Dynegy Inc. slide presentation

FORWARD-LOOKING STATEMENTS

This presentation contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future

events

that

are

intended

“forward-looking

statements.”

You

can

identify

these

statements,

including

those

relating

Dynegy’s

2007

financial

estimates

and

the

combination

with

Power,

the

fact

that

they

not

relate

strictly

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

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:

use

the

non-GAAP

financial

measures

“EBITDA”

and

“free

cash

flow”

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

restricted

cash)

equals

free

cash

flow.

use

free

cash

flow

measure

the

cash

generating ability of our operating asset-based energy business relative to our capital expenditure obligations. Free cash

flow

should

not

used

lieu

GAAP

measures

with

respect

cash

flows

and

should

not

interpreted

available

for

discretionary expenditures, as mandatory expenditures such as debt obligations are not deducted from the measure.

Dynegy will seek to capture value for all investors:

By having a power generation asset portfolio with sufficient diversity, scale

and scope to withstand and capture upside throughout commodity cycles

By having a flexible capital structure to capture market opportunities and

maintain strong liquidity

By having a management team driven to execute on growth opportunities

having

alignment

our

public

and

private

investors

VALUE PROPOSITION

Building a flexible and diverse portfolio of power generation assets

with a predictable cost structure to withstand sector cyclical lows

and benefit from sector cyclical highs

DYNEGY DIFFERENTIATED BY ITS

UNIQUE PLATFORM

DYNEGY DIFFERENTIATED BY ITS

UNIQUE PLATFORM

DIVERSE

OPERATING

PORTFOLIO

Greater stability and

diversity through the LS

transaction

Future market recovery

upside potential through

diversity of geography,

fuel, dispatch and sales

strategy

PREDICTABLE

COST

STRUCTURE

Fuel cost risk carefully

managed

Major maintenance and

environmental capex

programs well-defined

Current platform allows

for greater scale and

scope without

proportionate increase in

costs

FLEXIBLE

DEVELOPMENT

PORTFOLIO

Joint venture presents

additional opportunities

for organic growth or

value capture

More than 10,000 MW of

repowering and

development options

Dynegy’s portfolio of assets is uniquely positioned to deliver value

today and capture value in the future

DYNEGY’S PORTFOLIO

Scale and scope in key regions

Note: Plum Point 1 currently under construction. 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.

Primary Fuel Type

Nameplate Capacity (MW)

More than 900 MW

500 MW to 900 MW

150 MW to 500 MW

Less than 150 MW

Development/Repowering

Option

Coal

Gas

Gas/Oil

Wind

Operating Plant

Midwest

9,495 MW

Northeast

3,809 MW

Transmission

Total

20,044 MW

West

6,740 MW

Potential Sale

DIVERSIFIED AND BALANCED PORTFOLIO

Portfolio diversified through geographic locations, fuel and dispatch types

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

Louisiana,

the

closing

which

expected

early

2008.

Other

possible

divestitures

include

the

Bluegrass,

Cogen

Lyondell

and

Heard

County

generation

facilities.

Geographic

Diversity

Dispatch

Diversity

Fuell

Diversity

Dynegy

Today

Northeast

19.0%

Midwest

47.4%

West

26.1%

Dual

Fuel

6.5%

Gas -

CCGT

33.4%

Gas -

Simple

Cycle

39.2%

Coal/Oil

20.9%

Intermediate

25.8%

Peaking

41.7%

Baseload

32.5%

Dynegy

Pre-Close

Northeast

23.4%

Midwest

63.4%

South

13.2%

Coal/Oil

32.0%

Dual Fuel

11.1%

Gas -

CCGT

14.3%

Gas -

Simple

Cycle

42.6%

Intermediate

19.2%

Peaking

45.3%

Baseload

35.5%

South

7.5%

DYNEGY’S UPSIDE OPTIONS

Dynegy’s diversified portfolio provides several options to realize upside as energy markets tighten

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

and

increased

volumes

Peakers

–

should

benefit

from

both

improved

pricing/spreads

and

increased

volumes

Improving capacity markets provide benefits for all asset types

Consolidation

–

results

G&A,

O&M

and

financing

cost

savings

due

Dynegy’s

scalable

platform

and

reduced

duplication

overhead;

this

“Consolidation

Benefit”

addition

market

recovery

upside potential

Price / Spread

Volume

Cost Savings

Baseload

Intermediate

Peaker

Consolidation

= Areas for Potential Upside

Unique

portfolio

well

positioned

capture

potential

upside

NEAR-TERM OPPORTUNITIES

MIDWEST

MISO –

Outright power price for uncontracted

baseload volumes, and spark spread for gas-fired

peaking units

PJM –

Spark spread for uncontracted gas-fired

combined cycle units

NORTHEAST

NYISO –

Spark spread for uncontracted combined

cycle gas and fuel oil units, and outright power price

for uncontracted baseload coal volumes

ISO-NE –

Spark spread for uncontracted gas-fired

combined cycle units

WEST

Spark spread for uncontracted gas-fired combined

cycle and peaking units, and ancillary services

Target in-market availability of 90%

Opportunity for

capturing value

given growing risk

to new entrants

DYNEGY’S DEVELOPMENT APPROACH

Dynegy’s approach will involve a portfolio of fuel sources and

technologies,

including

new

coal,

gas,

wind

and

solar

resources,

through

the development joint venture with LS Associates

Meet market needs by providing economic and reliable energy

Comply with environmental, regulatory and legal requirements

Project pipeline will be dynamic and change over time

Open to new supply as it is demonstrated and becomes commercialized

Development

Joint

Venture

Regulators

and Other

Stakeholders

Customers

Balancing the needs for economic, reliable and clean energy

FOUR STEPS TO SUCCESSFUL DEVELOPMENT

Dynamic and flexible approach

Responsive to customer needs

Able to maximize value of each project through commercial agreements

All

supply

options

will

considered

weighed

against

economic,

reliable

and

clean

criteria

Focus on risk management

Execute long-term contracts and hedges for significant portion of project’s output prior to

significant capital commitment

Arrange appropriate financing package

Structure fixed-price construction contracts with respected counterparties

Build relationships

Work closely with local communities, customers, regulators, non-governmental organizations

& other interested parties

Leverage strong relationships with contractors and suppliers

Selectivity

Evaluate many sites and opportunities for each project pursued

“Quality over quantity”

Long-term investment outlook and proven development model

SIGNIFICANT OPPORTUNITIES

All fuel sources and technologies will be considered and judged on

ability to meet market needs with economic, reliable and clean energy

Primary Fuel Type

Nameplate Capacity (MW)

More than 900 MW

500 MW to 900 MW

150 MW to 500 MW

Less than 150 MW

Development Option

Coal

Gas

Gas/Oil

Wind

Repowering Option

Transmission

Multiple opportunities

Diversified fuel sources

including coal, gas, wind

and solar

Greenfield and expansion

of existing sites

Dynamic portfolio

expected to change over

time

Each project to stand on

its own merit

PREDICTABLE COST STRUCTURE

CAPITAL

SPENDING

Committed to environmental

stewardship that will achieve

approximately 90% reduction

of SO2

and NO

in the

Midwest

Overarching goal to operate

safely and efficiently, while

meeting the needs of the

market

G&A

Scale and scope increase

without proportionate

increase in costs

Strive to be a low-cost

provider

O&M COSTS &

FUEL SUPPLY

Long-term PRB coal and

rail contracts in place

Other fuel price risk

generally passed through

or purchased as needed at

index-related prices

Pursue growth while maintaining fiscal discipline,

delivering greater value for all investors

ROUTINE MAINTENANCE CAPITAL SPENDING

2007

generation

maintenance

capital

spending

expected

approximate

$155

(1)

$115 MM baseload coal

$20 MM intermediate combined-cycle gas

$20 MM gas peakers

Dynegy is committed to maintaining a

safe, efficient and reliable power generation fleet

(1)

Represents

Generation

capital

spend,

including

months

for

Dynegy

assets

and

months

for

assets

and

excludes

approximately

$15

corporate

routine maintenance.

Baseload Coal

Capital spending

usually routine and

predictable given

consistent run-times

Gas Peakers

Capital spending

primarily offset by

earnings from the

sale of power

Combined-Cycle Gas

Capital spending over a 5.5-

year period could average

from $50-$60 MM annually,

primarily depending on run-

time

Typically, no single year

exceeds spending of

$100 MM

O&M COSTS & FUEL SUPPLY

MIDWEST

Long-term PRB coal and rail contracts

Baldwin 2007E delivered price approximately $1.35/MMBtu

Approximately 97% of coal requirements contracted through 2010, with 98% contracted at a

fixed price through 2008

100% of rail requirements contracted at fixed prices through 2013

NORTHEAST

2007E South American coal delivered price ~$2.90/MMBtu

100% of coal supply contracted at fixed price through 2007, with

diversified suppliers

and load ports

Fuel oil and natural gas purchased as needed at index-related pricing

WEST

Fuel price risk generally passed through on hedges and tolling agreements or

purchased as needed at index-related prices

GROWTH THROUGH CONSOLIDATION

BENEFITS FOR INVESTORS

GROWTH THROUGH CONSOLIDATION

BENEFITS FOR INVESTORS

Greater scale and scope without proportionate increase in costs creates

significant value for all investors

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

full-year

estimates

for

Dynegy

and

months

estimates

for

Power

beginning

4/01/07,

including

certain

acquisition-related

expenditures.

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%

DYNEGY DIFFERENTIATED BY ITS

UNIQUE PLATFORM

DYNEGY DIFFERENTIATED BY ITS

UNIQUE PLATFORM

DIVERSE OPERATING PORTFOLIO

Diversification enhances financial stability

Strong assets with upside potential for

market recovery

FLEXIBLE DEVELOPMENT PORTFOLIO

Dynamic portfolio to create and capture

future value through organic growth

opportunities

PREDICTABLE COST STRUCTURE

Focused management team committed to

growing the business

Scalable platform with minimal

incremental costs for future sector

consolidation

Dynegy’s portfolio of

assets is uniquely

positioned to deliver

value today and

capture value in the

future for all investors

CCGT FACILITY MAINTENANCE

Frequency of major maintenance for gas turbine-driven facilities is primarily a

function of run-time

Major

maintenance

events

assumed

occur

every

24,000

run

hours

(approximate)

Costs vary depending on facility size, type of equipment, age, long-term service agreements

and other operating conditions

Run hour and capacity factor estimates are based on proprietary forecasts of natural

gas and power commodity prices, as well as expectations of future market demand

Capacity factors for the LS Power CCGT fleet have historically been in a range of 15-60% and

vary by facility

Example: 50% capacity factor x 24 hours x 365 days = 4,380 run hours per year

24,000 run hours / 4,380 run hours per year = ~5.5 years per maintenance cycle

Dynegy’s practice is to capitalize most major maintenance costs

Increased run-time will result in increased maintenance costs,

which is expected to be offset by improved earnings

Note: Example above shown for illustrative purposes only. Actual timing of maintenance and forecasted maintenance capital expenditures for

CCGT facilities will

vary

based

multiple

factors

and

actual

operating

conditions,

among

other

things.

Number

years

maintenance

cycle

may

less,

depending on the actual operation of the plant.

DEBT & OTHER OBLIGATIONS ($ in MM)

Dynegy Power Corp.

Central Hudson

(3)

$820

Dynegy Holdings Inc.

$850 Million Revolver

(1)

$275

Synthetic LC Facility

(2)

$400

Term Loan

$70

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)

1st Lien

$1,415

2 Lien

200

Operating Assets

$1,615

Plum Point, Net

204

Total

$1,819

Note: Represents current capital structure expectations and assumptions as of closing April 2, 2007.

(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, $83 MM for Sithe debt

reserve and $117 MM for LS Power parental support and 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 next page for more details about the LS Power debt portfolio.

LS POWER DEBT AND OTHER OBLIGATIONS ($ in MM)

1st Lien Debt

$ 1,415 MM

2nd Lien Debt

200 MM

Operating Assets

$ 1,615 MM

Plum Point, Net

204 MM

Total

$ 1,819 MM

Total LS Power

Amounts Outstanding

Key

Secured Non-Recourse

Kendall

Lien LC Facility $0

Lien Term Loan $396

Ontelaunee

Lien Term Loan $100

Lien Term Loan $50

LSP Gen Finance Co.

Lien Term Loans $919

Lien Term Loan $150

$100 MM 1

Lien Revolver

(1)

1st

Lien LC Facilities

(1)

Plum Point Energy Assoc.

Lien Term Loan

$185

$17 MM 1

Lien Revolver

(1)

Synthetic LC Facility

(2)

Tax Exempt Notes

(2)

$100

Sub-Total

$285

Less: Restricted Cash

($81)

Total, Net

$204

LS Power Portfolio

Note: Represents debt balances expected as of closing on 04/02/07. 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 $529 MM letters of credit

posted as of January 2007.

(2)

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

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

GAAP

basis,

are

based

quoted

forward

commodity

price

curves

1/30/07

and

assume

closing

the

Power

transaction

end

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

free

cash

flow.

Proceeds

from

the

expected

sale

Calcasieu

are

assumed

received

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)

Capex

Plum Point Development

(155)

Investment in Development Portfolio

(10)

Proceeds from Asset Sales and Acquisition Costs, Net

(1)

200

(145)

Change in Restricted Cash

155

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

2007 EARNINGS ESTIMATES: GAAP BASIS

Note:

2007

estimates

are

presented

GAAP

basis,

are

based

quoted

forward

commodity

price

curves

1/30/07

and

assume

closing

the

Power

transaction

end

2007,

excluding

purchase

accounting

adjustments.

Actual

results

may

vary

materially

from

these

estimates

based

changes

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

(a)

non-core

assets

where

the

earnings

potential

limited,

(b)

assets

where

the

value

that

can

captured

through

divestiture

believed

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

recorded

upon

closing

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

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

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

Gas

Peaking

MISO

Stallings

Stallings, IL

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

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

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

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

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.