2009 Financial Estimates
December 10, 2008
Investor & Public Relations | Norelle Lundy,Vice President | Nir Grossman,Senior Director | 713-507-6466 | ir@dynegy.com
This presentation contains statements reflecting assumptions, expectations, projections,
intentions or beliefs about future events that are intended as “forward-looking statements.” You
can identify these statements, including those relating to Dynegy’s 2009 financial estimates, by
the fact that they do not relate strictly to historical or current facts. Management cautions that
any or all of Dynegy’s forward-looking statements may turn out to be wrong. Please read
Dynegy’s annual, quarterly and current reports under the Securities Exchange Act of 1934,
including its 2007 Form 10-K and first quarter 2008 Form 10-Q, as amended, and second and
third quarter 2008 Forms 10-Q for additional information about the risks, uncertainties and
other factors affecting these forward-looking statements and Dynegy generally. Dynegy’s
actual future results may vary materially from those expressed or implied in any forward-
looking statements. All of Dynegy’s forward-looking statements, whether written or oral, are
expressly qualified by these cautionary statements and any other cautionary statements that
may accompany such forward-looking statements. In addition, Dynegy disclaims any
obligation to update any forward-looking statements to reflect events or circumstances after
the date hereof.
Non-GAAP Financial Measures: This presentation contains non-GAAP financial measures
including EBITDA, Adjusted EBITDA, Adjusted Cash Flow from Operations, Adjusted Free
Cash Flow and Adjusted Gross Margin. Reconciliations of these measures to the most directly
comparable GAAP measures are contained herein. To the extent required, statements
disclosing the utility and purposes of these measures are set forth in Item 2.02 to our Current
Report on Form 8-K filed with the SEC on December 10, 2008, which is available on our
website free of charge, www.dynegy.com.
Forward-looking Statements
Agenda
Bruce Williamson
Value Proposition
Industry Fundamentals
Commercial Strategy
Holli Nichols
Regional Overview
2009 Guidance Estimates and Sensitivities
Bruce Williamson
Strategic Outlook
Management Team
Q & A
Dynegy’s Value Proposition
Operate assets well
Capture commercial opportunities in
the near-term
Maintain an open commercial strategy
in outer years to capture longer term
market opportunities
Positioned to participate in industry
consolidation
Dynegy’s flexible capital structure allows
us to focus on operating and
commercializing assets well
Adjusted EBITDA expected to increase
~10% using midpoints from 2008 to 2009
Adjusted Free Cash Flow for 2009
essentially neutral after investing in
significant pollution control equipment,
protecting near-term cash flow
Dynegy is evaluating continued
participation in future development
activities
Protecting Value Today
Enhancing Value Tomorrow
Despite unprecedented economic times, we believe long-term power
generation market fundamentals remain unchanged
Dynegy has built a financial structure with ample liquidity, no significant debt
maturities before 2011, and bank and credit facilities scheduled to mature in
2012 and 2013, respectively, which positions us well to weather the current
market turbulence
Energy Economics – Global Energy Consumption
34%
Oil
24%
Natural Gas
28%
Coal
6%
Nuclear
8%
Renewables
World Total Energy Consumption by Fuel
Projected
Actual
Energy demand will continue to grow, utilizing all fuel types
Significant energy investments will be required to meet growing needs
Source: DOE/EIA
Energy Economics – U.S. Power Generation
Fuel Mix for U.S. Power Generation
4,153
4,722
Source: DOE/EIA
Coal
Natural Gas
Nuclear
Hydro/Renewable
Oil
Without significant investment in new infrastructure and technologies,
U.S. power generation fuel sources will remain essentially unchanged
Intensive capital requirements, rising costs and lengthy permitting process make construction
of new power generation facilities difficult in today’s financial and regulatory environment
Given that significant investments are not currently underway, it will likely take ~10-20 years
before a meaningful level of new baseload generation – of any technology – is operational
Therefore, in the near- to medium-term, where and how the U.S. generates power is likely
to remain relatively constant
49%
50%
18%
21%
19%
18%
1%
1%
10%
13%
Long-Term Power Generation Fundamentals
Supply: Continued Challenges
Construction Costs(1) ($/kW)
Demand is expected to continue to
grow over time
Energy efficiency improvements
expected to be offset by growth in
additional electricity demand
Demand: Continued Growth
U.S. Electric Consumption (MM MWh)
Generation supply is expected to
continue to tighten over time
Industry needs $1.2 trillion in capital
investments over next 15 years; $600
billion in new generation(2)
Barriers to entry remain high in a
capital intensive industry, likely causing
construction delays
Increased cost of construction
Challenging credit market
Regulatory uncertainty
(1) Construction costs are the midpoints of previously disclosed estimates and are based on various trade
publications and are intended solely as estimates. Actual cost estimates and actual cost of specific projects
may vary materially from these estimates. (2) Source: CERA
Data Source: EIA
U.S. Recessionary periods
Dynegy Expects Commodity Prices
to Continue to Rise Long-Term
CIN Hub On-Peak Prices ($/MWh)
Natural Gas Prices ($/MMBtu)
Despite historic and ongoing
volatility, commodity prices
continue to trend upward
Global demand for coal and
natural gas is expected to
continue to impact power prices
Note: Prices are historical monthly averages from brokered market indicators and NYMEX
Spark Spreads (Mass Hub vs TET M3 @ 7HR)
Commercial Strategy
Dynegy employs “Current +1” strategy based on
rationale that intra-year volatility can impact results
Intra-year volatility results from such events as weather
and commodity price spikes
Contracting in the “Current +1” years should bring
near-term stability against these uncertain events
and protect near-term cash flows
Typical commercial contracts include: heat rate call
options, bilateral contracts, tolling agreements, and
financial swaps
Longer term, we believe power market
fundamentals remain intact and demand will
outpace supply additions
As such, staying relatively open “+2 and Beyond”
provides opportunity to capture value in a
fundamentally rising price environment as supply/
demand tightens with no significant new generation
on the horizon
We believe our capital structure provides the “ultimate hedge”
Strong liquidity and minimal near-term debt maturities provide security as our “ultimate hedge” to
commercialize positions in volatile price environments
CIN Hub On-Peak Prices
Demonstrate Volatility ($/MWh)
Strategy Rationale
1
2
Midwest
West
Northeast
Commercial Strategy Differs by Region
Percent of Expected Adjusted Gross Margin Contracted by Year
Commercial strategy provides opportunity to capture rising price
trends but brings exposure to downside risks
Dynegy’s commercial strategy is tailored by region to match market opportunities
Dynegy expects to enter 2009 with ~60% of expected Adjusted Gross Margin
contracted on a consolidated basis through bilateral contracts, tolling agreements,
capacity agreements, financial forward sales and options
0%
20%
40%
60%
80%
100%
2009
2010
2011
0%
20%
40%
60%
80%
100%
2009
2010
2011
0%
20%
40%
60%
80%
100%
2009
2010
2011
58%
32%
12%
85%
85%
37%
52%
29%
26%
Contracted Open
10
Consolidated Portfolio
Going into 2009, Dynegy’s
expected Adjusted Gross Margin
is anticipated to be ~60% covered
by contractual arrangements
During 2009, we intend to monitor
commodity prices and seek to
capture additive short-term market
opportunities as they arise
Beyond 2010, portfolio is
essentially open – other than
structured transactions
Changes in market conditions or
contracted positions can impact
results both positively or
negatively
62%
20%
43%
Percent of Expected Adjusted
Gross Margin Contracted
Strong Liquidity is the Foundation for 2009
Dynegy maintained strong
liquidity during 2008
Strong liquidity and flexible capital
structure to manage collateral
requirements through market recovery
~$1.9 billion of liquidity as of 12/1/08
$300 million contingent facility available(1)
No significant debt maturities until 2011
Undrawn credit facility due 2012
Letter of credit facility due 2013
Highlights of 2009 Estimates
$825 million – $1 billion anticipated
Adjusted EBITDA, assuming:
$8/MMBtu natural gas
$61.50/MWh CIN Hub on-peak power
Adjusted Operating Cash Flow
essentially covers maintenance and
environmental capital needs which
protects liquidity position
Net Income of $(20) million – $85
million and Operating Cash Flow of
$360 million – $535 million
12
(1) Available in increments as 2009 natural gas strip increases above $13/MMBtu
2009 Estimates
and Regional Drivers
Holli Nichols
Executive Vice President & Chief Financial Officer
Regional Drivers:
Regional results are driven primarily by power prices, spark spreads and capacity markets
Longer-term results will be impacted by regulatory activities and environmental requirements
Performance Drivers:
Price
Cost
What to look for
Key Contracts
2009 Guidance Estimates
2009-2013 Capital
Expenditure Estimates
Regional Overviews
Dynegy’s diversified portfolio is focused in three key regions
5 facilities in
NY, ME & CT
~3,800 MW in
NYISO &
NEPOOL
9 facilities
located in
TX, GA, CA,
AZ & NV
~5,200 MW
primarily in
CAISO &
WECC
~540 MW in
Georgia
~300 MW
under
construction
in ERCOT
15 facilities in
IL, MI, PA, AR
& KY
~8,400 MW in
MISO & PJM
DYNEGY
Includes G&A, partially offset by
interest income
Corporate / Other
Power Generation
18,277 MW
Midwest
8,405 MW
Northeast
3,809 MW
West
6,063 MW
14
Performance Drivers
Price:
CIN Hub power price volatility
Spark spread for Kendall and Ontelaunee
Coal sets the marginal price 50-65% of the time in MISO
Natural gas sets the marginal price of power in PJM
Cost:
Fixed price PRB coal and rail contracts
Operating expense incorporates impact of investing in
pollution control equipment
Look For:
Capacity markets in MISO
Weather can impact volumes of CCGT fleet and absolute
price to coal fleet
Track CIN Hub to IL Hub basis differentials
Midwest – Primarily Baseload Coal
Regional Drivers
MISO – Outright power price for uncontracted baseload
volumes, and spark spread for uncontracted gas-fired
peaking units
PJM – Spark spread for uncontracted gas-fired
Capacity Markets – MISO capacity sold under bilateral
agreements; PJM capacity sold in forward auctions for
three years
345 – 470
Uncontracted Adjusted Gross Margin
$ 905 – 1,030
Adjusted Gross Margin
$ 560
Contracted Adjusted Gross Margin
(220) – (240)
Operating Expenses (1)
$ 685 – 790
Adjusted EBITDA
2009E
24.9 MM MWh
Generation Volumes
($MM)
$ 380 – 485
Operating Income
Going into 2009, ~ 60% Adjusted
Gross Margin contracted
Beyond 2009, Midwest portfolio is
substantially open
Note: Additional regional data provided in the Appendix. (1) Operating Expense excludes depreciation and amortization.
8,405 MW
15
Midwest – Key Contracts
100% of PRB coal supply is contracted through 2010, at largely fixed price
~35% of coal supply and price contracted for 2011 through 2012
Ten year transportation agreement with Burlington Northern through 2013
at attractive rates
2009 Average delivered coal cost at Baldwin is forecasted to be $1.49/MMBtu
Fuel Contracts:
Contracting activity primarily centers on the Midwest coal fleet
~1,200 MW CIN Hub On-Peak at an average price of $75/MWh, ~1,600 CIN Hub
Off-Peak MW at an average price of $38/MWh
200 MW Illinois auction contracted at ~$65/MWh expiring May 2009 (~50% load
factor)
Kendall Unit 3 (~ 280 MW) under tolling agreement to 2017 for ~$20 million
in 2009
Term capacity sales in place
PJM capacity auctions:
MISO capacity sales:
~1,100 MW bilateral capacity sales in place for 2009
Revenue
Contracts:
$ 174
~2,050
2010/2011
2011/2012
2009/2010
2008/2009
Auction Year
$ 110
~2,060
$ 191
~515
$ 102
~1,850
$ 112
~1,470
Auction Price
(~$/MW-day)
DYN MW cleared
West – Primarily Natural Gas
Regional Drivers
Spark spread for uncontracted gas-fired combined cycle
and peaking units, and ancillary services
California has no formal capacity auction market;
greater demand is expected for capacity in 2009 as
utilities will have increased Resource Adequacy
requirements
Operational performance since the majority of the plants
operate under term contracts
Performance Drivers
Price:
~2/3 of Adjusted Gross Margin is derived through
tolling agreements in the near-term
Regional spark spreads
Natural gas sets the marginal price of power
Cost:
Tolling counterparties take financial and delivery risk
for fuel during tolled periods
Fuel is purchased as needed at index related prices
Look For:
Spread variability mitigated by toll contracts
Weather can impact volumes of CCGT fleet
Note: Additional regional data provided in the Appendix. (1) Operating Expense excludes depreciation and amortization.
6,063 MW
35 – 65
Uncontracted Adjusted Gross Margin
$ 320 – 350
Adjusted Gross Margin
$ 285
Contracted Adjusted Gross Margin
(130) – (140)
Operating Expenses (1)
(5)
Loss from Unconsolidated Investments
$ 185 – 205
Adjusted EBITDA
2009E
11.4 MM MWh
Generation Volumes
($MM)
$ 90 – 110
Operating Income
Going into 2009, ~85% Adjusted
Gross Margin contracted
Heavily contracted in near-term
17
West – Key Contracts
Gas is transported to each facility via firm and interruptible
transportation agreements, primarily on El Paso, Transwestern or
PG&E pipelines
Tolling counterparty assumes fuel delivery risk associated with gas
requirements during tolled periods for tolled capacity
Fuel Contracts:
Tolling, RMR, Heat Rate Call Options and Capacity Agreements
Griffith: 570 MW Toll Jun-Sep thru 2017
Arlington: 560 MW Toll Jun-Sep 2010; May-Oct 2011-2019
Morro Bay: 650 MW Toll thru Sep 2013
Moss Landing 1 & 2: 750 MW Heat rate call option thru Sept 2010
Moss Landing 6 & 7: 1,500 MW Year round through 2010
Oakland: RMR year-to-year
South Bay: 700 MW Toll thru Dec 2009; RMR year-to-year
Heard: 500 MW Capacity contract thru Dec 2015
Revenue
Contracts:
18
Northeast – Diverse Fuel and Dispatch Type
(1)
Adjusted Gross Margin includes contract amortization from the Independence ConEd contract. See Appendix for more detail. (2) Operating Expense includes effects of Central Hudson
lease expense and excludes depreciation and amortization.
Regional Drivers
NYISO – Spark spread for uncontracted combined
cycle gas and fuel oil units, and outright power price for
uncontracted baseload coal volume
ISO-NE – Spark spread for uncontracted combined
cycle gas units
Capacity Markets – ISO-NE formal capacity market
auction for 2010/2011 occurred in February 2008.
2009 capacity contracted in 2006 during transition to
auction mechanism. NY Capacity market well developed
Performance Drivers
Price:
New York Zone G
Spark spreads for New York Zone C, New England
and Mass Hub
Natural gas sets the marginal price of power
Cost:
Increased South American coal costs driven by
increase in Central App and international coal prices
Implementation of RGGI at market rates
Look For:
Margin impact from volatile South American
coal costs
Weather can impact volumes of CCGT fleet
and Roseton
Spark spreads
3,809 MW
115 – 175
Uncontracted Adjusted Gross Margin
$ 270 – 330
Adjusted Gross Margin (1)
$ 155
Contracted Adjusted Gross Margin
(185) – (205)
Operating Expenses (2)
$ 85 – 125
Adjusted EBITDA
2009E
7.8 MM MWh
Generation Volumes
($MM)
$ 40 – 80
Operating Income
Going into 2009, ~50% Adjusted
Gross Margin contracted
Beyond 2009, portfolio is relatively
open – other than structured deals
19
Northeast – Key Contracts
Operating expense includes $50 million of Central Hudson lease
expense, and Operating Cash Flow includes cash lease
payments of $141 million in 2009
Coal (Danskammer):
One- to two-year contracts primarily sourced from South America
70% of coal supply priced for 2009, including delivery
Natural gas: Purchased on an as-needed basis
Fuel Oil (Roseton): Due to on-site storage availability of
1 MMBbls, fuel oil is purchased on an opportunistic basis
Fuel Contracts:
Other
Independence has a 740 MW capacity contract with ConEd (‘A’
Rated) through 2014; receive ~$100 million, net in cash but offset
by $50 million contract amortization in Adjusted Gross Margin
Danskammer has ~200 MW in power swaps at an average price
of ~$103/MWh on-peak and ~$73/MWh off-peak
Casco Bay and Bridgeport receive Forward Capacity Market
(FCM) payments from New England ISO
2009 Guidance includes ~900 MW of capacity sold
Heat Rate Call Options – Independence, 200 MW for ~$3.30/KW-
Mo; Casco Bay, 150 MW for ~$7/KW-Mo
Revenue
Contracts:
Anticipated Capital Expenditures (2009 – 2013)
5
15
20
25
25
Capitalized Interest
$ 50
$ 100
$ 55
$ 85
$ 85
Maintenance – Coal facilities
65
80
180
225
280
Environmental
$ 380
TBD
125
2011
$ 275
TBD
80
2012
$ 230
TBD
110
2013
($MM)
2009
2010
Maintenance – Other facilities
70
120
Discretionary Investment (1)
30
TBD
TOTAL
$ 490
$ 455
Environmental primarily includes Consent Decree and mercury reduction expenditures
Consent Decree spending on track for completion in 2012 with 25% of remaining costs fixed
Capitalized interest has historically been included in Maintenance but relates to both Maintenance
and Environmental capital expenditures
Discretionary investments will be determined opportunistically based on estimated project returns
(1) Discretionary investments are subject to change and target IRR ~15% or more.
Note: Plum Point development is excluded as Dynegy is evaluating participation in future development activities. Plum Point debt is fully financed on a non-recourse basis. Although Sandy
Creek is under construction, it is not included in capex as Sandy Creek is not consolidated. Sandy Creek is financed on a non-recourse basis.
Notes:
Adjusted EBITDA includes ~$50 million for Central Hudson lease expense while total cash payment is $141 million
Working capital / Non-cash adjustments / Other primarily reflects changes in Accounts Receivable/Accounts
Payable balances:
Adds back cash payment of ~$50 million in excess of revenues recognized related to the ConEd contract
Subtracts ~$90 million cash payment above Central Hudson lease expense
2009 Guidance
$ 1,000
$ –
$ 1,000
Contracted Adjusted Gross Margin
$ 1,495-1,710
$ –
$ 1,495-1,710
Adjusted Gross Margin (1)
495-710
–
495-710
Uncontracted Adjusted Gross Margin
(535)-(585)
–
(535)-(585)
Operating Expenses
(135)-(125)
(130)-(120)
(5)
G&A / Interest Income / Other
(280)
–
(280)
Environmental Capital Expenditures
($MM)
Generation
Other
TOTAL
Adjusted EBITDA (1)
$ 955-1,120
$ (130)-(120)
$ 825-1,000
Interest Payments
-
(415)
(415)
Cash Taxes
-
(15)
(15)
Working Capital / Non-cash Adjustments / Other
(40)
5
(35)
Adjusted Cash Flow from Operations (1)
$ 915-1,080
$ (555)-(545)
$ 360-535
Maintenance Capital Expenditures
(140)
(15)
(155)
Capitalized Interest
(25)
–
(25)
Adjusted Free Cash Flow (1)
$ 470-635
$ (570)-(560)
$ (100)-75
Plan includes assumptions of contracted positions as of 8/19/2008, which is representative of our current contracted portfolio, and commodity pricing based on
an $8.00/MMBtu forward gas curve
($MM)
2009 Guidance – GAAP Measures (1)
$ (60)
$ (390)
$ 360 – 535
$ (20) - 85
Net cash provided by operating activities
Net cash used in investing activities
Net income
Net cash used in financing activities
Note: Guidance estimates are forward-looking in nature; actual results may vary materially from these estimates. Plum Point and Sandy Creek are excluded from 2009 estimates.
(1) Not intended as a GAAP reconciliation, for a reconciliation please see the Appendix
22
Adjusted EBITDA
0
100
200
300
400
500
600
700
800
900
1,000
1,100
1,200
2008E (1)
Price/Volume
Capacity
Morro Bay
Toll
Other
OpEx
NE Coal
Kendall Toll
Midwest Coal
2009 Plan
Adjusted EBITDA 2008 to 2009 ($MM)
~$915
~$95
~$25
~$(60)
~$(40)
$840
~$105
~$(55)
~$25
~$(20)
Increase of ~10% based on 2009 Guidance midpoint of $825 – 1,000 million range
Estimated Range of
$825 – 1,000 million
(1) Estimate as presented November 6, 2008.
23
Adjusted Free Cash Flow 2008 to 2009 ($MM)
Adjusted Free Cash Flow Essentially Neutral
-100
-75
-50
-25
0
25
50
75
100
125
150
2008E
Adj.EBITDA Change
Interest Payments
Environmental
CapEx
Working Capital
Maintenance CapEx
2009 Plan
~$(10)
~$15
~$(80)
~$(10)
$25
~$75
~$(35)
2009 Adjusted Free Cash Flow essentially neutral based on midpoint
Adjusted Operating Cash Flow increases primarily due to higher
prices/volumes but is offset by greater environmental capital expenditures
Estimated Range of
$(100) – 75 million
(1)
(1) Estimate as presented November 6, 2008.
24
Things to Consider When Looking at the Future
Several factors, some of which are beyond our control, can impact
our business both positively and negatively – the outcome and
timing is difficult to predict
Often events and variables are interrelated and business impacts
are not always additive
Such uncertainties include:
Coal and fuel oil cost
In-market availability
Transmission availability or congestion
Weather
Power prices
Spark spreads
Capacity prices
Basis
Natural Gas Sensitivity
Primarily Impacts Baseload Coal
Sensitivities based on full-year estimates and assume natural gas price
change occurs for the entire year and entire portfolio
On-peak power prices are adjusted by holding the spark spread constant to
a 7,000 Btu/KWh heat rate
Off-peak prices are adjusted holding the market implied heat rate constant
Note: Uncontracted portfolio for longer term assumed for illustrative purposes only.
$ (280)
$ (140)
- $2.00
$ (145)
$ (70)
- $1.00
$ 165
$ 70
+ $1.00
$ 320
$ 140
+ $2.00
Longer Term Uncontracted
2009 ~60% Contracted
Change in Cost of
Natural Gas ($/MMBtu)
Adjusted Gross Margin Sensitivity ($MM)
$(70)
$85
$170
TOTAL
$(35)
$45
$85
Natural Gas
Coal/Fuel Oil
$(35)
- 500
$40
+ 500
$85
+ 1,000
Generation Adjusted Gross Margin
Sensitivity ($MM)
Market Implied
Heat Rate
Movement
(Btu/KWh)
2009 with ~60% Contracted
Sensitivities based on “on-peak” power price changes and full-year estimates
Assumes constant natural gas price of $8.00/MMBtu and heat rate changes are
for a full year
Increased run-time will result in increased maintenance costs, which are not
included in sensitivities
Market Implied Heat Rate
Sensitivities Impact Entire Fleet
Note: Spark spread value changes depend on natural gas price assumptions. Uncontracted portfolio for longer term assumed for illustrative purposes only.
$(135)
$175
$350
TOTAL
$(90)
$110
$225
Natural Gas
Coal/Fuel Oil
$(45)
- 500
$65
+ 500
$125
+ 1,000
Generation Adjusted Gross Margin
Sensitivity ($MM)
Market Implied
Heat Rate
Movement
(Btu/KWh)
Longer-Term: Uncontracted
2009 Adjusted EBITDA at Risk
2009 Adjusted EBITDA range: $825 million – $1 billion
“Current + 1” commercial strategy provides some margin stability
Opportunities exist to capture extrinsic value from weather, run-times or heat-rates
movements but cannot be contracted today, leaving margin at risk
On a consolidated basis, Dynegy expects to enter into 2009 with ~60% of its
expected Adjusted Gross Margin covered by contractual arrangements
Awareness, continuous evaluation, cultivating options and maintaining a
diverse portfolio are tools for managing uncertainties that can impact results
both positively and negatively, including:
Coal and fuel oil cost
In-market availability
Transmission availability or congestion
Weather
Power prices
Spark spreads
Capacity prices
Basis
Strategic Outlook
Bruce Williamson
Chairman, President & Chief Executive Officer
2008 Recap and 2009 Outlook
What Didn’t Go Well…
What Went Well…
What Dynegy Will Do…
2008 – The Year in Review
2009
Experienced significant forced
outages at Baldwin and Havana
Incurred higher costs due to
widening basis in the Midwest
caused by flooding and
transmission constraints, as well
as commercial execution at PJM
Increased South American coal
costs due to “price majeure”;
subsequently re-contracted
Experienced milder than
expected weather causing decreased volumes in the Midwest and Northeast
Achieved 90% in-market availability for baseload coal fleet as of 10/31/08
Created capital and credit structures
which mitigate exposure to market
turmoil
Maintained strong liquidity
Repriced PRB coal contracts,
achieving minimal increase in
cost through 2010 and locked
-in ~35% in 2011 and 2012
Entered into long-term tolling
agreements in the West,
providing predictable cash flow
Partially commercialized Midwest
at attractive on-peak prices
Sold Rolling Hills for ~$370
million in cash
Continue to focus on operating
assets well
Continue to maintain strong
liquidity
Improve execution to protect
near-term cash flow through
“Current + 1” commercial strategy
Work with coal suppliers to
further contract fuel price
Continued focus on managing
spending in rising cost
environment
30
Appendix
18,277 MW
Strategically Positioned Portfolio
Dispatch Diversity (1)
Peaking
45%
Intermediate
33%
Baseload
22%
Geographic Diversity (1)
Midwest
46%
Northeast
21%
West
33%
Fuel Diversity (1)
Combined Cycle
33%
Simple Cycle
36%
Total Gas-fired
69%
Coal
24%
Fuel Oil
7%
Note: Plum Point and Sandy Creek are currently under construction.
Sandy Creek and Plum Point are excluded from 2009 Guidance.
(1) Diversity percentages based on capacity, not actual volumes.
Located in 13 states –
serving regions that represent
~50% of total U.S. population
2009 Commodity Pricing Assumptions
* Represents annual average
Moss Landing, Morro Bay, Oakland
$73.88
NP-15 – California
Independence
$71.00
NY – Zone C
Roseton
$16.01
Fuel Oil #6 delivered to Northeast ($/MMBtu)
Danskammer
$5.83
South American delivered to Northeast
Baldwin
$1.49
Powder River Basin (PRB) delivered
Coal ($/MMBtu)
Arlington Valley, Griffith
$65.94
West – Palo Verde
South Bay
$74.38
SP-15 – California
Bridgeport, Casco Bay
$86.61
NE – Mass Hub
Roseton, Danskammer
$96.89
NY – Zone G
Midwest Coal, Midwest Peakers
$61.50
Cinergy
Ontelaunee
$73.50
PJM West
Kendall
$58.50
NI Hub / ComEd
Facilities
On-Peak Power ($/MWh)
$ 8.00
Natural Gas – Henry Hub ($/MMBtu)
2009E*
Key Assumptions
2009 Assumptions
Commodity pricing assumes
$8.00/MMBtu natural gas
Interest expense of ~$395 million and
Cash interest payments of ~$415
million
Plum Point and Sandy Creek are
excluded from 2009 Guidance
estimates
Resulting in net $265 million increase in
unrestricted cash from return of collateral
and decrease in restricted cash
Tax expense accrues at 40%; AMT
cash tax payment of $5 – 10 million
Expect to fully utilize federal NOLs in
2008
$260 million of AMT credits are
equivalent to approximately $750
million in federal NOLs
AMT credits reduce tax liability dollar-for-
dollar and do not expire
Other Assumptions
~$50 million annual amortization expense
included in Northeast EBITDA through
2014 related to ConEd contract; annual
capacity payment received of ~$100 million
Shares outstanding ~840 MM
Dynegy expected to become a partial cash
tax payer in 2012 after all AMT credits are
used and full year cash tax payer in 2013
Midwest Generation – Primarily Baseload Coal
$ 380 - 485
Operating Income
$ 685 - 790
Adjusted EBITDA
20 - 30
Peaking/Other (1)
2009
Midwest Forecast ($MM)
65 - 80
Combined Cycle
$ 600 - 680
Coal
$73.50
PJM West
Avg. Spark Spread
(PJM West vs TET M-3 @ 7HR)
$9.10
$9.20/MMBtu
Delivered Natural Gas
(TET M-3 + $0.05)
$(5.50)
On-Peak
Avg Gen to
CIN Hub Basis
($/MWh)
$3.18
PJM
Avg. Spark Spread
(NI Hub vs CHI CG @ 7HR)
$1.66
$1.49/MMBtu
Delivered PRB Coal (Baldwin)
0% - 10%
Peaking
10% - 20%
CC
70% - 90%
Baseload
Annual
Average
Capacity
Factors
$58.50
NI Hub
$61.50
CIN Hub
Power Prices
(Average on peak
prices $/MWh)
$(3.50)
Off-Peak
MISO
10,000 – 12,000
Peaking
7,000 – 8,000
CC
Baseload
Forecasted Fundamentals 2009
$1.90
Average
Capacity Price
(KW-Mo)
$8.12/MMBtu
Delivered Natural Gas
(CHI CG + $0.10)
10,000 – 11,000
Fleet Heat
Rate (2)
(Nameplate
Btu/KWh)
24.9
Volumes (MM MWh)
(1) Other comprised of ancillary services, emission credit sales and amortization of
intangibles and trading. (2) Nameplate Heat Rate is after adjustment for generating
starts & stops, weather, fuel types, efficiencies and other operational components.
Unlike PJM, the MISO capacity
market is not liquid in the outer years
But average MISO capacity payments
tend to follow PJM capacity payment
trends for the longer timeframe
35
West Generation – Primarily Natural Gas
0% - 20%
Peaking
30% - 60%
CC
n/a
Baseload
Annual
Average
Capacity Factors
Avg. Spark Spread (NP15 vs PG&E @ 7HR)
$16.02
$65.94
Palo Verde
$73.88
NP-15
Power Prices
(Average on-peak prices
$/MWh)
System RA $0.50 - $1.50
9,500 – 10,500
Peaking
7,000 – 7,200
CC
Baseload
Forecasted Fundamentals 2009
Avg. Capacity
Price (KW-Mo)
$8.26/MMBtu
Delivered Natural Gas (PG&E + $0.30)
n/a
Fleet Heat Rate (2)
(Nameplate, Btu/KWh)
11.4
Volumes (MM MWh)
$ 185 - 205
Adjusted EBITDA
35 - 45
Peaker/RMR/Other (1)
West Forecast ($MM) 2009
$ 90 - 110
Operating Income
$ 150 - 160
Combined Cycle
(1) Other comprised of ancillary services, emission credit sales, equity earnings(losses) and amortization of intangibles and trading. (2) Nameplate Heat Rate is after adjustment for
generating starts & stops, weather, fuel types, efficiencies and other operational components.
85% of West portfolio is contracted
for 2009 and 2010, therefore near-
term regional results should not
have much variability
Northeast Generation – Coal, Fuel Oil & Natural Gas
Other noteworthy items:
Operating expense includes $50 million
of Central Hudson lease expense, and
Operating Cash Flow includes cash
lease payments of $141 million in 2009
Independence under capacity
agreement with ConEd expiring 11/2014
Adjusted EBITDA includes approximately
$50 million net earnings, however Adjusted
Cash Flow from Operations will include cash
receipt of approximately $100 million in 2009
Carbon emissions include a cost
assumption of ~$3.00/MT for CO2
allowances associated with RGGI
$9.40
Gas (NY Zone C vs Dawn @ 7HR)
$8.80/MMBtu
Delivered Natural Gas (Dawn + $0.35)
$9.87/MMBtu
Delivered Natural Gas (Tran Z6 – NY)
$3.95
$2.49
0% - 10%
20% - 50%
75% - 85%
Peaking
$17.53
Gas (Mass Hub vs TRAN Z6-NY @ 7HR)
($79.17)
Fuel Oil (NY-G vs #6 Oil @11HR)
Avg.
Spark
Spread
CC
Baseload
Annual
Average
Capacity Factors
$5.83/MMBtu
$16.01/MMBtu
SA Coal
$86.61
Mass Hub
$71.00
NY Zone C
$96.89
NY Zone G
Power Prices
(Average on peak
prices $/MWh)
New England
NYISO
9,500 – 10,500
Peaking
7,000 – 8,000
CC
Baseload
Forecasted Fundamentals 2009
Average
Capacity Price
(KW-Mo)
Fuel Oil #6
Delivered Fuel
10,000 – 11,000
Fleet Heat
Rate (2)
(Nameplate,
Btu/KWh)
7.8
Volumes (MM MWh)
$ 40 - 80
Operating Income
$ 85 - 125
Adjusted EBITDA
(10) - 0
Peaking/Other (1)
2009
Northeast Forecast ($MM)
95 - 120
Combined Cycle
$ 0 - 5
Coal
(1) Other comprised of ancillary services, emission credit sales and amortization of intangibles and trading. (2) Nameplate Heat Rate is after adjustment for generating starts & stops,
weather, fuel types, efficiencies and other operational components.
$75
$35
$56
$131
$104
$115
$127
$57
$66
$60
$56
$48
$38
$28
$16
$48
0
25
50
75
100
125
150
175
200
2009
2010
2011
2012
2013
2014
2015
2016 - 2035
Imputed Interest
Imputed Debt Equivalent
Central Hudson Lease – Northeast Segment
Accrual Lease Expense
2009 Central Hudson treated as Debt
(would require the following adjustments to GAAP financials):
Income Statement – Add back $50 million lease expense to Adjusted EBITDA; add
$66 million imputed interest expense to Interest Expense; add $23 million estimated
depreciation & amortization expense; adjust tax expense for net difference
Depreciation & Amortization calculated using purchase price of $920 million divided by 40
years
Cash Flow Statement – Add back $75 million of imputed principal to Operating
Cash Flows
$141 million cash payment split between $66 million imputed interest payment (Operating
Cash Flows) and $75 million imputed principal payment (Financing Cash Flows)
Balance Sheet – Include $700 million total PV (10%) of future lease payments
2009 Central Hudson treated as Lease
(as currently shown in GAAP financials):
Income Statement – $50 million lease expense included
in Adjusted EBITDA; no interest expense or depreciation
& amortization expense
Cash Flow Statement – $141 million cash payment
included in Operating Cash Flows
Balance Sheet – lease obligation not included in debt
balance
Central Hudson Cash Payments
(remaining as of 12/31/08, $MM)
$141
$95
$112
$179
$142
$143
$143
$105
Imputed Debt Equivalent at PV(10%)
of future lease payments = $700 MM(1)
(1) PV of payments calculated as of 12/31/08
Chart represents total cash lease payments, which are included in Operating Cash Flows
Lease expense is approximately $50 million per year and included in Operating Expense
38
Dynegy is Financially Well Positioned
Pro-Forma
Debt Maturity Profile (As of 12/31/08, $MM)
Liquidity Profile ($MM)
No significant debt maturities until 2011
Undrawn facility due 2012
Bank debt is at LIBOR + 150 bp
Weighted average cost of debt at 7.5%
No significant restrictive covenants
$58
$63
$569
$576
$0
$550
$2,697
$999
0
500
1,000
1,500
2,000
2,500
3,000
2009
2010
2011
2012
2013
2014
2015
2016+
On balance sheet debt profile = $5.5 B
Strong liquidity position as of Dec.1
~$1.9 billion in liquidity
~$684 million of cash-on-hand
$300 million contingent facility available
Limited uncollateralized credit exposure
to financial counterparties
$328
$429
$271
$750
$684
$1,121
$1,056
$619
$1,180
$1,166
0
500
1,000
1,500
2,000
2,500
3,000
Dec-31-07
Mar-31-08
Jun-30-08
Sep-30-08
Dec-01-08
Cash
Availability
Contingent facility
$1,850
$1,449
$1,485
$890
$1,930
(2)
(1)
Under terms of our contingent letter of credit facility, up to $300 million capacity can become available based on forward natural gas prices rising above $13/MMBtu for 2009
(2)
Lehman Commercial Paper Inc. filed for bankruptcy in October 2008 thus reducing the available capacity of our Revolving Facility by $70 million
(1)
39
Pro Forma Debt & Other Obligations Capital Structure –
Expected as of 12/31/08
Dynegy Power Corp.
Central Hudson(1) $700
Dynegy Holdings Inc.
$1,080 Million Revolver $0
Term L/C Facility $850
Tranche B Term $69
Sr. Unsec. Notes/Debentures $4,047
Sub.Cap.Inc.Sec (“SKIS”) $200
Secured = $919
Key:
Secured Non-Recourse = $344
Unsecured = $4,947
Dynegy Inc..
Senior Debentures $344
NOTE: Capital Structure excludes debt associated with the Plum Point development project.
(1) Represents PV (10%) of future lease payments. Central Hudson lease payments are unsecured obligations of Dynegy Inc., but are a secured obligation of an unrelated third party (“lessor”) under the lease. DHI has guaranteed the lease payments on a senior unsecured basis. (2) Restricted cash includes $850MM related to the Synthetic Letter of Credit facility. Sandy Creek is excluded from Guidance, therefore $275 million has been reclassified from Restricted Cash to Unrestricted Cash. (3) Net Debt & Other Obligations and Net Debt are non-GAAP financial measures; for definitions and uses of such measures please see refer to Item 2.02 of our 8-K filed December 10, 2008.
($ MM)
Sithe Energies
($ Million)
12/31/08E
Total Obligations
$6,210
Less: Cash on hand & Investments
930
Less: Restricted cash (2)
850
Net Debt & Other Obligations (3)
$4,430
Less: Central Hudson Lease Obligation
700
Net Debt (3)
$3,730
40
Significant Environmental Progress
On target to further reduce emissions in the Midwest
Major Assumptions
Estimate of remaining spend is $660 – $710 million
for a total investment of $940 – $990 million
Approximately 25% of remaining costs are firm
Labor and material prices are assumed to escalate
at 4% annually
All projects include installing baghouses and
scrubbers with the exception of Hennepin and
Vermilion, which have baghouses only
Labor
56%
Rental Equipment
& Other 8%
Cost Composition
Materials
36%
2008
2010
2009
2011
2012
2007
Vermilion
Hennepin
Baldwin 3
Baldwin 1
Baldwin 2
Havana
Reg G Reconciliation – 2009 Guidance
Contracted Adjusted Gross Margin
560
$
560
$
285
$
285
$
155
$
155
$
1,000
$
1,000
$
-
$
-
$
1,000
$
1,000
$
Uncontracted Adjusted Gross Margin
345
470
35
65
115
175
495
710
-
-
495
710
Adjusted Gross Margin (2) (3)
905
$
1,030
$
320
$
350
$
270
$
330
$
1,495
$
1,710
$
-
$
-
$
1,495
$
1,710
$
Operating Expenses
(220)
(240)
(130)
(140)
(185)
(205)
(535)
(585)
-
-
(535)
(585)
General and administrative expense
-
-
-
-
-
-
-
-
(185)
(175)
(185)
(175)
Losses from unconsolidated investments
-
-
(5)
(5)
-
-
(5)
(5)
-
-
(5)
(5)
Other items, net
-
-
-
-
-
-
-
-
55
55
55
55
Adjusted EBITDA (2) (3)
685
$
790
$
185
$
205
$
85
$
125
$
955
$
1,120
$
(130)
$
(120)
$
825
$
1,000
$
(1)
(2)
This presentation is not intended to be a reconciliation of non-GAAP measures persuant to Reg G; please see below for such reconciliations.
(3)
Operating income (loss)
380
$
485
$
90
$
110
$
40
$
80
$
510
$
675
$
(195)
$
(185)
$
315
$
490
$
Losses from unconsolidated investments
-
-
(5)
(5)
-
-
(5)
(5)
-
-
(5)
(5)
Other items, net
-
-
-
-
-
-
-
-
55
55
55
55
Add: Depreciation and amortization expense
230
230
85
85
55
55
370
370
10
10
380
380
EBITDA
610
$
715
$
170
$
190
$
95
$
135
$
875
$
1,040
$
(130)
$
(120)
$
745
$
920
$
Plus / (Less):
Mark-to-market
75
75
15
15
(10)
(10)
80
80
-
-
80
80
Adjusted EBITDA
685
$
790
$
185
$
205
$
85
$
125
$
955
$
1,120
$
(130)
$
(120)
$
825
$
1,000
$
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
#REF!
Contracted Adjusted Gross Margin
560
$
560
$
285
$
285
$
155
$
155
$
1,000
$
1,000
$
-
$
-
$
1,000
$
1,000
$
Uncontracted Adjusted Gross Margin
345
470
35
65
115
175
495
710
-
-
495
710
Adjusted Gross Margin
905
$
1,030
$
320
$
350
$
270
$
330
$
1,495
$
1,710
$
-
$
-
$
1,495
$
1,710
$
Mark-to-market
(75)
(75)
(15)
(15)
10
10
(80)
(80)
-
-
(80)
(80)
Operating Expenses
(220)
(240)
(130)
(140)
(185)
(205)
(535)
(585)
-
-
(535)
(585)
Depreciation and amortization expense
(230)
(230)
(85)
(85)
(55)
(55)
(370)
(370)
(10)
(10)
(380)
(380)
General and administrative expense
-
-
-
-
-
-
-
-
(185)
(175)
(185)
(175)
Operating income (loss)
380
$
485
$
90
$
110
$
40
$
80
$
510
$
675
$
(195)
$
(185)
$
315
$
490
$
Net Income (Loss)
(20)
$
85
$
Add Back:
Income tax expense
(10)
60
Interest expense
395
395
Depreciation and amortization expense
380
380
EBITDA
745
$
920
$
Plus / (Less):
Mark-to-market
80
80
Adjusted EBITDA
825
$
1,000
$
Total
OTHER
Total
2009 EARNINGS ESTIMATES (1)
(IN MILLIONS)
GEN - MW
GEN - WE
GEN - NE
Total GEN
2009 estimates are based on forward commodity price curves using an $8/MMBtu gas price. Actual results may vary materially from these estimates based on changes in commodity prices, among other things,
including operational activities, legal settlements, financing or investing activities and other uncertain or unplanned items. Reduced 2009 and forward adjusted EBITDA could result from potential divestitures of (a)
non-core assets where the earnings potential is limited, or (b) assets where the value that can be captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets.
Divestitures could also result in impairment charges.
EBITDA, Adjusted EBITDA and Adjusted Gross Margin are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on December 10, 2008 for definitions, utility and uses of such non-GAAP
financial measures. Reconciliations of consolidated EBITDA and Adjusted EBITDA to Net Income and Adjusted Gross Margin to Operating income (loss) are presented below. Management does not allocate
interest expenses and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. Accordingly, a reconciliation of EBITDA and Adjusted EBITDA
to Operating income (loss) on a segment level is also presented below.
GEN - MW
GEN - WE
GEN - NE
Power Generation
Power Generation
Total
Total GEN
OTHER
Power Generation
Total
OTHER
GEN - WE
GEN - NE
Total GEN
GEN - MW
42
Reg G Reconciliation – 2009 Guidance (cont.)
Adjusted EBITDA (2) (3)
955
$
1,120
$
(130)
$
(120)
$
825
$
1,000
$
Cash Interest Payments
-
-
(415)
(415)
(415)
(415)
Cash Tax Payments
-
-
(15)
(15)
(15)
(15)
Collateral
-
-
-
-
-
-
Working Capital / Other Changes
(40)
(40)
5
5
(35)
(35)
Adjusted Cash Flow from Operations (3) (4)
915
1,080
(555)
(545)
360
535
Maintenance Capital Expenditures
(140)
(140)
(15)
(15)
(155)
(155)
Environmental Capital Expenditures
(280)
(280)
-
-
(280)
(280)
Capitalized Interest
(25)
(25)
-
-
(25)
(25)
Adjusted Free Cash Flow (3) (4)
470
$
635
$
(570)
$
(560)
$
(100)
$
75
$
Net cash used in Investing Activities
$ (390)
$ (390)
Net cash provided by Financing Activities
$ (60)
$ (60)
-
-
-
-
-
-
(1)
(2)
(3)
(4)
915
$
1,080
$
(555)
$
(545)
$
360
$
535
$
Maintenance capital expenditures
(140)
(140)
(15)
(15)
(155)
(155)
Environmental capital expenditures
(280)
(280)
-
-
(280)
(280)
Capitalized Interest
(25)
(25)
-
-
(25)
(25)
Adjusted Free Cash Flow
470
$
635
$
(570)
$
(560)
$
(100)
$
75
$
* Note that Cash Flow from Operations and Adjusted Cash Flow from Operations are the same amount in our 2009 Cash Flow Estimates.
Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on December 10, 2008 for definitions, utility and uses of such
non-GAAP financial measures. Please see 2009 Earnings Estimates for a reconciliation of Adjusted EBITDA to Net Income.
This presentation is not intended to be a reconciliation of non-GAAP measures pursuant to Regulation G.
Adjusted Cash Flow from Operations and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on
December 10, 2008 for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of Adjusted Cash Flow from Operations and
Adjusted Free Cash Flow to Cash Flow from Operations is presented below.
Cash Flow from Operations and Adjusted Cash Flow
from Operations (*)
GEN
OTHER
Total
2009 estimates are based on forward commodity price curves using an $8/MMBtu gas price. Actual results may vary materially from these estimates based on
changes in commodity prices, among other things, including operational activities, legal settlements, financing or investing activities and other uncertain or
unplanned items. Reduced 2009 and forward adjusted free cash flow could result from potential divestitures of (a) non-core assets where the earnings potential is
limited, or (b) assets where the value that can be captured through a divestiture is believed to outweigh the benefits of continuing to own or operate such assets.
(IN MILLIONS)
2009 CASH FLOW ESTIMATES (1) (3)
GEN
OTHER
Total
43
Reg G Reconciliation – 2008 Guidance
GEN - MW
GEN - WE
GEN - NE
Total GEN
OTHER
Total
Net Income
195
$
add back:
Income tax expenses
120
Interest expense
430
Deppreciation and amortization expense
380
EBITDA (2)
832
$
229
$
137
$
1,198
$
(73)
$
1,125
$
Plus/(less):
Release of state franchise tax and sales tax liabilities
-
-
-
-
(16)
(16)
Gain on liquidation of foreign entity
-
-
-
-
(26)
(26)
Gain on sale of NYMEX shares
-
-
-
-
(15)
(15)
Gain on sale of Sandy Creek ownership interest
-
(13)
-
(13)
-
(13)
Gain on sale of Oyster Creek ownership interest
-
(11)
-
(11)
-
(11)
Gain on sale of Rolling Hills
(57)
-
-
(57)
-
(57)
Mark-to-market
(105)
(45)
3
(147)
-
(147)
Adjusted EBITDA (2)
670
$
160
$
140
$
970
$
(130)
$
840
$
GEN
OTHER
TOTAL
Adjusted EBITDA (2)
970
$
(130)
$
840
$
Cash Interest Payments
-
(430)
(430)
Cash Tax Payments
-
(15)
(15)
Collateral
(15)
-
(15)
Working Capital/Other Changes
(25)
40
15
Adjusted Cash Flow from Operations (4)
930
(535)
395
Maintenance Capital Expenditures
(155)
(15)
(170)
Environmental Capital Expenditures
(200)
-
(200)
Adjusted Free Cash Flow (4)
575
$
(550)
$
25
$
Net cash used in investing Activities
(170)
$
Net cash provided by Financing Activities
150
$
(1)
(2)
GEN - MW
GEN - WE
GEN - NE
Total GEN
OTHER
Total
Operating income (loss)
617
$
132
$
77
$
826
$
(146)
$
680
$
Losses from unconsolidated investments
-
(8)
-
(8)
(11)
(19)
Other items, net
-
5
5
10
74
84
Add: Depreciation and amortization expense
215
100
55
370
10
380
EBITDA
832
$
229
$
137
$
1,198
$
(73)
$
1,125
$
(3)
(4)
GEN
OTHER
TOTAL
Cash Flow from Operations
920
$
(550)
$
370
$
Legal and regulatory payments
10
15
25
Adjusted Cash Flow from Operations
930
(535)
395
Maintenance capital expenditures
(155)
(15)
(170)
Environmental capital expenditures
(200)
-
(200)
Adjusted Free Cash Flow
575
$
(550)
$
25
$
Adjusted Cash Flow from Operations and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 6, 2008 for definitions, utility and
uses of such non-GAAP financial measures. A reconciliation of Adjusted Cash Flow from Operations and Adjusted Free Cash Flow to Cash from Operations is presented below.
2008 CASH FLOW ESTIMATES (1) (3)
(IN MILLION)
Power Generation
2008 estimates are based on quoted forward commodity price curves as of October 7, 2008. Actual results may vary materially from these estimates based on changes in commodity prices, among
other things, including operational activities, legal settlements, financing or investing activities and other uncertain or unplanned items. Reduced 2008 and forward EBITDA or free cash flow could result
from potential divestitures of (a) non-core assets where the earnings potential is limited, or (b) assets where the value that can be captured through a divestiture is believed to outweigh the benefits of
continuing to won or operate such assets. Divestitutures could also result in impairment charges.
EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 6, 2008 for definitions, utilities and uses of such non-GAAP financial
measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expenses and income taxes on segment level and therefore uses
Operating income (loss) as the most directly comparable GAAP measure.
This presentation is not intended to be a reconciliation of non-GAAP measures pursuant to Regulation G.
2008 EARNINGS ESTIMATES (1)
(IN MILLIONS)
Power Generation
As presented November 6, 2008
44
Generation Assets – Midwest & Northeast
Net
Primary
Dispatch
Region/Facility(1)
Location
Capacity(2)
Fuel Type
Type
Region
MIDWEST
Baldwin
Baldwin, IL
1,800
Coal
Baseload
MISO
Havana
Units 1-5
Havana, IL
228
Oil
Peaking
MISO
Unit 6
Havana, IL
441
Coal
Baseload
MISO
Hennepin
Hennepin, IL
293
Coal
Baseload
MISO
Oglesby
Oglesby, IL
63
Gas
Peaking
MISO
Stallings
Stallings, IL
89
Gas
Peaking
MISO
Tilton
Tilton, IL
188
Gas
Peaking
MISO
Vermilion
Units 1-2
Oakwood, IL
164
Coal/Gas
Baseload
MISO
Unit 3
Oakwood, IL
12
Oil
Peaking
MISO
Wood River
Units 1-3
Alton, IL
119
Gas
Peaking
MISO
Units 4-5
Alton, IL
446
Coal
Baseload
MISO
Kendall
Minooka, IL
1,200
Gas - CCGT
Intermediate
PJM
Ontelaunee
Ontelaunee Township, PA
580
Gas - CCGT
Intermediate
PJM
Rocky Road(3)
East Dundee, IL
330
Gas
Peaking
PJM
Riverside/Foothills
Louisa, KY
960
Gas
Peaking
PJM
Renaissance
Carson City, MI
776
Gas
Peaking
MISO
Plum Point(4)
Osceola, AR
140
Coal
Baseload
SERC
Bluegrass
Oldham County, KY
576
Gas
Peaking
SERC
Midwest Combined
8,405
NORTHEAST
Independence
Scriba, NY
1,064
Gas - CCGT
Intermediate
NYISO
Roseton(5)
Newburgh, NY
1,185
Gas/Oil
Peaking
NYISO
Bridgeport
Bridgeport, CT
527
Gas - CCGT
Intermediate
ISO-NE
Casco Bay
Veazie, ME
540
Gas - CCGT
Intermediate
ISO-NE
Danskammer(5)
Units 1-2
Newburgh, NY
123
Gas/Oil
Peaking
NYISO
Units 3-4
Newburgh, NY
370
Coal/Gas
Baseload
NYISO
Northeast Combined
3,809
45
Generation Assets – West & Notes
Region/Facility(1)
Location
Net
Capacity(2)
Primary
Fuel Type
Dispatch
Type
Region
WEST
Moss Landing
Units 1-2
Monterrey County, CA
1,020
Gas - CCGT
Intermediate
CAISO
Units 6-7
Monterrey County, CA
1,509
Gas
Peaking
CAISO
Morro Bay
(6)
Morro Bay, CA
650
Gas
Peaking
CAISO
South Bay
Chula Vista, CA
706
Gas
Peaking
CAISO
Oakland
Oakland, CA
165
Oil
Peaking
CAISO
Arlington Valley
Arlington, AZ
585
Gas - CCGT
Intermediate
WECC
Griffith
Golden Valley, AZ
558
Gas - CCGT
Intermediate
WECC
Heard County
Heard County, GA
539
Gas
Peaking
SERC
Black Mountain
(7)
Las Vegas, NV
43
Gas
Baseload
WECC
Sandy Creek
(8)
Waco, TX
288
Coal
Baseload
ERCOT
West Combined
6,063
TOTAL DYNEGY GENERATION
18,277
(8) Under construction. The DYN/LS Power Group joint venture owns 64% of this facility. DYN owns a 50% interest in the joint venture and the remaining 50% interest is held by LS Power Group. Total generating capacity of this facility is 900MW. Together, DYN and LS Power Group own 64% of this facility.
(7) DYN owns a 50% interest in this facility and the remaining 50% interest is held by Chevron.
(1) DYN owns 100% of each unit listed except as otherwise indicated. For each unit in which DYN owns less than a 100%
(2) Unit capabilities are based on winter capacity.
(5) DYN entered into a $920 MM sale-leaseback transaction for the Roseton facility and units 3 and 4 of the Danskammer facility in 2001. Cash lease payments extend until 2029 and include $108 MM in 2007, $144 MM in 2008, $141 MM in 2009, $95 MM in 2010 and $112 MM in 2011. GAAP lease payments are $50.5 MM through 2030 and decrease until last GAAP lease payment in 2035.
(4) Under construction.
(3) Excludes 28 MW for Unit 3, which is not available during cold weather due to winterization requirements.
(6) Represents operating capacity of units 3 and 4. Units 1 and 2, with a combined net generating capacity of 352 MW, are currently in layup status and out of operation.
46