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.

20

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