Calpine Reports Fourth Quarter and Full Year 2012 Results, Raises Adjusted Free Cash Flow Per Share Guidance and Increases Share

  Calpine Reports Fourth Quarter and Full Year 2012 Results, Raises Adjusted
  Free Cash Flow Per Share Guidance and Increases Share Repurchase
  Authorization by $400 Million

Business Wire

HOUSTON -- February 13, 2013

Calpine Corporation (NYSE: CPN)

Summary of 2012 Financial Results (in millions, except per share amounts):

            Three Months Ended December 31,   Year Ended December 31,
             2012       2011       % Change   2012      2011       % Change
                                                                       
Operating    $ 1,367     $ 1,459     (6.3  )%   $ 5,478    $ 6,800     (19.4 )%
Revenues
Commodity    $ 515       $ 553       (6.9  )%   $ 2,538    $ 2,474     2.6   %
Margin
Adjusted     $ 315       $ 379       (16.9 )%   $ 1,749    $ 1,726     1.3   %
EBITDA
Adjusted
Free Cash    $ 41        $ 108       (62.0 )%   $ 564      $ 489       15.3  %
Flow
Per Share    $ 0.09      $ 0.22      (59.1 )%   $ 1.20     $ 1.01      18.8  %
(diluted)
Net Income   $ 100       $ (13   )              $ 199      $ (190  )
(Loss)^1
Per Share    $ 0.22      $ (0.03 )              $ 0.42     $ (0.39 )
(diluted)
Net Income
(Loss), As   $ (86   )   $ (43   )              $ 78       $ (13   )
Adjusted^2
                                                                       


2013 Full Year Guidance (in millions, except per share amounts):
                                           2013
                                            
Adjusted EBITDA                             $1,760 - 1,960
Adjusted Free Cash Flow                     $575 - 775
Per Share Midpoint (diluted)                $1.50
                                            

Recent Achievements:

  *Operations:
    — Generated approximately 116 million MWh^3 of electricity in 2012, a
    record and 23% more than 2011
    — Held 2012 normal, recurring plant operating expense^4 essentially flat,
    despite increased generation^3, after accounting for prior period
    insurance reimbursements in 2011
    — Delivered lowest annual fleetwide forced outage factor on record: 1.6%
    — Achieved remarkable annual fleetwide starting reliability: 98.3%

  *Commercial:
    — Entered into a new 10-year PPA with Tennessee Valley Authority to
    provide the full output of power from our Decatur Energy Center,
    commencing in January 2013
    — Completed sales of Broad River and Riverside Energy Centers for
    approximately $829 million^5
    — Completed acquisition of Bosque Energy Center for approximately $432
    million

  *Capital Allocation:
    — Completed previously announced share repurchase program, having
    repurchased approximately 35.6 million shares, or 7.25%^6, of our
    outstanding common stock
    — Announced authorization of $400 million additional share repurchases:
    cumulative authorized total now $1 billion
    — Invested in future growth with development of approximately 1,600 MW of
    new combined-cycle power plants

Calpine Corporation (NYSE: CPN) today reported fourth quarter 2012 Adjusted
EBITDA of $315 million, compared to $379 million in the prior year period, and
Adjusted Free Cash Flow of $41 million, or $0.09 per diluted share, compared
to $108 million, or $0.22 per diluted share, in the prior year period. Net
Income^1 for the fourth quarter was $100 million, or $0.22 per diluted share,
compared to a Net Loss^1 of $13 million, or $0.03 per diluted share, in the
prior year period. Net Loss, As Adjusted^2, for the fourth quarter of 2012 was
$86 million compared to $43 million in the prior year period. The declines in
fourth quarter Adjusted EBITDA, Adjusted Free Cash Flow and Net Loss, As
Adjusted^2, in 2012 compared to 2011 were driven primarily by lower Commodity
Margin, largely as a result of differences in the seasonal shaping of our
hedging activity which tended to benefit the fourth quarter of 2011 more so
than the comparable 2012 period.

Full year 2012 Adjusted EBITDA was $1,749 million, compared to $1,726 million
in the prior year period, and Adjusted Free Cash Flow was $564 million, or
$1.20 per diluted share, compared to $489 million, or $1.01 per diluted share,
in the prior year period. Net Income^1 for 2012 was $199 million, or $0.42 per
diluted share, compared to a Net Loss^1 of $190 million, or $0.39 per diluted
share, in the prior year period. Net Income, As Adjusted^2, for 2012 was $78
million compared to a Net Loss, As Adjusted^2, of $13 million in 2011. The
increases in 2012 Adjusted Free Cash Flow and Net Income, As Adjusted^2,
compared to 2011 were primarily due to higher Commodity Margin and lower
interest expense resulting from our refinancing efforts.

“2012 was a breakout year for Calpine, as we capitalized on the secular shift
toward greater utilization of combined-cycle gas turbines in the power
generation industry,” said Jack Fusco, Calpine’s Chief Executive Officer. “We
achieved record operating results, generating 116 million MWh – 23% more than
last year. The increased generation was primarily due to our excellent power
plant operations and unprecedented coal-to-gas switching. Overall, our
business continues to be resilient across a wide range of natural gas prices.

“I want to thank our employees for their outstanding response to the increased
utilization of our fleet and their success in concurrently decreasing major
maintenance cost and holding plant operating expenses essentially flat. This
was due in large part to our continued focus on operational excellence and
preventative maintenance, which also yielded our lowest annual forced outage
factor on record.

“2012 was an active year for allocating capital as well. We sold 1,450 MW at
two plants in South Carolina and Wisconsin and redeployed more than half the
proceeds to purchase an 800 MW plant in Texas, while also continuing to
execute our share repurchase program. We originated more than 2,100 MW of
long-term contracts with our customers. In addition, we are on track to bring
approximately 1,600 MW of additional natural gas-fired capacity online in
California, Texas and Delaware over the next two and a half years.

“Finally, we ended the year with more than $1 billion of excess cash. Based on
the strength of our balance sheet at year-end and the completion early this
year of our $600 million share repurchase program, our Board has authorized a
$400 million increase to our share repurchase program. We will continue to
balance this authorization against growth opportunities in order to maximize
shareholder value.”

“We successfully delivered on our 2012 financial commitments with Adjusted
EBITDA and Adjusted Free Cash Flow of $1,749 million and $564 million,
respectively, each of which was at the high end of our original guidance
ranges,” said Zamir Rauf, Calpine’s Chief Financial Officer. “This resulted in
a 19% increase in Adjusted Free Cash Flow Per Share to $1.20, which is also at
the high end of our 15-20% compound annual growth rate target. Turning to
2013, based on the completion of our previously authorized $600 million share
repurchase program, we are raising our Adjusted Free Cash Flow Per Share
midpoint guidance to $1.50, which represents a 25% increase over 2012, while
maintaining our full year Adjusted EBITDA and Adjusted Free Cash Flow guidance
ranges.”

__________

^1 Reported as net income (loss) attributable to Calpine on our Consolidated
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 three months and
years ended December 31, 2011 and 2012.

^5 Includes fees associated with a five-year consulting agreement with the
buyer of Broad River Energy Center.

^6 Based upon shares outstanding (including shares held in reserve) as of June
30, 2011, immediately prior to announcement of program.

SUMMARY OF FINANCIAL PERFORMANCE

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2012 was $315 million, compared to
$379 million in the prior year period. The year-over-year decrease in Adjusted
EBITDA was primarily due to a $38 million decrease in Commodity Margin and a
$20 million increase in plant operating expense^4. The decrease in Commodity
Margin was primarily due to:

      –  lower contribution from hedges and
                expiration of contracts, particularly in our West and
            –   Southeast segments, some of which have since been
                recontracted, partially offset by
            +   higher regulatory capacity revenue.

The increase in plant operating expense^4 was primarily due to reimbursements
for insurance claims from prior periods that disproportionately reduced our
plant operating expense in the fourth quarter of 2011.

Net Income^1 was $100 million for the fourth quarter of 2012, compared to a
Net Loss^1 of $13 million in the prior year period. As detailed in Table 1,
Net Loss, As Adjusted^2, was $86 million in the fourth quarter of 2012
compared to $43 million in the prior year period. The year-over-year decline
was driven largely by:

      –  lower Commodity Margin, as previously discussed and
            –   higher plant operating expense, as previously discussed,
                partially offset by
                an income tax benefit primarily due to a decrease in state
            +   income taxes and a reduction in income tax expense related to
                the application of non-cash intraperiod tax allocations.

Full Year Results

Adjusted EBITDA in 2012 was $1,749 million compared to $1,726 million in 2011.
The year-over-year increase in Adjusted EBITDA was primarily due to a $64
million increase in Commodity Margin, partially offset by a $26 million
increase in plant operating expense^4 and a $14 million increase in sales,
general and administrative expense^7. The increase in Commodity Margin was
primarily due to:

      +  higher contribution from hedges
                higher generation in our Texas and North segments due to lower
                natural gas prices and higher generation in our West segment
            +   due to improved market conditions, less hydroelectric
                generation and a nuclear power plant outage in California
                during 2012 and
                an extreme cold weather event in Texas that occurred in 2011
            +   that resulted in unplanned outages at some of our power
                plants, negatively impacting our revenue in 2011, which did
                not reoccur in 2012, partially offset by
            –   lower regulatory capacity revenue and
            –   expiration of contracts, some of which have since been
                recontracted.

The increase in plant operating expense^4 was primarily due to prior period
insurance reimbursements that benefited 2011 compared to 2012, as previously
discussed.

Net Income^1 was $199 million in 2012, compared to a Net Loss^1 of $190
million in 2011. As detailed in Table 1, Net Income, As Adjusted^2, was $78
million in 2012, compared to Net Loss, As Adjusted^2, of $13 million in 2011.
The year-over-year improvement was driven largely by:

      +  higher Commodity Margin, as previously discussed
            +   lower interest expense, primarily resulting from a decrease in
                our annual effective interest rate and
                lower income tax expense related to the application of
            +   intraperiod tax allocation and a decrease in various state and
                federal jurisdiction income taxes, partially offset by
            –   modestly higher plant operating expenses, as previously
                discussed.

___________

^7 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 years ended December 31, 2011 and 2012.

Table 1: Net Income, As Adjusted
                     
                       Three Months Ended December   Year Ended December 31,
                       31,
                       2012            2011           2012         2011
                       (in millions)
Net income (loss)
attributable to        $   100          $  (13  )      $  199        $  (190 )
Calpine
Debt extinguishment    18               —              30            94
costs^(1)
(Gain) on sale of      (222      )      —              (222    )     —
assets, net^(1)
Unrealized MtM
(gain) loss on         31               (72     )      (72     )     (30     )
derivatives^(1) (2)
Other items ^ (1)      (13       )      42            143          113     
(3)
Net Income (loss),     $   (86   )      $  (43  )      $  78        $  (13  )
As 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 months and year ended December 31, 2012, respectively, and $42
million and $189 million for the three months and year ended December 31,
2011, respectively. Other items for the three months and year ended December
31, 2012, include a $13 million tax refund associated with our 2004 amended
federal income tax return. Other items for the year ended December 31, 2011,
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 December     Year Ended December 31,
            31,
            2012      2011     Variance     2012       2011       Variance
West        $  246     $ 263     $  (17 )     $ 994       $ 1,061     $  (67 )
Texas       98         112       (14    )     570         469         101
North       138        126       12           729         704         25
Southeast   33        52       (19    )     245        240        5      
Total       $  515    $ 553    $  (38 )     $ 2,538    $ 2,474    $  64  

West Region

Fourth Quarter: Commodity Margin in our West segment decreased by $17 million
in the fourth quarter of 2012 compared to the prior year period. Primary
drivers were:

      –  lower contribution from hedges and
            –   lower revenue due to the expiration of contracts, partially
                offset by
            +   an increase in Commodity Margin on our open position driven by
                higher market spark spreads on higher generation volumes.

Full Year: Commodity Margin in our West segment decreased by $67 million in
2012 compared to 2011. Primary drivers were:

      –  lower contribution from hedges
            –   lower market power prices associated with our Geysers assets
                and
            –   lower revenue due to the expiration of contracts, partially
                offset by
            +   an increase in Commodity Margin on our open position driven by
                higher market spark spreads and
                increased generation driven primarily by improved market
            +   conditions, less hydroelectric generation and a nuclear power
                outage in California during 2012.

Texas Region

Fourth Quarter: Commodity Margin in our Texas segment decreased by $14 million
in the fourth quarter of 2012 compared to the prior year period. Primary
drivers were:

      –  lower contribution from hedges and
            –   weak market pricing conditions due to mild weather.

Full Year: Commodity Margin in our Texas segment increased by $101 million in
2012 compared to 2011. 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 lower natural gas prices in the
                first half of 2012 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

Fourth Quarter: Commodity Margin in our North segment increased by $12 million
in the fourth quarter of 2012 compared to the prior year period. Primary
drivers were:

      +  higher regulatory capacity revenues and
            +   to a far lesser extent, increased generation.

Full Year: Commodity Margin in our North segment increased by $25 million in
2012 compared to 2011. Primary drivers were:

      +  York Energy Center achieving commercial operation in March
                2011
            +   higher contribution from hedges and
            +   increased generation driven by lower natural gas prices,
                partially offset by
            –   lower regulatory capacity revenues and
            –   lower nodal pricing in PJM during 2012.

Southeast Region

Fourth Quarter: Commodity Margin in our Southeast segment decreased by $19
million in the fourth quarter of 2012 compared to the prior year period. The
primary drivers were:

      –  expiration of a PPA during the third quarter of 2012, which
                has since been recontracted, and
            –   lower contribution from hedges.

Full Year: Commodity Margin in our Southeast segment increased by $5 million
in 2012 compared to 2011. Primary drivers were:

      +  higher contribution from hedges and
            +   higher generation resulting from lower natural gas prices,
                largely offset by
            –   the negative impact from the expiration of a PPA during the
                third quarter of 2012, which has since been recontracted.
                

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity

                                          
                                            December 31,  December 31,
                                            2012           2011
                                            (in millions)
Cash and cash equivalents, corporate^(1)    $  1,153       $    946
Cash and cash equivalents, non-corporate    131           306
Total cash and cash equivalents             1,284          1,252
Restricted cash                             253            194
Corporate Revolving Facility availability   757            560
Letter of credit availability^(2)           —             7
Total current liquidity availability        $  2,294      $    2,013

__________

^(1) Includes $11 million and $34 million of margin deposits held by us posted
by our counterparties at December 31,2012, and 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. As a result of the
completion of the sale of Riverside Energy Center, LLC, a wholly owned
subsidiary of CDHI, on December 31, 2012, we are required to cash
collateralize letters of credit issued in excess of $225 million until
replacement collateral is contributed to the CDHI collateral package, which we
are in the process of arranging. At December31, 2012, we had $28 million of
cash collateral posted in support of outstanding letters of credit under our
CDHI letter of credit facility. We do not believe that this change will have a
material impact on our liquidity.

Liquidity increased to approximately $2.3 billion as of December 31, 2012, up
from approximately $2.0 billion at December 31, 2011.

Cash flows from operating activities in 2012 resulted in net inflows of $653
million compared to $775 million in 2011. The decrease in cash provided by
operating activities was primarily due to an increase in cash paid for
interest due to timing of interest payments on our debt and an increase in
working capital driven by higher margin requirements.

Cash flows used in investing activities decreased to $470 million in 2012
compared to $836 million in 2011, driven largely by higher proceeds from the
sales of our Broad River and Riverside Energy Centers, partially offset by the
purchase of our Bosque Energy Center.

Cash flows used in financing activities were $151 million in 2012, driven
largely by $463 million in share repurchases in 2012, partially offset by net
proceeds from borrowing on our project debt facilities and our 2012
refinancing activities, as further described below.

Consistent with our efforts to optimize and simplify our capital structure,
during 2012, we entered into an $835 million first lien term loan, the
proceeds of which were used 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 currently bears
interest at LIBOR plus 3.25% per annum (subject to a LIBOR floor of 1.25%).
This transaction is expected to produce annual interest savings of
approximately $25 million.

Subsequently, in February 2013, we repriced approximately $2.5 billion of our
first lien term loans, including the aforementioned $835 million term loan.
This repricing lowers the term loans’ LIBOR floor by 0.25% to 1.0% and lowers
their applicable margin by 0.25% to 3.0%. We estimate that this repricing will
produce additional annual interest savings of approximately $12 million. We
expect this transaction to close in the second half of February.

Adjusted Free Cash Flow was $564 million in 2012, compared to $489 million in
2011. Adjusted Free Cash Flow increased during the period primarily due to
lower interest expense associated with our refinancing efforts, as well as a
$23 million increase in Adjusted EBITDA, as previously discussed. Lower major
maintenance expenditures related to our plant outage schedule further
contributed to the improvement in Adjusted Free Cash Flow.

CAPITAL ALLOCATION

Portfolio Optimization

During the fourth quarter of 2012, we completed the following transactions
that allowed us to strategically redeploy capital:

  *the purchase of our Bosque Energy Center, an 800 MW modern, natural
    gas-fired combined-cycle power plant in Central Texas, for approximately
    $432 million, or $540/kW
  *the sale of our Broad River Energy Center, an 847 MW natural gas-fired
    peaking power plant in South Carolina, for approximately $427 million^5,
    or $504/kW and
  *the sale of our Riverside Energy Center, a 603 MW combined-cycle power
    plant in Wisconsin, for approximately $402 million, or $667/kW.

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. In early 2013, we completed this $600
million share repurchase program, having repurchased a total of approximately
35.6 million shares of our outstanding common stock at an average price paid
of $16.87 per share. In February 2013, our Board of Directors authorized the
repurchase of up to an additional $400 million in shares of our common stock,
bringing the cumulative authorization total to $1.0 billion.

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. Construction is ongoing and COD is
expected in the summer of 2013. Upon completion, the Russell City Energy
Center is contracted to deliver its full output to PG&E under a 10-year PPA.

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.
Construction is ongoing and COD is expected in the summer of 2013.

Texas:

Channel and Deer Park Expansions: In September and November 2011, we filed air
permit applications with the Texas Commission on Environmental Quality
(“TCEQ”) and the EPA to expand the baseload capacity of the Deer Park and
Channel Energy Centers by approximately 260 MW^8 each. We received air permit
approvals from the TCEQ for our Deer Park and Channel expansion projects in
September and October 2012, respectively, and from the EPA in November 2012.
Construction on these expansion projects commenced in the fourth quarter of
2012. We expect COD during the summer of 2014 for these expansions and 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), we have executed the
Interconnection Services Agreement and the Interconnection Construction
Services Agreement with PJM. For the second phase (309 MW), we have completed
a feasibility study and are currently conducting a system impact study.
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 received the air permit and executed a
preliminary notice to proceed with the engineering, procurement and
construction agreement during the first quarter of 2013. We expect COD for the
first phase by the summer of 2015 and are currently evaluating funding sources
including, but not limited to, nonrecourse financing, corporate financing or
internally generated funds.

All Segments:

Turbine Modernization: We continue to move forward with our turbine
modernization program. Through December 31, 2012, we have completed the
upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have
committed to upgrade approximately three additional turbines.

___________

^8 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

2012 Power Operations Achievements:

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

  *Availability Performance:
    — Delivered lowest annual fleetwide forced outage factor on record: 1.6%
    — Achieved an impressive full year fleetwide starting reliability: 98.3%

  *Cost Performance:
    — Held normal, recurring plant operating expense^4 essentially flat,
    despite a 23% increase in generation^3, after accounting for prior period
    insurance reimbursements in 2011

  *Geothermal Generation:
    — Provided more than 6 million MWh of renewable baseload generation with a
    remarkable 0.26% forced outage factor during 2012

  *Natural Gas-fired Generation:
    — Increased combined-cycle capacity factor in 2012 to 52.3% compared to
    42.6% in 2011
    — Deer Park Energy Center: Produced 6.2 million MWh in 2012, the most by
    any individual plant in fleet history

2012 Commercial Operations Achievements:

  *Customer-oriented Growth:
    — Entered into a 10-year PPA with Tennessee Valley Authority to provide
    the full output of power from our Decatur Energy Center, a natural
    gas-fired, combined-cycle power plant that can generate up to 795 MW,
    commencing in January 2013
    — 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
    — Entered into a five-year PPA with Southwestern Public Service Company to
    provide an additional 200 MW of capacity and energy from our Oneta Energy
    Center beginning June 2014
    — Executed a new five-year resource adequacy contract with PG&E for
    approximately 280 MW of combined heat and power capacity from our Los
    Medanos Energy Center commencing in summer 2013
    — Entered into a new seven-year resource adequacy contract with Southern
    California Edison Company ("SCE") for approximately 280 MW of combined
    heat and power capacity from our Los Medanos Energy Center commencing in
    January 2014
    — Executed a new five-year resource adequacy contract with SCE for
    approximately 120 MW of combined heat and power capacity from our Gilroy
    Cogeneration Plant commencing in January 2014
    — Amended an existing PPA with Dow Chemical Company for an incremental
    energy sale of up to approximately 158,000 MWh per year of energy from our
    Los Medanos Energy Center that runs through February 2025
    — Signed 20-year PPA with Western Farmers Electric Cooperative to provide
    160 MW of power and capacity from our Oneta Energy Center beginning June
    2014. The capacity under contract will increase in increments, up to a
    maximum of 280 MW in years 2019 through 2035.

FINANCIAL OUTLOOK

(in millions, except per share amounts)

                                                              Full Year 2013
                                                                
Adjusted EBITDA                                               $ 1,760 - 1,960
Less:
Operating lease payments                                        35
Major maintenance expense and maintenance capital               370
expenditures^(1)
Cash interest, net^(2)                                          755
Cash taxes                                                      15
Other                                                          10       
Adjusted Free Cash Flow                                       $ 575 - 775
Per Share Midpoint (diluted)                                  $ 1.50
                                                                
Growth capital expenditures (net of debt funding)             $ (250     )
Debt amortization                                             $ (140     )

________

^(1) 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.

^(2) Includes commitment, letter of credit and other bank fees from both
consolidated and unconsolidated investments, net of capitalized interest and
interest income.

As detailed above, today we are reaffirming our 2013 guidance. We project
Adjusted EBITDA of $1,760 million to $1,960 million and Adjusted Free Cash
Flow of $575 million to $775 million. Our guidance reflects all previously
announced acquisition and divestiture activity, including the sales of Broad
River and Riverside Energy Centers, and the purchase of Bosque Energy Center,
each of which closed during the fourth quarter of 2012. We also expect to
invest $250 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. (Though our
construction projects at Russell City and Los Esteros continue into 2013, we
met our equity contribution requirements on these projects in 2011, such that
all costs incurred in 2013 will be funded from the project debt we have
secured for these projects.)

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results
for the fourth quarter and full year 2012 on Wednesday, February 13,2013, at
10 a.m. ET / 9 a.m. CT. A listen-only webcast of the call may be accessed
through our website at www.calpine.com, or by dialing (800) 447-0521 in the
U.S. or (847) 413-3238 outside the U.S. The confirmation code is 34044836. 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 34044836. Presentation materials to
accompany the conference call will be available on our website on February 13,
2013.

INVESTOR DAY

Calpine will be hosting an investor and analyst meeting on Wednesday, April
10, 2013, from 1 p.m. to 5 p.m. CT in Houston, Texas. Members of the Calpine
management team will present their views on the company and its markets and
provide updates on financial, regulatory and strategic initiatives. More
information about the event, including online registration and a link to the
live webcast, can be found on the Investor Relations section of our website at
www.calpine.com.

ABOUT CALPINE

Calpine Corporation generates more electricity than any other independent
power producer in America, with a fleet of 92 power plants in operation or
under construction, representing more than 27,000 megawatts of generation
capacity in operation. Serving customers in 20 states and Canada, we
specialize in developing, constructing, owning and operating natural gas-fired
and renewable geothermal power plants that use advanced technologies to
generate power in a low-carbon and environmentally responsible manner. Our
clean, efficient, modern and flexible fleet is uniquely positioned to benefit
from the secular trends affecting our industry, including the abundant and
affordable supply of clean natural gas, stricter environmental regulation,
aging power generation infrastructure and the increasing need for dispatchable
power plants to successfully integrate intermittent renewables into the grid.
We focus on wholesale competitive power markets and advocate for market-driven
solutions that result in nondiscriminatory forward price signals for
investors. Please visit www.calpine.com to learn more about why Calpine is a
generation ahead - today.

Calpine’s Annual Report on Form 10-K for the year ended December 31, 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, regulation 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;
  *Our ability to manage our liquidity needs and to comply with covenants
    under our First Lien Notes, Corporate Revolving Facility, First Lien Term
    Loans, CCFC Notes and other existing financing obligations;
  *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;
  *The unknown future impact on our business from the Dodd-Frank Act and the
    rules to be promulgated thereunder;
  *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 2012 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 STATEMENTS OF OPERATIONS

(in millions, except share and per share amounts)

                    (Unaudited)                                  
                     Three Months Ended December 31,   Year Ended December 31,
                     2012              2011           2012          2011
Operating
revenues:
Commodity revenue    $   1,339          $  1,477       $  5,417      $ 6,753
Unrealized
mark-to-market       24                 (21       )    48            35
gain (loss)
Other revenue        4                 3             13           12      
Operating revenues   1,367             1,459         5,478        6,800   
Operating
expenses:
Fuel and purchased
energy expense:
Commodity expense    821                924            2,894         4,299
Unrealized
mark-to-market       57                (43       )    130          60      
(gain) loss
Fuel and purchased   878               881           3,024        4,359   
energy expense
Plant operating      223                193            922           904
expense
Depreciation and
amortization         144                145            562           550
expense
Sales, general and
other                36                 32             140           131
administrative
expense
Other operating      20                21            78           77      
expenses
Total operating      1,301             1,272         4,726        6,021   
expenses
(Gain) on sale of    (222        )      —              (222      )   —
assets, net
(Income) from
unconsolidated       (7          )      (9        )    (28       )   (21     )
investments in
power plants
Income from          295                196            1,002         800
operations
Interest expense     184                185            736           760
(Gain) loss on
interest rate        —                  (4        )    14            145
derivatives
Interest (income)    (4          )      (2        )    (11       )   (9      )
Debt
extinguishment       18                 —              30            94
costs
Other (income)       1                 7             15           21      
expense, net
Income (loss)
before income        96                 10             218           (211    )
taxes
Income tax expense   (4          )      23            19           (22     )
(benefit)
Net income (loss)    100                (13       )    199           (189    )
Net income
attributable to      —                 —             —            (1      )
the noncontrolling
interest
Net income (loss)
attributable to      $   100           $  (13    )    $  199       $ (190  )
Calpine
                                                                     
Basic earnings
(loss) per common
share attributable
to Calpine:
Weighted average
shares of common     459,304           482,468       467,752      485,381 
stock outstanding
(in thousands)
Net income (loss)
per common share     $   0.22          $  (0.03  )    $  0.43      $ (0.39 )
attributable to
Calpine — basic
                                                                     
Diluted earnings
(loss) per common
share attributable
to Calpine:
Weighted average
shares of common     463,291           482,468       471,343      485,381 
stock outstanding
(in thousands)
Net income (loss)
per common share     $   0.22          $  (0.03  )    $  0.42      $ (0.39 )
attributable to
Calpine — diluted
                                                                             


CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS

December 31, 2012 and 2011

(in millions, except share and per share amounts)

                                                      2012        2011
ASSETS
Current assets:
Cash and cash equivalents                              $ 1,284      $ 1,252
Accounts receivable, net of allowance of $6 and $13    437          598
Margin deposits and other prepaid expense              244          193
Restricted cash, current                               193          139
Derivative assets, current                             339          1,051
Inventory and other current assets                     335         329      
Total current assets                                   2,832        3,562
Property, plant and equipment, net                     13,005       13,019
Restricted cash, net of current portion                60           55
Investments                                            81           80
Long-term derivative assets                            98           113
Other assets                                           473         542      
Total assets                                           $ 16,549    $ 17,371 
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable                                       $ 382        $ 435
Accrued interest payable                               180          200
Debt, current portion                                  115          104
Derivative liabilities, current                        357          1,144
Income taxes payable                                   11           3
Other current liabilities                              273         276      
Total current liabilities                              1,318        2,162
Debt, net of current portion                           10,635       10,321
Long-term derivative liabilities                       293          279
Other long-term liabilities                            247         245      
Total liabilities                                      12,493       13,007
                                                                    
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value per share;
authorized 100,000,000 shares, none issued and         —            —
outstanding at December 31, 2012 and 2011
Common stock, $0.001 par value per share; authorized
1,400,000,000 shares, 492,495,100 shares issued and
457,048,970 shares outstanding at December 31, 2012,   1            1
and 490,468,815 shares issued and 481,743,738 shares
outstanding at December 31, 2011
Treasury stock, at cost, 35,446,130 and 8,725,077      (594     )   (125     )
shares, respectively
Additional paid-in capital                             12,335       12,305
Accumulated deficit                                    (7,500   )   (7,699   )
Accumulated other comprehensive loss                   (248     )   (178     )
Total Calpine stockholders’ equity                     3,994        4,304
Noncontrolling interest                                62          60       
Total stockholders’ equity                             4,056       4,364    
Total liabilities and stockholders’ equity             $ 16,549    $ 17,371 
                                                                             


CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2012 and 2011

(in millions)

                                                        2012       2011
Cash flows from operating activities:
Net income (loss)                                        $ 199       $ (189  )
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization expense^(1)                605         587
Debt extinguishment costs                                —           82
Deferred income taxes                                    1           (21     )
(Gain) loss on sale of power plants and other, net       (212    )   13
Unrealized mark-to-market (gain) loss                    (72     )   (30     )
(Income) from unconsolidated investments in power        (28     )   (21     )
plants
Return on unconsolidated investments in power plants     24          6
Stock-based compensation expense                         25          24
Other                                                    1           6
Change in operating assets and liabilities, net of
effects of acquisitions:
Accounts receivable                                      159         74
Derivative instruments, net                              (52     )   15
Other assets                                             (57     )   1
Accounts payable and accrued expenses                    (86     )   28
Settlement of non-hedging interest rate swaps            156         189
Other liabilities                                        (10     )   11      
Net cash provided by operating activities                653        775     
Cash flows from investing activities:
Purchases of property, plant and equipment               (637    )   (683    )
Proceeds from sale of power plants, interests and        825         13
other
Purchase of Bosque Energy Center, net of cash            (432    )   —
Return of investment from unconsolidated investments     5           —
Settlement of non-hedging interest rate swaps            (156    )   (189    )
(Increase) decrease in restricted cash                   (59     )   54
Purchases of deferred transmission credits               (12     )   (31     )
Other                                                    (4      )   —       
Net cash used in investing activities                     (470  )    (836  )
Cash flows from financing activities:
Borrowings under First Lien Term Loans                   835         1,657
Repayments of First Lien Term Loans                      (19     )   —
Repayments on NDH Project Debt                           —           (1,283  )
Issuance of First Lien Notes                             —           1,200
Repayments of First Lien Notes                           (590    )   —
Repayments on First Lien Credit Facility                 —           (1,195  )
Borrowings from project financing, notes payable and     389         327
other
Repayments of project financing, notes payable and       (289    )   (550    )
other
Capital contributions from noncontrolling interest       —           33
holder
Financing costs                                          (20     )   (81     )
Stock repurchases                                        (463    )   (119    )
Other                                                    6          (3      )
Net cash used in financing activities                    (151    )   (14     )
Net increase (decrease) in cash and cash equivalents     32          (75     )
Cash and cash equivalents, beginning of period           1,252      1,327   
Cash and cash equivalents, end of period                 $ 1,284    $ 1,252 
                                                                     
Cash paid during the period for:
Interest, net of amounts capitalized                     $ 719       $ 656
Income taxes                                             $ 16        $ 18
                                                                     
Supplemental disclosure of non-cash investing and
financing activities:
Change in capital expenditures included in accounts      $ 19        $ (24   )
payable
Other non-cash additions to property, plant and          $ 13        $ —
equipment

__________

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

REGULATION G RECONCILIATIONS

Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted
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 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 and other adjustments, including non-recurring items.
Adjusted 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 December 31, 2012 and 2011 (in millions):

                Three Months Ended December 31, 2012
                                                      Consolidation 
                                                          And
                 West      Texas    North     Southeast   Elimination     Total
Commodity        $ 246     $ 98     $ 138     $  33       $    —          $ 515
Margin^(1)(2)
Add:
Unrealized
mark-to-market   (13   )   21       3         (28     )   (9        )     (26   )
commodity
activity, net
and other^(3)
Less:
Plant
operating        87        58       52        33          (7        )     223
expense
Depreciation
and              52        38       34        19          1               144
amortization
expense
Sales, general
and other        13        11       6         6           —               36
administrative
expense
Other
operating        12        1        8         3           (4        )     20
expenses
(Gain) on sale   —         —        (7    )   (215    )   —               (222  )
of assets, net
(Income) from
unconsolidated   —        —       (7    )   —          —              (7    )
investments in
power plants
Income from      $ 69     $ 11    $ 55     $  159     $    1         $ 295 
operations
                                                                                

                Three Months Ended December 31, 2011
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 263     $ 112     $ 126     $  52       $    —          $ 553
Margin^(1)(2)
Add:
Unrealized
mark-to-market   77        (48   )   (1    )   5           (9        )     24
commodity
activity, net
and other^(3)
Less:
Plant
operating        83        42        41        34          (7        )     193
expense
Depreciation
and              52        36        36        23          (2        )     145
amortization
expense
Sales, general
and other        14        10        5         4           (1        )     32
administrative
expense
Other
operating        11        1         7         2           (1        )     20
expenses
(Income) from
unconsolidated   —        —        (9    )   —          —              (9    )
investments in
power plants
Income (loss)
from             $ 180    $ (25 )   $ 45     $  (6  )    $    2         $ 196 
operations
                                                                                 

The following table reconciles our Commodity Margin to its U.S. GAAP results
for the years ended December 31, 2012 and 2011 (in millions):

                Year Ended December 31, 2012
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 994     $ 570     $ 729     $  245      $    —          $ 2,538
Margin^(1)(2)
Add:
Unrealized
mark-to-market   (93   )   87        (14   )   (33     )   (31       )     (84     )
commodity
activity, net
and other^(4)
Less:
Plant
operating        368       247       206       131         (30       )     922
expense
Depreciation
and              203       142       134       85          (2        )     562
amortization
expense
Sales, general
and other        36        47        28        29          —               140
administrative
expense
Other
operating        42        5         29        5           (3        )     78
expenses
(Gain) on sale   —         —         (7    )   (215    )   —               (222    )
of assets, net
(Income) from
unconsolidated   —        —        (28   )   —          —              (28     )
investments in
power plants
Income from      $ 252    $ 216    $ 353    $  177     $    4         $ 1,002 
operations
                                                                                   

                Year Ended December 31, 2011
                                                         Consolidation 
                                                             And
                 West        Texas     North     Southeast   Elimination     Total
Commodity        $ 1,061     $ 469     $ 704     $  240      $    —          $ 2,474
Margin^(1)(2)
Add:
Unrealized
mark-to-market   113         (102  )   (13   )   1           (32       )     (33     )
commodity
activity, net
and other^(4)
Less:
Plant
operating        380         235       177       141         (29       )     904
expense
Depreciation
and              192         135       138       90          (5        )     550
amortization
expense
Sales, general
and other        43          43        24        22          (1        )     131
administrative
expense
Other
operating        41          3         30        5           (2        )     77
expenses
(Income) from
unconsolidated   —          —        (21   )   —          —              (21     )
investments in
power plants
Income (loss)
from             $ 518      $ (49 )   $ 343    $  (17  )   $    5         $ 800   
operations

__________

^(1) Our North segment includes Commodity Margin related to Riverside Energy
Center, LLC, of $9 million and $8 million for the three months ended December
31, 2012 and 2011, respectively, and $73 million and $70 million for the years
ended December 31, 2012 and 2011, respectively.

^(2) Our Southeast segment includes Commodity Margin related to Broad River of
$8 million and $9 million for the three months ended December 31, 2012 and
2011, respectively, and $52 million and $51 million for the years ended
December 31, 2012 and 2011, respectively.

^(3) Includes $(6) million and $(3) million of lease levelization for the
three months ended December 31, 2012 and 2011, respectively, and $3 million of
amortization expense for each of the three months ended December 31, 2012 and
2011.

^(4) Includes $1 million and $12 million of lease levelization and $14 million
and $8 million of amortization expense for the years ended December 31, 2012
and 2011, respectively.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted
Free Cash Flow to our net income (loss) attributable to Calpine for the three
months and years ended December 31, 2012 and 2011, as reported under U.S.
GAAP.

                        Three Months Ended December  Year Ended December 31,
                         31,
                         2012           2011          2012         2011
                         (in millions)
Net income (loss)
attributable to          $   100         $  (13   )    $  199        $ (190  )
Calpine
Net income
attributable to the      —               —             —             1
noncontrolling
interest
Income tax expense       (4        )     23            19            (22     )
(benefit)
Debt extinguishment
costs and other          19              7             45            115
(income) expense, net
(Gain) loss on
interest rate            —               (4       )    14            145
derivatives
Interest expense, net    180            183          725          751     
of interest income
Income from operations   $   295         $  196        $  1,002      $ 800
Add:
Adjustments to
reconcile income from
operations to Adjusted
EBITDA:
Depreciation and
amortization expense,    145             146           564           552
excluding deferred
financing costs^(1)
Major maintenance        42              36            200           205
expense
Operating lease          8               9             34            35
expense
Unrealized (gain) loss
on commodity
derivative               33              (23      )    82            25
mark-to-market
activity
(Gain) on sale of        (222      )     —             (222      )   —
assets, net
Adjustments to reflect
Adjusted EBITDA from     8               6             31            36
unconsolidated
investments^(2)(3)
Stock-based              6               6             25            24
compensation expense
(Gain) loss on           3               (1       )    12            16
dispositions of assets
Acquired contract        3               3             14            8
amortization
Other                    (6        )     1            7            25      
Total Adjusted EBITDA    $   315        $  379       $  1,749     $ 1,726 
Less:
Operating lease          8               9             34            35
payments
Major maintenance
expense and capital      77              62            375           397
expenditures^(4)
Cash interest, net^(5)   186             194           757           781
Cash taxes               1               2             11            13
Other                    2              4            8            11      
Adjusted Free Cash       $   41         $  108       $  564       $ 489   
Flow^(6)
                                                                     
Weighted average
shares of common stock   463,291        482,468      471,343      485,381 
outstanding (diluted,
in thousands)
Adjusted Free Cash
Flow
Per Share (diluted)      $   0.09       $  0.22      $  1.20      $ 1.01  

_________

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

^(2) Included on our Consolidated 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 months ended December 31, 2012 and 2011, respectively, and nil and
$1 million for the years ended December 31, 2012 and 2011, respectively.

^(4) Includes $42 million and $192 million in major maintenance expense for
the three months and year ended December 31, 2012, respectively, and $35
million and $183 million in maintenance capital expenditures for the three
months and year ended December 31, 2012, respectively. Includes $27 million
and $201 million in major maintenance expense for the three months and year
end December 31, 2011, respectively, and $35 million and $196 million in
maintenance capital expenditures for the three months and year ended December
31, 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 a decrease in working capital of $91 million and $107 million
for the three months and year ended December 31, 2012, respectively, and a
decrease in working capital of $8 million and increase in working capital of
$13 million for the three months and year ended December 31, 2011,
respectively. Adjusted Free Cash Flow, as reported, excludes changes in
working capital, such that it is calculated on the same basis as our guidance.

In the following table, we have reconciled our Adjusted EBITDA to our
Commodity Margin, both of which are non-GAAP measures, for the three months
and years ended December 31, 2012 and 2011. Reconciliations for both Adjusted
EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided
above.

                        Three Months Ended December  Year Ended December 31,
                         31,
                         2012            2011         2012         2011
                         (in millions)
Commodity Margin         $   515          $  553       $  2,538      $ 2,474
Other revenue            3                2            12            13
Plant operating          (174      )      (154    )    (692      )   (666    )
expense^(1)
Sales, general and
administrative           (33       )      (28     )    (127      )   (113    )
expense^(2)
Other operating          (11       )      (10     )    (41       )   (40     )
expenses^(3)
Adjusted EBITDA from
unconsolidated           14               15           58            57
investments in power
plants^(4)
Other                    1               1           1            1       
Adjusted EBITDA          $   315         $  379      $  1,749     $ 1,726 

_________

^(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 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 Free Cash Flow Reconciliation for Guidance

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

_________

^(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 $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.

^(4) Includes commitment, letter of credit and other bank fees from both
consolidated and unconsolidated investments, net of capitalized interest and
interest income.

OPERATING PERFORMANCE METRICS

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

                        Three Months Ended December  Year Ended December 31,
                         31,
                         2012            2011         2012          2011
Total MWh generated      25,189           24,954       112,216        90,875
(in thousands)^(1)
West                     9,179            7,634        33,390         23,823
Texas                    7,689            8,533        35,946         32,552
Southeast                3,404            4,494        21,148         18,983
North                    4,917            4,293        21,732         15,517
                                                                      
Average availability     90.9     %       91.4    %    91.3     %     90.1   %
West                     93.9     %       95.8    %    91.9     %     88.2   %
Texas                    93.1     %       89.4    %    91.1     %     89.0   %
Southeast                90.6     %       91.5    %    93.4     %     91.9   %
North                    86.0     %       89.4    %    89.3     %     91.6   %
                                                                      
Average capacity
factor, excluding        48.0     %       48.7    %    53.7     %     44.3   %
peakers^(1)
West                     66.2     %       55.3    %    60.6     %     43.6   %
Texas                    46.6     %       55.2    %    57.4     %     53.2   %
Southeast                29.5     %       39.2    %    44.6     %     40.6   %
North                    46.2     %       40.3    %    48.8     %     35.9   %
                                                                      
Steam adjusted heat      7,378            7,358        7,361          7,412
rate (Btu/kWh)
West                     7,306            7,287        7,278          7,418
Texas                    7,139            7,203        7,147          7,243
Southeast                7,345            7,279        7,309          7,312
North                    7,900            7,867        7,914          7,919

________

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

Contact:

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