Jason Cox, Dynegy, Inc. - Speaker at the marcus evans Generation Summit 2012, held in San Antonio, TX, delivered his presentation entitled Enigma, Paradox or Conundrum? The Asset Manager’s Challenge to Do More with Le$$

1. Enigma, Paradox, or Conundrum?
The Asset Manager’s Challenge to Do
More With Le$$
$$
St t i A t M tF P Pl t
Strategic Asset Management For Power Plants J 24 2012
January 24, 2012
Jason W. Cox

2. Outline
• Maintaining large assets while working within tightening
budget constraints
budget constraints
– Capex
– Opex
– Limited staff
– Environmental costs
• How maximize the value of your assets across multiple markets
y p
– Key metrics
– Pitfalls to avoid
• Know when to fold ‘em
Know when to fold em
– Trading strategies
– Plant retirements
2

3. DYNEGY FACTS ‐
DYNEGY FACTS ‐ 2002
• Established in 1984
• # 30 on Fortune 500 list (2001)
# 30 F t 500 li t (2001)
• “DYN” ticker symbol; traded on NYSE
• Member of S&P 500
• 6,700+ employees
6 700+ l
• $33 Billion Revenues
• $23 Billion Assets
• 19,100 MW Generation Control
19 100 MW Generation Control
• 213 MM MWh Total Power Sales
• 12.5 Bcf/d Natural Gas Sales
• 562 MBbls/d Liquids Sales
562 MBbls/d Liquids Sales
• 30 MM Tons Coal Sales

4. DYNEGY HISTORY & MILESTONES
NNG Pipeline
BGSL Storage
C. Hudson Assets
Extant
Illinova
SDG&E Assets
Edison Assets
45% CAGR
Destec
Warren (Chevron)
IPO / Trident
1995 1996 1997 1998 1999 2000 2001 2002

5. TOTAL ENERGY DELIVERY NETWORK ‐ 2002
TOTAL ENERGY DELIVERY NETWORK ‐
Power Generation 18,800 MW
Natural Gas Term Supply 5 Bcf/d
Power Firm Transmission 5,050 MW
Natural Gas Firm Transport 6 Bcf/d
Natural Gas Storage 112 Bcf Liquids Supply & Assets:
Natural Gas Processing 97 MBbls/d
Fuel Oil Storage 5 MMBbls
Fractionation 224 MBbls/ d
Coal Supply 12.3 MMT/yr Storage 1091 MMBbls
Coal Transportation 17 MMT/yr LNG 750 MMcf/d
NNG Pipeline Miles 16,000

6. Latin American Plants in Operation ‐ 2002
Latin American Plants in Operation ‐
El Cosa
Dr Bird
PESA
Panama

7. Asian Plants in Operation ‐ 2002
Asian Plants in Operation ‐
Zhejiang
Uch
Zhuzhou

8. DYNEGY ENERGY NETWORK: Europe 2002
Nord Pool
UK
London Holland
Dynegy office Lausanne
Continental Milan
Europe

9. Commercial Asset Management ‐ 2002
Commercial Asset Management ‐
Focus on Portfolio Management Strategy
Coordinate Fuel Management Services
Integrate Power Product Pricing & Sales
Evaluate L-T Development & Expansions
Optimize Generation Portfolio
Fuels Power
Management Product Sales
Fuel Supply Wholesale Markets
Fuel Transportation Retail Markets
Fuel Resale
Risk Management GENERATION Ancillary Services
Risk Management
ASSETS
Development Optimize
Build Gen. Development
Acquire Energy Trading
Lease Mktg. & Orig.
g g
Control Equity & Alliances
9

10. DYN Stock History
Enigma [ɪ'nɪgmə]
n
A person, thing, or situation that is mysterious, puzzling, or ambiguous
10

11. Dynegy Portfolio:
Post LS Power – December 2009
Post LS Power –
Geographic Diversity Fuel Diversity Dispatch Diversity
Northeast Combined Cycle
Peaking Baseload
Midwest 25% 34%
37% 29%
43%
3% Simple Cycle Fuel Oil
Fuel Oil
25% 10%
Total Gas‐fired
Coal
West 59%
31% Intermediate
32%
34%
12,950 MW
Note: Plum Point is currently under construction. 11

12. Blackstone Buyout Headlines
• Dynegy Inc. Agrees to Be Acquired by Blackstone (8/16/2010)
Dynegy Inc. Agrees to Be Acquired by Blackstone (8/16/2010)
• Dynegy in danger, Investor revolt stirs over Blackstone's $4.7B
deal (10/7/2010)
• Dynegy and Blackstone Agree on Increased Merger
Consideration (11/17/2010)
• Dynegy, Blackstone End Merger Agreement (11/23/2010)
12

13. Icahn Buyout Headlines
• Icahn Beats Blackstone Bid ‐ Dynegy Approves Acquisition
(12/15/2010)
• Dynegy Deal Fight! Seneca Turns on Carl Icahn (12/20/2010)
• Some Dynegy investors still fighting Icahn deal (2/12/2011)
• Dynegy‐Icahn deal fails, management to exit (2/21/2011)
13

14. Current Structure of Operating Entities (as of 11/8/11)
(as of 11/8/11)
Entities in Chapter 11 Entities not included in DH Chapter 11 filing(1)
Dynegy Inc. (DI)
Bankruptcy Remote Entity
Entity included in
Chapter 11 filing
Dynegy
Holdings, LLC
(DH)
Dynegy Gas
Investments, LLC
,
(DGI)
Dynegy Coal
Dynegy Northeast
Generation, Inc. (DNE) HoldCo, LLC
(Coal HoldCo)
Dynegy
Administrative Dynegy Gas
Hudson Power, L.L.C. Services Co. ld
HoldCo, LLC
(Gas HoldCo)
Dynegy
Midwest
Dynegy Danskammer, L.L.C.
Generation,
Dynegy
Dynegy LLC (CoalCo)
Dynegy Roseton, L.L.C. Power, LLC
(GasCo)
Public equity issued by Dynegy Inc.
Net Debt of $176 million as of 11/8/2011, excluding entities in Chapter 11
Substantially all Adjusted EBITDA and Cash Flow from Operations is generated from non‐filed
entities
(1) There are other Dynegy entities not depicted that are also not included in the filing
14

15. Dynegy Fleet – January 2012
Dynegy Fleet –
15

16. Dynegy Regional Diversity –
Dynegy Regional Diversity – 2012
16

17. Asset Management Structure
Executive Management Team (EMT)
Broad Commercial Strategy
Employ Fle ible
Emplo a Flexible Commercial Strategy to Maintain Long Term Market Upside Potential
Strateg Long-Term
While Protecting Against Downside Risks
EMT Sub-delegation
Operations Commercial
• Safe and efficient
Trading
operation of plants • Help develop and
execute strategy
• Prepare and manage
annual budget process Asset Manager • Optimize assets
within confines of
ithi fi f
• Metrics to evaluate the sub-delegation
deployment of Sub-delegation
discretionary capital - Tenor
- VaR
Risk Control

18. Vision
• Let departmental experts be experts
– Operators focus on Operations, Commercial focus on commercialization
– Asset Managers set strategy to drive process
– Set the guard rail boundaries so that functional experts can drive fast in the left
lane or slow in the right lane but stay within boundaries
– L k
Look at volatility around dollars spent and focus time accordingly
l ili d d ll df i di l
• Be a facilitator
– Ask the hard questions
– Turn over the rocks
– Cooperation not Competition

19. How do we do it?
How do we do it?
• Study the Past
– Discover why Actual results vary from Forecasted results
– Drill down to 3 main goals to achieve
Drill down to 3 main goals to achieve
– Goals are set, known, and achievable
• Asset Management sets rails
– C
Commercial Ops
i lO
XXXX MW’s up to 18 months
– Origination
XXXX MW s up to 5 years
XXXX MW’s up to 5 years
– Open
XXXX MW’s exposed to commodity pricing
– O&M
Justification process for projects
Eyes and ears for remote locations (plants & regional offices)
Clear the way for operators to be operators
Involved in budgeting process

20. Natural Gas and Power Hub Prices
Natural Gas and Power Hub Prices
320
270
220
PJMWH
170
NP15
120
70
20
1/1/2007 1/1/2008 1/1/2009 1/1/2010 1/1/2011 1/1/2012
Henry Hub Historical Cash Price
14
12
10
$/mmbtu
8
6
4
2
0
20

21. Maintaining assets within budget constraints
IMA ‐ Coal Plants
96%
95% Dynegy Capex & Opex
arket Availability
94%
93% 650
IMA‐MW
92% 600
IMA‐NE
In‐Ma
91%
550
90%
500
89%
ons of $
2007 2008 2009 2010 2011 450
Millio Capex
400
Capacity Factor ‐ Combined Opex
350
Cycle
300
70%
60% 250
50% 200
Axis Title
40% Cap Fact ‐ MW 2007 2008 2009 2010 2011
30% Cap Fact ‐ NE Year
20% Cap Fact ‐ WE
10%
0%
2008 2009 2010 2011
21

22. Producing Results through Innovation
PRIDE: by Dynegy Employees
1. Fixed Cash Cost Reduction 2. Gross Margin Improvement 3. Balance Sheet Efficiency
2011 recurring G&A and OpEx $49MM 2012 PRIDE targets adjusted upward PRIDE initiatives will free up
lower than 2010; Additional savings of to include $25 million in gross margin $453 MM of liquidity during
$36MM expected in 2012 improvements 2011‐2012
$25
$600 $25
$537 (1,3) $500 $453
$488(2,3) $452(3)
$137 $20
$106 $400 $133
$400
$15 $18
$300
$200 $400 $450 $10
$382 $200
$320
$5 $100
$0 $7
2010 Actual 2011 Forecast 2012 Target $0 $0
11/10/11 2011 Target 2012 Target 2011 Target 2012 Target
OpEx
O E G&A GMI Cash
• Rationalized insurance coverage • Increasing unit capacity or dispatch • Freeing up cash collateral in 2011 and
• Discontinued non‐essential contract • Driving heat rate improvements through 2012 by increasing usage of first lien
services internal benchmarking agreements
• Reduced chemical costs • Developing program of actions and targets • Lowering non‐fuel inventory
• Trimmed vehicle fleet by one‐third for IMA improvement • Driving down procurement process costs
• Reduced staffing • Reducing station power at various facilities and improving days payable outstanding
• Streamlined IT vendor spend • Salvaging non‐operating assets
• Restructured leases
• Leveraging cross‐fleet spend to reduce
prices on materials and services
prices on materials and services
PRIDE ‐ Driving EBITDA improvements and adding liquidity
(1) Excludes non‐recurring G&A expense of $26 million for proposed transaction costs (2) Excludes non‐recurring G&A expense of $19 million for proposed transaction costs and executive separation agreement expense (3) Excludes non‐recurring OpEx of $50 million associated
with the Roseton and Danskammer leases. The status of the leases and related obligations are subject to future determination.
22

23. Challenges to doing more with less
• Limited staffing
– Multiple rounds of reductions since 2002 (from 6,700 employees)
– Approximately 1,500 Employees total (as of March 3, 2011)
334 in Houston
1,185 at plants sites or regional office
748 employees under collective bargaining agreements
• Environmental costs
– CSAPR
– MACT / HAP
– Consent Decree
– Once‐Through Cooling (Federal and State programs)
Once Through Cooling (Federal and State programs)
– Coal Ash Regulation
– GHG NSPS (expected NOPR in 2012)
– Reporting requirements
23

24. Coal Segment
Environmental Compliance Plan
Coal Segment CSAPR SO2 Allocations 2012/2014 (tons) Regulation Highlights
60,000 Cross State Air Pollution Rule (CSAPR)
− Expect lower emissions as environmental equipment on Baldwin units becomes
50,000
operational
− NOx allocations sufficient
40,000
45,460 49,016 Hazardous Air Pollutant (HAPs)/ Maximum Achievable Control Technology (MACT)
30,000 − Most units meet proposed limits, rule has not been finalized
20,000
29,000 26,256 − Wood River 4 testing alternatives for Particulate Matter and Mercury
compliance
10,000 − Wood River 5 testing alternatives for Mercury compliance
Coal Combustion Residuals (CCR)
0 − Fi l l
Final rule not anticipated until 2013
t ti i t d til 2013
2010 Actual Emissions 2012 Allowances − Impact to Coal segment is predicated upon final rule; capital expenditures are
0
2013 Consent Decree SO Cap 2014 Allowances expected but still under review
2
EPA Proposed Clean Water Act Regulations(316(b))
− Compliance period between 2015‐2020
− No significant capital expenditures anticipated
Plant Environmental Plan by Regulation
Pl E i l Pl b R l i
CSAPR HAPs/MACT CCR 316(b)
Anticipate effective January 1, 2012 Anticipate effective January 1, 2015 Anticipate final rule ‐ 2013 Anticipate final rule ‐ 2012
Baldwin 1 Allowances exceed emissions Meets proposed limits Ash pond Minor modifications expected
Baldwin 2 Allowances exceed emissions Meets proposed limits Ash pond Minor modifications expected
Baldwin 3 Allowances exceed emissions Meets proposed limits Ash pond Minor modifications expected
Havana 6 Allowances exceed emissions Meets proposed limits Ash pond Minor modifications expected
Hennepin 1‐2 Covered by fleet allowances Meets proposed limits Landfill under construction Modifications expected
Testing w/alternative sorbents to meet
Wood River 4‐5 Covered by fleet allowances proposed limits Ash pond Modifications expected
Coal segment expected to benefit from emission control investments
24

25. Gas Segment
Environmental Compliance Plan
Plant Environmental Plan by Regulation
CSAPR 316(b) NY NOx RACT Rule CA Water Intake Policy AB32
Effective January 1, 2012 Anticipate final rule ‐ 2012 Effective July 1, 2014 Effective 2013
Facility has closed cycle cooling, but
Casco Bay N/A minor modifications may be required N/A N/A N/A
Facility has SCR equipment, should
Independence Sufficient allowances 2012 & 2014 N/A – Uses public water supply meet requirements N/A N/A
Facility has cooling towers, but minor
Kendall Sufficient allowances 2012 & 2014 modifications may be required N/A N/A N/A
Ontelaunee Sufficient allowances 2012 & 2014 N/A – Uses public water supply N/A N/A N/A
Compliance by 12/31/15;
CA Water Intake Policy expected to be
CA W t I t k P li t dt b Reviewing alternative
R i i lt ti
Morro Bay N/A more stringent N/A technologies N/A
Compliance by 12/31/17; Moss Landing 1&2 will need to
CA Water Intake Policy expected to be Reviewing alternative procure California Carbon
Moss Landing N/A more stringent N/A technologies Allowances (CCA)
Regulation Highlights
Regulation Highlights
CSAPR CA Water Intake Policy
− SO2 and NOx allocations should exceed projected − Exploring alternative control measures at Moss Landing and
emissions unless increase in plant capacity factors Morro Bay that are commercially viable and capable of
316(b) achieving compliance
− Compliance period anticipated to begin between 2015‐ CA Global Warming Solutions Act (AB32)
2020 − Morro Bay and Moss Landing 6 & 7 are not impacted; tolled
Morro Bay and Moss Landing 6 & 7 are not impacted; tolled
− For CA units, major modifications may be required, units pass through carbon credit costs to tolling
however, still under review counterparty
NY NOx Reasonably Available Control Technology (RACT) Rule − The CCA market is currently an illiquid market, therefore,
− Independence only facility impacted, should meet costs to Moss Landing 1&2 still under review
requirements
Gas segment well positioned to comply with environmental regulations
25

26. Commercial Strategy – Past to Present
Commercial Strategy –
Value of options as a hedging tool is currently reduced: 2010 Forward Pricing for
2011 Natural Gas Price and Volatility
$7 60%
Volatility V
− A component to determine premium prices for options O
$6 50% L
− Greater volatility, higher premium prices P
− Greater range in price of underlying commodity (e.g. natural A
R
T
gas), greater the volatility I $5 40%
I
C
L
E
Forward hedging opportunities with options in 2010 were more $4
Range: ~30-37%
30% I
robust T
Y
− 2011 Natural Gas prices dropped ~$2.00/MMBtu $3 20%
− Volatilities ranged from 30‐37% Jan Feb Mar Apr May Jun Aug Sep
− Higher premiums made options more attractive as a hedging Cal '11 HH ‐ $/MMBtu Vol ‐ Cal11
tool
2011 Forward Pricing for
g
Forward hedging opportunities with options in 2011 not as
Forward hedging opportunities with options in 2011 not as
2012 Natural Gas Price and Volatility
compelling $7 60%
− 2012 Natural Gas prices dropped ~$0.75/MMBtu V
O
− Volatilities ranged from ~25‐28% $6 50%
P L
− Lower premiums made options less attractive as a hedging tool A
R
I $5 40% T
Adjusting commercial strategy to changing market dynamics C I
− Spark spreads expanding in eastern regions potentially creates E L
$4 30% I
a valuable hedge opportunity
Range: ~25-28% T
− Maintain current hedge portfolio in anticipation of market
$3 20% Y
improvement
Jan Feb Mar Apr May Jun Aug Sep
− Future hedging activity will continue usage of standard hedging
C l '12 HH $/MMBt
Cal '12 HH ‐ $/MMBtu V l C l12
Vol ‐ Cal12
products such as tolls, financial swaps and options
Commercial strategy positioning portfolio for market improvement
26

27. Assets In Different Markets
• How maximize the value of your assets across multiple markets
– Know your markets (the details matter!)
– Understand the politics of your market (city county state federal)
Understand the politics of your market (city, county, state, federal)
– Utilize adjacent markets if superior to the one you’re in
• Key metrics
– Gross Margin?
– Operating Margin?
– p p
Spark Spreads?
– MWh produced?
– Capacity Factor?
– In Market Availability?
In‐Market Availability?
• Pitfalls to avoid
– Not knowing the rules
– Analysis paralysis
l l
– “One size fits all” mentality
27

28. Know when to fold ‘em
Know when to fold ‘em
• Trading strategies
– When to exit?
Certain date on the calendar?
Certain date on the calendar?
Certain % move (up or down)
When you run out of credit?
When you will exceed your assigned VAR?
y y g
When your boss tells you to?
Paradox [păr å dǒks
Paradox [păr´å`dǒks]
n
A seemingly contradictory statement that may nonetheless be true
28

29. Commercial Highlights
Generation Hedged Position Coal Supply and Transport Hedged – Coal Segment
(as of 10/31/11)
BOY 2011 2012 2013
100%
Jul‐11 Oct–11 Jul–11 Oct–11 Jul–11 Oct ‐ 11 100% 100% 100% 100%
80%
Coal 85% 95% 20% 20% 5% 3%
60% Coal Supply
Transport
Gas 90% 89% 55% 48% 20% 14% 40%
DNE 90% 0% 40% 0% 0% 0% 20%
0%
Note: Values are based upon expected on and off‐peak generation as of 7/15/11 and 10/10/11
2011 2012
Adjusted EBITDA Sensitivities (in $MM)
Gas Supply Hedged – Gas Segment (as of 10/10/11)
FY 2012 Portfolio Unhedged
FY 2012 Portfolio Unhedged Year
Gas Coal Gas Coal 100%
Market Implied
Plus .5 HR(1) $15 $25 $45 $30 80% 93%
Movement
(Btu/KWh)
Heat Rate
Minus .5 HR(1) $(20) $(25) $(40) $(25) 60%
56%
Change in Cost
of Natural Gas
40%
Plus $1 Gas(2) $(75) $135 $10 $150
($/MMBtu)
20%
Minus $1 Gas(2) $(60) $(145) $(10) $(145)
15%
0%
(1) Sensitivities based on “on-peak” power price changes and full-year estimates; Assumes constant
natural gas price of ~$4.42/MMBtu and heat rate changes are for a full year; Increased run-time will
2011 2012 2013
result in increased maintenance costs, which are not included in sensitivities (2) Sensitivities based
on full year estimates and assume natural gas price change occurs for the entire year and entire
full-year
portfolio; On-peak power prices are adjusted by holding the spark spread constant to a 7,000
Btu/KWh heat rate; Off-peak prices are adjusted holding the market implied heat rate constant
Dynegy positioned to capture value in a rising pricing environment
29

30. Know when to fold ‘em
Know when to fold ‘em
• Plant retirements
– When to retire?
Plant is losing $ for the foreseeable future
Even a miracle won’t change the outcome (e.g. 2x increase in revenue)
Not feasible (or not economical) to run on an alternative fuel (nat gas)
No “green” subsidy available (co‐firing landfill gas, bio‐fuel, etc)
Not required for reliability by the ISO / RTO (no RMR payments)
Conundrum [kuh‐nuhn‐druhm]
n.
a: A question or problem having only a conjectural answer
a A question or problem having only a conjectural answer
b: An intricate and difficult problem
30

31. AES Greenidge
AES Greenidge 3 & 4
AES Greenidge
•
Location: Dresden, NY
Location: Dresden NY
•
Operator: AES Corp
•
Employees: 40
•
Configuration: Unit 3 (50 MW,
• f (
retired December 2009),
Unit 4 (113 MW, to be mothballed
Reasons for retirement: 3/18/2011)
• Economics; unit is operating at a net loss • Operation: 1950‐1953
(Source: NYPSC Filing) • Fuel: coal, wood
• Plant Manager Doug Roll cited a
combination of increased costs for coal and • Environmental modifications total
Environmental modifications total
rail transportation, high state taxes, fees, $49mm and include a bag house,
decreased demand for electricity and a dry scrubber, SCR, Biomass co‐firing
decline in the price of natural gas. (October
5, 2010) (Source: Finger Lakes Times
Online)

32. AES Westover 7 & 8
• AES Westover
• Location: Union, NY
Location: Union NY
• Operator: AES Corp
• Employees: 37
• Configuration: Unit 7 (44 MW,
f (
retired December 2009),
Unit 8 (80 MW, to be mothballed
3/18/2011)
• Operation: 1943‐1951
Reason for retirement:
• Fuel: coal
Economics; unit is • Environmental modifications total
Environmental modifications total
$60mm and include a bag house,
operating at a net loss dry scrubber, SCR
Source: NYPSC Filing

33. Exelon –
Exelon – Cromby Units 1 & 2
• Location: Phoenixville, PA
•OOperator: Exelon
t E l
• Employees: 82
• Configuration: Units 1 (160 MW, to
be mothballed 5/31/11) Unit 2
(208 MW, to be mothballed
12/31/11)
• Operation: 1954‐1955
Reason for retirement: • Fuel: coal, fuel oil, natural gas
•“Decreased power demand, over
supply of natural gas and increasing
operating costs, has led Exelon
Power to retire these units,” said
Doyle Beneby, senior vice president
of Exelon Power
Power.
Source: Exelon Press Release

34. Exelon –
Exelon – Eddystone Units 1 & 2
• Location: Eddystone, PA
•OOperator: Exelon
t E l
• Employees: 172 (total site)
• Configuration: Units 1 (294 MW, to
be mothballed 5/31/11) Unit 2
(294 MW, to be mothballed 6/1/12)
• Six natural gas or fuel oil units
(820MW total) will remain in service
Reason for retirement: • Operation: 1960
“Decreased power demand, over
supply of natural gas and increasing ue coa , atu a gas, ue o
• Fuel: coal, natural gas, fuel oil
operating costs, has led Exelon
Power to retire these units,” said
Doyle Beneby, senior vice president
of Exelon Power
Power.
Source: Exelon Press Release

35. AEP Philip Sporn – Unit 5
AEP Philip Sporn
• Location: New Haven, WV
•OOperator: AEP
t AEP
• Configuration: Unit 5 – 496MW
• Operation: 1960
• Fuel: coal
• Supercritical
Reason for retirement:
•Based on present and projected economic conditions, Sporn unit 5 is no longer
economic to operate and Ohio Power plans to shut down the plant earlier than
previously anticipated contingent upon commission approval, said th fili at th
i l ti i t d ti t i i l id the filing t the
PUCO. Sporn unit 5 is forecast to produce negative operating income for the next
two years. Based on recent market forecasts, the PJM revenues from the unit are not
expected to recover the anticipated expenses necessary to operate the unit. Results
for
f 2013 are expected to be similar, Ohio Power noted in the fili
t d t b i il Ohi P t d i th filing.
Source: PennEnergy

36. Q & A