Dyne Therapeutics 8K Regulation FD Disclosure | SEC 10 Dec 08

2009 Financial Estimates

December 10, 2008

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

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 2009 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 and first quarter 2008 Form 10-Q, as amended, and second and
third quarter 2008 Forms 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 Adjusted Gross Margin. 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 December 10, 2008, which is available on our
website free of charge, www.dynegy.com.

Forward-looking Statements

Agenda

Bruce Williamson

Value Proposition

Industry Fundamentals

Commercial Strategy

Holli Nichols

Regional Overview

2009 Guidance Estimates and Sensitivities

Bruce Williamson

Strategic Outlook

Management Team

Q & A

Dynegy’s Value Proposition

Operate assets well

Capture commercial opportunities in
the near-term

Maintain an open commercial strategy
in outer years to capture longer term
market opportunities

Positioned to participate in industry
consolidation

Dynegy’s flexible capital structure allows
us to focus on operating and
commercializing assets well

Adjusted EBITDA expected to increase
~10% using midpoints from 2008 to 2009

Adjusted Free Cash Flow for 2009
essentially neutral after investing in
significant pollution control equipment,
protecting near-term cash flow

Dynegy is evaluating continued
participation in future development
activities

Protecting Value Today

Enhancing Value Tomorrow

Despite unprecedented economic times, we believe long-term power
generation market fundamentals remain unchanged

Dynegy has built a financial structure with ample liquidity, no significant debt
maturities before 2011, and bank and credit facilities scheduled to mature in
2012 and 2013, respectively, which positions us well to weather the current
market turbulence

Energy Economics – Global Energy Consumption

34%

Oil

24%

Natural Gas

28%

Coal

Nuclear

Renewables

World Total Energy Consumption by Fuel

Projected

Actual

Energy demand will continue to grow, utilizing all fuel types

Significant energy investments will be required to meet growing needs

Source: DOE/EIA

Energy Economics – U.S. Power Generation

Fuel Mix for U.S. Power Generation

4,153

4,722

Source: DOE/EIA

Coal

Natural Gas

Nuclear

Hydro/Renewable

Oil

Without significant investment in new infrastructure and technologies,
U.S. power generation fuel sources will remain essentially unchanged

Intensive capital requirements, rising costs and lengthy permitting process make construction
of new power generation facilities difficult in today’s financial and regulatory environment

Given that significant investments are not currently underway, it will likely take ~10-20 years
before a meaningful level of new baseload generation – of any technology – is operational

Therefore, in the near- to medium-term, where and how the U.S. generates power is likely
to remain relatively constant

49%

50%

18%

21%

19%

18%

10%

13%

Long-Term Power Generation Fundamentals

Supply: Continued Challenges

Construction Costs⁽¹⁾ ($/kW)

Demand is expected to continue to
grow over time

Energy efficiency improvements
expected to be offset by growth in
additional electricity demand

Demand: Continued Growth

U.S. Electric Consumption (MM MWh)

Generation supply is expected to
continue to tighten over time

Industry needs $1.2 trillion in capital
investments over next 15 years; $600
billion in new generation⁽²⁾

Barriers to entry remain high in a
capital intensive industry, likely causing
construction delays

Increased cost of construction

Challenging credit market

Regulatory uncertainty

(1) Construction costs are the midpoints of previously disclosed estimates and are based on various trade
publications and are intended solely as estimates. Actual cost estimates and actual cost of specific projects
may vary materially from these estimates. (2) Source: CERA

Data Source: EIA

U.S. Recessionary periods

Dynegy Expects Commodity Prices
to Continue to Rise Long-Term

CIN Hub On-Peak Prices ($/MWh)

Natural Gas Prices ($/MMBtu)

Despite historic and ongoing
volatility, commodity prices
continue to trend upward

Global demand for coal and
natural gas is expected to
continue to impact power prices

Note: Prices are historical monthly averages from brokered market indicators and NYMEX

Spark Spreads (Mass Hub vs TET M3 @ 7HR)

Commercial Strategy

Dynegy employs “Current +1” strategy based on
rationale that intra-year volatility can impact results

Intra-year volatility results from such events as weather
and commodity price spikes

Contracting in the “Current +1” years should bring
near-term stability against these uncertain events
and protect near-term cash flows

Typical commercial contracts include: heat rate call
options, bilateral contracts, tolling agreements, and
financial swaps

Longer term, we believe power market
fundamentals remain intact and demand will
outpace supply additions

As such, staying relatively open “+2 and Beyond”
provides opportunity to capture value in a
fundamentally rising price environment as supply/
demand tightens with no significant new generation
on the horizon

We believe our capital structure provides the “ultimate hedge”

Strong liquidity and minimal near-term debt maturities provide security as our “ultimate hedge” to
commercialize positions in volatile price environments

CIN Hub On-Peak Prices
Demonstrate Volatility ($/MWh)

Strategy Rationale

Midwest

West

Northeast

Commercial Strategy Differs by Region

Percent of Expected Adjusted Gross Margin Contracted by Year

Commercial strategy provides opportunity to capture rising price
trends but brings exposure to downside risks

Dynegy’s commercial strategy is tailored by region to match market opportunities

Dynegy expects to enter 2009 with ~60% of expected Adjusted Gross Margin
contracted on a consolidated basis through bilateral contracts, tolling agreements,
capacity agreements, financial forward sales and options

20%

40%

60%

80%

100%

2009

2010

2011

20%

40%

60%

80%

100%

2009

2010

2011

20%

40%

60%

80%

100%

2009

2010

2011

58%

32%

12%

85%

37%

52%

29%

26%

Contracted Open

Consolidated Portfolio

Going into 2009, Dynegy’s
expected Adjusted Gross Margin
is anticipated to be ~60% covered
by contractual arrangements

During 2009, we intend to monitor
commodity prices and seek to
capture additive short-term market
opportunities as they arise

Beyond 2010, portfolio is
essentially open – other than
structured transactions

Changes in market conditions or
contracted positions can impact
results both positively or
negatively

62%

20%

43%

Percent of Expected Adjusted
Gross Margin Contracted

Strong Liquidity is the Foundation for 2009

Dynegy maintained strong
liquidity during 2008

Strong liquidity and flexible capital
structure to manage collateral
requirements through market recovery

~$1.9 billion of liquidity as of 12/1/08

$300 million contingent facility available⁽¹⁾

No significant debt maturities until 2011

Undrawn credit facility due 2012

Letter of credit facility due 2013

Highlights of 2009 Estimates

$825 million – $1 billion anticipated
Adjusted EBITDA, assuming:

$8/MMBtu natural gas

$61.50/MWh CIN Hub on-peak power

Adjusted Operating Cash Flow
essentially covers maintenance and
environmental capital needs which
protects liquidity position

Net Income of $(20) million – $85
million and Operating Cash Flow of
$360 million – $535 million

(1) Available in increments as 2009 natural gas strip increases above $13/MMBtu

2009 Estimates
and Regional Drivers

Holli Nichols

Executive Vice President & Chief Financial Officer

Regional Drivers:

Regional results are driven primarily by power prices, spark spreads and capacity markets

Longer-term results will be impacted by regulatory activities and environmental requirements

Performance Drivers:

Price

Cost

What to look for

Key Contracts

2009 Guidance Estimates

2009-2013 Capital
Expenditure Estimates

Regional Overviews

Dynegy’s diversified portfolio is focused in three key regions

5 facilities in
NY, ME & CT

~3,800 MW in
NYISO &
NEPOOL

9 facilities

located in

TX, GA, CA,

AZ & NV

~5,200 MW

primarily in

CAISO &

WECC

~540 MW in

Georgia

~300 MW

under

construction

in ERCOT

15 facilities in

IL, MI, PA, AR

& KY

~8,400 MW in

MISO & PJM

DYNEGY

Includes G&A, partially offset by
interest income

Corporate / Other

Power Generation

18,277 MW

Midwest

8,405 MW

Northeast

3,809 MW

West

6,063 MW

Performance Drivers

Price:

CIN Hub power price volatility

Spark spread for Kendall and Ontelaunee

Coal sets the marginal price 50-65% of the time in MISO

Natural gas sets the marginal price of power in PJM

Cost:

Fixed price PRB coal and rail contracts

Operating expense incorporates impact of investing in
pollution control equipment

Look For:

Capacity markets in MISO

Weather can impact volumes of CCGT fleet and absolute
price to coal fleet

Track CIN Hub to IL Hub basis differentials

Midwest – Primarily Baseload Coal

Regional 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

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

345 – 470

Uncontracted Adjusted Gross Margin

$ 905 – 1,030

Adjusted Gross Margin

$ 560

Contracted Adjusted Gross Margin

(220) – (240)

Operating Expenses ⁽¹⁾

$ 685 – 790

Adjusted EBITDA

2009E

24.9 MM MWh

Generation Volumes

($MM)

$ 380 – 485

Operating Income

Going into 2009, ~ 60% Adjusted

Gross Margin contracted

Beyond 2009, Midwest portfolio is

substantially open

Note: Additional regional data provided in the Appendix. (1) Operating Expense excludes depreciation and amortization.

8,405 MW

Midwest – Key Contracts

100% of PRB coal supply is contracted through 2010, at largely fixed price

~35% of coal supply and price contracted for 2011 through 2012

Ten year transportation agreement with Burlington Northern through 2013
at attractive rates

2009 Average delivered coal cost at Baldwin is forecasted to be $1.49/MMBtu

Fuel Contracts:

Contracting activity primarily centers on the Midwest coal fleet

~1,200 MW CIN Hub On-Peak at an average price of $75/MWh, ~1,600 CIN Hub
Off-Peak MW at an average price of $38/MWh

200 MW Illinois auction contracted at ~$65/MWh expiring May 2009 (~50% load
factor)

Kendall Unit 3 (~ 280 MW) under tolling agreement to 2017 for ~$20 million
in 2009

Term capacity sales in place

PJM capacity auctions:

MISO capacity sales:

~1,100 MW bilateral capacity sales in place for 2009

Revenue
Contracts:

$ 174

~2,050

2010/2011

2011/2012

2009/2010

2008/2009

Auction Year

$ 110

~2,060

$ 191

~515

$ 102

~1,850

$ 112

~1,470

Auction Price
(~$/MW-day)

DYN MW cleared

West – Primarily Natural Gas

Regional 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 increased Resource Adequacy
requirements

Operational performance since the majority of the plants
operate under term contracts

Performance Drivers

Price:

~2/3 of Adjusted Gross Margin is derived through
tolling agreements in the near-term

Regional spark spreads

Natural gas sets the marginal price of power

Cost:

Tolling counterparties take financial and delivery risk
for fuel during tolled periods

Fuel is purchased as needed at index related prices

Look For:

Spread variability mitigated by toll contracts

Weather can impact volumes of CCGT fleet

Note: Additional regional data provided in the Appendix. (1) Operating Expense excludes depreciation and amortization.

6,063 MW

35 – 65

Uncontracted Adjusted Gross Margin

$ 320 – 350

Adjusted Gross Margin

$ 285

Contracted Adjusted Gross Margin

(130) – (140)

Operating Expenses ⁽¹⁾

(5)

Loss from Unconsolidated Investments

$ 185 – 205

Adjusted EBITDA

2009E

11.4 MM MWh

Generation Volumes

($MM)

$ 90 – 110

Operating Income

Going into 2009, ~85% Adjusted

Gross Margin contracted

Heavily contracted in near-term

West – Key Contracts

Gas is transported to each facility via firm and interruptible
transportation agreements, primarily on El Paso, Transwestern or
PG&E pipelines

Tolling counterparty assumes fuel delivery risk associated with gas
requirements during tolled periods for tolled capacity

Fuel Contracts:

Tolling, RMR, Heat Rate Call Options and Capacity Agreements

Griffith: 570 MW Toll Jun-Sep thru 2017

Arlington: 560 MW Toll Jun-Sep 2010; May-Oct 2011-2019

Morro Bay: 650 MW Toll thru Sep 2013

Moss Landing 1 & 2: 750 MW Heat rate call option thru Sept 2010

Moss Landing 6 & 7: 1,500 MW Year round through 2010

Oakland: RMR year-to-year

South Bay: 700 MW Toll thru Dec 2009; RMR year-to-year

Heard: 500 MW Capacity contract thru Dec 2015

Revenue
Contracts:

Northeast – Diverse Fuel and Dispatch Type

(1)

Adjusted Gross Margin includes contract amortization from the Independence ConEd contract. See Appendix for more detail. (2) Operating Expense includes effects of Central Hudson
lease expense and excludes depreciation and amortization.

Regional Drivers

NYISO – Spark spread for uncontracted combined
cycle gas and fuel oil units, and outright power price for
uncontracted baseload coal volume

ISO-NE – Spark spread for uncontracted combined
cycle gas units

Capacity Markets – ISO-NE formal capacity market
auction for 2010/2011 occurred in February 2008.
2009 capacity contracted in 2006 during transition to
auction mechanism. NY Capacity market well developed

Performance Drivers

Price:

New York Zone G

Spark spreads for New York Zone C, New England
and Mass Hub

Natural gas sets the marginal price of power

Cost:

Increased South American coal costs driven by
increase in Central App and international coal prices

Implementation of RGGI at market rates

Look For:

Margin impact from volatile South American
coal costs

Weather can impact volumes of CCGT fleet
and Roseton

Spark spreads

3,809 MW

115 – 175

Uncontracted Adjusted Gross Margin

$ 270 – 330

Adjusted Gross Margin ⁽¹⁾

$ 155

Contracted Adjusted Gross Margin

(185) – (205)

Operating Expenses ⁽²⁾

$ 85 – 125

Adjusted EBITDA

2009E

7.8 MM MWh

Generation Volumes

($MM)

$ 40 – 80

Operating Income

Going into 2009, ~50% Adjusted

Gross Margin contracted

Beyond 2009, portfolio is relatively

open – other than structured deals

Northeast – Key Contracts

Operating expense includes $50 million of Central Hudson lease
expense, and Operating Cash Flow includes cash lease
payments of $141 million in 2009

Coal (Danskammer):

One- to two-year contracts primarily sourced from South America

70% of coal supply priced for 2009, including delivery

Natural gas: Purchased on an as-needed basis

Fuel Oil (Roseton): Due to on-site storage availability of
1 MMBbls, fuel oil is purchased on an opportunistic basis

Fuel Contracts:

Other

Independence has a 740 MW capacity contract with ConEd (‘A’
Rated) through 2014; receive ~$100 million, net in cash but offset
by $50 million contract amortization in Adjusted Gross Margin

Danskammer has ~200 MW in power swaps at an average price
of ~$103/MWh on-peak and ~$73/MWh off-peak

Casco Bay and Bridgeport receive Forward Capacity Market
(FCM) payments from New England ISO

2009 Guidance includes ~900 MW of capacity sold

Heat Rate Call Options – Independence, 200 MW for ~$3.30/KW-
Mo; Casco Bay, 150 MW for ~$7/KW-Mo

Revenue
Contracts:

Anticipated Capital Expenditures (2009 – 2013)

Capitalized Interest

$ 50

$ 100

$ 55

$ 85

Maintenance – Coal facilities

180

225

280

Environmental

$ 380

TBD

125

2011

$ 275

TBD

2012

$ 230

TBD

110

2013

($MM)

2009

2010

Maintenance – Other facilities

120

Discretionary Investment ⁽¹⁾

TBD

TOTAL

$ 490

$ 455

Environmental primarily includes Consent Decree and mercury reduction expenditures

Consent Decree spending on track for completion in 2012 with 25% of remaining costs fixed

Capitalized interest has historically been included in Maintenance but relates to both Maintenance
and Environmental capital expenditures

Discretionary investments will be determined opportunistically based on estimated project returns

(1) Discretionary investments are subject to change and target IRR ~15% or more.

Note: Plum Point development is excluded as Dynegy is evaluating participation in future development activities. Plum Point debt is fully financed on a non-recourse basis. Although Sandy
Creek is under construction, it is not included in capex as Sandy Creek is not consolidated. Sandy Creek is financed on a non-recourse basis.

Notes:

Adjusted EBITDA includes ~$50 million for Central Hudson lease expense while total cash payment is $141 million

Working capital / Non-cash adjustments / Other primarily reflects changes in Accounts Receivable/Accounts
Payable balances:

Adds back cash payment of ~$50 million in excess of revenues recognized related to the ConEd contract

Subtracts ~$90 million cash payment above Central Hudson lease expense

2009 Guidance

$ 1,000

$ –

$ 1,000

Contracted Adjusted Gross Margin

$ 1,495-1,710

$ –

$ 1,495-1,710

Adjusted Gross Margin ⁽¹⁾

495-710

–

495-710

Uncontracted Adjusted Gross Margin

(535)-(585)

–

(535)-(585)

Operating Expenses

(135)-(125)

(130)-(120)

(5)

G&A / Interest Income / Other

(280)

–

(280)

Environmental Capital Expenditures

($MM)

Generation

Other

TOTAL

Adjusted EBITDA ⁽¹⁾

$ 955-1,120

$ (130)-(120)

$ 825-1,000

Interest Payments

(415)

Cash Taxes

(15)

Working Capital / Non-cash Adjustments / Other

(40)

(35)

Adjusted Cash Flow from Operations ⁽¹⁾

$ 915-1,080

$ (555)-(545)

$ 360-535

Maintenance Capital Expenditures

(140)

(15)

(155)

Capitalized Interest

(25)

–

(25)

Adjusted Free Cash Flow ⁽¹⁾

$ 470-635

$ (570)-(560)

$ (100)-75

Plan includes assumptions of contracted positions as of 8/19/2008, which is representative of our current contracted portfolio, and commodity pricing based on
an $8.00/MMBtu forward gas curve

($MM)

2009 Guidance – GAAP Measures ⁽¹⁾

$ (60)

$ (390)

$ 360 – 535

$ (20) - 85

Net cash provided by operating activities

Net cash used in investing activities

Net income

Net cash used in financing activities

Note: Guidance estimates are forward-looking in nature; actual results may vary materially from these estimates. Plum Point and Sandy Creek are excluded from 2009 estimates.

(1) Not intended as a GAAP reconciliation, for a reconciliation please see the Appendix

Adjusted EBITDA

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

2008E ⁽¹⁾

Price/Volume

Capacity

Morro Bay

Toll

Other

OpEx

NE Coal

Kendall Toll

Midwest Coal

2009 Plan

Adjusted EBITDA 2008 to 2009 ($MM)

~$915

~$95

~$25

~$(60)

~$(40)

$840

~$105

~$(55)

~$25

~$(20)

Increase of ~10% based on 2009 Guidance midpoint of $825 – 1,000 million range

Estimated Range of

$825 – 1,000 million

(1) Estimate as presented November 6, 2008.

Adjusted Free Cash Flow 2008 to 2009 ($MM)

Adjusted Free Cash Flow Essentially Neutral

-100

-75

-50

-25

100

125

150

2008E

Adj.EBITDA Change

Interest Payments

Environmental

CapEx

Working Capital

Maintenance CapEx

2009 Plan

~$(10)

~$15

~$(80)

~$(10)

$25

~$75

~$(35)

2009 Adjusted Free Cash Flow essentially neutral based on midpoint

Adjusted Operating Cash Flow increases primarily due to higher
prices/volumes but is offset by greater environmental capital expenditures

Estimated Range of

$(100) – 75 million

(1)

(1) Estimate as presented November 6, 2008.

Things to Consider When Looking at the Future

Several factors, some of which are beyond our control, can impact
our business both positively and negatively – the outcome and
timing is difficult to predict

Often events and variables are interrelated and business impacts
are not always additive

Such uncertainties include:

Coal and fuel oil cost

In-market availability

Transmission availability or congestion

Weather

Power prices

Spark spreads

Capacity prices

Basis

Natural Gas Sensitivity
Primarily Impacts Baseload Coal

Sensitivities based on full-year estimates and assume natural gas price
change occurs for the entire year and entire portfolio

On-peak power prices are adjusted by holding the spark spread constant to
a 7,000 Btu/KWh heat rate

Off-peak prices are adjusted holding the market implied heat rate constant

Note: Uncontracted portfolio for longer term assumed for illustrative purposes only.

$ (280)

$ (140)

- $2.00

$ (145)

$ (70)

- $1.00

$ 165

$ 70

+ $1.00

$ 320

$ 140

+ $2.00

Longer Term Uncontracted

2009 ~60% Contracted

Change in Cost of
Natural Gas ($/MMBtu)

Adjusted Gross Margin Sensitivity ($MM)

$(70)

$85

$170

TOTAL

$(35)

$45

$85

Natural Gas

Coal/Fuel Oil

$(35)

- 500

$40

+ 500

$85

+ 1,000

Generation Adjusted Gross Margin
Sensitivity ($MM)

Market Implied
Heat Rate
Movement
(Btu/KWh)

2009 with ~60% Contracted

Sensitivities based on “on-peak” power price changes and full-year estimates

Assumes constant natural gas price of $8.00/MMBtu and heat rate changes are
for a full year

Increased run-time will result in increased maintenance costs, which are not
included in sensitivities

Market Implied Heat Rate
Sensitivities Impact Entire Fleet

Note: Spark spread value changes depend on natural gas price assumptions. Uncontracted portfolio for longer term assumed for illustrative purposes only.

$(135)

$175

$350

TOTAL

$(90)

$110

$225

Natural Gas

Coal/Fuel Oil

$(45)

- 500

$65

+ 500

$125

+ 1,000

Generation Adjusted Gross Margin
Sensitivity ($MM)

Market Implied
Heat Rate
Movement
(Btu/KWh)

Longer-Term: Uncontracted

2009 Adjusted EBITDA at Risk

2009 Adjusted EBITDA range: $825 million – $1 billion

“Current + 1” commercial strategy provides some margin stability

Opportunities exist to capture extrinsic value from weather, run-times or heat-rates
movements but cannot be contracted today, leaving margin at risk

On a consolidated basis, Dynegy expects to enter into 2009 with ~60% of its
expected Adjusted Gross Margin covered by contractual arrangements

Awareness, continuous evaluation, cultivating options and maintaining a
diverse portfolio are tools for managing uncertainties that can impact results
both positively and negatively, including:

Coal and fuel oil cost

In-market availability

Transmission availability or congestion

Weather

Power prices

Spark spreads

Capacity prices

Basis

Strategic Outlook

Bruce Williamson

Chairman, President & Chief Executive Officer

2008 Recap and 2009 Outlook

What Didn’t Go Well…

What Went Well…

What Dynegy Will Do…

2008 – The Year in Review

2009

Experienced significant forced
outages at Baldwin and Havana

Incurred higher costs due to
widening basis in the Midwest
caused by flooding and
transmission constraints, as well
as commercial execution at PJM

Increased South American coal
costs due to “price majeure”;
subsequently re-contracted

Experienced milder than
expected weather causing decreased volumes in the Midwest and Northeast

Achieved 90% in-market availability for baseload coal fleet as of 10/31/08

Created capital and credit structures
which mitigate exposure to market
turmoil

Maintained strong liquidity

Repriced PRB coal contracts,
achieving minimal increase in
cost through 2010 and locked
-in ~35% in 2011 and 2012

Entered into long-term tolling
agreements in the West,
providing predictable cash flow

Partially commercialized Midwest
at attractive on-peak prices

Sold Rolling Hills for ~$370
million in cash

Continue to focus on operating
assets well

Continue to maintain strong
liquidity

Improve execution to protect
near-term cash flow through
“Current + 1” commercial strategy

Work with coal suppliers to
further contract fuel price

Continued focus on managing
spending in rising cost
environment

Appendix

18,277 MW

Strategically Positioned Portfolio

Dispatch Diversity ⁽¹⁾

Peaking

45%

Intermediate

33%

Baseload

22%

Geographic Diversity ⁽¹⁾

Midwest

46%

Northeast

21%

West

33%

Fuel Diversity ⁽¹⁾

Combined Cycle

33%

Simple Cycle

36%

Total Gas-fired

69%

Coal

24%

Fuel Oil

Note: Plum Point and Sandy Creek are currently under construction.
Sandy Creek and Plum Point are excluded from 2009 Guidance.

(1) Diversity percentages based on capacity, not actual volumes.

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

2009 Commodity Pricing Assumptions

* Represents annual average

Moss Landing, Morro Bay, Oakland

$73.88

NP-15 – California

Independence

$71.00

NY – Zone C

Roseton

$16.01

Fuel Oil #6 delivered to Northeast ($/MMBtu)

Danskammer

$5.83

South American delivered to Northeast

Baldwin

$1.49

Powder River Basin (PRB) delivered

Coal ($/MMBtu)

Arlington Valley, Griffith

$65.94

West – Palo Verde

South Bay

$74.38

SP-15 – California

Bridgeport, Casco Bay

$86.61

NE – Mass Hub

Roseton, Danskammer

$96.89

NY – Zone G

Midwest Coal, Midwest Peakers

$61.50

Cinergy

Ontelaunee

$73.50

PJM West

Kendall

$58.50

NI Hub / ComEd

Facilities

On-Peak Power ($/MWh)

$ 8.00

Natural Gas – Henry Hub ($/MMBtu)

2009E*

Key Assumptions

2009 Assumptions

Commodity pricing assumes
$8.00/MMBtu natural gas

Interest expense of ~$395 million and
Cash interest payments of ~$415
million

Plum Point and Sandy Creek are
excluded from 2009 Guidance
estimates

Resulting in net $265 million increase in
unrestricted cash from return of collateral
and decrease in restricted cash

Tax expense accrues at 40%; AMT
cash tax payment of $5 – 10 million

Expect to fully utilize federal NOLs in
2008

$260 million of AMT credits are
equivalent to approximately $750
million in federal NOLs

AMT credits reduce tax liability dollar-for-
dollar and do not expire

Other Assumptions

~$50 million annual amortization expense
included in Northeast EBITDA through
2014 related to ConEd contract; annual
capacity payment received of ~$100 million

Shares outstanding ~840 MM

Dynegy expected to become a partial cash
tax payer in 2012 after all AMT credits are
used and full year cash tax payer in 2013

Midwest Generation – Primarily Baseload Coal

$ 380 - 485

Operating Income

$ 685 - 790

Adjusted EBITDA

20 - 30

Peaking/Other ⁽¹⁾

2009

Midwest Forecast ($MM)

65 - 80

Combined Cycle

$ 600 - 680

Coal

$73.50

PJM West

Avg. Spark Spread

(PJM West vs TET M-3 @ 7HR)

$9.10

$9.20/MMBtu

Delivered Natural Gas

(TET M-3 + $0.05)

$(5.50)

On-Peak

Avg Gen to
CIN Hub Basis

($/MWh)

$3.18

PJM

Avg. Spark Spread

(NI Hub vs CHI CG @ 7HR)

$1.66

$1.49/MMBtu

Delivered PRB Coal (Baldwin)

0% - 10%

Peaking

10% - 20%

70% - 90%

Baseload

Annual

Average

Capacity

Factors

$58.50

NI Hub

$61.50

CIN Hub

Power Prices

(Average on peak
prices $/MWh)

$(3.50)

Off-Peak

MISO

10,000 – 12,000

Peaking

7,000 – 8,000

Baseload

Forecasted Fundamentals 2009

$1.90

Average

Capacity Price

(KW-Mo)

$8.12/MMBtu

Delivered Natural Gas

(CHI CG + $0.10)

10,000 – 11,000

Fleet Heat

Rate ⁽²⁾

(Nameplate
Btu/KWh)

24.9

Volumes (MM MWh)

(1) Other comprised of ancillary services, emission credit sales and amortization of
intangibles and trading. (2) Nameplate Heat Rate is after adjustment for generating
starts & stops, weather, fuel types, efficiencies and other operational components.

Unlike PJM, the MISO capacity
market is not liquid in the outer years

But average MISO capacity payments
tend to follow PJM capacity payment
trends for the longer timeframe

West Generation – Primarily Natural Gas

0% - 20%

Peaking

30% - 60%

n/a

Baseload

Annual

Average

Capacity Factors

Avg. Spark Spread (NP15 vs PG&E @ 7HR)

$16.02

$65.94

Palo Verde

$73.88

NP-15

Power Prices

(Average on-peak prices
$/MWh)

System RA $0.50 - $1.50

9,500 – 10,500

Peaking

7,000 – 7,200

Baseload

Forecasted Fundamentals 2009

Avg. Capacity
Price (KW-Mo)

$8.26/MMBtu

Delivered Natural Gas (PG&E + $0.30)

n/a

Fleet Heat Rate ⁽²⁾(Nameplate, Btu/KWh)

11.4

Volumes (MM MWh)

$ 185 - 205

Adjusted EBITDA

35 - 45

Peaker/RMR/Other ⁽¹⁾

West Forecast ($MM) 2009

$ 90 - 110

Operating Income

$ 150 - 160

Combined Cycle

(1) Other comprised of ancillary services, emission credit sales, equity earnings(losses) and amortization of intangibles and trading. (2) Nameplate Heat Rate is after adjustment for
generating starts & stops, weather, fuel types, efficiencies and other operational components.

85% of West portfolio is contracted
for 2009 and 2010, therefore near-
term regional results should not
have much variability

Northeast Generation – Coal, Fuel Oil & Natural Gas

Other noteworthy items:

Operating expense includes $50 million
of Central Hudson lease expense, and
Operating Cash Flow includes cash
lease payments of $141 million in 2009

Independence under capacity
agreement with ConEd expiring 11/2014

Adjusted EBITDA includes approximately
$50 million net earnings, however Adjusted
Cash Flow from Operations will include cash
receipt of approximately $100 million in 2009

Carbon emissions include a cost
assumption of ~$3.00/MT for CO2
allowances associated with RGGI

$9.40

Gas (NY Zone C vs Dawn @ 7HR)

$8.80/MMBtu

Delivered Natural Gas (Dawn + $0.35)

$9.87/MMBtu

Delivered Natural Gas (Tran Z6 – NY)

$3.95

$2.49

0% - 10%

20% - 50%

75% - 85%

Peaking

$17.53

Gas (Mass Hub vs TRAN Z6-NY @ 7HR)

($79.17)

Fuel Oil (NY-G vs #6 Oil @11HR)

Avg.
Spark
Spread

Baseload

Annual

Average

Capacity Factors

$5.83/MMBtu

$16.01/MMBtu

SA Coal

$86.61

Mass Hub

$71.00

NY Zone C

$96.89

NY Zone G

Power Prices

(Average on peak
prices $/MWh)

New England

NYISO

9,500 – 10,500

Peaking

7,000 – 8,000

Baseload

Forecasted Fundamentals 2009

Average

Capacity Price
(KW-Mo)

Fuel Oil #6

Delivered Fuel

10,000 – 11,000

Fleet Heat
Rate ⁽²⁾

(Nameplate,
Btu/KWh)

7.8

Volumes (MM MWh)

$ 40 - 80

Operating Income

$ 85 - 125

Adjusted EBITDA

(10) - 0

Peaking/Other ⁽¹⁾

2009

Northeast Forecast ($MM)

95 - 120

Combined Cycle

$ 0 - 5

Coal

(1) Other comprised of ancillary services, emission credit sales and amortization of intangibles and trading. (2) Nameplate Heat Rate is after adjustment for generating starts & stops,
weather, fuel types, efficiencies and other operational components.

$75

$35

$56

$131

$104

$115

$127

$57

$66

$60

$56

$48

$38

$28

$16

$48

100

125

150

175

200

2009

2010

2011

2012

2013

2014

2015

2016 - 2035

Imputed Interest

Imputed Debt Equivalent

Central Hudson Lease – Northeast Segment

Accrual Lease Expense

2009 Central Hudson treated as Debt
(would require the following adjustments to GAAP financials):

Income Statement – Add back $50 million lease expense to Adjusted EBITDA; add
$66 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 $75 million of imputed principal to Operating
Cash Flows

$141 million cash payment split between $66 million imputed interest payment (Operating
Cash Flows) and $75 million imputed principal payment (Financing Cash Flows)

Balance Sheet – Include $700 million total PV (10%) of future lease payments

2009 Central Hudson treated as Lease
(as currently shown in GAAP financials):

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

Cash Flow Statement – $141 million cash payment
included in Operating Cash Flows

Balance Sheet – lease obligation not included in debt
balance

Central Hudson Cash Payments

(remaining as of 12/31/08, $MM)

$141

$95

$112

$179

$142

$143

$105

Imputed Debt Equivalent at PV(10%)
of future lease payments = $700 MM⁽¹⁾

(1) PV of payments calculated as of 12/31/08

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

Dynegy is Financially Well Positioned

Pro-Forma

Debt Maturity Profile (As of 12/31/08, $MM)

Liquidity Profile ($MM)

No significant debt maturities until 2011

Undrawn facility due 2012

Bank debt is at LIBOR + 150 bp

Weighted average cost of debt at 7.5%

No significant restrictive covenants

$58

$63

$569

$576

$550

$2,697

$999

500

1,000

1,500

2,000

2,500

3,000

2009

2010

2011

2012

2013

2014

2015

2016+

On balance sheet debt profile = $5.5 B

Strong liquidity position as of Dec.1

~$1.9 billion in liquidity

~$684 million of cash-on-hand

$300 million contingent facility available

Limited uncollateralized credit exposure
to financial counterparties

$328

$429

$271

$750

$684

$1,121

$1,056

$619

$1,180

$1,166

500

1,000

1,500

2,000

2,500

3,000

Dec-31-07

Mar-31-08

Jun-30-08

Sep-30-08

Dec-01-08

Cash

Availability

Contingent facility

$1,850

$1,449

$1,485

$890

$1,930

⁽²⁾

(1)

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

(2)

Lehman Commercial Paper Inc. filed for bankruptcy in October 2008 thus reducing the available capacity of our Revolving Facility by $70 million

⁽¹⁾

Pro Forma Debt & Other Obligations Capital Structure –
Expected as of 12/31/08

Dynegy Power Corp.

Central Hudson⁽¹⁾ $700

Dynegy Holdings Inc.

$1,080 Million Revolver $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 = $344

Unsecured = $4,947

Dynegy Inc..

Senior Debentures $344

NOTE: Capital Structure excludes debt associated with the Plum Point development project.

(1) 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. (2) Restricted cash includes $850MM related to the Synthetic Letter of Credit facility. Sandy Creek is excluded from Guidance, therefore $275 million has been reclassified from Restricted Cash to Unrestricted Cash. (3) Net Debt & Other Obligations and Net Debt are non-GAAP financial measures; for definitions and uses of such measures please see refer to Item 2.02 of our 8-K filed December 10, 2008.

($ MM)

Sithe Energies

($ Million)

12/31/08E

Total Obligations

$6,210

Less: Cash on hand & Investments

930

Less: Restricted cash ⁽²⁾

850

Net Debt & Other Obligations ⁽³⁾

$4,430

Less: Central Hudson Lease Obligation

700

Net Debt ⁽³⁾

$3,730

Significant Environmental Progress

On target to further reduce emissions in the Midwest

Major Assumptions

Estimate of remaining spend is $660 – $710 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

Reg G Reconciliation – 2009 Guidance

Contracted Adjusted Gross Margin

560

285

155

1,000

Uncontracted Adjusted Gross Margin

345

470

115

175

495

710

495

710

Adjusted Gross Margin (2) (3)

905

1,030

320

350

270

330

1,495

1,710

1,495

1,710

Operating Expenses

(220)

(240)

(130)

(140)

(185)

(205)

(535)

(585)

(535)

(585)

General and administrative expense

(185)

(175)

(185)

(175)

Losses from unconsolidated investments

(5)

Other items, net

Adjusted EBITDA (2) (3)

685

790

185

205

125

955

1,120

(130)

(120)

825

1,000

(1)

(2)

This presentation is not intended to be a reconciliation of non-GAAP measures persuant to Reg G; please see below for such reconciliations.

(3)

Operating income (loss)

380

485

110

510

675

(195)

(185)

315

490

Losses from unconsolidated investments

(5)

Other items, net

Add: Depreciation and amortization expense

230

370

380

EBITDA

610

715

170

190

135

875

1,040

(130)

(120)

745

920

Plus / (Less):

Mark-to-market

(10)

Adjusted EBITDA

685

790

185

205

125

955

1,120

(130)

(120)

825

1,000

#REF!

Contracted Adjusted Gross Margin

560

285

155

1,000

Uncontracted Adjusted Gross Margin

345

470

115

175

495

710

495

710

Adjusted Gross Margin

905

1,030

320

350

270

330

1,495

1,710

1,495

1,710

Mark-to-market

(75)

(15)

(80)

Operating Expenses

(220)

(240)

(130)

(140)

(185)

(205)

(535)

(585)

(535)

(585)

Depreciation and amortization expense

(230)

(85)

(55)

(370)

(10)

(380)

General and administrative expense

(185)

(175)

(185)

(175)

Operating income (loss)

380

485

110

510

675

(195)

(185)

315

490

Net Income (Loss)

(20)

Add Back:

Income tax expense

(10)

Interest expense

395

Depreciation and amortization expense

380

EBITDA

745

920

Plus / (Less):

Mark-to-market

Adjusted EBITDA

825

1,000

Total

OTHER

Total

2009 EARNINGS ESTIMATES (1)

(IN MILLIONS)

GEN - MW

GEN - WE

GEN - NE

Total GEN

2009 estimates are based on forward commodity price curves using an $8/MMBtu gas price. 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 2009 and forward adjusted EBITDA 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, Adjusted EBITDA and Adjusted Gross Margin are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on December 10, 2008 for definitions, utility and uses of such non-GAAP

financial measures. Reconciliations of consolidated EBITDA and Adjusted EBITDA to Net Income and Adjusted Gross Margin to Operating income (loss) are presented below. Management does not allocate

interest expenses and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. Accordingly, a reconciliation of EBITDA and Adjusted EBITDA

to Operating income (loss) on a segment level is also presented below.

GEN - MW

GEN - WE

GEN - NE

Power Generation

Total

Total GEN

OTHER

Power Generation

Total

OTHER

GEN - WE

GEN - NE

Total GEN

GEN - MW

Reg G Reconciliation – 2009 Guidance (cont.)

Adjusted EBITDA (2) (3)

955

1,120

(130)

(120)

825

1,000

Cash Interest Payments

(415)

Cash Tax Payments

(15)

Collateral

Working Capital / Other Changes

(40)

(35)

Adjusted Cash Flow from Operations (3) (4)

915

1,080

(555)

(545)

360

535

Maintenance Capital Expenditures

(140)

(15)

(155)

Environmental Capital Expenditures

(280)

Capitalized Interest

(25)

Adjusted Free Cash Flow (3) (4)

470

635

(570)

(560)

(100)

Net cash used in Investing Activities

$ (390)

Net cash provided by Financing Activities

$ (60)

(1)

(2)

(3)

(4)

915

1,080

(555)

(545)

360

535

Maintenance capital expenditures

(140)

(15)

(155)

Environmental capital expenditures

(280)

Capitalized Interest

(25)

Adjusted Free Cash Flow

470

635

(570)

(560)

(100)

* Note that Cash Flow from Operations and Adjusted Cash Flow from Operations are the same amount in our 2009 Cash Flow Estimates.

Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on December 10, 2008 for definitions, utility and uses of such

non-GAAP financial measures. Please see 2009 Earnings Estimates for a reconciliation of Adjusted EBITDA to Net Income.

This presentation is not intended to be a reconciliation of non-GAAP measures pursuant to Regulation G.

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on

December 10, 2008 for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of Adjusted Cash Flow from Operations and

Adjusted Free Cash Flow to Cash Flow from Operations is presented below.

Cash Flow from Operations and Adjusted Cash Flow

from Operations (*)

GEN

OTHER

Total

2009 estimates are based on forward commodity price curves using an $8/MMBtu gas price. 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 2009 and forward adjusted 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.

(IN MILLIONS)

2009 CASH FLOW ESTIMATES (1) (3)

GEN

OTHER

Total

Reg G Reconciliation – 2008 Guidance

GEN - MW

GEN - WE

GEN - NE

Total GEN

OTHER

Total

Net Income

195

add back:

Income tax expenses

120

Interest expense

430

Deppreciation and amortization expense

380

EBITDA (2)

832

229

137

1,198

(73)

1,125

Plus/(less):

Release of state franchise tax and sales tax liabilities

(16)

Gain on liquidation of foreign entity

(26)

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

(57)

Mark-to-market

(105)

(45)

(147)

Adjusted EBITDA (2)

670

160

140

970

(130)

840

GEN

OTHER

TOTAL

Adjusted EBITDA (2)

970

(130)

840

Cash Interest Payments

(430)

Cash Tax Payments

(15)

Collateral

(15)

Working Capital/Other Changes

(25)

Adjusted Cash Flow from Operations (4)

930

(535)

395

Maintenance Capital Expenditures

(155)

(15)

(170)

Environmental Capital Expenditures

(200)

Adjusted Free Cash Flow (4)

575

(550)

Net cash used in investing Activities

(170)

Net cash provided by Financing Activities

150

(1)

(2)

GEN - MW

GEN - WE

GEN - NE

Total GEN

OTHER

Total

Operating income (loss)

617

132

826

(146)

680

Losses from unconsolidated investments

(8)

(11)

(19)

Other items, net

Add: Depreciation and amortization expense

215

100

370

380

EBITDA

832

229

137

1,198

(73)

1,125

(3)

(4)

GEN

OTHER

TOTAL

Cash Flow from Operations

920

(550)

370

Legal and regulatory payments

Adjusted Cash Flow from Operations

930

(535)

395

Maintenance capital expenditures

(155)

(15)

(170)

Environmental capital expenditures

(200)

Adjusted Free Cash Flow

575

(550)

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 6, 2008 for definitions, utility and

uses of such non-GAAP financial measures. A reconciliation of Adjusted Cash Flow from Operations and Adjusted Free Cash Flow to Cash from Operations is presented below.

2008 CASH FLOW ESTIMATES (1) (3)

(IN MILLION)

Power Generation

2008 estimates are based on quoted forward commodity price curves as of October 7, 2008. 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 won or operate such assets. Divestitutures could also result in impairment charges.

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 6, 2008 for definitions, utilities and uses of such non-GAAP financial

measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expenses and income taxes on segment level and therefore uses

Operating income (loss) as the most directly comparable GAAP measure.

This presentation is not intended to be a reconciliation of non-GAAP measures pursuant to Regulation G.

2008 EARNINGS ESTIMATES (1)

(IN MILLIONS)

Power Generation

As presented November 6, 2008

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⁽⁵⁾

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

Region/Facility⁽¹⁾

Location

Net

Capacity⁽²⁾

Primary

Fuel Type

Dispatch

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

WECC

Griffith

Golden Valley, AZ

558

Gas - CCGT

Intermediate

WECC

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. Together, DYN and LS Power Group own 64% of this facility.

(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%

(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.

(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.

Dyne Therapeutics Inactive 8-KRegulation FD Disclosure