Dyne Therapeutics 8K Lehman Brothers CEO Energy/Power Conference | SEC 2 Sep 08

Lehman Brothers
CEO Energy/Power Conference

Bruce Williamson

September 2, 2008

Investor & Public Relations | Norelle Lundy, Vice President | Nir Grossman, Senior Director | 713-507-6466 | ir@dynegy.com

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 2008 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,
including its 2007 Form 10-K, first quarter 2008 Form 10-Q, as amended, and second quarter
2008 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: This presentation contains non-GAAP financial measures
including EBITDA, Adjusted EBITDA, Adjusted Cash Flow from Operations, Adjusted Free
Cash Flow and Net Debt. Reconciliations of these measures to the most directly comparable
GAAP measures are contained herein. To the extent required, statements disclosing the utility
and purposes of these measures are set forth in Item 2.02 to our Current Report on Form 8-K
filed with the SEC on August 7, 2008, which is available on our website, www.dynegy.com.

$20

$40

$60

$80

$100

$20

$40

$60

$80

$100

$120

$140

$160

Trailing 12-Month Trends

Despite volatility in the near-term market commodity prices have increased over the past
12 months

While stocks have followed recent commodity declines, stocks do not reflect incremental
uplift over the same period

Long-term industry fundamentals remain strong and recent downward stock trends will
likely reverse as supply/demand tightens

Natural Gas ($/MMBtu)

Crude Oil ($/Bbl)

Power ($/MWh)

Electric Utility & IPP Averages

Note: All prices shown Sept 2007 through Aug 2008. Sources: Brokered market sources

WTI - Crude

2009 CIN Hub On Peak

$10

$12

$14

Utilities

IPP Avg

50%

60%

70%

80%

90%

100%

110%

120%

Henry Hub

Why Invest in Dynegy?

As Dynegy’s coal fleet operates in a region
where coal typically sets the marginal price of
power, the Midwest coal fleet should pass
through 100% of potential carbon costs up to
50-65% of the time

The ripple effect of significant carbon costs
could increase Dynegy’s recovery of costs

100% of potential carbon costs should
be passed through in a region where
coal sets the marginal price of power

Significant carbon costs should
increase the demand for and price of
natural gas, increasing the price of
power and with it, the dark spread

Potential
regulations to curb
CO2 emissions

Eastern Coal has become a global
commodity and there has likely been
a step-change in its pricing

Longer-term prices and spreads
are expected to increase due to
tightening supply/demand

Demand growth is expected to
continue over the longer term as
industry fundamentals remain strong

Barriers to entry should limit new
supply, increasing the value of
incumbent assets

Dynegy’s Midwest fleet burns 100% regionally-
driven Powder River Basin Coal which is not
exposed to global forces

Dynegy has key contracts to lock-in prices

Majority of coal supply pricing locked-in through 2010

Rail contracted at fixed price through 2013

Rising “global”
coal prices

Dynegy’s “Current +1” hedge strategy captures
value associated with near-term commodity
price volatility and allows for participation in
expected heat rate expansion on a year by
year basis

Dynegy’s significant gas fleet available to
increase utilization

Temporary
decline/volatility in
power prices and
spark spreads

Dynegy is well positioned to capture growth
in 3 economic regions

Midwest, West and Northeast

Baseload and combined cycle assets

Supply/demand
balance

… and Dynegy’s advantages

… consider Dynegy’s belief

If you are
worried about…

Electricity Market Growing in an Uncertain Environment

Global oil, natural gas/LNG, Eastern coal and power have experienced a step-change in price

Electric forward curves do not yet fully reflect anticipated market implied heat rate expansion

Barriers to entry for new development remain strong and may be rising

Longer term electric demand forecasts remain strong even through economic slowdown

Global competition for energy

Rising barriers to entry

Two major trends

are colliding with a constant

Rising U.S. energy consumption

Historic U.S. Electric Consumption (% increase)

Source: EIA, US Dept of Energy

100%

120%

140%

160%

180%

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

200%

Barriers to Entry Remain High

Note: Development lead-time ranges include the complete development cycle: siting, permitting, engineering and construction. $/KW includes estimated financing costs. Cost development and
construction schedules are based on various trade publications and are intended solely as estimates. Others’ cost development and construction schedule estimates and actual cost and
construction schedules of specific projects may vary materially from these estimates. CO2 capture technology currently unavailable.

New Generation – Estimated Costs and Lead-Time

Wind

Gas

16 years

Timeframe

Solar

Coal

Nuclear

$700 – 1,100/KW

$900 – 1,500/KW

$3,000 – 4,200/KW

$3,800 – 4,900/KW

$4,600 – 6,800/KW

$8,000 – 12,000/KW

Concentrate

Photovoltaic

Simple Cycle

Pulverized Super Critical

IGCC & IGCC with CO₂ capture

Combined Cycle

$2,000 – 2,200/KW

$4,900 –
6,000/KW

Delays will increase
the value of
Dynegy’s existing
operating assets

Regulatory Uncertainties

Successful U.S. energy policy must address 3 critical, interrelated issues:

Global oil

Global gas & LNG

Global coal

Prior focus: SOx,
NOx, mercury,
particulates

New focus:
climate change

Cost to consumers

Cost to jobs

Cost to trade

The

Environment

The

Economy

U.S. Energy

Dependence

Energy companies work within our country’s legal & regulatory framework

Federal

Leadership

Price of
Electricity

Midwest Capacity

West Capacity

Northeast Capacity

Dynegy’s Carbon Emission Profile

Note: Generated volumes, CO2 emitted and intensity based on full year 2007 operational data and include 9 months of data from facilities acquired on April 2007 from LS Power. Plum Point
and Sandy Creek are currently under construction. Intensity is calculated using gross generated volumes not net generated volumes as presented above. “NMWh” = Net Megawatt Hours

Combined Cycle

36%

Simple Cycle

57%

Total Gas-fired

93%

Fuel Oil

Combined Cycle

21%

Simple Cycle

37%

Total Gas-fired

58%

Coal

42%

Combined Cycle

56%

Simple Cycle

Total Gas-fired

56%

Coal

10%

Fuel Oil

34%

12.9 MM NMWh

Gen volumes

5 MM tons

CO2 emitted

37%

Intensity

25 MM NMWh

Gen volumes

25.6 MM tons

CO2 emitted

97%

Intensity

9.5 MM NMWh

Gen volumes

5.6 MM tons

CO2 emitted

57%

Intensity

As a general rule:

Coal facilities produce 1 MM tons of CO2 per 1 MM MWh of generated volumes

Gas-fired facilities produce 1 MM tons of CO2 per 2 MM MWh of generated volumes

Coal facilities should pass through 100% of the cost when a coal plant sets the price of power

Dynegy’s coal fleet primarily located in the Midwest region where coal sets the price of power up
to 50-65% of the time

Hypothetical Midwest Carbon Cost Example

Carbon Cost Scenarios – Possible Impacts to Dynegy’s Midwest Fleet

See Appendix for assumption details.

2007 Midwest Generation = 25 MM MWh

2007 Midwest CO₂ Emissions = 25.6 MM tons

An Example:

Step 1: If you assume…

2007 generation and emissions levels

$10.00/ton cost of carbon

50% cost recovery rate

+$0.50

% Cost Recovery

$/MWh

$20/ton

Potential cost of CO2 per ton
set by new regulation

Step 1 = $5/MWh cost

Natural gas
increases
$/MMBtu

$5/ton

$15/ton

$10/ton

+$1.00

+$1.50

+$3.00

+$2.00

+$2.50

$/MWh increase in power price resulting
from higher natural gas prices

Step 2 = $3/MWh benefit

Result = $2/MWh net cost

Step 2: If you assume…

Natural gas prices increase $0.50/MMBtu

Example Sensitivity:

To achieve 100% recovery of carbon cost, natural gas prices
would need to increase ~$0.85/MMBtu instead of ~$0.50/MMBtu

100%

75%

50%

25%

Current Market Creates Opportunities for Dynegy

CIN Hub On-Peak Prices ($/MWh)

Power prices have risen
significantly year-over-year,
despite near-term volatility

$90.00

$85.00

$80.00

$75.00

$70.00

$65.00

$60.00

$55.00

$50.00

$45.00

Avg Settle 2007

$59.28

$49.02

Avg Settle 2006

Avg Settle 2008⁽²⁾

$69.56

Cal 09 Prices⁽¹⁾

Cal 09 Current Avg⁽¹⁾ $74.23

(1) Cal 09 prices as of 8/22/08 (2) CIN Hub Average Settle 2008 prices include forward prices from 8/23/08 through end of year

Power prices have risen
significantly year-over-year,
despite near-term volatility

We are focused on “Current + 1”
commercial strategy

We’re actively commercializing
2009 to capture rising price trends

For example: recently contracted
~1,400 MW of Midwest coal fleet’s
on-peak power for an average on-
peak price of ~$79/MWh at CIN
and PJM Hubs

Looking Forward…

We anticipate continued global
demand for commodities and
barriers to entry

We continue to execute a flexible
commercial strategy and capital
structure

Source: physical numbers published by ISO

Managing Supply Contracts Offers Advantages

Jan-08

Feb-08

Mar-08

Apr-08

May-08

Jun-08

Jul-08

Aug-08

Coal Pricing Trends

Competition for energy has resulted in higher global coal prices, while some coal
supplies remain regionally driven

For Dynegy, key contracts mitigate exposure to rising coal costs, offering
competitive advantage

Midwest coal fleet burns PRB, one facility in Northeast burns low sulfur South
American coal

Midwest rail contracted at a fixed price through 2013; majority of coal supply
pricing locked in through 2010

2008 Coal Prices ($/MMBtu)

Eastern

South American

Powder River Basin

DYN PRB Delivered Price = $1.39

Source: Energy_Argus; NYMEX

Dynegy’s delivered PRB
price includes benefit of
rail contract

Market prices of Eastern
and South American coal
exclude cost of delivery

Why Invest in Dynegy?

Dispatch Diversity

Peaking

45%

Intermediate

33%

Baseload

22%

Geographic Diversity

Midwest

46%

Northeast

21%

West

33%

Fuel Diversity

Combined Cycle

33%

Simple Cycle

36%

Total Gas-fired

69%

Coal

24%

Fuel Oil

Dynegy’s Competitive Advantages:

Dynegy’s portfolio provides unique platform
for value today & upside tomorrow

Geographic diversity means Dynegy is well-
positioned in 3 key regions

Dispatch diversity includes both baseload
generation, which provides today’s core earnings,
as well as gas-fired facilities, which are expected
to increase utilization as markets tighten

Operational excellence

Key fuel and rail contracts manage fuel supply risk

“Current + 1” commercial strategy provides near-
term stability and long-term flexibility

Dynegy actively maintains a flexible and liquid
capital structure

We Believe Dynegy is Significantly Undervalued

$ 16.66

$ 14.10

$ 11.54

$ 8.98

Coal/Dual Fuel Asset Value ($/KW)

$ 19.22

$ 18.17

$ 17.13

$ 16.08

$ 15.03

$ 13.99

750

$ 15.61

$ 14.57

$ 13.52

$ 12.47

$ 11.43

600

$ 13.05

$ 12.01

$ 10.96

$ 9.91

$ 8.87

450

$ 10.49

$ 9.45

$ 8.40

$ 7.35

$ 6.31

300

$ 7.93

$ 6.89

$ 5.84

$ 4.79

$ 3.75

150

2,750

2,500

2,250

2,000

1,750

1,500

Gas/Oil Asset
Value ($/KW)

As value of incumbent assets increases, stock price should follow

Implied Price per Share
based on Asset Valuations

Note: Value excludes current and future development opportunities, assets under construction and associated non-recourse project debt. $/KW for asset sales based on summer capacity.
Plum Point $/KW based on fully constructed and financed values. Sandy Creek $/KW based on fully constructed values.

Sandy Creek

~$2,600/KW

Plum Point

~$2,800/KW

Calcasieu Peaker

~$160/KW

Cogen Lyondell

~$880/KW

Rockingham

~$235/KW

Current replacement cost estimates:

Coal: $3,000 – 4,200/KW

Combined Cycle: $900 – 1,500/KW

Simple Cycle: $700 – 1,100/KW

Rolling Hills

~$450/KW

Appendix

Investor & Public Relations | Norelle Lundy, Vice President | Nir Grossman, Senior Director | 713-507-6466 | ir@dynegy.com

18,277 MW

Diverse Portfolio Provides Advantages

Dispatch Diversity

Peaking

45%

Intermediate

33%

Baseload

22%

Geographic Diversity

Midwest

46%

Northeast

21%

West

33%

Fuel Diversity

Combined Cycle

33%

Simple Cycle

36%

Total Gas-fired

69%

Coal

24%

Fuel Oil

Note: Plum Point and Sandy Creek are currently under construction.

Located in 13 states –
serving regions that represent
~50% of total U.S. population

Guidance

Notes:

Adjusted EBITDA includes ~$50 million for Central Hudson lease expense while total cash
payment is ~$145 million

Working capital/non-cash adjustments/other primarily reflects changes in Accounts
Receivable/Accounts Payable balances and includes ~$50 amortization of ConEd contract
and ~$25 million non-cash equity losses

$140

Adjusted free cash flow

(200)

(170)

$510

(15)

(430)

$955

8/7/2008

Guidance⁽¹⁾

⁽¹⁾ 8/7/08 Guidance based on price curves as of 7/8/08 with an average natural gas price of $11.36/MMBtu

Environmental capital expenditures

Maintenance capital expenditures

Adjusted cash flow from operations

Working capital / non-cash adjustments / other

Collateral

Cash taxes

Interest payments

Adjusted EBITDA

($MM)

As presented August 7, 2008

Midwest Generation

Regional Market Drivers

MISO – Outright power price for uncontracted baseload volumes, and spark spread for
uncontracted gas-fired peaking units

PJM – Spark spread for uncontracted gas-fired combined cycle units

Capacity markets – MISO capacity sold under bilateral agreements; PJM capacity sold in
forward auctions for three years

Regional Highlights

Bilateral & tolling agreements and financial forward sales

Illinois auction – receive approximately $65/MWh

Up to 200 MW expiring 5/2009 (~50% load factor)

100% of coal supply contracted through 2010; majority coal supply pricing locked up
through 2010

100% of rail contracted at a fixed price through 2013

Midwest Power Market – Basis Differentials

CIN Hub

PJM

Illinois Hub

Dynegy uses forward power
contracts to optimize assets

Traditionally the differences
between IL and CIN, and between
CIN and PJM, move in tandem
within a narrow range

June 2008 – the basis moved
well outside the anticipated ranges

Increasing natural gas prices,
transmission congestion and
warmer temperatures in PJM were
all factors in widening the basis

Average Day-Ahead On-Peak Prices ($/MWh)

140

120

100

CIN Hub

IL Hub

PJM Hub

Transacting further east
provides more liquidity…

…and creates additional risk

Pricing as of 8/22/08

Midwest Power Market – Basis Differentials

(45)

(25)

(5)

Gain/(loss) of
forward sale

$ 40

$ 65

Example 1

Forward
sale @ PJM

Year Ahead Forward Power Sale

Cost to
generate

$ 20

$ 45

100

Example 3

Real-time
Sale

Basis @
Settlement

$ 25

$ 65

Net of
Sales

Example 4

Example 2

Base Case

Settlement @
PJM

120

Physical
sale @ IL

$ 0

$ 40

TOTAL

Basis Differential Examples ($/MWh)

Note: For all examples, the assumed basis differential on the contract date is $10, as differential moves away from $10 results are affected

–

West Generation

Regional Market Drivers

Spark spread for uncontracted gas-fired combined cycle and peaking units, and ancillary
services

California has no formal capacity auction market; greater demand is expected for capacity
in 2009 as utilities will have reduced Resource Adequacy requirements

Regional Highlights

Includes RMR contracts, tolling agreements, and financial forward sales contracts

Fuel price risk generally passed through on hedges and tolling agreements or purchased
as needed at index-related prices

Northeast Generation

Regional Market Drivers

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 combined cycle gas units

New England – formal capacity market auction for 2010/2011 capacity occurred in February
2008

Regional Highlights

Includes bilateral capacity agreements and financial forward sales contracts

Operating expense includes $50 million of Central Hudson lease expense, and operating cash
flow includes cash lease payments of $144 million in 2008

Adjusted EBITDA will include approximately $50 million net earnings from ConEd contract;
however, operating cash flow will include cash receipt of approximately $100 million in 2008

100% of coal supply contracted at a fixed price through 2008

Assumptions For
Hypothetical Midwest Carbon Cost Example

Assumptions based on hypothetical variables, which are
dependent on a variety of factors including market conditions and
future environmental regulations

Actual results may vary materially from these assumptions

(1) CO2 emissions and generation volumes include 9 months of the

Kendall and Ontelaunee facilities acquired April 2007. Analysis
excludes Plum Point as it is not in 2007 generation volumes.

(2) Assumes ATC market implied heat rate of 6,000 Btu/KWh.

(3) Calculated result using stated assumptions:

25.6 MM tons * ($10.00/ton * 50% recovery)/ 25 MM NMWh = $5.00/MWh cost

$0.50 nat gas * 6,000 Btu/KWh = $3.00/MWh benefit

$5/MWh cost less $3.00/MWh benefit = $2.00/MWh net cost

2008 Generation Gross Margin by Contract Term Length

100%

80%

60%

40%

20%

Midwest

West

Northeast

Aggregated Portfolio

At Dynegy, this means:

Linking the commercial strategy and capital

structure in order to capture benefits and

mitigate risk through industry cycles

Managing a diversified operating portfolio

Maintaining a flexible capital structure

Minimal debt maturities through market

recovery create additional opportunities

Maintaining a Solid Foundation in a Cyclical Business

Linking Commercial with Capital Strategies

Focus on
core
business

Continuously
evaluate

Respond to
change with
the right
option

Maintain
discipline
throughout
cycles

Recognize
the cycles

Keep
options
open

Long-term contracts (5+ yrs)

Medium-term contracts (2-5 yrs)

Short-term sales (0-2 yrs)

Debt Maturity Profile (As of 12/31/07, $MM)

3,500

3,000

On balance sheet debt profile = $6.0 B

2,500

2,000

1,500

1,000

500

$23

$58

$63

$569

$579

$1,003

$556

$3,208

2008

2009

2010

2011

2012

2013

2014

2015

2016+

Debt and Lease Obligations ($ MM)

Increase in debt and lease obligations since
December 31, 2007 primarily reflects the following:

Draw of $111 million on Plum Point construction loan

Repaid $21 million on Sithe Energies Senior
Debentures

Note: Debt includes par value debt obligations and PV(10) of lease payments for Central Hudson. Debt for 12/31/07, 3/31/08 and 6/30/08 excludes $470 MM, $1,150 MM and $1,150 MM,
respectively, of undrawn portion of revolving credit facility due 2012.

(1) Restricted cash as set forth above consists of collateral posted for the credit facility, cash associated with Plum Point debt and the cash deposit associated with a letter of credit supporting
the Sandy Creek project equity commitment.

12/31/07

3/31/08

6/30/08

$6,813

$6,743

$6,839

$2,000

$4,000

$6,000

$8,000

12/31/07

3/31/08

6/30/08

Secured Obligations

920

919

Secured Non-Recourse Obligations

806

857

897

Unsecured Obligations

5,017

5,036

5,023

Total Obligations

6,743

6,813

6,839

Cash on Hand

328

429

271

Restricted Cash

(1)

1,227

1,222

1,165

Central Hudson Lease – Northeast Segment

Chart represents total cash lease payments, which are included in Operating Cash Flows

Lease expense is approximately $50 million per year and included in Operating Expense

Accrual Lease Expense

2008 Central Hudson treated as Debt
(would require the following adjustments to GAAP financials):

Income Statement – Add back $50 million lease expense to EBITDA; add $36
million imputed interest expense to Interest Expense; add $23 million estimated
depreciation & amortization expense; adjust tax expense for net difference

Depreciation & Amortization calculated using purchase price of $920 million divided by
40 years

Cash Flow Statement – Add back $77 million of imputed principal to operating
cash flows

$113 million cash payment split between $36 million imputed interest payment
(operating cash flows) and $77 million imputed principal payment (financing cash flows)

Balance Sheet – Include $776 million total PV (10%) of future lease payments

2008 Central Hudson treated as Lease
(as currently shown in GAAP financials):

Income Statement – $50 million lease expense included
in EBITDA; no interest expense or depreciation &
amortization expense

Cash Flow Statement – $113 million cash payment
included in Operating Cash Flows (*~$145 million for full
year cash spend)

Balance Sheet – lease obligation not included in debt
balance

Central Hudson Cash Payments
remaining as of 6/30/08 ($MM)

200

175

150

125

100

$113*

$141

$95

$112

$179

$142

$143

$105

2008

2009

2010

2011

2012

2013

2014

2015

2016-2035

$36

$67

$60

$56

$48

$38

$28

$16

$48

$77

$74

$35

$56

$131

$104

$115

$127

$57

Imputed Debt Equivalent at PV(10%)
of future lease payments = $776 MM⁽¹⁾

Imputed Interest

Imputed Debt Equivalent

(1) PV of payments calculated as of 6/30/08

Debt & Other Obligations Capital Structure – 6/30/08

Dynegy Power Corp.

Central Hudson⁽²⁾$776

Dynegy Holdings Inc.

$1,150 Million Revolver⁽¹⁾ $0

Term L/C Facility $850

Tranche B Term $69

Sr. Unsec. Notes/Debentures $4,047

Sub.Cap.Inc.Sec (“SKIS”) $200

Secured = $919

Key:

Secured Non-Recourse = $897

Unsecured = $5,023

Dynegy Inc..

Senior Debentures $367

Plum Point Energy Assoc.

PP 1^st Lien $430

Tax Exempt 100

Gross Debt $530

Less:Restricted Cash (40)

Total, Net Debt $490

(1) Represents drawn amounts under the revolver. (2) Represents PV (10%) of future lease payments. 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. (3) Restricted cash includes $850MM related
to the Synthetic Letter of Credit facility, $275MM for Sandy Creek Letter of Credit which is used in lieu of cash on hand and $40MM related to Plum Point.

($ MM)

Sithe Energies

$5,403

Net Debt & Other Obligations

490

Plus: Net Non-recourse Project Debt, under construction

490

Less: Net Non-recourse Project Debt, under construction

$4,913

Net Debt & Other Obligations associated with Operating Assets

$4,627

Net Debt

$5,403

Net Debt & Other Obligations

776

Less: Central Hudson Lease Obligation

1,165

Less: Restricted cash ⁽³⁾

271

Less: Cash on hand

$6,839

Total Obligations

6/30/08

($ Million)

Liquidity ($ MM)

Cash

Availability

$2,400

$2,000

$1,600

$1,200

$800

$400

$1,449

$1,121

$1,056

$619

$794

$328

$429

$271

$912

12/31/07

Liquidity excludes $28 million cash posted as collateral as of June 30, 2008

Liquidity decreased from 3/31/08 to 6/30/08 due to increased collateral postings supporting normal power sales
as result of higher power prices

Liquidity increased from 6/30/08 to 8/1/08 due to:

Cash received from the sale of the Rolling Hills facility

Decreased power prices, lowering collateral requirements

Cash increase of ~$140 million due to return of cash from the daily settlements of our exchange-traded or brokered commodity
futures positions held with our futures clearing manager

3/31/08

$1,485

6/30/08

$890

Standby facility ⁽¹⁾

(1) Under terms of our standby letter of credit facility, up to $300 million capacity can become available contingent on forward natural gas prices rising above $13/MMBtu for 2009.

$1,706

8/1/08

Enhancing Flexibility with Liquidity Options

Complementary sources of liquidity increase our flexibility and ability to
execute our commercial strategy in a rising commodity price environment

First Lien Hedging Structure

Creates the option to reduce traditional collateral requirements
on a commodity position by substituting a lien on Dynegy’s
generation assets

Contingent Letter of Credit Facility

Availability tied to rising 2009 natural gas prices ranging
from $13.00 to $20.50

Supplies incremental liquidity at times when collateral
requirements are also increasing

Term Letter of Credit Facility

Revolving Credit Facility

Cash on hand (as of 6/30/08)

as needed

$300 million

Complementary Liquidity Facilities Match Price with Need

$850 million

$1.15 billion

$271 million

Current Liquidity Remains Strong with Traditional Facilities

Significant Environmental Progress

On target to further reduce emissions in the Midwest

Major Assumptions

Estimate of remaining spend is $850 – $900 million
for a total investment of $940 – $990 million

Approximately 25% of remaining costs are firm

Labor and material prices are assumed to escalate
at 4% annually

All projects include installing baghouses and
scrubbers with the exception of Hennepin and
Vermilion, which have baghouses only

Labor

56%

Rental Equipment
& Other 8%

Cost Composition

Materials

36%

2008

2010

2009

2011

2012

2007

Vermilion

Hennepin

Baldwin 3

Baldwin 1

Baldwin 2

Havana

As presented February 27, 2008

Anticipated Capital Expenditures (2008 – 2012)

$ 290

$ 405

$ 590

$ 625

$ 620

TOTAL

Discretionary Investment (target IRR 15% or more)⁽²⁾

110

220

Development (Plum Point) ⁽¹⁾

100

185

225

265

200

Environmental

$ 190

$ 220

$ 245

$ 210

$ 170

Maintenance

2012

2011

2010

2009

2008

($MM)

Environmental includes Consent Decree, mercury reduction, marine life barriers
and NOx / SO₂ control equipment

Development fleet currently consists of Plum Point, which is scheduled to become
operational in 2010; 100% of Plum Point project cost is debt financed

Discretionary Investment includes projects designed to increase available capacity
or lower facility heat rate, which should improve market availability

Projects include replacing/updating technology such as upgrading steam turbines on
existing units to improve output and plant heat rate; in some cases, such projects may
require environmental permits

(1) Plum Point is consolidated and fully financed on a non-recourse basis. Although Sandy Creek is under construction, it is not included in the development capex as Sandy Creek is not
consolidated. Sandy Creek is also financed on a non-recourse basis. (2) Discretionary investments are subject to change.

As presented August 7, 2008

Development Detail

Consolidated

140

21%

665

Plum Point

Equity Investment

288

32%

898

Sandy Creek

% Owned by Dynegy

Equivalent MW
Owned by Dynegy

Financial Statement
Impact

Total MW

Construction Projects

Development JV

Joint venture not consolidated as we are not the primary beneficiary of the earnings and losses of the JV

Proportionate share of earnings and losses recorded in earnings from unconsolidated subsidiaries in our financial statements

Several thousand megawatts of greenfield & brownfield opportunities

Variety of geographic locations & fuel types: gas, coal, renewables

Opportunities for building or value capture through project monetization

Plum Point

Plum Point Energy Associates (PPEA) owns 57% interest in the Plum Point Energy Station

Dynegy owns 37% of the equity in PPEA

Approximately 60% of the economic value of PPEA owned by Dynegy as a result of the project’s contract structure

As primary beneficiary of the earnings and losses, Dynegy consolidates 100% of PPEA in our financial statements

Minority interest recorded for the share that we do not own

Output fully contracted

Scheduled for completion in 2010

Sandy Creek

Sandy Creek Holdings owns 64% of the Sandy Creek Energy Station

Dynegy owns 50% of Sandy Creek Holdings

Dynegy does not consolidate Sandy Creek as we are not the primary beneficiary of the earnings and losses on the project

Proportionate share of earnings and losses recorded in earnings from unconsolidated subsidiaries in our financial statements

Scheduled for completion in 2012

Reg G Reconciliation – 2008 Guidance

GEN - MW

GEN - WE

GEN - NE

Total GEN

OTHER

Total

Net Loss

(30)

Add Back:

Income tax benefit

(20)

Interest expense

430

Depreciation and amortization expense

380

EBITDA (2)

655

144

869

(109)

760

Plus / (Less):

Release of state franchise tax and sales tax liabilities

(16)

Gain on sale of NYMEX shares

(15)

Gain on sale of Sandy Creek ownership interest

(13)

Gain on sale of Oyster Creek ownership interest

(11)

Gain on sale of Rolling Hills

(50)

Mark-to-market

140

100

300

Adjusted EBITDA (2)

745

180

170

1,095

(140)

955

GEN

OTHER

Total

Adjusted EBITDA (2)

1,095

(140)

955

Cash Interest Payments

(430)

Cash Tax Payments

(15)

Collateral

(15)

Working Capital / Other Changes

(25)

Adjusted Cash Flow from Operations (3)

1,055

(545)

510

Maintenance Capital Expenditures

(155)

(15)

(170)

Environmental Capital Expenditures

(200)

Adjusted Free Cash Flow (4)

700

(560)

140

(1)

(2)

GEN - MW

GEN - WE

GEN - NE

Total GEN

OTHER

Total

Operating income (loss)

440

499

(159)

340

Losses from unconsolidated investments

(25)

Other items, net

Add: Depreciation and amortization expense

215

100

370

380

EBITDA

655

144

869

(109)

760

(3)

GEN

OTHER

Total

Adjusted Cash Flow from Operations

1,055

(545)

510

Legal and regulatory payments

(10)

(15)

(25)

Cash Flow from Operations

1,045

(560)

485

(4)

2008 EARNINGS ESTIMATES (1)

(IN MILLIONS)

Power Generation

Adjusted Cash Flow from Operations is a non-GAAP financial measure. Please see Summary Cash Flow Information for a definition.

Adjusted Free Cash Flow is a non-GAAP financial measure. Please see Summary Cash Flow Information for a definition.

2008 CASH FLOW ESTIMATES (1)

(IN MILLIONS)

Power Generation

2008 estimates are based on quoted forward commodity price curves as of 7/8/08. 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 2008 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 also result in impairment charges.

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please see Reported Segmented Results of Operations for the three months ended June 30, 2008 for a definition. A reconciliation of

EBITDA to Operating income (loss) by reportable segment is presented below.

Generation Assets – Midwest & Northeast

Net

Primary

Dispatch

Region/Facility

(1)

Location

Capacity

(2)

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

Ontelaunee Township, PA

580

Gas - CCGT

Intermediate

PJM

Rocky Road

(3)

East Dundee, IL

330

Gas

Peaking

PJM

Riverside/Foothills

Louisa, KY

960

Gas

Peaking

PJM

Renaissance

Carson City, MI

776

Gas

Peaking

MISO

Plum Point

(4)

Osceola, AR

140

Coal

Baseload

SERC

Bluegrass

Oldham County, KY

576

Gas

Peaking

SERC

Midwest Combined

8,405

NORTHEAST

Independence

Scriba, NY

1,064

Gas - CCGT

Intermediate

NYISO

Roseton

(5)

Newburgh, NY

1,185

Gas/Oil

Peaking

NYISO

Bridgeport

Bridgeport, CT

527

Gas - CCGT

Intermediate

ISO-NE

Casco Bay

Veazie, ME

540

Gas - CCGT

Intermediate

ISO-NE

Danskammer

Units 1-2

Newburgh, NY

123

Gas/Oil

Peaking

NYISO

Units 3-4

Newburgh, NY

370

Coal/Gas

Baseload

NYISO

Northeast Combined

3,809

Generation Assets – West & Notes

Net

Primary

Dispatch

Region/Facility⁽¹⁾

Location

Capacity

(2)

Fuel Type

Type

Region

WEST

Moss Landing

Units 1-2

Monterrey County, CA

1,020

Gas - CCGT

Intermediate

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

WAPA

Griffith

Golden Valley, AZ

558

Gas - CCGT

Intermediate

WAPA

Heard County

Heard County, GA

539

Gas

Peaking

SERC

Black Mountain

(7)

Las Vegas, NV

Gas

Baseload

WECC

Sandy Creek

(8)

Waco, TX

288

Coal

Baseload

ERCOT

West Combined

6,063

TOTAL DYNEGY GENERATION

18,277

(8) Under construction. The DYN/LS Power Group joint venture owns 64% of this facility. DYN owns a 50% interest in the

joint venture and the remaining 50% interest is held by LS Power Group. Total generating capacity of this facility is

~900MW.

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

(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 Capacity set forth in this table includes only DYN’s proportionate share of such unit’s gross generating

capacity.

(2) 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.

(4) Under construction. Represents net 21% ownership.

(3) Excludes 28 MW for Unit 3, which is not available during cold weather due to winterization requirements.

(6) Represents operating 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.

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