Dynegy Illinois 8-K Regulation FD Disclosure

UBS 2006 Natural Gas &

Electric Utilities Conference

UBS 2006 Natural Gas &

Electric Utilities Conference

February 16, 2006

New York City

Investor

&

Public

Relations:

John

Sousa,

Vice

President

Hillarie

Bloxom,

Senior

Analyst

(713)

507-6466

ir@dynegy.com

Exhibit 99.1

2

FORWARD-LOOKING STATEMENTS

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 to Dynegy’s 2005 and 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 2004 Form 10-K

and third quarter 2005 Form 10-Q, 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”

and

“free

cash

flow”

in

these

materials.

We

have

defined these terms in the Appendix.  For our 2005 and 2006 guidance, we have provided reconciliations

of non-GAAP measures to the most directly comparable GAAP measures, reconciling “EBITDA”

to net

income and “free cash flow”

to cash flow from operations.

Business Update

4

STERLINGTON TOLL TERMINATION

STERLINGTON TOLL TERMINATION

Represents substantial completion of exit from CRM business

Eliminates approximately $755 MM in future capacity payments;

approximately $60 MM annually through 2017

Dynegy to pay approximately $370 MM to terminate all

obligations

Results in 4Q 2005 pre-tax charge of approximately $360 MM

(approximately $235 MM after-tax)

Provides a competitive rate of return

On track for 1Q 2006 close

Allows for greater focus on physical sales of

electricity from company-owned assets

5

WEST COAST POWER –

ROCKY ROAD

ASSET EXCHANGE

WEST COAST POWER –

ROCKY ROAD

ASSET EXCHANGE

Dynegy to acquire NRG’s 50% interest in Rocky Road

330-MW natural gas-fired peaker developed in 1999

Long-term capacity contract through 2009

Dynegy’s 50% interest in West Coast Power to be sold to NRG

Dynegy to receive net cash proceeds of $160 MM from NRG

Increases Dynegy’s generating capacity in key region

All of Dynegy’s Midwest interests will be 100% Dynegy-owned

On track for 1Q 2006 close

Provides greater earnings and cash flow potential

in key Midwest generating region

6

GENERATION EARNINGS SENSITIVITY TO

NATURAL GAS

GENERATION EARNINGS SENSITIVITY TO

NATURAL GAS

$550

$650

$750

$850

$950

$9.75 Gas

$11.75 Gas

$13.75 Gas

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

($/MMBtu)

$725 MM

$825 MM

$615 MM

$670 MM

$725 MM

$775 MM

$825 MM

$860 MM

$900 MM

Note:  Reflects guidance ranges as presented November 8, 2005.

7

$0

$25

$50

$75

$100

$125

J

F

M

A

M

J

J

A

S

O

N

D

$0

$40

$80

$120

$160

J

F

M

A

M

J

J

A

S

O

N

D

$0

$25

$50

$75

$100

J

F

M

A

M

J

J

A

S

O

N

D

$0

$30

$60

$90

J

F

M

A

M

J

J

A

S

O

N

D

2006 ON-PEAK POWER PRICES

2006 ON-PEAK POWER PRICES

NI Hub/ComEd

2005A:  $61.67

2006A/F (Jan):  $66.10

2006P:  $75.00

2006A/F (Oct):  $68.79

New York Zone G

2005A:  $92.39

2006A/F (Jan):  $103.05

2006P:  $119.00

2006A/F (Oct):  $119.19

Cinergy

2005A:  $63.65

2006A/F (Jan):  $67.64

2006P:  $78.00

2006A/F (Oct):  $72.96

New York Zone A

2005A:  $76.03

2006A/F (Jan):  $83.76

2006P:  $103.00

2006A/F (Oct):  $97.53

($/MWh)

2005 Actual

2006 Forward as of 10/31/05

(1)

2006 Forward as of 1/31/06

(2)

(1)

Pricing as of 10/31/05.  Prices reflect forward on-peak monthly prices for 2006.

(2)

Pricing

as

of

1/31/06.

Prices

reflect

actual

day

ahead

on-peak

settlement

prices

for

Jan.

and

forward

on-peak

monthly

prices

for

Feb.

-

Dec.

2006.

8

Annual Actual/Forward as of 1/31/06

(1)

$0

$30

$60

$90

ANNUAL ON-PEAK POWER PRICES

ANNUAL ON-PEAK POWER PRICES

NI Hub/ComEd

2003A:  $37.07

2006A/F:  $66.10

2004A:  $42.11

2005A:  $61.67

New York Zone G

Cinergy

New York Zone A

($/MWh)

(1)

Pricing

as

of

1/31/06.

Prices

reflect

actual

day

ahead

on-peak

settlement

prices

for

full-year

2003

–

Jan.

2006

and

forward

on-peak

monthly

prices for Feb. –

Dec. 2006.

2005

2004

2003

2006

Trend Line

$0

$25

$50

$75

$100

2003A:  $37.56

2006A/F:  $67.64

2004A:  $43.36

2005A:  $63.65

2005

2004

2003

2006

$0

$25

$50

$75

$100

$125

2003A:  $61.70

2006A/F:  $103.05

2004A:  $61.82

2005A:  $92.39

2005

2004

2003

2006

$0

$25

$50

$75

$100

$125

2003A:  $51.37

2006A/F:  $83.76

2004A:  $52.57

2005A:  $76.03

2005

2004

2003

2006

9

THEORETICAL HEDGING ACTIVITY

THEORETICAL HEDGING ACTIVITY

Time

Hedging

Activity

Hedging

Activity

Assumes market recovery progresses in an upward trend

Hedging locks in pre-set value discounted from market

10

ILLINOIS MARKET STRUCTURE

ILLINOIS MARKET STRUCTURE

1/24/06:  Affirmative 5-0 vote for reverse auction process by state regulators

adds surety and regulatory certainty to the Illinois marketplace

Expiration of current Ameren PPA at year-end 2006 will allow us to consider

multiple commercialization options for our Midwest fleet

Bilateral agreements, auction participation and other strategies

Dynegy is committed to serving Illinois state consumers

and market participants through our diverse assets

Southern Illinois

Coal-fired assets

Baseload facilities

Low-cost, reliable

Northern Illinois

Gas-fired assets

Peaking facilities

Strategic, efficient

Financial Overview

12

PAR OFFER TO REPURCHASE SPNs

PAR OFFER TO REPURCHASE SPNs

Declared Excess Proceeds and offered to repurchase $1.75 billion

of

SPNs at par on November 10, 2005

Par offer closed December 12, 2005

$400,000 accepted the offer and payment was delivered

Excess asset sale proceeds may now be used for any purpose not

otherwise prohibited under the SPN Indenture, such as

Repay (without permanently reducing) Priority Lien Debt

Repay Parity Lien Debt

Make a capital expenditure or otherwise invest in replacement assets

Toll settlement

Unsecured bond repurchase

Repayment of subordinated notes at maturity

13

DEBT CHART (12/31/05)

DEBT CHART (12/31/05)

Dynegy Inc..

Convertible Debentures     $225

Convertible Preferred         $400

Dynegy Power Corp.

Central Hudson

(1)

$785

Dynegy Holdings Inc.

Second Secured Notes     $1,750

Senior Notes/Debentures  $1,373

Subordinated Debentures    $200

Sithe Energies

Senior Debentures

$465

Subordinated Debentures

$419

Secured

Key

Secured Non-Recourse

Unsecured

(1)

Reflects PV (10%) of future lease payments.

14

LIABILITY MANAGEMENT CONSIDERATIONS

LIABILITY MANAGEMENT CONSIDERATIONS

Overall yield and cash interest

savings

Rate of return on dollars invested

Maturity profile

Further extension of Dynegy’s   

“Option Horizon”

Covenant relief

Unsecured bonds have limited

covenants

SPNs have most restrictive

covenants

Liquidity

Maintain adequate liquidity to provide

a solid financial foundation

(1) Yield To Worst reflects yield based on the bond call date.

113.75%

6.000%

900.0

7/15/13

10.125%

Sr. Secured

110.50%

5.620%

625.0

7/15/10

9.875%

Sr. Secured

106.25%

4.040%

225.0

7/15/08

L + 650

Sr. Secured -

Floaters

90.50%

9.350%

200.0

6/1/27

8.316%

SKIS -

Trust Preferred

96.50%

7.970%

175.0

10/15/26

7.625%

Sr. Unsecured

95.50%

7.700%

175.0

5/15/18

7.125%

Sr. Unsecured

109.50%

6.810%

500.0

2/15/12

8.750%

Sr. Unsecured

100.00%

6.875%

500.0

4/1/11

6.875%

Sr. Unsecured

Price

YTW

(1)

Amount

Maturity

Coupon

1/17/06

1/17/06

($ in MM)

Bond Prices and Yields

15

LOOKING AHEAD

LOOKING AHEAD

Restoring Confidence and Credibility

Completed new bank credit facilities

Reduced debt and extended maturities

Sold non-core lines of business

Restructured all long-term tolling

obligations

Resolved numerous litigations,

investigations and claims

Monetized tax assets for shareholder

benefit

The Next Phase of Dynegy’s Development

New senior leadership team

Option horizon for recovery

Commodity-cyclical business model

Midwest and Northeast regional focus

Financial flexibility

Organic growth

Opportunistic growth

Liability management

Running and Growing

Running and Restructuring

2006

2005

2002

Shareholder

Value

Appendix

17

DYNEGY POST-MIDSTREAM SALE:

A PURE POWER GENERATION PLAY

DYNEGY POST-MIDSTREAM SALE:

A PURE POWER GENERATION PLAY

Diversified portfolio

35% baseload, 19% intermediate,

46% peaking

31% coal/oil, 18% dual fuel,      

50% 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

FRCC

FRCC

SPP

SPP

MAIN

MAIN

ERCOT

ERCOT

WECC

WECC

SERC

SERC

West

43 MW Gas

Texas

610 MW Gas

3,384 MW Coal/Oil

442 MW Gas

Southeast

815 MW Gas

825 MW Gas/Oil

Northeast

1,338 MW Gas/Oil

370 MW Coal

1,021 MW Gas

49 MW Hydro

Midwest-Peakers

3,135 MW Gas

U.S. PORTFOLIO

12,032 net MW

Note:  In December 2005, Dynegy announced the planned exchange of ownership interests in the West Coast Power and Rocky Road assets.  Map

and percentages above exclude West Coast Power (902 MW) as NRG will purchase Dynegy’s 50% ownership in this facility.  Additionally, Dynegy

will acquire NRG’s 50% interest in Rocky Road (165 MW) in the Midwest.  This transaction is expected to close 1Q 2006.

Midwest

18

FUNDED DEBT AND OTHER OBLIGATIONS

MATURITY PROFILE (11/1/05, $ in MM)

FUNDED DEBT AND OTHER OBLIGATIONS

MATURITY PROFILE (11/1/05, $ in MM)

2005

2006

2007

2008

2009

2010

2011

$35

$44

$70

$339

$132

$115

$1,641

2012

2013

2014

2015

2016+

$722

$624

$138

$705

$1,087

Option Horizon

Option Horizon

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.

19

DEBT AND OTHER OBLIGATIONS ($ in MM)

DEBT AND OTHER OBLIGATIONS ($ in MM)

2005 net increase in debt primarily consists of

approximately $919 MM project debt acquired in

Sithe Energies acquisition

As of 9/30/05, 2005 debt repayments include:

$18 MM DHI Senior Notes

$17 MM Sithe Senior Notes

$5 MM Term Loan

On 10/31/05, repaid Term Loan and Riverside

note in amount of $783 MM

Net proceeds from Midstream sale of $2.4 B may

be applied to liability management or growth

opportunities

12/31/03

12/31/04

9/30/05

Secured Obligations

4,844

$        

3,307

$        

3,328

$      

Secured Non-Recourse Obligations

-

-

901

Unsecured Obligations

2,134

1,816

1,798

Preferred

411

400

400

Total Obligations

7,389

$        

5,523

$        

6,427

$      

Cash on Hand

477

$          

628

$          

205

$         

Note:  Debt includes preferred stock, par value debt obligations and obligations for Central Hudson.

12/31/03

12/31/04

$7,389

$5,523

$6,427

9/30/05

20

COLLATERAL POSTED ($ in MM)

COLLATERAL POSTED ($ in MM)

Total collateral higher from year-end 2004 to 3Q 2005

Increase in GEN due to increase in fuel requirements and commodity prices

Collateral for Independence tolling arrangement reclassified from CRM to GEN

NGL collateral expected to be returned substantially by 12/31/05

Beginning

in

2Q

2005,

collateral

transitioned

toward

letters

of

credit

versus

cash

in

order

to

replenish

cash

following

the

Sithe

Energies

acquisition

and

shareholder

class

action

settlement

payment

0

100

200

300

400

500

600

9/04

12/04

3/05

6/05

9/05

12/31/04

9/30/05

CRM

94

$        

86

$        

GEN

192

260

NGL

167

159

REG

10

-

Other

7

7

Total

470

$      

512

$      

Cash

376

$      

187

$      

LCs

94

325

Total

470

$      

512

$      

21

LIQUIDITY ($ in MM)

LIQUIDITY ($ in MM)

Decrease in cash on hand from 12/31/04 primarily due to Sithe Energies acquisition on

1/31/05

and

payments

for

shareholder

class

action

litigation

settlement,

offset

by

increase

in

cash from substitution of letters of credit as collateral

Cash collateral (not included in liquidity figures above) totaled $187 MM at 9/30/05

Effective shelf registration statement with approximately $430 MM of availability not

included in the $580 MM of liquidity*

Following sale of Midstream and required priority debt repayments, cash of $1.6 B will be

available for further liability management or growth opportunities

* Settlement of shareholder class action litigation in 1Q 2005 required issuance of 17.6 MM shares of Class A common stock.  These shares were

issued

pursuant

to

an

exemption

from

registration,

and

such

issuance

did

not

reduce

availability

under

the

effective

shelf

registration

of

$430

MM.

9/30/04

$1,508

Cash

Availability

$1,234

12/31/04

6/30/05

$968

3/31/05

$765

$580

9/30/05

22

REPORTED FINANCIAL PERFORMANCE

($ in MM, except per share amounts)

REPORTED FINANCIAL PERFORMANCE

($ in MM, except per share amounts)

(1) NGL classified as held for sale and financial results included in discontinued operations.

(2) REG business segment (Illinois Power) sold to Ameren as of 9/30/04.

(3) Includes results from continuing and discontinued operations.

(4) Reflects amounts included on the significant items schedule attached to the third quarter 2005 earnings release.

(5) Includes $11 MM (1Q 2004), $24 MM (2Q 2004) and $7 MM (3Q 2005) after-tax gains on asset sales in applicable periods.

RESULTS OF OPERATIONS

2004

2005

2004

2005

GEN

220

$           

177

$           

491

$           

362

$           

NGL

(1)

92

88

277

229

REG

(2)

85

-

171

-

CRM

(35)

(25)

62

(226)

Other

(49)

(26)

(167)

(329)

EBITDA

313

$           

214

$           

834

$           

36

$             

Depreciation and Amortization

(3)

(79)

(58)

(249)

(202)

Interest Expense

(3)

(125)

(114)

(402)

(324)

Income Tax Benefit (Expense)

(3)

(31)

(13)

(27)

295

Net Income (Loss)

78

$             

29

$             

156

$           

(195)

$          

Less: Preferred Stock Dividends

6

6

17

17

Net Income (Loss) Applicable to Common Shareholders

72

$             

23

$             

139

$           

(212)

$          

Diluted Earnings (Loss) Per Share

0.16

$          

0.06

$          

0.37

$          

(0.55)

$         

Significant Items (After-Tax)

(4)

-

Included in Net Income (Loss) Above

Tax -

Release of Valuation Allowance/Other

13

$             

-

$            

43

$             

125

$           

Independence Toll Settlement Adjustment (Charge)

-

-

-

(109)

Discontinued Operations

(5)

36

43

133

97

Gas Transportation Contracts

-

-

55

-

Gains on Asset Sales

56

-

56

-

Asset Impairments/Loss on Asset Sale

(43)

-

(86)

-

Acceleration of Financing Costs

-

-

(9)

-

Legal and Settlement Charges

-

(15)

(35)

(191)

Cash Flow from Operations

59

$             

(169)

$          

120

$           

(178)

$          

Three Months Ended Sept. 30

Nine Months Ended Sept. 30

23

2005 EARNINGS GUIDANCE ESTIMATES:

GAAP BASIS

2005 EARNINGS GUIDANCE ESTIMATES:

GAAP BASIS

Guidance as presented November 8, 2005

($ in millions)

       GEN

             NGL

            CRM

        OTHER

2005 Total

Previous EBITDA

$ 425-435

-

$ (70)

$ (100-95)

$ 255-270

Adjustments (Approximate)

Operations/Pricing/Other

65

-

15

-

80

New EBITDA

$ 480-500

-

$ (55)

$ (100-95)

$ 325-350

Depreciation

(210)

-

-

(15)

(225)

Interest

(385)

Tax Benefit

112-107

Preferred Dividend

(22)

Net Loss Applicable to Common Shareholders - Core Business

$ (195-175)

Independence Toll Settlement Charge, pre-tax

-

-

(169)

-

(169)

Legal and Settlements Charges, pre-tax

-

-

(29)

(249)

(278)

Tax Benefit, Tax Impact - on items above

-

-

71

76

147

Discontinued Operations - NGL

-

~ 930

-

-

~ 930

Net Income Applicable to Common Shareholders - GAAP

$ 435-455

NGL financial results classified as discontinued operations, see

following pages for further discussion

Independence toll settlement charge recorded 1Q 2005 upon closing of acquisition; $14 MM favorable pre-

tax adjustment recorded following completion of purchase price allocation

CRM legal and settlements charges reflect additional $29 MM pre-tax reserve recorded 3Q 2005

Other legal and settlements charges include $253 MM related to shareholder class action and derivative

settlements recorded in first six months 2005; $4 MM favorable pre-tax adjustment recorded 3Q 2005

Note:  Estimates are provided as a guide for forecasted 2005 consolidated financial results on an as-reported GAAP basis.  Forecasted segment

results are intended merely to reflect management’s estimate of the breakdown of its consolidated results and are subject to change.  Estimates do

not incorporate assumptions for potential items such as legal settlements, tolling settlements, capital raising activities or other restructuring events.

24

2005 CASH FLOW GUIDANCE ESTIMATES

2005 CASH FLOW GUIDANCE ESTIMATES

NGL segment results included in non-core cash flow, see following pages for further explanation

Sithe Energies acquisition cost of $120 MM comprised of purchase

price of $135 MM less various purchase

price adjustments and cash acquired; Dynegy also acquired $93 MM

of restricted cash that is not reflected

in cash flow

Baldwin escrow funds received 3Q 2005

Shareholder class action and derivative settlements and associated legal expenses paid 2Q 2005 and 3Q

2005

Illinois Power payments related to income taxes, final working capital settlement and other items

Note:  Estimates are provided as a guide for forecasted 2005 consolidated financial results on an as-reported GAAP basis.  Forecasted segment results

are intended merely to reflect management’s estimate of the breakdown of its consolidated results and are subject to change.  Estimates do not

incorporate assumptions for potential items such as legal settlements, tolling settlements, capital raising activities or other restructuring events.

Guidance as presented November 8, 2005

($ in millions)

        GEN

             NGL

            CRM

        OTHER

2005 Total

Previous OCF - Core Business

$ 465-470

-

$  (5)

$ (460-455)

$ 0-10

Adjustments (Approximate)

Operations/Pricing

65

-

(20)

(30)

15

Working Capital

(65)

-

(25)

-

(90)

New OCF - Core Business

$ 465-470

-

$  (50)

$ (490-485)

$ (75-65)

Capex - Maintenance

(130)

-

-

(6)

(136)

Free Cash Flow - Core Business

$ 335-340

-

$  (50)

$ (496-491)

$ (211-201)

Significant Items:

NGL Cash Flow

-

~ 2,588

-

-

~ 2,588

ANR/Middleton Gas Payment

-

-

(26)

-

(26)

Sithe Energies Acquisition

(120)

-

-

-

(120)

Baldwin Escrow Release

-

-

-

100

100

Shareholder Class Action and Derivative Settlements

-

-

-

(268)

(268)

Illinois Power Working Capital/Other

-

-

-

(14)

(14)

Capex - Development

(30)

-

-

(5)

(35)

Free Cash Flow

$ 185-190

$ ~ 2,588

$  (76)

$ (683-678)

$ 2,014-2,024

25

2005 EARNINGS GUIDANCE ESTIMATES: GAAP

BASIS –

NGL DISCONTINUED OPERATIONS

2005 EARNINGS GUIDANCE ESTIMATES: GAAP

BASIS –

NGL DISCONTINUED OPERATIONS

NGL financial results classified as discontinued operations for all periods

Depreciation of NGL assets ceased as of June 1, 2005 in accordance with GAAP due to

previous

“held-for-sale”

classification

Allocation of interest expense related to required debt reduction following sale; includes

expense associated with term loan and Riverside note

Note:  Estimates are provided as a guide for forecasted 2005 consolidated financial results on an as-reported GAAP basis.  Forecasted segment

results are intended merely to reflect management’s estimate of the breakdown of its consolidated results and are subject to change. 

Guidance as presented November 8, 2005

($ in millions)

            NGL

Previous EBITDA

$250

Adjustments (Approximate)

Operations/Pricing

15

New EBITDA

$  265

Depreciation

(37)

Interest

(50)

Tax Expense

(66)

NGL Operating Results

$  112

Gain on Sale of Assets

~ 1,100

Tax Expense - Gain on Sale

(407)

Reversal of Deferred Tax Valuation Allowance

125

Net Income From NGL Discontinued Operations

$  ~ 930

26

2005 CASH FLOW GUIDANCE ESTIMATES:

NGL FREE CASH FLOW

2005 CASH FLOW GUIDANCE ESTIMATES:

NGL FREE CASH FLOW

NGL segment results included in non-core cash flow due to sale

Proceeds from asset sale of $10 MM related to 3Q 2005 sale of Port Everglades property

Estimated return of collateral in 2005 of $80 MM; remaining $15 MM expected in 2006

Approximately $30 MM cash remaining in Midstream business

Note:  Estimates are provided as a guide for forecasted 2005 consolidated financial results on an as-reported GAAP basis.  Forecasted segment

results are intended merely to reflect management’s estimate of the breakdown of its consolidated results and are subject to change. 

Guidance as presented November 8, 2005

($ in millions)

            NGL

Previous OCF - Core Business

$260

Adjustments (Approximate)

Operations/Pricing

20

New OCF - Non-Core NGL Business

$  280

Proceeds from Asset Sale

10

Capex

(47)

Free Cash Flow From NGL Operations

$  243

Cash Proceeds at Closing

2,350

Estimated Return of Collateral

~ 80

Estimated Cash Taxes

~ (40)

Estimated Transaction Costs

~ (15)

Cash Remaining with Acquirer

~ (30)

Free Cash Flow From NGL

$ ~ 2,588

27

2006 EARNINGS GUIDANCE ESTIMATES:

GAAP BASIS

2006 EARNINGS GUIDANCE ESTIMATES:

GAAP BASIS

1.

GEN includes Central Hudson lease expense of approximately $50 MM and Sithe fair market

amortization of approximately $50 MM

Reflects operational EBITDA range of $825-925 MM

2.

CRM consists primarily of Sterlington toll, also reflects miscellaneous legacy gas and

power positions

3.

Other includes approximately $130 MM G&A, which is no longer allocated to business

segments, offset by approximately $30 MM interest income

4.

Interest reflects savings from debt reduction, offset by costs associated with liability

management activities assumed to occur throughout the year

5.

Preferred dividend related to Series C Convertible Preferred Securities held by Chevron

Note:  Estimates are provided as a guide for forecasted 2006 consolidated financial results on an as-reported GAAP basis.  Forecasted segment results

are intended merely to reflect management’s estimate of the breakdown of its consolidated results and are subject to change.  Estimates do not

incorporate assumptions for potential items such as legal settlements, tolling settlements, capital raising activities or other restructuring events.

Guidance as presented November 8, 2005

($ in millions)

        GEN

            CRM

        OTHER

2006 Total

EBITDA

$ 725-825

$ (60)

$ (100-90)

$ 565-675

Depreciation

(230)

-

(10)

(240)

Interest

(410)

Tax Benefit (Expense)

32-(8)

Preferred Dividend

(22)

Net Loss Applicable to Common Shareholders

$ (75-5)

1

2

3

4

5

28

2006 CASH FLOW GUIDANCE ESTIMATES

2006 CASH FLOW GUIDANCE ESTIMATES

1.

GEN includes Central Hudson lease payment of approximately $60 MM and Sithe interest

expense of approximately $70 MM

Excluding these payments, GEN OCF range is approximately $840-940 MM

2.

CRM consists of approximately $60 MM Sterlington toll payment and also includes

approximately $70 MM cash working capital impact arising from timing of settlement

differences between physical and financial transactions for previously hedged legacy gas

and power contracts

3.

Other primarily includes G&A costs of approximately $130 MM and cash interest payments

of approximately $260 MM, offset by approximately $30 MM interest income

Note:  Estimates are provided as a guide for forecasted 2006 consolidated financial results on an as-reported GAAP basis.  Forecasted segment results

are intended merely to reflect management’s estimate of the breakdown of its consolidated results and are subject to change.  Estimates do not

incorporate assumptions for potential items such as legal settlements, tolling settlements, capital raising activities or other restructuring events.

Guidance as presented November 8, 2005

($ in millions)

        GEN

            CRM

        OTHER

2006 Total

OCF - Core Business

$ 710-810

$ (130)

$ (360-350)

$ 220-330

Capex - Maintenance

(190)

-

(5)

(195)

Free Cash Flow - Core Business

$ 25-135

Significant Items:

Capex - Development

(5)

(5)

Free Cash Flow

$ 20-130

1

2

3

29

GAAP RECONCILIATION:  EARNINGS

GUIDANCE ESTIMATES

GAAP RECONCILIATION:  EARNINGS

GUIDANCE ESTIMATES

November 8, 2005

November 8, 2005

($ in millions)

2005 Guidance

2006 Guidance

Earnings before interest, taxes, and depr. and amort. (EBITDA) (1)(2)

$ 1,243-1,268

$ 565-675

Depreciation and amortization expense from continuing operations

(225)

(240)

Depreciation and amortization expense from discontinued operations

(37)

-

Interest expense from continuing operations

(385)

(410)

Interest expense from discontinued operations

(50)

-

Income tax benefit (expense) from continuing operations

259-254

32-(8)

Income tax expense from discontinued operations

(348)

-

Net income (loss)

$ 457-477

$ (53)-17

Preferred stock dividends

22

22

Net income (loss) applicable to common shareholders

$ 435-455

$ (75-5)

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

calculation: Net income  (loss) less Income tax benefit, plus Interest expense and Depreciation and amortization expense. 

Management

and

some

members

of

the

investment

community

utilize

EBITDA

to

measure

financial

performance

on

an

ongoing

basis.  However, EBITDA should not be used in lieu of GAAP measures such as net income (loss) and cash flow from operations.

(1) 2005 EBITDA guidance includes a $169 MM pre-tax ($109 MM after-tax) loss related to the Independence toll settlement charge

and

a

$278

MM

pre-

tax

($191

MM

after-tax)

charge

primarily

related

to

the

settlement

of

our

shareholder

class

action

law

suit

and

other legal and settlement charges.  2005 EBITDA guidance also includes earnings from the NGL segment as well as the associated

gain on sale of NGL assets.

30

GAAP RECONCILIATION:  QTD 3Q 2005

EARNINGS ($ in MM)

GAAP RECONCILIATION:  QTD 3Q 2005

EARNINGS ($ in MM)

GEN

NGL

REG

CRM

OTHER

Total

Generation

115

$         

115

$         

Natural Gas Liquids

Upstream  

-

$          

-

Downstream  

-

-

Regulated Energy Delivery

-

$              

-

Customer Risk Management

(18)

$          

(18)

Other  

(32)

$          

(32)

Operating income (loss)

115

-

-

(18)

(32)

65

$           

Earnings from unconsolidated investments

7

-

-

-

-

7

Other items, net

2

-

-

(5)

3

-

Add: Depreciation and amortization expense, a component of operating income (loss)

53

-

-

-

3

56

EBITDA from continuing operations (1)

177

-

-

(23)

(26)

128

EBITDA from discontinued operations, pre-tax (2)

-

88

-

(2)

-

86

EBITDA (1)

177

$         

88

$           

-

$          

(25)

$          

(26)

$          

214

$         

Depreciation and amortization expense

(58)

Interest expense

(114)

Pre-tax income

42

Income tax expense

(13)

Net income

29

$           

GEN

NGL

REG

CRM

OTHER

Total

Generation

71

$           

71

$           

Natural Gas Liquids

Upstream  

-

$          

-

Downstream  

-

-

Regulated Energy Delivery

83

$           

83

Customer Risk Management

(32)

$          

(32)

Other  

(57)

$          

(57)

Operating income (loss)

71

-

83

(32)

(57)

65

$           

Earnings from unconsolidated investments

99

-

-

-

-

99

Other items, net

-

-

2

(3)

1

-

Add: Depreciation and amortization expense, a component of operating income (loss)

50

-

-

1

7

58

EBITDA from continuing operations (1)

220

-

85

(34)

(49)

222

EBITDA from discontinued operations, pre-tax (2)

-

92

-

(1)

-

91

EBITDA (1)

220

$         

92

$           

85

$           

(35)

$          

(49)

$          

313

$         

Depreciation and amortization expense, a component of operating income (loss)

(79)

Interest expense

(125)

Pre-tax income

109

Income tax expense

(31)

Net income

78

$           

(1)

(2)

See Note (2) to "GAAP Reconciliation" on page 32. 

See Note (1) to "GAAP Reconciliation" on page 37.  EBITDA is a non-GAAP financial measure.  Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income

(loss) less Income tax benefit, plus Interest expense and Depreciation and amortization expense.  Management and some members of the investment community utilize EBITDA to measure financial

performance on an ongoing basis.  However, EBITDA  should not be used in lieu of GAAP measures such as net income and cash flow from operations. 

Three Months Ended September 30, 2004

Three Months Ended September 30, 2005

31

GAAP RECONCILIATION:  YTD 3Q 2005

EARNINGS ($ in MM)

GAAP RECONCILIATION:  YTD 3Q 2005

EARNINGS ($ in MM)

GEN

NGL

REG

CRM

OTHER

Total

Generation

194

$         

194

$         

Natural Gas Liquids

Upstream  

-

$          

-

Downstream  

-

-

Regulated Energy Delivery

-

$          

-

Customer Risk Management

(225)

$        

(225)

Other  

(353)

$        

(353)

Operating income (loss)

194

-

-

(225)

(353)

(384)

$        

Earnings from unconsolidated investments

14

-

-

-

-

14

Other items, net

4

-

-

(5)

10

9

Add: Depreciation and amortization expense, a component of operating income (loss)

150

-

-

1

14

165

EBITDA from continuing operations (1)

362

-

-

(229)

(329)

(196)

EBITDA from discontinued operations, pre-tax (2)

-

229

-

3

-

232

EBITDA (1)

362

$         

229

$         

-

$          

(226)

$        

(329)

$        

36

$           

Depreciation and amortization expense

(202)

Interest expense

(324)

Pre-tax loss

(490)

Income tax benefit

295

Net loss

(195)

$        

GEN

NGL

REG

CRM

OTHER

Total

Generation

159

$         

159

$         

Natural Gas Liquids

Upstream  

-

$          

-

Downstream  

-

-

Regulated Energy Delivery

158

$         

158

Customer Risk Management

45

$           

45

Other  

(201)

$        

(201)

Operating income (loss)

159

-

158

45

(201)

161

$         

Earnings (losses) from unconsolidated investments

187

-

-

-

-

187

Other items, net

-

-

3

(1)

4

6

Add: Depreciation and amortization expense, a component of operating income (loss)

145

-

10

1

27

183

EBITDA from continuing operations (1)

491

-

171

45

(170)

537

EBITDA from discontinued operations, pre-tax (2)

-

277

-

17

3

297

EBITDA (1)

491

$         

277

$         

171

$         

62

$           

(167)

$        

834

$         

Depreciation and amortization expense, a component of operating income (loss)

(249)

Interest expense

(402)

      ��   

Pre-tax income

183

Income tax expense

(27)

Net income

156

$         

(1)

(2)

See Note (2) to "GAAP Reconciliation" on page 32. 

See Note (1) to "GAAP Reconciliation" on page 37.  EBITDA is a non-GAAP financial measure.  Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation:

Net income (loss) less Income tax benefit, plus Interest expense and Depreciation and amortization expense.  Management and some members of the investment community utilize EBITDA

to measure financial performance on an ongoing basis.  However, EBITDA  should not be used in lieu of GAAP measures such as net income and cash flow from operations. 

Nine Months Ended September 30, 2004

Nine Months Ended September 30, 2005

32

GAAP RECONCILIATION ($ in MM)

GAAP RECONCILIATION ($ in MM)

(1)

2005

2004

2005

2004

Operating income (loss)

65

$                        

65

$                        

(384)

$                     

161

$                      

Add: Depreciation and amortization expense, a component of operating income (loss)

56

58

165

183

Earnings from unconsolidated investments

7

99

14

187

Other income and expense, net

-

-

9

6

EBITDA from discontinued operations (3)

86

91

232

297

Earnings before interest, taxes, and depreciation and amortization (EBITDA)

214

313

36

834

Depreciation and amortization expense, a component of operating income (loss)

(56)

(58)

(165)

(183)

Depreciation and amortization expense from discontinued operations

(2)

(21)

(37)

(66)

Interest expense from continuing operations

(99)

(115)

(284)

(386)

Interest expense from discontinued operations

(15)

(10)

(40)

(16)

Income tax benefit (expense) from continuing operations

13

(7)

228

75

Income tax benefit (expense) from discontinued operations

(26)

(24)

67

(102)

Net income (loss)

29

$                        

78

$                        

(195)

$                     

156

$                      

-

-

-

-

(2)

2005

2004

2005

2004

EBITDA from discontinued operations

86

$                        

91

$                        

232

$                      

297

$                      

Depreciation and amortization expense from discontinued operations

(2)

(21)

(37)

(66)

Interest expense from discontinued operations

(15)

(10)

(40)

(16)

Income tax benefit (expense) from discontinued operations

(26)

(24)

67

(102)

Income from discontinued operations, net of tax

43

$                        

36

$                        

222

$                      

113

$                      

A reconciliation of EBITDA from discontinued operations to Income from discontinued operations, net of tax for the periods presented is included below.

Three Months Ended

Nine Months Ended

September 30,

September 30,

September 30,

September 30,

Nine Months Ended

Three Months Ended

EBITDA is a non-GAAP financial measure.  Consolidated EBITDA can be reconciled to Net income (loss) using the following calculation: Net income (loss) less Income tax benefit, plus Interest

expense and Depreciation and amortization expense.  Management and some members of the investment community utilize EBITDA to measure financial performance on an ongoing basis. 

However, EBITDA should not be used in lieu of GAAP measures such as net income and cash flow from operations.  A reconciliation of EBITDA to Operating income (loss) and Net income (loss)

for the periods presented is included below.

33

GAAP RECONCILIATION:  CASH FLOW

ESTIMATES

GAAP RECONCILIATION:  CASH FLOW

ESTIMATES

November 8, 2005

November 8, 2005

($ in millions)

2005 Guidance

2006 Guidance

Cash Flow from Operations (1)

$ (98-88)

$ 220-330

Less: Capex

and Business Acquisition Costs (2)

(338)

(200)

Add:  Proceeds from Asset Sales (3)

2,450

-

Free Cash Flow (4)

$ 2,014-2,024

$ 20-130

(1) Cash flow from operations in 2005 guidance includes $26 MM payment to ANR/Middleton related to the exit of long-

term gas transportation contracts, $268 MM payment related to settlement of shareholder class action litigation and $9 MM

payment related to Illinois Power working capital and other.

(2)

Capex

and

business

acquisition

costs

in

2005

guidance

includes

$120

MM

outflow

related

to

the

Sithe

Energies

acquisition.

This

consists

of

the

purchase

price

of

$135

MM

less

various

purchase

price

adjustments.

Dynegy

also

received $93 MM of restricted cash which is excluded from cash flow.

(3)

Proceeds

from

asset

sales

in

2005

guidance

includes

proceeds

from

the

sale

of

the

NGL

business,

as

well

as

the

release of $100 MM cash held in Baldwin escrow account, offset by $5 MM payment related to Illinois Power purchase

price adjustment regarding sale of assets to Ameren.

(4) Free cash flow is a non-GAAP financial measure.  Free cash flow consists of cash flows from operations less capital

expenditures and business acquisition costs, adjusted for proceeds from asset sales.  We use free cash flow to

measure the cash generating ability of our operating asset-based energy businesses relative to their capital expenditure

obligations.  Free cash flow should not be used in lieu of GAAP measures with respect to cash flows and should not be

interpreted

as

available

for

discretionary

expenditures,

as

mandatory

expenditures

such

as

debt

obligations

are

not

deducted

from

the

measure.

A

reconciliation

of

free

cash

flow

to

cash

flow

from

operations

by

segment

for

the

periods

presented

on

page

34.

34

GAAP RECONCILIATION:  CASH FLOW ($ in MM)

GAAP RECONCILIATION:  CASH FLOW ($ in MM)

GEN

NGL

REG

CRM

OTHER

Total

Cash Flow from Operations

354

$            

241

$            

-

$            

(64)

$            

(709)

$          

(178)

$          

Capital Expenditures

(87)

(39)

-

-

(6)

(132)

Business Acquisition Costs

(120)

-

-

-

-

(120)

Proceeds from Asset Sales (1)

1

10

(5)

-

100

106

Free Cash Flow (2)

148

$            

212

$            

(5)

$              

(64)

$            

(615)

$          

(324)

$          

GEN

NGL

REG

CRM

OTHER

Total

Cash Flow from Operations

351

$            

194

$            

213

$            

(179)

$          

(459)

$          

120

$            

Capital Expenditures

(78)

(41)

(92)

-

(10)

(221)

Proceeds from Asset Sales

245

65

217

-

-

527

Free Cash Flow (2)

518

$            

218

$            

338

$            

(179)

$          

(469)

$          

426

$            

(1)

During the first quarter 2005, we paid approximately $5 million to Ameren related to the working capital adjustment for our sale of Illinois Power.

(2)

Free cash flow is a non-GAAP financial measure.  Free cash flow consists of cash flows from operations less capital expenditures and business

acquisition costs, net, adjusted for proceeds from asset sales.  We use free cash flow to measure the cash generating ability of our operating asset-

based energy businesses relative to their capital expenditure obligations.  Free cash flow should not be used in lieu of GAAP measures with respect

to cash flows and should not be interpreted as available for discretionary expenditures, as mandatory expenditures such as debt obligations are not

deducted from the measure.  A reconciliation of free cash flow to cash flow from operations by segment for the periods presented is included above.

Nine Months Ended September 30, 2005

Nine Months Ended September 30, 2004

35

DYNEGY GENERATION FACILITIES

DYNEGY GENERATION FACILITIES

Net

Primary

Dispatch

Region/Facility

(1)

NERC Region

Location

Capacity

Fuel Type

Type

DMG

Baldwin

MAIN (Midwest)

Baldwin, IL

1,768

Coal

Baseload

Havana

Units 1-5

MAIN (Midwest)

Havana, IL

238

Oil

Peaking

Unit 6

MAIN (Midwest)

Havana, IL

445

Coal

Baseload

Hennepin

MAIN (Midwest)

Hennepin, IL

290

Coal

Baseload

Oglesby

MAIN (Midwest)

Oglesby, IL

54

Gas

Peaking

Stallings

MAIN (Midwest)

Stallings, IL

82

Gas

Peaking

Tilton

MAIN (Midwest)

Tilton, IL

176

Gas

Peaking

Vermilion

MAIN (Midwest)

Oakwood, IL

191

Coal/Gas/Oil

Baseload/Peaking

Wood River

Units 1-3

MAIN (Midwest)

Alton, IL

130

Gas

Peaking

Units 4-5

MAIN (Midwest)

Alton, IL

452

Coal

Baseload

DMG COMBINED

3,826

DMW

Bluegrass

ECAR (Midwest)

Oldham, Cty, KY

495

Gas

Peaking

Foothills

ECAR (Midwest)

Louisa, KY

330

Gas

Peaking

Renaissance

ECAR (Midwest)

Carson City, MI

660

Gas

Peaking

Riverside

(6)

ECAR (Midwest)

Oldham, Cty, KY

495

Gas

Peaking

Rocky Road

(2)

MAIN (Midwest)

East Dundee, IL

165

Gas

Peaking

Rolling Hills

ECAR (Midwest)

Wilkesville, OH

825

Gas

Peaking

DMW COMBINED

2,970

DNE

Allegheny

MAAC (Northeast)

Pennsylvania

49

Hydro

Intermediate

Danskammer

Units 1-2

NPCC (Northeast)

Newburgh, NY

128

Gas/Oil

Peaking

Units 3-4 (3)

NPCC (Northeast)

Newburgh, NY

370

Coal/Gas/Oil

Baseload

Independence

NPCC (Northeast)

Scriba, NY

1,021

Gas

Intermediate

Roseton (3)

NPCC (Northeast)

Newburgh, NY

1,210

Gas/Oil

Intermediate

DNE COMBINED

2,778

36

DYNEGY GENERATION FACILITIES

(CONTINUED)

DYNEGY GENERATION FACILITIES

(CONTINUED)

Net

Primary

Dispatch

Region/Facility

NERC Region

Location

Capacity

Fuel Type

Type

DSE

Calcasieu

SERC (Southeast)

Sulphur, LA

320

Gas

Peaking

Heard County

SERC (Southeast)

Heard Cty, GA

495

Gas

Peaking

Rockingham

SERC (Southeast)

Rockingham Cty, NC

825

Gas/Oil

Peaking

DSE COMBINED

1,640

WEST

West Coast Power

(4)

Cabrillo

I (Encina)

WECC (West)

Carlsbad, CA

480

Gas

Intermediate

Cabrillo

II

WECC (West)

San Diego, CA

87

Gas

Peaking

El Segundo

WECC (West)

El Segundo, CA

335

Gas

Intermediate

West Coast Power Combined

902

Black Mountain

(5)

WECC (West)

Las Vegas, NV

43

Gas

Baseload

WEST COMBINED

945

TEXAS

Cogen

Lyondell

ERCOT (Texas)

Houston, TX

610

Gas

Baseload

TEXAS COMBINED

610

TOTAL DYNEGY GENERATION

12,769

(6) DYN leases this facility.

(2) DYN owns a 50% interest in this facility and the remaining 50% interest is held by NRG Energy.

(3)

DYN

entered

into

a

$920

mm

sale-leaseback

transaction

for

the

Roseton

facility

and

units

3

and

4

of

the

Danskammer

facility.  Cash lease payments extend until 2029 and include $60.4 mm in 2004-2006, $107.5 mm in

2007, $144 mm in 2008, $141.3 mm in 2009 and $95.4 mm in 2010.  GAAP lease payments are $50.5 mm through

2030 and decrease until last GAAP lease payment in 2035.

(1) DYN owns 100% of each unit listed except as otherwise indicated.  For each unit in which DYN owns less

than

a

100%

interest,

the

Total

Net

Generating

Capacity

set

forth

in

this

table

includes

only

DYN's

proportionate

share of such unit's gross generating capacity.

(5) DYN owns a 50% interest in this facility and the remaining 50% interest is held by Chevron.

(4) DYN owns a 50% interest in each of these facilities through West Coast Power, L.L.C., a joint venture with

NRG Energy.  DYN's

50% interest in West Coast Power's Long Beach generation facility has not been included

because this asset was retired effective January 1, 2005.