EX-99 2 ex99.htm EXHIBIT 99

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

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

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

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

(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

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

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

$0.10

$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

PSEG Overview & Update

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

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

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

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

Merger Overview & Update

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

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

34,457

17,018

51,475

5,200,000

2,100,000

7,300,000

460,000

1,700,000

2,160,000

(1) Year-end 2004; Generation numbers include long-term contracts.

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

Strong Generation Platform

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

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

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

2.40

$235

Quartile

2nd

4th

2nd

3rd

Performance

0.63

2.88

$191

Quartile

1st

2nd

1st

Financial Benefits

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

By Business

Nuclear

Trading

Genco Corp/
Fossil

T&D

Corporate,
Business
Services

34%

11%

39%

Supply

Corporate
Programs

Info
Technology

Nuclear
Outage
Costs

Nuclear
Production
Improvements

Staffing

16%

15%

43%

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%

(1) Ratios exclude securitized debt and PSEG Energy Holdings

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

0.2

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

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

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

Appendix

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

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

An Environmental Asset

250

200

150

100

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

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)

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 2^nd or 3^rd quarter of 2005

Illinois Post-2006 Update –
Process Moving Forward

Understanding the Auction:
Product Laddering

ComEd Suggested Load Auctioned by Term

5% 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.

2 yrs. + 5 mos.

3 yrs. + 5 mos.

5 yrs.

5 yrs.>>

3 yrs.

3 yrs.>>

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 1^st Auction to stagger load in future Auctions

1^st 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%

2007

2008

2009

2010

2011

2012

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

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

Distr

Trans

Line Losses

Energy/Other

ATC range from
$32 to $37
(current forward
price = $37);
adders from
40% to 50%

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

78 - 88

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

Break-Even Price for New Construction

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

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

GAAP EPS Reconciliation 2000-2002

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)

$2.24

$2.22

0.35

(0.18)

0.02

$2.41

GAAP EPS Reconciliation 2003-2004

$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

$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

(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