2008 Financial Estimates
and Future Outlook
December 12, 2007
Investor & Public Relations | Norelle Lundy, Vice President | Nir Grossman, Senior Director | 713-507-6466 | ir@dynegy.com
Forward-looking Statements
This presentation contains statements reflecting assumptions, expectations, projections, intentions or beliefs
about future events that are intended as “forward-looking statements.” You can identify these statements,
including those relating to Dynegy’s 2007 and 2008 financial estimates and Market Recovery Outlook, 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 2006 Form 10-K, as amended, and first, second
and third quarter 2007 Forms 10-Q for additional information about the risks, uncertainties and other factors
affecting these forward-looking statements and Dynegy generally. Dynegy’s actual future results may vary
materially from those expressed or implied in any forward-looking statements. All of Dynegy’s forward-looking
statements, whether written or oral, are expressly qualified by these cautionary statements and any other
cautionary statements that may accompany such forward-looking statements. In addition, Dynegy disclaims any
obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Non-GAAP Financial Measures: This presentation contains non-GAAP financial measures. Reconciliations of
these measures to the most directly comparable GAAP measures are contained herein. To the extent required,
statements disclosing the utility and purposes of these measures are set forth in Item 2.02 to our Current Report
on Form 8-K accompanying this presentation, which is available on our website, www.dynegy.com.
Dynegy’s Market Recovery Outlook and related estimates are provided solely as a reference point and are
intended to represent a range of potential performance that could be achieved in each of the company’s key
regions at a point in time when supply and demand are in balance. The company does not intend to update this
Market Recovery Outlook or the potential range of performance provided except as otherwise required by
applicable SEC rules and regulations.
2
Agenda
Bruce Williamson
Strategic Overview
Dynegy’s Value Proposition
Building a Solid Foundation
Maintaining Optionality
Value Creation: Operate, Build, Transact
Holli Nichols
2008 Estimates and Regional Drivers
Market Recovery Outlook
Bruce Williamson
Creating and Capitalizing on Options
Management Team
Q&A
3
Value Proposition for Dynegy Investors
Value Proposition & Key Points
S&P 500 company with Market Cap of $6.7 Billion
Generation assets of approximately 20,000 MW; value of existing
assets continues to rise as barriers to entry limit new supply
Commercial function aligned with capital structure mitigates risk
and captures benefits through industry cycles
Operate-Build-Transact strategy should result in meaningful
cumulative cash flow before discretionary uses
Dynegy has the potential to generate ~40% of its current equity market
cap in cumulative annual cash flow over ~5 years
Equity Value of Operating Portfolio
($B)
60%
Replacement Value
Inherent value
$8.10 – $12.14
per share
Inherent value
$12.62 – $18.10
per share
Expected EBITDA Growth
80%
Replacement Value
Notes: Annual cash before discretionary uses represents operating cash flows and proceeds from asset sales, less maintenance and consent decree capital expenditures. Actual cash flow may vary materially from this estimate and is dependent on a variety of factors including weather, market conditions and future environmental regulations and refinancing of certain term debt starting in 2011. Equity Value assumes net debt and other obligations excluding non-recourse project debt related to assets under construction of ~$4.8B (pro forma 12/31/07) remains constant in both 60% and 80% estimates and assumes 840MM shares outstanding. See Appendix for estimated Equity Value calculations.
We expect to generate
~$200 - $600MM
cash annually before
discretionary uses
Expected Annual Cash Flow
~15%
Average Annual Growth
as markets reach recovery
4
Valuing Dynegy’s Asset Portfolio
Even at conservative assumptions regarding Dynegy’s coal and gas assets,
Dynegy appears to be undervalued
$ 17.96
$ 15.24
$ 12.52
$ 9.79
Coal/Oil Asset Value ($/KW)
$ 20.68
$ 19.52
$ 18.35
$ 17.19
$ 16.02
$ 14.85
750
$ 16.80
$ 15.63
$ 14.46
$ 13.30
$ 12.13
600
$ 14.07
$ 12.91
$ 11.74
$ 10.57
$ 9.41
450
$ 11.35
$ 10.18
$ 9.02
$ 7.85
$ 6.68
300
$ 8.63
$ 7.46
$ 6.30
$ 5.13
$ 3.96
150
2,750
2,500
2,250
2,000
1,750
1,500
Gas Asset
Value ($/KW)
As value of incumbent assets increases, stock price should follow
Implied Price per Share based on Asset Valuations
Note: Value excludes current and future development opportunities, assets under construction and associated non-recourse project debt.
5
Solid Foundation
47%
49%
Net Debt to Capitalization
4.1x – 3.7x
$4,281
$45
$200 – $300
$1,050 – $1,150
2008
4.6x – 4.3x
$4,441
$40
$215 – $265
$975 – $1,035
2007
Net Debt / EBITDA – Core Business (3)(4)
Net Debt (4)
Debt Maturities
Free Cash Flow – Core Business (3)
EBITDA – Core Business (2)(3)
Dynegy Projections(1) ($MM)
(1) See reconciliations in Appendix. (2) 2007 includes $40MM of unrealized mark-to-market earnings. (3) EBITDA and free cash flow are adjusted for significant items. See Appendix for reconciliations. No adjustments were made for 2008 EBITDA, such that EBITDA and EBITDA – Core Business are the same. (4) Net debt includes $360MM and $580MM of non-recourse project debt related to an asset under construction for 2007 and 2008, respectively.
Solid balance sheet
Ample liquidity
Producing free cash flow from
core operating business
Metrics that measure the strength of any business
Flexible capital structure
Well-positioned, well-operated
portfolio of assets
Management team with proven
ability to execute
6
2008 Generation Gross Margin by Contract Term Length
At Dynegy, this means:
Linking the commercial strategy and capital
structure in order to capture benefits and
mitigate risk through industry cycles
Managing a diversified operating portfolio
Maintaining a flexible capital structure
Minimal debt maturities through market
recovery create additional opportunities
Maintaining a Solid Foundation in a Cyclical Business
Linking Commercial with Capital Strategies
Focus on
core
business
Continuously
evaluate
Respond to
change with
the right
option
Maintain
discipline
throughout
cycles
Recognize
the cycles
Keep
options
open
Long-term contracts (5+ yrs)
Medium-term contracts (2-5 yrs)
Short-term sales (0-2 yrs)
We expect to
enter 2008 with
50-65%
contracted
Debt Maturity Profile (Pro Forma 12/31/07, $MM)
Midwest
West
Northeast
Aggregated Portfolio
7
Value Creation Strategy
Operate and commercialize power plants
Build or expand power plants by leveraging off development opportunities
Transact to grow diversified portfolio, creating new options for value
Existing assets
increasing in value
& earnings power
Investing in a
portfolio of
development options
to create value
Continuous
evaluation to
grow through
industry
opportunities
Operate
Transact
Build
8
Value Creation Strategy
Existing assets
increasing in value
& earnings power
Operate
How We Operate Today…
Assets are operated efficiently, reliably & safely
Existing portfolio is generating meaningful cash flow today
& positioned to further benefit from improving markets
Declining reserve margins resulting in more favorable
market fundamentals
In the Future…
Operations will be focused on reliability to serve markets
as they grow more supply-constrained
Upside potential for entire portfolio as reserve margins
continue to decrease and capacity markets improve
Portfolio should continue to produce cash flow for growth
opportunities and/or capital return to investors
Key Metrics for Success:
In-market availability
Commercial execution
Cost control
Operate and commercialize power plants
Build or expand power plants by leveraging off development opportunities
Transact to grow diversified portfolio, creating new options for value
9
Diversified & Balanced Portfolio
Dispatch Diversity
Peaking
48%
Intermediate
31%
Baseload
21%
Geographic Diversity
Midwest
48%
Northeast
19%
West
33%
Fuel Diversity
Combined Cycle
31%
Simple Cycle
40%
Total Gas-fired
71%
Coal
22%
Fuel Oil
7%
19,642 MW
Note: Plum Point and Sandy Creek are currently under construction.
Dynegy’s agreement to sell the Calcasieu facility in Louisiana is
expected to close in first half of 2008.
10
Regional Power Market Outlook
Note: Reserve margins derived from NERC 2007 Summer Assessment and regional NERC and ISO documents. Reserve margins reflect Dynegy’s projections based on assumptions as to
demand growth, new assets under construction and plant retirements, although actual reserve margins may vary materially from these projections.
Overbuilt
Underbuilt
As supply tightens, existing assets should become more valuable
Target range
for reliability
871
Locational Resource Adequacy
1,067
2,742
3,179
580
3,455
4,619
New England
PJM - MAAC+APS
NYISO
Northeast
System Resource Adequacy
California
PJM - RTO
MISO
Midwest
Dynegy MW
Opportunity to increase free cash flow as
reserve margins decline with plant
retirements, barriers to entry remain high
and demand rises, which should result in:
Improved spark spreads, strong power
prices and capacity prices
Increased value of existing assets
Regional Reserve Margin % Projections
11
Operate and commercialize power plants
Build or expand power plants by leveraging off development opportunities
Transact to grow diversified portfolio, creating new options for value
Investing in a
portfolio of
development options
to create value
Build
Value Creation Strategy
How We Build Today …
Dynamic portfolio of greenfield & brownfield
projects in progress
Project pipeline will change over time, not all
projects will advance
Build new generation utilizing a variety of fuels
Reinvest in the business, focused on high-
return projects
In the Future…
Execution of a development strategy can create
meaningful cash flow
12
Operate or monetize to harvest value
Refinance project debt with more
attractive terms
Lock-in cash flow & reduce risk with
additional PPAs
Begin construction
Obtain permits & long-term anchor
contract to support financing
Development Pipeline
Proven model with options to capture value at various stages
Plum Point
665 MW pulverized coal
facility with advanced
emissions control
Output fully contracted
Permitting process began
2001; currently under
construction; commercial
operations anticipated in 2010
Agreement to sell ownership
interest of 125 MWs for the
equivalent of ~$2,800/KW
Other Developments
Several thousand megawatts
of greenfield & brownfield
opportunities
Variety of geographic
locations & fuel types: gas,
coal, renewables
Opportunities for building or
value capture through project
monetization
Sandy Creek
900 MW “Supercritical”
pulverized coal facility with
advanced emissions control
Permitting process began
2003; construction began
4Q07; commercial operations
anticipated in 2012
Sold 25% interest for $30
MM (DYN share ~$15MM),
plus assumption of pro rata
construction costs
Pursuing additional contracts
to refinance with more
attractive terms
13
Development Opportunities
Portfolio of projects is dynamic and changes over time
Portfolio of greenfield projects in various stages of development
Brownfield projects are expected to have lower costs and shorter development time compared to
greenfield projects
Current development portfolio includes renewables, natural gas and coal projects
Geographically diverse portfolio
Note: Cost development and construction schedules are based on various trade publications and are intended solely as estimates. Others’ cost development and construction schedule
estimates and actual cost and construction schedules of specific projects may vary materially from these estimates. CO2 capture technology currently unavailable.
Lead-Time for Generation Project Development & Construction
Wind
Gas
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16 years
Timeframe
Solar
Coal
Nuclear
– OR –
Advanced development
portfolio has time cycle
advantage for building
new capacity
$500 – 800/KW
$800 – 1,100/KW
$2,600 – 2,900/KW
$3,100 – 4,100+/KW
Development lead-time
ranges include the complete
development cycle: siting,
permitting, engineering and
construction. $/KW includes
estimated financing costs.
$4,600 – 6,800/KW
$8,000 – 12,000/KW
Concentrate
Photovoltaic
Simple Cycle
Pulverized Super Critical
IGCC & IGCC with CO2 capture
Combined Cycle
$2,000 – 2,500/KW
$3,800 –
4,900/KW
Regional and national
delays will drive up the
value of Dynegy’s
existing operating assets
14
Operate and commercialize power plants
Build or expand power plants by leveraging off development opportunities
Transact to grow diversified portfolio, creating new options for value
Transact
Value Creation Strategy
How We Transact Today…
Well positioned in evolving industry for
combinations and acquisitions with:
Flexible capital structure
Diversified portfolio & scaleable platform
Management team focused on creating value
for all investors
Proven ability to execute transactions
In the Future…
Opportunistic and regular evaluation of potential
combinations or asset acquisitions to capture
additional value
Harvest value that exists in our portfolio today
Continuous
evaluation to
grow through
industry
opportunities
15
2
Proven Execution
Dynegy continues to be disciplined and opportunistic in building
a solid foundation to create and capitalize on options
Closed sale of CoGen Lyondell facility for ~$880/KW (1)
Announced sale of the Calcasieu peaking facility for
~$160/KW
Agreed to sell ownership investment equivalent to
125 MW of Plum Point for ~$2,800/KW
Sale of interest in Sandy Creek project
Streamlined capital structure and bank facilities
Issued $1.65 B unsecured bonds to eliminate project
debt and cash sweeps
Repaid remaining $225 MM of debt on revolving
credit facility
Obtained off balance sheet, non-recourse financing to
begin construction of Sandy Creek
Closed LS Power combination
Completed integration of LS Power assets
Delivered positive quarterly results throughout 2007
Accomplishments:
1
3
Integrate acquired LS Power assets
“Right-hand” side of the balance sheet:
enhance flexibility, minimize costs and
protect credit ratings
“Left-hand” side of the balance sheet:
sale of selected assets
2007 Goals:
(1) Based on Summer capacity of 537MW.
16
2008 Estimates
and Regional Drivers
Holli Nichols
Executive Vice President & Chief Financial Officer
Regional Overviews
Market Drivers:
Regional results are driven primarily by
commodity markets, power prices, spark
spreads and capacity markets
Longer-term results will be impacted by
regulatory activities and environmental
requirements
Regional Highlights:
Bilateral, tolling agreements, RMR and
financial agreements
Fuel and transportation contracts
EBITDA forecasts include energy and
capacity revenues, cost of sales and
operating expenses
Regional forecasts are based on
commodity curves as of 10/30/07
Capital Expenditure estimates for the
next five years
General & Administrative expenses
are included in Other
18
Midwest Generation
Regional Market Drivers
MISO – Outright power price for uncontracted baseload
volumes, and spark spread for uncontracted gas-fired
peaking units
PJM – Spark spread for uncontracted gas-fired combined
cycle units
Capacity markets – MISO capacity sold under bilateral
agreements; PJM capacity sold in forward auctions for
three years
Regional Highlights
Bilateral & tolling agreements and financial forward sales
Illinois auction – receive approximately $65/MWh
Up to 1,200 MW expiring 5/2008 (~50% load factor)
Up to 200 MW expiring 5/2009 (~50% load factor)
100% of coal supply contracted through 2010; 2008
contracted at a fixed price
100% of rail contracted at a fixed price through 2013
1,535
Revenues
10
Other (1)
2008
Midwest Forecast ($MM)
$ 855
EBITDA
(190)
Operating Expense (3)
1,045
Gross Margin
(490)
Cost of Sales (2)
185
Capacity
$ 1,340
Energy
Avg. Spark Spread (CIN vs TCO APP @ 7HR) $7.75
$1.39/MMBtu
Delivered PRB Coal (Baldwin)
$2.45
PJM - RTO
0% - 10%
Peaking
10% - 20%
CC
80% - 90%
Baseload
Annual Average
Capacity
Factors
$81.25
PJM West
$67.65
CIN Hub
Power Prices
(Average on peak
prices $/MWh)
$2.45
PJM - MAAC+APS
MISO
10,000 – 12,000
Peaking
7,000 – 8,000
CC
Baseload
Forecasted Fundamentals
2008
Plum Point construction – completion expected 2010
$1.00 - $2.00
Average
Capacity Price
(KW-Mo)
$8.55/MMBtu
Delivered Natural Gas (TCO APP)
10,000 – 11,000
Fleet Heat
Rate (4)
(Nameplate
Btu/KWh)
26.5
Volumes (MM MWh)
(1) Other comprised of ancillary services, emission credit sales and amortization of intangibles. (2) Cost of Sales includes
fuel, transportation, start-up costs and emission credit costs. (3) Operating Expense excludes depreciation and
amortization. (4) Nameplate Heat Rate is adjusted for generating starts & stops, weather, fuel types, efficiencies and other
operational components.
19
West Generation
Regional Market Drivers
Spark spread for uncontracted gas-fired combined
cycle and peaking units, and ancillary services
California has no formal capacity auction market;
greater demand is expected for capacity in 2009 as
utilities will have reduced Resource Adequacy
requirements
Regional Highlights
Includes RMR contracts, tolling agreements, and
financial forward sales contracts
Fuel price risk generally passed through on hedges
and tolling agreements or purchased as needed at
index-related prices
0% - 20%
Peaking
30% - 60%
CC
n/a
Baseload
Annual
Average
Capacity Factors
Avg. Spark Spread (NP15 vs PG&E @ 7HR)
$21.50
$72.75
Palo Verde
$78.25
NP-15
Power Prices
(Average on-peak
prices $/MWh)
System RA
$0.50 - $1.50
9,500 – 10,500
Peaking
7,000 – 8,000
CC
Baseload
Forecasted Fundamentals
2008
Sandy Creek construction – completion expected 2012
Avg. Capacity
Price (KW-Mo)
$8.12/MMBtu
Delivered Natural Gas (PG&E)
n/a
Fleet Heat
Rate (4)
(Nameplate
Btu/KWh)
12.1
Volumes (MM MWh)
850
Revenues
5
Other (1)
2008
West Forecast ($MM)
$ 190
EBITDA
(135)
Operating Expense (3)
325
Gross Margin
(525)
Cost of Sales (2)
190
Capacity/RMR
$ 655
Energy
(1) Other comprised of ancillary services, emission credit sales and amortization of intangibles. (2) Cost of Sales includes
fuel, transportation, start-up costs and emission credit costs. (3) Operating Expense excludes depreciation and
amortization. (4) Nameplate Heat Rate is adjusted for generating starts & stops, weather, fuel types, efficiencies and other
operational components.
20
Northeast Generation
Regional Market Drivers
NYISO – Spark spread for uncontracted combined
cycle gas and fuel oil units, and outright power price for
uncontracted baseload coal volumes
ISO-NE – Spark spread for uncontracted combined
cycle gas units
New England – formal capacity market auction will
occur in early 2008 for 2010/2011 capacity
Regional Highlights
Includes bilateral capacity agreements and
financial forward sales contracts
Operating expense includes $50 million of Central
Hudson lease expense, and operating cash flow
includes cash lease payments of $144 million in 2008
EBITDA will include approximately $50 million net
earnings from ConEd contract; however, operating
cash flow will include cash receipt of approximately
$100 million in 2008
100% of coal supply contracted at a fixed price
through 2008
$9.12/MMBtu
Delivered Natural Gas (TETCO-M3)
$3.45
$2.50
0% - 10%
30% - 50%
80% - 90%
Peaking
$22.75
Gas (Mass Hub vs TET M3 @ 7HR)
($24.00)
Fuel Oil (NY-G vs #6 Oil @10.5HR)
Avg.
Spark
Spread
CC
Baseload
Annual
Average
Capacity
Factors
$3.20/MMBtu
$11.38/MMBtu
SA Coal
$86.62
Mass Hub
$73.78
NY Zone A
$95.60
NY Zone G
Power Prices
(Average on peak
prices $/MWh)
New England
NYISO
9,500 – 10,500
Peaking
7,000 – 8,000
CC
Baseload
Forecasted Fundamentals
2008
Average
Capacity Price
(KW-Mo)
Fuel Oil #6
Delivered Fuel
10,000 – 11,000
Fleet Heat
Rate (4)
(Nameplate
Btu/KWh)
10.0
Volumes (MM MWh)
1,000
Revenues
(25)
Other (1)
2008
Northeast Forecast ($MM)
$ 185
EBITDA
(180)
Operating Expense (3)
365
Gross Margin
(635)
Cost of Sales (2)
225
Capacity
$ 800
Energy
(1) Other comprised of ancillary services, emission credit sales and amortization of intangibles. (2) Cost of Sales includes
fuel, transportation, start-up costs and emission credit costs. (3) Operating Expense excludes depreciation and
amortization. (4) Nameplate Heat Rate is adjusted for generating starts & stops, weather, fuel types, efficiencies and other
operational components.
21
Central Hudson Lease – Northeast Segment
Chart represents total cash lease payments, which are included in Operating Cash Flows
Lease expense is approximately $50 million per year and included in Operating Expense
Accrual Lease Expense
2008 Central Hudson treated as Debt
(would require the following adjustments to GAAP financials):
Income Statement – Add back $50 million lease expense to EBITDA; add $74
million imputed interest expense to Interest Expense; add $23 million estimated
depreciation & amortization expense; adjust tax expense for net difference
Depreciation & Amortization calculated using purchase price of $920 million divided by
40 years
Cash Flow Statement – Add back $70 million of imputed principal to operating
cash flows
$144 million cash payment split between $74 million imputed interest payment
(operating cash flows) and $70 million imputed principal payment (financing cash flows)
Balance Sheet – Include $770 million total PV (10%) of future lease payments
2008 Central Hudson treated as Lease
(as currently shown in GAAP financials):
Income Statement – $50 million lease expense included
in EBITDA; no interest expense or depreciation &
amortization expense
Cash Flow Statement – $144 million cash payment
included in Operating Cash Flows
Balance Sheet – lease obligation not included in debt
balance
Central Hudson Cash Payment ($MM)
$144
$141
$95
$112
$179
$142
$143
$143
$105
Total Principal Payments at PV(10%)
of future lease payments = $770 MM
22
Anticipated Capital Expenditures (2008 – 2012)
$ 280
$ 335
$ 550
$ 560
$ 640
TOTAL
-
-
10
30
45
Discretionary Investment (target IRR 15% or more)
-
-
110
110
220
Development (Plum Point) (1)
50
15
10
15
30
Other Environmental
40
100
175
195
150
Consent Decree (Midwest)
135
160
180
145
115
Major Maintenance (Outage Work)
$ 55
$ 60
$ 65
$ 65
$ 80
General Maintenance
2012
2011
2010
2009
2008
($MM)
Major maintenance for a CCGT facility is primarily based on run-time, assumed to occur approximately every 24,000
run hours
Costs may vary depending on unit size, equipment, age and other operating factors
Over a 5.5 year period, assuming a 50% capacity factor, total maintenance costs for our CCGT fleet are estimated at $250 MM
Other Environmental includes mercury reduction, marine life barriers and NOx / SO2 control equipment outside the
Consent Decree
Development fleet currently consists of Plum Point, which is scheduled to become operational in 2010; 100% of total
Plum Point project cost is debt financed
Discretionary Investment includes projects designed to increase available capacity or lower facility heat rate, which
should improve market availability
Projects include replacing/updating technology such as upgrading steam turbines on existing units to improve output and plant heat rate;
in some cases, such projects may require environmental permits
(1) Plum Point is consolidated and fully financed on a non-recourse basis. Although Sandy Creek is under construction, it is not included in the development capex as Sandy Creek is not
consolidated. Sandy Creek will also be fully financed on a non-recourse basis.
23
2008 Cash Flow Estimates: GAAP Basis
Note: 2008 estimates are presented on a GAAP basis and are based on quoted forward commodity price curves as of 10/30/07. 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. Core business
represents continuing operating results, excluding significant items. Proceeds from the expected sale of Calcasieu are assumed to be received in first half of 2008.
45
Add Back: Discretionary Investment
(20)
(20)
-
Investment in Development Portfolio
(30)
-
(30)
CapEx – Other Environmental
(80)
(20)
(60)
CapEx – General Maintenance
(150)
-
(150)
CapEx – Consent Decree
$ 200 – 300
Free Cash Flow – Core Operating Business
(200)
Less: Proceeds from Asset Sales
(125)
Less: Change in Restricted Cash
10
Add Back: Illinois Rate Relief
220
Add Back: Plum Point Development CapEx
$ 250 – 350
Free Cash Flow
125
95
30
Change in Restricted Cash
200
200
Proceeds from Asset Sales
(220)
-
(220)
CapEx – Development (Plum Point)
(45)
-
(45)
CapEx – Discretionary Investment
(115)
-
(115)
CapEx – Outage Work
GAAP ICF:
$ 585 – 685
$ (550) – (540)
$ 1,135 – 1,225
GAAP OCF estimates as of Dec 12, 2007
2008 TOTAL
Other / CRM
Generation
Based on price curves as of October 30, 2007 ($MM)
Development CapEx related to Plum Point is 100% debt financed; therefore, $220 MM CapEx is offset in
financing cash flow
Discretionary Investments are added back as they relate to optional spending
Net proceeds from asset sales include anticipated proceeds from pending sale of Calcasieu of $57MM
Remaining proceeds expected to come from other non-core asset sales or monetization of equity interests
Change in restricted cash primarily related to return of cash collateral posted to support equity
commitments associated with development projects
24
2008 Earnings Estimates: GAAP Basis
$ 140 – 200
Net Income – GAAP
(380)
(10)
(370)
(55)
(105)
(210)
Depreciation and Amortization
$ 830 - 880
Midwest
$ 180 - 200
West
$ 175 - 195
Northeast
$0.17 – 0.24
Basic EPS
(90) – (130)
Tax Expense
(440)
Interest
$ 1,050 – 1,150
$ (135) – (125)
$ 1,185 - 1,275
EBITDA estimates as of Dec 12, 2007
2008 TOTAL
Other/CRM
Total Gen
Based on price curves as of October 30, 2007 ($MM)
Note: 2008 estimates are presented on a GAAP basis and are based on quoted forward commodity price curves as of 10/30/07. Actual results may vary materially from these estimates based
on changes in commodity prices, among other things, including operational activities, legal settlements, financing or investing activities and other uncertain or unplanned items. Reduced
2008 and forward EBITDA or free cash flow could result from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets where the value that can be
captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets. Divestitures could also result in impairment charges.
Northeast region EBITDA includes:
~$50 million lease expense related to Central Hudson lease obligation
~$50 million non-cash amortization of ConEd contract
Other includes general & administrative costs of ~ $175 million, primarily offset by interest income
Earnings may be volatile as many forward sales commitments are marked to market, which may create
differences between EBITDA and timing of cash received
Assumed 39% tax rate
25
EBITDA Reconciliation: 2007 to 2008
Core Business EBITDA(1) ($MM)
$965
$1,100
$45
$15
$40
$(10)
$(15)
2007 EBITDA –
Core Business (2)
$975 – 1,035
2008 EBITDA
$1,050 – 1,150
$35
$(40)
$25
$1,005
2007 EBITDA –
Core Business
excluding MTM
$935 – 995
(1) 2007 Core Business EBITDA is adjusted for significant items. See Appendix for reconciliation. No adjustments to 2008 EBITDA have been made. (2) Core Business EBITDA as
estimated November 8, 2007.
$1,100
$965
~15%
Increase
26
EBITDA Sensitivity to Natural Gas
Sensitivities based on full-year estimates and assume natural gas price change occurs for the
entire year and entire portfolio
On-peak power prices are adjusted by holding the spark spread constant to a 7,000 Btu/KWh heat rate
Off-peak prices are adjusted holding the market implied heat rate constant
MTM accounting treatment will cause differences between EBITDA and timing of cash received
Estimates exclude potential changes in portfolio value associated with contracts beyond 2008
Note: Uncontracted portfolio assumed for illustrative purposes only.
Natural gas sensitivity primarily impacts baseload coal-fired generation
$(280)
- $2.00
$(60)
- $2.00
$(145)
- $1.00
$(30)
- $1.00
$165
+ $1.00
$50
+ $1.00
$320
+ $2.00
$100
+ $2.00
Generation EBITDA
Sensitivity ($MM)
Change in Cost of Natural Gas
($/MMBtu)
Generation EBITDA
Sensitivity ($MM)
Change in Cost of Natural Gas
($/MMBtu)
Long-Term: Uncontracted
2008: Includes contracts as of 10/30/07
27
$(50)
$60
$120
TOTAL
$(30)
$40
$80
Natural Gas
Coal/Fuel Oil
$(20)
- 500
$20
+ 500
$40
+ 1,000
Generation EBITDA Sensitivity ($MM)
Market Implied
Heat Rate
Movement
(Btu/KWh)
2008: Includes contracts as of 10/30/07
$(135)
$175
$350
TOTAL
$(90)
$110
$225
Natural Gas
Coal/Fuel Oil
$(45)
- 500
$65
+ 500
$125
+ 1,000
Generation EBITDA Sensitivity ($MM)
Market Implied
Heat Rate
Movement
(Btu/KWh)
Long-Term: Uncontracted
Sensitivities based on “on-peak” power price changes and full-year estimates
Assumes constant natural gas price of $8.25/MMBtu(1) and heat rate changes are for
a full year
Increased run-time will result in increased maintenance costs, which are expected to
be largely offset by improved earnings
EBITDA Sensitivity to Market Implied Heat Rates
Market implied heat rates sensitivities impact entire operating fleet
Note: Spark spread value changes depend on natural gas price assumptions. Uncontracted portfolio assumed for illustrative purposes only. (1) Represents average natural
gas prices as of 10/30/07.
28
Market Implied Heat Rate Analysis
Note: Reserve margins derived from NERC 2007 Summer Assessment and regional NERC and ISO documents. Reserve margins reflect Dynegy’s projections based on assumptions as
to demand growth, new assets under construction and plant retirements, although actual reserve margins may vary materially from these projections. Market implied heat rates were
calculated using the following actual and forward price points for power and natural gas: NY/NE – NY & NE/ TETCO M3; West – NP15/PGECG; PJM – PJM West / TETCO M3; MISO –
CIN / Con App. Actual prices were used for all periods.
As reserve margins decline, market implied heat rates rise…
especially as markets reach 15-20% reserve levels
Market Implied Heat Rate (Btu/KWh)
Overbuilt
Underbuilt
Target range
for reliability
Regional Reserve Margin Projections (%)
MISO
PJM
West
Northeast
MISO
PJM
California
Northeast
29
Market Recovery Outlook
Assuming Market Recovery
Outlook is applicable in 5
years, although volatile,
annual average increase in
EBITDA would be ~15%
With current operations,
Dynegy has the potential to
generate ~40% of its current
equity market cap in
cumulative annual cash flow
over ~5 years
Value of existing generation
assets & advanced
development projects should
continue to rise as barriers-
to-entry limit new supply
Total Portfolio Gross Margin ($MM)
Note: Dynegy’s Market Recovery Outlook and related estimates are provided solely as a reference point and are intended to represent a range of potential performance that could be achieved in
each of the company’s key regions at a point in time when supply and demand are in balance. The company does not intend to update this Market Recovery Outlook or the potential range of
performance provided except as otherwise required by applicable SEC rules and regulations.
EBITDA $1,050 – 1,150 MM
Core FCF $200 – 300 MM
EBITDA +/- $1,800 MM
Core FCF +/- $600 MM
30
Creating & Capitalizing on Options
Bruce Williamson
Chairman & Chief Executive Officer
47%
49%
Net Debt to Capitalization
4.1x – 3.7x
$4,281
$45
$200 – $300
$1,050 – $1,150
2008
4.6x – 4.3x
$4,441
$40
$215 – $265
$975 – $1,035
2007
Net Debt / EBITDA – Core Business (3)(4)
Net Debt (4)
Debt Maturities
Free Cash Flow – Core Business (3)
EBITDA – Core Business (2)(3)
Dynegy Projections(1) ($MM)
(1) See reconciliations in Appendix. (2) 2007 includes $40MM of unrealized mark-to-market earnings. (3) EBITDA and free cash flow are adjusted for significant items. See Appendix for reconciliations. No adjustments were made for 2008 EBITDA, such that EBITDA and EBITDA – Core Business are the same. (4) Net debt includes $360MM and $580MM of non-recourse project debt related to an asset under construction for 2007 and 2008, respectively.
How is Dynegy Competitively Advantaged?
Well-positioned, well-operated assets
No significant debt maturity until 2011
Credible, focused management team
Flexible capital structure
Ample liquidity
Positive free cash flow from core
operating business
Solid balance sheet
Creating & Maintaining
a Solid Foundation
32
How will it be
implemented?
When will
it begin?
Things to Consider when Looking at the Future
Unknowns will impact the company’s results, both positively and negatively, and
the outcome and/or timing is extremely difficult to predict or control, including:
What will
happen?
Industry
Issue
Focus on
core
business
Continuously
evaluate
Respond to
change with
the right
option
Maintain
discipline
throughout
cycles
Recognize
the cycles
Keep
options
open
Who will be
impacted?
Chain of Uncertainty is also a Link to Opportunity
Where will
it occur?
Global & national economics
Weather
Market design changes – change in laws
Sector consolidation
Environmental regulation &
the potential for carbon legislation
Supply/demand balance
Awareness, continuous evaluation, cultivating options and maintaining a
diverse portfolio are tools for managing the uncertainties
33
Positioned for the Future
Operate
Transact
Build
Focused on Delivering
Value to Investors
Dynegy’s bottom line:
Focus
on core
business
Keep
options
open
Continuous
evaluation
Maintain
discipline
through
cycles
Recognize
the cycles
Solid
Foundation
Respond
to change
Management team with
proven ability to operate,
execute & respond to change
As market demand increases,
our operational excellence
and reliability track record will
be key to capturing value
Anticipate average annual
EBITDA growth of ~15% as
markets reach recovery
Expect to generate
~$200 to $600MM cash flow
annually before discretionary uses
or ~$2.5B over the next 5 years
Notes: Annual cash before discretionary uses represents operating cash flows and proceeds from asset sales, less maintenance and consent decree capital expenditures. Actual cash flow may vary materially from this
estimate and is dependent on a variety of factors including weather, market conditions and future environmental regulations and refinancing of certain term debt starting in 2011.
34
Appendix
2008 Commodity Pricing Assumptions (as of 10/30/07)
* Represents annual average
Moss Landing, Morro Bay, Oakland
$78.25
NP-15 – California
Independence
$73.78
NY – Zone A
Roseton
$11.38
Fuel Oil #6 delivered to Northeast ($/MMBtu)
Danskammer
$3.20
Colombian delivered to Northeast
Baldwin
$1.39
Powder River Basin (PRB) delivered
Coal ($/MMBtu)
Arlington Valley, Griffith
$72.75
West – Palo Verde
South Bay
$78.75
SP-15 – California
Bridgeport, Casco Bay
$86.62
NE – Mass Hub
Roseton, Danskammer
$95.60
NY – Zone G
Midwest Peakers
$67.65
Cinergy
Ontelaunee
$81.25
PJM West
Midwest Coal, Kendall
$65.40
NI Hub / ComEd
On-Peak Power ($/MWh)
$ 8.25
Natural Gas – Henry Hub ($/MMBtu)
Facilities
2008E*
37
Key Assumptions
2008 Assumptions
Commodity pricing as of October 30, 2007
$200 MM in asset sales
Proceeds can come from sale of operating or
development assets
Expect to close $57 MM sale of Calcasieu in first half of 2008
Assume assets sold at book value (i.e., no EBITDA impact)
Interest expense of $440 million and Cash interest
payments of $445 million
Sandy Creek debt is not consolidated
Current Sandy Creek equity commitment of
approximately $325 MM is cash collateralized until
offtake contracts are executed during 2008 (as
indicated by restricted cash shown in Appendix)
Taxes accrue at 39%
Minimal AMT cash taxes
Future Outlook Assumptions
Credit Facility, Term Letter of Credit Facility and
Senior Unsecured notes are refinanced at stated
maturities
Plum Point debt, which is non-recourse, is
assumed to be consolidated; balance will increase
from $419 MM at the end of 2007 to $800 MM in
2010 upon construction completion
~$50 million annual amortization included in
Northeast EBITDA through 2014 related to ConEd
contract; annual capacity payments received of
~$100 million through 2014
Shares outstanding ~840 MM
Minimal AMT cash taxes paid until 2010; full cash
tax payer beginning in 2011
~$40
NOL Asset beginning 2008
$400-500/yr.
NOL Limit
~$10-$20/yr.
AMT Cash Taxes
~$250
AMT credit carry forward, dollar for dollar
(Estimated as of Year End 2007, $MM)
38
Debt Maturity Profile ($ MM)
Note: Annual maturities reflect par value debt obligations outstanding pro forma 12/31/07. Debt as of 12/31/07 excludes $1,150 MM of revolving credit facility due 2012 as it is expected to be
undrawn. Central Hudson lease obligations are not included as debt. (1) 2013 includes an $850 million Letter of Credit Facility that is offset by restricted cash.
(1)
Pro Forma 12/31/07
39
Debt & Other Obligations Capital Structure –
Pro Forma 12/31/07
Dynegy Power Corp.
Central Hudson(2) $770
Dynegy Holdings Inc.
$1,150 Million Revolver(1) $0
Term L/C Facility $850
Tranche B Term $70
Sr. Unsec. Notes/Debentures $4,047
Sub.Cap.Inc.Sec (“SKIS”) $200
Secured = $920
Key:
Secured Non-Recourse = $808
Unsecured = $5,017
Dynegy Inc..
Senior Debentures $389
Plum Point Energy Assoc.
PP 1st Lien $319
Tax Exempt 100
Gross Debt $419
Restricted Cash 59
Total, Net Debt $360
(1) Represents drawn amounts under the revolver. (2) Represents PV (10%) of future lease payments. Central Hudson lease payments are unsecured obligations of Dynegy Inc., but are a
secured obligation of an unrelated third party (“lessor”) under the lease. DHI has guaranteed the lease payments on a senior unsecured basis. (3) Restricted cash includes $850MM related
to the Synthetic Letter of Credit facility, $325MM for Sandy Creek Letter of Credit which is used in lieu of cash on hand and $59MM related to Plum Point.
($ MM)
Sithe Energies
360
Less: Net Non-recourse Project Debt, under construction
$4,441
Net Debt
$5,211
Net Debt and Other Obligations
770
Less: Central Hudson Lease Obligation
1,234
Less: Restricted cash (3)
$4,081
Net Debt associated with Operating Assets
300
Less: Cash on hand
$6,745
Total Obligations
12/31/07
($ Million)
40
Debt & Other Obligations Capital Structure –
Pro Forma 12/31/08
Dynegy Power Corp.
Central Hudson(2) $700
Dynegy Holdings Inc.
$1,150 Million Revolver(1) $0
Term L/C Facility $850
Tranche B Term $69
Sr. Unsec. Notes/Debentures $4,047
Sub.Cap.Inc.Sec (“SKIS”) $200
Dynegy Inc..
Senior Debentures $345
Plum Point Energy Assoc.
PP 1st Lien $509
Tax Exempt 100
Gross Debt $609
Restricted Cash 29
Total, Net Debt $580
(1) Represents drawn amounts under the revolver. (2) Represents PV (10%) of future lease payments. Central Hudson lease payments are unsecured obligations of Dynegy Inc., but are a
secured obligation of an unrelated third party (“lessor”) under the lease. DHI has guaranteed the lease payments on a senior unsecured basis. (3) Restricted Cash includes $850 million
related to the Synthetic Letter of Credit Facility, $225 million for Sandy Creek Letter of Credit which is used in lieu of cash on hand and $29 million related to Plum Point.
($ MM)
Sithe Energies
580
Less: Net Non-recourse Project Debt, under construction
$4,281
Net Debt
$ 4,981
Net Debt and Other Obligations
700
Less: Central Hudson Lease Obligation
1,104
Less: Restricted cash (3)
$3,701
Net Debt associated with Operating Assets
735
Less: Cash on hand
$6,820
Total Obligations
12/31/08
($ Million)
Secured = $919
Key:
Secured Non-Recourse = $954
Unsecured = $4,947
41
Market Recovery Outlook (1)
$3.00
N/A
N/A
Avg Colombian Coal ($/MMBtu)
Peaking
CC
Baseload
Fuel Oil ($/MMBtu)
Natural Gas ($/MMBtu) Henry Hub
PRB Coal ($/MMBtu)
0%-10%
20%-30%
0%-10%
40%-50%
60%-70%
20%-30%
80%-90%
N/A
80%-90%
Average
Capacity Factors
$10.40
N/A
N/A
~$8.25
~$8.25
~$8.25
N/A
N/A
$1.39
Fuel
9.90
10.40
9.70
Average Market-Implied Heat Rate (MMBtu/MWh)
12.3
17.1
29.1
Volumes (MM MWh)
Northeast
West
Midwest
(1) Dynegy’s Market Recovery Outlook and related estimates are provided solely as a reference point and are intended to represent a range of potential performance that could be achieved in
each of the company’s key regions at a point in time when supply and demand are in balance. The company does not intend to update this Market Recovery Outlook or the potential range
of performance provided except as otherwise required by applicable SEC rules and regulations.
(2) Represents uncontracted volumes.
(3) Excludes ConEd capacity contracted on Independence. Approximately 75% of the facility’s capacity is obligated under a capacity sales agreement, which is effective through 2014.
Revenues from this agreement are largely fixed at approximately $100MM/year, or approximately $11.20/KW-Mo.
NE
MISO
RTO
MAAC+APS
$3-$4
580
$3-$4
3,165
PJM
Midwest
$2-$3
4,619
$4-$5
1,067
Northeast
West
Capacity Revenues
$4-$5
1,958
NYISO (3)
165
Locational RA
14,083
TOTAL
$2-$3
2,529
System RA
Price ($/kW-mo)
Dynegy MWs Available (2)
EBITDA +/- $1,800 MM
Core FCF +/- $600 MM
42
Equity Value Calculations
(5.2)
(5.2)
(5.2)
(5.2)
Net Debt and Other
Obligations(2)
$ 10.12
$ 15.36
Average Implied
Value per Share ($)
$ 12.14
$ 8.10
$ 18.10
$ 12.62
Implied Value per Share ($)
840
840
840
840
Million Shares Outstanding
$ 10.2
$ 6.8
$ 15.2
$ 10.6
Equity Value
0.4
0.4
0.4
0.4
Net Non-recourse Project
Debt (under construction)
$ 15.0
$ 11.6
$ 20.0
$ 15.4
Enterprise Value Estimate (1)
High
Low
High
Low
($B)
60% Replacement
80% Replacement
(1) Market value estimate derived from 19,165MW of operating assets, which excludes 140MW for Plum Point and 337MW for Sandy Creek, multiplied by indicated percentages of
applicable replacement cost ranges shown on slide 14. Estimates exclude any value associated with development opportunities. (2) Pro forma 12/31/07.
43
Reconciliations –
Gross Margin, EBITDA and Core EBITDA ($MM)
GEN-WE
GEN-MW
GEN-NE
Total GEN
Other/CRM
Total
Revenue
470
$
1,310
$
1,075
$
2,855
$
40
$
2,895
$
Cost of sales
(185)
(440)
(680)
(1,305)
(10)
(1,315)
Gross margin
285
870
395
1,550
30
1,580
Operating expense
(95)
(200)
(190)
(485)
(5)
(490)
General and administrative expense
-
-
-
-
(205)
(205)
Gain on sale
-
80
-
80
-
80
Depreciation expense
(65)
(190)
(45)
(300)
(15)
(315)
Operating income
125
560
160
845
(195)
650
Other income and expense, net
10
-
-
10
40
50
EBITDA from discontinued operations
215
-
-
215
20
235
Plus: Depreciation expense
65
190
45
300
15
315
EBITDA
415
750
205
1,370
(120)
1,250
Less: Depreciation expense
(315)
Less: Interest expense
(385)
Less: Income tax expense
(240)
Net income
310
$
GEN-WE
GEN-MW
GEN-NE
Total GEN
Other/CRM
Total
Revenue
850
$
1,535
$
1,000
$
3,385
$
-
$
3,385
$
Cost of sales
(525)
(490)
(635)
(1,650)
(5)
(1,655)
Gross margin
325
1,045
365
1,735
(5)
1,730
Operating expense
(135)
(190)
(180)
(505)
-
(505)
General and administrative expense
-
-
-
-
(175)
(175)
Depreciation expense
(105)
(210)
(55)
(370)
(10)
(380)
Operating income
85
645
130
860
(190)
670
Other income and expense, net
-
-
-
-
50
50
Plus: Depreciation expense
105
210
55
370
10
380
EBITDA
190
855
185
1,230
(130)
1,100
Less: Depreciation expense
(380)
Less: Interest expense
(440)
Less: Income tax expense
(110)
Net income
170
$
Reconciliation of Gross Margin and EBITDA
Year Ending 12/31/08
Year Ending 12/31/07
EBITDA
$ 1,250
Legal and settlement, net
30
Illinois rate relief
25
Purchasing accounting adjustments
(30)
Gain on sale - CoGen Lyondell
(210)
Gain on sale - Percent ownership of Plum
Point & Sandy Creek
(80)
Change in fair value of interest rate swaps
and minority interest
20
Core Business EBITDA
$ 1,005
Reconciliation of 2007 Core Business EBITDA
Total
Revenue
5,000
$
Cost of sales
(2,500)
Gross margin
2,500
Operating expense
(650)
General and administrative expense
(225)
Depreciation expense
(530)
Operating income
1,095
Other income and expense, net
175
Plus: Depreciation expense
530
EBITDA
1,800
Less: Depreciation expense
(530)
Less: Interest expense
(470)
Less: Income tax expense
(265)
Net income
535
$
Market Recovery Outlook
44
Reconciliations –
Free Cash Flow & Net Debt and Other Obligations ($MM)
Market Recovery
Outlook
GEN
Other
Total
GEN
Other
Total
Operating Cash Flows
1,030
$
(635)
$
395
$
1,180
$
(545)
$
635
$
880
$
General maintenance
(125)
(15)
(140)
(60)
(20)
(80)
-
Outage work
-
-
-
(115)
-
(115)
-
Consent decree
(70)
-
(70)
(150)
-
(150)
-
Other environmental
-
-
-
(30)
-
(30)
-
Organic development
-
-
-
(45)
-
(45)
-
Plum Point development
(160)
-
(160)
(220)
-
(220)
-
Total Capital Expenditures
(355)
(15)
(370)
(620)
(20)
(640)
(280)
Investment in development portfolio
-
(10)
(10)
(20)
(20)
-
Proceeds from asset sales
560
(130)
430
200
-
200
-
Change in restricted cash
25
(975)
(950)
30
95
125
70
Investing Cash Flows
230
(1,130)
(900)
(390)
55
(335)
(210)
Free Cash Flow
(505)
300
670
Plus: Illinois rate relief / Legal settlements
50
10
-
Plus: Cash taxes on asset sales
10
-
-
Plus: Organic development
-
45
-
Plus: Plum Point development
165
220
-
Less: Proceeds from asset sales
(430)
(200)
-
Plus/(Less): Change in restricted cash
950
(125)
(70)
Free Cash Flow - Core Operating Business
240
$
250
$
600
$
12/31/07
12/31/08
Debt per pro-forma balance sheet
5,975
$
6,120
$
Less:
Cash and cash equivalents
(300)
(735)
Restricted cash - LC/Sandy Creek
(1,175)
(1,075)
Restricted cash - Plum Point
(59)
(29)
Net Debt
4,441
$
4,281
$
Plus:
Central Hudson Imputed Principal
770
700
Net Debt & Other Obligations
5,211
$
4,981
$
12/31/07
12/31/08
Net Debt
4,441
$
4,281
$
Equity
4,558
4,733
Total Capitalization
8,999
$
9,014
$
Net Debt / Capitalization
49%
47%
Reconciliation of Free Cash Flow and Free Cash Flow - Core Operating Business
Capitalization
Reconciliation of Net Debt and Net Debt & Other Obligations
Year Ending 12/31/07
Year Ending 12/31/08
45
Generation Assets – Midwest & Northeast
46
Generation Assets – West & Notes
47