Dynegy's Midwest portfolio is well-positioned with over 5,500 MW of baseload coal and efficient natural gas-fired plants. Coal plants generally set the marginal price of power over 80% of the time in the Midwest ISO market due to low natural gas prices and reduced demand. Dynegy's Midwest facilities benefit from low-cost Powder River Basin coal and rail contracts.

1. B k fA
Bank of America | M ill L h
Bank of America | Merrill Lynch
i
2010 Megawatt Roundup
April 7, 2010
Investor Relations | Norelle Lundy, Vice President | Laura Hrehor, Senior Director | 713‐507‐6466 | ir@dynegy.com

2. Forward‐looking Statements
Forward‐looking Statements
• This presentation contains statements reflecting assumptions, expectations, projections, intentions or beliefs
about future events that are intended as “forward‐looking statements.” You can identify these statements,
including those relating to Dynegy’s 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
addition, Dynegy disclaims any obligation to update any forward‐looking statements to reflect events or
dditi D di l i bli ti t d t f d l ki t t t t fl t t
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

3. Dynegy at a Glance
Dynegy at a 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)
j p $( )
$ (15) – 110 MM
2010 Adjusted Free Cash Flow (2) $ (360) – (235) MM
Market Cap (1) ~$ 785 MM
Shares outstanding
Shares outstanding ~600 MM
600 MM
(1) As of March 30, 2010, using $1.31 closing share price. (2) Forecasted estimates provided on November 5, 2009.
3

4. We Believe Long Term Industry
Fundamentals Remain Strong
Power generation remains cyclical – the recent downward trend is
expected to reverse over time as supply/demand tightens
expected 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
expected stronger power prices and demand
Near Term Expectations Long Term Expectations
Power prices remain weak Power markets should tighten
Natural gas prices remain volatile Natural gas prices should rise, increasing
New power generation will come online power prices
at a slower rate due to barriers to entry
at a slower rate due to barriers to entry Newer, more efficient units could push
N ffi i t it ld h
such as: older generation into retirement
– Depressed capital markets
Development trends point to emphasis
– Uncertainty around Cap & Trade and other on renewables – however, cost is high
environmental regulation & legislation
environmental regulation & legislation and grid infrastructure remains an issue
and grid infrastructure remains an issue
– Low power prices, making it difficult to
justify returns Industry consolidation could provide
synergies leading to shareholder value
4

5. Market 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

6. Regional Overview
Dynegy’s ~12,500 MW portfolio is focused in 3 regions
Midwest 5,575 MW Primarily low‐cost baseload coal and efficient CCGTs
10 facilities well‐positioned in generation dispatch order
West 3,696 MW Primarily natural gas‐fired facilities
Primarily natural gas‐fired facilities
5 facilities
Northeast 3,282 MW Diverse fuels and dispatch type
4 facilities
Adjusted EBITDA by Region Adjusted EBITDA by Fuel Type
West Gas
Gas
~20% ~45%
Midwest Northeast Coal
~65% ~15% ~50%
Other
~5%
Dynegy’s Midwest region represents While coal contributes about half of Adjusted
~40% of generation capacity, but EBITDA, natural gas becomes a larger
contributes ~65% of Adjusted EBITDA contributor in a low gas price environment
6

7. Midwest – Well‐
Midwest – Well‐Positioned
Baseload Coal & Efficient CCGTs
Regional Performance Drivers $/MWh MISO Dispatch Order
$240
Price: • CIN Hub power price for MISO fleet
CIN Hub power price for MISO fleet 220 Dynegy MISO facilities by unit
y gy y
200
• Spark spreads for Kendall and Ontelaunee 180
Min. Load Avg. Load Peak Load
160
• Coal generally has been setting the 140 228 MW
marginal price of power in MISO ~80‐85% 120
of the time in a low natural gas
of the time in a low natural gas 100 271 MW
271 MW
environment and reduced demand 80
2,241 MW 903 MW
60
• Natural gas sets the marginal price of 40
power in PJM 20
Source: Energy Velocity as of 4/13/09
0
10 20 30 40 50 60 70 80 90 100 110 120 130
Cost:
C t •LLow cost PRB coal and rail contracts 100%
t PRB l d il t t 100%
Cumulative Capacity GW
contracted/ priced for 2010
Hydro Nuclear Coal Renewables Gas Oil
• 2010 Average Delivered PRB to Baldwin is
$1.49/MMBtu
•OOperating expense incorporates impact
ti i t i t
of investing in pollution control
equipment
Watch: • Track CIN Hub to IL Hub basis differentials
• Capacity markets in MISO
• New environmental regulations/
enforcement Baldwin Facility: 1,800 MW
7

8. West –
West – Primarily Natural Gas
Regional Performance Drivers $/MWh
$180
Cal‐ISO Dispatch Order
Price: • ~70% of Adjusted Gross Margin is
70% of Adjusted Gross Margin is 160
60 Dynegy Cal‐ISO facilities by unit
derived through tolling agreements in 140
Min. Load Avg. Load Peak Load
the near‐term 120
• Regional spark spreads 100
80
• Natural gas sets the marginal price of
Natural gas sets the marginal price of 3,179 MW
3 179 MW
706 MW
706 MW
60
power
40
Cost: • Tolling counterparties take financial and 20
delivery risk for fuel during tolled periods 0
Source: Energy Velocity as of 4/13/09
4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64
• Fuel is purchased as needed at index
Fuel is purchased as needed at index
Cumulative Capacity GW
related prices
Hydro Nuclear Coal Renewables Gas Oil
Watch: • Operational performance since the
majority of the plants operate under
j y p p
tolling contracts
• Weather can affect volumes of
uncontracted CCGT fleet
p y g y
• Spread variability mitigated by toll
contracts
• New environmental regulations/
enforcement Moss Landing Facility: 2,529 MW
8

9. Northeast –
Northeast – Diverse Fuel and Dispatch Type
Regional Performance Drivers $/MWh
$180
NY‐ISO Dispatch Order
Price: • New York Zone G power price for
p p 160
60 Dynegy NY‐ISO facilities by unit
Peak Load
Peak Load
Danskammer and New York Zone G 140
123 MW
Min. Load Avg. Load
spark spread for Roseton 120
1,185 MW
• Spark spreads for New York Zone C 100
for Independence and Mass Hub for 80
1,974 MW
1 974 MW
Casco Bay
C B 60
• Natural gas sets the marginal price of 40
power 20
Source: Energy Velocity as of 4/13/09
0
Cost: • 2010 delivered South American coal 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36
80% contracted/ priced at $3.55/MMBtu Cumulative Capacity GW
• Natural gas purchased as needed Hydro Nuclear Coal Renewables Gas Oil
• RGGI allowance cost at market rates
Watch: • Weather can affect volumes of
uncontracted CCGT fleet and Roseton
facility
• Coal delivery
• New environmental regulations/
enforcement Independence Facility: 1,064 MW
9

10. Why Invest in Dynegy?
Why Invest in Dynegy?
If you are
worried about… … consider Dynegy’s belief … and Dynegy’s advantages
• Dynegy is well positioned to capture demand growth in 3
• Longer‐term prices and spreads economic regions with a diverse portfolio of assets
Depressed power should increase as demand grows • Dynegy’s gas‐fired fleet becomes a larger contributor in a low
prices & spark and economic conditions improve natural gas prices environment
spreads • Supply/demand should tighten as
pp y g • Dynegy’s commercial strategy increases predictability of
Dynegy s commercial strategy increases predictability of
older assets are retired earnings and cash flow in near term, while maintaining
potential for upside as markets improve in the longer term
• Dynegy’s Midwest fleet burns 100% regionally‐driven Powder
• Eastern Coal prices are volatile due River Basin coal which is not exposed to global forces
Rising coal prices to global demand
g
• Dynegy’s coal and rail contracts continue to provide stability
• Dynegy remains committed to environmental investments
and has spent ~$550 MM of ~$960 MM program in Illinois
Impact of potential • Air, water and solid waste
• Current spending is anticipated to lessen impact of future
regulations are pending and could
environmental
environmental result in a significant impact to the
lt i i ifi t i t t th
regulations
g
regulations power industry • 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
g
• Prolonged decline in commodity y
prices and potential environmental • Dynegy has significantly reduced near term debt maturities
Liquidity regulations could result in lower and adequate liquidity to commercialize positions
earnings and increased costs
10

11. Dynegy Expects Demand to Rise Long‐Term
Dynegy Expects Demand to Rise Long‐
U.S. Electricity demand is projected to increase by ~2% in 2010 (1)
110,000
U.S. Electric Generation (GWh)
( )
• 2009 U.S. electric demand was down ~4%, but
100,000
remained within the 5 year average range
90,000
• 2010 may continue to be a challenging business
80,000
, environment with commodity prices
environment with commodity prices
70,000 remaining volatile
60,000 • Weather spikes, as seen this winter, continue to
2010 YTD 2009 5 Year Avg
50,000
represent opportunities to capture
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
incremental value
incremental value
• U.S. electricity demand is projected to increase
$70
Natural Gas & Power Prices $14
by 1.5% in 2011(1)
$60 $12 • Despite ongoing volatility, commodity prices
CIN Hub On‐Peak ($/MWh)
CIN Hub On‐Peak ($/MWh)
$50 $10 b i i t t d
are beginning to trend upward d
$40 $8
$30
Natural Gas ($/MMBtu)
$6
Dynegy believes commodities
$20 $4
will remain volatile and
will remain volatile and
$10
Source: Brokered market indicators
$2
demand will increase over time
$0 $0
2009 Bal 10 2011 2012 2013
Note: 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 11

12. Dynegy’s Commercial Strategy
Reflects Long Term Industry Fundamentals
Contracted Percentage of Expected Commercial Strategy
G
Generation Volumes (% of MWh, as of 1/26/10)
ti V l
100%
>95%
Near to intermediate term view:
>95%
•Dynegy is focused on capturing
75% ~85% gp y
extrinsic value, increasing predictability
of earnings and cash flow and also
protecting against downside risk
50% ~50%
Long term view:
25%
•Dynegy is relatively uncontracted in
~15% outer years to provide opportunities to
capture value in a fundamentally rising
~5%
0%
p
price environment as supply/demand
pp y
2010 2011 2012
tightens
Uncontracted Contracted Level as of 11/5/09
Maintaining long term market upside potential
M i t i i l t k t id t ti l
while protecting against downside risks
12

13. Midwest Coal Fleet is Competitively
Advantaged with Key Contracts
Coal Price Outlook 2008‐09 Coal Prices ($/MMBtu)
$6
$6
• South American and Central
S. American
Appalachian coal prices are volatile due
$5
to global demand and weather cycles
• Dynegy’s Midwest rail is contracted
$4
through 2013 with no fuel price
escalators Central App
$3
$3
• Dynegy’s Midwest coal fleet burns
100% Powder River Basin coal and coal
supply is 100% priced through 2010 $2
Baldwin PRB
$1 39 Delivered Price
$1.39 Delivered Price $1.49
$1 $0.81
Dynegy’s coal and rail contracts $0.62
continue to provide stability $0
$
Powder River Basin
1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10
(1)
Sources: Historical prompt month coal pricing from: PRB – Platts, CAPP – NYMEX; SA – Argus (1) 1Q10 represents 1/1/10– 3/8/10 13

14. Midwest Coal Fleet is Competitively
Advantaged with Environmental Upgrades
Environmental Spending Outlook $600
Significant Cash Investment ($MM)
• Consent Decree spending and $545
associated controls should lessen $500
impact of potential changes in air
regulations
$400
$400
• Remaining spend of ~$415 million for
a total investment of $960 million to
$300
upgrade pollution control equipment
to further reduce certain emissions
by ~90% $200 $185
$140
• Annual spending declines through
2013 and cash‐on‐hand of ~$746 $100 $75
million as of February 19 in excess of
o as o eb ua y 9 e cess o
$15
CapEx requirements $0
2005‐2009 2010 2011 2012 2013
Dynegy’s environmental investments demonstrate
Dynegy’s environmental investments demonstrate
ongoing commitment to meet regulatory standards
14

15. Dynegy’s Capital Structure
Complements Our Commercial Strategy
Debt Maturity Profile (As of 12/31/09, $MM) Non‐recourse Plum Point debt (2) Term LC facility (1) Other balance sheet debt
1,500
Total balance sheet debt = ~$5.6 B
T lb l h d b $5 6 B
1,250
$1,054 $1,112 $1,064
$1,003
1,000
$790
750
500
250 $166 $186
$148
$63 $4 $9
0
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
accounted for as current, but continues to be non‐recourse to Dynegy
–Dynegy’s maximum liability is $15 million (3)
Dynegy has significantly reduced near‐term debt maturities
y gy g y
and 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. 15

16. What Makes a Long‐Term Value Play?
What Makes a Long‐
Operate &
Operate & Prudent Strategic
Commercialize Financial
Management Positioning
Well
Ability to manage risk
Abilit t ik Continuing to pro‐actively
C ti i t ti l Simplified capital
Si lifi d it l
through geographic and manage capital structure structure provides
dispatch diversity to facilitate execution of strategic flexibility
commercial strategy
Continuing to maximize Simplified stock structure
cash flows by maintaining
cash flows by maintaining Maintaining simple,
Maintaining simple, in which all outstanding
in which all outstanding
a low‐cost, reliable flexible capital structure equity is publicly held
operating platform
No significant bond
Commercial strategy maturities until 2015
remaining open to
h t l l
harvest value as supply Driving down costs with
Driving down costs with
and demand tighten over multi‐year cost savings
the longer term program
Dynegy believes it is positioned to capture value
as markets improve over the longer term
16

17. Q & A

18. Appendix

19. Dynegy’s Diversified Asset Portfolio
Geographic Diversity Fuel Diversity Dispatch Diversity
Northeast Combined Cycle
Peaking Baseload
Midwest 26% 36%
35% 30%
44% Peaking
P ki Fuel Oil
21% 14%
Total Gas‐fired
Coal
West 57%
29% Intermediate
30%
35%
12,434 MW
Note: Plum Point is currently under construction. 19

20. 2010 Guidance Range
2010 Guidance 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
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. 20

21. Adjusted 2010 EBITDA Sensitivities
Adjusted 2010 EBITDA Sensitivities
Anticipated Range for
2010 Adjusted EBITDA ($MM))
j ($
$600 •Expected range of Adjusted EBITDA
for 2010 continues to be sensitive to
$550 MM several factors
$550
•The horizontal X‐axis represents possible
p p
changes in natural gas prices
$500 – As percentage of expected generation
contracted goes up, sensitivity decreases
•The vertical Y‐axis represents the possible
p p
$450 impacts of various other factors:
– Volatility of commodity prices
$425 MM
$400 – Basis differentials
– Capacity prices
Capacity prices
$5.72 Gas
– Unplanned outages
Nat. Gas 12‐Mo Avg
($/MMBtu) $5.00 Gas $6.00 Gas $7.00 Gas •Often events and variables are
interrelated and individual sensitivities
CIN Hub On‐Peak
CIN Hub On Peak
$35.00 $42.00 $49.00 are not always additive
are not always additive
($/MWh)
Note: 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. 21

22. As presented November 5, 2009
2010 Commodity Pricing Assumptions
2010 Commodity Pricing Assumptions
2010E*
Natural Gas – Henry Hub
Natural Gas Henry Hub ($/MMBtu) $ 6.15
$ 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 $3.55 Danskammer
Fuel Oil #6 delivered to Northeast ($/MMBtu) $10.97 Roseton
* Represents annual average based on 10/6/09 pricing. 22

23. As presented November 5, 2009
Tax and Other Assumptions
Tax and Other Assumptions
Tax Assumptions Other Assumptions
– Tax expense accrues at ~40%; expect to – Commodity pricing assumes
pay state cash tax payments of ~$2 million $6.15/MMBtu natural gas
– Dynegy not expected to become a – ~$50 million annual amortization
significant cash tax payer until well into
significant cash tax payer until well into expense included in Northeast Adjusted
expense included in Northeast Adjusted
the future EBITDA through 2014 related to ConEd
contract; annual capacity payment
received of ~$100 million
– Shares outstanding ~595 MM
23

24. As presented November 5, 2009
Natural Gas Sensitivity
Primarily Impacts Baseload Coal
Adjusted EBITDA Sensitivity ($MM)
Change in Cost of Natural Gas
($/MMBtu) 2010 >95% Contracted Longer Term Uncontracted
+ $2.00
+ $2 00 $ 30
$ 30 $ 340
$ 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
Off‐peak prices are adjusted holding the market implied heat rate constant
k i dj t d h ldi th k t i li d h t t t t
Note: Uncontracted portfolio for longer term assumed for illustrative purposes only. 24

25. As presented November 5, 2009
Market Implied Heat Rate
Sensitivities Impact Entire Fleet
2010 with >95% Contracted Longer‐Term: Uncontracted
Market Implied Generation Adjusted EBITDA Sensitivity Market Implied Generation Adjusted EBITDA Sensitivity
Heat Rate ($MM) Heat Rate ($MM)
Movement Movement
(Btu/KWh) Coal/Fuel Oil Natural Gas TOTAL (Btu/KWh) Coal/Fuel Oil Natural Gas TOTAL
+ 1,000 $‐ $20 $20 + 1,000 $15 $120 $135
+ 500 $‐ $10 $10 + 500 $5 $60 $65
‐ 500 $‐
$ $(5)
$( ) $(5)
$( ) ‐ 500 $(5)
$( ) $(55)
$( ) $(60)
$( )
•Sensitivities based on “on‐peak” power price changes and full‐year estimates
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
Note: Spark spread value changes depend on natural gas price assumptions. Uncontracted portfolio for longer term assumed for illustrative purposes only. 25

26. As presented November 5, 2009
Basis Sensitivities
• 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
• Northeast
– 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
2010 Plan assumes Casco Bay volumes of ~2 MM MWh
C B l f 2 MM MWh
– +/‐ $1.00/MWh change in basis = +/‐ $2 million impact to Adjusted
EBITDA on a full year basis
26

27. As presented November 5, 2009
Midwest Capacity Price Sensitivities
• 2010 Guidance assumes:
– As of 10/6/09, the weighted average unsold MISO capacity of 2,066 MW
g p yp $ / ( g / / p g)
– Average capacity price of $0.58/KW‐Mo (using 10/6/09 pricing)
– Current value of unsold MISO capacity in 2010 Plan = ~$14 million
– Ch
Change in price and volumes can alter capacity revenue
i i d l l i
27

28. As presented February 25, 2010
Anticipated Capital Expenditures (2010 – 2013)
(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
Capitalized 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
• Maintenance for “Gas and other facilities” is largely a function of run‐time and also includes
expenditures for Roseton
28

29. As presented February 25, 2010
Significant Environmental Progress
On target to further reduce emissions in the Midwest
2007 2008 2009 2010 2011 2012
Vermilion
Hennepin
Havana
Baldwin 3
Baldwin 1
Cash outflow
continues
Baldwin 2 Projects complete through 2013
Major Assumptions Go Forward
• Estimate of remaining spend is ~$415 million for a total
Cost Composition
investment of $960 million
investment of $960 million
• Approximately 25% of remaining costs are firm
Labor Materials
• Labor and material prices are assumed to escalate 4% 56% 32%
annually
• All projects include installing baghouses and scrubbers
with the exception of Hennepin and Vermilion, which Rental Equipment
have baghouses only & Other 12%
29

30. Commodity Prices
2008 Actual 2009 Actual 2010 Actual/Forward as of 1/26/10(1)
CIN Hub/Cinergy ($/MWh) New York Zone G ($/MWh)
$160
$160 $160
$160
$140 2008A: $ 66.84 $140 2008A: $ 100.86
2009A: $ 34.67 2009A: $ 49.83
$120 $120 2010A/F (Jan): $ 64.97
2010A/F (Jan): $ 43.54
$100 $100
$80 $80
$60
$ $60
$40 $40
$20 $20
$0 $0
J F M A M J J A S O N D J F M A M J J A S O N D
Palo Verde ($/MWh) Natural Gas ($/MMBtu)
$160 $16
2008A: $ 71.82 $14 2008A: $ 8.85
$140
2009A: $ 34.73 2009A: $ 3.92
$120 / ( )
2010A/F (Jan): $
$ 51.71 $12 2010A/F (Jan): $ 5.72
$100 $10
$80 $8
$60 $6
$40 $4
$
$20 $2
$0 $0
J F M A M J J A S O N D J F M A M J J A S O N D
(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. 30

31. Spark Spreads
2008 Actual 2009 Actual 2010 Actual/Forward as of 1/26/10(1)
$50
$50 PJM West ($/MWh) $50
$50
Mass Hub ($/MWh)
2008A: $ 14.86 2008A: $ 20.54
$40 $40 2009A: $ 12.10
2009A: $ 12.19
2010A/F(Jan): $ 11.67 2010A/F(Jan): $ 14.14
$30 $30
$20 $20
$10 $10
$0 $0
($10) ($10)
J F M A M J J A S O N D J F M A M J J A S O N D
Palo Verde ($/MWh) NP‐15 ($/MWh)
$50 $50
2008A: $ 13.24 2008A: $ 17.84
$40 2009A: $ 7.23 $40
2009A: $ 8.28
2010A/F(Jan): $
/ ( ) $ 8.14 2010A/F(Jan): $ 11.99
2010A/F(Jan): $ 11.99
$30
$30 $30
$30
$20 $20
$10 $10
$0 $0
($10) ($10)
J F M A M J J A S O N D J F M A M J J A S O N D
(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. 31

32. As presented February 25, 2010
Collateral
($MM) 12/31/2008 12/31/2009 2/19/2010
Generation $ 1,064
$ 1,064 $ 638
$ 638 $ 515
$ 515
Other 189 189 189
Total $ 1,253 $ 827 $ 704
Cash $ 118 $ 291 $ 204
LCs 1,135 536 500
Total $ 1,253
$ 1 253 $ 827
$ 827 $704
$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
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
32

33. Central Hudson Lease – Northeast Segment
Central Hudson Lease –
Imputed Debt Equivalent at PV (10%) of
future lease payments = $626 MM(1)
Central Hudson Cash Payments (remaining as of 12/31/09, $MM)
200
Imputed Interest
I dI
175
$179
Imputed Debt Equivalent
150 $48 $142 $143 $143
$16
125 $37 $28
$112
100 $95
$56 $77
75
$60 Accrual Lease Expense
50 $42
$27
25 $5
$35 $56 $131 $105 $115 $127 $22 $35
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 Lease Central Hudson treated as Debt
(as currently shown in GAAP financials): (would require the following adjustments to GAAP financials):
• Income Statement – $50 million lease expense included in •Income Statement – Add back $50 million lease expense to Adjusted EBITDA; add $60
Adjusted EBITDA; no interest expense or depreciation & million imputed interest expense to Interest Expense; add $23 million estimated
amortization expense depreciation & amortization expense; adjust tax expense for net difference
• Cash Flow Statement – $
$95 million cash payment included in • Depreciation & Amortization calculated using purchase price of $920 million divided by 40 years
$
Operating Cash Flows •Cash Flow Statement – Add back $35 million of imputed principal to Operating Cash Flows
• Balance Sheet – lease obligation not included in debt balance • $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
(1) PV of payments calculated as of 12/31/09 33

34. As presented February 25, 2010
Dynegy’s Financial Position
2,400
Liquidity Profile ($MM)
1,500
Debt Maturity Profile (As of 12/31/09, $MM)
$2,253
Total balance sheet debt = ~$5.6 B
2,000 $1,942 1,250
$1,840 $1,112
$1,054 $1,064
1,600 1,000 $1,003
$1,507
$1,147 $790
1,200 $1,471 750
800 500
400 $166
$693 $746 250
$148
$186
$471 $63 $4 $9
0 0
Dec 31 2008
Dec 31 2008 Dec 31 2009
Dec 31 2009 Feb 19 2010
Feb 19 2010 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
Availability Cash
• Decrease in cash from FY08 to FY09 due to • Undrawn $1.08 billion revolver due 2012
FY09 operating activities • $850 million letter of credit facility due 2013
• Increased availability as a result of decreased • Includes $744 million associated with Plum Point
collateral requirements due to lower construction
commodity prices – This debt has been reclassified to current, but
continues to be non‐recourse to Dynegy (2)
• Increase in cash from year‐end 2009 due to
– Dynegy’s maximum liability associated with Plum Point
cash inflow from collateral clearing broker due is a $15 million letter of credit to cover construction
is a $15 million letter of credit to cover construction
to lower commodities overruns and defaults, should they occur
(1) Term Letter of Credit facility is supported by $850 million of restricted cash. (2) Dynegy is a minority • Excludes $626 million related to Central Hudson
shareholder in Plum Point Energy Associates, LLC (PPEA). Total debt for PPEA of ~$744 million has been lease, which is off‐balance sheet
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.
34

35. As presented February 25, 2010
Capital Structure
Capital Structure
Dynegy Inc. TOTALS ($ Million) 12/31/09
Debt & Other Obligations as of 12/31/09
Secured $918
Dynegy Holdings Inc.
Dynegy Holdings Inc.
Secured Non‐Recourse $1,031
$1,080 Million Revolver(1) $0
Term L/C Facility $850 Unsecured $3,650
Tranche B Term $68
Lease Obligation $626
Sr. Unsec. Notes/Debentures $3,450
Sub.Cap.Inc.Sec (“SKIS”) $200
Sithe Energies Dynegy Power Corp. Plum Point Energy Assoc.
Senior Debentures $287 Central Hudson(2) $626 PP 1st Lien $644
Tax Exempt 100
Gross Debt $744
Less: Restricted Cash (19)
Total, Net Debt $725
($ Million) 12/31/09 12/31/08
Total Obligations $6,225 $6,825
Less: Cash on hand & Investments 471 693
(3) (3)
Less: Restricted cash
Less: Restricted cash 869 1,154
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
Represents drawn amounts under the revolver; actual amount of revolver was $1.08 Billion as of
Net Debt & Other Obligations $4,885 $4,978 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
Less: Central Hudson Lease Obligation 626 700 (“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
Net Debt $4,259 $4,278 related to Plum Point in 12/31/09 and ~$29MM related to Plum Point in 12/31/08.
35

36. Collar Option Example
Call Option: Combining Put & Call Options creates a
Dynegy sells a 100 MW on‐peak call option for the 2011 “Collar” Option
calendar year at a $65 strike price at a premium of $0.85/MWh • Collars provide earnings certainty and reduce exposure to
• Dynegy receives and realizes a premium payment in current power price volatility
period from buyer for the call option (See Calculation 1) - If market price clears at $70, buyer will strike call option. Maximum
• Option gives buyer right to buy 100 MW on‐peak from Dynegy revenue on 100 MW will be $27MM versus $29MM had power been
sold at market price (See Calculations 3 & 4)
for 2011 calendar year at $65 if buyer strikes the option on the
option expiration date - If market price clears at $30, Dynegy will strike put option. Maximum
revenue on 100 MW will be $14MM versus $12MM had power been
• Buyer will strike option if 2011 calendar prices exceed $65 in
y p p $ sold at market price (See Calculations 5 & 6)
sold at market price (See Calculations 5 & 6)
order to sell the 100 MW at a higher price
• Option impact on Financial Statements:
• Commitment sets a potential price on the sale of the 100 MW - Premium revenue and expenses are realized in period options were
for Dynegy at $65 which is realized during option period if sold/purchased
buyer strikes option
- Record liability or asset based on buy or sell of option in future
• If prices are below $65 on the option expiration date, option option period
expires without exercise
p - Exercised option value realized during the option period
Exercised option value realized during the option period
Put Option: Calculations
Dynegy buys a 100 MW on‐peak put option for the 2011 Premium Calculations:
calendar year at a $35 strike price at a premium of $0.45/MWh
• Dynegy pays and realizes a premium expense in current period 1) 4,080 on‐peak hours/year x $0.85/MWh x 100 MW = $346,800
to seller for the put option (See Calculation 2) 2) 4,080 on‐peak hours/year x $0.45/MWh x 100 MW = $183,600
• Option gives Dynegy right to sell 100 MW to seller for 2011
calendar year at $35 if Dynegy strikes the option on the option Sales Calculations:
expiration date
3) 4,080 on‐peak hours/year x $65/MWh x 100 MW = ~$27 MM
• Dynegy will strike option if 2011 calendar prices go below $35
in order to sell the 100 MW at a higher price 4) 4,080 on‐peak hours/year x $70/MWh x 100 MW = ~$29 MM
• 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 5) 4,080 on‐peak hours/year x $35/MWh x 100 MW = ~$14 MM
• If prices are above $35 on the option expiration date, option
expires without exercise 6) 4,080 on‐peak hours/year x $30/MWh x 100 MW = ~$12 MM
36

37. As presented February 25, 2010
Contracted Generation Volumes –
Contracted Generation Volumes – 2011 & 2012
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
Nov 09 Jan 10 Feb 10
Feb 10
Midwest 1% 1% 1%
West 15% 50% 50%
Northeast
N h 10% 10% 15%
Consolidated 5% 15% 15%
37

38. Financial Covenant Ratios
Covenant ratios are requirements of the DHI Credit Agreement covenants and are calculated based
C t ti i t f th DHI C dit A t t d l l t db d
on trailing four quarters
38

39. Dynegy Generation Facilities (as of 1/30/10)
Region/Facility(1) Location Net Capacity(2) Primary Fuel Dispatch Type NERC Region
NOTES:
MIDWEST
1) Dynegy owns 100% of each unit
) y gy
Baldwin Baldwin, IL
Baldwin IL 1,800
1 800 Coal Baseload MISO listed except as otherwise
Havana Havana, IL indicated. For each unit in which
Dynegy owns less than a 100%
Units 1‐5 228 Oil Peaking MISO interest, the Total Net Capacity set
Unit 6 441 Coal Baseload MISO forth in this table includes only
Dynegy’s proportionate share of
Hennepin Hennepin, IL 293 Coal Baseload MISO such unit’s gross generating
Oglesby Oglesby, IL 63 Gas Peaking MISO capacity.
Stallings
g Stallings, IL
g, 89 Gas Peakingg MISO 2) Unit capabilities are based on
Unit capabilities are based on
Vermilion Oakwood, IL winter capacity.
Units 1‐2 164 Coal/Gas Baseload MISO 3) Under construction. Represents net
Unit 3 12 Oil Peaking MISO ownership of 21%.
Wood River Alton, IL 4) Dynegy entered into a $920 MM
sale‐leaseback transaction for the
Units 4‐5 446 Coal Baseload MISO Roseton facility and units 3 and 4 of
Kendall Minooka, IL 1,200 Gas ‐ CCGT Intermediate PJM the Danskammer facility in 2001.
Cash lease payments extend until
Cash lease payments extend until
Ontelaunee
O l Ontelaunee Township, PA
O l T hi PA 580 Gas ‐ CCGT
G Intermediate
I di PJM 2029 and include $108 MM in 2007,
Plum Point (3) Osceola, AR 140 Coal Baseload SERC $144 MM in 2008, $141 MM in
2009, $95 MM in 2010 and $112
Midwest TOTAL 5,456 MM in 2011. GAAP lease payments
are $50.5 MM through 2030 and
NORTHEAST decrease until last GAAP lease
payment in 2035.
Independence Scriba, NY 1,064 Gas ‐ CCGT Intermediate NYISO
5) Represents operating capacity of
Roseton (4) Newburgh, NY
Newburgh, NY 1,185 Gas/Oil Intermediate NYISO Units 3 & 4. Units 1 & 2, with a
Units 3 & 4 Units 1 & 2 with a
Casco Bay Veazie, ME 540 Gas ‐ CCGT Intermediate ISO‐NE combined net generating capacity
of 352 MW, are currently in layup
Danskammer Newburgh, NY status and out of operation.
Units 1‐2 123 Gas/Oil Peaking NYISO
6) Represents operating capacity of
Units 3‐4 (4) 370 Coal/Gas Baseload NYISO Units 1 & 2 and CT. Units 3 & 4, with
Northeast TOTAL 3,282 a combined net generating capacity
of 397 MW, did not receive RMR
status from CAISO for 2010 and are
WEST currently out of operation and in
the process of being
Moss Landing Monterey County, CA decommissioned.
Units 1‐2 1,020 Gas ‐ CCGT Intermediate CAISO 7) Dynegy owns a 50% interest in this
Units 6‐7 1,509 Gas Peaking CAISO facility and the remaining 50%
Morro Bay (5) Morro Bay, CA 650 Gas Peaking CAISO interest is held by Chevron.
South Bay (6) Chula Vista, CA 309 Gas Peaking CAISO
Oakland Oakland, CA
Oakland CA 165 Oil Peaking CAISO
Black Mountain (7) Las Vegas, NV 43 Gas Baseload WECC
West TOTAL 3,696
TOTAL GENERATION 12,434
39

40. Appendix –
Appendix – Reg G Reconciliations

41. Debt 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 j
reducing 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

42. Reg G Reconciliation – 2010 Guidance
DYNEGY INC.
2010 EARNINGS ESTIMATES (1)
( )
(IN MILLIONS)
Power Generation
GEN ‐ MW GEN ‐ WE GEN ‐ NE Total GEN OTHER Total
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
2010 CASH FLOW ESTIMATES (1) (3)
(IN MILLIONS)
GEN OTHER Total
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)
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) 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.
(2) 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 below.
segment level is also presented below
Continued on next page
42

43. Reg G Reconciliation – 2010 Guidance (cont.)
Power Generation
P G i
GEN ‐ MW GEN ‐ WE GEN ‐ NE Total GEN OTHER Total
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
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
Power Generation
GEN ‐ MW GEN ‐ WE GEN ‐ NE Total GEN OTHER Total
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
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
Total
Net loss attributable to Dynegy Inc. $ (215) $ (140)
Add Back:
Income Tax Benefit (140) (90)
Interest Expense 375 375
Depreciation and Amortization Expense
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) This presentation is not intended to be a reconciliation of non‐GAAP measures pursuant to Regulation G.
(4) 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
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
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 Free Cash Flow $ 165 $ 290 $ (525) $ (525) $ (360) $ (235)
43