dyn

B k f A iB k f A i ||M ill L hM ill L hBank of America Bank of America ||Merrill LynchMerrill Lynch

2010 Megawatt Roundup2010 Megawatt Roundup

April 7, 2010

Investor Relations | Norelle Lundy, Vice President | Laura Hrehor, Senior Director | 713‐507‐6466 | [email protected]

ForwardForward‐‐looking looking StatementsStatements

• 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 2010 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 2009 Form 10‐K for additional information about the risks, uncertainties and other factors affecting these forward‐looking statements and Dynegy generally. Dynegy’s actual future results may vary materially from those expressed or implied in any forward‐looking statements. All of Dynegy’s forward‐looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward‐looking statements. In dditi D di l i bli ti t d t f d l ki t t t t fl t taddition, 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, Net Debt and Adjusted Gross Margin. Reconciliations of these measures to the most directly comparable GAAP measures to the extent available without unreasonable effort 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 February 25, 2010, which is available on our website free of charge, www.dynegy.com.

2

Dynegy at a Dynegy at a Glance Glance

Dynegy provides wholesale power, capacity and ancillary services to utilities, cooperatives, municipalities and other energy companies in key U.S. regions

Generation Capacity ~12,500 MW

2010 Adjusted EBITDA (2) $ 425 – 550 MM

2010 Adjusted Cash Flow from Ops (2) $ (15) – 110 MMj p $ ( )

2010 Adjusted Free Cash Flow (2) $ (360) – (235) MM

Market Cap (1) ~$ 785 MM

Shares outstanding ~600 MM

3

Shares outstanding 600 MM

(1) As of March 30, 2010, using $1.31 closing share price. (2) Forecasted estimates provided on November 5, 2009.

We Believe Long Term Industry We Believe Long Term Industry Fundamentals Remain StrongFundamentals Remain Strong

Power generation remains cyclical – the recent downward trend is expected to reverse over time as supply/demand tightensexpected to reverse over time as supply/demand tightens • Near term, Dynegy will continue to focus on operating and commercializing well and on maintaining ample liquidity

• Longer term, Dynegy’s ability to harvest value will center around capitalizing on

Near Term Expectations Long Term Expectations

expected stronger power prices and demand

Power markets should tighten

Natural gas prices should rise, increasing power prices

N ffi i t it ld h

Power prices remain weak

Natural gas prices remain volatile

New power generation will come online at a slower rate due to barriers to entry Newer, more efficient units could push

older generation into retirement

Development trends point to emphasis on renewables – however, cost is high and grid infrastructure remains an issue

at a slower rate due to barriers to entry such as: – Depressed capital markets

– Uncertainty around Cap & Trade and other environmental regulation & legislation

4

and grid infrastructure remains an issue

Industry consolidation could provide synergies leading to shareholder value

environmental regulation & legislation

– Low power prices, making it difficult to justify returns

Market ChallengesMarket Challenges

If you are worried about…

• Depressed power prices & spark spreads• Rising coal prices• Impact of potential environmental regulations• Liquidity

…we believe Dynegy is positioned to meet these challenges with our diverse operating portfolio

5

Regional OverviewRegional Overview

Dynegy’s ~12,500 MW portfolio is focused in 3 regions

MidwestMidwest 5,575 MW10 facilities

Primarily low‐cost baseload coal and efficient CCGTs well‐positioned in generation dispatch order

WestWest Primarily natural gas‐fired facilities3,696 MW

Diverse fuels and dispatch type

Primarily natural gas‐fired facilities5 facilities

3,282 MW4 facilities

NortheastNortheast

Adjusted EBITDA by Region

West

Adjusted EBITDA by Fuel Type

Gas

Northeast~15%

~20%

Midwest~65%

Other~5%

Gas ~45%

Coal~50%

6

Dynegy’s Midwest region represents ~40% of generation capacity, but contributes ~65% of Adjusted EBITDA

While coal contributes about half of Adjusted EBITDA, natural gas becomes a larger contributor in a low gas price environment

Midwest Midwest –– WellWell‐‐PositionedPositionedBaseloadBaseload Coal & Efficient CCGTsCoal & Efficient CCGTs

Regional Performance DriversPrice: • CIN Hub power price for MISO fleet

MISO Dispatch Order$240

220 Dynegy MISO facilities by unit

$/MWh

Price: CIN Hub power price for MISO fleet• Spark spreads for Kendall and Ontelaunee• Coal generally has been setting the marginal price of power in MISO ~80‐85% of the time in a low natural gas

200

180

160

140

120

100

Min. Load Avg. Load Peak Load

271MW

228 MW

y gy y

of the time in a low natural gas environment and reduced demand

• Natural gas sets the marginal price of power in PJM

C t L t PRB l d il t t 100%

100

80

60

40

20

010 20 30 40 50 60 70 80 90 100 110 120 130

903 MW

271 MW

2,241 MW

Source: Energy Velocity as of 4/13/09

Cost: • Low cost PRB coal and rail contracts 100% contracted/ priced for 2010

• 2010 Average Delivered PRB to Baldwin is $1.49/MMBtuO ti i t i t

Hydro Nuclear Coal Renewables Gas Oil

Cumulative Capacity GW

• Operating expense incorporates impact of investing in pollution control equipment

Watch: • Track CIN Hub to IL Hub basis differentials

7

• Capacity markets in MISO • New environmental regulations/ enforcement Baldwin Facility: 1,800 MWBaldwin Facility: 1,800 MW

West West –– Primarily Natural GasPrimarily Natural Gas

Regional Performance Drivers Cal‐ISO Dispatch OrderPrice: • ~70% of Adjusted Gross Margin is

$180

160 Dynegy Cal‐ISO facilities by unit

$/MWh

Price: 70% of Adjusted Gross Margin is derived through tolling agreements in the near‐term

• Regional spark spreads• Natural gas sets the marginal price of

60

140

120

100

80

Min. Load Avg. Load Peak Load

706MW3 179MWNatural 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

60

40

20

0Source: Energy Velocity as of 4/13/09

4 8 12 16 24 28 32 36 40 44 48 52 6456 6020

706 MW3,179 MW

• Fuel is purchased as needed at index related prices

Watch: • Operational performance since the majority of the plants operate under



j y p ptolling contracts

• Weather can affect volumes of uncontracted CCGT fleet

• Spread variability mitigated by toll

8

p y g ycontracts

• New environmental regulations/ enforcement Moss Landing Facility: 2,529 MWMoss Landing Facility: 2,529 MW

Northeast Northeast –– Diverse Fuel and Dispatch TypeDiverse Fuel and Dispatch Type

Regional Performance Drivers NY‐ISO Dispatch OrderPrice: • New York Zone G power price for

$180

160 Dynegy NY‐ISO facilities by unit Peak Load

$/MWh

p pDanskammer and New York Zone G spark spread for Roseton

• Spark spreads for New York Zone C for Independence and Mass Hub for C B

60

140

120

100

80

Min. Load Avg. Load

1,185 MW

1 974MW

123 MW

Peak Load

Casco Bay• Natural gas sets the marginal price of power

Cost: • 2010 delivered South American coal

60

40

20

0Source: Energy Velocity as of 4/13/09

2 4 6 8 12 14 16 18 20 22 24 26 28 3010 32 34 36

1,974 MW

80% contracted/ priced at $3.55/MMBtu• Natural gas purchased as needed• RGGI allowance cost at market rates



Watch: • Weather can affect volumes of uncontracted CCGT fleet and Rosetonfacility

9

• Coal delivery• New environmental regulations/ enforcement Independence Facility: 1,064 MWIndependence Facility: 1,064 MW

Why Invest in DynegyWhy Invest in Dynegy? ?

… and Dynegy’s advantages… consider Dynegy’s beliefIf you are worried about…

Depressed power prices & spark

spreads

• Longer‐term prices and spreads should increase as demand grows and economic conditions improve

• Supply/demand should tighten as

• Dynegy is well positioned to capture demand growth in 3 economic regions with a diverse portfolio of assets

• Dynegy’s gas‐fired fleet becomes a larger contributor in a low natural gas prices environment

• Dynegy’s commercial strategy increases predictability ofspreads pp y golder assets are retired

Dynegy s commercial strategy increases predictability of earnings and cash flow in near term, while maintaining potential for upside as markets improve in the longer term

Rising coal prices • Eastern Coal prices are volatile due to global demand

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

g• Dynegy’s coal and rail contracts continue to provide stability

Impact of potential environmental

• Air, water and solid waste regulations are pending and could

lt i i ifi t i t t th

• Dynegy remains committed to environmental investments and has spent ~$550 MM of ~$960 MM program in Illinois

• Current spending is anticipated to lessen impact of future regulationsenvironmental

regulationsresult in a significant impact to the power industry

g

• Dynegy’s Midwest fleet operates in a region where coal sets the marginal price of power 50‐65% of the time – and as much as 65‐85% when natural gas prices are low

• Prolonged decline in commodity

10

Liquidityg y

prices and potential environmental regulations could result in lower earnings and increased costs

• Dynegy has significantly reduced near term debt maturities and adequate liquidity to commercialize positions

Dynegy Expects Demand to Rise LongDynegy Expects Demand to Rise Long‐‐TermTerm

U.S. Electric Generation (GWh)

U.S. Electricity demand is projected to increase by ~2% in 2010 (1)

• 2009 U.S. electric demand was down ~4%, but remained within the 5 year average range

• 2010 may continue to be a challenging business environment with commodity prices

( )

80,000

90,000

100,000

110,000

environment with commodity prices remaining volatile

• Weather spikes, as seen this winter, continue to represent opportunities to capture incremental value

50,000

60,000

70,000

,

2010 YTD 2009 5 Year Avg

$12

$14

$60

$70

incremental value

• U.S. electricity demand is projected to increase by 1.5% in 2011(1)

• Despite ongoing volatility, commodity prices b i i t t d d

Natural Gas & Power Prices

CIN Hub On‐Peak ($/MWh)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

$4

$6

$8

$10

$20

$30

$40

$50 are beginning to trend upwardCIN Hub On‐Peak ($/MWh)

Natural Gas ($/MMBtu) Dynegy believes commodities will remain volatile and

$0

$2

$0

$10

2009 Bal 10 2011 2012 2013

11Note: Generation as of 2/13/10 from EEI. Pricing as of 3/8/10, reflects actual day ahead on‐peak settlement prices and quoted forward on‐peak monthly prices. (1) EIA Short‐term Energy Outlook, March 2010

Source: Brokered market indicators

will remain volatile and demand will increase over time

Dynegy’s Commercial StrategyDynegy’s Commercial StrategyReflects Long Term Industry Fundamentals Reflects Long Term Industry Fundamentals

Contracted Percentage of Expected G ti V l

Commercial Strategy

75%

100%Generation Volumes (% of MWh, as of 1/26/10)

~85%

>95%Near to intermediate term view:

•Dynegy is focused on capturing extrinsic value, increasing predictability

>95%

50%

g p yof earnings and cash flow and also protecting against downside risk

Long term view: ~50%

0%

25%•Dynegy is relatively uncontracted in outer years to provide opportunities to capture value in a fundamentally rising price environment as supply/demand

~15%~15%

~5%

0%

2010 2011 2012

Uncontracted Contracted

p pp ytightens

M i t i i l t k t id t ti l

Level as of 11/5/09

12

Maintaining long term market upside potential while protecting against downside risks

Midwest Coal Fleet is CompetitivelyMidwest Coal Fleet is CompetitivelyAdvantaged with Key ContractsAdvantaged with Key Contracts

$62008‐09 Coal Prices ($/MMBtu)Coal Price Outlook

$5

$6 • South American and Central Appalachian coal prices are volatile due to global demand and weather cycles

S. American

$3

$4 •Dynegy’s Midwest rail is contracted through 2013 with no fuel price escalators

Central App

$2

$3 •Dynegy’s Midwest coal fleet burns 100% Powder River Basin coal and coal supply is 100% priced through 2010

Baldwin PRBDelivered Price$1 39 $1.49

$0

$1

Dynegy’s coal and rail contracts continue to provide stability Powder River Basin

Delivered Price

$0.81$0.62

$1.39 $1.49

$1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10

(1)

13Sources: Historical prompt month coal pricing from: PRB – Platts, CAPP – NYMEX; SA – Argus (1) 1Q10 represents 1/1/10– 3/8/10

Midwest Coal Fleet is CompetitivelyMidwest Coal Fleet is CompetitivelyAdvantaged with Environmental UpgradesAdvantaged with Environmental Upgrades

$600 Significant Cash Investment ($MM)Environmental Spending Outlook$545

$400

$500

•Consent Decree spending and associated controls should lessen impact of potential changes in air regulations

$300

$400 •Remaining spend of ~$415 million for a total investment of $960 million to upgrade pollution control equipment to further reduce certain emissions

$185

$140

$75$100

$200 by ~90%

•Annual spending declines through 2013 and cash‐on‐hand of ~$746 million as of February 19 in excess of

$15$0

2005‐2009 2010 2011 2012 2013

o as o eb ua y 9 e cess oCapEx requirements

Dynegy’s environmental investments demonstrate

14

Dynegy’s environmental investments demonstrate ongoing commitment to meet regulatory standards

Dynegy’s Capital Structure Dynegy’s Capital Structure Complements Our Commercial StrategyComplements Our Commercial Strategy

1,500Non‐recourse Plum Point debt (2) Term LC facility (1) Other balance sheet debt Debt Maturity Profile (As of 12/31/09, $MM)

T l b l h d b $5 6 B

750

1,000

1,250Total balance sheet debt = ~$5.6 B

$1,003

$790

$1,054 $1,112 $1,064

$63$148

0

250

500

$166$4 $9

$186

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020+

• Liquidity of ~$1.94 billion at 12/31/09, with no significant bond maturities until 2015

• $744 million of debt associated with the Plum Point construction project(2) has been accounted for as current but continues to be non recourse to Dynegy

Dynegy has significantly reduced near‐term debt maturities

accounted for as current, but continues to be non‐recourse to Dynegy –Dynegy’s maximum liability is $15 million (3)

15

y gy g yand adequate liquidity to commercialize positions

(1) Term Letter of Credit facility is supported by $850 million of restricted cash. (2) Dynegy is a minority shareholder in Plum Point Energy Associates, LLC (PPEA). Total debt for PPEA of ~$744 million has been reclassified to current debt due to the uncertainty surrounding PPEA’s ability to meet certain 2010 credit agreement covenants. This debt is non‐recourse to Dynegy. (3) Dynegy’s maximum liability associated with Plum Point is a $15 million letter of credit supporting its contingent equity commitment.

What Makes a LongWhat Makes a Long‐‐Term Value Play? Term Value Play?

Operate &Operate & PrudentPrudent StrategicStrategic

Abilit t i k C ti i t ti l Si lifi d it l

Operate &Operate &CommercializeCommercialize

WellWellFinancialFinancial

ManagementManagement

StrategicStrategicPositioningPositioning

Ability to manage risk through geographic and dispatch diversity

Continuing to maximize cash flows by maintaining

Continuing to pro‐actively manage capital structure to facilitate execution of commercial strategy

Maintaining simple,

Simplified capital structure provides strategic flexibility

Simplified stock structure in which all outstandingcash flows by maintaining

a low‐cost, reliable operating platform

Commercial strategy remaining open to h t l l

Maintaining simple, flexible capital structure

No significant bond maturities until 2015

Driving down costs with

in which all outstanding equity is publicly held

harvest value as supply and demand tighten over the longer term

Driving down costs with multi‐year cost savings program

16

Dynegy believes it is positioned to capture value as markets improve over the longer term

Q & AQ & A

Appendix Appendix

Dynegy’s Diversified Asset Portfolio Dynegy’s Diversified Asset Portfolio

Dispatch Diversity

Peaking35%

Baseload30%

Geographic Diversity

MidwestNortheast26%

Fuel DiversityCombined Cycle36%P ki 35%

Intermediate35%

30%44%

West30%

Peaking21%

Total Gas‐fired57%

Coal29%

Fuel Oil14%

12,434 MW

Note: Plum Point is currently under construction. 19

2010 2010 Guidance Guidance Range Range

($MM) 2/25/2010 Guidance(1)

Adjusted EBITDA $ 425 – 550

Interest payments (380)

Other (2) (60)

Adjusted cash flow from operations $ (15) – 110

Maintenance capital expenditures (120)

Environmental capital expenditures (200)

Capitalized Interest (25)

Adjusted free cash flow $ (360) – (235)

Table above is not intended as a GAAP reconciliation; reconciliation located in the Appendix.

2010 Guidance – GAAP Measures ($MM)

Net loss $ (215) – (140)

Net cash provided by (used in) operating activities $ (15) – 110

20

Net cash used in investing activities $ (400)

Net cash provided by financing activities $ 15

Note: Guidance estimates are forward‐looking in nature; actual results may vary materially from these estimates. (1) Based on 2010 forward natural gas prices of $5.72/MMBtu as of 1/26/10. (2) “Other” includes working capital, non‐cash adjustments and cash taxes.

Adjusted Adjusted 2010 2010 EBITDA SensitivitiesEBITDA Sensitivities

Anticipated Range for2010 Adjusted EBITDA ($MM)

$550 MM

•Expected range of Adjusted EBITDA for 2010 continues to be sensitive to several factors

•The horizontal X‐axis represents possible

$600

$550

j ($ )

p pchanges in natural gas prices – As percentage of expected generation contracted goes up, sensitivity decreases

•The vertical Y‐axis represents the possible

$500

$425 MM

p pimpacts of various other factors:– Volatility of commodity prices

– Basis differentials

– Capacity prices

$450

$400

Nat. Gas 12‐Mo Avg($/MMBtu) $5.00 Gas $6.00 Gas $7.00 Gas

– Capacity prices

– Unplanned outages

•Often events and variables are interrelated and individual sensitivities are not always additiveCIN Hub On Peak

$5.72 Gas

21Note: Sensitivities reflect >95% of expected generation contracted on a consolidated basis. 2/25/10 guidance ranges based on 2010 forward natural gas prices of $5.72/MMBtu as of 01/26/10.

are not always additive$35.00 $42.00 $49.00CIN Hub On‐Peak($/MWh)

2010 2010 Commodity Pricing AssumptionsCommodity Pricing AssumptionsAs presented November 5, 2009

2010E*

Natural Gas Henry Hub ($/MMBtu) $ 6 15Natural Gas – Henry Hub ($/MMBtu) $ 6.15

On‐Peak Power ($/MWh) Facilities

NI Hub / ComEd $42.95 Kendall

PJM West $59.25 Ontelaunee

Cinergy $44.32 Midwest Coal

NY – Zone C $53.62 Independence

NY – Zone G $71.24 Roseton, Danskammer

NE – Mass Hub $66.11 Casco Bay

NP‐15 – California $60.65 Moss Landing, Morro Bay, Oakland

SP‐15 – California $58.90 South Bay

Coal ($/MMBtu)

Powder River Basin (PRB) delivered $1.49 Baldwin

South American delivered to Northeast $3.55 Danskammer

22* Represents annual average based on 10/6/09 pricing.

Fuel Oil #6 delivered to Northeast ($/MMBtu) $10.97 Roseton

Tax and Other Tax and Other Assumptions Assumptions As presented November 5, 2009

Tax Assumptions Other Assumptions– Tax expense accrues at ~40%; expect to pay state cash tax payments of ~$2 million

– Dynegy not expected to become a significant cash tax payer until well into

– Commodity pricing assumes $6.15/MMBtu natural gas

– ~$50 million annual amortization expense included in Northeast Adjustedsignificant cash tax payer until well into

the futureexpense included in Northeast Adjusted EBITDA through 2014 related to ConEdcontract; annual capacity payment received of ~$100 million

– Shares outstanding ~595 MM

23

Natural Gas SensitivityNatural Gas SensitivityPrimarily Impacts Baseload CoalPrimarily Impacts Baseload Coal

As presented November 5, 2009

Adjusted EBITDA Sensitivity ($MM)Change in Cost of Natural Gas

($/MMBtu) 2010 >95% Contracted Longer Term Uncontracted

+ $2 00 $ 30 $ 340+ $2.00 $ 30 $ 340

+ $1.00 $ 15 $ 165

‐ $1.00 $ (15) $ (165)

•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 k i dj t d h ldi th k t i li d h t t t t

24

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

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

Market Implied Heat RateMarket Implied Heat RateSensitivities Impact Entire FleetSensitivities Impact Entire Fleet

As presented November 5, 2009

2010 with >95% Contracted

Market Implied Heat Rate Movement

Generation Adjusted EBITDA Sensitivity ($MM)

Longer‐Term: Uncontracted

Market Implied Heat Rate Movement

Generation Adjusted EBITDA Sensitivity ($MM)

(Btu/KWh) Coal/Fuel Oil Natural Gas TOTAL

+ 1,000 $‐ $20 $20

+ 500 $‐ $10 $10

$ $( ) $( )

(Btu/KWh) Coal/Fuel Oil Natural Gas TOTAL

+ 1,000 $15 $120 $135

+ 500 $5 $60 $65

$( ) $( ) $( )‐ 500 $‐ $(5) $(5)

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

‐ 500 $(5) $(55) $(60)

p p p g y

•Assumes constant natural gas price of ~$6.15/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

25Note: Spark spread value changes depend on natural gas price assumptions. Uncontracted portfolio for longer term assumed for illustrative purposes only.

BasisBasis SensitivitiesSensitivitiesAs presented November 5, 2009

• Midwest– 2010 Plan assumes average generation to CIN Hub basis of $(5.50)/MWh

– 2010 Plan assumes Midwest volumes of ~25 MM MWh

– +/‐ $1.00/MWh change in basis = +/‐ $25 million impact to Adjusted EBITDA on a full year basis

• NortheastNortheast– 2010 Plan assumes average Casco Bay generation to Mass Hub basis of $(4.50)/MWh on peak and $(2.75)/MWh off peak

2010 Pl C B l f 2 MMMWh– 2010 Plan assumes Casco Bay volumes of ~2 MM MWh

– +/‐ $1.00/MWh change in basis = +/‐ $2 million impact to Adjusted EBITDA on a full year basis

26

Midwest Capacity Price SensitivitiesMidwest Capacity Price SensitivitiesAs presented November 5, 2009

• 2010 Guidance assumes:

– As of 10/6/09, the weighted average unsold MISO capacity of 2,066 MW

– Average capacity price of $0.58/KW‐Mo (using 10/6/09 pricing)g p y p $ / ( g / / p g)

– Current value of unsold MISO capacity in 2010 Plan = ~$14 million

Ch i i d l l i– Change in price and volumes can alter capacity revenue

27

Anticipated Capital Expenditures Anticipated Capital Expenditures (2010 (2010 –– 2013)2013)

As presented February 25, 2010

($MM) 2010 2011 2012 2013

Maintenance – Coal facilities $ 85 $ 70 $ 70 $ 65

Maintenance – Gas and other facilities 25 55 20 70

Environmental 200 140 95 50

Corporate 10 10 10 10

Capitalized Interest 25 20 10 5Capitalized Interest 25 20 10 5

TOTAL Cap Ex $ 345 $ 295 $ 205 $ 200

• “Environmental” primarily consists of Consent Decree and mercury reduction expenditures

– 2013 includes ~$15 million related to final Consent Decree expenditures

• Coal facility maintenance is relatively stable over time

28

•Maintenance for “Gas and other facilities” is largely a function of run‐time and also includes expenditures for Roseton

Significant Environmental Progress Significant Environmental Progress As presented February 25, 2010

On target to further reduce emissions in the Midwest

2008 20102009 2011 20122007

Vermilion

Hennepin

Baldwin 3

Baldwin 1

Baldwin 2

Havana

Projects completeCash outflow continues through 2013

Major Assumptions• Estimate of remaining spend is ~$415 million for a total investment of $960 million

Go Forward Cost Composition

investment of $960 million

• Approximately 25% of remaining costs are firm

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

Labor56%

Materials32%

29

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

Rental Equipment & Other 12%

Commodity PricesCommodity Prices

$160$160CIN Hub/Cinergy ($/MWh) New York Zone G ($/MWh)

2008 Actual 2010 Actual/Forward as of 1/26/10(1)2009 Actual

$80

$100

$120

$140

$160

$

$80

$100

$120

$140

$160 2008A: $ 66.842009A: $ 34.672010A/F (Jan): $ 43.54

2008A: $ 100.862009A: $ 49.832010A/F (Jan): $ 64.97

$0

$20

$40

$60

J F M A M J J A S O N D

$0

$20

$40

$60


Palo Verde ($/MWh) Natural Gas ($/MMBtu)

$120

$140

$160

$12

$14

$16 2008A: $ 71.822009A: $ 34.732010A/F (Jan): $ 51.71

2008A: $ 8.852009A: $ 3.922010A/F (Jan): $ 5.72

$20

$40

$60

$80

$100

$2

$4

$6

$8

$10 / ( ) $

30

$0

$


$0


(1) Pricing as of 1/26/10. Prices reflect actual day ahead on‐peak settlement prices for 1/1/10 – 1/26/10 and quoted forward on‐peak monthly prices for 1/27/10 – 12/31/10.

Spark SpreadsSpark Spreads

$50$50 PJM West ($/MWh) Mass Hub ($/MWh)

2008 Actual 2010 Actual/Forward as of 1/26/10(1)2009 Actual

$20

$30

$40

$50

$20

$30

$40

$50

2008A: $ 14.862009A: $ 12.192010A/F(Jan): $ 11.67

2008A: $ 20.542009A: $ 12.102010A/F(Jan): $ 14.14

($10)

$0

$10


($10)

$0

$10


Palo Verde ($/MWh) NP‐15 ($/MWh)

$30

$40

$50

$30

$40

$50 2008A: $ 13.242009A: $ 7.232010A/F(Jan): $ 8.14

2008A: $ 17.842009A: $ 8.282010A/F(Jan): $ 11.99

$0

$10

$20

$30

$0

$10

$20

$30 / ( ) $ 2010A/F(Jan): $ 11.99

31

($10)


($10)


(1) Pricing as of 1/26/10. Prices reflect actual day ahead on‐peak settlement prices for 1/1/10 – 1/26/10 and quoted forward on‐peak monthly prices for 1/27/10 – 12/31/10.

Collateral Collateral As presented February 25, 2010

($MM) 12/31/2008 12/31/2009 2/19/2010

Generation $ 1,064 $ 638 $ 515$ 1,064 $ 638 $ 515

Other 189 189 189

Total $ 1,253 $ 827 $ 704

Cash $ 118 $ 291 $ 204

LCs 1,135 536 500

Total $ 1 253 $ 827 $704Total $ 1,253 $ 827 $704

•Decrease in generation collateral:

–LC reduction due to $275 million reduction of LC facility for Sandy Creek and lower commodity–LC reduction due to $275 million reduction of LC facility for Sandy Creek, and lower commodity prices, partially offset by

–Cash increase due to initial margin postings resulting from an increase in volume of transactions executed through our futures clearing manager

•Other collateral primarily includes Sithe Debt Service Reserve of $83 million and $101 million related to a

32

•Other collateral primarily includes Sithe Debt Service Reserve of $83 million and $101 million related to a tax‐exempt facility liquidity backstop LC provided by the non‐recourse PPEA credit facility

Central Hudson Lease Central Hudson Lease –– Northeast SegmentNortheast Segment

200I d I

Central Hudson Cash Payments (remaining as of 12/31/09, $MM)

Imputed Debt Equivalent at PV (10%) of future lease payments = $626 MM(1)

$48

$37 $28 $16

100

125

150

175Imputed InterestImputed Debt Equivalent

$95$112

$179

$142 $143 $143

$35 $56 $131 $105 $115 $127 $22 $35

$60

$56

$5

$42

25

50

75

100

Accrual Lease Expense $27

$77

0

2010 2011 2012 2013 2014 2015 2016 2017‐ 2035

• 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

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 $60 million imputed interest expense to Interest Expense; add $23 million estimated depreciation & amortization expense; adjust tax expense for net difference

$

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

$

33

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

•Cash Flow Statement – Add back $35 million of imputed principal to Operating Cash Flows

• $95 million cash payment split between $60 million imputed interest payment (Operating Cash Flows) and $35 million imputed principal payment (Financing Cash Flows)

•Balance Sheet – Include $626 million total PV (10%) of future lease payments

• Cash Flow Statement – $95 million cash payment included in Operating Cash Flows

• Balance Sheet – lease obligation not included in debt balance

(1) PV of payments calculated as of 12/31/09

Dynegy’s Financial Position Dynegy’s Financial Position As presented February 25, 2010

1,5002,400Debt Maturity Profile (As of 12/31/09, $MM) Liquidity Profile ($MM)

$2,253Total balance sheet debt = ~$5.6 B

750

1,000

1,250

$1,147 $1,471

$1,507

1,200

1,600

2,000$1,840

$1,942

$1,003

$790

$1,054$1,112 $1,064

$63$148

0

250

500

$693$471

$746

0

400

800

Dec 31 2008 Dec 31 2009 Feb 19 2010

$166

$4 $9

$186

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020+

Non‐recourse Plum Point debt (2) Term LC facility (1) Other balance sheet debt

Dec 31 2008 Dec 31 2009 Feb 19 2010

Availability Cash

• Undrawn $1.08 billion revolver due 2012• $850 million letter of credit facility due 2013

•Decrease in cash from FY08 to FY09 due to FY09 operating activities

• Includes $744 million associated with Plum Point construction– This debt has been reclassified to current, but

continues to be non‐recourse to Dynegy (2)

– Dynegy’s maximum liability associated with Plum Point is a $15 million letter of credit to cover construction

• Increased availability as a result of decreased collateral requirements due to lower commodity prices

• Increase in cash from year‐end 2009 due to cash inflow from collateral clearing broker due

34

is a $15 million letter of credit to cover construction overruns and defaults, should they occur

• Excludes $626 million related to Central Hudson lease, which is off‐balance sheet

to lower commodities

(1) Term Letter of Credit facility is supported by $850 million of restricted cash. (2) Dynegy is a minority shareholder in Plum Point Energy Associates, LLC (PPEA). Total debt for PPEA of ~$744 million has been reclassified to current debt due to the uncertainty surrounding PPEA’s ability to meet certain 2010 credit agreement covenants. This debt is non‐recourse to Dynegy.

Capital Capital Structure Structure As presented February 25, 2010

TOTALS ($ Million) 12/31/09

Secured $918Debt & Other Obligations as of 12/31/09

Dynegy Holdings Inc.

Dynegy Inc.

Secured Non‐Recourse $1,031

Unsecured $3,650

Lease Obligation $626

Dynegy Holdings Inc.

$1,080 Million Revolver(1) $0Term L/C Facility $850Tranche B Term $68

Sr. Unsec. Notes/Debentures $3,450Sub.Cap.Inc.Sec (“SKIS”) $200

Dynegy Power Corp.

Central Hudson(2) $626Senior Debentures $287 PP 1st Lien $644Tax Exempt 100Gross Debt $744Less: Restricted Cash (19)

Sithe Energies Plum Point Energy Assoc.

($ Million) 12/31/09 12/31/08

Total Obligations $6,225 $6,825

Less: Cash on hand & Investments 471 693

Less: Restricted cash 869 1 154

Total, Net Debt $725

(3) (3)Less: Restricted cash 869 1,154

Net Debt & Other Obligations $4,885 4,978

Less: Net Non‐recourse Project Debt, under construction 725 586

Net Debt & Other Obligations associated with Operating Assets $4,160 $4,392

Plus: Net Non‐recourse Project Debt, under construction 725 586(1) Represents drawn amounts under the revolver; actual amount of revolver was $1 08 Billion as of

Net Debt & Other Obligations $4,885 $4,978

Less: Central Hudson Lease Obligation 626 700

Net Debt $4,259 $4,278

35

(1) Represents drawn amounts under the revolver; actual amount of revolver was $1.08 Billion as of 12/31/09 . (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 Term Letter of Credit facility and ~$19MM related to Plum Point in 12/31/09 and ~$29MM related to Plum Point in 12/31/08.

Collar Option ExampleCollar Option Example

Call Option:Dynegy sells a 100 MW on‐peak call option for the 2011 calendar year at a $65 strike price at a premium of $0.85/MWh

Combining Put & Call Options creates a “Collar” Option• Collars provide earnings certainty and reduce exposure to

•Dynegy receives and realizes a premium payment in current period from buyer for the call option (See Calculation 1)

•Option gives buyer right to buy 100 MW on‐peak from Dynegy for 2011 calendar year at $65 if buyer strikes the option on the option expiration date

•Buyer will strike option if 2011 calendar prices exceed $65 in

power price volatility- If market price clears at $70, buyer will strike call option. Maximum revenue on 100 MW will be $27MM versus $29MM had power been sold at market price (See Calculations 3 & 4)

- If market price clears at $30, Dynegy will strike put option. Maximum revenue on 100 MW will be $14MM versus $12MM had power been sold at market price (See Calculations 5 & 6)y p p $

order to sell the 100 MW at a higher price

•Commitment sets a potential price on the sale of the 100 MW for Dynegy at $65 which is realized during option period if buyer strikes option

• If prices are below $65 on the option expiration date, option expires without exercise

sold at market price (See Calculations 5 & 6)

• Option impact on Financial Statements:- Premium revenue and expenses are realized in period options were sold/purchased

- Record liability or asset based on buy or sell of option in future option period

- Exercised option value realized during the option periodp

Put Option:Dynegy buys a 100 MW on‐peak put option for the 2011 calendar year at a $35 strike price at a premium of $0.45/MWh

•Dynegy pays and realizes a premium expense in current period

Exercised option value realized during the option period

CalculationsPremium Calculations:

1) 4,080 on‐peak hours/year x $0.85/MWh x 100 MW = $346,800to seller for the put option (See Calculation 2)

•Option gives Dynegy right to sell 100 MW to seller for 2011 calendar year at $35 if Dynegy strikes the option on the option expiration date

•Dynegy will strike option if 2011 calendar prices go below $35 in order to sell the 100 MW at a higher price

2) 4,080 on‐peak hours/year x $0.45/MWh x 100 MW = $183,600

Sales Calculations:

3) 4,080 on‐peak hours/year x $65/MWh x 100 MW = ~$27 MM


36

•Commitment sets a potential price on the sale of the 100 MW for Dynegy at $35 which is realized during option period if Dynegy strikes option

• If prices are above $35 on the option expiration date, option expires without exercise



Contracted Generation Volumes Contracted Generation Volumes –– 2011 & 20122011 & 2012As presented February 25, 2010

2011 Contracted Generation Volumes as of:

Dec 08 Feb 09 May 09 Aug 09 Nov 09 Jan 10 Feb 10

Midwest 5% 5% 5% 15% 50% 75% 75%

West 20% 20% 20% 40% 50% >95% >95%

Northeast 10% 5% 5% 15% 60% >95% >95%

Consolidated 10% 10% 10% 20% 50% 85% 85%

2012 Contracted Generation Volumes as of:

Nov 09 Jan 10 Feb 10Nov 09 Jan 10 Feb 10

Midwest 1% 1% 1%

West 15% 50% 50%

N h 10% 10% 15%

37

Northeast 10% 10% 15%

Consolidated 5% 15% 15%

Financial Covenant RatiosFinancial Covenant Ratios

C t ti i t f th DHI C dit A t t d l l t d b dCovenant ratios are requirements of the DHI Credit Agreement covenants and are calculated based on trailing four quarters

38

Dynegy Generation Facilities (as of 1/30/10)Region/Facility(1) Location Net Capacity(2) Primary Fuel Dispatch Type NERC Region

MIDWESTBaldwin Baldwin IL 1 800 Coal Baseload MISO

NOTES:

1) Dynegy owns 100% of each unit Baldwin Baldwin, IL 1,800 Coal Baseload MISOHavana Havana, IL

Units 1‐5 228 Oil Peaking MISOUnit 6 441 Coal Baseload MISO

Hennepin Hennepin, IL 293 Coal Baseload MISOOglesby Oglesby, IL 63 Gas Peaking MISOStallings Stallings, IL 89 Gas Peaking MISO

) y gylisted except as otherwise indicated. For each unit in which Dynegy owns less than a 100% interest, the Total Net Capacity set forth in this table includes only Dynegy’s proportionate share of such unit’s gross generating capacity.

2) Unit capabilities are based ong g , gVermilion Oakwood, IL

Units 1‐2 164 Coal/Gas Baseload MISOUnit 3 12 Oil Peaking MISO

Wood River Alton, ILUnits 4‐5 446 Coal Baseload MISO

Kendall Minooka, IL 1,200 Gas ‐ CCGT Intermediate PJMO l O l T hi PA 580 G CCGT I di PJM

2) Unit capabilities are based on winter capacity.

3) Under construction. Represents net ownership of 21%.

4) Dynegy 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 untilOntelaunee Ontelaunee Township, PA 580 Gas ‐ CCGT Intermediate PJM

Plum Point (3) Osceola, AR 140 Coal Baseload SERCMidwest TOTAL 5,456

NORTHEASTIndependence Scriba, NY 1,064 Gas ‐ CCGT Intermediate NYISORoseton (4) Newburgh, NY 1,185 Gas/Oil Intermediate NYISO

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.

5) Represents operating capacity of Units 3 & 4 Units 1 & 2 with aRoseton Newburgh, NY 1,185 Gas/Oil Intermediate NYISO

Casco Bay Veazie, ME 540 Gas ‐ CCGT Intermediate ISO‐NEDanskammer Newburgh, NY

Units 1‐2 123 Gas/Oil Peaking NYISOUnits 3‐4 (4) 370 Coal/Gas Baseload NYISO

Northeast TOTAL 3,282

WEST

Units 3 & 4. Units 1 & 2, with a combined net generating capacity of 352 MW, are currently in layup status and out of operation.

6) Represents operating capacity of Units 1 & 2 and CT. Units 3 & 4, with a combined net generating capacity of 397 MW, did not receive RMR status from CAISO for 2010 and are

WESTMoss Landing Monterey County, CA

Units 1‐2 1,020 Gas ‐ CCGT Intermediate CAISOUnits 6‐7 1,509 Gas Peaking CAISO

Morro Bay (5) Morro Bay, CA 650 Gas Peaking CAISOSouth Bay (6) Chula Vista, CA 309 Gas Peaking CAISOOakland Oakland CA 165 Oil Peaking CAISO

currently out of operation and in the process of being decommissioned.

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

39

Oakland Oakland, CA 165 Oil Peaking CAISOBlack Mountain (7) Las Vegas, NV 43 Gas Baseload WECC

West TOTAL 3,696

TOTAL GENERATION 12,434

Appendix Appendix –– RegReg G ReconciliationsG Reconciliations

Debt DefinitionsDebt Definitions

Debt Measures: We believe that our debt measures are useful because we consider these measures as a way to re‐evaluate our progress toward our strategic corporate objective of y p g g p jreducing our overall indebtedness. In addition, many analysts and investors use these measures for valuation analysis purposes. The most directly comparable GAAP financial measure to the below measures is GAAP debt.

– “Net Debt” – We define “Net Debt” as total GAAP debt less cash and cash equivalents and restricted cash.Net Debt We define Net Debt as total GAAP debt less cash and cash equivalents and restricted cash. Restricted cash in this case consists only of collateral posted for the credit facility at the end of each period, and cash associated with the Sandy Creek letter of credit, the Sithe debt reserve and Plum Point debt, at the end of each period where applicable.

– “Net Debt and Other Obligations” – We define “Net Debt and Other Obligations” as total GAAP debt plus certain operating lease commitments less cash and cash equivalents and restricted cash. Restricted cash in this case consists only of collateral posted for the credit facility at the end of each period, and cash associated with the Sandy Creek letter of credit and Plum Point debt, at the end of each period where applicable.

– “Net Debt and Other Obligations Associated with Operating Assets” – We believe that this measure is useful for of the purpose of evaluating our operating assets. We define “Net Debt and Other Obligations Associated with Operating Assets” as “Net Debt and Other Obligations” less GAAP debt associated with assets under construction.

41

Reg G Reconciliation – 2010 Guidance

DYNEGY INC.2010 EARNINGS ESTIMATES (1)

Adjusted Gross Margin (2) 585$ 680$ 245$ 255$ 225$ 245$ 1,055$ 1,180$ ‐$ ‐$ 1,055$ 1,180$ Operating Expenses (215) (215) (115) (115) (165) (165) (495) (495) ‐ ‐ (495) (495) General and Administrative Expense ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ (150) (150) (150) (150) Other Items, Net ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 15 15 15 15

Adjusted EBITDA (2) 370$ 465$ 130$ 140$ 60$ 80$ 560$ 685$ (135)$ (135)$ 425$ 550$

( )(IN MILLIONS)

Total GEN OTHER TotalPower Generation

GEN ‐ MW GEN ‐ WE GEN ‐ NE

Adjusted EBITDA (2) 560$ 685$ (135)$ (135)$ 425$ 550$ Cash Interest Payments ‐ ‐ (380) (380) (380) (380) Cash Tax Payments ‐ ‐ (5) (5) (5) (5) Working Capital / Other Changes (60) (60) 5 5 (55) (55)

Adjusted Cash Flow from Operations (4) 500 625 (515) (515) (15) 110

Total

2010 CASH FLOW ESTIMATES (1) (3)(IN MILLIONS)

GEN OTHER

Adjusted Cash Flow from Operations (4) 500 625 (515) (515) (15) 110 Maintenance Capital Expenditures (110) (110) (10) (10) (120) (120) Environmental Capital Expenditures (200) (200) ‐ ‐ (200) (200) Capitalized Interest (25) (25) ‐ ‐ (25) (25)

Adjusted Free Cash Flow (4) 165$ 290$ (525)$ (525)$ (360)$ (235)$

Net Cash Used in Investing Activities (400)$ (400)$

Net Cash Provided by Financing Activities 15$ 15$

(1)

(2)

2010 estimates are based on quoted forward commodity price curves using a $5.72/MMBtu gas price as of January 26, 2010. 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 2010 and forward adjusted 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, Adjusted EBITDA and Adjusted Gross Margin are non‐GAAP financial measures. Please refer to Item 2.02 of our Form 8‐K filed on February 25, 2010, for definitions, utility and uses of such non‐GAAP financial measures. Reconciliations of consolidated EBITDA and Adjusted EBITDA to Net Loss attributable to Dynegy Inc. 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 belowsegment level is also presented below.

Continued on next page

42

Reg G Reconciliation – 2010 Guidance (cont.)

P G i

Operating Income (Loss) 75$ 170$ 70$ 80$ 15$ 35$ 160$ 285$ (165)$ (165)$ (5)$ 120$ Noncontrolling Interests 10 10 ‐ ‐ ‐ ‐ 10 10 ‐ ‐ 10 10 Other Items, Net ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 15 15 15 15 Add: Depreciation and Amortization Expense 245 245 65 65 35 35 345 345 15 15 360 360

EBITDA 330$ 425$ 135$ 145$ 50$ 70$ 515$ 640$ (135)$ (135)$ 380$ 505$ Plus / (Less):

Noncontrolling Interests (10) (10) ‐ ‐ ‐ ‐ (10) (10) ‐ ‐ (10) (10)

TotalGEN ‐ NEGEN ‐ MW GEN ‐ WE Total GEN OTHERPower Generation

Noncontrolling Interests (10) (10) (10) (10) (10) (10) Mark‐to‐Market Losses (Gains) 50 50 (5) (5) 10 10 55 55 ‐ ‐ 55 55 Adjusted EBITDA 370$ 465$ 130$ 140$ 60$ 80$ 560$ 685$ (135)$ (135)$ 425$ 550$

Adjusted Gross Margin 585$ 680$ 245$ 255$ 225$ 245$ 1,055$ 1,180$ ‐$ ‐$ 1,055$ 1,180$ Mark‐to‐Market (Losses) Gains (50) (50) 5 5 (10) (10) (55) (55) ‐ ‐ (55) (55) Operating Expenses (215) (215) (115) (115) (165) (165) (495) (495) ‐ ‐ (495) (495) Depreciation and Amortization Expense (245) (245) (65) (65) (35) (35) (345) (345) (15) (15) (360) (360)

TotalPower Generation

Total GEN OTHERGEN ‐ MW GEN ‐ WE GEN ‐ NE

Depreciation and Amortization Expense (245) (245) (65) (65) (35) (35) (345) (345) (15) (15) (360) (360) General and Administrative Expenses ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ (150) (150) (150) (150)

Operating Income (Loss) 75$ 170$ 70$ 80$ 15$ 35$ 160$ 285$ (165)$ (165)$ (5)$ 120$

Net loss attributable to Dynegy Inc. (215)$ (140)$ Add Back:

Income Tax Benefit (140) (90) Interest Expense 375 375 Depreciation and Amortization Expense 360 360

Total

Depreciation and Amortization Expense 360 360 EBITDA 380$ 505$ Plus / (Less): Noncontrolling Interests (10) (10) Mark‐to‐Market Losses 55 55 Adjusted EBITDA 425$ 550$

(3)

(4)

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 February 25 2010 for definitions utility and uses of such non GAAP financial(4)

Cash Flow and Adjusted Cash Flow From Operations 500$ 625$ (515)$ (515)$ (15)$ 110$

Maintenance Capital Expenditures (110) (110) (10) (10) (120) (120) Environmental Capital Expenditures (200) (200) ‐ ‐ (200) (200) Capitalized Interest (25) (25) ‐ ‐ (25) (25)

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 February 25, 2010, 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.

GEN OTHER Total

43

Adjusted Free Cash Flow 165$ 290$ (525)$ (525)$ (360)$ (235)$

dyn

Business

t itldhsuchas

t prbl d ilt t

i bli ti t d t fd

mw diversefuelsanddispatchtype

mw marginalpriceofpowerinmiso

midwest northeast coal

low natural gas

fa bankofamerica