Dynegy 8K Entry into a Material Definitive Agreement | SEC 29 Mar 06

$750 Million

Senior Unsecured Notes Offering

March 29, 2006

Exhibit

99.2

FORWARD-LOOKING STATEMENTS

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

Dynegy’s

2006 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 2005 Form 10-K 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

implied

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 “Adjusted

EBITDA”

these materials.

Adjusted EBITDA is a non-GAAP financial measure. Adjusted EBITDA can be reconciled to Operating income (loss) using the following

calculation: Operating income (loss) plus Earnings from unconsolidated investments, plus Other income and expense (net), plus Minority

interest

income

(expense),

plus

Depreciation

and

amortization

expense,

less

Impairment

and

other

charges,

less

other

significant

items

equals Adjusted EBITDA. Management and some members of the investment community utilize Adjusted EBITDA to measure financial

performance on an ongoing basis. However, Adjusted

EBITDA

should

not be used in lieu of GAAP measures such as net income and cash

flow from operations.

Senior Unsecured Notes

Security:

2016

Maturity:

Repay outstanding indebtedness and for general corporate purposes

Use of Proceeds:

Offering Size:

Type of Offering:

Issuer:

$750 million

144A with Registration Rights

Dynegy Holdings Inc.

SUMMARY OF THE OFFERING

Bruce Williamson

Chairman and CEO

Holli Nichols

Executive Vice President

and Chief Financial Officer

Chuck Cook

Senior Vice President

and Treasurer

Steve Furbacher

President

and Chief Operating Officer

MANAGEMENT REPRESENTATIVES

Bruce Williamson

Chairman & CEO

Bruce Williamson

Chairman & CEO

Power Generation

12,820 MW

2006E EBITDA: $565 -

$660MM

Consolidated 2006E EBITDA: $480MM -

$585MM

DYNEGY IS A PURE PLAY INDEPENDENT

POWER PRODUCER

DYNEGY IS A PURE PLAY INDEPENDENT

POWER PRODUCER

Other (Corp.)

2006E EBITDA: $(100) -

$(90)MM

(1)

CRM

2006E EBITDA: $15MM

Midwest

7,551 MW

(2)

2006E EBITDA: $490

$540MM

13 facilities in IL, MI, OH and KY

Includes 3,452 MW of low

production cost generation

3,210 MW coal-fired

242 MW oil-fired

Favorable long-term

transportation and coal supply

contracts

Expiration of below market

AmerenIP contract at end of

2006 potentially increases

EBITDA

Net long SO

allowances in

2006 –

2009

Completed conversion to PRB

coal in 2005

Entered into comprehensive

settlement with the EPA

(Baldwin Consent Decree)

Northeast

2,803 MW

2006E EBITDA:

$80

$115MM

3 facilities serving attractive NY

market

Danskammer

371 MW coal facility with

additional 130 MW gas/oil units

Can capture attractive dark

spreads in NY

Roseton

1,210 MW dual-fuel (oil / gas)

facility

Can capture significant option

value from oil / gas price

spreads

Sithe Independence

(3)

1,092 MW gas-fired facility

Low 7,750 heat rate

750 MW long-term capacity

contract with ConEd (‘A’

Rated)

through 2014

South

2,466 MW

(2)

2006E EBITDA: ($5)

$5MM

5 facilities located in TX, NC,

GA, LA and NV

1,566 MW gas and 900 MW

dual-fuel (gas/oil)

New Cogen Lyondell contract

beginning 2007 on significantly

improved terms

Remaining tolling agreement is

Kendall, which has been

restructured through 2008

Substantive out-of-the-money

legacy trading positions

expected to roll off by 2007

Represents total G&A which has

been significantly reduced to

approximately $130 million in

2006

Also includes interest income of

approximately $30 million

(1)

G&A no longer allocated to segments in 2006.

(2)

Pro Forma for the sale of our interest in West Coast Power and acquisition of the remaining 50% interest in Rocky Road. These transactions are expected to close early 2006.

(3)

DHI contractual agreements with Independence reflected in CRM for DHI.

Diversified portfolio with significant baseload

cash flow.

Gas

913 MW

50%

Gas/Oil

900 MW

50%

Coal

371 MW

13%

Gas

1,092 MW

39%

Gas/Oil

1,340 MW

48%

Gas

610 MW

100%

FRCC

MAPP

SPP

MAIN

ERCOT

WECC

SERC

Texas

Midwest

Southeast

Northeast

Midwest-Peakers

U.S. PORTFOLIO

(1)

12,820 net MW

DIVERSIFIED PORTFOLIO LOCATED IN

FAVORABLE REGIONS

DIVERSIFIED PORTFOLIO LOCATED IN

FAVORABLE REGIONS

33% baseload, 18% intermediate, 49%

peaking

30% coal/oil, 17% dual fuel, 53% gas

Coal plants benefit from

increases in gas prices

Gas plants present future upside

Predictable maintenance capital

Scaleable systems with multi-fuel

logistical expertise

Note: Figures include the Sithe Independence 1,092 MW gas-fired facility in NY (owned by Dynegy Inc.).

(1)

In December 2005, Dynegy announced the planned disposition of ownership interests in West Coast Power and the planned acquisition of ownership

interests in Rocky Road. Map and percentages above exclude West Coast Power (902 MW) as NRG agreed to purchase Dynegy’s 50% ownership

interest in this facility. Additionally, map and percentages above include Rocky Road (total nameplate capacity 364 MW) as Dynegy agreed to acquire

NRG’s 50% ownership interest in this facility. These transactions are expected to close early 2006.

Gas

3,626 MW

100%

Gas

43 MW

100%

West

Gas

473 MW

12%

Coal/Oil

3,452 MW

88%

NERC REGION

ESTIMATED 2004

RESERVE MARGIN

ESTIMATED 2005

RESERVE MARGIN

TARGET ESTIMATED

RESERVE MARGIN

RANGE OF

EXPECTED DATES

Northeast (NYISO)

(1)

21%

19%

18%

2008–2009

Midwest (MAIN)

30%

22%

15-17%

2009–2010

Midwest (ECAR)

27%

26%

15-17%

2009–2010

Southeast (SERC-VACAR)

33%

24%

15-17%

2010–2011

Texas (ERCOT)

(2)

26%

25%

12-13%

2012–2013

Southeast (SERC-Southern)

43%

37%

15-17%

2015

Southeast (SERC-Entergy)

77%

84%

15-17%

2015

ESTIMATED RESERVE MARGIN TIMELINE

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Midwest (MAIN)

Midwest (ECAR)

Southeast (SERC-VACAR)

Texas (ERCOT)

Represents

~81% of

our MWs

(1)

Southeast (SERC-Southern)

Northeast (NYISO)

Southeast (SERC-Entergy)

(1)

Includes the Sithe Independence 1,092 MW gas-fired facility in NY (owned by Dynegy Inc.).

(2)

Estimated 2005 reserve margin for ERCOT is 17% when excluding mothballed plants. Market recovery in ERCOT could be as early as 2008 if mothballed capacity is

excluded from the calculations.

Note: Estimated and targeted reserve margins derived from

the

NERC

2005

Summer Assessment and regional ISO documents. Estimated reserve margins and the date

ranges during which target reserve margins are expected to be achieved are management’s current estimates based on various market indicators, including projected

supply-demand imbalances and the perceived reaction to the risk of supply interruption. Actual reserve margins and the years during which target reserve margins are

achieved, if any, for some or all of the regions identified could differ materially from these estimates.

NEXT PHASE OF DEVELOPMENT

Running the Business

Operate safely and efficiently

Build a sustainable capital structure

Manage costs, collateral and capital

Maintain fiscal discipline, strong liquidity and

financial flexibility

Produce and sell megawatts to the market

when and where needed

Delevering and Growing the Business

Maintain commitment to all investors

Equity and fixed income

Redeploy our cash through strategies

designed to create the strongest long-term

return

Execute liability management activities

Begin to grow our business in key

business regions through organic and/or

opportunistic investments and

combinations

Running, Delevering and Growing

Running and Restructuring

2006

2002

Steve Furbacher

President & COO

Steve Furbacher

President & COO

Note:

Figures include the Sithe Independence 1,092 MW gas-fired facility in NY (owned by Dynegy Inc.).

(1)

Excludes WCP volume.

PERFORMANCE

DYNEGY INC. 2005 OPERATIONAL HIGHLIGHTS

Volumes were 33.9 million MWh in

2005

(1)

Completed conversion of Midwest fleet to lower-cost, lower-emission

PRB coal

Renegotiated Lyondell power and steam contract on more favorable

terms

Strong safety record demonstrates focus and discipline

2005 average power prices increased nearly 50% compared to 2004

2005 average natural gas and fuel oil prices up 50% and 43%,

respectively, compared to 2004

Baldwin units all set new continuous operating day records

Havana surpassed previous annual production record by Oct. 2005

Roseton achieved highest single day of generation since July 2001

Sithe Independence 3Q 2005 production four times greater than

2004

PRICES

PRODUCTION

AmerenIP

PPA

Long-Term

Fuel Supply

Long-Term

Transportation

Dynegy Midwest Generation (“DMG”) contract to serve AmerenIP through the end of

2006 is below market

$4/kW-month capacity payments and $30/MWh round-the-clock energy payments

No Provider of Last Resort (POLR) obligation; 11.5 million MWh annual cap on

AmerenIP’s take

Represents approximately 1/3 of estimated on-peak production for 2006

96% of coal requirements at DMG through 2010 are contracted

97% of 2006 coal requirements at DMG contracted at a fixed price

57% of coal requirements through 2008 at DMG are contracted at a

fixed price

Ten year transportation agreement with Burlington Northern through 2013 at

attractive rates

Fixed price through 2008; DMG option to extend for remaining 5 years on

similar terms

KEY CONTRACTS

POTENTIAL IMPACT IN 2007 FROM

EXPIRATION OF AmerenIP CONTRACT

POTENTIAL IMPACT IN 2007 FROM

EXPIRATION OF AmerenIP CONTRACT

Margins at Midwest generation segment are currently compressed due to obligations under PPA

with AmerenIP, which expires in December 2006

Under contract, AmerenIP can take up to 2,800 MW of energy each hour from May through

September and 2,300 MW each hour during the other months, under the following terms:

Fixed capacity payments of $4.00/kW-month = ~$120 million per year; plus

Variable energy payments of $30.00/MWh, with a maximum of 11.5 million MWh of offtake

per year

Current forward around the clock market prices in 2007 are significantly higher

(1)

Prices quoted are for energy only (exclude capacity payments).

(2)

Around the clock price is average of on-peak and off-peak prices. Based on assumed off-peak price of $30/MWh and 5x16 on-peak period.

(3)

Calculated using Around-The-Clock pricing.

(4)

Includes energy payments at $30/MWh

and capacity payment of $120 million per year. Assumes average ~2,500 MW per month.

(5)

Based on sales to AmerenIP

of 11.5 million MWh. Assumes that all other variables remain constant.

Potential 2007 Market Price Impact

($ in millions, except as indicated)

On-Peak Price

($ / MWh)

(1)

Around-the-Clock

Price

(2)

($ / MWh)

Total Sales to

AmerenIP (Million

MWh)

Potential Market

Energy Revenues

(3)

Theoretical

Revenues Under

AmerenIP

Contract

(4)

Theoretical Impact

($MM)

(5)

$75.00

$51.43

11.5

$591

$465

$126

$70.00

$49.05

11.5

$564

$465

$99

$65.00

$46.67

11.5

$537

$465

$71

$60.00

$44.29

11.5

$509

$465

$44

$55.00

$41.90

11.5

$482

$465

$17

Midwest power price drivers include natural gas prices and

weather

Rocky Road acquisition expected to place all Midwest fleet

under 100% Dynegy ownership

No significant change in major maintenance programs

anticipated for 2006 –

2007

Favorable long-term PRB coal and rail contracts (Baldwin

2006E delivered price approximately $1.20/MMBtu)

2006 is last year of AmerenIP contract

In addition to capacity contracted with AmerenIP, 27% of

capacity contracted in 2006

Expect to invest approximately $584 million in emission

control projects through 2013

(2)

$417

2005

2006E

$490 - $540

(1)

MIDWEST

Adjusted EBITDA

Average On-Peak Market Power Prices

(1)

Net Volumes (MM MWh)

($ in millions)

$20

$30

$40

$50

$60

$70

$80

$90

2004A

2005A

2006E

Cinergy

NI Hub/ComEd

($/MWh)

Cinergy

NI Hub/ComEd

$43

$64

$61

$42

$62

$60

(1)

See Adjusted EBITDA in appendix.

21.9

22.0 - 23.0

2005

2006E

(1) 2004 and 2005 prices are average on-peak prices for the year. 2006E prices are as of 2/7/06 and reflect day ahead on-peak settlement prices for Jan. -

Feb. 7 and quoted forward on-peak monthly prices for Feb. 8 –

Dec. 2006

(2)

$27 million of planned $611 million total was spent in 2005

PRB

conversion

for Vermilion and Havana.

8.3

2005

2006E

7.5 - 8.5

(1)

$40

$60

$80

$100

$120

2004A

2005A

2006E

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

NY - Zone G

NY - Zone A

Fuel Oil Delivered

$75

2005

2006E

$80 - $115

(1)

NORTHEAST

Adjusted EBITDA

Average On-Peak Market Power Prices

(1)

Net Volumes (MM MWh)

($ in millions)

($/MWh)

NY -

Zone G

NY -

Zone A

Fuel Oil Delivered

($/MMBtu)

$62

$92

$93

$53

$76

$74

$4.99

$7.13

$8.72

(1)

The Sithe Independence facility was acquired in 2005.

Northeast power price drivers include natural gas prices

and weather

Coal, oil and gas assets provide both flexibility and

operating leverage to meet market needs

2006E South American coal delivered price ~$2.90/MMBtu

Warmer than normal temperatures at the start of 2006

have led to lower demand; as a result, we expect lower

dispatch in the first half of 2006 relative to 2005

On-peak power prices at Roseton (Zone G) remain

relatively flat from 2005 to 2006 while fuel oil costs

increase, reducing spark spread

72% of capacity contracted under Independence through

2014

(1)

See Adjusted EBITDA in appendix.

Note: Figures include the Sithe Independence 1,092 MW gas-fired facility in NY (owned by Dynegy Inc.).

(1) 2004 and 2005 prices are average on-peak prices for the year. 2006E prices are

as of 2/7/06 and reflect day ahead on-peak settlement prices for Jan. -

Feb. 7

and quoted forward on-peak monthly prices for Feb. 8

–

Dec.

2006.

$20

$40

$60

$80

$100

2004A

2005A

2006E

ERCOT

Southern

SOUTH

Adjusted EBITDA

Average On-Peak Market Power Price

(1)

Volumes (MM MWh)

(1)

($ in millions)

3.7

3.5

2005A

2006E

($/MWh)

ERCOT

Southern

Natural Gas

($/MMBtu)

$51

$80

$79

$49

$71

$72

$5.85

$8.80

$8.63

(1)

Excludes West Coast Power.

See Adjusted EBITDA in appendix.

ERCOT:

2006E sales volumes of 3-4 million MWh

Ancillary service market expected to continue to

generate earnings

New Lyondell contract begins 2007 on more favorable

terms

Southeast Peakers:

Low utilization expected to continue through 2006 due

to compressed spark spreads

69% of capacity contracted in 2006

West Coast Power:

Announced agreement to sell remaining interest to NRG

in December 2005. Results are removed in all years

(1)

Volumes exclude West Coast Power.

(1) 2004 and 2005 prices are average on-peak prices for the year. 2006E prices are as

of 2/7/06 and reflect day ahead on-peak settlement prices for Jan. -

Feb. 7 and

quoted forward on-peak monthly prices for Feb. 8 –

Dec. 2006.

$23

2005A

2006E

(1)

$(5) - $5

39,972

46,335

57,094

64,063

2006E

2007E

2008E

2009E

Comprehensive settlement with EPA covering

Midwest coal fleet

Set emissions limits

Requires certain equipment installments

Set equipment operating requirements

Expect to invest approximately $584 million in

emission control projects through 2013

(1)

ENVIRONMENTAL / EMISSIONS

We have a net long SO

position through 2009 and have completed conversion of our Midwest

fleet in 2005 to low sulfur PRB coal.

Cumulative Net Long SO

Position

Baldwin Consent Decree

Expected emissions position adequate to maintain reliable operations

Plan to install scrubbers and baghouses at Baldwin 1, 2, 3 & Havana by 2012. Construction will be

staggered throughout years

Plan to install baghouse at Vermilion by 2007

New players entering emissions market

Separate line of business for some entities

Significant SO

price increases resulted in recent all-time highs

Longer-term technological developments, post-2010 environmental regulations and capital

improvement programs will drive market changes

(1)

$27 million of planned $611 million total was spent in 2005 on PRB conversion

for Vermilion and Havana.

Holli Nichols

EVP & CFO

Holli Nichols

EVP & CFO

Note: Excludes assets / subsidiaries sold.

DYNEGY INC. CONSOLIDATED FINANCIAL

PERFORMANCE

DYNEGY INC. CONSOLIDATED FINANCIAL

PERFORMANCE

Adjusted Generation and Other Capital

Expenditures

(1)(2)

($ in millions)

Adjusted EBITDA

(1)

($ in millions)

$113

(3)

$21

$112

$47

$25

2005

2006E

Other

(1)

See Adjusted EBITDA in appendix.

(1)

Excludes NGL.

(2)

See reconciliation to total capex in appendix.

(3)

Excludes $3 million of business acquisition costs.

$150

$189

$417

$75

$23

($236)

$490 - $540

$80 - $115

($5) - $5

($85) - ($75))

2005

2006E

CRM & Other

$480 – $585

$279

$170

$130

2005

2006E

(1)(2)

(3)

Estimated Adjusted G&A reduced to approximately $130 million

(2)

in 2006 vs. $170 million

(3)

2005

G&A is no longer allocated to business segments

(1)

Excludes $287 million in legal charges and $11 million in restructuring charges.

(2)

G&A only. Excludes $9 million in interest income. See appendix for reconciliation.

(3)

G&A only. Excludes $30 million in interest income.

SIZABLE COST REDUCTIONS

($ in millions)

HEAT RATE

EXPIRATION

ANNUAL CAPACITY PAYMENTS

Project

(Btu/KWh)

LOCATION

DATE

2006

2007

2008

2009 – 2017

Kendall

7,300

Illinois

3/2017

578

$41

$42

$332

(-) Payments from Constellation

(41)

(42)

–

(1)

Net Dynegy Payments

–

$332

One remaining tolling agreement in CRM Segment

Kendall capacity payments are covered by payments received from Constellation Energy Commodities

Group Inc. in a back-to-back tolling agreement through 2008

Kendall is an efficient facility (7,300 heat rate)

Sithe Independence contract is now an intercompany agreement

DHI makes ~$75 million per year payment to Sithe Independence for the right to dispatch 955 MW

DHI captures margin associated with plant dispatching

Sithe is a wholly-owned subsidiary of Dynegy Inc.

CRM: RESTRUCTURED / TERMINATED ALL

TOLLING AGREEMENTS

CRM: RESTRUCTURED / TERMINATED ALL

TOLLING AGREEMENTS

(1)

Excludes margin potentially earned by DHI post 2008.

CAPITAL STRUCTURE / LIQUIDITY

Secured

Unsecured

Secured Non-Recourse

($ in millions)

12/31/05

As Adjusted

Senior Debentures

$465

Sub. Debentures

$419

Sithe Energies

(2)

12/31/05

As Adjusted

Central Hudson

(6)

$785

Dynegy Power Corp.

12/31/05

As Adjusted

Sub. Conv. Debentures

(1)

$225

Series C Convertible Preferred

$400

Dynegy Inc.

12/31/05

As Adjusted

Revolver

(4) (5)

Synthetic LC Facility

$200

Second Secured Notes (SPNs)

$1,750

Dynegy Holdings Inc.

(3)

New Senior Unsecured Notes

$750

Senior Notes/Debentures

$1,373

Sub. Capital Inc. Securities

$200

Note:

Assumes that all SPNs are tendered.

(1)

Guaranteed on a senior unsecured basis by Dynegy Holdings Inc.

(2)

Debt balance represents face value.

(3)

Capital structure excludes $120 million subordinated affiliate note payable from DHI to Dynegy Inc.

(4)

Amount

12/31/05

excludes

million

letters

credit

posted

under

Dynegy’s

cash-collateralized

letter

credit

facility.

(5)

$400 million Revolver is undrawn.

(6)

Represents future lease payments discounted at 10%. Guaranteed by DHI on a Senior Unsecured basis.

12/31/05

As Adjusted

DI Cash

$1,549

$399

DHI Cash

$1,301

$195

DI Liquidity

$1,615

$740

DHI Liquidity

$1,367

$536

Cash and Liquidity

$ in millions

Dynegy Inc.

DHI

Cash (12/31/2005)

$1,549

$1,301

Additions:

$400 million 3 year revolver

$200 million Synthetic LC Facility

200

New Senior Unsecured Notes

750

Release of DHI Collateral (Former Cash Collateralized LC Facility)

335

Proceeds from West Coast Power / Rocky Road Exchange

160

Reductions:

Tender for SPNs

(1,750)

Tender Premiums (SPNs)

(205)

Cash Collateral for Synthetic LC Facility

(200)

Premium Paid (Conv. Sub. Debentures)

(44)

Sterlington Toll Settlement

(370)

Fees and Expenses

(26)

Cash (Pro Forma)

$399

$195

($ in millions)

SOURCES

USES

Credit Facilities

SPN Repurchase

$400 million 3-year Revolver

L+650 bps 2nd Priority Sr. Secured FRNs due 7/15/2008

(1)

225

Synthetic LC Facility Due 1/31/2012

200

9.875% 2nd Priority Sr. Secured Notes due 7/15/2010

(1)

625

10.125% 2nd Priority Sr. Secured Notes due 7/15/2013

(1)

900

Senior Unsecured Notes Due 2016

750

SPN Tender Premiums

(2)

205

Release of DHI Cash Collateral (Former Cash Coll. LC Facility)

335

Convert Exchange Premium

(3)

Net Cash Proceeds from West Coast Power / Rocky Road Asset

Exchange

160

Cash Collateral for Synthetic LC Facility

200

Sterlington Toll Settlement

370

Cash on Hand

1,150

Other Fees and Expenses

Total Sources

$2,595

Total Uses

$2,595

SOURCES & USES, DYNEGY INC.

Note:

Reflects selected transactions since 12/31/05.

(1)

Sources and uses assumes that all SPNs are tendered.

(2)

Fees, expenses and tender premiums are estimated.

(3)

Premium to be paid by Dynegy Inc.

12/31/05

12/31/05 PF

Cash

Availability

$1,367

COLLATERAL POSTED AND LIQUIDITY

Total collateral reduced from year-end 2004 to year-end 2005

Midstream

business

collateral

returned

2005

following

sale

Targa

Resources

Decrease

from

year-end

2005

March

2006

due

change

commodity

prices

(1)

Excludes $248 million of cash at Dynegy Inc.

(2)

Liquidity

figures

exclude

$122

million

cash

collateral

posted

12/31/05.

(3)

Excludes $204 million of cash at Dynegy Inc. after $44 million premium paid for convert exchange. Pro

Forma for transactions listed on Sources / Uses page.

(4)

$195 million of cash and $341 million of availability ($600 million available less $259 posted for LCs).

DHI Collateral Posted

($ in millions)

DHI Liquidity

(1)

($ in millions)

$536

(4)

(2)(3)

(1)(2)

Hedging strategy reduces risk of significant increases in collateral.

(1) DHI collateral requirements related to Sithe Independence

transportation and fuel are included in Other and CRM, respectively.

12/31/04

12/31/05

3/17/06

CRM

106

GEN

192

263

180

NGL

167

Other

(1)

Total

470

381

279

Cash

376

122

LCs

259

193

Total

470

381

279

(1)

$23

$47

$84

$490

$28

$500

$60

$560

$500

$104

$804

$113

$122

$131

$750

$20

$770

$550

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017+

$400

$90

$200

DHI CURRENT AND PRO FORMA MATURITY

PROFILE

(1)

DHI CURRENT AND PRO FORMA MATURITY

PROFILE

(1)

1st Secured

(3)

2nd Secured

Unsecured & Sr. Sub. Debt

Convertible Securities

Central Hudson

(4)

12/31/2005

Pro Forma

$23

$47

$225

$84

$309

$90

$625

$28

$653

$500

$60

$560

$500

$104

$604

$900

$113

$1,013

$122

$131

$20

$550

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017+

Note:

Excludes Sithe debt and subordinated convertible debentures.

(1)

Excludes $120 million subordinated affiliate note payable from DHI to Dynegy Inc.

(2)

$400 million revolving credit facility maturing 3/6/09 is not currently drawn and $200 million synthetic LC facility maturing 1/31/12 is cash collateralized.

(3)

Represents $400 million revolving credit facility and $200 million Synthetic LC facility.

(4)

Represents amortization of lease debt with an $800 million face value. Excludes payments to lease equity.

(5)

Excludes $200 mm Synthetic LC facility as it is cash collateralized and assumes $400 million Revolving Credit Facility is undrawn.

(2)

Total Debt

(12/31/2005)

(1)

$4.1 Bn

Total Debt

(Pro Forma)

(1)(5)

$3.1 Bn

Bruce Williamson

Chairman & CEO

Bruce Williamson

Chairman & CEO

Strong player in Power Generation

Excellent operational track record

Assets located in favorable regions

Diversified U.S. generation portfolio

Solid baseload earnings and cash flow with

significant upside in high gas price

environment

Significant upside potential from peaking fleet

Scalable platform originally designed for a much

larger portfolio

VALUE PROPOSITION

Strong / Stable

Assets with

Upside to Market

Recovery

Strong Financial

Position

Focused

Management

Strong and improving financial position

$1 billion debt reduction since 4Q 2005

No significant debt maturities until 2010

Stable cash flow generated from Midwest

coal assets

Strong and stable liquidity profile

Focused management team

Consistent, credible track record

Committed to deleverage and grow the

business

Working For

All

Investors

APPENDIX

ON-PEAK POWER PRICES

$25

$50

$75

$100

Cinergy

2005A: $63.65

2006A/F (Feb): $60.91

2006F (Oct): $77.83

$40

$80

$120

$160

New York Zone G

2005A: $92.39

2006A/F (Feb): $93.12

2006F (Oct): $119.23

$12

$16

Natural Gas

2005A: $8.80

2006A/F (Feb): $8.63

2006F (Oct): $11.74

$35

$70

$105

$140

ERCOT

2005A: $79.89

2006A/F (Feb): $79.11

2006F (Oct): $103.37

2005 Actual

2006 Forward as of 10/04/05

(1)

2006 Actual/Forward as of 2/07/06

(2)

(1)

Pricing as of 10/04/05, which was the basis for estimates as presented 11/08/05. Prices reflect forward on-peak monthly prices for 2006.

(2)

Pricing

2/07/06,

which

was

the

basis

for

estimates

presented

3/08/06.

Prices

reflect

actual

day

ahead

on-peak

settlement

prices

for

Jan.

–

Feb.

and

quoted

forward

on-peak

monthly

prices

for

Feb.

–

Dec.

2006.

($ / MMBtu)

($ / MWh)

$450

$550

$650

$750

$850

$950

$7.75 Gas

$9.75 Gas

$11.75 Gas

$13.75 Gas

GENERATION EARNINGS SENSITIVITY

TO NATURAL GAS

GENERATION EARNINGS SENSITIVITY

TO NATURAL GAS

Expected 2006 Generation EBITDA Ranges Given $/MMBtu Cost of Natural Gas

(12-Month Average $/MMBtu)

$725 MM

$825 MM

$615 MM

$670 MM

$725 MM

$775 MM

$825 MM

$860 MM

$900 MM

Note: Reflects estimates as presented March 8, 2006.

$495 MM

$550 MM

$605 MM

2005 DYNEGY INC. ADJUSTED EBITDA

RECONCILIATION

2005 DYNEGY INC. ADJUSTED EBITDA

RECONCILIATION

GEN - MW

GEN - NE

GEN - SO

CRM

NGL

REG

OTHER

Total

Generation

194

(21)

202

Customer Risk Management

(647)

Other

(393)

Operating income (loss)

194

(21)

(647)

(393)

(838)

Earnings (losses) from unconsolidated investments

(5)

Other items, net

(1)

Cumulative effect of change in accounting principle, pre-tax

(5)

(2)

(7)

Add: Depreciation and amortization expense,

a component of operating income (loss)

157

220

EBITDA from continuing operations

355

(4)

(646)

(355)

(597)

EBITDA from discontinued operations, pre-tax

1,341

1,347

EBITDA

355

(4)

(640)

1,341

(355)

750

Depreciation and amortization expense

(258)

Interest expense

(442)

Pre-tax income

Income tax benefit

Net income

103

Reconciliation to Adjusted EBITDA

GEN - MW

GEN - NE

GEN - SO

CRM

NGL

REG

OTHER

Total

Reported EBITDA

355

(4)

(640)

1,341

(355)

750

Plus: Asset Impairment

Plus: Impairment of Equity Investments

Less: West Coast Power EBITDA

(11)

Plus: Sterlington Toll Charge

364

Plus: Independence Toll Charge

169

Plus: Legal and Settlement Charges

249

287

Plus: Corporate Restructuring Charges

Less: Discontinued Operations

(6)

(1,341)

(1,347)

Plus: G&A Allocated to Segments

(66)

Adjusted EBITDA

417

(75)

(161)

279

Twelve Months Ended December 31, 2005

Power Generation

Twelve Months Ended December 31, 2005

Power Generation

2005 -

2006 RECONCILIATION OF CAPEX AND

G&A

2005 -

2006 RECONCILIATION OF CAPEX AND

G&A

Dynegy Inc. G&A

2005

G&A as Reported

468

Legal Charges, GEN

Legal Charges, CRM

(38)

Legal Charges, Other

(249)

Restructuring Charges

(11)

Adjusted G&A

170

(1) Actual for 2005.

(2) Projected for 2006.

2005

(1)

2006

(2)

NGL Capex

Midwest GEN Capex

113

112

Northeast GEN Capex

South GEN Capex

Other Capex

Total Capex

195

189

Less: NGL Capex (Discontinued Ops)

(45)

Adjusted Capex - GEN & Other

150

189

Dynegy Inc. Capex

Dynegy Inactive 8-KEntry into a Material Definitive Agreement