Calpine Reports Third Quarter 2012 Results, Narrows 2012 Guidance, Provides 2013 Guidance and Announces Sale of Broad River

  Calpine Reports Third Quarter 2012 Results, Narrows 2012 Guidance, Provides
  2013 Guidance and Announces Sale of Broad River Energy Center

Business Wire

HOUSTON -- November 06, 2012

Calpine Corporation (NYSE: CPN):

Summary of Third Quarter 2012 Financial Results (in millions):

             Three Months Ended September    Nine Months Ended September 30,
              30,
              2012       2011      %         2012      2011       % Change
                                     Change
                                                                   
Operating     $  1,996    $ 2,209    (9.6 )%   $ 4,111    $ 5,341     (23.0 )%
Revenues
Commodity     $  897      $ 825      8.7  %    $ 2,023    $ 1,921     5.3   %
Margin
Adjusted      $  706      $ 638      10.7 %    $ 1,434    $ 1,347     6.5   %
EBITDA
Adjusted
Recurring     $  463      $ 361      28.3 %    $ 523      $ 381       37.3  %
Free Cash
Flow
Per Share     $  0.99     $ 0.74     33.8 %    $ 1.10     $ 0.78      41.0  %
(diluted)
Net Income    $  437      $ 190                $ 99       $ (177  )
(Loss)^1
Net Income,
As            $  215      $ 195                $ 164      $ 30
Adjusted^2
                                                                      

Narrowing 2012 Full Year Guidance and Providing 2013 Full Year Guidance:

                                                    
                                    2012                 2013
                                    (in millions)
Adjusted EBITDA                     $1,725 - 1,775       $1,760 - 1,960
Adjusted Recurring Free Cash Flow   $525 - 575           $575 - 775
Per Share Midpoint (diluted)        $1.16                $1.45

Note: 2013 guidance range reflects all pending acquisition and divestiture
activity, including today’s announced sale of Broad River Energy Center, which
we estimate would have contributed approximately $40 million of Adjusted
EBITDA in 2013.

Recent Achievements:

  *Operations:
    — Generated more than 33 million MWh^3 of electricity in the third quarter
    of 2012, a record for the period and a 14% increase compared to the third
    quarter of 2011
    —Held year-to-date plant operating expense^4 essentially flat, despite a
    31% increase in generation^3
    —Delivered lowest year-to-date fleetwide forced outage factor on record:
    1.6%
    —Produced highest year-to-date fleetwide starting reliability on record:
    98.5%
    —Achieved best year-to-date safety performance on record

  *Commercial:
    —Announcing sale of Broad River Energy Center, an 847 MW simple-cycle
    power plant in South Carolina, for $427 million^5, or $504/kW
    —Announced acquisition of Bosque Energy Center, an 800 MW combined-cycle
    power plant in Central Texas for $432 million^5, or $540/kW
    —Signed 15-year PPA for 260 MW of capacity, energy and ancillary services
    from our Oneta Energy Center commencing in June 2016

  *Capital Structure:
    —Simplified capital structure by entering into $835 million first lien
    term loan at an attractive rate, using proceeds to redeem 10% of existing
    first lien notes and retire project-level BRSP debt

Calpine Corporation (NYSE: CPN) today reported third quarter 2012 Adjusted
EBITDA of $706 million, compared to $638 million in the prior year period, and
Adjusted Recurring Free Cash Flow of $463 million, or $0.99 per diluted share,
compared to $361 million, or $0.74 per diluted share, in the prior year
period. Net Income^1 for the third quarter was $437 million, or $0.94 per
diluted share, compared to $190 million, or $0.39 per diluted share, in the
prior year period. Net Income, As Adjusted^2, for the third quarter of 2012
was $215 million compared to $195 million in the prior year period.

Year-to-date 2012 Adjusted EBITDA was $1,434 million, compared to $1,347
million in the prior year period, and Adjusted Recurring Free Cash Flow was
$523 million, or $1.10 per diluted share, compared to $381 million, or $0.78
per diluted share, in the prior year period. Net Income^1 for the first nine
months of 2012 was $99 million, or $0.21 per diluted share, compared to a Net
Loss^1 of $177 million, or $0.36 per diluted share, in the prior year period.
Net Income, As Adjusted^2, for the first nine months of 2012 was $164 million
compared to $30 million in the prior year period.

“Calpine’s power plants continue to deliver record operating results,” said
Jack Fusco, Calpine’s President and Chief Executive Officer. “Our versatile
fleet generated nearly 90 million MWhs through the first nine months of 2012 –
31% more than last year – while holding plant operating expenses essentially
flat. This was due in large part to our focus on operational excellence and
preventive maintenance, which yielded our best year-to-date forced outage
factor and starting reliability on record. In addition, our commercial
optimization efforts resulted in significant contribution from our Texas
segment during the third quarter due to our seasonal hedging activity, which
captured margin above what ultimately proved to be weak market prices driven
by mild weather. As a result, we are able to maintain the midpoint of our
full-year 2012 Adjusted EBITDA and Adjusted Recurring Free Cash Flow guidance
while narrowing the range.

“Consistent with our disciplined capital allocation program, Calpine continues
to make significant progress across the board, from acquisitions and
divestitures to organic growth to share repurchases. With respect to
acquisitions and divestitures, I am pleased to report that we have taken
another meaningful step forward in our initiative to realign our portfolio by
monetizing non-core assets and redeploying capital to enhance long-term
shareholder value. Today, we are announcing the divestiture of our Broad River
Energy Center, a contracted peaking plant in South Carolina, for $427 million,
which complements our recently announced $432 million acquisition of Bosque, a
merchant CCGT in the attractive Texas market. In addition, we expect to
receive $392 million by year-end for the sale of our Riverside Energy Center,
a CCGT in Wisconsin. Meanwhile, we plan to bring almost 800 MW of contracted
growth projects in California online by mid-2013 and continue to advance more
than 800 MW of development projects in Texas and Delaware. Finally, we have
completed approximately $427 million of our previously announced $600 million
share repurchase program.”

Zamir Rauf, Calpine’s Chief Financial Officer, added, “We’ve had a great year
to date, as evidenced by our 41% growth in Adjusted Recurring Free Cash Flow
Per Share, which I believe is the best measure for evaluating shareholder
value creation. Free cash flow per share represents cash available for capital
allocation and captures value created through asset monetizations, debt
portfolio optimization, our substantial NOL tax position and share
repurchases. Therefore, in addition to our 2013 guidance, we are initiating an
Adjusted Recurring Free Cash Flow Per Share growth target rate of 15-20%
compounded annually, which we also believe represents potential annual total
shareholder return.”

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2012 was $706 million compared to
$638 million in the prior year period. The year-over-year increase in Adjusted
EBITDA was primarily due to a $72 million increase in Commodity Margin, which
was driven primarily by:

      +  higher contribution from hedges in our Texas segment, and
            +   higher regulatory capacity revenue in the Mid-Atlantic market.

Net Income^1 was $437 million for the third quarter of 2012, compared to $190
million in the prior year period. As detailed in Table 1, Net Income, As
Adjusted^2, was $215 million in the third quarter of 2012 compared to $195
million in the prior year period. The year-over-year improvement was driven
largely by:

      +  higher Commodity Margin, as previously discussed, and
            +   lower interest expense, primarily resulting from a decrease in
                our annual effective interest rate, partially offset by
            –   increased income tax expense due primarily to an increase in
                various state and foreign jurisdiction income taxes.

Year-to-Date Results

Adjusted EBITDA for the nine months ended September 30, 2012, was $1,434
million compared to $1,347 million in the prior year period. The
year-over-year increase in Adjusted EBITDA was primarily due to a $102 million
increase in Commodity Margin, partially offset by modest increases in plant
operating expense^4 and sales, general and administrative expenses^6. The
increase in Commodity Margin was primarily due to:

                higher contribution from hedges, primarily in our Texas
      +  segment during the third quarter of 2012 compared to the prior
                year period
                higher generation due to increased market opportunities,
                primarily driven by lower natural gas prices in all segments
            +   during the first half of 2012 compared to the same period in
                2011, as well as lower hydroelectric generation and a nuclear
                power plant outage in California during the nine months ended
                September 30, 2012, and
                an extreme cold weather event in Texas in February 2011 that
            +   negatively impacted our Commodity Margin in that period, which
                did not recur in the current year, partially offset by
            –   lower regulatory capacity revenues during the first half of
                2012 compared to the prior year period and
            –   the expiration of contracts.

Net Income^1 was $99 million for the nine months ended September 30, 2012,
compared to a Net Loss^1 of $177 million in the prior year period. As detailed
in Table 1, Net Income, As Adjusted^2, was $164 million in the nine months
ended September 30, 2012, compared to $30 million in the prior year period.
The year-over-year improvement was driven largely by:

      +  higher Commodity Margin, as previously discussed, and
            +   lower interest expense, primarily resulting from a decrease in
                our annual effective interest rate.

___________

^1 ^Reported as net income (loss) attributable to Calpine on our Consolidated
Condensed Statements of Operations.

^2 ^Refer to Table 1 for further detail of Net Income, As Adjusted.

^3 ^Includes generation from power plants owned but not operated by Calpine
and our share of generation from unconsolidated power plants.

^4 ^Increase in plant operating expense excludes changes in major maintenance
expense, stock-based compensation expense, non-cash loss on disposition of
assets and other costs. See the table titled “Consolidated Adjusted EBITDA
Reconciliation” for the actual amounts of these items for the nine months
ended September 30, 2012 and 2011.

^5 ^Amounts subject to adjustments upon close.

^6 ^Increase in sales, general and administrative expense excludes changes in
stock-based compensation expense, amortization and other items. See the table
titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of
these items for the nine months ended September 30, 2012 and 2011.

Table 1: Net Income, As Adjusted

                    
                      Three Months Ended September  Nine Months Ended
                      30,                            September 30,
                      2012             2011         2012         2011
                      (in millions)
Net income (loss)
attributable to       $   437           $  190       $  99         $  (177  )
Calpine
Debt extinguishment   —                 (4      )    12            94
costs^(1)
Unrealized MtM
(gain) loss on        (222      )       (35     )    (103    )     42
derivatives^(1) (2)
Other items ^ (1)     —                44          156          71       
(3)
Net Income, As        $   215          $  195      $  164       $  30    
Adjusted^(4)

__________

^(1) Shown net of tax, assuming a 0% effective tax rate for these items.

^(2) In addition to changes in market value on derivatives not designated as
hedges, changes in unrealized (gain) loss also includes de-designation of
interest rate swap cash flow hedges and related reclassification from AOCI
into earnings, hedge ineffectiveness and adjustments to reflect changes in
credit default risk exposure.

^(3) Other items include realized mark-to-market losses associated with the
settlement of non-hedged interest rate swaps totaling nil and $156 million for
the three and nine months ended September 30, 2012, respectively, and $44
million and $147 million for the three and nine months ended September 30,
2011, respectively. Other items for the nine months ended September 30, 2011,
also include a $76 million federal deferred income tax benefit associated with
our election to consolidate our CCFC subsidiary for tax reporting purposes.

^(4) See “Regulation G Reconciliations” for further discussion of Net Income,
As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

           Three Months Ended September     Nine Months Ended September 30,
            30,
            2012        2011     Variance   2012       2011       Variance
West        $  330       $ 329     $  1       $ 748       $ 798       $  (50 )
Texas       218          162       56         472         357         115
North       266          259       7          591         578         13
Southeast   83          75       8         212        188        24     
Total       $  897      $ 825    $  72     $ 2,023    $ 1,921    $  102 

West Region

Third Quarter: Commodity Margin in our West segment increased by $1 million in
the third quarter of 2012 compared to the prior year period. Primary drivers
were:

                increased generation and higher spark spreads driven primarily
      +  by lower hydroelectric generation and a nuclear power plant
                outage in California during 2012, largely offset by
            –   lower contribution from hedges associated with our Geysers
                assets.

Year-to-Date: Commodity Margin in our West segment decreased by $50 million
for the nine months ended September 30, 2012, compared to the prior year
period. Primary drivers were:

      –  lower contribution from hedges associated with our Geysers
                assets
            –   lower revenue due to the expiration of contracts and
                lower Commodity Margin associated with our Sutter Energy
            –   Center, which did not run in the first half of 2012, partially
                offset by
                increased generation and higher spark spreads resulting from
            +   lower hydroelectric generation and a nuclear power plant
                outage in California during 2012.

Texas Region

Third Quarter: Commodity Margin in our Texas segment increased by $56 million
in the third quarter of 2012 compared to the prior year period. The primary
driver was:

                higher contribution from hedging activities that secured
      +  favorable pricing despite lower market prices driven by milder
                weather.

Year-to-Date: Commodity Margin in our Texas segment increased by $115 million
for the nine months ended September 30, 2012, compared to the prior year
period. Primary drivers were:

                higher contribution from hedging activities that secured
      +  favorable pricing despite lower market prices driven by milder
                weather in the third quarter of 2012 compared to the prior
                year period
            +   higher generation driven by increased market opportunities
                primarily due to lower natural gas prices and
                an extreme cold weather event in Texas in February 2011 that
            +   negatively impacted our Commodity Margin in the first quarter
                of the prior year, which did not recur in the current year.

North Region

Third Quarter: Commodity Margin in our North segment increased by $7 million
in the third quarter of 2012 compared to the prior year period. Primary
drivers were:

      +  higher regulatory capacity revenues and
                to a far lesser extent, increased generation, the impact of
            +   which was mitigated by contracted plants that generated higher
                volumes, as well as lower margins experienced by the remaining
                plants.

Year-to-Date: Commodity Margin in our North segment increased by $13 million
in the nine months ended September 30, 2012, compared to the prior year
period. Primary drivers were:

      +  higher contribution from hedges
            +   York Energy Center achieving commercial operation in March
                2011 and
            +   increased generation driven by increased market opportunities
                primarily due to lower natural gas prices, partially offset by
            –   lower regulatory capacity revenues during the nine months
                ended September 30, 2012, compared to the prior year period.

Southeast Region

Third Quarter: Commodity Margin in our Southeast segment increased by $8
million in the third quarter of 2012 compared to the prior year period.
Primary drivers were:

      +  higher contribution from hedges associated with lower natural
                gas prices, partially offset by
            –   the expiration of a contract.

Year-to-Date: Commodity Margin in our Southeast segment increased by $24
million in the nine months ended September 30, 2012, compared to the prior
year period. Primary drivers were:

      +  higher contribution from hedges and
            +   higher generation resulting from increased market            .
                opportunities due to lower natural gas prices

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity

                                          
                                            September 30,  December 31,
                                            2012            2011
                                            (in millions)
Cash and cash equivalents, corporate^(1)    $   886         $    946
Cash and cash equivalents, non-corporate    211            306
Total cash and cash equivalents             1,097           1,252
Restricted cash                             226             194
Corporate Revolving Facility availability   720             560
Letter of credit availability^(2)           25             7
Total current liquidity availability        $   2,068      $    2,013

__________

^(1) Includes $9 million and $34 million of margin deposits held by us posted
by our counterparties at September30,2012, and December 31, 2011,
respectively.

^(2) Includes availability under our CDHI letter of credit facility. On
January 10, 2012, we increased the CDHI letter of credit facility to $300
million and extended the maturity date to January 2, 2016.

Liquidity remained strong at over $2 billion as of September 30, 2012.

Cash flows from operating activities for the nine months ended September 30,
2012, resulted in net inflows of $608 million compared to $536 million in the
prior year period. The increase in cash provided by operating activities was
primarily due to an increase in income from operations (adjusted for non-cash
items), partially offset by an increase in cash paid for interest due to
timing of interest payments on our debt.

Cash flows used in investing activities increased to $701 million for the nine
months ended September 30, 2012, compared to $660 million in the prior year
period, driven largely by the termination of our legacy interest rate swaps
and by an increase in restricted cash associated with 2011 changes in project
related debt that did not recur in the nine months ended September 30, 2012.

Cash flows used in financing activities were $62 million for the nine months
ended September 30, 2012, and were primarily related to the payments we made
under our share repurchase program, offset by the receipt of proceeds from
project financings related to our Russell City and Los Esteros construction
projects. In addition, we incurred lower financing costs and lower repayments
on project debt due in part to the refinancing activities we completed during
the nine months ended September 30, 2011.

Adjusted Recurring Free Cash Flow was $523 million for the nine months ended
September 30, 2012, compared to $381 million for the prior year period.
Adjusted Recurring Free Cash Flow increased during the period primarily due to
an $87 million increase in Adjusted EBITDA, as previously discussed. Lower
maintenance capital expenditures related to our plant outage schedule and
lower interest expense further contributed to the increase compared to the
prior year period.

Consistent with our efforts to optimize and simplify our capital structure, on
October 9, 2012, we announced that we had entered into a $835 million term
loan, the proceeds of which we intend to use to redeem 10% (or approximately
$590 million) of our senior secured notes and to retire variable rate
project-level BRSP debt (approximately $218 million remaining balance). The
term loan, which amortizes at a rate of 1% per year, matures in 2019. The term
loan bears interest at LIBOR plus 3.25% per annum (subject to a LIBOR floor of
1.25%) and is expected to produce annual interest savings of approximately $25
million. “As a result of this opportunistic refinancing,” said Zamir Rauf,
Calpine’s Chief Financial Officer, “we have improved our capital structure
while reducing our cost of debt, delivering Adjusted Recurring Free Cash Flow
accretion.”

CAPITAL ALLOCATION

Portfolio Optimization

Today, we are announcing that we have entered into an agreement with Broad
River Power, LLC, a wholly owned subsidiary of Energy Capital Partners, LLC,
to sell our Broad River Energy Center, an 847 MW natural gas-fired,
simple-cycle power plant in South Carolina, for $427 million plus adjustments,
or approximately $504/kW. We expect the transaction to close in December 2012,
subject to regulatory approvals.

On October 3, 2012, we agreed to purchase the Bosque Energy Center, an 800 MW
natural gas-fired, combined-cycle power plant in Central Texas, for $432
million plus adjustments, or approximately $540/kW. The acquisition will
increase our capacity in Texas, one of our key markets. We expect the
transaction to close in November 2012 and will fund the acquisition with cash
on hand.

In addition, on May 18, 2012, our customer exercised its option to purchase
our Riverside Energy Center for approximately $392 million. The sale is
expected to close in December 2012.

Share Repurchase Program

On August 23, 2011, we announced that our Board of Directors had authorized
the repurchase of up to $300 million in shares of our common stock. In April
2012, our Board of Directors authorized us to double the size of our share
repurchase program, increasing our permitted cumulative repurchases to $600
million in shares of our common stock. The announced share repurchase program
did not specify an expiration date. The repurchases may be commenced or
suspended from time to time without prior notice. Through the filing of this
release, a total of 25.6 million shares of our outstanding common stock have
been repurchased under this program for approximately $427 million at an
average price of $16.66 per share. The shares repurchased as of the date of
this release were purchased in open market transactions.

PLANT DEVELOPMENT

West:

Russell City Energy Center: Construction at our Russell City Energy Center
continues to move forward. Upon completion, this project will bring online
approximately 429 MW of net interest baseload capacity (464 MW with peaking
capacity) representing our 75% share. Upon completion, the Russell City Energy
Center is contracted to deliver its full output to PG&E under a 10-year PPA.
Construction is ongoing and COD is expected during the summer of 2013.

Los Esteros Critical Energy Facility: During 2009, we and PG&E negotiated a
new PPA to replace the existing California Department of Water Resources
contract and facilitate the upgrade of our Los Esteros Critical Energy
Facility from a 188 MW simple-cycle generation power plant to a 309 MW
combined-cycle generation power plant, which will also increase the efficiency
and environmental performance of the power plant by lowering the heat rate.
The existing 188 MW simple-cycle facility was shut down at the end of 2011 to
allow for major maintenance on the combustion turbines and installation of the
new heat recovery steam generators and a steam turbine generator in connection
with the new PPA. Construction is ongoing and COD is expected during the
summer of 2013.

Texas:

Channel and Deer Park Expansions: We are actively permitting the addition of
520 MW^7 of combined-cycle capacity at existing sites in ERCOT, based on
tightening reserve margins and the potential impact of EPA regulations on
generation in Texas. At both our Deer Park and Channel Energy Centers, we have
the ability to install an additional combustion turbine generator and connect
to the existing steam turbine generator to expand the capacity of these
facilities and to improve overall plant efficiency. In September and November
2011, we filed air permit applications with the Texas Commission on
Environmental Quality (TCEQ) and the EPA to expand the Deer Park and Channel
Energy Centers by approximately 260 MW each. We received air permit approvals
from the TCEQ for our Deer Park and Channel expansion projects in September
and October 2012, respectively, and we executed engineering, procurement and
construction agreements during the third quarter of 2012. We expect COD in
summer 2014 for these expansions. We are currently evaluating funding sources,
including, but not limited to, nonrecourse financing, corporate financing or
internally generated funds.

North:

Garrison Energy Center: We are actively permitting 618 MW of new
combined-cycle capacity at a development site secured by a long-term lease
with the City of Dover. For the first phase (309 MW), PJM has completed a
feasibility study and a system impact study and is currently conducting a
facility study. For the second phase (309 MW), a feasibility study has been
completed and a system impact study is ongoing. Environmental permitting, site
development planning and development engineering are underway, and the first
phase’s capacity cleared PJM’s 2015/2016 base residual auction. We expect to
receive the air permit in the fourth quarter of 2012 and expect COD for the
first phase by the summer of 2015. We are currently evaluating funding
sources, including but not limited to nonrecourse financing, corporate
financing or internally generated funds.

All Segments:

Turbine Upgrades: We continue to move forward with our turbine upgrade
program. Through September30, 2012, we have completed the upgrade of eleven
Siemens and eight GE turbines totaling over 200 MW and have agreed to upgrade
approximately three additional turbines (and may upgrade additional turbines
in the future).

___________

^7 Represents incremental baseload capacity at annual average conditions.
Incremental summer peaking capacity is approximately 200 MW per unit,
supplemented by incremental efficiencies across the balance of plant.

OPERATIONS UPDATE

Third Quarter 2012 Power Operations Achievements:

  *Safety Performance:
    — Maintained stellar safety metrics
    — Recognized 10 years with no lost time incidents: Westbrook Energy
    Center, Pine Bluff Energy Center, Baytown Energy Center, Geysers plants –
    Aidlin, Sonoma, Cobb Creek, Quicksilver, Socrates

  *Availability Performance:
    — Delivered lowest year-to-date fleetwide forced outage factor on record:
    1.6%
    — Maintained impressive third quarter fleetwide starting reliability:
    98.8%

  *Cost Performance:
    — Held year-to-date plant operating expense^4 essentially flat, despite a
    31% increase in generation^3

  *Geothermal Generation:
    — Provided over 1.5 million MWh of renewable baseload generation with a
    record 0.5% forced outage factor during the third quarter of 2012

  *Natural Gas-fired Generation:
    — Increased combined-cycle capacity factor in the first nine months of
    2012 to 54.3% compared to 40.9% in the prior year period
    — Santa Rosa Energy Center: 100% starting reliability, 0.00% forced outage
    factor

Third Quarter 2012 Commercial Operations Achievements:

  *Customer-oriented Growth:
    — Entered into a 15-year PPA with Public Service Company of Oklahoma to
    provide 260 MW of capacity, energy and ancillary services from our Oneta
    Energy Center commencing in June 2016 through May 2031

FINANCIAL OUTLOOK

                                        Full Year 2012     Full Year
                                                               2013^(1)
                                         (in millions)
Adjusted EBITDA                          $ 1,725 - 1,775    $  1,760 -
                                                                  1,960
Less:
Operating lease payments                   35                     35
Major maintenance expense and              350                    370
maintenance capital expenditures^(2)
Accelerated parts purchases to support     30                     -
upgrades^(3)
Recurring cash interest, net^(4)           770                    755
Cash taxes                                 10                     15
Other                                     5                 10         
Adjusted Recurring Free Cash Flow        $ 525 - 575           $  575 - 775
Per Share Midpoint                       $ 1.16                $  1.45
                                                                             
Non-recurring interest rate swap         $ (156     )          $  -
payments^(5)
Growth capital expenditures (net of      $ (100     )          $  (250       )
debt funding)
Debt amortization                        $ (115     )          $  (140       )
Asset purchases                          $ (432     )          $  -
Asset sale proceeds^(6)                  $ 819                 $  -

________

^(1) 2013 guidance range reflects all pending acquisition and divestiture
activity, including today’s announced sale of Broad River Energy Center, which
we estimate would have contributed approximately $40 million of Adjusted
EBITDA in 2013.

^(2) Includes projected major maintenance expense of $200 million and $210
million and maintenance capital expenditures of $150 million and $160 million
in 2012 and 2013, respectively. Capital expenditures exclude major
construction and development projects. 2012 figures exclude amounts to be
funded by project debt. 2013 figures exclude non-recurring IT system upgrade.

^(3) Incremental impact on 2012 maintenance capital expenditures related to
acceleration of future turbine upgrades into 2012 and deferral of use of
on-hand parts to post-2012 periods.

^(4) Includes fees for letters of credit, net of interest income.

^(5) Interest payments related to legacy LIBOR hedges associated with floating
rate first lien credit facility, which has been retired.

^(6) Amounts subject to adjustments upon close.

As detailed above, today we are narrowing our 2012 guidance. We now project
Adjusted EBITDA of $1,725 million to $1,775 million and Adjusted Recurring
Free Cash Flow of $525 million to $575 million. We also expect to invest $100
million, net of debt funding, in growth-related projects during the year,
including our Garrison Energy Center development project and the expansion of
our Deer Park and Channel Energy Centers, as well as our ongoing turbine
upgrade program. (Though our construction projects at Russell City and Los
Esteros continue through 2012, we met our equity contribution requirements on
these projects in 2011, such that all costs incurred in 2012 and beyond will
be funded from the project debt we have secured for these projects.) Finally,
during the fourth quarter of 2012, we expect to close on the sales of our
Broad River and Riverside Energy Centers and the purchase of Bosque Energy
Center.

Today, we are also initiating 2013 guidance. We expect Adjusted EBITDA of
$1,760 million to $1,960 million and Adjusted Recurring Free Cash Flow of $575
million to $775 million. The 2013 guidance range reflects all pending
acquisition and divestiture activity, including today’s announced sale of
Broad River Energy Center, which we estimate would have contributed
approximately $40 million of Adjusted EBITDA in 2013. We also expect to invest
$250 million, net of debt funding, in our ongoing growth-related projects
during the year.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results
for the third quarter of 2012 on Tuesday, November 6,2012, at 11 a.m. ET / 10
a.m. CT. A listen-only webcast of the call may be accessed through our website
at www.calpine.com, or by dialing (888) 895-5271 in the U.S. or (847) 619-6547
outside the U.S. The confirmation code is 33421254. An archived recording of
the call will be made available for a limited time on our website or by
dialing (888) 843-7419 in the U.S. or (630) 652-3042 outside the U.S. and
providing confirmation code 33421254. Presentation materials to accompany the
conference call will be available on our website on November 6, 2012.

ABOUT CALPINE

Calpine Corporation is the largest independent power producer in the U.S.,
with a fleet of 93 power generation plants representing more than 28,000
megawatts of generation capacity. Last year our plants generated more than 94
million megawatt hours of power for our wholesale customers in 20 states and
Canada. Our 91 operating plants as well as two under construction consist
primarily of natural gas-fired and renewable geothermal power plants that use
advanced technologies to generate power in a low-carbon and environmentally
responsible manner. Our modern, clean, efficient and cost-effective fleet
stands ready to respond to the increased need for cleaner and more affordable
power as the economy recovers, as new environmental rules are implemented and
force older, dirtier plants to retire or reduce generation, as variable
renewable power generation from wind and solar grows and with it the need for
flexible natural gas generation to assure firm supply to the grid, and
finally, as natural gas becomes economically competitive with coal as a fuel
for power generation. Please visit www.calpine.com to learn more about why
Calpine is a generation ahead - today. Calpine’s Quarterly Report on Form 10-Q
for the quarter ended September 30, 2012, has been filed with the Securities
and Exchange Commission (SEC) and may be found on the SEC’s website at
www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this release contains “forward-looking
statements” within the meaning of the Private Securities Litigation Reform Act
of 1995, Section27A of the Securities Act, and Section21E of the Exchange
Act. Forward-looking statements may appear throughout this release. We use
words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,”
“will,” “should,” “estimate,” “potential,” “project” and similar expressions
to identify forward-looking statements. Such statements include, among others,
those concerning our expected financial performance and strategic and
operational plans, as well as all assumptions, expectations, predictions,
intentions or beliefs about future events. You are cautioned that any such
forward-looking statements are not guarantees of future performance and that a
number of risks and uncertainties could cause actual results to differ
materially from those anticipated in the forward-looking statements. Such
risks and uncertainties include, but are not limited to:

  *Financial results that may be volatile and may not reflect historical
    trends due to, among other things, fluctuations in prices for commodities
    such as natural gas and power, changes in U.S. macroeconomic conditions,
    fluctuations in liquidity and volatility in the energy commodities markets
    and our ability to hedge risks;
  *Laws, regulations and market rules in the markets in which we participate
    and our ability to effectively respond to changes in laws, regulations or
    market rules or the interpretation thereof including those related to the
    environment, derivative transactions and market design in the regions in
    which we operate;
  *The unknown future impact on our business from the Dodd-Frank Act and the
    rules to be promulgated thereunder;
  *Our ability to manage our liquidity needs and to comply with covenants
    under our First Lien Notes, Corporate Revolving Facility, First Lien Term
    Loans, 2019 First Lien Term Loan, CCFC Notes and other existing financing
    obligations;
  *Risks associated with the continued economic and financial conditions
    affecting certain countries in Europe including financial institutions
    located within those countries and their ability to fund their financial
    commitments;
  *Risks associated with the operation, construction and development of power
    plants including unscheduled outages or delays and plant efficiencies;
  *Risks related to our geothermal resources, including the adequacy of our
    steam reserves, unusual or unexpected steam field well and pipeline
    maintenance requirements, variables associated with the injection of
    wastewater to the steam reservoir and potential regulations or other
    requirements related to seismicity concerns that may delay or increase the
    cost of developing or operating geothermal resources;
  *Competition, including risks associated with marketing and selling power
    in the evolving energy markets;
  *The expiration or early termination of our PPAs and the related results on
    revenues;
  *Future capacity revenues may not occur at expected levels;
  *Natural disasters, such as hurricanes, earthquakes and floods, acts of
    terrorism or cyber attacks that may impact our power plants or the markets
    our power plants serve and our corporate headquarters;
  *Disruptions in or limitations on the transportation of natural gas, fuel
    oil and transmission of power;
  *Our ability to manage our customer and counterparty exposure and credit
    risk, including our commodity positions;
  *Our ability to attract, motivate and retain key employees;
  *Present and possible future claims, litigation and enforcement actions;
    and
  *Other risks identified in this press release and in our 2011 Form 10-K.

Given the risks and uncertainties surrounding forward-looking statements, you
should not place undue reliance on these statements. Many of these factors are
beyond our ability to control or predict. Our forward-looking statements speak
only as of the date of this release. Other than as required by law, we
undertake no obligation to update or revise forward-looking statements,
whether as a result of new information, future events, or otherwise.

CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

                  Three Months Ended September  Nine Months Ended September
                   30,                            30,
                   2012           2011           2012           2011
                   (in millions, except share and per share amounts)
Operating          $  1,996        $  2,209       $  4,111        $  5,341
revenues
Operating
expenses:
Fuel and
purchased energy   893             1,401          2,137           3,470
expense
Plant operating    207             212            699             711
expense
Depreciation and
amortization       140             143            418             405
expense
Sales, general
and other          36              33             104             99
administrative
expense
Other operating    22             22            67             64        
expenses
Total operating    1,298          1,811         3,425          4,749     
expenses
(Income) from
unconsolidated     (7        )     (5        )    (21       )     (12       )
investments in
power plants
Income from        705             403            707             604
operations
Interest expense   183             192            552             575
Loss on interest   —               3              14              149
rate derivatives
Interest           (2        )     (2        )    (7        )     (7        )
(income)
Debt
extinguishment     —               (4        )    12              94
costs
Other (income)     6              4             14             14        
expense, net
Income (loss)
before income      518             210            122             (221      )
taxes
Income tax
expense            81             20            23             (45       )
(benefit)
Net income         437             190            99              (176      )
(loss)
Net income
attributable to
the                —              —             —              (1        )
noncontrolling
interest
Net income
(loss)             $  437         $  190        $  99          $  (177   )
attributable to
Calpine
Basic earnings
(loss) per
common share
attributable to
Calpine:
Weighted average
shares of common
stock              462,307        486,420       470,589        486,363   
outstanding (in
thousands)
Net income
(loss) per
common share       $  0.95        $  0.39       $  0.21        $  (0.36  )
attributable to
Calpine — basic
                                                                  
Diluted earnings
(loss) per
common share
attributable to
Calpine:
Weighted average
shares of common
stock              465,953        489,062       474,131        486,363   
outstanding (in
thousands)
Net income
(loss) per
common share       $  0.94        $  0.39       $  0.21        $  (0.36  )
attributable to
Calpine —
diluted
                                                                            

CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

                                     September 30,           December 31,
                                      2012                     2011
                                      (in millions, except share and per share
                                      amounts)
ASSETS
Current assets:
Cash and cash equivalents             $     1,097              $   1,252
Accounts receivable, net of           500                      598
allowance of $10 and $13
Margin deposits and other prepaid     143                      193
expense
Restricted cash, current              163                      139
Derivative assets, current            487                      1,051
Inventory and other current assets    297                     329          
Total current assets                  2,687                    3,562
Property, plant and equipment, net    13,129                   13,019
Restricted cash, net of current       63                       55
portion
Investments                           79                       80
Long-term derivative assets           146                      113
Other assets                          489                     542          
Total assets                          $     16,593            $   17,371   
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable                      $     361                $   435
Accrued interest payable              163                      200
Debt, current portion                 105                      104
Derivative liabilities, current       457                      1,144
Other current liabilities             265                     279          
Total current liabilities             1,351                    2,162
Debt, net of current portion          10,567                   10,321
Long-term derivative liabilities      286                      279
Other long-term liabilities           275                     245          
Total liabilities                     12,479                   13,007
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value
per share; authorized 100,000,000     —                        —
shares, none issued and outstanding
Common stock, $0.001 par value per
share; authorized 1,400,000,000
shares, 492,072,137 and 490,468,815   1                        1
shares issued, respectively, and
465,572,396 and 481,743,738 shares
outstanding, respectively
Treasury stock, at cost, 26,499,741   (439             )       (125         )
and 8,725,077 shares, respectively
Additional paid-in capital            12,327                   12,305
Accumulated deficit                   (7,600           )       (7,699       )
Accumulated other comprehensive       (237             )       (178         )
loss
Total Calpine stockholders’ equity    4,052                    4,304
Noncontrolling interest               62                      60           
Total stockholders’ equity            4,114                   4,364        
Total liabilities and stockholders’   $     16,593            $   17,371   
equity
                                                                            

CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

                                              Nine Months Ended September 30,
                                               2012              2011
                                               (in millions)
Cash flows from operating activities:
Net income (loss)                              $   99             $  (176   )
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation and amortization expense^(1)      449                431
Debt extinguishment costs                      —                  82
Deferred income taxes                          (7          )      (56       )
Loss on disposition of assets                  10                 18
Unrealized mark-to-market activities, net      (103        )      42
(Income) from unconsolidated investments in    (21         )      (12       )
power plants
Return on unconsolidated investments in        20                 6
power plants
Stock-based compensation expense               19                 18
Other                                          1                  5
Change in operating assets and liabilities:
Accounts receivable                            96                 (87       )
Derivative instruments, net                    (114        )      (6        )
Other assets                                   97                 27
Accounts payable and accrued expenses          (119        )      95
Settlement of non-hedging interest rate        156                147
swaps
Other liabilities                              25                2         
Net cash provided by operating activities      608               536       
Cash flows from investing activities:
Purchases of property, plant and equipment     (509        )      (511      )
Settlement of non-hedging interest rate        (156        )      (147      )
swaps
Return of investment in unconsolidated         5                  —
investment in power plants
(Increase) decrease in restricted cash         (32         )      9
Purchases of deferred transmission credits     (12         )      (16       )
Other                                          3                 5         
Net cash used in investing activities          $   (701    )      $  (660   )
Cash flows from financing activities:
Repayment of First Lien Term Loans             $   (12     )      $  —
Borrowings under First Lien Term Loans         —                  1,657
Repayments on NDH Project Debt                 —                  (1,283    )
Issuance of 2023 First Lien Notes              —                  1,200
Repayments on First Lien Credit Facility       —                  (1,191    )
Borrowings from project financing, notes       312                223
payable and other
Repayments of project financing, notes         (53         )      (476      )
payable and other
Capital contributions from noncontrolling      —                  34
interest holder
Financing costs                                (6          )      (78       )
Stock repurchases                              (308        )      —
Other                                          5                 (4        )
Net cash provided by (used in) financing       (62         )      82        
activities
Net decrease in cash and cash equivalents      (155        )      (42       )
Cash and cash equivalents, beginning of        1,252             1,327     
period
Cash and cash equivalents, end of period       $   1,097         $  1,285  
                                                                  
Cash paid during the period for:
Interest, net of amounts capitalized           $   565            $  509
Income taxes                                   $   14             $  15
                                                                  
Supplemental disclosure of non-cash
investing and financing activities:
Change in capital expenditures included in     $   (3      )      $  (13    )
accounts payable
Additions to property, plant and equipment     $   8              $  —
through assumption of long-term note payable

__________

^(1) Includes depreciation and amortization included in fuel and purchased
energy expense and interest expense on our Consolidated Condensed Statements
of Operations.

REGULATION G RECONCILIATIONS

Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted
Recurring Free Cash Flow are non-GAAP financial measures that we use as
measures of our performance. These measures should be viewed as a supplement
to and not a substitute for our U.S. GAAP measures of performance.

Net Income (Loss), As Adjusted, represents net income (loss) attributable to
Calpine, adjusted for certain non-cash and non-recurring items as previously
detailed in Table 1, including debt extinguishment costs, unrealized
mark-to-market (gain) loss on derivatives, and other adjustments. Net Income
(Loss), As Adjusted, is presented because we believe it is a useful tool for
assessing the operating performance of our company in the current period. Net
Income (Loss), As Adjusted, is not intended to represent net income (loss),
the most comparable U.S. GAAP measure, as an indicator of operating
performance and is not necessarily comparable to similarly titled measures
reported by other companies.

Commodity Margin includes our power and steam revenues, sales of purchased
power and physical natural gas, capacity revenue, revenue from renewable
energy credits, sales of surplus emission allowances, transmission revenue and
expenses, fuel and purchased energy expense, fuel transportation expense, RGGI
compliance and other environmental costs, and cash settlements from our
marketing, hedging and optimization activities including natural gas
transactions hedging future power sales that are included in mark-to-market
activity, but excludes the unrealized portion of our mark-to-market activity
and other revenues. Commodity Margin is presented because we believe it is a
useful tool for assessing the performance of our core operations, and it is a
key operational measure reviewed by our chief operating decision maker.
Commodity Margin does not intend to represent income (loss) from operations,
the most comparable U.S. GAAP measure, as an indicator of operating
performance and is not necessarily comparable to similarly titled measures
reported by other companies.

Adjusted EBITDA represents net income (loss) attributable to Calpine before
net (income) loss attributable to the noncontrolling interest, interest,
taxes, depreciation and amortization, adjusted for certain non-cash and
non-recurring items as detailed in the following reconciliation. Adjusted
EBITDA is presented because our management uses Adjusted EBITDA as a measure
of operating performance to assist in comparing performance from period to
period on a consistent basis and to readily view operating trends, as a
measure for planning and forecasting overall expectations and for evaluating
actual results against such expectations, and in communications with our Board
of Directors, shareholders, creditors, analysts and investors concerning our
financial performance. We believe Adjusted EBITDA is also used by and is
useful to investors and other users of our financial statements in evaluating
our operating performance because it provides them with an additional tool to
compare business performance across companies and across periods. We believe
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. Adjusted EBITDA is not
a measure calculated in accordance with U.S. GAAP and should be viewed as a
supplement to and not a substitute for our results of operations presented in
accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash
flows from operations or net income (loss) as defined by U.S. GAAP as an
indicator of operating performance and is not necessarily comparable to
similarly titled measures reported by other companies.

Adjusted Recurring Free Cash Flow represents net income before interest,
taxes, depreciation and amortization, as adjusted, less operating lease
payments, major maintenance expense and maintenance capital expenditures, net
cash interest, cash taxes, working capital and other adjustments. Adjusted
Recurring Free Cash Flow is a performance measure and is not intended to
represent net income (loss), the most directly comparable U.S. GAAP measure,
or liquidity and is not necessarily comparable to similarly titled measures
reported by other companies.

Commodity Margin Reconciliation

The following table reconciles our Commodity Margin to its U.S. GAAP results
for the three months ended September 30, 2012 and 2011 (in millions):

                Three Months Ended September 30, 2012
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 330     $ 218     $ 266     $  83       $    —          $ 897
Margin^(1)
Add:
Mark-to-market
commodity        (40   )   249       (26   )   27          (8        )     202
activity, net
and
other^(2)(3)
Less:
Plant
operating        88        49        51        29          (10       )     207
expense
Depreciation
and              52        35        33        21          (1        )     140
amortization
expense
Sales, general
and other        9         12        8         8           (1        )     36
administrative
expense
Other
operating        10        1         6         (1     )    2               18
expenses^(4)
(Income) from
unconsolidated   —        —        (7    )   —          —              (7    )
investments in
power plants
Income from      $ 131    $ 370    $ 149    $  53      $    2         $ 705 
operations
                                                                                 
                 Three Months Ended September 30, 2011
                                                           Consolidation
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 329     $ 162     $ 259     $  75       $    —          $ 825
Margin^(1)
Add:
Mark-to-market
commodity        20        (21   )   (11   )   —           (8        )     (20   )
activity, net
and
other^(2)(3)
Less:
Plant
operating        94        50        44        33          (9        )     212
expense
Depreciation
and              52        34        36        22          (1        )     143
amortization
expense
Sales, general
and other        10        10        7         7           (1        )     33
administrative
expense
Other
operating        11        (1    )   7         —           2               19
expenses^(4)
(Income) from
unconsolidated   —        —        (5    )   —          —              (5    )
investments in
power plants
Income from      $ 182    $ 48     $ 159    $  13      $    1         $ 403 
operations

Commodity Margin Reconciliation (continued)

The following table reconciles our Commodity Margin to its U.S. GAAP results
for the nine months ended September 30, 2012 and 2011 (in millions):

                Nine Months Ended September 30, 2012
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 748     $ 472     $ 591     $  212      $    —          $ 2,023
Margin^(1)
Add:
Mark-to-market
commodity        (80   )   66        (17   )   (5      )   (22       )     (58     )
activity, net
and
other^(2)(5)
Less:
Plant
operating        281       189       154       98          (23       )     699
expense
Depreciation
and              151       104       100       66          (3        )     418
amortization
expense
Sales, general
and other        23        36        22        23          —               104
administrative
expense
Other
operating        30        4         21        2           1               58
expenses^(4)
(Income) from
unconsolidated   —        —        (21   )   —          —              (21     )
investments in
power plants
Income from      $ 183    $ 205    $ 298    $  18      $    3         $ 707   
operations
                 
                 Nine Months Ended September 30, 2011
                                                           Consolidation
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 798     $ 357     $ 578     $  188      $    —          $ 1,921
Margin^(1)
Add:
Mark-to-market
commodity        36        (54   )   (12   )   (4      )   (23       )     (57     )
activity, net
and
other^(2)(5)
Less:
Plant
operating        297       193       136       107         (22       )     711
expense
Depreciation
and              140       99        102       67          (3        )     405
amortization
expense
Sales, general
and other        29        33        19        18          —               99
administrative
expense
Other
operating        30        2         23        3           (1        )     57
expenses^(4)
(Income) from
unconsolidated   —        —        (12   )   —          —              (12     )
investments in
power plants
Income (loss)
from             $ 338    $ (24 )   $ 298    $  (11  )   $    3         $ 604   
operations

__________

^(1) Our North segment includes Commodity Margin related to Riverside Energy
Center, LLC, of $32 million and $31 million for the three months ended
September30, 2012 and 2011, respectively, and $64 million and $62 million for
the nine months ended September30, 2012 and 2011, respectively.

^(2) Mark-to-market commodity activity represents the change in the unrealized
portion of our mark-to-market activity, net, included in operating revenues
and fuel and purchased energy expense on our Consolidated Condensed Statements
of Operations.

^(3) Includes $16 million and $11 million of lease levelization for the three
months ended September 30, 2012 and 2011, respectively, and $4 million of
amortization expense for each of the three months ended September30, 2012 and
2011.

^(4) Excludes $4 million and $3 million of RGGI compliance and other
environmental costs for the three months ended September30, 2012 and 2011,
respectively, and $9 million and $7 million for the nine months ended
September30, 2012 and 2011, respectively, which are components of Commodity
Margin.

^(5) Includes $7 million and $15 million of lease levelization and $11 million
and $5 million of amortization expense for the nine months ended September30,
2012 and 2011, respectively.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted
Recurring Free Cash Flow to our net income (loss) attributable to Calpine for
the three and nine months ended September 30, 2012 and 2011, as reported under
U.S. GAAP.

                      Three Months Ended September  Nine Months Ended
                       30,                            September 30,
                       2012            2011          2012          2011
                       (in millions)
Net income (loss)
attributable to        $   437          $  190        $  99          $ (177  )
Calpine
Net income
attributable to the    —                —             —              1
noncontrolling
interest
Income tax expense     81               20            23             (45     )
(benefit)
Debt extinguishment
costs and other        6                —             26             108
(income) expense,
net
Loss on interest       —                3             14             149
rate derivatives
Interest expense,
net of interest        181             190          545           568     
income
Income from            $   705          $  403        $  707         $ 604
operations
Add:
Adjustments to
reconcile income
from operations to
Adjusted EBITDA:
Depreciation and
amortization
expense, excluding     140              143           419            406
deferred financing
costs^(1)
Major maintenance      31               33            158            169
expense
Operating lease        9                9             26             26
expense
Unrealized (gain)
loss on commodity
derivative             (219       )     9             49             48
mark-to-market
activity
Adjustments to
reflect Adjusted
EBITDA from            7                9             23             30
unconsolidated
investments^(2)(3)
Stock-based            6                6             19             18
compensation expense
Loss on dispositions   5                8             9              17
of assets
Acquired contract      4                4             11             5
amortization
Other                  18              14           13            24      
Total Adjusted         $   706         $  638       $  1,434      $ 1,347 
EBITDA
Less:
Lease payments         9                9             26             26
Major maintenance
expense and capital    43               72            298            335
expenditures^(4)
Cash interest,         190              194           571            587
net^(5)
Cash taxes             (1         )     1             10             11
Other                  2               1            6             7       
Adjusted Recurring     $   463         $  361       $  523        $ 381   
Free Cash Flow^(6)
                                                                     
Weighted average
shares of common
stock outstanding      465,953         489,062      474,131       486,363 
(diluted, in
thousands)
Adjusted Recurring
Free Cash Flow         $   0.99        $  0.74      $  1.10       $ 0.78  

Per Share (Diluted)

_________

^(1) Depreciation and amortization expense in the income from operations
calculation on our Consolidated Condensed Statements of Operations excludes
amortization of other assets.

^(2) Included on our Consolidated Condensed Statements of Operations in
(income) from unconsolidated investments in power plants.

^(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments
include unrealized (gain) loss on mark-to-market activity of nil for each of
the three and nine months ended September 30, 2012, and $1 million for each of
the three and nine months ended September 30, 2011.

^(4) Includes $19 million and $150 million in major maintenance expense for
the three and nine months ended September 30, 2012, respectively, and $24
million and $148 million in maintenance capital expenditures for the three and
nine months ended September 30, 2012, respectively. Includes $36 million and
$174 million in major maintenance expense for the three and nine months ended
September 30, 2011, respectively, and $36 million and $161 million in
maintenance capital expenditures for the three and nine months ended September
30, 2011, respectively.

^(5) Includes commitment, letter of credit and other bank fees from both
consolidated and unconsolidated investments, net of capitalized interest and
interest income.

^(6) Excludes an increase in working capital of $4 million and a decrease in
working capital of $16 million for the three and nine months ended September
30, 2012, respectively, and increases in working capital of $166 million and
$21 million for the three and nine months ended September 30, 2011,
respectively. Adjusted Recurring Free Cash Flow, as reported, excludes changes
in working capital, such that it is calculated on the same basis as our
guidance.

Consolidated Adjusted EBITDA Reconciliation (continued)

In the following table, we have reconciled our Adjusted EBITDA to our
Commodity Margin, both of which are non-GAAP measures, for the three and nine
months ended September 30, 2012 and 2011. Reconciliations for both Adjusted
EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided
above.

                      Three Months Ended        Nine Months Ended September
                       September 30,              30,
                       2012         2011         2012           2011
                       (in millions)
Commodity Margin       $  897        $  825       $  2,023        $  1,921
Other revenue          3             4            9               11
Plant operating        (167    )     (166    )    (518      )     (512      )
expense^(1)
Sales, general and
administrative         (34     )     (30     )    (94       )     (85       )
expense^(2)
Other operating        (9      )     (11     )    (30       )     (30       )
expenses^(3)
Adjusted EBITDA from
unconsolidated         14            15           44              42
investments in power
plants^(4)
Other                  2            1           —              —         
Adjusted EBITDA        $  706       $  638      $  1,434       $  1,347  

_________

^(1) Shown net of major maintenance expense, stock-based compensation expense,
non-cash loss on dispositions of assets and other costs.

^(2) Shown net of stock-based compensation expense and other costs.

^(3) Shown net of operating lease expense, amortization, RGGI compliance and
other costs.

^(4) Amount is comprised of income from unconsolidated investments in power
plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated
investments.

Adjusted EBITDA and Adjusted Recurring Free Cash Flow Reconciliation for
Guidance

Full Year 2012 Range:                      Low    High
                                            (in millions)
GAAP Net Income ^(1)                        $   250             $   300
Plus:
Debt extinguishment costs                   12                  12
Loss on interest rate derivatives           14                  14
Interest expense, net of interest income    760                 760
Depreciation and amortization expense       575                 575
Major maintenance expense                   205                 205
Operating lease expense                     35                  35
(Gain) on sale of assets                    (210       )        (210        )
Other^(2)                                   84                 84          
Adjusted EBITDA                             $   1,725           $   1,775
Less:
Operating lease payments                    35                  35
Major maintenance expense and maintenance   350                 350
capital expenditures^(3)
Accelerated parts purchases to support      30                  30
upgrades^(4)
Recurring cash interest, net^(5)            770                 770
Cash taxes                                  10                  10
Other                                       5                  5           
Adjusted Recurring Free Cash Flow           $   525            $   575     
Non-recurring interest rate swap            $   (156   )        $   (156    )
payments^(6)

_________

^(1) For purposes of Net Income guidance reconciliation, unrealized
mark-to-market adjustments are assumed to be nil.

^(2) Other includes stock-based compensation expense, adjustments to reflect
Adjusted EBITDA from unconsolidated investments, income tax expense and other
items.

^(3) Includes projected major maintenance expense of $200 million and
maintenance capital expenditures of $150 million. Capital expenditures exclude
major construction and development projects. 2012 figures exclude amounts to
be funded by project debt.

^(4) Incremental impact on 2012 maintenance capital expenditures related to
acceleration of future turbine upgrades into 2012 and deferral of use of
on-hand parts to post-2012 periods.

^(5) Includes fees for letters of credit, net of interest income.

^(6) Interest payments related to legacy LIBOR hedges associated with floating
rate First Lien Credit Facility, which has been retired.

Full Year 2013 Range^1:                   Low      High
                                          (in millions)
GAAP Net Income ^(2)                    $ 135                 $ 335
Plus:
Interest expense, net of interest         745                   745
income
Depreciation and amortization expense     575                   575
Major maintenance expense                 205                   205
Operating lease expense                   35                    35
Other^(3)                                 65                   65
Adjusted EBITDA                         $ 1,760               $ 1,960
Less:
Operating lease payments                  35                    35
Major maintenance expense and             370                   370
maintenance capital expenditures^(4)
Recurring cash interest, net^(5)          755                   755
Cash taxes                                15                    15
Other                                     10                   10
Adjusted Recurring Free Cash Flow       $ 575                 $ 775

_________

^(1) 2013 guidance range reflects all pending acquisition and divestiture
activity, including today’s announced sale of Broad River Energy Center, which
we estimate would have contributed approximately $40 million of Adjusted
EBITDA in 2013.

^(2) For purposes of Net Income guidance reconciliation, unrealized
mark-to-market adjustments are assumed to be nil.

^(3) Other includes stock-based compensation expense, adjustments to reflect
Adjusted EBITDA from unconsolidated investments, income tax expense and other
items.

^(4) Includes projected major maintenance expense of $210 million and
maintenance capital expenditures of $160 million. Capital expenditures exclude
major construction and development projects. 2013 figures exclude
non-recurring IT system upgrade.

^(5) Includes fees for letters of credit, net of interest income.

OPERATING PERFORMANCE METRICS

The table below shows the operating performance metrics for continuing
operations:

                       Three Months Ended September   Nine Months Ended
                      30,                           September
                                                      30,
                       2012            2011          2012         2011
Total MWh generated    32,291           28,400        87,027        65,921
(in thousands)^(1)
West                   9,817            6,540         24,211        16,189
Texas                  10,025           10,833        28,257        24,019
Southeast              5,821            5,918         17,744        14,489
North                  6,628            5,109         16,815        11,224
                                                                    
Average availability   97.7     %       95.9     %    91.5    %     89.8    %
West                   98.5     %       91.2     %    91.2    %     86.4    %
Texas                  97.2     %       98.2     %    90.4    %     88.8    %
Southeast              98.3     %       96.6     %    94.4    %     92.0    %
North                  96.9     %       97.5     %    90.5    %     92.3    %
                                                                    
Average capacity
factor, excluding      61.0     %       53.8     %    55.7    %     42.9    %
peakers^(1)
West                   70.7     %       47.4     %    58.7    %     39.6    %
Texas                  64.7     %       70.1     %    61.3    %     52.5    %
Southeast              48.4     %       48.9     %    49.6    %     41.0    %
North                  56.1     %       43.4     %    49.7    %     34.4    %
                                                                    
Steam adjusted heat    7,404            7,464         7,357         7,434
rate (mmbtu/kWh)
West                   7,313            7,479         7,267         7,488
Texas                  7,211            7,296         7,149         7,256
Southeast              7,325            7,344         7,302         7,323
North                  7,943            8,003         7,918         7,939

________

^(1) Excludes generation from unconsolidated power plants and power plants
owned but not operated by us.

Contact:

Calpine Corporation
Norma F. Dunn, 713-830-8883 (Media Relations)
norma.dunn@calpine.com
Bryan Kimzey, 713-830-8777 (Investor Relations)
bryan.kimzey@calpine.com
 
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