
3,500
TWh
Peak
Demand:
715 GW
Net
Book Value:
$638 Billion
Source: Cambridge Energy Research Associates (CERA); 2003 data
27
An Environmental Asset
250
200
150
100
50
0
AEP
Sout-
hern
Exel-
on
Ente-
rgy
Duke
FPL
Dom-
inion
Prog-
ress
First
Ene-
rgy
Edis-
on
Intl
Ame-
ren
Cin-
ergy
PG-
&E
PS-
EG
TXU
2002 generation by fuel source
GWhs
28
Non-
Gas/Oil
Coal
Fossil
Illinois Post-2006 Update –
Competition Benefiting IL Customers
Since the onset of customer choice in 1997, more than 70% of ComEd’s
biggest customers have chosen alternatives to bundled rates, some
saving up to 15%
Residential customers saved 20% with a rate reduction, and even more
considering a 10-year rate freeze when the Consumer Price Index
increased 20% (current rates lowest since early 1990’s)
Since 1998, outage frequency is down 44%, duration is down 53%
Nuclear capacity factors have increased from 49% to 93%
9,000 megawatts of new competitive power supply brought on line (and
not in rate base)
29
12/3/04 Illinois Commerce Commission (ICC) staff report to General
Assembly endorsed an auction process similar to New Jersey’s (best fit
with consensus of Procurement Working Group)
ComEd made filings at the ICC on February 25 proposing an auction
process
Details of the filing and case schedule were previewed with all stakeholders
including ICC staff
Proceeding will likely run through January 2006
Auction has support of a variety of stakeholders
Bi-partisan House Committee formed to oversee Post-2006 process
(Chairman: George Scully)
Hearing testimony from a broad range of stakeholders before determining General
Assembly’s level of involvement and direction to the ICC
A separate filing for delivery rates and new rate design will be made in
the 2nd or 3rd quarter of 2005
30
Illinois Post-2006 Update –
Process Moving Forward
Understanding the Auction:
Product Laddering
ComEd Suggested Load Auctioned by Term
5% of load
5% of load
5% of load
5% of load
5% of load
20% of load
20% of load
20% of load
15% of load
25%
in 5
year
60%
in 3
year
15%
in 1
year
5 yrs. + 5 mos.
4 yrs. + 5 mos.
3 yrs. + 5 mos.
2 yrs. + 5 mos.
17 mos.
17 mos.
17 mos.
2 yrs. + 5 mos.
3 yrs. + 5 mos.
5 yrs.
5 yrs.
5 yrs.
5 yrs.
5 yrs.
5 yrs.
5 yrs.
5 yrs.
5 yrs.
5 yrs.>>
5 yrs.>>
5 yrs.>>
5 yrs.>>
3 yrs.
3 yrs.
3 yrs.
3 yrs.
3 yrs.
3 yrs.
3 yrs.
3 yrs.
3 yrs.
3 yrs.>>
3 yrs.>>
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
1 yr.
Calendar Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
PJM Planning Year
(June 1 – May 31)
Transitional contracts shown in black.
Notes:
Unique product term required in 1st Auction to stagger load in future Auctions
1st Auction term begins 1/1/07 with 5 months added to each term to align with the PJM planning year (June 1 – May 31)
• 50% Auction Load Cap allows Exelon Generation to sell slightly less
than 50% of its economic generation directly to ComEd; remainder sold
through other channels
• Annual auctions allow for rebalancing position up to the load cap curve
• Physical asset ownership not required to participate or win in Load
Auctions
Load Available in Each Auction Year
Auction 2
Q1 2008
for 5/1/08
Auction 3
Q1 2009
Auction 4
Q1 2010
Auction 5
Q1 2011
Auction 6
Q1 2012
Auction 1 - Q4 2006
for 1/1/07
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
2007
2008
2009
2010
2011
2012
31
P
E
A
K
(MW)
Basic Generation Service (BGS)
Auction Summary
Fourth annual reverse auction in NJ completed 2/16/05
While the wholesale price of energy increased by 18% over last
year’s prices, the staggered terms of the auction contracts will
result in customers of NJ’s largest utility (PSE&G) seeing an
annual increase to total bills of 2.8%
Only 1/3 of the energy component in the overall bill is put out to bid
annually
The energy component is approximately half of the overall bill (with the
delivery and transmission components comprising the remaining half)
Therefore, in any given year, 1/3 of about 50% (or about 1/6) of the total
electric bill is out for bid
25 suppliers participated in the reverse auction with 7 winning
bidders
32
2005 BGS Auction Results
$52.70
(10 Month NJ Avg.)
$54.45
(12 Month NJ Avg.)
$65.91
(36 Month NJ Avg.)
Transmission
Ancillary services
Load shape
Congestion
Risk premium
Capacity
RTC Forward
Energy Cost
RTC = round the clock
~ $20
~ $18
~ $21
2003 Auction
2004 Auction
2005 Auction
$32 - $33
$36 - $37
$44 - $46
33
34
Distr
Trans
Line Losses
Energy/Other
ATC range from
$32 to $37
(current forward
price = $37);
adders from
40% to 50%
90
80
70
60
50
40
30
20
10
0
Notes: 2000 and 2004 are representative of unbundling existing tariff.
Energy/other includes the cost of energy, capacity, load following, weather, switching and congestion.
Mass Market represents residential and small commercial and industrial customer classes (<1 MW).
Assumes increase in wires charges to recover increased investment
in transmission and distribution infrastructure and costs.
2000
2004
2007
77
77
78 - 88
49
2
22
4
47
4
3
23
4
3
26
45 - 55
~ 13% rate
increase
Sales mix: more
higher rate sales
$/MWh
ComEd Bundled Tariff for Mass Market
Higher gas & coal prices, declining capacity margins
and higher emission standards causing higher around
the-clock (ATC) power prices
Rolling Forward 12 Month (Year 1) ATC Prices
Rolling Forward 13-24 Month (Year 2) ATC Prices
Source: Morgan Stanley Research 4/21/05
New England
Mid Atlantic
Northern Illinois
$70
$60
$50
$40
$30
$20
Sep-04
Oct-04
Nov-04
Dec-04
Jan-05
Feb-05
Mar-05
Apr-01
$70
$60
$50
$40
$30
$20
Sep-04
Oct-04
Nov-04
Dec-04
Jan-05
Feb-05
Mar-05
Apr-01
35
Break-Even Price for New Construction
36
Energy/
Capacity
$/MWh
2005 Market
2007 Forecast (1)
Fixed Costs
Variable Costs
POLR
Price
$/MWh
Nuclear
Coal
Integrated Gasification
Combined Cycle
Combined Cycle Gas
Turbine
2,230 Net MWe
93% Capacity Factor
~$1,250 / kWe
$7.15/MWh Fuel
~3 years to Permit
~4 years to Construct
Tech. Readiness: Low
670 Net MWe
85% Capacity Factor
~$1,550 / kWe
$1.20/MMBTU Fuel
~2 years to Permit
~3 years to Construct
Tech. Readiness: High
810 Net MWe
85% Capacity Factor
~$1,800 kWe
$1.20/MMBTU Fuel
~2 years to Permit
~3 years to Construct
Tech. Readiness: Med.
500 Net MWe
90% Capacity Factor
~$600/ kWe
$5.10/MMBTU Fuel
~1.5 years to Permit
~2 years to Construct
Tech. Readiness: High
Global Assumptions: 40-year plant life; 9% after-tax weighted avg. cost of capital; 40% tax rate; 3% cost, fuel and power price escalation. Fixed costs
include fixed O&M, capital and return on capital. Variable costs include variable O&M, fuel and emissions costs. POLR price assumed to be 1.32 x energy
+ capacity (equivalent to 1.5 x energy only) for base-loaded plants. (1) CERA Energy Forecast adjusted for Capacity
70
60
50
40
30
20
10
0
92
79
66
53
40
26
13
0
Market Power Mitigation
2/4/05 - Filed the merger
application with FERC
Proposed Divestiture
“Virtual Divestiture”
Transfer control of 2,600MW of
baseload nuclear energy
Divest a total of 2,900MW fossil
fuel facilities
Peaking 1,000MW
Mid-Merit 1,900MW
at least 550MW coal-fired
Exelon
Baseload
Load Following
Peaking
PSEG
Baseload
Load Following
Peaking
37
GAAP EPS Reconciliation 2000-2002
38
2000 GAAP Reported EPS
Change in common shares
Extraordinary items
Cumulative effect of accounting change
Unicom pre-merger results
Merger-related costs
Pro forma merger accounting adjustments
2000 Adjusted (non-GAAP) Operating EPS
2001 GAAP Reported EPS
Cumulative effect of adopting SFAS No. 133
Employee severance costs
Litigation reserves
Net loss on investments
CTC prepayment
Wholesale rate settlement
Settlement of transition bond swap
2001 Adjusted (non-GAAP) Operating EPS
2002 GAAP Reported EPS
Cumulative effect of adopting SFAS No. 141 and No. 142
Gain on sale of investment in AT&T Wireless
Employee severance costs
2002 Adjusted (non-GAAP) Operating EPS
$1.44
(0.53)
(0.04)
--
0.79
0.34
(0.07)
$1.93
$2.21
(0.02)
0.05
0.01
0.01
(0.01)
(0.01)
--
$2.24
$2.22
0.35
(0.18)
0.02
$2.41
GAAP EPS Reconciliation 2003-2004
39
$1.38
2003 GAAP Reported EPS
Boston Generating impairment
Charges associated with investment in Sithe Energies, Inc.
Severance
Cumulative effect of adopting SFAS No. 143
Property tax accrual reductions
Enterprises’ Services goodwill impairment
Enterprises’ impairments due to anticipated sale
March 3 ComEd Settlement Agreement
2003 Adjusted (non-GAAP) Operating EPS
2004 GAAP Reported EPS
Charges associated with debt repurchases
Investments in synthetic fuel-producing facilities
Severance
Cumulative effect of adopting FIN No. 46-R
Settlement associated with the storage of spent nuclear fuel
Boston Generating 2004 impact
Charges associated with investment in Sithe Energies, Inc.
Costs related to proposed merger with PSEG
2004 Adjusted (non-GAAP) Operating EPS
0.87
0.27
0.24
(0.17)
(0.07)
0.03
0.03
0.03
$2.61
$2.78
0.12
(0.10)
0.07
(0.05)
(0.04)
(0.03)
0.02
0.01
$2.78
Total Increase in Cash and Cash Equivalents
to Free Cash Flow Reconciliation ($ in millions)
GAAP Increase in Cash and Cash Equivalents
Adjustments for Goal:
Discretionary Debt Activity:
- Change in Short-Term Debt
- Net Long-Term Debt Retirements(1)
- Other Financing Activities
Cash from Long-Term Incentive Plan(2)
Other Discretionary Adjustments(3)
Total Adjustments
Free Cash Flow
Includes net long-term debt issuances and payment on the acquisition note to Sithe Energies, Inc.
and excludes ComEd Transitional Funding Trust and PECO Energy Transition Trust Retirements.
Net of treasury shares purchased.
Includes the incremental increase in dividend payments over 2003, exclusion of Sithe cash,
severance payments, call premiums associated with the redemption of debt as a result of
the accelerated liability management plan, and the tax effect of discretionary items.
$ 35
(164)
1,424
(34)
(158)
283
1,351
$ 1,386
Full Year 2004 Cash Reconciliation
40
(1)
(2)
(3)
Cash Flow Definitions
We define free cash flow as:
Cash from operations (which includes pension contributions
Cash used in investing activities, less
Transition debt maturities
Common stock dividend payments at 2003 rates
Other routine activities (e.g., severance payments, tax
effect of discretionary items, etc.)
and the benefit of synthetic fuel investments), less
We define available cash flow as:
Cash from operations less capital expenditures, less common
stock dividend payments, less securitized debt retired
41