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Calpine Reports Second Quarter 2013 Results, Reaffirms 2013 Adjusted Free Cash Flow Per Share Guidance, Tightens 2013 Adjusted

  Calpine Reports Second Quarter 2013 Results, Reaffirms 2013 Adjusted Free
  Cash Flow Per Share Guidance, Tightens 2013 Adjusted EBITDA and Free Cash
  Flow Guidance Ranges

Business Wire

HOUSTON -- July 25, 2013

Calpine Corporation (NYSE: CPN):

Summary of Second Quarter 2013 Financial Results (in millions, except per
share amounts):

            Three Months Ended June 30,       Six Months Ended June 30,
             2013       2012       % Change   2013       2012       % Change
                                                                        
Operating    $ 1,572     $ 879       78.8  %    $ 2,813     $ 2,115     33.0   %
Revenues
Commodity    $ 533       $ 609       (12.5 )%   $ 994       $ 1,126     (11.7  )%
Margin
Adjusted     $ 343       $ 403       (14.9 )%   $ 629       $ 728       (13.6  )%
EBITDA
Adjusted
Free Cash    $ 38        $ 87        (56.3 )%   $ (5    )   $ 60        (108.3 )%
Flow
Per Share    $ 0.08      $ 0.19      (57.9 )%   $ (0.01 )   $ 0.13      (107.7 )%
(diluted)
Net Loss^1   $ (70   )   $ (329  )              $ (195  )   $ (338  )
Per Share    $ (0.16 )   $ (0.69 )              $ (0.43 )   $ (0.71 )
(diluted)
Net Income
(Loss), As   $ (33   )   $ 14                   $ (103  )   $ (51   )
Adjusted^2
                                                                        

2013 Full Year Guidance (in millions, except per share amounts):

                             Prior Guidance (as of May 2,    Current Guidance
                             2013)
                                                              
Adjusted EBITDA              $1,800 - 1,960                   $1,800 - 1,875
Adjusted Free Cash Flow      $615 - 775                       $640 - 715
Per Share Estimate (diluted) $1.50                            $1.50
                                                              

Recent Achievements:

  *Operations:
    — Generated approximately 23 million MWh^3 of electricity in the second
    quarter of 2013
    — Achieved record-low second quarter fleetwide forced outage factor: 1.6%
    — Delivered exceptional second quarter fleetwide starting reliability: 99%

  *Commercial:
    — Entered into three-year PPA with South Carolina Electric and Gas to
    provide 200 MW of power from our Columbia Energy Center commencing in
    January 2014
    — Entered into two new resource adequacy contracts with Pacific Gas and
    Electric Company for our Delta and Sutter Energy Centers for the full
    capacity of each plant, commencing in January and June 2014, respectively
    — Entered into two new contracts with Marin Energy Authority to provide up
    to 10 MW of renewable power from our Geysers assets

  *Capital Management:
    — Completed $400 million share repurchase authorization, bringing the
    cumulative total of shares repurchased to $1 billion, or approximately 11%
    of our outstanding shares^4
    — Refinanced our CCFC notes and Corporate Revolver, providing material
    interest savings and extending maturities

Calpine Corporation (NYSE: CPN) today reported second quarter 2013 Adjusted
EBITDA of $343 million, compared to $403 million in the prior year period, and
Adjusted Free Cash Flow of $38 million, or $0.08 per diluted share, compared
to $87 million, or $0.19 per diluted share, in the prior year period. Net
Loss^1 for the second quarter of 2013 was $70 million, or $0.16 per diluted
share, compared to $329 million, or $0.69 per diluted share, in the prior year
period. Net Loss, As Adjusted^2, for the second quarter of 2013 was $33
million compared to Net Income, As Adjusted^2, of $14 million in the prior
year period. The declines in Adjusted EBITDA, Adjusted Free Cash Flow and Net
Income, As Adjusted^2, in the second quarter of 2013 compared to the prior
year period were driven primarily by lower Commodity Margin, largely as a
result of changes in our portfolio, milder weather and lower generation due to
the reversal in 2013 of the coal-to-gas switching that we benefited from
during the first half of 2012.

Year-to-date 2013 Adjusted EBITDA was $629 million, compared to $728 million
in the prior year period, and Adjusted Free Cash Flow was $(5) million, or
$(0.01) per diluted share, compared to $60 million, or $0.13 per diluted
share, in the prior year period. Net Loss^1 for the first half of 2013 was
$195 million, or $0.43 per diluted share, compared to $338 million, or $0.71
per diluted share, in the prior year period. Net Loss, As Adjusted^2, for the
first half of 2013 was $103 million compared to $51 million in the prior year
period. The declines in year-to-date 2013 Adjusted EBITDA, Adjusted Free Cash
Flow and Net Income, As Adjusted^2, compared to the prior year period were
primarily due to the same factors that drove comparative performance for the
second quarter, as previously discussed.

“We remain steadfastly focused on positioning Calpine to take advantage of the
secular shift in the U.S. power generation industry to clean, efficient and
dispatchable combined-cycle gas turbines,” said Jack Fusco, Calpine’s Chief
Executive Officer.

“Today, we are reaffirming our Adjusted Free Cash Flow Per Share guidance of
$1.50 for 2013, despite challenging market conditions during the first half of
this year. Our second quarter and year-to-date results reflect milder weather
this year, as well as the sale of two contracted power plants late last year.
We expect these headwinds to be offset during the balance of the year by
higher regulatory capacity revenues in PJM, the commencement of operations at
our two new contracted plants in California and the acquisition of Bosque
Energy Center in Texas. Our hedge position in the second half of the year also
allows us to benefit from any improved conditions in our markets.

“Meanwhile, we continue to proactively enhance shareholder value through
commercial origination and capital allocation. We recently signed new
multiyear capacity contracts for 1,645 MW in California and the Southeast as
we continue to identify solutions for our customers. In addition, we expect to
bring approximately 900 MW of contracted capacity on-line in California during
the third quarter. Construction is also advancing on our two expansion
projects in Texas with in-service expected next summer, and we recently broke
ground on our new 309 MW plant in Delaware. Finally, we recently completed our
$1 billion of share repurchase authorizations, demonstrating our commitment to
returning capital to our shareholders.”

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA for the second quarter of 2013 was $343 million, compared to
$403 million in the prior year period. The year-over-year decrease in Adjusted
EBITDA was primarily due to a $76 million decrease in Commodity Margin,
partially offset by a $15 million decrease in plant operating expense^5. The
decrease in Commodity Margin was primarily due to:

                the sale of Broad River and Riverside Energy Centers,
      –  partially offset by the acquisition of Bosque Energy Center in
                the fourth quarter of 2012
                
                weaker market conditions due to milder weather, an increase in
            –   wind generation in Texas and higher natural gas prices
                primarily in our Texas, North and Southeast segments in the
                second quarter of 2013 compared to the prior year period and
                
            –   lower contribution from hedges, partially offset by
                
            +   higher regulatory capacity revenue in the North and
                
            +   higher revenue from a tolling contract in our West segment
                that became effective in January 2013.

The offsetting decrease in plant operating expense^5 was primarily due to
lower equipment failure costs and other miscellaneous expenses.

Net Loss^1 was $70 million for the second quarter of 2013, compared to a Net
Loss^1 of $329 million in the prior year period. As detailed in Table 1, Net
Loss, As Adjusted^2, was $33 million in the second quarter of 2013 compared to
Net Income, As Adjusted^2, of $14 million in the prior year period. The
year-over-year decline was driven largely by:

      –  lower Commodity Margin, as previously discussed, partially
                offset by
                
            +   lower plant operating expense, as previously discussed, and
                
                lower interest expense associated with a decrease in our
            +   annual effective interest rate as a result of the refinancing
                activities completed during the fourth quarter of 2012 and
                first half of 2013.

Adjusted Free Cash Flow was $38 million in the second quarter of 2013 compared
to $87 million in the prior year period. Adjusted Free Cash Flow decreased
during the period primarily due to a decrease in Adjusted EBITDA, as
previously discussed. Partially offsetting this decline was lower interest
expense, as previously discussed.

Year-to-Date Results

Adjusted EBITDA for the six months ended June 30, 2013, was $629 million
compared to $728 million in the prior year period. The year-over-year decrease
in Adjusted EBITDA was primarily due to a $132 million decrease in Commodity
Margin, partially offset by a $31 million decrease in plant operating
expense^5. The decrease in Commodity Margin was primarily due to:

                the sale of Broad River and Riverside Energy Centers,
      –  partially offset by the acquisition of Bosque Energy Center in
                the fourth quarter of 2012
                
                weaker market conditions due to milder weather, an increase in
            –   wind generation in Texas and higher natural gas prices
                primarily in our Texas, North and Southeast segments in the
                first half of 2013 compared to the prior year period and
                
            –   lower contribution from hedges, partially offset by
                
            +   higher regulatory capacity revenue in the North and
                
            +   higher revenue from a tolling contract in our West segment
                that became effective in January 2013.

The offsetting decrease in plant operating expense^5 was primarily due to the
reversal of previously recognized regulatory fees for which we determined that
we have no obligation, as well as lower equipment failure costs.

Net Loss^1 was $195 million for the six months ended June 30, 2013, compared
to $338 million in the prior year period. As detailed in Table 1, Net Loss, As
Adjusted^2, was $103 million in the six months ended June 30, 2013, compared
to $51 million in the prior year period. The year-over-year change in Net
Loss, As Adjusted^2, was driven largely by:

      –  lower Commodity Margin, as previously discussed, and
            
                higher depreciation and amortization expense primarily
            –   resulting from our acquisition of our Bosque Energy Center,
                partially offset by
            
            +   an increase in various state and foreign jurisdiction income
                tax benefits and
            
            +   lower interest expense associated with a decrease in our
                annual effective interest rate, as previously discussed.

Adjusted Free Cash Flow was $(5) million for the six months ended June 30,
2013, compared to $60 million in the prior year period. Adjusted Free Cash
Flow decreased during the period primarily due to the same factors that drove
comparative performance for the second quarter, as previously discussed.

__________

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

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

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

^4 Based upon shares outstanding (including shares held in reserve) as of June
30, 2011, immediately prior to the initial announcement of the repurchase
program.

^5 Decrease 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 and six
months ended June 30, 2013 and 2012.

                                                  
Table 1: Net Income (Loss), As Adjusted
                                                     
                       Three Months Ended June 30,   Six Months Ended June 30,
                       2013           2012          2013          2012
                       (in millions)                 (in millions)
Net loss
attributable to        $   (70   )     $  (329  )    $  (195  )     $  (338  )
Calpine
Debt extinguishment    68              —             68             12
costs^(1)
Unrealized MtM
(gain) loss on         (31       )     343           24             119
derivatives^(1) (2)
Other items ^ (1)      —              —            —             156      
(3)
Net Income (Loss),     $   (33   )     $  14        $  (103  )     $  (51   )
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 and six months ended June 30, 2012.

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


REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)
                                        
            Three Months Ended June 30,    Six Months Ended June 30,
            2013     2012     Variance   2013     2012       Variance
West        $ 198     $ 210     $  (12 )   $ 400     $ 418       $ (18  )
Texas       133       145       (12    )   209       254         (45    )
North       159       181       (22    )   301       325         (24    )
Southeast   43       73       (30    )   84       129        (45    )
Total       $ 533    $ 609    $  (76 )   $ 994    $ 1,126    $ (132 )
                                                                        

West Region

Second Quarter: Commodity Margin in our West segment decreased by $12 million
in the second quarter of 2013 compared to the prior year period. Primary
drivers were:

      –  lower contribution from hedges, partially offset by
                
            +   higher revenue from a tolling contract and
                
                higher spark spreads on increased generation driven by
            +   improved market conditions associated with lower hydroelectric
                generation, warmer weather and the implementation of the AB32
                carbon market.

Year-to-Date: Commodity Margin in our West segment decreased by $18 million
for the six months ended June 30, 2013, compared to the prior year period. The
year-to-date results were largely impacted by the same factors that drove
comparative performance for the second quarter, as previously discussed.

Texas Region

Second Quarter: Commodity Margin in our Texas segment decreased by $12 million
in the second quarter of 2013 compared to the prior year period. Primary
drivers were:

      –  lower spark spreads resulting from milder weather and an
                increase in wind generation and
                
                lower generation output resulting from a reversal of
            –   coal-to-gas switching due to higher natural gas prices,
                partially offset by
                
            +   higher contribution from hedges and
                
            +   the acquisition of Bosque Energy Center in November 2012.

Year-to-Date: Commodity Margin in our Texas segment decreased by $45 million
for the six months ended June 30, 2013, compared to the prior year period. The
year-to-date results were largely impacted by the same factors that drove
comparative performance for the second quarter, as previously discussed.

North Region

Second Quarter: Commodity Margin in our North segment decreased by $22 million
in the second quarter of 2013 compared to the prior year period. Primary
drivers were:

      –  the sale of Riverside Energy Center in December 2012 and
                
                lower spark spreads and lower generation output resulting from
            –   a reversal of coal-to-gas switching due to higher natural gas
                prices, partially offset by
                
            +   higher regulatory capacity revenues.

Year-to-Date: Commodity Margin in our North segment decreased by $24 million
for the six months ended June 30, 2013, compared to the prior year period. The
year-to-date results were largely impacted by the same factors that drove
comparative performance for the second quarter, as previously discussed.

Southeast Region

Second Quarter: Commodity Margin in our Southeast segment decreased by $30
million in the second quarter of 2013 compared to the prior year period.
Primary drivers were:

      –  the sale of Broad River Energy Center in December 2012 and
            
                lower spark spreads and lower generation output resulting from
            –   milder weather and a reversal of coal-to-gas switching due to
                higher natural gas prices.

Year-to-Date: Commodity Margin in our Southeast segment decreased by $45
million in the six months ended June 30, 2013, compared to the prior year
period. The year-to-date results were largely impacted by the same factors
that drove comparative performance for the second quarter, as previously
discussed.


LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity
                                          
                                            June 30,  December 31,
                                           2013               2012
                                            (in millions)
Cash and cash equivalents, corporate^(1)    $    588           $    1,153
Cash and cash equivalents, non-corporate    127               131
Total cash and cash equivalents             715                1,284
Restricted cash                             198                253
Corporate Revolving Facility availability   760                757
CDHI letter of credit availability^(2)      —                 —
Total current liquidity availability        $    1,673        $    2,294

__________

^(1) Includes $3 million and $11 million of margin deposits posted with us by
our counterparties at June30, 2013, and December31, 2012, respectively.

^(2) 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 June30, 2013, we had $18 million in
outstanding letters of credit issued in excess of $225 million under our CDHI
letter of credit facility that were collateralized by cash. We do not believe
that this change will have a material impact on our liquidity.

Liquidity was approximately $1.7 billion as of June 30, 2013. Cash and cash
equivalents declined during the first half of the year due largely to our
deployment of capital, including the repurchase of $362 million of our common
stock, the funding of $143 million in construction payments related to our
Garrison Energy Center and the expansion of our Deer Park and Channel Energy
Centers, as well as other seasonal variations in working capital which cause
fluctuations in our cash and cash equivalents.


Table 4: Cash Flow Activities

                                           Six Months Ended June 30,
                                            2013           2012
Beginning cash and cash equivalents         $  1,284       $ 1,252 
Net cash used in:
Operating activities                        (175      )     (32     )
Investing activities                        (281      )     (513    )
Financing activities                        (113      )     (120    )
Net decrease in cash and cash equivalents   (569      )     (665    )
Ending cash and cash equivalents            $  715         $ 587   
                                                                    

Cash flows from operating activities in the six months ended June 30, 2013,
resulted in net outflows of $175 million compared to $32 million in the prior
year period. The increase in outflows was primarily due to a decrease in
income from operations as well as an increase in working capital employed,
primarily as a result of higher net accounts receivable balances related to
relatively higher prices for both gas and power across all regions. Also
contributing to the change in net outflows, debt extinguishment costs were
higher in the first half of 2013 due to payments associated with the
redemption of our CCFC notes. These decreases in cash flows from operating
activities were partially offset by less cash paid for interest due to the
refinancing activities of the fourth quarter of 2012 and first half of 2013.

Cash flows used in investing activities during the six months ended June 30,
2013, were $281 million compared to $513 million in the prior year period. The
decrease in outflows was primarily due to $156 million in non-hedging interest
rate swap settlements paid in the prior year period that did not recur this
year, as well as a larger decrease in restricted cash in the first half of
2013 compared to the first half of 2012, primarily due to a release of cash
collateral related to lower exposure on letter of credit facilities and
reduced major maintenance reserve requirements resulting from our plant outage
schedule.

Cash flows used in financing activities were $113 million and were primarily
related to the execution of our share repurchase program, offset by net
proceeds associated with the refinancing of our CCFC notes and the receipt of
proceeds from project debt related to our Russell City and Los Esteros
construction projects.

During the second quarter of 2013, we opportunistically refinanced the notes
of CCFC, our indirect, wholly owned subsidiary. The $1.0 billion 8.0% notes,
previously due in 2016, were replaced with a two-tranche term loan composed of
(i) $900 millionpriced at LIBOR plus 2.25% due in 2020, and (ii) $300 million
priced at LIBOR plus 2.50% due in 2022, each of which is subject to a LIBOR
floor of 0.75%. During the second quarter, we also executed an amendment to
our $1.0 billion Corporate Revolver, extending the maturity from 2015 to 2018
and reducing the LIBOR margin by 1.0% and the undrawn commitment fees by
0.25%. “These refinancings, which we estimate will save us more than $45
million in annual, run-rate interest expense, provide another example of our
focus on growing Adjusted Free Cash Flow Per Share,” said Zamir Rauf,
Calpine’s Chief Financial Officer.

CAPITAL ALLOCATION

Share Repurchase Program

In February 2013, our Board of Directors authorized the repurchase of an
additional $400 million in shares of our common stock, bringing the cumulative
authorization total to $1.0 billion. We completed the repurchase of the
additional $400 million authorization in July 2013. Over the course of our
$1.0 billion share repurchase program, we have repurchased more than 55
million shares of our outstanding common stock at an average price paid of
$18.18 per share.

PLANT DEVELOPMENT

West:

Russell City Energy Center: Construction at our Russell City Energy Center
continues to move forward. Upon completion, this project will bring on line
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 third quarter 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 third quarter 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 our Deer Park and Channel
Energy Centers by approximately 260 MW^6 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 both expansion projects commenced in the fourth quarter of
2012. We expect COD on the expansions of our Channel and Deer Park Energy
Centers during the second quarter of 2014.

North:

Garrison Energy Center: Garrison Energy Center is a 309 MW combined-cycle
project located in Delaware on a site secured by a long-term lease with the
City of Dover. Construction commenced in April 2013, and we expect COD by the
second quarter of 2015. The project’s capacity cleared PJM’s 2015/2016 and
2016/2017 base residual auctions. We are in the early stages of development of
a second phase (309 MW) of this project. PJM has completed the feasibility and
system impact studies for this phase and the facilities study is currently
underway.

Deepwater Energy Center: We are currently evaluating our Deepwater facility
since the existing 158 MW fossil fuel steam-based power plant is currently
scheduled to be decommissioned by May 1, 2015. The Deepwater development
opportunity would add approximately 350 MW of new combined-cycle capacity and
leverage existing infrastructure; however, our Deepwater development proposal
did not clear PJM’s 2016/2017 base residual auction. The project is continuing
to advance entitlements (permits, zoning, transmission, etc.) for the
potential development of Deepwater at a future date.

Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the
Mankato Power Plant in response to a competitive resource acquisition process
established by the Minnesota Public Utilities Commission (MPUC). The process,
which will be managed via a contested case hearing, is intended to address a
capacity shortfall in the Northern States Power service territory of up to 500
MW over the 2017 to 2019 time frame. The MPUC will evaluate proposals for
intermediate and/or peaking capacity to meet all or part of the 500 MW needed.
We expect that winning bidders will be identified in the fourth quarter of
2013.

All Segments:

Turbine Modernization: We continue to move forward with our turbine
modernization program. Through June 30, 2013, we have completed the upgrade of
twelve Siemens and eight GE turbines totaling approximately 200 MW and have
committed to upgrade approximately four additional turbines. Similarly, we
have the opportunity at several of our power plants in Texas to implement
further modernizations to add as much as 300 MW of incremental capacity across
the region at attractive prices. Our decision to invest in these
modernizations depends upon, among other things, further clarity on market
design reforms currently being considered by the Public Utility Commission of
Texas.

___________

^6 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

Second Quarter 2013 Power Operations Achievements:

  *Safety Performance:
    — Maintained top quartile^7 safety metrics: 0.97 Total Recordable Incident
    Rate

  *Availability Performance:
    — Maintained impressive fleetwide forced outage factor: 1.6%
    — Delivered remarkable fleetwide starting reliability: 99%

  *Geothermal Generation:
    — Provided approximately 1.5 million MWh of renewable baseload generation
    during the quarter with a 0.70% forced outage factor year-to-date

  *Natural Gas-fired Generation:
    — Corpus Christi Energy Center: 100% starting reliability, 0% forced
    outage factor
    — Carville Energy Center: 100% starting reliability, 99.9% availability

Second Quarter 2013 Commercial Operations Achievements:

  *Customer-oriented Growth:
    — Entered into a three-year PPA with South Carolina Electric and Gas
    Company to provide 200 MW of power from our Columbia Energy Center
    beginning January 2014
    — Entered into two new resource adequacy contracts with Pacific Gas and
    Electric Company for our Delta and Sutter Energy Centers for the full
    capacity of each plant which commence in January and June 2014,
    respectively, and extend through December 2015 and 2016, respectively
    — Entered into two new PPAs with Marin Energy Authority to provide 3 MW
    and 10 MW of renewable power in 2014 and 2017-2026, respectively, from our
    Geysers assets

___________

^7 According to EEI Safety Survey (2012).

2013 FINANCIAL OUTLOOK

(in millions, except per share amounts)

                                   Prior Guidance       
                                   (as of May 2, 2013)    Current Guidance
Adjusted EBITDA                   $ 1,800 - 1,960           $ 1,800 - 1,875
Less:
Operating lease payments            35                        35
Major maintenance expense and
maintenance capital                 370                       390
expenditures^(1)
Cash interest, net^(2)              755                       710
Cash taxes                          15                        15
Other                              10                    10        
Adjusted Free Cash Flow           $ 615 - 775               $ 640 - 715
Per Share Estimate (diluted)      $ 1.50                    $ 1.50
                                                              
Growth capital expenditures       $ (250        )           $ (250      )
(net of debt funding)
Debt amortization                 $ (140        )           $ (150      )

________

^(1) Includes projected major maintenance expense of $230 million and
maintenance capital expenditures of $160 million. Capital expenditures exclude
major construction and development projects. 2013 figures exclude a
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 updating our 2013 guidance. In order to
reflect the weaker market conditions during the first half of the year, we are
lowering the top end of our Adjusted EBITDA and Adjusted Free Cash Flow
guidance, while maintaining the bottom end of Adjusted EBITDA, and increasing
the bottom end of Adjusted Free Cash Flow. We now project Adjusted EBITDA of
$1,800 million to $1,875 million and Adjusted Free Cash Flow of $640 million
to $715 million. Meanwhile, we are reaffirming our Adjusted Free Cash Flow Per
Share guidance of $1.50, which would result in a 22% compound annual growth
rate since 2011.

Finally, we 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 second quarter of 2013 on Thursday, July 25,2013, 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 35088347. 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 35088347. Presentation materials to accompany the
conference call will be available on our website on July 25, 2013.

ABOUT CALPINE

Calpine Corporation generates more electricity than any other independent
power producer in America, with a fleet of 93 power plants in operation or
under construction, representing more than 27,000 megawatts of generation
capacity. 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
competitive wholesale 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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2013,
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, seasonality of demand, 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 Term Loans 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 CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)
                                                  
                       Three Months Ended June 30,   Six Months Ended June 30,
                       2013           2012          2013           2012
                       (in millions, except share and per share amounts)
Operating revenues:
Commodity revenue      $  1,539        $  1,177      $  2,847        $ 2,389
Unrealized
mark-to-market gain    31              (302      )   (40       )     (280    )
(loss)
Other revenue          2              4            6              6       
Operating revenues     1,572          879          2,813          2,115   
Operating expenses:
Fuel and purchased
energy expense:
Commodity expense      998             570           1,833           1,261
Unrealized
mark-to-market         2              44           (12       )     (12     )
(gain) loss
Fuel and purchased     1,000          614          1,821          1,249   
energy expense
Plant operating        257             271           484             492
expense
Depreciation and       145             138           291             278
amortization expense
Sales, general and
other administrative   36              35            69              68
expense
Other operating        20             19           38             40      
expenses
Total operating        1,458          1,077        2,703          2,127   
expenses
(Income) from
unconsolidated         (8        )     (5        )   (16       )     (14     )
investments in power
plants
Income (loss) from     122             (193      )   126             2
operations
Interest expense       170             184           346             369
Loss on interest       —               —             —               14
rate derivatives
Interest (income)      (1        )     (2        )   (3        )     (5      )
Debt extinguishment    68              —             68              12
costs
Other (income)         3              6            8              8       
expense, net
Loss before income     (118      )     (381      )   (293      )     (396    )
taxes
Income tax benefit     (48       )     (52       )   (98       )     (58     )
Net loss               (70       )     (329      )   (195      )     (338    )
Net income
attributable to the    —              —            —              —       
noncontrolling
interest
Net loss
attributable to        $  (70    )     $  (329   )   $  (195   )     $ (338  )
Calpine
                                                                     
Basic and diluted
loss per common
share attributable
to Calpine:
Weighted average
shares of common       447,558        471,444      449,620        474,775 
stock outstanding
(in thousands)
Net loss per common
share attributable     $  (0.16  )     $  (0.69  )   $  (0.43  )     $ (0.71 )
to Calpine — basic
and diluted
                                                                             


CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)
                                                         
                                      June 30,        December 31,
                                      2013                    2012
                                      (in millions, except share and per share
                                      amounts)
ASSETS
Current assets:
Cash and cash equivalents             $    715                $   1,284
Accounts receivable, net of           726                     437
allowance of $2 and $6
Margin deposits and other prepaid     310                     244
expense
Restricted cash, current              140                     193
Derivative assets, current            601                     339
Inventory and other current assets    447                    335          
Total current assets                  2,939                   2,832
Property, plant and equipment, net    13,057                  13,005
Restricted cash, net of current       58                      60
portion
Investments in power plants           85                      81
Long-term derivative assets           136                     98
Other assets                          483                    473          
Total assets                          $    16,758            $   16,549   
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable                      $    551                $   382
Accrued interest payable              175                     180
Debt, current portion                 169                     115
Derivative liabilities, current       630                     357
Other current liabilities             206                    284          
Total current liabilities             1,731                   1,318
Debt, net of current portion          10,851                  10,635
Deferred income tax liability,        3                       —
non-current
Long-term derivative liabilities      291                     293
Other long-term liabilities           298                    247          
Total liabilities                     13,174                  12,493
                                                              
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, 495,214,960 and 492,495,100   1                       1
shares issued, respectively, and
441,671,019 and 457,048,970 shares
outstanding, respectively
Treasury stock, at cost, 53,543,941   (962           )        (594         )
and 35,446,130 shares, respectively
Additional paid-in capital            12,370                  12,335
Accumulated deficit                   (7,695         )        (7,500       )
Accumulated other comprehensive       (191           )        (248         )
loss
Total Calpine stockholders’ equity    3,523                   3,994
Noncontrolling interest               61                     62           
Total stockholders’ equity            3,584                  4,056        
Total liabilities and stockholders’   $    16,758            $   16,549   
equity
                                                                           


CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)
                                                   
                                                     Six Months Ended June 30,
                                                     2013          2012
                                                     (in millions)
Cash flows from operating activities:
Net loss                                             $  (195  )     $  (338  )
Adjustments to reconcile net loss to net cash used
in operating activities:
Depreciation and amortization expense^(1)            315            299
Debt extinguishment costs                            28             —
Deferred income taxes                                (15      )     (31      )
Loss on disposition of assets                        4              4
Unrealized mark-to-market activity, net              24             119
(Income) from unconsolidated investments in power    (16      )     (14      )
plants
Return on unconsolidated investments in power        16             16
plants
Stock-based compensation expense                     20             13
Other                                                (4       )     1
Change in operating assets and liabilities:
Accounts receivable                                  (285     )     63
Derivative instruments, net                          1              (111     )
Other assets                                         (182     )     (122     )
Accounts payable and accrued expenses                67             (86      )
Settlement of non-hedging interest rate swaps        —              156
Other liabilities                                    47            (1       )
Net cash used in operating activities                (175     )     (32      )
Cash flows from investing activities:
Purchases of property, plant and equipment           (335     )     (369     )
Settlement of non-hedging interest rate swaps        —              (156     )
Decrease in restricted cash                          55             19
Purchases of deferred transmission credits           —              (12      )
Other                                                (1       )     5        
Net cash used in investing activities                  (281  )       (513  )
Cash flows from financing activities:
Repayment under First Lien Term Loans                  (12   )       (8    )
Borrowings from CCFC Term Loans                      1,197          —
Repayment of CCFC Notes                              (1,000   )     —
Borrowings from project financing, notes payable     116            226
and other
Repayments of project financing, notes payable and   (43      )     (46      )
other
Financing costs                                      (27      )     (5       )
Stock repurchases                                    (362     )     (290     )
Proceeds from exercises of stock options             17             3
Other                                                1             —        
Net cash used in financing activities                (113     )     (120     )
Net decrease in cash and cash equivalents            (569     )     (665     )
Cash and cash equivalents, beginning of period       1,284         1,252    
Cash and cash equivalents, end of period             $  715        $  587   
                                                                    
Cash paid during the period for:
Interest, net of amounts capitalized                 $  334         $  352
Income taxes                                         $  21          $  13
                                                                    
Supplemental disclosure of non-cash investing
activities:
Change in capital expenditures included in           $  17          $  3
accounts 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 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 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 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,
environmental compliance expense, and realized settlements from our marketing,
hedging and optimization activities including natural gas transactions hedging
future power sales, but excludes the unrealized portion of our mark-to-market
activity and other revenues. We believe that Commodity Margin 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 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.

We believe Adjusted EBITDA is 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.

Additionally, we believe that investors commonly adjust EBITDA information to
eliminate the effect of restructuring and other expenses, which vary widely
from company to company and impair comparability. As we define it, Adjusted
EBITDA represents EBITDA adjusted for the effects of impairment losses, gains
or losses on sales, dispositions or retirements of assets, any unrealized
gains or losses from accounting for derivatives, stock-based compensation
expense, operating lease expense, non-cash gains and losses from foreign
currency translations, major maintenance expense, gains or losses on the
repurchase or extinguishment of debt, Conectiv Acquisition-related costs and
any extraordinary, unusual or non-recurring items plus the Adjusted EBITDA
from our discontinued operations and adjustments to reflect the Adjusted
EBITDA from our unconsolidated investments. We adjust for these items in our
Adjusted EBITDA as our management believes that these items would distort
their ability to efficiently view and assess our core operating trends.

In summary, 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.

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 presented because we believe it is a useful tool
for assessing the financial performance of our company in the current period.
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 June 30, 2013 and 2012 (in millions):

               
                 Three Months Ended June 30, 2013
                                                        Consolidation 
                                                            And
                 West      Texas      North     Southeast   Elimination     Total
Commodity        $ 198     $ 133      $ 159     $  43       $    —          $ 533
Margin
Add:
Unrealized
mark-to-market   19        34         (12   )   7           (9        )     39
commodity
activity, net
and other^(1)
Less:
Plant
operating        88        96         46        35          (8        )     257
expense
Depreciation
and              52        44         32        18          (1        )     145
amortization
expense
Sales, general
and other        3         21         6         7           (1        )     36
administrative
expense
Other
operating        11        1          7         (1      )   2               20
expenses
(Income) from
unconsolidated   —        —         (8    )   —          —              (8     )
investments in
power plants
Income (loss)
from             $ 63     $ 5       $ 64     $  (9   )   $    (1   )     $ 122  
operations
                 
                 
                 Three Months Ended June 30, 2012
                                                            Consolidation
                                                            And
                 West      Texas      North     Southeast   Elimination     Total
Commodity        $ 210     $ 145      $ 181     $  73       $    —          $ 609
Margin^(2)(3)
Add:
Unrealized
mark-to-market   (76   )   (217   )   (3    )   (42     )   (6        )     (344   )
commodity
activity, net
and other^(1)
Less:
Plant
operating        112       72         58        36          (7        )     271
expense
Depreciation
and              49        34         34        22          (1        )     138
amortization
expense
Sales, general
and other        6         13         8         7           1               35
administrative
expense
Other
operating        9         1          6         2           1               19
expenses
(Income) from
unconsolidated   —        —         (5    )   —          —              (5     )
investments in
power plants
Income (loss)
from             $ (42 )   $ (192 )   $ 77     $  (36  )   $    —         $ (193 )
operations
                                                                                   

The following table reconciles our Commodity Margin to its U.S. GAAP results
for the six months ended June 30, 2013 and 2012 (in millions):

               
                 Six Months Ended June 30, 2013
                                                        Consolidation 
                                                            And
                 West      Texas      North     Southeast   Elimination     Total
Commodity        $ 400     $ 209      $ 301     $  84       $    —          $ 994
Margin
Add:
Unrealized
mark-to-market   (18   )   23         (5    )   14          (16       )     (2      )
commodity
activity, net
and other^(4)
Less:
Plant
operating        181       164        90        65          (16       )     484
expense
Depreciation
and              103       87         65        37          (1        )     291
amortization
expense
Sales, general
and other        7         38         12        12          —               69
administrative
expense
Other
operating        20        2          14        1           1               38
expenses
(Income) from
unconsolidated   —        —         (16   )   —          —              (16     )
investments in
power plants
Income (loss)
from             $ 71     $ (59  )   $ 131    $  (17  )   $    —         $ 126   
operations
                 
                 
                 Six Months Ended June 30, 2012
                                                            Consolidation
                                                            And
                 West      Texas      North     Southeast   Elimination     Total
Commodity        $ 418     $ 254      $ 325     $  129      $    —          $ 1,126
Margin^(2)(3)
Add:
Unrealized
mark-to-market   (40   )   (183   )   9         (32     )   (14       )     (260    )
commodity
activity, net
and other^(4)
Less:
Plant
operating        193       140        103       69          (13       )     492
expense
Depreciation
and              99        69         67        45          (2        )     278
amortization
expense
Sales, general
and other        14        24         14        15          1               68
administrative
expense
Other
operating        20        3          15        3           (1        )     40
expenses
(Income) from
unconsolidated   —        —         (14   )   —          —              (14     )
investments in
power plants
Income (loss)
from             $ 52     $ (165 )   $ 149    $  (35  )   $    1         $ 2     
operations

_________

^(1) Includes $(11) million and $(1) million of lease levelization and $3
million and $3 million of amortization expense for the three months ended
June30, 2013 and 2012, respectively.

^(2) Our North segment includes Commodity Margin of $24 million and $32
million for the three and six months ended June 30, 2012, related to Riverside
Energy Center, LLC, which was sold in December 2012.

^(3) Our Southeast segment includes Commodity Margin of $13 million and $24
million for the three and six months ended June 30, 2012, related to Broad
River Energy Center, which was sold in December 2012.

^(4) Includes $(27) million and $(9) million of lease levelization and $7
million and $7 million of amortization expense for the six months ended
June30, 2013 and 2012, respectively.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted
Free Cash Flow to our net loss attributable to Calpine for the three and six
months ended June 30, 2013 and 2012, as reported under U.S. GAAP.

                      Three Months Ended June 30,  Six Months Ended June 30,
                       2013            2012         2013           2012
                                                                     
Net loss
attributable to        $    (70   )     $  (329  )   $  (195   )     $  (338 )
Calpine
Income tax benefit     (48        )     (52      )   (98       )     (58     )
Debt extinguishment
costs and other        71               6            76              20
(income) expense,
net
Loss on interest       —                —            —               14
rate derivatives
Interest expense,
net of interest        169             182         343            364     
income
Income (loss) from     $    122         $  (193  )   $  126          $  2
operations
Add:
Adjustments to
reconcile income
from operations to
Adjusted EBITDA:
Depreciation and
amortization
expense, excluding     146              138          292             279
deferred financing
costs^(1)
Major maintenance      83               81           149             127
expense
Operating lease        8                8            17              17
expense
Unrealized (gain)
loss on commodity
derivative             (29        )     346          28              268
mark-to-market
activity
Adjustments to
reflect Adjusted
EBITDA from            7                9            13              16
unconsolidated
investments^(2)(3)
Stock-based            12               7            20              13
compensation expense
Loss on dispositions   2                2            4               4
of assets
Acquired contract      3                3            7               7
amortization
Other                  (11        )     2           (27       )     (5      )
Total Adjusted         $    343        $  403      $  629         $  728  
EBITDA
Less:
Operating lease        8                8            17              17
payments
Major maintenance
expense and capital    105              109          241             255
expenditures^(4)
Cash interest,         175              190          355             381
net^(5)
Cash taxes             14               7            17              11
Other                  3               2           4              4       
Adjusted Free Cash     $    38         $  87       $  (5     )     $  60   
Flow^(6)
                                                                     
Weighted average
shares of common
stock outstanding      447,558         471,444     449,620        474,775 
(diluted, in
thousands)
Adjusted Free Cash
Flow Per Share         $    0.08       $  0.19     $  (0.01  )     $  0.13 
(diluted)

_________

^(1) Depreciation and amortization expense 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 six months ended June30, 2013 and 2012.

^(4) Includes $85 million and $151 million in major maintenance expense for
the three months and six months ended June 30, 2013, respectively, and $20
million and $90 million in maintenance capital expenditure for the three and
six months ended June 30, 2013, respectively. Includes $84 million and $131
million in major maintenance expense for the three months and six months ended
June 30, 2012, respectively, and $25 million and $124 million in maintenance
capital expenditure for the three and six months ended June 30, 2012,
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 $121 million and $304 million
for the three months and six months ended June 30, 2013, respectively, and an
increase in working capital of $56 million and a decrease in working capital
of $20 million for the three months and six months ended June 30, 2012,
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 and six
months ended June 30, 2013 and 2012. Reconciliations for both Adjusted EBITDA
and Commodity Margin to comparable U.S. GAAP measures are provided above.

                      Three Months Ended June 30,  Six Months Ended June 30,
                       2013            2012         2013         2012
                                                     
Commodity Margin       $   533          $  609       $  994        $  1,126
Other revenue          3                3            6             6
Plant operating        (166      )      (181    )    (320    )     (351      )
expense^(1)
Sales, general and
administrative         (30       )      (30     )    (59     )     (60       )
expense^(2)
Other operating        (11       )      (10     )    (21     )     (21       )
expenses^(3)
Adjusted EBITDA from
unconsolidated         14               14           29            30
investments in power
plants^(4)
Other                  —               (2      )    —            (2        )
Adjusted EBITDA        $   343         $  403      $  629       $  728    

_________

^(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 composed 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)                                         $ 162     $ 237
Plus:
Debt extinguishment costs                                      68        68
Interest expense, net of interest income                       700       700
Depreciation and amortization expense                          595       595
Major maintenance expense                                      225       225
Operating lease expense                                        35        35
Other^(2)                                                      15       15
Adjusted EBITDA                                              $ 1,800   $ 1,875
Less:
Operating lease payments                                       35        35
Major maintenance expense and maintenance capital              390       390
expenditures^(3)
Cash interest, net^(4)                                         710       710
Cash taxes                                                     15        15
Other                                                          10       10
Adjusted Free Cash Flow                                      $ 640     $ 715

_________

^(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 $230 million and
maintenance capital expenditures of $160 million. Capital expenditures exclude
major construction and development projects. 2013 figures exclude a
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 June 30  Six Months Ended June 30,
                        2013           2012         2013          2012
Total MWh generated     22,339          26,681       46,337         54,736
(in thousands)^(1)
West                    7,229           6,191        15,566         14,394
Texas                   7,270           9,089        15,300         18,232
Southeast               3,773           6,201        7,495          11,923
North                   4,067           5,200        7,976          10,187
                                                                    
Average availability    88.2     %      86.4    %    89.2     %     88.4    %
West                    88.8     %      81.6    %    88.7     %     87.6    %
Texas                   83.5     %      88.3    %    85.4     %     87.0    %
Southeast               95.2     %      90.8    %    94.7     %     92.5    %
North                   88.2     %      85.4    %    90.2     %     87.3    %
                                                                    
Average capacity
factor, excluding       43.4     %      51.0    %    45.5     %     53.0    %
peakers^(1)
West                    52.5     %      45.0    %    57.0     %     52.7    %
Texas                   42.8     %      59.3    %    45.3     %     59.6    %
Southeast               33.7     %      51.8    %    33.7     %     50.3    %
North                   42.9     %      45.6    %    43.1     %     46.4    %
                                                                    
Steam adjusted heat     7,447           7,391        7,394          7,329
rate (Btu/kWh)
West                    7,414           7,366        7,345          7,233
Texas                   7,184           7,150        7,173          7,115
Southeast               7,429           7,309        7,349          7,291
North                   8,015           7,991        7,963          7,903

________

^(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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