Onshore Property Program London Underwriter Meetings February 2005 Confidential
Onshore Property Program
London Underwriter Meetings
February 2005
Confidential
2
Safe Harbor Statement
This presentation contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” You can identify these statements, including those relating to Dynegy’s 2004 and 2005 financial estimates, by the fact that they do not relate strictly to historical or current facts. Management cautions that any or all of Dynegy’s forward-looking statements may turn out to be wrong. Please read Dynegy’s annual, quarterly and current reports under the Securities Exchange Act of 1934, as amended, including its 2003 Form 10-K, as amended, and third quarter 2004 Form 10-Q, as amended, for additional information about the risks, uncertainties and other factors affecting these forward-looking statements and Dynegy generally. Dynegy’s actual future results may vary materially from those expressed or implied in any forward-looking statements. All of Dynegy’s forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, Dynegy disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Non-GAAP Financial Measures:
We use the non-GAAP financial measures “EBITDA,” “free cash flow” and “Operating Margin/Deficit” in these materials. We have defined these terms in the Appendix. For our 2005 guidance, we have provided reconciliations of non-GAAP measures to the most directly comparable GAAP measures, namely net income and operating cash flow, respectively.
Confidential InformationThe information set forth herein is highly confidential, and it is provided by Dynegy Inc. (“Dynegy” or the “Company”)
with the understanding that it shall not be traded upon or used other than for the purposes of an evaluation of insurance needs and pricing, and the placing of such insurance/reinsurance. Furthermore, in providing the
information set forth herein, it is understood that this presentation and these documents (and in any supplementary documents or additional information, or imparted in any conversation of discussion) is strictly of a confidential nature
and is supplied on the condition that it shall not be disclosed to any person, other than your Directors, Officers and Employees who need to know such information for the above purpose, without prior permission being granted by
Dynegy.
3
Introduction
Financial Overview
Business Unit Overview
Technical Matters
In Summary
Appendix
Agenda
Introduction
5
Appointed new executive leadership team Simplified capital structure Deferred significant debt maturities through 2010 Maintained strong liquidity Closed new bank credit facilities Exited non-core, domestic and international lines of
business Exited five of nine long-term tolls Completed acquisition of Sithe Restructured Kendall toll Exited legacy gas and power contracts Exited four gas transportation agreements Restructured Natural Gas Liquids contracts Discontinued Trading & Marketing Significantly reduced cost structure Continued to reduce G&A and other ongoing costs Addressed certain legacy litigation and regulatory
issues Divested certain minority interests in non-core Power
Generation and Natural Gas Liquids assets
Completed Objectives
The “To Do” List… Moving On
• We took responsibility for past issues and put them behind us
• We believe we have restored credibility
• We provided clarity in financial results
Result
6
Exited all non-core businesses (IP, speculative Trading, Telecommunications) Decrease in debt and other obligations of $6 B (43% reduction) since December 31, 2002
– Debt reduction of $3.3 B, including restructuring of CVX $1.5B security for $850MM
– Tolling, turbines, and other obligations reduced by $2.7 B Decrease in debt maturing within 5 years by $4.7 B (to less than $500 MM) Eliminated uncertainties surrounding FERC, CFTC and SEC investigations Enhanced corporate governance (11 new Board members and new corporate leadership) Proven access to public and bank debt markets through series of re-financings
– Extended $1.3 B facility ($700MM maturing 2007; $600MM term loan maturing 2010)
– $2.0 billion public debt issuances Market confidence reflected in securities pricing
– Stock price increase from $1.18 to $4.50/$4.75 range– Unsecured bond trading range improvement from low 30s to high 80s and
90s
Achievements Since December 2002
7
Financial Accomplishments Since December 2002
(1) Total debt reflects balance sheet debt, off balance sheet leases and preferred stock.
Debt reduced $3.3 B (37%) while maintaining strong liquidity
($ in millions)
Proforma12/31/2002 12/31/2003 12/31/2004
Debt Debt maturing within 5 years 5,206$ 1,319$ 483$ Debt maturing > 5 years 2,872 5,309 4,268 Capital lease obligation 746 758 771
Total Adjusted Debt (1) 8,824$ 7,386$ 5,522$
Toll capacity payment obligations 3,761 2,279 1,923 Other Obligations 1,517 1,549 409
Total Other Obligations 5,278$ 3,827$ 2,333$
TOTAL DEBT & OTHER OBLIGATIONS 14,102$ 11,213$ 7,854$
Liquidity 1,315$ 1,389$ 1,200$
Rating Caa2 Caa2 Caa2Outlook Negative Developing Positive
Financial Overview
9
Funded Debt and Other Obligations Maturity Profile
2005 2006 2007 2008 2009 2010 2011
$44 $50
$266$345
$138 $115
$1,641
2012 2013 2014 2015 2016+
$1,289
$624
$137
$705
$1,088
Note: Debt includes preferred stock, par value debt obligations and obligations for Central Hudson shown annually as a change in present value of the obligation using a discount factor of 10%. Holders of Dynegy convertible subordinated debentures have a put right in 2013, but are shown above maturing at the due date in 2023. Includes obligations of Sithe Energies.
Sithe
Current Maturity Profile
Option Horizon
($ in millions)
10
Liquidity
Current liquidity levels are well in excess of what is required to sustain the business
$1.4 $1.3 $1.4
12/31/03 3/31/04 6/30/04 9/30/04
$1.5
Cash Availability
Proforma12/31/04
$1.2
$ in billions
11
Dynegy Bond Activity… Returning Value to Investors
$20
$40
$60
$80
$100
$120
10/1/02 1/1/03 4/1/03 7/1/03 10/1/03 1/1/04 4/1/04 7/1/04 10/1/04 1/1/05
Source: Advantage Data Inc. / CSFB
Closing Stock PriceDHI 8.750% Senior Notes Due 2/15/12
DHI 10.125% Senior Secured Notes Due 7/15/13
$0
$1
$2
$3
$4
$5
$6
10/1/02 1/1/03 4/1/03 7/1/03 10/1/03 1/1/04 4/1/04 7/1/04 10/1/04 1/1/05
12
AES
Aquila
Calpine
Duke
El Paso
Mirant
NRG
Reliant
Williams
Reduced debt levels
Lower G&A
Less duplication of efforts
Less duplication of liquidity
Improved balance sheet Improved cash flow More efficient systems/operations Sustainable business in scale and
scope
Scalability Allows for Consolidation
Scalability Allows for Consolidation
Industry Consolidation
Too much… Debt per MWh G&A per MWh Duplication of efforts Duplication of liquidity
… which will lead to consolidation
Current Industry Environment:
Business Unit Overview
14
Dynegy’s Business Structure
InternationalInternationalGas, Power and Gas, Power and
TradingTrading
Wholesale Energy Wholesale Energy NetworkNetwork
Natural Gas LiquidsNatural Gas Liquids
Transmission Transmission & Distribution& Distribution
U.S. and Global U.S. and Global CommunicationsCommunications
Power GenerationPower Generation
Natural Gas Natural Gas LiquidsLiquids
FORMER CURRENT
Strengthening focus on core operations simplifies
business structure and provides clarity
15
Dynegy’s New Structure
Power GenerationPower Generation
U.S. portfolio of 13,005 net MWs
Substantially contracted/hedged
Geographically advantaged in New York, Midwest and California
Scaleable systems
Well-positioned to benefit in power recovery
Natural Gas Liquids
Integrated upstream and downstream businesses
Most processing contracts structured as percentage of proceeds/percentage of liquids or fee-based
Provides upside in today’s high oil and gas price environment
16
Power Generation Portfolio
Note: Map above includes Independence in the Northeast (1,021 MW) and other plants acquired in Sithe transaction (334 MW), but excludes Long Beach in the West (235 MW) due to retirement.
Diversified portfolio
32% baseload, 24% intermediate, 44% peaking
28% coal/oil, 18% dual fuel, 54% gas
Coal and dual fuel plants perform in current high gas price environment
Gas plants present upside for future
Low maintenance capital
Scaleable systems with multi-fuel logistical expertise
Originally built for significantly larger portfolio
NEPOO
L
NEPOO
L
FRCCFRCC
MAPPMAPP
SPPSPP
MAINMAIN
ERCOTERCOT
WECCWECC
SERCSERC
West
964 MW Gas
Texas
610 MW Gas
Midwest
3,316 MW Coal/Oil 442 MW Gas
Southeast815 MW Gas
825 MW Gas/Oil
Northeast
1,507 MW Gas/Oil 370 MW Coal1,137 MW Gas49 MW Hydro
Midwest-Peakers
2,970 MW Gas
U.S. PORTFOLIO13,005 net MW (1)
17
Power Generation – 3Q 2004 Financial Performance
QTD and YTD 2004 volumes essentially on plan
Net YTD volumes up 2%*
Net QTD volumes down 10%* due to reduced generation at the Havana station in anticipation of its PRB fuel switch
Northeast volumes improved 18% YTD
YTD 2004 operating cash flow $351 MM, capex $78 MM and proceeds from asset sales $245 MM
Free cash flow $518 MM for YTD 2004
YTD 2004 OCF/ICF = 5.32
$555E
$145E
EBITDA CapEx
($ in millions)
2003 2004
2003 2004 2003 2004
EBITDA 177$ 220$ 500$ 491$
WCP Impairment - 45 - 45
Gain on Sale of Joppa - (75) - (75)
Gain on Sale of Oyster Creek - (15) - (15)
177$ 175$ 500$ 446$ West Coast Power Reserve
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
$151A
$500
$538A
$491
$78$117
2003 2004
YTD YTD
Average Actual On-Peak Market Power Prices: ($/MWh) 3Q 2003 3Q 2004
Cinergy $39 $43NI Hub/ComEd $39 $41Southern $44 $50NY – Zone G $61 $57ERCOT $43 $50SP-15 $54 $57
* Volume change calculated excluding non-core assets either sold or targeted for sale.
18
Power Generation – Longer-term Generation Earnings Potential
Market
($ in millions) Recovery(1)
DMG 630$
DNE 110
Sithe Acquisition 60
DMW 150
DSE & ERCOT 120
Operating Margin with DNE Lease 1,070$
DNE Operating Lease (2) 50
Operating Margin without DNE Lease 1,120$
General & Administrative (70)
Equity Earnings & Other 20
EBITDA without DNE Lease 1,070$
EBITDA with DNE Lease 1,020$
(1) Represents an average mid-point for expected generation earnings. Actual results may differ.(2) DNE is financed at the project level and includes annual lease expense of $50 MM for GAAP purposes. Operating margin and EBITDA
are shown without the DNE lease expense to negate the impact from financing.
Power market recovery and stable cost structure allows for significant uplift in baseload coal fleet performance DNE dual-fuel capability provides an expanding dark spread advantage Significant margin from gas-fired plants occurs in market recovery
Market
Recovery
Power Prices ($/MWh)
Midwest 60.00$
Northeast 70.00$
Southeast 54.00$
Capacity Prices ($/KW-yr.)
Midwest 36.00$
Northeast 36.00$
Southeast 36.00$
Natural Gas - Henry Hub ($/MMBtu) $ 5.00-5.50
Coal ($/MMBtu)
PRB Delivered to Baldwin 1.10$
Colombian Delivered to Northeast 2.00$
Fuel Oil #6 Delivered to Northeast ($/MMBtu) 5.40$
Estimated Volumes (Million MWh)
DMG 24.5 DNE/Independence 6.8 DMW & DSE 6.5
19
Power Market Recovery Timeline
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Midwest (MAIN)
Midwest (ECAR)
Northeast (NYISO)
Southeast (SERC-VACAR)
Texas (ERCOT)
Southeast (SERC-Southern)
Southeast (SERC-Entergy)
California (WECC)
Northeast (NYISO)
Midwest (MAIN)
Midwest (ECAR)
Southeast (SERC-VACAR)
Southeast (SERC-Southern)
Southeast (SERC-Entergy)
Texas (ERCOT)
18%
15-17%
15-17%
15-17%
15-17%
15-17%
12.5%
Target Estimated
Reserve Margin
21%
30%
27%
33%
43%
77%
26%
Estimated 2004Reserve MarginNERC Region
3 – 5 years
4 – 6 years
4 – 6 years
5 – 7 years
9 – 11 years
10 + years
6 – 9 years
Dynegy’s EstimatedTime Horizon
Note: Estimated and targeted reserve margins derived from NERC 2004 Summer Assessment and regional NERC and ISO documents. Dynegy’s estimated time horizon for market recovery reflects our projections as to when reserve margins are likely to return to target levels based on Dynegy’s demand growth and plant retirement assumptions.
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2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Power Market Recovery Timeline
Midwest (MAIN)
Midwest (ECAR)
Northeast (NYISO)
Southeast (SERC-VACAR)
Texas (ERCOT)
Southeast (SERC-Southern)
Southeast (SERC-Entergy)
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016+
California (WECC)
21
Power Generation Capital Expenditures
($ in millions) 2004E 2005E
Maintenance
DMG 70$ 75$
DNE (1) 13 40
Gas-Fired/IT 30 45
Total Maintenance 113 160
Development
Havana PRB Conversion 24 10
Vermilion PRB Conversion - 20
Other 8 -
Total Development 32 30
Total Capex 145$ 190$
Long-term maintenance capital expenditures should approximate $130 MM - $160 MM annually
Resolution of Baldwin litigation or new Clean Air environmental regulations may require an aggregate of approximately $350 MM of compliance capital expenditures by 2010, primarily at baseload coal plants
Federal mercury proposals, if enacted, could result in incremental capital expenditures
(1) 2005E capital expenditures for DNE include Independence.
22
Natural Gas Liquids
Upstream assets are strategically located
High growth areas of North Texas and Gulf Coast
Mature Permian Basin
Fractionation and storage assets optimally located in Mont Belvieu NGL hub and Louisiana
Major producer customers include ChevronTexaco, Burlington, BP, Kerr-McGee, Forest Oil and Devon
Major NGL and end-use customers include ChevronPhillips Chemical, ChevronTexaco, AmeriGas, Dow, Eastman, Heritage, Suburban, Tesoro and Valero
Gas Processing Plant
Fractionation Plant
Bulk NGL Storage
Marine Terminal
Marketing Terminal
Dynegy Pipeline
Third Party Pipeline
Permian Basin
North Texas
Gulf Coast
Field: 99% POP/Fee, 1% Other
Straddle: 53% Hybrid, 22% Fee, 19% POL, 6% Keep Whole
23
Natural Gas Liquids – 3Q 2004 Financial Performance
$385E
Upstream financial results continued to benefit from high commodity prices and strong asset availability
Downstream financial results favorable due to NGL price impacts and 38% increase in fractionation volumes
Full-year 2004 capex increase over 2003 primarily due to Chico ($14 MM) and Monument ($7 MM) development projects
YTD 2004 operating cash flow $194 MM, capex $41 MM and proceeds from asset sales $65 MM
Free cash flow $218 MM for YTD 2004
YTD 2004 OCF/ICF = 7.46
$230A
$51A $60E
$36
$173
$273
EBITDA CapEx
2003 2004 2003 2004
($ in millions)
2003 2004 2003 2004
EBITDA 48$ 91$ 173$ 273$
Gain on Sale of Hackberry - - (10) (17)
Gain on Sale of Indian Basin - - - (36)
48$ 91$ 163$ 220$ West Coast Power Reserve
Three Months Ended Sept. 30 Nine Months Ended Sept. 30Average Actual Quarterly Data:
3Q 2003 3Q 2004
Nat. Gas ($/MMbtu) $4.97 $5.76
Crude ($/Bbl) $30.45 $42.22
Frac Spr. ($/MMbtu) $0.95 $2.93
NGL ($/gal) $0.51 $.75
YTD
YTD
$41
24
Natural Gas Liquids – Longer-term Midstream Earnings Potential
($ in millions) $35 Crude $40 Crude $45 Crude $50 Crude
Field Plants $ 135-170 $ 160-205 $ 185-220 $ 210-285
Straddle Plants 30-35 35-45 40-50 50-55
Fractionation 40-50 40-50 40-50 40-55
Wholesale Marketing 25 25 25 25
NGL Marketing 25 25 25 30
Operating Margin* $ 265-295 $ 295-340 $ 330-365 $ 370-435
General & Administrative (35) (35) (35) (35)
Equity Earnings 10 10 10 10
Minority Interest (25-20) (30-25) (35-30) (40-35)
EBITDA $ 215-250 $ 240-290 $ 270-310 $ 305-375
Henry Hub ($/MMBtu) $ 5.00-6.00 $ 5.25-6.25 $ 5.75-6.75 $ 6.25-7.25Frac Spread ($/MMBtu) $ 1.09-2.09 $ 1.85-2.85 $ 2.37-3.37 $ 2.80-3.80Weighted Average NGL ($/Gal) $ 0.61 $ 0.71 $ 0.80 $ 0.88Propane Relationship to Crude 77% 77% 77% 77%
* Depending on commodity pricing, spreads and volumes, operating margin can be a combination of low and high ranges for each business component.
25
Natural Gas Liquids - Capital Expenditures
($ in millions) 2004E 2005E
Upstream Maintenance 30$ 38$
Downstream Maintenance 7 12
Total Maintenance 37 50
Upstream Development 22 8
Downstream Development 1 20
Total Development 23 28
Total Capex 60$ 78$
Annual maintenance expected to be $40 MM-$60 MM, with $50 MM as a mid-point
New well connect capex ranges from $12 MM - $14 MM
* Includes 100% of capex spent on partnerships.
Approximately $20 MM in 2004 development capex
Monument compression
North Texas expansion
2005 Development capex includes notional allocation of $28 MM for high-return new business opportunities under evaluation
Maintenance and well connect capex is assumed to be relatively flat going forward
In Summary
27
Concentrate on Concentrate on core business core business fundamentals fundamentals to maximize to maximize results for results for today and today and tomorrow tomorrow
Today
From Self-Restructuring… to Future Growth
• Maintain operational readiness and asset availability
• Pursue selected growth opportunities
• Capture commodity-cyclical returns to extinguish debt, driving return to equity holders
• Strive for excellence through safety, efficiency and compliance
• Leverage the scalability of our infrastructure
• Deliver value to our investors
What We Will Do Appointed new executive leadership team Simplified capital structure Deferred significant debt maturities through 2010 Maintained strong liquidity Closed new bank credit facilities Exited non-core, domestic and international lines of business Exited five of nine long-term tolls Completed acquisition of Sithe Restructured Kendall toll Settled four power supply contracts Exited four gas transportation agreements Restructured Natural Gas Liquids contracts Reduced G&A and other ongoing costs Outsourced IT systems and infrastructure Addressed certain legacy litigation and regulatory issues Divested certain minority interests in non-core Power Generation and
Natural Gas Liquids assets
What We Have Done
2002 2005 Market Recovery
Technical MattersRisk Mitigation and Sparing
29
Generation Fleet – Accomplishments and Major Unit Upgrades
2004 Accomplishments: Implemented Operations Information Systems (OIS) Program
Virtual Diagnostic Center Standardized Predictive Maintenance Practices
2004 Major Unit Upgrades:
Wood River Major Enhancements - $24MM
Powder River Basin Coal Conversions
Havana Conversion to Powder River Basin Coal - $36MM
Vermillion to convert in 2005 - $18MM
Baldwin Units Major Upgrades
Unit #2 - $22MM
Unit #1 - overhaul in 2005 - $35MM
Roseton/Danskammer Units Major Upgrades
Roseton - $6MM
Danskammer - $9MM (includes $2.8MM for new conveyer system )
30
Generation Fleet – Maintenance
Siemens W501F Fleet (Total 2004 Fired Hours on Dynegy Fleet = 1,281) LTPSA w/Siemens Westinghouse Event Failure Analysis Total Maintenance Service (TMS) Process Mechanical Equipment Integrity Program In-House Siemens Westinghouse Engineer
DMG/DNE Fleet Updated Distributed Control Systems (DCS) Boiler Tube Failure/Cycle Chemistry / Boiler Maintenance Workstation
31
Generation Fleet - Sparing Practices…2004 Update
501F Fleet (Total 2004 Fired Hours – 1,284) Exceeds Siemens Westinghouse Recommendations Multiple Sets:
Combustion Hardware Hot Gas Path Hardware Opening / Closure Hardware
Spare Generator Rotor Available; Turbine Rotor under repair at Siemens’ Ontario shop
Spare W501FD2 Package in Storage – Available
>$33MM in Spares Inventory Available
DMG/DNE Fleet
Spare Exciter Assemblies for Baldwin and Roseton Stations (>$2MM)
Second spare Induced Draft Fan motor purchased for Roseton ($400K)
32
Generation Fleet – Loss Risk Mitigation Efforts
Transformer Losses Renaissance Power
Roseton – Central Hudson Breaker Failure – Damage to Main Step-up Transformer
Ongoing Risk Engineering Surveys GE Insurance Solutions – Fire Protection Annual Surveys CNA – Boiler & Machinery / Jurisdictionals
33
Generation Fleet – Sithe Acquisition
Independence Power – 1020 MW Combined-Cycle Cogen – Built 1994 MRA / Hydro Facilities: May be Decommissioned Facility 2004 Percentage Run Hours by Location:
Independence – 20% Ogdensburg MRA – 10-15%% Massena/Batavia/Sterling MRAs - < 5%
Long-Term Service Agreement with General Electric
Major capital spares on-hand: Generator Field Gas Turbine Rotor (to be installed in 2005)
Planned Expenditures: 2005 CapEx Budget: 2005 O&M Budget:
Risk Engineering Surveys GE Insurance Solutions – Fire Protection Annual Surveys HSB to Continue B&M Surveys / Jurisdictionals
Questions
Appendix
37
Portfolio Primarily Located in Favorable Markets
Note: Favorable markets are based on our assumptions regarding the timing of market recovery and the potential for development of competitive markets.
Favorable
Neutral
Unfavorable
WECC – CA
WECC – CA
WECCWECC
WECC - SWWECC - SW
MAPPMAPP
SPPSPP
ERCOTERCOT
SERC - SERC - EntergyEntergy
SERC - SERC - SouthernSouthern
SERC - TVASERC - TVA
ECARECAR
PJMPJM
NEPOOL
NEPOOL
FRCCFRCCMarkets: Coal
Gas
Dual Fuel
Dynegy Facilities:
SERC - VACARSERC - VACAR
MAINMAIN
NYISONYISO
Hydro