Dynegy Illinois 8-K Other Events

Merrill Lynch

Houston Power & Gas Day

Merrill Lynch

Houston Power & Gas Day

March 20, 2007

Houston, TX

Investor

&

Public

Relations:

Norelle-Lundy,

Vice

President

Hillarie

Forister,

Senior

Analyst

(713)

507-6466

ir@dynegy.com

Filed

by

Dynegy

Acquisition,

Inc.

Pursuant

to

Rule

425

of

the

Securities

Act

of

1933,

as

amended,

and

deemed

filed

pursuant

to

Rule

14a-12

of

the

Securities

Exchange

Act

of

1934,

as

amended

Subject

Company:

Dynegy

Inc.

Commission

File

No:

001-15659

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

2007

financial

estimates

and

the

proposed

combination

with

LS

Power,

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,

including

its

2006

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

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.

In

connection

with

the

LS

Power

transaction

announced

on

September

15,

2006,

Dynegy

and

Dynegy

Acquisition,

Inc.

have

filed

a

definitive

proxy

statement/prospectus

with

the

SEC.

INVESTORS

AND

SECURITY

HOLDERS

ARE

URGED

TO

CAREFULLY

READ

THE

IMPORTANT

INFORMATION

CONTAINED

IN

THE

MATERIALS

REGARDING

THE

PROPOSED

TRANSACTION.

THEY

CONTAIN

IMPORTANT

INFORMATION

ABOUT

DYNEGY,

LS

POWER,

THE

NEW

COMPANY

AND

THE

PROPOSED

TRANSACTION.

Investors

and

security

holders

may

obtain

a

copy

of

the

definitive

proxy

statement/prospectus

and

other

documents

containing

information

about

Dynegy

and

LS

Power,

free

of

charge,

at

the

SEC’s

web

site

at

www.sec.gov

and

at

Dynegy’s

web

site

at

www.dynegy.com.

Copies

of

the

definitive

proxy

statement/prospectus

may

also

be

obtained

by

writing

Dynegy

Inc.

Investor

Relations,

1000

Louisiana

Street,

Suite

5800,

Houston,

Texas

77002

or

by

calling

713-507-6466.

Dynegy,

LS

Power

and

their

respective

directors

and

executive

officers

and

other

members

of

management

and

employees

may

be

deemed

to

be

participants

in

the

solicitation

of

proxies

from

Dynegy’s

shareholders

with

respect

to

the

proposed

transaction.

Information

regarding

Dynegy’s

directors

and

executive

officers

is

available

in

the

company’s

proxy

statement

for

its

2006

Annual

Meeting

of

Shareholders,

dated

April

3,

2006. 

Additional

information

regarding

the

interests

of

such

potential

participants

is

included

in

the

definitive

proxy

statement/prospectus

and

other

relevant

documents

filed

with

the

SEC.

Non-GAAP

Financial

Measures:

We

use

the

non-GAAP

financial

measures

“EBITDA”

and

“free

cash

flow”

in

these

materials. 

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

(expense),

plus

Interest

expense

and

Depreciation

and

amortization

expense

equals

EBITDA.

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.

Free

cash

flow

is

a

non-GAAP

financial

measure.

Free

cash

flow

can

be

reconciled

to

operating

cash

flow

using

the

following

calculation: 

Operating

cash

flow

plus

investing

cash

flow

(consisting

of

asset

sale

proceeds

less

business

acquisition

costs,

capital

expenditures

and

changes

in

restricted

cash)

equals

free

cash

flow.

We

use

free

cash

flow

to

measure

the

cash

generating

ability

of

our

operating

asset-based

energy

business

relative

to

our

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.

3

2006 ANNUAL HIGHLIGHTS

2006 ANNUAL HIGHLIGHTS

Generation EBITDA improved year-over-year

2006 benefited from strong execution of near-term commercial strategy and continued focus on reliable

operations

2006 impacted by liability management costs and asset impairments, while 2005 included the

gain on the sale of the Midstream business, offset by toll settlements and legal charges

Completed

comprehensive

liability

management

plan,

reducing

debt

and

other

obligations

by

more

than

$2.5

B

Completed Rocky Road-West Coast Power asset exchange and Rockingham asset sale

Announced

agreement

with

state

of

Illinois

to

reduce

mercury

and

other

emissions,

which

is

expected

to

create

one

of

the

cleanest-burning

coal

fleets

in

Illinois

and

U.S.

Participated in Illinois auction process to supply a portion of Ameren’s full-requirements load

Settled Enron trade credit litigation, resolving a major legacy legal claim

Announced proposed LS Power combination and development joint venture

Building a strong platform for future consolidation and growth

4

INTEGRATION UPDATE

INTEGRATION UPDATE

Expiration of Hart-Scott-Rodino waiting period

Filing of preliminary proxy statement/prospectus with SEC

Presentation of 2007 combined company cash flow and earnings estimates

Receipt of New York Public Service Commission approval

Receipt of FERC approval

Proxy

statement

and

prospectus

effective

with

the

SEC

and

mailed

to

shareholders

Pending:

Special shareholder meeting and affirmative vote of at least 2/3 of Dynegy’s

Class A shares; meeting scheduled for March 29, 2007

Pending:

Transaction closing

On track for transaction closing on April 2nd

5

NEW DYNEGY’S PLANNED CAPITAL STRUCTURE

PRO FORMA AS OF CLOSING ($ in MM)

NEW DYNEGY’S PLANNED CAPITAL STRUCTURE

PRO FORMA AS OF CLOSING ($ in MM)

Dynegy Power Corp.

Central Hudson

(3)

$820

Dynegy Holdings Inc.

$750 Million Revolver

(1)

$275

Synthetic LC Facility

(2)

$500

Second Secured Notes

$11

Sr. Unsec. Notes/Debentures

$2,397

Subordinated Debentures

$200

Secured

Key

Secured Non-Recourse

Unsecured

Dynegy Inc..

Sithe Energies

Senior Debentures      $428

LS Power Portfolio

(4)

1

st

Lien

$1,500

2

nd

Lien

200

Operating Assets

$1,700

Plum Point, Net

202

Total

$1,902

Note:

Represents

current

capital

structure

expectations

and

assumptions

as

of

February

2007,

which

have

been

adjusted

to

reflect

balances

expected

as

of

3/31/07.

(1)

Represents

drawn

amounts

under

the

revolver

upon

expected

closing

of

transaction.

(2)

Proceeds

from

this

facility

are

expected

to

be

drawn

and

fully

collateralize

the

issuance

of

letters

of

credit.

Includes

$200

MM

from

original

facility,

$185

MM

for

LS

Power

parental

support,

$83

MM

for

Sithe

debt

reserve

and

$32

MM

for

miscellaneous

developmental

requirements.

(3)

Central

Hudson

lease

payments

are

unsecured

obligations

of

Dynegy

Inc.,

but

are

a

secured

obligation

of

an

unrelated

third

party

(“lessor”)

under

the           

lease.

DHI

has

guaranteed

the

lease

payments

on

a

senior

unsecured

basis.

Amount

reflects

PV

(10%)

of

future

lease

payments

as

of

3/31/07.

(4)

See

the

appendix

for

more

details

about

the

LS

Power

debt

portfolio.

6

2007 CASH FLOW ESTIMATES: GAAP BASIS

2007 CASH FLOW ESTIMATES: GAAP BASIS

GEN OCF adjustment primarily related to cash received in 2006 for 2007 forward sales

Other OCF adjustment due to timing of Sithe interest payment previously expected in 2006

Note:  2007 estimates are presented on a GAAP basis, are based on quoted forward commodity price curves as of 1/30/07 and assume

closing of the LS Power transaction at

end 1Q 2007.  Actual results may vary materially from these estimates based on changes in commodity prices, among other things, including operational activities, legal

settlements, financing or investing activities and other uncertain or unplanned items. Core business represents continuing operating results, excluding significant items.

(1) Asset sale proceeds in the range of $200-500 MM are expected from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets

where the value that can be captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets.  Divestitures could result in

impairment charges and could reduce 2007 and forward EBITDA or free cash flow.  Proceeds from the expected sale of Calcasieu are

assumed to be received in early 2008. 

As Presented February 27, 2007; Based on Price Curves as of January 30, 2007

($ in millions)

GEN

OTHER

2007 Total

Previous GAAP OCF Estimates

$ 1,170-1,260

$ (570-560)

$ 600-700

Adjustments (Approximate):

Timing of Receipts and Payments

(80)

(20)

(100)

New GAAP OCF Estimates

$ 1,090-1,180

$ (590-580)

$ 500-600

GAAP ICF

Capex

-

Maintenance

(155)

(15)

(170)

Capex

-

Consent Decree

(90)

-

(90)

Capex

-

Plum Point Development

(155)

-

(155)

Investment in Development Portfolio

-

(10)

(10)

Proceeds from Asset Sales and Acquisition Costs, Net

(1)

200

(145)

55

Change in Restricted Cash

155

30

185

Free Cash Flow

$ 315-415

Add Back: Acquisition Costs

145

Less: Proceeds from Asset Sales

(1)

(200)

Free Cash Flow -

Core Business

$ 260-360

7

2007 EARNINGS ESTIMATES: GAAP BASIS

2007 EARNINGS ESTIMATES: GAAP BASIS

As Presented February 27, 2007; Based on Price Curves as of January 30, 2007

($ in millions)

      Midwest

    West

    Northeast

      Total GEN

        OTHER

2007 Total

EBITDA Estimates

$ 745-795

$ 215-235

$ 175-205

$ 1,135-1,235

$ (115-105)

$ 1,020-1,130

Depreciation

(180)

(45)

(40)

(265)

(15)

(280)

Interest

(435)

Tax Expense

(115-160)

Net Income Applicable to Common Shareholders - GAAP

$ 190-255

Earnings Per Share

(1)

$ 0.25-0.34

Note:  2007 estimates are presented on a GAAP basis, are based on quoted forward commodity price curves as of 1/30/07 and assume

closing of the LS Power transaction at

end 1Q 2007, excluding purchase accounting adjustments.  Actual results may vary materially from these estimates based on changes in commodity prices, among other

things, including operational activities, legal settlements, financing or investing activities and other uncertain or unplanned items.  Reduced 2007 and forward EBITDA or free

cash flow could result from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets where the value that can be captured through a

divestiture is believed to outweigh the benefits of continuing to own or operate such assets. Divestitures could result in impairment charges.

(1) Calculated based on 755 MM weighted-average shares outstanding.

Other includes G&A costs of approximately $160 MM, primarily offset by interest income

Interest expense of $435 MM includes approximately $30 MM for Plum Point

Estimates exclude purchase accounting adjustments to be recorded

upon closing of LS

Power transaction

Earnings may be more volatile as many of the forward sales commitments associated

with the LS Power portfolio are marked-to-market under GAAP, which may create

variances between earnings and cash flows in certain periods

8

Expected 2007 Total EBITDA Ranges

Given $/MMBtu Cost of Natural Gas

2007 TOTAL EARNINGS SENSITIVITY

TO NATURAL GAS

2007 TOTAL EARNINGS SENSITIVITY

TO NATURAL GAS

Full-year 2007 average natural gas price

as of 1/30/07 = $7.80/MMBtu (Henry Hub)

+/-

$1/MMBtu change in natural gas is

approximately equal to:

+/-

~4% change

(3)

in Generation EBITDA

+/-

~$50 MM change in Generation EBITDA

Note:

EBITDA

based

on

full-year

estimates

as

presented

2/27/07

for

existing

Dynegy

assets

and

9

months

of

estimates

for

LS

Power

assets

beginning

4/01/07.

(1)

Pricing

as

of

11/01/06,

which

was

the

basis

for

estimates

as

presented

12/13/06.

Prices

reflect

quoted

forward

on-peak

monthly

prices

for

2007.

(2)

Pricing

as

of

1/30/07,

which

was

the

basis

for

estimates

as

presented

2/27/07.

Prices

reflect

actual

day

ahead

settlement

prices

for

Jan.

1

–

Jan.

30       

and

quoted

forward

monthly

prices

for

Jan.

31

–

Dec.

2007.

(3)

Percentage

change

calculated

based

on

Generation

EBITDA

estimates

of

a

range

of

$1,135-1,235

MM

as

presented

2/27/07.

(12-Month Average $/MMBtu)

$900

$1,000

$1,100

$1,200

$1,300

$6.00 Gas

$8.00 Gas

$10.00 Gas

$920

$1,030

$975

$1,020

$1,130

$1,120

$1,230

$1,175

$1,075

$0

$2

$4

$6

$8

$10

J

F

M

A

M

J

J

A

S

O

N

D

2006A:  $6.74

2007F (Nov):  $8.05

($/MMBtu)

Natural

Gas

2006 Actual

2007 Forward as of 11/01/06

(1)

--

OR --

2007A/F (Jan):  $7.80

2007 Actual/Forward as of 1/30/07

(2)

9

MARKET IMPLIED HEAT RATES

MARKET IMPLIED HEAT RATES

Market implied heat rates are derived from market gas and power prices, and are impacted by

weather and outages in the short-term, and overall supply/demand balance in the longer-term

Changes in market implied heat rates can affect plants in various ways:

Impact to coal plants is primarily as a result of changes to margin based on the difference between power

prices and production costs

Roseton more sensitive to spreads based on fuel oil prices than spreads based on natural gas

Impact to gas plants results from changes to margin and volume

Facilities with forward sales commitments, RMR contracts, or tolling arrangements may not be as sensitive to

changes in market implied heat rates

In

this

example,

ERCOT

market

implied

heat

rates

reflect

“on-peak”

pricing,

assuming

constant

natural

gas

price:

Spark spread value changes depend on natural gas price assumptions

Example: ~$8.00/MMBtu natural gas x .5 MMBtu/MWh heat rate change = $4.00

spark spread value

OR  ~$10.00/MMBtu natural gas x .5 MMBtu/MWh heat rate change = $5.00 spark spread value

Note: Baseload coal sensitivity to heat rate changes does not apply if power prices are assumed constant with variable natural gas prices.

(1) Average natural gas price as of 11/01/06, which was the basis for estimates as presented 12/13/06.

+ 500 Btu/MWh

Base Case

- 500 Btu/MWh

On-Peak Power Price ($/MWh)

$ 84

$ 80

$ 76

Natural Gas ($/MMBtu)

(1)

$ 8.05

$ 8.05

$ 8.05

Market Implied Heat Rate

~10,500

~10,000

~9,500

10

2007 TOTAL EARNINGS SENSITIVITY TO

MARKET IMPLIED HEAT RATES

2007 TOTAL EARNINGS SENSITIVITY TO

MARKET IMPLIED HEAT RATES

Sensitivities based on “on-peak”

power price changes

Estimates based on full-year and nine months of earnings for Dynegy and LS Power assets,

respectively

Sensitivities apply only  to 2007 earnings

Assumes constant natural gas price of $8.05/MMBtu and heat rate changes are for a full year

Coal

and

fuel-oil

plant

impacts

primarily

driven

by

changes

in

power

prices

Combined

cycle

sensitivities

impacted

by

spark

spread

value

and

associated

changes

in

run-time

Peakers

run

when

economical

but

have

minimal

impact

in

current

pricing

environment;

however,

if

market

implied

heat

rates

continue

to

increase,

peakers

will

add

increased

upside

potential

Market Implied

Heat Rate Movement

Coal/Fuel Oil

Gas

Total

+ 1,500 Btu/MWh

$105

$125

$230

+ 500 Btu/MWh

$40

$35

$75

- 500 Btu/MWh

-$25

-$30

-$55

- 1,500 Btu/MWh

-$75

-$95

-$170

Generation EBITDA Sensitivity ($ in MM)

Note: EBITDA calculations exclude purchase accounting adjustments, which will impact the value of the LS Power fleet when recorded upon

transaction close.

11

MARKET RECOVERY UPSIDE

MARKET RECOVERY UPSIDE

Market recovery upside refers to expected benefits resulting from tightening markets due to 

supply/demand balance and consolidation benefits

Baseload –

affected by increased outright power pricing, as run-times are currently at high levels

and coal and rail costs are essentially flat in the near-term

Intermediate –

should benefit from both improved pricing/spreads, increased volumes and

improved capacity markets

Peakers –

should benefit from both improved pricing/spreads, increased volumes and improved

capacity markets

Consolidation –

results in G&A, O&M and financing cost savings due to Dynegy’s scalable

platform

and

reduced

duplication

of

overhead;

this

“Consolidation

Benefit”

is

in

addition

to

market recovery upside

Price / Spread

Volume

Cost Savings

Baseload

Intermediate

Peaker

Consolidation

= Areas for Potential Upside in Market Recovery

12

Closing Price of Dynegy Common Stock

Closing Price of DHI 8.375%

Senior Unsecured Notes Due 2016

RECENT PRICE PERFORMANCE

RECENT PRICE PERFORMANCE

Dynegy common stock and unsecured bond prices have steadily risen since

announcement of LS Power combination, illustrating, in part, both the equity and fixed

income market’s favorable perception of the proposed merger

Voting

for

the

combination

is

important…a

failure

to

vote

is

a

vote

“against”

the

deal

$5

$6

$7

$8

9/15/06

10/15/06

11/15/06

12/15/06

1/15/07

2/15/07

$100

$103

$106

$109

9/15/06

10/15/06

11/15/06

12/15/06

1/15/07

2/15/07

9/15/06:

$6.07

2/21/07:

$8.00

9/15/06:

$101.50

2/21/07:

$108.25

13

UPCOMING EVENTS

UPCOMING EVENTS

Houston:  Special Meeting of Shareholders on March 29

Special Meeting of Shareholders on March 29

VOTING “FOR”

the Dynegy/LS Power Merger is Important

A Failure to Vote is a Vote “Against”

the Deal

14

Appendix

15

NEW DYNEGY PORTFOLIO

NEW DYNEGY PORTFOLIO

Scale and scope in key regions

Note:

Plum

Point

1

currently

under

construction.

MW

totals

exclude

development

and

repowerings,

opportunities

for

which

exist

at

Bridgeport,

Griffith,

Morro

Bay,

Moss

Landing,

Oakland

and

South

Bay.

Dynegy

has

entered

into

an

agreement

to

sell

the

351-MW

Calcasieu

peaking

facility

in

Louisiana,

the closing of which is expected in early 2008.

Primary Fuel Type

Nameplate Capacity (MW)

More than 900 MW

500 MW to 900 MW

150 MW to 500 MW

Less than 150 MW

LS Power -

Operating

Coal

Gas

Gas/Oil

Wind

LS Power -

Development

Dynegy Inc.

Midwest

9,495 MW

Northeast

3,809 MW

Transmission

Total

20,044 MW

West

6,740 MW

Dynegy Inc. –

Potential Sale

16

DIVERSIFIED AND BALANCED PORTFOLIO

DIVERSIFIED AND BALANCED PORTFOLIO

Northeast

23.4%

Midwest

63.4%

South

13.2%

Northeast

12.9%

Midwest

24.6%

West

62.5%

Intermediate

19.2%

Peaking

45.3%

Baseload

35.5%

Intermediate

25.8%

Peaking

41.7%

Baseload

32.5%

Peaking

36.5%

Baseload

28.3%

Intermediate

35.2%

Fuel

Diversity

Coal/Oil

20.9%

Dual Fuel

6.5%

Gas -

CCGT

33.4%

Gas -

Simple Cycle

39.2%

Portfolio diversified through geographic locations,

fuel and dispatch types

Dynegy

Capacity

LS Power

Capacity

Combined

Capacity

Geographic

Diversity

Dispatch

Diversity

Note:

Includes

MWs

for

assets

to

be

sold

or

considered

for

divestiture.

Dynegy

has

entered

into

an

agreement

to

sell

the

351-MW

Calcasieu

peaking

facility

in

Louisiana,

the

closing

of

which

is

expected

in

early

2008.

Other

possible

divestitures

include

the

Bluegrass,

Cogen

Lyondell

and

Heard

County

generation

facilities.

Northeast

19.0%

Midwest

47.4%

South 

7.5%

West

26.1%

17

GROWTH THROUGH CONSOLIDATION

BENEFITS FOR INVESTORS

GROWTH THROUGH CONSOLIDATION

BENEFITS FOR INVESTORS

Greater scale and scope without proportionate increase in costs

Greater scale and scope without proportionate increase in costs

New Dynegy’s competitive position enhanced

through more assets under management

Note: G&A estimates are as presented 2/27/07.

(1) Excludes $55 MM pre-tax legal and settlement charges recorded in G&A.

(2)

Based

on

full-year

estimates

for

Dynegy

and

9

months

of

estimates

for

LS

Power

beginning

4/01/07,

including

certain

acquisition-related

expenditures.

0

5,000

10,000

15,000

20,000

25,000

Megawatts

Estimated G&A ($ in MM)

2007

2006

$140

(1)

$160

(2)

11,739

20,044

Megawatts increase 71%,

while G&A up only 14%

Megawatts increase 71%,

while G&A up only 14%

18

GREENFIELD DEVELOPMENT

GREENFIELD DEVELOPMENT

More than 7,600 MW in various stages of power generation development

Sandy

Creek

Long Leaf

White Pine/

Egan

Elk Run

Plum Point

Unit 2

High Plains

Five Forks

West

Deptford

West Texas

Texas

Georgia

Nevada

Iowa

Arkansas

Colorado

Virginia

New Jersey

Texas

Coal/800

Coal/1,200

Coal/Wind

1,600/200

Coal/750

Coal/665

Coal/600

Coal/800

Coal/500

Natural

Gas/500

Application Filed

Permit Issued

Application Filed

Permit Issued

Application Filed

Permit Issued

Location

Solid

Waste

Permit

Water

Discharge

Permit

Air

Permit

Water Supply Secured/Available

Fuel/MW

Site Secured

Zoning Approved/Not Required

N/A

N/A

Note: Sandy Creek air permit appeal hearing scheduled for 1Q 2007.

Draft

Draft

19

$0

$30

$60

$90

J

F

M

A

M

J

J

A

S

O

N

D

COMMODITY PRICING

COMMODITY PRICING

($/MWh)

2006 Actual

2007 Forward as of 11/01/06

(1)

2007 Actual/Forward as of 1/30/07

(2)

Cin Hub/Cinergy

2006A: $51.58

2007F (Nov): $59.04

2007A/F (Jan): $59.34

(1)

Pricing as of 11/01/06, which was the basis for estimates as presented 12/13/06.  Prices reflect quoted forward on-peak monthly prices for 2007.

(2)

Pricing

as

of

1/30/07,

which

was

the

basis

for

estimates

as

presented

2/27/07.

Prices

reflect

actual

day

ahead

on-peak

settlement

prices

for

Jan.

1

–

Jan.

30

and

quoted

forward

on-peak

monthly

prices

for

Jan.

31

–

Dec.

2007.

$0

$25

$50

$75

$100

$125

J

F

M

A

M

J

J

A

S

O

N

D

New York Zone G

$0

$25

$50

$75

$100

$125

J

F

M

A

M

J

J

A

S

O

N

D

ERCOT

($/MWh)

$0

$25

$50

$75

$100

J

F

M

A

M

J

J

A

S

O

N

D

($/MWh)

NP-15

($/MWh)

2006A: $75.84

2007F (Nov): $88.75

2007A/F (Jan): $88.00

2006A: $63.09

2007F (Nov): $75.47

2007A/F (Jan): $74.87

2006A: $61.15

2007F (Nov): $75.13

2007A/F (Jan): $75.56

20

2007 CASH FLOW ESTIMATES: GAAP BASIS

2007 CASH FLOW ESTIMATES: GAAP BASIS

Development capex related to Plum Point of $155 MM expected to be funded from Plum Point’s

restricted cash

Net proceeds from asset sales and acquisition includes $200 MM from potential generation asset

sales, offset by $100 MM cash paid to LS Power and $45 MM expected transaction costs

Other OCF includes all interest payments, including Sithe interest previously recorded in GEN, as

well as Plum Point cash interest of $30 MM funded from Plum Point’s restricted cash

Note:  2007 estimates are presented on a GAAP basis, are based on quoted forward commodity price curves as of 11/01/06 and assume closing of the LS Power transaction

at end 1Q 2007.  Actual results may vary materially from these estimates based on changes in commodity prices, among other things, including operational activities, legal

settlements, financing or investing activities and other uncertain or unplanned items. Core business represents continuing operating results, excluding significant items.

(1) Asset sale proceeds in the range of $200-500 MM are expected from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets

where the value that can be captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets.  Divestitures could result in

impairment charges and could reduce 2007 and forward EBITDA or free cash flow. 

As Presented December 13, 2006; Based on Price Curves as of November 1, 2006

($ in millions)

        GEN

        OTHER

2007 Total

GAAP OCF

$ 1,170-1,260

$ (570-560)

$ 600-700

GAAP ICF

Capex - Maintenance

(155)

(15)

(170)

Capex - Consent Decree

(90)

-

(90)

Capex - Plum Point Development

(155)

-

(155)

Investment in Development Portfolio

-

(10)

(10)

Proceeds from Asset Sales and Acquisition Costs, Net

(1)

200

(145)

55

Change in Restricted Cash

155

30

185

Free Cash Flow

$ 415-515

Add Back: Acquisition Costs

145

Less: Proceeds from Asset Sales

(1)

(200)

Free Cash Flow - Core Business

$ 360-460

21

2007 EARNINGS ESTIMATES: GAAP BASIS

2007 EARNINGS ESTIMATES: GAAP BASIS

As Presented December 13, 2006; Based on Price Curves as of November 1, 2006

($ in millions)

      Midwest

    West

    Northeast

      Total GEN

        OTHER

2007 Total

EBITDA Estimates

$ 745-795

$ 215-235

$ 175-205

$ 1,135-1,235

$ (115-105)

$ 1,020-1,130

Depreciation

(180)

(45)

(40)

(265)

(15)

(280)

Interest

(435)

Tax Expense

(115-160)

Net Income Applicable to Common Shareholders - GAAP

$ 190-255

Earnings Per Share

(1)

$ 0.25-0.34

Note:  2007 estimates are presented on a GAAP basis, are based on quoted forward commodity price curves as of 11/01/06 and assume closing of the LS Power transaction

at end 1Q 2007, excluding purchase accounting adjustments.  Actual results may vary materially from these estimates based on changes in commodity prices, among other

things, including operational activities, legal settlements, financing or investing activities and other uncertain or unplanned items.  Reduced 2007 and forward EBITDA or free

cash flow could result from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets where the value that can be captured through a

divestiture is believed to outweigh the benefits of continuing to own or operate such assets. Divestitures could result in impairment charges.

(1) Calculated based on 755 MM weighted-average shares outstanding.

Other includes G&A costs of approximately $160 MM, primarily offset by interest income

Interest expense of $435 MM includes approximately $30 MM for Plum Point

Estimates exclude purchase accounting adjustments to be recorded

upon closing of LS

Power transaction

Earnings may be more volatile as many of the forward sales commitments associated

with the LS Power portfolio are marked-to-market under GAAP, which may create

variances between earnings and cash flows in certain periods

22

DYNEGY STAND-ALONE 2007 ESTIMATES:

GAAP BASIS

DYNEGY STAND-ALONE 2007 ESTIMATES:

GAAP BASIS

Dynegy stand-alone expected to have positive

net income and free cash flow in 2007

EBITDA includes G&A expenses of

approximately $140 MM

OCF adjustment primarily related to cash

received in 2006 for 2007 forward sales

Note:  2007 estimates are presented on a GAAP basis and are based on quoted forward commodity price curves as of 1/30/07.  Actual results may vary

materially from these estimates based on changes in commodity prices, among other things, including operational activities, legal settlements, financing or

investing activities and other uncertain or unplanned items. Core business represents continuing operating results, excluding significant items.

(1) Asset sale proceeds in a range of $200-500 MM are expected from potential divestitures of (a) non-core assets where the earnings potential is limited,

or (b) assets where the value that can be captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets.

Divestitures

could

result

in

impairment

charges

and

could

reduce

2007

and

forward

EBITDA

or

free

cash

flow.

Proceeds

from

the

expected

sale

of

Calcasieu are assumed to be received in early 2008. 

As Presented February 27, 2007; Based on Price Curves as of January 30, 2006

($ in millions)

2007 Total

($ in millions)

2007 Total

EBITDA Estimates

$ 770-830

Previous GAAP OCF

$ 410-460

Depreciation

(230)

Adjustments (Approximate)

Interest

(275)

Timing of Receipts and Payments

(100)

Tax Expense

(100-125)

New GAAP OCF Estimates

$ 310-360

Net Income Applicable to Common Shareholders -

GAAP

$ 165-200

GAAP ICF

Capex

-

Maintenance

(140)

Capex

-

Consent Decree

(90)

Proceeds from Asset Sales

(1)

200

Free Cash Flow

$ 280-330

-

Less: Proceeds from Asset Sales

(1)

(200)

Free Cash Flow -

Core Business

$ 80-130

23

DEBT AND OTHER OBLIGATIONS CHART –

AS OF 12/31/06 ($ in MM)

DEBT AND OTHER OBLIGATIONS CHART –

AS OF 12/31/06 ($ in MM)

Dynegy Inc..

Dynegy Power Corp.

Central Hudson

(3)

$801

Dynegy Holdings Inc.

Revolver

(1)

$0

Synthetic LC Facility

(2)

$200

Second Secured Notes

$11

Sr. Unsec. Notes/Debentures

$2,397

Subordinated Debentures

$200

Sithe Energies

Senior Debentures

(4)

$447

Secured

Key

Secured Non-Recourse

Unsecured

(1)

Represents drawn amounts under the revolver as of 12/31/06.

(2)

Proceeds from this facility have been drawn and fully collateralize the issuance of letters of credit.

(3)

Central Hudson lease payments are unsecured obligations of Dynegy Inc., but are a secured obligation of an unrelated third party (“lessor”) under

the lease.  DHI has guaranteed the lease payments on a senior unsecured basis.  Amount reflects PV (10%) of future lease payments as of 12/31/06.

(4)

Includes approximately $19 MM as of 12/31/06 that was paid 1/02/07.

Total: $4.1 B

24

DEBT AND LEASE OBLIGATIONS ($ in MM)

DEBT AND LEASE OBLIGATIONS ($ in MM)

Net decrease from 12/31/05 to 12/31/06 primarily

reflects the following:

$1.7 B repayment of SPNs

$225 MM repayment of convertible subordinated

debentures

$400 MM redemption of Series C preferred

$419 MM elimination of Sithe subordinated debt,     

offset by

$1,047 MM addition of senior unsecured notes due

2016

$200 MM addition of term credit facility due 2012

12/31/03

12/31/04

12/31/05

12/31/06

Secured Obligations

4,087

$            

2,536

$            

1,749

$            

211

$               

Secured Non-Recourse Obligations

-

-

885

447

Unsecured Obligations

2,891

2,587

2,583

3,398

Preferred

411

400

400

-

Total Obligations

7,389

$            

5,523

$            

5,617

$            

4,056

$            

Cash on Hand

477

$               

628

$               

1,549

$            

371

$               

Note:  Debt includes par value debt obligations and obligations for Central Hudson.  Debt as of 12/31/06: (1) includes approximately $19 MM of

Sithe

senior

debt

that

was

paid

1/02/07;

and

(2)

excludes

$470

MM

revolving

credit

facility

due

2009

as

it

is

currently

undrawn.

$7,389

$5,523

$5,617

$4,056

12/31/03

12/31/04

12/31/05

12/31/06

25

DEBT MATURITY PROFILE ($ in MM)

DEBT MATURITY PROFILE ($ in MM)

$60

$40

$269

$57

$0

$1,584

$687

$568

$10

$575

$982

12/31/05: $4.8 B

Note: Annual maturities reflect par value debt obligations, excluding Central Hudson lease payments. Debt as of 12/31/06: (1) includes $19 MM of Sithe

senior debt in 2007 that was paid 1/02/07; (2) excludes $470 MM revolving credit facility due 2009 as it is currently undrawn; and (3) excludes LS Power

debt of approximately $1.9 B expected to be assumed upon the closing of the transaction at end 1Q 2007.

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016+

$0

$59

$44

$57

$0

$1,597

$73

$568

$0

$775

$82

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016+

12/31/06: $3.3 B

26

COLLATERAL POSTED ($ in MM)

COLLATERAL POSTED ($ in MM)

Collateral reduced from year-end 2005

Decrease in generation business collateral due to decreased prices, expiration of certain

hedge positions and West Coast Power sale completion

CRM decrease due to price changes and contract expirations

Increase in generation collateral from year-end 2006 primarily due to increased

facility run-times

$0

$50

$100

$150

$200

$250

$300

$350

$400

12/31/05

12/31/06

2/22/07

CRM

91

$        

54

$        

50

$        

GEN

280

134

178

Other

10

7

7

Total

381

$      

195

$      

235

$      

Cash

122

$      

38

$        

40

$        

LCs

259

157

195

Total

381

$      

195

$      

235

$      

12/05                  3/06                 6/06                

9/06                 12/06     

27

LIQUIDITY ($ in MM)

LIQUIDITY ($ in MM)

Decrease in cash on hand from 3/31/06 primarily due to liability

management

activities and repayment of debt obligations, offset by receipt of proceeds from

issuance of new unsecured notes and equity offering

Liquidity

figure

above

excludes

$38

MM

cash

collateral

posted

as

of

12/31/06

Cash

Availability

$1,620

12/31/05

3/31/06

$1,913

9/30/06

$846

6/30/06

$864

12/31/06

$878

28

LS POWER DEBT AND OTHER OBLIGATIONS

PRO FORMA AS OF CLOSING ($ in MM)

LS POWER DEBT AND OTHER OBLIGATIONS

PRO FORMA AS OF CLOSING ($ in MM)

1st Lien Debt

$ 1,500 MM

2nd Lien Debt

200 MM

Operating Assets

$ 1,700 MM

Plum Point, Net

202 MM

Total

$ 1,902 MM

Total LS Power

Amounts Outstanding

Key

Secured Non-Recourse

Kendall

1

st

Lien

LC

Facility             $0

1

st

Lien Term Loan         $402

Ontelaunee

1

st

Lien Term Loan      $95

2

nd

Lien Term Loan     $50

LSP Gen Finance Co.

1

st

Lien Term Loans                    $933

2

nd

Lien Term Loan                     $150

$100 MM 1

st

Lien Revolver

(1)

$0

1

st

Lien LC Facilities

(1)

$0

Plum Point Energy Assoc.

1

st

Lien Term Loan

(3)

$356

2

nd

Lien Term Loan

(3)

$147

$50 MM 1

st

Lien Rev.

(1)

$0

Synthetic LC Facility

(4)

$0

Tax Exempt Notes

(3)

$100

Sub-Total

$603

Less: Cash

(5)

($401)

Total, Net

$202

LS Power Portfolio

Griffith

1

st

Lien Facility

(2)

$70

Note: Represents pro forma debt balances as of 3/31/07. Plum Point is expected to be consolidated in Dynegy’s financial results, but the facility will be

only net 40% owned by the new company.

(1)

Revolver facilities assumed to be undrawn as of 3/31/07.  LSP Gen Finance Co. First Lien LC Facilities totaling $650 MM exclude $514 MM letters

of credit posted as of January 2007.

(2)

First lien facility to be entered into upon expected closing of transaction.

(3)

Does not reflect a total of $401 MM restricted cash.

(4)

$102 MM Synthetic LC Facility is undrawn and collateralizes tax exempt notes.

(5)

Restricted cash expected to be approximately $401 MM as of 3/31/07.

29

GENERATION ASSET LIST

GENERATION ASSET LIST

Net

Primary

Dispatch

NERC

Region/Facility

Location

Capacity

(1)

Fuel Type

Type

Region

MIDWEST

Baldwin

Baldwin, IL

1,800

Coal

Baseload

MISO

Havana

Units 1-5

Havana, IL

228

Oil

Peaking

MISO

Unit 6

Havana, IL

441

Coal

Baseload

MISO

Hennepin

Hennepin, IL

293

Coal

Baseload

MISO

Oglesby

Oglesby, IL

63

Gas

Peaking

MISO

Stallings

Stallings, IL

89

Gas

Peaking

MISO

Tilton

Tilton, IL

188

Gas

Peaking

MISO

Vermilion

Units 1-2

Oakwood, IL

164

Coal/Gas

Baseload

MISO

Unit 3

Oakwood, IL

12

Oil

Peaking

MISO

Wood River

Units 1-3

Alton, IL

119

Gas

Peaking

MISO

Units 4-5

Alton, IL

446

Coal

Baseload

MISO

Kendall

Minooka, IL

1,200

Gas - CCGT

Intermediate

PJM

Ontelaunee

Ontelaunee Township, PA

580

Gas - CCGT

Intermediate

PJM

Rocky Road

(2)

East Dundee, IL

330

Gas

Peaking

PJM

Riverside/Foothills

Louisa, KY

960

Gas

Peaking

PJM

Rolling Hills

Wilkesville, OH

965

Gas

Peaking

PJM

Renaissance

Carson City, MI

776

Gas

Peaking

MISO

Plum Point

(3)

Osceola, AR

265

Coal

Baseload

SERC

Bluegrass

(4)

Oldham County, KY

576

Gas

Peaking

SERC

Midwest Combined

9,495

NORTHEAST

Independence

Scriba, NY

1,064

Gas - CCGT

Intermediate

NYISO

Roseton

(5)

Newburgh, NY

1,185

Gas/Oil

Intermediate

NYISO

Bridgeport

Bridgeport, CT

527

Gas - CCGT

Baseload

ISO-NE

Casco Bay

Veazie, ME

540

Gas - CCGT

Baseload

ISO-NE

Danskammer

Units 1-2

Newburgh, NY

123

Gas/Oil

Peaking

NYISO

Units 3-4

(5)

Newburgh, NY

370

Coal/Gas/Oil

Baseload

NYISO

Northeast Combined

3,809

30

GENERATION ASSET LIST (CONT.)

GENERATION ASSET LIST (CONT.)

Net

Primary

Dispatch

NERC

Region/Facility

Location

Capacity

(1)

Fuel Type

Type

Region

WEST

Moss Landing

Units 1-2

Monterrey County, CA

1,020

Gas - CCGT

Baseload

CAISO

Units 6-7

Monterrey County, CA

1,509

Gas

Peaking

CAISO

Morro Bay

(6)

Morro Bay, CA

650

Gas

Peaking

CAISO

South Bay

Chula Vista, CA

706

Gas

Peaking

CAISO

Oakland

Oakland, CA

165

Oil

Peaking

CAISO

Arlington Valley

Arlington, AZ

585

Gas - CCGT

Intermediate

WECC

Griffith

Golden Valley, AZ

558

Gas - CCGT

Intermediate

WECC

Calcasieu

(7)

Sulphur, LA

351

Gas

Peaking

SERC

Heard County

(4)

Heard County, GA

539

Gas

Peaking

SERC

Black Mountain

(8)

Las Vegas, NV

43

Gas

Baseload

WECC

Cogen Lyondell

(4)

Houston, TX

614

Gas - CCGT

Baseload

ERCOT

West Combined

6,740

TOTAL DYNEGY GENERATION

20,044

(8) Dynegy owns a 50% interest in this facility and the remaining 50% interest is held by Chevron.  Total generating

capacity of this facility is 85 MW.

(1) Unit capabilities are based on winter capacity.

(5) DYN entered into a $920 MM sale-leaseback transaction for the Roseton facility and units 3 and 4 of the

Danskammer facility in 2001.  Cash lease payments extend until 2029 and include $108 MM in 2007, $144 MM in 2008,

$141 MM in 2009, $95 MM in 2010 and $112 MM in 2011.  GAAP lease payments are $50.5 MM through 2030 and

decrease until last GAAP lease payment in 2035.

(3) Under construction.  Represents net 40% ownership.

(2) Excludes 28 MW of capacity for Unit 3, which is not available during cold weather because of winterization

requirements.

(6) Represents generating capacity of units 3 and 4.  Units 1 and 2, with a combined net generating capacity of 352

MW, are currently in layup status and out of operation.

(4) Dynegy is conducting a portfolio review and may consider divesting certain assets that (a) are primarily peaking in

nature and generally operate in locations where market recovery is projected to occur much further in the future than

in other regions in which the company will have a significant asset position, or (b) could present value propositions

through potential dispositions not likely to be achieved through continued ownership and operation by the company. 

Based on this review, the Bluegrass, Cogen Lyondell and Heard County generation facilities could be targets for sale in

2007.

(7) Dynegy has entered into an agreement to sell this generation facility, the closing of which is expected in early

2008.