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CALPINE CORPORATION
    Second Quarter 2008
      Earnings Results

      August 11, 2008
Safe Harbor Statement

Forward-Looking Statements
The information contained in this presentation includes certain estimates, projections and other forward-looking
information that reflect Calpine’s current views with respect to future events and financial performance. These
estimates, projections and other forward-looking information are based on assumptions that Calpine believes, as
of the date hereof, are reasonable. Inevitably, there will be differences between such estimates and actual
results, and those differences may be material.

There can be no assurance that any estimates, projections or forward-looking information will be realized.

All such estimates, projections and forward-looking information speak only as of the date hereof. Calpine
undertakes no duty to update or revise the information contained herein.

You are cautioned not to place undue reliance on the estimates, projections and other forward-looking
information in this presentation as they are based on current expectations and general assumptions and are
subject to various risks, uncertainties and other factors, including those set forth in Calpine’s Form 10-K for the
fiscal year ended December 31, 2007, Calpine’s Quarterly Reports filed on Form 10-Q for the periods ended
March 31, 2008 and June 30, 2008, and in other documents that Calpine files with the SEC. Many of these risks,
uncertainties and other factors are beyond Calpine’s control and may cause actual results to differ materially
from the views, beliefs and estimates expressed herein. Calpine’s reports and other information filed with the
SEC, including the risk factors identified in its Annual Report on Form 10-K for the year ended December 31, 2007
and in its Quarterly Reports on Form 10-Q for the periods ended March 31, 2008 and June 30, 3008, can be found
on the SEC’s website at www.sec.gov and on Calpine’s website at www.calpine.com.

Reconciliation to GAAP Financial Information                                                     1
The following presentation includes certain “non-GAAP financial measures” as defined in Regulation G under
the Securities Exchange Act of 1934. A schedule is attached hereto that reconciles the non-GAAP financial
measures included in the following presentation to the most directly comparable financial measures calculated
and presented in accordance with Generally Accepted Accounting Principles.


                                                                                                                      1
Agenda


• Opening Remarks     Bill Patterson, Chairman

• Calpine Update      Todd Filsinger, Interim COO

• Operations Review   Todd Filsinger, Interim COO

• Financial Review    Zamir Rauf, Interim CFO

• Conclusion          Zamir Rauf, Interim CFO

• Q&A




                                        2




                                                    2
CALPINE UPDATE




                 3




                     3
Calpine is a unique independent power producer…

                   Calpine is the nation’s largest baseload renewable, natural gas
                   Calpine is the nation’s largest baseload renewable, natural gas
                                  and cogeneration power provider.
                                   and cogeneration power provider.



Most Geographically Diversified Among Large IPPs                                                                        Most Generation Among Large IPPs

                                                                                                       100,000
                      North                                                                             90,000
                    2,822 MW            Southeast                                                       80,000
                       12%              6,254 MW




                                                                           Total MWh Generated (000)
                                                                                                        70,000
                                           26%
                                                                                                        60,000
               West
                                                                                                        50,000
            7,246 MW
                                                                                                        40,000
               30%                  Texas
                                                                                                        30,000
                                  7,487 MW
                                     32%                                                                20,000

                                                                                                        10,000


                                                                                                                  CPN             NRG           DYN              RRI           MIR
                                                                                                                                                             4
                             Total                                                                                         Coal   Nuclear   Natural Gas   Geothermal   Other
                          23,809 MW
                           77 Plants
    Note: Represents Calpine’s net ownership including peaking capacity.                                         Source: Energy Velocity, CEMS domestic data (2007) and company data.




                                                                                                                                                                                        4
…well-positioned to respond to anticipated
 environmental regulations

        Lowest SO2 Emissions/MWh Among Large IPPs                                                         Lowest NOx Emissions/MWh Among Large IPPs
                                                                                                                             2.78
                       16.33                                                                                                              2.66

                               14.33




                                                                                                           NOx (lbs / MWh)
      SO2 (lbs /MWh)




                                                                                                                                                 1.49


                                                                                                                                                            1.01
                                            5.03
                                                                    4.04


                                                                                                                                                                   0.23
                                                                                   0.01

                                                                                                                             MIR          RRI    NRG        DYN    CPN
                       MIR      RRI         NRG                     DYN            CPN


                                                                    Lowest CO2 Emissions/MWh Among Large IPPs
                                                                           2,115
                                                                                          1,931   1,924         1,917
                                                   CO2 (lbs /MWh)




                                                                                                                                                        5
                                                                                                                                    904




                                                                           NRG             RRI    DYN                  MIR          CPN
Source: Energy Velocity, CEMS data (2007)
                                                                                                                                                                          5
Calpine has made significant progress in its first full
quarter post-emergence


Operations
• Deep bench of talent

• Organizationally integrated commercial and power operations

• Improved safety record across fleet

• Increased fleet utilization

Financial
• Improved Commodity Margin and Adjusted EBITDA over prior year for second
   quarter and year-to-date

• Continued efforts to optimize capital structure through refinancing of Metcalf
  project debt and preferred interests

• Added liquidity sources to support hedging activities                  6




                                                                                   6
OPERATIONS REVIEW




                    7




                        7
Calpine’s assets are well located and well positioned


 Calpine is…

 • Present in markets with tight supply/demand conditions

 • Poised to benefit from anticipated environmental regulations

 • Well-positioned to respond to wind capacity additions in ERCOT

 • Favorably situated with respect to increasing replacement costs for power
   generation nationwide

 • Less sensitive to earnings impacts from fluctuating natural gas prices

 • Environmentally friendly with largest geothermal resource in U.S.


                                                                            8




                                                                                8
Calpine primarily operates in areas with tight
reserve margins

• Reserve margins have been declining in much of the U.S.
   - Majority of Calpine’s capacity is located in markets that currently have
      relatively tight reserve margins
                                                                                                                        NEPOOL



                                                    Northwest1
                                                                                                                 NYPP2
                                                                                           MISO                                  Capacity Deficit
                                                                               MRO

                                                                                                                PJM3
                               California1                           CO-WY

                                                                                     SPP
                                                                                                     TVA        VACAR
                                                                                                                                 Capacity Surplus
                                                          AZ-NM-SV
                                                                                           Entergy
                                                                                                     Southern

                                                                             ERCOT
                                                                                                                          FRCC




• Markets with tight supply and demand conditions often display price spikes and
  improved bilateral contract opportunities
                                                                                                                                       9
• Calpine expects market conditions to continue to support spark spreads and
  create the need for new capacity – positive factors for Calpine
 Supply in the Northwest and California varies according to hydro conditions.
1

 NYPP excludes NYLI and NY-in city.
2

The degree of overbuild does not reflect potential local transmission constraints.
Source: PA Consulting Group.
                                                                                                                                                    9
Calpine is poised to benefit from anticipated
environmental regulations


                                                                                               Sample Impact on Green Spreads (Geysers)
Sample Impact on Spark Spreads (Combined Cycle)



                                                                                                                          $8.34                                   $16.67


                                                                     $2.46        $9.30

                                                                                                             $8.34
                                                        $2.46

                                      $2.19

                    $2.19




                                                                                              No CO2       $15 / Ton,   $30 / Ton,   $30 / Ton,    $30 / Ton,    TOTAL:
 No CO2           $15 / Ton,       $30 / Ton,         $30 / Ton,   $30 / Ton,    TOTAL:
                                                                                             Regulations   No Allow.    No Allow.    20% Allow.    40% Allow.   $30 / Ton,
Regulations       No Allow.         No Allow.         20% Allow.   40% Allow.   $30 / Ton,
                                                                                                                                                                40% Allow.
                                                                                40% Allow.




                  Greenhouse gas regulations could provide material upside for Calpine.
                  Greenhouse gas regulations could provide material upside for Calpine.
                                                                                                                                                  10




 Assumptions:
 Combined cycle HR        7.0   CC CO2/MW    h           0.4
 Avg. On-peak Mkt. HR     9.5   Marg'l unit CO2/MWh      0.6
 Tons CO2/MMBtu         117.0   Coal CO2/MW   h          1.0
                                                                                                                                                                             10
Calpine is prepared to respond to Texas wind
expansion

                                                                                                        Hourly Wind Generation as % of Installed Capacity
                                                                                                                            (ERCOT)
                                                                                            50%
• Wind generation tends to supply more
  power during off-peak hours and during
                                                                                            40%



  shoulder months
                                                                                            30%



    - As an intermediate power generator,                                                   20%



      Calpine has less margin at risk during                                                10%


      periods when wind blows most                                                              0%
                                                                                                     0:00   2:00   4:00    6:00   8:00 10:00 12:00 14:00 16:00 18:00 20:00 22:00

                                                                                                                   On-Peak Hours            2006 AVG           2007 AVG


• Unpredictable nature of wind may                                                                   Change in Hourly Wind Generation vs Installed Wind Capacity
                                                                                                                           (ERCOT, 2007)
  increase need for flexible gas-fired                                              2000                                                                                                5000

  capacity to support grid reliability                                                                                     Wind Change from Previous Hour                               4500
                                                                                    1500
                                                                                                                           Wind Capacity Installed
    - Combined-cycle generators are well-


                                                Hourly Change in Wind Output (MW)
                                                                                                                                                                                        4000




                                                                                                                                                                                                 Installed Wind Capacity (MW)
                                                                                    1000

       positioned to respond to volatility                                                                                                                                              3500

                                                                                     500
                                                                                                                                                                                        3000

                                                                                       0                                                                                                2500
• Additional revenues from ancillary services                                                                                                                                           2000

  are expected to mitigate energy revenue
                                                                                     -500
                                                                                                                                                                                        1500

  declines for CT’s and CC’s, particularly if
                                                                                    -1000
                                                                                                                                                               11                       1000


  new gas-fired capacity is needed to                                               -1500
                                                                                                                                                                                        500


  support demand growth                                                             -2000                                                                                               0
                                                                                            1         877      1753       2629    3505      4381        5257    6133   7009   7885   8761
                                                                                                                                         Hour of 2007




   Source: ERCOT
                                                                                                                                                                                            11
Calpine is favorably situated with respect to increasing
costs of new generation construction

           As replacement costs increase, so does the value of Calpine’s young fleet.
            As replacement costs increase, so does the value of Calpine’s young fleet.


• Rising costs of construction     higher value for
                                                                                                                                        2



  existing Calpine portfolio
    - Industry construction costs up 230% in past
        8 years
    - Recent CA utility filing requested more
        than $1,500/kW for new construction1
    - Potential restriction of CO2 allowances to
        existing plants could further increase
        relative costs for new build

• Rising costs of construction  higher long-term
  power prices due to capital recovery increases

• Calpine is additionally advantaged relative to
                                                                                                                                   12
  rising costs of construction by opportunities for
  brownfield development at existing plants

       Source: Megawatt Daily, 7/23/2008.
   1

       PCCI index is composed of a portfolio of 10 power generating assets (includes coal, wind, gas, nuclear) across the US and
   2

       tracks how costs associated with these assets would change in value.
                                                                                                                                            12
Declining natural gas prices have limited impact on
Calpine’s earnings

• In gas-on-the-margin markets, increases or decreases in gas prices have smaller
  absolute impacts on gas generators than coal or nuclear generators
    - Gas prices tend to drive power prices in Calpine's key markets, linking Calpine's
       fuel costs and revenues


    Example – Assume $1/mmbtu decline in gas prices; 9,500 btu/kWh market heat
       rate; and 7,000 btu/kWh heat rate for gas-fired plant:


                   ($/MWh)                          Gas-fired Plant

                   Impact to revenues                   $(9.5)

                   Impact to costs                        7.0


                                                        $ (2.5)
                   Net impact to gross margin
                                                                          13




                                                                                          13
Calpine’s Geysers are a unique power generating asset



• Largest geothermal resource in U.S.

• Highly reliable power-generating asset (~95% availability year-to-date)

• Green spreads are highest among baseload generators, with no emissions costs

• Ideally situated with respect to potential environmental regulation




             Calpine continues to maximize the value of this key resource.

• Recent capital expenditures have enhanced geothermal production by ~20 MW

• Recent additions of water reinjection sources preserve future value
                                                                            14




                                                                                 14
Calpine features a flexible portfolio able to
respond to evolving markets



 Continuing tight supply/demand conditions
                                                –   +

 Anticipated environmental regulations
                                                –   +

 Exposure to wind expansion in ERCOT
                                                –   +

 Rising costs of new build
                                                –   +

 Largest geothermal resource in U.S.
                                                –   + 15



                                                           15
Calpine delivered favorable operating results
in key markets
Employee Lost Time Accident Rate                                                                  Generation in Key Markets (000 MWh)
                                                                                                                                9,477

                                                                                          1.3
                                                                                                      7,824 7,982       7,962




                                                                                                                                            3,827

                                                                  0.42                                                                              2,635
                0.31                          0.31
                                                                                                                                                            1,552
   0.20                                                                                                                                                             1,117

                               0.01                                                    0.00

                                                                                                        West              Texas             Southeast         North
   2003         2004           2005           2006                2007                 1H08
                                                                    2                                                                   1
                                                                                                                                2Q07         2Q08
                           Calpine        BLS 2006 Average


                                                                                                        •Major 2Q08 outages:
Forced Outage Factor (%)
                                                                                                          - Broad River insulator failure (SE)
                                       5.44
                                                                                                          - Columbia CT failure (SE)
                                                                                                          - Freestone CT failure (TX)
                                                                                                          - Magic Valley CT damage (TX)
                                                3.69
                                                                                                          - Westbrook (N)
 3.17                                                                           3.02
                                                       2.41
               2.23 2.37                                                 2.31
                                                                                                        •Key operations initiatives:   16
        1.96
                                                                                                          - Methodical analysis and resolution of
                                                                                                            industry CT outages
                                0.60
                                                                                                          - Continued focus on fleet optimization /
                                                                                                            best practices
  West          Texas          Southeast             North                 CPN

                                                                  Excludes plants sold, deconsolidated or mothballed since 2Q07
               2Q07            2Q08                           1

                                                                  NAICS 221112 – Fossil Fuel Electric Power Generation 1,000+ Employees
                                                              2
                                                                                                                                                                            16
Calpine’s hedging program focuses on capturing
near-term value while preserving long-term upside

    • 87% of 2008 Gross Margin hedged1

    • Strategically hedged in future periods


                                Power Hedge Profile1                                                              Natural Gas Hedge Profile1
                     15%
                                                                                                        15%
                                      43%
                                                                                                                         47%
                                                       63%              65%                                                             58%               62%

                     85%                                                                                85%
                                      57%                                                                                53%
                                                                                                                                        42%
                                                       37%                                                                                                38%
                                                                        35%


                                                                                                        2008             2009           2010          2011
                    2008             2009             2010              2011
                                            2                       2                                                             2                   2
                         Hedged Volume             Open Volume                                                  Hedged Volume           Open Volume




    • 2008 EBITDA sensitivities to commodity price changes1:
        - $1/mmbtu Δ in natural gas prices       $20 - $25 million Δ in EBITDA 17
        - .25mmbtu/MWh Δ in implied market heat rates           $20 - $25 million Δ in EBITDA


    Balance of year, as of portfolio valuation on 7/24/08.
1

    Volumes shown on a Delta Basis. Delta Volumes are the expected volume based on the probability of economic dispatch at a
2

    future date based on current market prices for that future date. This is typically lower than the Notional Volume, which is plant
    capacity, less known performance and operating constraints.
                                                                                                                                                                17
Calpine continues to invest in select growth opportunities


• Greenfield Energy Center
  Sarnia, ON
    - 1,005 MW gas-fired facility
    - 50% CPN-owned
    - Milestones achieved: Mechanical completion; all CTs fired to full load
    - Oct 2008 COD

• Otay Mesa Energy Center
  San Diego, CA
    - 596 MW combined-cycle plant
    - 100% CPN-owned
    - Milestones achieved: Both CTs and steam turbine set on foundations
    - Projected Q3 2009 COD

• Russell City
  Hayward, CA
   - 600 MW combined-cycle plant
   - 65% CPN-owned                                                     18

   - Agreement in principle with Pacific Gas and Electric on a modified PPA
   - Projected Q2 2012 COD


                                                                               18
FINANCIAL REVIEW




                   19




                        19
Calpine delivered improved financial performance
during 2Q08

Commodity Margin ($mm)
                                $1,271
                                         Highlights:
                        $957
                                         • Commodity Margin improved 47% and
           $785
                                           Adjusted EBITDA improved 45% (2Q08 v 2Q07)
    $535
                                            - Higher spark spreads in key markets
                                            - Improvement despite 8% decline in avg.
                                               MW in operation
    2Q07   2Q08          1H07    1H08
                                         • Maintained flat Plant Operating Expenses / MWh
                                           (2Q08 v 2Q07)
Adjusted EBITDA ($mm)

                                         • Interest Expense declined 22% (2Q08 v 2Q07)
                                 $768
                                             - Lower LIBOR
                                             - Lower debt balances due to settlements
                         $576
           $474
                                                upon exit from Chapter 11
    $326
                                                                           20
                                         • Commodity Margin and Adjusted EBITDA
                                           improved 33% (1H08 v 1H07)

    2Q07   2Q08          1H07    1H08

                                                                                         20
Strong financial performance achieved in key markets

Commodity Margin by Region ($mm)                                                           Avg. On-Peak Spark Spreads by Region1 ($/MWh)

                                                                                                                           $82.63

          $340


      $265                $258



                      $138

                                            $91
                                                      $75 $72
                                      $65                                                                                                                     $20.39
                                                                                               $17.98 $19.74      $19.36
                                                                                                                                    $16.45$17.35
                                                                             $24                                                                     $14.07



                                                                      $(8)

                                                                                                 NP-15           ERCOT-HOU           Entergy       NEPOOL - Maine
        West           Texas         Southeast         North           Other

                                                                                                                       2Q07          2Q08
                        2Q07           2Q08


                                                                                           Southeast Region – 40% ↑ Commodity Margin
 West Region – 28% ↑ Commodity Margin
                                                                                           • Sale of transmission capacity
 • Higher spark spreads
                                                                                           • Benefits from new PPAs
 • Benefits from new agreements
 • Higher avg. capacity factor & availability
                                                                                                                       21
                                                                                           North Region – Flat Commodity Margin
 Texas Region – 87% ↑ Commodity Margin
                                                                                           • Higher spark spreads
 • Higher spark spreads
                                                                                           • Westbrook plant outages
 • Higher avg. capacity factor & availability


      Based on market liquidation rates, assuming heat rate of 7,000 btu/kWh. Sources: Gas Daily, Megawatt Daily, ICE, NEISO.
  1
                                                                                                                                                                       21
Calpine has added flexibility to manage liquidity


                                                                                    1Q08                           2Q08                 JUL’08 (E)
 ($mm)


 Cash & Cash Equivalents (non-restricted)1                                                   $ 115                          $ 157              $ 205
 Revolver / LC Availability2                                                                    721                            306               795
 Liquidity (current)                                                                         $ 836                          $ 463             $ 1,000
 Liquidity (contingent)                                                                             –                          150               350
 Liquidity (total)                                                                           $ 836                          $ 613            $ 1,350


 Two new credit facilities added since 1Q08:
 • $200mm Knock-in facility (June 2008)
     - $50mm available immediately; remainder available upon gas price thresholds
     - Provides liquidity in event of gas price spikes
 • $300mm Contingent Commodity Revolver facility (July 2008)
     - $100mm available immediately; remainder contingent upon spark spreads
     - Allows CPN to extend first lien collateral to wider group of counterparties; mitigates
        requirements for cash collateral

 Liquidity Sensitivities to Collateral Requirements3:
                                                                                            22
 • $1/mmbtu Δ in natural gas prices         $50 - $75 million inverse Δ in liquidity
 • .25mmbtu/MWh Δ in implied market heat rates              $100 - $150 million inverse Δ in liquidity

   Equal to Cash and Cash Equivalents (as reported), less cash balances subject to project finance & lease agreement restrictions
 1

   Includes total capacity under exit facility revolver, Calpine Development Holding, Inc. (CDHI) letter of credit facility, knock-in
 2

   facility, and contingent commodity revolver, less cash drawn and letters of credit outstanding as of such date.
 3 As of portfolio valuation on 7/24/08.
                                                                                                                                                        22
Calpine continues to optimize its capital structure


• During Q2, Calpine refinanced the Metcalf $100 million term loan and $155
  million preferred interests with $265 million term loan facility

• Calpine will continue to opportunistically refinance its debt prior to maturity1
                                                                                                                        $5,606




                                                        $85 mm of PCFIII Notes
                       ($mm)




                                                        to be repaid from cash
                                                          collateral account


                                                                                $1,646




                                                 $366
                                                                  $85

                                                                                                                                 23
                                 2008            2009            2010            2011             2012        2013       2014

                                                      CCFC              Project Debt             First Lien
     Assumptions:
     •   Maturity balances assume no cash sweeps
     •   All other debt maturities are paid off from operating cash flows at the project level

    The schedule shown here is not prepared on a GAAP basis and does not conform to the debt maturity schedule presented in
1

    Calpine’s Form 10-Q. Refer to the Form 10-Q for further information regarding GAAP-basis debt maturity.
                                                                                                                                      23
Calpine’s capital expenditures enhance
fleet performance


                                                  JUN YTD
 ($mm)


 Capital Expenditures:
    Growth                                          $33
    Maintenance / Other                              46
    Total CapEx                                     $79


 Major Maintenance Expense                          $96


CapEx and Maintenance Highlights:

• $33mm of Growth CapEx primarily related to Geysers, as well as Calpine
  Engine Optimization program
                                                                      24

• Additional $129mm of debt-funded CapEx in equity-method development
  projects (Greenfield, Otay Mesa)


                                                                           24
Calpine continues to benefit from NOL positions


 • Calpine (including CCFC) has $5.1 billion of U.S. NOLs which will have annual
   IRC Section 382 limitations on usage as follows:
         $4.4 billion over 14 years ($325 million/year)
     -
         $665 million over 5 years ($133 million/year)
     -
         Any amount not utilized in any year from these limitations can be carried
     -
         forward to succeeding years.
 • There are approximately $900 million of NOLs associated with Canada.
 • In addition to these NOLs, Calpine has significant deferred tax assets related to
   the bankruptcy that will generate tax deductions not limited under IRC Section
   382.
 • Calpine has identified an estimated $1.5 - $2.0 billion in total U.S. NOLs
   generated during 2008, ~90% of which will not be limited under IRC Section 382.


                                                                         25




                                                                                       25
CONCLUSION




             26




                  26
Calpine continues to create value for its shareholders


• Unique and well-positioned to capture trends that drive our business

• Solid financial performance with clear demonstration of ability to be opportunistic

• Additional liquidity, adding flexibility to hedging program

• Continued execution of day-to-day operations for the benefit of our customers, led
  by experienced management team




                                                                         27




                                                                                        27
Q&A




      28




           28
APPENDIX




           29




                29
Reg G Reconciliation: Commodity Margin

Calpine uses the non-GAAP financial measure “Commodity Margin” to assess its financial performance on a consolidated basis and by
its reportable segments. Commodity Margin includes its electricity and steam revenues, hedging and optimization activities, renewable
energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expenses, but excludes mark-to-market
activity and other service revenues. Calpine believes that Commodity Margin is a useful tool for assessing the performance of its core
operations and is a key operational measure reviewed by its chief operating decision maker. Commodity Margin is not a measure
calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for Calpine’s results of operations
presented in accordance with GAAP. Commodity Margin does not purport to represent gross profit (loss), the most comparable GAAP
measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other
companies.
                                                                                     Three Months Ended June 30, 2008
                                                                                                                                    Consolidation
                                                                                                                                         and
 (in millions)                                   West             Texas          Southeast         North            Other            Elimination          Total
  Revenues from external customers       $         1,156 $           1,185 $            400 $          170 $                (83) $             —$            2,828
  Intersegment revenues                               12                75               59              6                    3              (155)              —
    Total revenue                        $         1,168 $           1,260 $            459 $          176 $                (80) $           (155) $         2,828
  Commodity margin                                   340               258               91             72                   24                —               785
  Add: Mark-to-market commodity
  activity, net and other service
  revenues(1)                                            4                74             —                 —                (40)               (3)                 35
  Less:
  Plant operating expense                                95                48            22                24                22                (5)                206
  Depreciation and amortization                          44                33            18                13                 1                (1)                108
  Other cost of revenue                                  14                —              8                 6                 2                —                   30
    Gross profit (loss)                                 191               251            43                29               (41)                3                 476

                                                                                       Three Months Ended June 30, 2007
                                                                                                                                     Consolidation
   (in millions)
                                                                                                                                          and
                                                  West             Texas           Southeast        North            Other            Elimination          Total
  Revenues from external customers           $           806 $             797 $          294 $             147 $             16 $               —$               2,060
  Intersegment revenues                                    8                 1             50                 1                2                (62)                 —
    Total revenue                            $           814 $             798 $          344 $             148 $             18 $              (62) $            2,060
  Commodity margin                                       265               138             65                75               (8)                —                  535
                                                                                                                                                                          30
  Add: Mark-to-market commodity
  activity, net and other service
  revenues(1)                                                 3             48                 8            —                 13                    (3)             69
  Less:
  Plant operating expense                                 86                39               31             22                36                    (3)            211
  Depreciation and amortization                           54                29               19             14                 1                     1             118
  Other cost of revenue                                   13                —                 8              9                 4                    (1)             33
    Gross profit (loss)                                  115               118               15             30               (36)                   —              242


       (1) Included in operating revenues and fuel and purchased energy expenses.
                                                                                                                                                                               30
Reg G Reconciliation: Commodity Margin (cont’d)


                                                                                     Six Months Ended June 30, 2008
                                                                                                                                Consolidation
                                                                                                                                     and
 (in millions)                                  West          Texas          Southeast          North           Other            Elimination        Total
Revenues from external customers           $       2,118 $         1,826 $            657 $          320 $            (142) $              —$          4,779
Intersegment revenues                                 21             116               93             11                 5               (246)            —
  Total revenue                            $       2,139 $         1,942 $            750 $          331 $            (137) $            (246) $       4,779
Commodity margin                                     609             388              128            134                12                 —           1,271
Add: Mark-to-market commodity
activity, net and other service
revenues(1)                                            14              41                1              —             (155)                (6)          (105
Less:
Plant operating expense                                199            110              50               49              37                 (7)              438
Depreciation and amortization                           94             63              37               25               2                 (2)              219
Other cost of revenue                                   30             —               16               12               4                 —                 62
  Gross profit (loss)                                  300            256              26               48            (186)                 3               447




                                                                                     Six Months Ended June 30, 2007
                                                                                                                                Consolidation
                                                                                                                                     and
   (in millions)
                                                West           Texas         Southeast          North           Other            Elimination        Total
 Revenues from external customers           $       1,604 $        1,320 $             501 $            299 $            (2) $              —$          3,722
 Intersegment revenues                                 15             (2)               72                2              15               (102)            —
   Total revenue                            $       1,619 $        1,318 $             573 $            301 $            13 $             (102) $       3,722
 Commodity margin                                     495            224               102              138              (2)                —             957
 Add: Mark-to-market commodity
 activity, net and other service
 revenues(1)                                            15             52                 8             —                (21)              (16)              38
 Less:
 Plant operating expense                               165              68               55             38                58                (5)             379
                                                                                                                                                                  31
 Depreciation and amortization                         105              60               42             27                 2                —               236
 Other cost of revenue                                  22              —                16             17                21                (6)              70
   Gross profit (loss)                                 218             148               (3)            56              (104)               (5)             310




        (1) Included in operating revenues and fuel and purchased energy expenses.
                                                                                                                                                                       31
Reg G Reconciliation: Adjusted EBITDA

Calpine uses the non-GAAP financial measure “Adjusted EBITDA” as a measure of its liquidity and performance. Calpine defines
Adjusted EBITDA as EBITDA as adjusted for certain items described in this presentation and in the accompanying reconciliation.
Adjusted EBITDA is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute
for our results of operations presented in accordance with GAAP. Adjusted EBITDA does not purport to represent cash flow from
operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not
necessarily comparable to similarly-titled measures reported by other companies.
Calpine believes Adjusted EBITDA is used by and useful to investors and other users of our financial statements in analyzing our liquidity
as it is the basis for material covenants under our DIP Facility, which was our primary source of financing during our Chapter 11 cases,
and under our Exit Facility, which is our primary source of funding. Calpine also believes that EBITDA is widely used by investors to
measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization,
which can vary substantially from company to company depending upon accounting methods and book value of assets, capital
structure and the method by which assets were acquired.

                                                             Three Months Ended June 30,            Six Months Ended June 30,
 (in millions)                                                 2008              2007                2008              2007
 Cash provided by (used in) operating activities         $           (324) $               48   $         (586) $               (184 )
 Less:
   Changes in operating assets and liabilities,
   excluding the effects of acquisition                              (306)                 51             (432)                  (78 )
   Additional adjustments to reconcile GAAP net
   income (loss) to net cash provided by (used in)
   operating activities:
     Depreciation and amortization (1)                                125              141                 280                  284
     Deferred income taxes, net                                        21               (7)                 85                   82
     Change in derivatives and derivative contracts
     classified as financing activities under SFAS No.
     149                                                             (362)             (73)               (192)                  (10 )
     Reorganization items                                               3              434                (322)                  497
     Other                                                             (2)               2                  12                    —
 GAAP net income (loss)                                               197             (500)                (17)                 (959 )
 Add:
   Adjustments to reconcile Adjusted EBITDA to net
   income (loss):
     Interest expense, net of interest income                         192              247                 598                  530
                                                                                                                                         32
     Depreciation and amortization expense, excluding
     deferred financing costs(1)                                      118              129                 240                  258
     Provision (benefit) for income taxes                              25               (7)                 20                   82
     Impairment charges                                                 6               —                    6                    2
     Reorganization items                                              18              469                (261)                 574
     Major maintenance expense                                         42               46                  96                   74
     Losses on repurchase or extinguishment of debt                     6               —                   13                   —
     Operating lease expense                                           11               13                  23                   24
     (Gains) losses on derivatives (non-cash portion)                (151)             (65)                 28                   (2 )
     Other                                                             10               (6)                 22                   (7 )
       Adjusted EBITDA                                   $            474 $            326 $               768 $                576
                                                                                                                                              32
Selected Operating Statistics

     (in thousands, except heat rate)

                                                         2Q08 1        2Q07                                                                2Q08       2Q07
                                                                                                                                                  1



    Total MWh Generated                                                                       Average MW of Peaker Facilities
                                                            21,211      21,439                                                              2,540      3,019
     West                                                    7,982       7,824                 West                                           983        983
     Texas                                                   9,477       7,962                 Texas                                            -          -
     Southeast                                               2,635       4,084                 Southeast                                      963        963
     North                                                   1,117       1,569                 North                                          594      1,073

    Average Availability                                                                      Average Capacity Factor, exc. Peakers
                                                            89.9%        89.9%                                                             46.4%      43.3%
     West                                                    89.6%        86.2%                West                                         57.3%      55.1%
     Texas                                                   91.8%        88.0%                Texas                                        59.8%      50.1%
     Southeast                                               89.3%        95.5%                Southeast                                    21.2%      26.8%
     North                                                   87.4%        90.8%                North                                        28.0%      35.4%

    Average Total MW in Operation                                                             Steam Adjusted Heat Rate
                                                            23,113      25,091                                                              7,268      7,182
     West                                                    7,246       7,246                 West                                         7,319      7,366
     Texas                                                   7,251       7,274                 Texas                                        7,144      6,780
     Southeast                                               6,254       7,556                 Southeast                                    7,459      7,462
     North                                                   2,362       3,015                 North                                        7,635      7,857




                                                                                                                                      33




    Excludes plants which have been deconsolidated, sold, are not operated by Calpine or are no longer in operation.
1

                                                                                                                                                               33
34




     34

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Calpine2Q08_Earnings_Presentation_vFINAL

  • 1. CALPINE CORPORATION Second Quarter 2008 Earnings Results August 11, 2008
  • 2. Safe Harbor Statement Forward-Looking Statements The information contained in this presentation includes certain estimates, projections and other forward-looking information that reflect Calpine’s current views with respect to future events and financial performance. These estimates, projections and other forward-looking information are based on assumptions that Calpine believes, as of the date hereof, are reasonable. Inevitably, there will be differences between such estimates and actual results, and those differences may be material. There can be no assurance that any estimates, projections or forward-looking information will be realized. All such estimates, projections and forward-looking information speak only as of the date hereof. Calpine undertakes no duty to update or revise the information contained herein. You are cautioned not to place undue reliance on the estimates, projections and other forward-looking information in this presentation as they are based on current expectations and general assumptions and are subject to various risks, uncertainties and other factors, including those set forth in Calpine’s Form 10-K for the fiscal year ended December 31, 2007, Calpine’s Quarterly Reports filed on Form 10-Q for the periods ended March 31, 2008 and June 30, 2008, and in other documents that Calpine files with the SEC. Many of these risks, uncertainties and other factors are beyond Calpine’s control and may cause actual results to differ materially from the views, beliefs and estimates expressed herein. Calpine’s reports and other information filed with the SEC, including the risk factors identified in its Annual Report on Form 10-K for the year ended December 31, 2007 and in its Quarterly Reports on Form 10-Q for the periods ended March 31, 2008 and June 30, 3008, can be found on the SEC’s website at www.sec.gov and on Calpine’s website at www.calpine.com. Reconciliation to GAAP Financial Information 1 The following presentation includes certain “non-GAAP financial measures” as defined in Regulation G under the Securities Exchange Act of 1934. A schedule is attached hereto that reconciles the non-GAAP financial measures included in the following presentation to the most directly comparable financial measures calculated and presented in accordance with Generally Accepted Accounting Principles. 1
  • 3. Agenda • Opening Remarks Bill Patterson, Chairman • Calpine Update Todd Filsinger, Interim COO • Operations Review Todd Filsinger, Interim COO • Financial Review Zamir Rauf, Interim CFO • Conclusion Zamir Rauf, Interim CFO • Q&A 2 2
  • 5. Calpine is a unique independent power producer… Calpine is the nation’s largest baseload renewable, natural gas Calpine is the nation’s largest baseload renewable, natural gas and cogeneration power provider. and cogeneration power provider. Most Geographically Diversified Among Large IPPs Most Generation Among Large IPPs 100,000 North 90,000 2,822 MW Southeast 80,000 12% 6,254 MW Total MWh Generated (000) 70,000 26% 60,000 West 50,000 7,246 MW 40,000 30% Texas 30,000 7,487 MW 32% 20,000 10,000 CPN NRG DYN RRI MIR 4 Total Coal Nuclear Natural Gas Geothermal Other 23,809 MW 77 Plants Note: Represents Calpine’s net ownership including peaking capacity. Source: Energy Velocity, CEMS domestic data (2007) and company data. 4
  • 6. …well-positioned to respond to anticipated environmental regulations Lowest SO2 Emissions/MWh Among Large IPPs Lowest NOx Emissions/MWh Among Large IPPs 2.78 16.33 2.66 14.33 NOx (lbs / MWh) SO2 (lbs /MWh) 1.49 1.01 5.03 4.04 0.23 0.01 MIR RRI NRG DYN CPN MIR RRI NRG DYN CPN Lowest CO2 Emissions/MWh Among Large IPPs 2,115 1,931 1,924 1,917 CO2 (lbs /MWh) 5 904 NRG RRI DYN MIR CPN Source: Energy Velocity, CEMS data (2007) 5
  • 7. Calpine has made significant progress in its first full quarter post-emergence Operations • Deep bench of talent • Organizationally integrated commercial and power operations • Improved safety record across fleet • Increased fleet utilization Financial • Improved Commodity Margin and Adjusted EBITDA over prior year for second quarter and year-to-date • Continued efforts to optimize capital structure through refinancing of Metcalf project debt and preferred interests • Added liquidity sources to support hedging activities 6 6
  • 9. Calpine’s assets are well located and well positioned Calpine is… • Present in markets with tight supply/demand conditions • Poised to benefit from anticipated environmental regulations • Well-positioned to respond to wind capacity additions in ERCOT • Favorably situated with respect to increasing replacement costs for power generation nationwide • Less sensitive to earnings impacts from fluctuating natural gas prices • Environmentally friendly with largest geothermal resource in U.S. 8 8
  • 10. Calpine primarily operates in areas with tight reserve margins • Reserve margins have been declining in much of the U.S. - Majority of Calpine’s capacity is located in markets that currently have relatively tight reserve margins NEPOOL Northwest1 NYPP2 MISO Capacity Deficit MRO PJM3 California1 CO-WY SPP TVA VACAR Capacity Surplus AZ-NM-SV Entergy Southern ERCOT FRCC • Markets with tight supply and demand conditions often display price spikes and improved bilateral contract opportunities 9 • Calpine expects market conditions to continue to support spark spreads and create the need for new capacity – positive factors for Calpine Supply in the Northwest and California varies according to hydro conditions. 1 NYPP excludes NYLI and NY-in city. 2 The degree of overbuild does not reflect potential local transmission constraints. Source: PA Consulting Group. 9
  • 11. Calpine is poised to benefit from anticipated environmental regulations Sample Impact on Green Spreads (Geysers) Sample Impact on Spark Spreads (Combined Cycle) $8.34 $16.67 $2.46 $9.30 $8.34 $2.46 $2.19 $2.19 No CO2 $15 / Ton, $30 / Ton, $30 / Ton, $30 / Ton, TOTAL: No CO2 $15 / Ton, $30 / Ton, $30 / Ton, $30 / Ton, TOTAL: Regulations No Allow. No Allow. 20% Allow. 40% Allow. $30 / Ton, Regulations No Allow. No Allow. 20% Allow. 40% Allow. $30 / Ton, 40% Allow. 40% Allow. Greenhouse gas regulations could provide material upside for Calpine. Greenhouse gas regulations could provide material upside for Calpine. 10 Assumptions: Combined cycle HR 7.0 CC CO2/MW h 0.4 Avg. On-peak Mkt. HR 9.5 Marg'l unit CO2/MWh 0.6 Tons CO2/MMBtu 117.0 Coal CO2/MW h 1.0 10
  • 12. Calpine is prepared to respond to Texas wind expansion Hourly Wind Generation as % of Installed Capacity (ERCOT) 50% • Wind generation tends to supply more power during off-peak hours and during 40% shoulder months 30% - As an intermediate power generator, 20% Calpine has less margin at risk during 10% periods when wind blows most 0% 0:00 2:00 4:00 6:00 8:00 10:00 12:00 14:00 16:00 18:00 20:00 22:00 On-Peak Hours 2006 AVG 2007 AVG • Unpredictable nature of wind may Change in Hourly Wind Generation vs Installed Wind Capacity (ERCOT, 2007) increase need for flexible gas-fired 2000 5000 capacity to support grid reliability Wind Change from Previous Hour 4500 1500 Wind Capacity Installed - Combined-cycle generators are well- Hourly Change in Wind Output (MW) 4000 Installed Wind Capacity (MW) 1000 positioned to respond to volatility 3500 500 3000 0 2500 • Additional revenues from ancillary services 2000 are expected to mitigate energy revenue -500 1500 declines for CT’s and CC’s, particularly if -1000 11 1000 new gas-fired capacity is needed to -1500 500 support demand growth -2000 0 1 877 1753 2629 3505 4381 5257 6133 7009 7885 8761 Hour of 2007 Source: ERCOT 11
  • 13. Calpine is favorably situated with respect to increasing costs of new generation construction As replacement costs increase, so does the value of Calpine’s young fleet. As replacement costs increase, so does the value of Calpine’s young fleet. • Rising costs of construction higher value for 2 existing Calpine portfolio - Industry construction costs up 230% in past 8 years - Recent CA utility filing requested more than $1,500/kW for new construction1 - Potential restriction of CO2 allowances to existing plants could further increase relative costs for new build • Rising costs of construction higher long-term power prices due to capital recovery increases • Calpine is additionally advantaged relative to 12 rising costs of construction by opportunities for brownfield development at existing plants Source: Megawatt Daily, 7/23/2008. 1 PCCI index is composed of a portfolio of 10 power generating assets (includes coal, wind, gas, nuclear) across the US and 2 tracks how costs associated with these assets would change in value. 12
  • 14. Declining natural gas prices have limited impact on Calpine’s earnings • In gas-on-the-margin markets, increases or decreases in gas prices have smaller absolute impacts on gas generators than coal or nuclear generators - Gas prices tend to drive power prices in Calpine's key markets, linking Calpine's fuel costs and revenues Example – Assume $1/mmbtu decline in gas prices; 9,500 btu/kWh market heat rate; and 7,000 btu/kWh heat rate for gas-fired plant: ($/MWh) Gas-fired Plant Impact to revenues $(9.5) Impact to costs 7.0 $ (2.5) Net impact to gross margin 13 13
  • 15. Calpine’s Geysers are a unique power generating asset • Largest geothermal resource in U.S. • Highly reliable power-generating asset (~95% availability year-to-date) • Green spreads are highest among baseload generators, with no emissions costs • Ideally situated with respect to potential environmental regulation Calpine continues to maximize the value of this key resource. • Recent capital expenditures have enhanced geothermal production by ~20 MW • Recent additions of water reinjection sources preserve future value 14 14
  • 16. Calpine features a flexible portfolio able to respond to evolving markets Continuing tight supply/demand conditions – + Anticipated environmental regulations – + Exposure to wind expansion in ERCOT – + Rising costs of new build – + Largest geothermal resource in U.S. – + 15 15
  • 17. Calpine delivered favorable operating results in key markets Employee Lost Time Accident Rate Generation in Key Markets (000 MWh) 9,477 1.3 7,824 7,982 7,962 3,827 0.42 2,635 0.31 0.31 1,552 0.20 1,117 0.01 0.00 West Texas Southeast North 2003 2004 2005 2006 2007 1H08 2 1 2Q07 2Q08 Calpine BLS 2006 Average •Major 2Q08 outages: Forced Outage Factor (%) - Broad River insulator failure (SE) 5.44 - Columbia CT failure (SE) - Freestone CT failure (TX) - Magic Valley CT damage (TX) 3.69 - Westbrook (N) 3.17 3.02 2.41 2.23 2.37 2.31 •Key operations initiatives: 16 1.96 - Methodical analysis and resolution of industry CT outages 0.60 - Continued focus on fleet optimization / best practices West Texas Southeast North CPN Excludes plants sold, deconsolidated or mothballed since 2Q07 2Q07 2Q08 1 NAICS 221112 – Fossil Fuel Electric Power Generation 1,000+ Employees 2 16
  • 18. Calpine’s hedging program focuses on capturing near-term value while preserving long-term upside • 87% of 2008 Gross Margin hedged1 • Strategically hedged in future periods Power Hedge Profile1 Natural Gas Hedge Profile1 15% 15% 43% 47% 63% 65% 58% 62% 85% 85% 57% 53% 42% 37% 38% 35% 2008 2009 2010 2011 2008 2009 2010 2011 2 2 2 2 Hedged Volume Open Volume Hedged Volume Open Volume • 2008 EBITDA sensitivities to commodity price changes1: - $1/mmbtu Δ in natural gas prices $20 - $25 million Δ in EBITDA 17 - .25mmbtu/MWh Δ in implied market heat rates $20 - $25 million Δ in EBITDA Balance of year, as of portfolio valuation on 7/24/08. 1 Volumes shown on a Delta Basis. Delta Volumes are the expected volume based on the probability of economic dispatch at a 2 future date based on current market prices for that future date. This is typically lower than the Notional Volume, which is plant capacity, less known performance and operating constraints. 17
  • 19. Calpine continues to invest in select growth opportunities • Greenfield Energy Center Sarnia, ON - 1,005 MW gas-fired facility - 50% CPN-owned - Milestones achieved: Mechanical completion; all CTs fired to full load - Oct 2008 COD • Otay Mesa Energy Center San Diego, CA - 596 MW combined-cycle plant - 100% CPN-owned - Milestones achieved: Both CTs and steam turbine set on foundations - Projected Q3 2009 COD • Russell City Hayward, CA - 600 MW combined-cycle plant - 65% CPN-owned 18 - Agreement in principle with Pacific Gas and Electric on a modified PPA - Projected Q2 2012 COD 18
  • 21. Calpine delivered improved financial performance during 2Q08 Commodity Margin ($mm) $1,271 Highlights: $957 • Commodity Margin improved 47% and $785 Adjusted EBITDA improved 45% (2Q08 v 2Q07) $535 - Higher spark spreads in key markets - Improvement despite 8% decline in avg. MW in operation 2Q07 2Q08 1H07 1H08 • Maintained flat Plant Operating Expenses / MWh (2Q08 v 2Q07) Adjusted EBITDA ($mm) • Interest Expense declined 22% (2Q08 v 2Q07) $768 - Lower LIBOR - Lower debt balances due to settlements $576 $474 upon exit from Chapter 11 $326 20 • Commodity Margin and Adjusted EBITDA improved 33% (1H08 v 1H07) 2Q07 2Q08 1H07 1H08 20
  • 22. Strong financial performance achieved in key markets Commodity Margin by Region ($mm) Avg. On-Peak Spark Spreads by Region1 ($/MWh) $82.63 $340 $265 $258 $138 $91 $75 $72 $65 $20.39 $17.98 $19.74 $19.36 $16.45$17.35 $24 $14.07 $(8) NP-15 ERCOT-HOU Entergy NEPOOL - Maine West Texas Southeast North Other 2Q07 2Q08 2Q07 2Q08 Southeast Region – 40% ↑ Commodity Margin West Region – 28% ↑ Commodity Margin • Sale of transmission capacity • Higher spark spreads • Benefits from new PPAs • Benefits from new agreements • Higher avg. capacity factor & availability 21 North Region – Flat Commodity Margin Texas Region – 87% ↑ Commodity Margin • Higher spark spreads • Higher spark spreads • Westbrook plant outages • Higher avg. capacity factor & availability Based on market liquidation rates, assuming heat rate of 7,000 btu/kWh. Sources: Gas Daily, Megawatt Daily, ICE, NEISO. 1 21
  • 23. Calpine has added flexibility to manage liquidity 1Q08 2Q08 JUL’08 (E) ($mm) Cash & Cash Equivalents (non-restricted)1 $ 115 $ 157 $ 205 Revolver / LC Availability2 721 306 795 Liquidity (current) $ 836 $ 463 $ 1,000 Liquidity (contingent) – 150 350 Liquidity (total) $ 836 $ 613 $ 1,350 Two new credit facilities added since 1Q08: • $200mm Knock-in facility (June 2008) - $50mm available immediately; remainder available upon gas price thresholds - Provides liquidity in event of gas price spikes • $300mm Contingent Commodity Revolver facility (July 2008) - $100mm available immediately; remainder contingent upon spark spreads - Allows CPN to extend first lien collateral to wider group of counterparties; mitigates requirements for cash collateral Liquidity Sensitivities to Collateral Requirements3: 22 • $1/mmbtu Δ in natural gas prices $50 - $75 million inverse Δ in liquidity • .25mmbtu/MWh Δ in implied market heat rates $100 - $150 million inverse Δ in liquidity Equal to Cash and Cash Equivalents (as reported), less cash balances subject to project finance & lease agreement restrictions 1 Includes total capacity under exit facility revolver, Calpine Development Holding, Inc. (CDHI) letter of credit facility, knock-in 2 facility, and contingent commodity revolver, less cash drawn and letters of credit outstanding as of such date. 3 As of portfolio valuation on 7/24/08. 22
  • 24. Calpine continues to optimize its capital structure • During Q2, Calpine refinanced the Metcalf $100 million term loan and $155 million preferred interests with $265 million term loan facility • Calpine will continue to opportunistically refinance its debt prior to maturity1 $5,606 $85 mm of PCFIII Notes ($mm) to be repaid from cash collateral account $1,646 $366 $85 23 2008 2009 2010 2011 2012 2013 2014 CCFC Project Debt First Lien Assumptions: • Maturity balances assume no cash sweeps • All other debt maturities are paid off from operating cash flows at the project level The schedule shown here is not prepared on a GAAP basis and does not conform to the debt maturity schedule presented in 1 Calpine’s Form 10-Q. Refer to the Form 10-Q for further information regarding GAAP-basis debt maturity. 23
  • 25. Calpine’s capital expenditures enhance fleet performance JUN YTD ($mm) Capital Expenditures: Growth $33 Maintenance / Other 46 Total CapEx $79 Major Maintenance Expense $96 CapEx and Maintenance Highlights: • $33mm of Growth CapEx primarily related to Geysers, as well as Calpine Engine Optimization program 24 • Additional $129mm of debt-funded CapEx in equity-method development projects (Greenfield, Otay Mesa) 24
  • 26. Calpine continues to benefit from NOL positions • Calpine (including CCFC) has $5.1 billion of U.S. NOLs which will have annual IRC Section 382 limitations on usage as follows: $4.4 billion over 14 years ($325 million/year) - $665 million over 5 years ($133 million/year) - Any amount not utilized in any year from these limitations can be carried - forward to succeeding years. • There are approximately $900 million of NOLs associated with Canada. • In addition to these NOLs, Calpine has significant deferred tax assets related to the bankruptcy that will generate tax deductions not limited under IRC Section 382. • Calpine has identified an estimated $1.5 - $2.0 billion in total U.S. NOLs generated during 2008, ~90% of which will not be limited under IRC Section 382. 25 25
  • 27. CONCLUSION 26 26
  • 28. Calpine continues to create value for its shareholders • Unique and well-positioned to capture trends that drive our business • Solid financial performance with clear demonstration of ability to be opportunistic • Additional liquidity, adding flexibility to hedging program • Continued execution of day-to-day operations for the benefit of our customers, led by experienced management team 27 27
  • 29. Q&A 28 28
  • 30. APPENDIX 29 29
  • 31. Reg G Reconciliation: Commodity Margin Calpine uses the non-GAAP financial measure “Commodity Margin” to assess its financial performance on a consolidated basis and by its reportable segments. Commodity Margin includes its electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expenses, but excludes mark-to-market activity and other service revenues. Calpine believes that Commodity Margin is a useful tool for assessing the performance of its core operations and is a key operational measure reviewed by its chief operating decision maker. Commodity Margin is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for Calpine’s results of operations presented in accordance with GAAP. Commodity Margin does not purport to represent gross profit (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies. Three Months Ended June 30, 2008 Consolidation and (in millions) West Texas Southeast North Other Elimination Total Revenues from external customers $ 1,156 $ 1,185 $ 400 $ 170 $ (83) $ —$ 2,828 Intersegment revenues 12 75 59 6 3 (155) — Total revenue $ 1,168 $ 1,260 $ 459 $ 176 $ (80) $ (155) $ 2,828 Commodity margin 340 258 91 72 24 — 785 Add: Mark-to-market commodity activity, net and other service revenues(1) 4 74 — — (40) (3) 35 Less: Plant operating expense 95 48 22 24 22 (5) 206 Depreciation and amortization 44 33 18 13 1 (1) 108 Other cost of revenue 14 — 8 6 2 — 30 Gross profit (loss) 191 251 43 29 (41) 3 476 Three Months Ended June 30, 2007 Consolidation (in millions) and West Texas Southeast North Other Elimination Total Revenues from external customers $ 806 $ 797 $ 294 $ 147 $ 16 $ —$ 2,060 Intersegment revenues 8 1 50 1 2 (62) — Total revenue $ 814 $ 798 $ 344 $ 148 $ 18 $ (62) $ 2,060 Commodity margin 265 138 65 75 (8) — 535 30 Add: Mark-to-market commodity activity, net and other service revenues(1) 3 48 8 — 13 (3) 69 Less: Plant operating expense 86 39 31 22 36 (3) 211 Depreciation and amortization 54 29 19 14 1 1 118 Other cost of revenue 13 — 8 9 4 (1) 33 Gross profit (loss) 115 118 15 30 (36) — 242 (1) Included in operating revenues and fuel and purchased energy expenses. 30
  • 32. Reg G Reconciliation: Commodity Margin (cont’d) Six Months Ended June 30, 2008 Consolidation and (in millions) West Texas Southeast North Other Elimination Total Revenues from external customers $ 2,118 $ 1,826 $ 657 $ 320 $ (142) $ —$ 4,779 Intersegment revenues 21 116 93 11 5 (246) — Total revenue $ 2,139 $ 1,942 $ 750 $ 331 $ (137) $ (246) $ 4,779 Commodity margin 609 388 128 134 12 — 1,271 Add: Mark-to-market commodity activity, net and other service revenues(1) 14 41 1 — (155) (6) (105 Less: Plant operating expense 199 110 50 49 37 (7) 438 Depreciation and amortization 94 63 37 25 2 (2) 219 Other cost of revenue 30 — 16 12 4 — 62 Gross profit (loss) 300 256 26 48 (186) 3 447 Six Months Ended June 30, 2007 Consolidation and (in millions) West Texas Southeast North Other Elimination Total Revenues from external customers $ 1,604 $ 1,320 $ 501 $ 299 $ (2) $ —$ 3,722 Intersegment revenues 15 (2) 72 2 15 (102) — Total revenue $ 1,619 $ 1,318 $ 573 $ 301 $ 13 $ (102) $ 3,722 Commodity margin 495 224 102 138 (2) — 957 Add: Mark-to-market commodity activity, net and other service revenues(1) 15 52 8 — (21) (16) 38 Less: Plant operating expense 165 68 55 38 58 (5) 379 31 Depreciation and amortization 105 60 42 27 2 — 236 Other cost of revenue 22 — 16 17 21 (6) 70 Gross profit (loss) 218 148 (3) 56 (104) (5) 310 (1) Included in operating revenues and fuel and purchased energy expenses. 31
  • 33. Reg G Reconciliation: Adjusted EBITDA Calpine uses the non-GAAP financial measure “Adjusted EBITDA” as a measure of its liquidity and performance. Calpine defines Adjusted EBITDA as EBITDA as adjusted for certain items described in this presentation and in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Adjusted EBITDA does not purport to represent cash flow from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies. Calpine believes Adjusted EBITDA is used by and useful to investors and other users of our financial statements in analyzing our liquidity as it is the basis for material covenants under our DIP Facility, which was our primary source of financing during our Chapter 11 cases, and under our Exit Facility, which is our primary source of funding. Calpine also believes that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Three Months Ended June 30, Six Months Ended June 30, (in millions) 2008 2007 2008 2007 Cash provided by (used in) operating activities $ (324) $ 48 $ (586) $ (184 ) Less: Changes in operating assets and liabilities, excluding the effects of acquisition (306) 51 (432) (78 ) Additional adjustments to reconcile GAAP net income (loss) to net cash provided by (used in) operating activities: Depreciation and amortization (1) 125 141 280 284 Deferred income taxes, net 21 (7) 85 82 Change in derivatives and derivative contracts classified as financing activities under SFAS No. 149 (362) (73) (192) (10 ) Reorganization items 3 434 (322) 497 Other (2) 2 12 — GAAP net income (loss) 197 (500) (17) (959 ) Add: Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net of interest income 192 247 598 530 32 Depreciation and amortization expense, excluding deferred financing costs(1) 118 129 240 258 Provision (benefit) for income taxes 25 (7) 20 82 Impairment charges 6 — 6 2 Reorganization items 18 469 (261) 574 Major maintenance expense 42 46 96 74 Losses on repurchase or extinguishment of debt 6 — 13 — Operating lease expense 11 13 23 24 (Gains) losses on derivatives (non-cash portion) (151) (65) 28 (2 ) Other 10 (6) 22 (7 ) Adjusted EBITDA $ 474 $ 326 $ 768 $ 576 32
  • 34. Selected Operating Statistics (in thousands, except heat rate) 2Q08 1 2Q07 2Q08 2Q07 1 Total MWh Generated Average MW of Peaker Facilities 21,211 21,439 2,540 3,019 West 7,982 7,824 West 983 983 Texas 9,477 7,962 Texas - - Southeast 2,635 4,084 Southeast 963 963 North 1,117 1,569 North 594 1,073 Average Availability Average Capacity Factor, exc. Peakers 89.9% 89.9% 46.4% 43.3% West 89.6% 86.2% West 57.3% 55.1% Texas 91.8% 88.0% Texas 59.8% 50.1% Southeast 89.3% 95.5% Southeast 21.2% 26.8% North 87.4% 90.8% North 28.0% 35.4% Average Total MW in Operation Steam Adjusted Heat Rate 23,113 25,091 7,268 7,182 West 7,246 7,246 West 7,319 7,366 Texas 7,251 7,274 Texas 7,144 6,780 Southeast 6,254 7,556 Southeast 7,459 7,462 North 2,362 3,015 North 7,635 7,857 33 Excludes plants which have been deconsolidated, sold, are not operated by Calpine or are no longer in operation. 1 33
  • 35. 34 34