Calpine Reports Strong Third Quarter 2013 Results, Provides 2014 Guidance, Announces $1 Billion Multi-Year Share Repurchase

  Calpine Reports Strong Third Quarter 2013 Results, Provides 2014 Guidance,
  Announces $1 Billion Multi-Year Share Repurchase Authorization and Reaffirms
  15-20% Adjusted Free Cash Flow Per Share Compound Annual Growth Rate

Business Wire

HOUSTON -- November 7, 2013

Calpine Corporation (NYSE: CPN):

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

             Three Months Ended September 30,  Nine Months Ended          
                                                 September 30,
              2013        2012      % Change   2013      2012      %
                                                                       Change
                                                                       
Operating     $  2,050     $ 1,996    2.7   %    $ 4,863    $ 4,111    18.3 %
Revenues
Commodity     $  985       $ 897      9.8   %    $ 1,979    $ 2,023    (2.2 )%
Margin
Adjusted      $  802       $ 706      13.6  %    $ 1,431    $ 1,434    (0.2 )%
EBITDA
Adjusted
Free Cash     $  556       $ 463      20.1  %    $ 551      $ 523      5.4  %
Flow
Per Share     $  1.27      $ 0.99     28.3  %    $ 1.23     $ 1.10     11.8 %
(diluted)
Net           $  306       $ 437                 $ 111      $ 99
Income^1
Per Share     $  0.70      $ 0.94                $ 0.25     $ 0.21
(diluted)
Net Income,
As            $  268       $ 215                 $ 165      $ 164
Adjusted^2
                                                                       

Narrowing 2013 and Providing 2014 Full Year Guidance (in millions, except per
share amounts):

                             2013            2014
                                              
Adjusted EBITDA              $1,800 - 1,825   $1,800 - 1,900
Adjusted Free Cash Flow      $645 - 670       $685 - 785
Per Share Estimate (diluted) $1.50            $1.60 - 1.80
                                              

Recent Achievements:

  *Operations:
    — Generated over 30 million MWh^3 of electricity in the third quarter of
    2013
    — Achieved record-low year-to-date fleetwide forced outage factor: 1.5%
    — Delivered record-high year-to-date fleetwide starting reliability: 98.5%
    — Reduced year-to-date plant operating expense^4 and sales, general and
    administrative expense^5 by ~7% each

  *Commercial:
    — Successfully completed construction of more than 900 MW of
    combined-cycle capacity in California and began servicing related
    contracts with Pacific Gas and Electric
    — Entered into a new five-year PPA with Celanese Ltd for approximately 50
    MW commencing in 2014 and extended existing steam agreement for ten years
    beyond 2016 from our Clear Lake Power Plant
    — Entered into a 100 MW financial PPA with a counterparty in PJM that
    commences in November 2013 and extends through 2016

  *Capital Management:
    — Announcing new $1 billion multi-year share repurchase authorization
    — Separately completed approximately $92 million of interim share
    repurchases since last earnings announcement
    — Refinanced approximately $1.6 billion of Senior Secured Notes, achieving
    interest savings and extending maturities

Calpine Corporation (NYSE: CPN) today reported third quarter 2013 Adjusted
EBITDA of $802 million, compared to $706 million in the prior year period, and
Adjusted Free Cash Flow of $556 million, or $1.27 per diluted share, compared
to $463 million, or $0.99 per diluted share, in the prior year period. Net
Income^1 for the third quarter of 2013 was $306 million, or $0.70 per diluted
share, compared to $437 million, or $0.94 per diluted share, in the prior year
period. Net Income, As Adjusted^2, for the third quarter of 2013 was $268
million compared to $215 million in the prior year period. The increases in
Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted^2, were
driven primarily by higher Commodity Margin resulting from increased
regulatory capacity payments, new contracts and higher contribution from
hedges, partially offset by the net impact of portfolio changes.

Year-to-date 2013 Adjusted EBITDA was $1,431 million, compared to $1,434
million in the prior year period, and Adjusted Free Cash Flow was $551
million, or $1.23 per diluted share, compared to $523 million, or $1.10 per
diluted share, in the prior year period. Net Income^1 for the first nine
months of 2013 was $111 million, or $0.25 per diluted share, compared to $99
million, or $0.21 per diluted share, in the prior year period. Net Income, As
Adjusted^2, for the first nine months of 2013 was $165 million compared to
$164 million in the prior year period. The comparable year-to-date results
reflect the favorable year-over-year third quarter performance, as previously
discussed, which offset comparatively lower first half results that were
primarily related to portfolio changes and milder weather.

“The Calpine team remains focused on delivering on our 2013 financial
commitments to shareholders through disciplined operational and commercial
performance,” said Jack Fusco, Calpine’s Chief Executive Officer. “As
reflected in our strong third quarter results, our plant personnel delivered a
record-low fleetwide forced outage factor and record-high starting
reliability, while exercising strict cost discipline. Our commercial
operations team captured value through an effective hedging program,
especially in Texas during this summer’s challenging market conditions.
Finally, our construction team achieved commercial operations on two new
contracted plants in California in August, further contributing to the
quarter’s performance.

“We also remain intently focused on enhancing shareholder value through
disciplined capital allocation. We remain confident that Calpine is
strategically well positioned to benefit from the favorable fundamental and
secular trends in our core competitive wholesale power markets. As we have
made clear in the past, our approach to capital allocation includes analyzing
M&A and development opportunities and evaluating them against our fundamental
view when deciding whether the optimal allocation to earn superior returns for
our shareholders is through growth investments or share repurchases. Over
time, we expect it will be a mix, and of course, we will continue to divest
non-strategic assets opportunistically. Accordingly, during the last few
months, we repurchased approximately $92 million of our shares. More
significantly, today we are announcing a further $1 billion multi-year share
repurchase authorization, representing approximately 11% of our current market
capitalization. In executing this authorization, we will continue to evaluate
share repurchase against other opportunities.

“Finally, I would like to re-emphasize an important point we made at this time
last year when we introduced our Adjusted Free Cash Flow Per Share growth
target. Calpine’s Adjusted Free Cash Flow is levered, both operationally and
financially, such that modest increases in Adjusted EBITDA can lead to strong
growth in Adjusted Free Cash Flow Per Share, hence our 15 - 20% targeted
multi-year compound annual growth rate. The updated 2013 and initial 2014
guidance we are providing today reaffirms this growth and, in our view,
validates the Calpine investment thesis – the combination of a technologically
and geographically well-positioned fleet, operational excellence, strong
commercial execution and disciplined capital allocation translate into a
compelling total shareholder return value proposition.”

__________

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

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

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

^4 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 nine
months ended September 30, 2013 and 2012.

^5 Decrease 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 three and nine months ended September 30, 2013 and 2012.

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2013 was $802 million, compared to
$706 million in the prior year period. The year-over-year increase in Adjusted
EBITDA was primarily related to an $88 million increase in Commodity Margin,
which was primarily due to:

                the acquisition of Bosque Energy Center in November 2012 and
                the positive impact from Russell City and Los Esteros power
      +  plants commencing commercial operations during the third
                quarter of 2013, partially offset by the sale of our Broad
                River and Riverside Energy Centers in December 2012
            +   higher regulatory capacity revenue in the North
            +   higher revenue from contracts in our West and Southeast
                segments that became effective in January 2013 and
            +   higher contribution from hedges, partially offset by
                weaker market conditions across all segments due primarily to
            –   milder weather in July and August 2013 compared to the same
                months in 2012.

Net Income^1 was $306 million for the third quarter of 2013, compared to $437
million in the prior year period. As detailed in Table 1, Net Income, As
Adjusted^2, was $268 million in the third quarter of 2013 compared to $215
million in the prior year period. This year-over-year increase was driven
largely by:

      +  higher Commodity Margin, as previously discussed, and
                lower interest expense due to a decrease in our annual
            +   effective interest rate associated with refinancings we have
                completed during the year, partially offset by
            –   higher income taxes resulting primarily from an increase in
                various state and foreign jurisdiction income tax expense and
                higher depreciation and amortization expense due to the
            –   acquisition of Bosque Energy Center and the commencement of
                commercial operations at our Russell City and Los Esteros
                power plants in August 2013.

Adjusted Free Cash Flow was $556 million in the third quarter of 2013 compared
to $463 million in the prior year period. Adjusted Free Cash Flow increased
during the period primarily due to the increase in Adjusted EBITDA, as
previously discussed.

Year-to-Date Results

Adjusted EBITDA for the nine months ended September 30, 2013, was $1,431
million compared to $1,434 million in the prior year period. A $44 million
year-over-year decrease in Commodity Margin was largely offset by a $38
million decrease in plant operating expense^4. The decrease in Commodity
Margin was primarily due to:

                the sale of Broad River and Riverside Energy Centers in
                December 2012, partially offset by the acquisition of Bosque
      –  Energy Center in November 2012 and the positive impact from
                our Russell City and Los Esteros power plants commencing
                commercial operations during the third quarter of 2013 and
                weaker year-to-date market conditions in our Texas, North and
            –   Southeast segments, compared to the same period in 2012,
                partially offset by
            +   higher regulatory capacity revenue in the North
            +   higher revenue from contracts in our West and Southeast
                segments that became effective in January 2013 and
            +   higher contribution from hedges.

The offsetting decrease in plant operating expense^4 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 and other
miscellaneous expenses.

Net Income^1 was $111 million for the nine months ended September 30, 2013,
compared to $99 million in the prior year period. As detailed in Table 1, Net
Income, As Adjusted^2, was $165 million in the nine months ended September 30,
2013, compared to $164 million in the prior year period. The comparable
year-to-date Net Income, As Adjusted^2, reflects:

      –  lower Commodity Margin, as previously discussed, and
                higher depreciation and amortization expense primarily due to
            –   the acquisition of Bosque Energy Center and our Russell City
                and Los Esteros power plants commencing commercial operations
                in August 2013, partially offset by
            +   lower interest expense associated with a decrease in our
                annual effective interest rate
            +   lower plant operating expense, as previously discussed, and
                lower income tax expense primarily related to the expiration
            +   of applicable statutes of limitation related to uncertain tax
                positions.

Adjusted Free Cash Flow was $551 million for the nine months ended September
30, 2013, compared to $523 million in the prior year period. Adjusted Free
Cash Flow increased during the period primarily due to lower interest expense,
as previously discussed.

Table 1: Net Income, As Adjusted

                                                              
                       Three Months Ended September   Nine Months Ended
                       30,                            September 30,
                       2013              2012         2013          2012
                       (in millions)                  (in millions)
Net income
attributable to        $   306           $  437       $  111        $  99
Calpine
Debt extinguishment    —                 —            68            12
costs^(1)
Unrealized MtM gain
on derivatives^(1)     (38       )       (222    )    (14     )     (103    )
(2)
Other items ^ (1)      —                —           —            156     
(3)
Net Income, As         $   268          $  215      $  165       $  164  
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 $156 million for the
nine months ended September 30, 2012.

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

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

                                                               
            Three Months Ended September      Nine Months Ended September 30,
            30,
            2013         2012      Variance   2013        2012        Variance
West        $  337       $ 330     $  7       $ 737       $ 748       $  (11 )
Texas       328          218       110        537         472         65
North       242          266       (24    )   543         591         (48    )
Southeast   78          83       (5     )   162        212        (50    )
Total       $  985      $ 897    $  88     $ 1,979    $ 2,023    $  (44 )
                                                                             

West Region

Third Quarter: Commodity Margin in our West segment increased by $7 million in
the third quarter of 2013 compared to the prior year period. Primary drivers
were:

      +  higher revenue from a tolling contract that became effective
                in January 2013 and
                our contracted Russell City and Los Esteros power plants
            +   commencing commercial operations in August 2013, partially
                offset by
            –   lower contribution from hedges.

Year-to-Date: Commodity Margin in our West segment decreased by $11 million
for the nine months ended September 30, 2013, compared to the prior year
period. Primary drivers were:

      –  lower contribution from hedges, partially offset by
            +   our contracted Russell City and Los Esteros power plants
                commencing commercial operations in August 2013
            +   higher revenue from a tolling contract that became effective
                in January 2013 and
            +   stronger market conditions in the first half of 2013 compared
                to the prior year period.

Texas Region

Third Quarter: Commodity Margin in our Texas segment increased by $110 million
in the third quarter of 2013 compared to the prior year period. Primary
drivers were:

      +  higher contribution from hedges and
            +   the acquisition of Bosque Energy Center in November 2012,
                partially offset by
            –   lower spark spreads resulting from weaker market conditions.

Year-to-Date: Commodity Margin in our Texas segment increased by $65 million
for the nine months ended September 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 third quarter, as previously
discussed.

North Region

Third Quarter: Excluding a $32 million decrease from the sale of our Riverside
Energy Center in December 2012, Commodity Margin in our North segment
increased by $8 million in the third quarter of 2013 compared to the prior
year period. Primary drivers were:

      +  higher regulatory capacity revenues, partially offset by
                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: Excluding a $64 million decrease from the sale of our Riverside
Energy Center in December 2012, Commodity Margin in our North segment
increased by $16 million for the nine months ended September 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 third
quarter, as previously discussed.

Southeast Region

Third Quarter: Excluding a $20 million decrease from the sale of our Broad
River Energy Center in December 2012, Commodity Margin in our Southeast
segment increased by $15 million in the third quarter of 2013 compared to the
prior year period. Primary drivers were:

      +  higher revenue from a new contract that became effective in
                January 2013, partially offset by
                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: Excluding a $44 million decrease from the sale of our Broad
River Energy Center in December 2012, Commodity Margin in our Southeast
segment decreased by $6 million in the nine months ended September 30, 2013,
compared to the prior year period. Primary drivers were:

                  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, partially offset by
              +   higher revenue from a new contract that became effective
                  January 2013.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

                                          
                                            September 30,  December 31,
                                            2013            2012
                                            (in millions)
Cash and cash equivalents, corporate^(1)    $   829         $    1,153
Cash and cash equivalents, non-corporate    195            131
Total cash and cash equivalents             1,024           1,284
Restricted cash                             248             253
Corporate Revolving Facility availability   756             757
CDHI letter of credit availability^(2)      —              —
Total current liquidity availability        $   2,028      $    2,294

__________

^(1) Includes $22 million and $11 million of margin deposits posted with us by
our counterparties at September30, 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 September30, 2013, we had $4 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 $2 billion as of September 30, 2013. Cash and cash
equivalents declined during the first nine months of the year due largely to
our deployment of capital, including the repurchase of $462 million of our
common stock, in addition to the funding of construction payments related to
our Garrison Energy Center and the expansion of our Deer Park and Channel
Energy Centers. These expenditures were partially offset by $551 million in
Adjusted Free Cash Flow earned during the period.

Table 4: Cash Flow Activities

                                           Nine Months Ended September 30,
                                            2013              2012
                                            (in millions)
Beginning cash and cash equivalents         $   1,284         $  1,252  
Net cash provided by (used in):
Operating activities                        415                608
Investing activities                        (468        )      (701      )
Financing activities                        (207        )      (62       )
Net decrease in cash and cash equivalents   (260        )      (155      )
Ending cash and cash equivalents            $   1,024         $  1,097  
                                                                         

Cash flows from operating activities in the nine months ended September 30,
2013, resulted in net inflows of $415 million compared to $608 million in the
prior year period. The decrease was primarily due to an increase in working
capital employed, largely as a result of higher net accounts receivable and
accounts payable balances and margin deposits due to increased revenues and
prices combined with higher inventory balances resulting from purchases of
environmental allowances. Also contributing to the decrease were higher debt
extinguishment costs in the first half of 2013 due to payments associated with
the redemption of our CCFC notes.

Cash flows used in investing activities during the nine months ended September
30, 2013, were $468 million compared to $701 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 lower capital expenditures during the nine months
ended September 30, 2013, compared to the prior year period, primarily due to
the timing of our construction projects and turbine modernization program.
Also contributing to the decrease in outflows was $12 million of transmission
credits related to the construction of our Russell City Energy Center that
were purchased in the prior year period and did not recur this year.

Cash flows used in financing activities were $207 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.

In October 2013, we launched a tender offer to repay our $1.08 billion 7.25%
Senior Secured Notes due 2017 with proceeds from a concurrently launched $390
million 2020 Term Loan that bears interest at LIBOR + 3% and $750 million of
6% Senior Secured Notes due 2022. During the same month, we also issued $490
million of 5.875% Senior Secured Notes due 2024, the proceeds of which we
intend to use to redeem 10% of our remaining Senior Secured Notes. “These
refinancings continue to show Calpine’s focus on balance sheet management, and
the interest savings produced will directly contribute to the growth of our
Adjusted Free Cash Flow Per Share,” said Zamir Rauf, Calpine’s Chief Financial
Officer.

CAPITAL ALLOCATION

Share Repurchase Program

Having previously authorized $600 million in repurchases of our common stock,
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 the
aggregate $1.0 billion share repurchase program, we repurchased approximately
55.0 million shares of our outstanding common stock at an average price of
$18.18 per share. Under a new $100 million share repurchase authorization
approved by our Board of Directors in August 2013, we have repurchased
approximately 4.7 million shares of our common stock for approximately $92
million at an average price of $19.51 per share as of the filing of this
release. This brings our cumulative share repurchases to approximately $1.1
billion, representing approximately 59.7 million shares at an average price of
$18.28 per share. In November 2013, our Board of Directors approved an
additional $1.0 billion multi-year share repurchase authorization.

PLANT DEVELOPMENT

West:

Russell City Energy Center: Our Russell City Energy Center commenced
commercial operations in August 2013 and brought on-line approximately 429 MW
of net interest baseload capacity (464 MW with peaking capacity) representing
our 75% share. Russell City Energy Center is contracted to deliver its full
output to PG&E under a ten-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 modernization 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 has increased the efficiency and
environmental performance of the power plant by lowering the heat rate. Our
Los Esteros Critical Energy Facility commenced commercial operations as a
combined-cycle power plant in August 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 Environmental Protection Agency (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.

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 an
anticipated 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 first
quarter of 2014.

PJM Development Opportunities: We are currently evaluating development
opportunities in the PJM market area. Our 158 MW Deepwater power plant, which
is currently scheduled to be decommissioned, presents an opportunity to
leverage the existing infrastructure to add approximately 370 MW of new
combined-cycle capacity to our fleet. In addition, we are evaluating adding up
to 760 MW of additional capacity on the site where our York power plant is
located. These projects are continuing to advance entitlements (permits,
zoning, transmission, etc.) for their potential development at a future date.

All Segments:

Turbine Modernization: We continue to move forward with our turbine
modernization program. Through September 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

Third Quarter 2013 Power Operations Achievements:

  *Safety Performance:
    — Maintained top quartile^7 safety metrics: 0.85 Total Recordable Incident
    Rate year-to-date

  *Availability Performance:
    — Maintained impressive fleetwide forced outage factor: 1.4%
    — Delivered remarkable fleetwide starting reliability: 98.8%

  *Geothermal Generation:
    — Provided approximately 1.5 million MWh of renewable baseload generation
    during the quarter with a 0.7% forced outage factor

  *Natural Gas-fired Generation:
    — Osprey Energy Center: 100% starting reliability, 0% forced outage factor
    — Pastoria Energy Center: 92% capacity factor, 99.8% availability

Third Quarter 2013 Commercial Operations Achievements:

  *Customer-oriented Growth:
    — Successfully completed construction of our Russell City and Los Esteros
    power plants in California and began servicing related contracts with
    Pacific Gas and Electric
    — Entered into a 100 MW financial PPA with a counterparty in PJM that
    commences in November 2013 and extends through 2016
    — Entered into a new five-year PPA commencing in 2014 for approximately 50
    MW and extended existing steam agreement for ten years beyond 2016 with
    Celanese Ltd from our Clear Lake Power Plant

___________

^7 According to EEI Safety Survey (2012).

2013 & 2014 FINANCIAL OUTLOOK

(in millions, except per share amounts)

                                            Full Year 2013    Full Year 2014
Adjusted EBITDA                            $ 1,800 - 1,825    $ 1,800 - 1,900
Less:
Operating lease payments                     35                 35
Major maintenance expense and                390                380
maintenance capital expenditures^(1)
Cash interest, net^(2)                       700                675
Cash taxes                                   20                 20
Other                                       10               5        
Adjusted Free Cash Flow                    $ 645 - 670        $ 685 - 785
Per Share Estimate (diluted)               $ 1.50             $ 1.60 - 1.80
                                                                         
Growth capital expenditures (net of debt   $ 275              $ 200
funding)
Debt amortization                          $ 130              $ 200

________

^(1) Includes projected major maintenance expense of $230 million and $220
million and maintenance capital expenditures of $160 million and $160 million
in 2013 and 2014, respectively. 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 narrowing our 2013 guidance. We now project
Adjusted EBITDA of $1,800 million to $1,825 million and Adjusted Free Cash
Flow of $645 million to $670 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. In addition, we are updating our
expected investment for growth-related projects during the year to $275
million to reflect changes in timing of payments. Overall project cost
estimates remain unchanged.

Today, we are also initiating guidance for 2014. We expect Adjusted EBITDA of
$1,800 million to $1,900 million, Adjusted Free Cash Flow of $685 million to
$785 million and Adjusted Free Cash Flow Per Share of $1.60 to $1.80. We also
expect to invest $200 million in our ongoing growth-related projects during
the year, including the expected completion of our Deer Park and Channel
Energy Center expansions and ongoing construction of our Garrison Energy
Center.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results
for the third quarter of 2013 on Thursday, November 7,2013, at 10 a.m.
Eastern time / 9 a.m. Central time. 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
35497707. 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 35497707.
Presentation materials to accompany the conference call will be available on
our website on November 7, 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 28,000 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 September 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, regulations and market rules in the markets in which we participate
    and our ability to effectively respond to changes in laws, regulations or
    market rules or the interpretation thereof including those related to the
    environment, derivative transactions and market design in the regions in
    which we operate;
  *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          Nine Months Ended
                             September 30,               September 30,
                             2013           2012        2013       2012
                             (in millions, except share and per share amounts)
Operating revenues:
Commodity revenue            $  2,020        $ 1,689     $ 4,867     $ 4,078
Unrealized mark-to-market    26              304         (14     )   24
gain (loss)
Other revenue                4              3          10         9       
Operating revenues           2,050          1,996      4,863      4,111   
Operating expenses:
Fuel and purchased energy
expense:
Commodity expense            1,076           812         2,909       2,073
Unrealized mark-to-market    (17       )     85         (29     )   73      
(gain) loss
Fuel and purchased energy    1,059          897        2,880      2,146   
expense
Plant operating expense      200             207         684         699
Depreciation and             150             140         441         418
amortization expense
Sales, general and other     33              36          102         104
administrative expense
Other operating expenses     20             18         58         58      
Total operating expenses     1,462          1,298      4,165      3,425   
(Income) from
unconsolidated investments   (9        )     (7      )   (25     )   (21     )
in power plants
Income from operations       597             705         723         707
Interest expense             176             183         522         552
Loss on interest rate        —               —           —           14
derivatives
Interest (income)            (2        )     (2      )   (5      )   (7      )
Debt extinguishment costs    —               —           68          12
Other (income) expense,      7              6          15         14      
net
Income before income taxes   416             518         123         122
Income tax expense           110            81         12         23      
Net income                   306             437         111         99
Net income attributable to
the noncontrolling           —              —          —          —       
interest
Net income attributable to   $  306         $ 437      $ 111      $ 99    
Calpine
Basic earnings per common
share attributable to
Calpine:
Weighted average shares of
common stock outstanding     434,384        462,307    444,486    470,589 
(in thousands)
Net income per common
share attributable to        $  0.70        $ 0.95     $ 0.25     $ 0.21  
Calpine — basic
Diluted earnings per
common share attributable
to Calpine:
Weighted average shares of
common stock outstanding     438,493        465,953    448,546    474,131 
(in thousands)
Net income per common
share attributable to        $  0.70        $ 0.94     $ 0.25     $ 0.21  
Calpine — diluted
                                                                             

                                                         
CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)
                                                              
                                      September 30,           December 31,
                                      2013                    2012
                                      (in millions, except share and per share
                                      amounts)
ASSETS
Current assets:
Cash and cash equivalents             $     1,024             $   1,284
Accounts receivable, net of           657                     437
allowance of $1 and $6
Margin deposits and other prepaid     343                     244
expense
Restricted cash, current              185                     193
Derivative assets, current            471                     339
Inventory and other current assets    355                    335          
Total current assets                  3,035                   2,832
Property, plant and equipment, net    13,039                  13,005
Restricted cash, net of current       63                      60
portion
Investments in power plants           95                      81
Long-term derivative assets           148                     98
Other assets                          423                    473          
Total assets                          $     16,803           $   16,549   
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable                      $     451               $   382
Accrued interest payable              123                     180
Debt, current portion                 154                     115
Derivative liabilities, current       472                     357
Other current liabilities             284                    284          
Total current liabilities             1,484                   1,318
Debt, net of current portion          10,869                  10,635
Long-term derivative liabilities      333                     293
Other long-term liabilities           317                    247          
Total liabilities                     13,003                  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, 497,754,264 and 492,495,100   1                       1
shares issued, respectively, and
437,262,887 and 457,048,970 shares
outstanding, respectively
Treasury stock, at cost, 60,491,377   (1,069          )       (594         )
and 35,446,130 shares, respectively
Additional paid-in capital            12,380                  12,335
Accumulated deficit                   (7,389          )       (7,500       )
Accumulated other comprehensive       (184            )       (248         )
loss
Total Calpine stockholders’ equity    3,739                   3,994
Noncontrolling interest               61                     62           
Total stockholders’ equity            3,800                  4,056        
Total liabilities and stockholders’   $     16,803           $   16,549   
equity
                                                                           

                                             
CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)
                                               
                                               Nine Months Ended September 30,
                                               2013              2012
                                               (in millions)
Cash flows from operating activities:
Net income                                     $   111            $  99
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization expense^(1)      474                449
Debt extinguishment costs                      28                 —
Deferred income taxes                          18                 (7        )
Loss on disposition of assets                  5                  10
Unrealized mark-to-market activity, net        (14         )      (103      )
(Income) from unconsolidated investments in    (25         )      (21       )
power plants
Return on unconsolidated investments in        23                 20
power plants
Stock-based compensation expense               28                 19
Other                                          (2          )      1
Change in operating assets and liabilities:
Accounts receivable                            (219        )      96
Derivative instruments, net                    47                 (114      )
Other assets                                   (111        )      97
Accounts payable and accrued expenses          (11         )      (119      )
Settlement of non-hedging interest rate        —                  156
swaps
Other liabilities                              63                25        
Net cash provided by operating activities      415               608       
Cash flows from investing activities:
Purchases of property, plant and equipment     (472        )      (509      )
Settlement of non-hedging interest rate        —                  (156      )
swaps
Return of investment in unconsolidated         1                  5
investments in power plants
(Increase) decrease in restricted cash         5                  (32       )
Purchases of deferred transmission credits     —                  (12       )
Other                                          (2          )      3         
Net cash used in investing activities             (468    )        (701   )
Cash flows from financing activities:
Repayment under First Lien Term Loans              (19     )         (12    )
Borrowings from CCFC Term Loans                1,197              —
Repayments under CCFC Term Loans               (3          )      —
Repayment of CCFC Notes                        (1,000      )      —
Borrowings from project financing, notes       139                312
payable and other
Repayments of project financing, notes         (51         )      (53       )
payable and other
Financing costs                                (27         )      (6        )
Stock repurchases                              (462        )      (308      )
Proceeds from exercises of stock options       19                 4
Other                                          —                 1         
Net cash used in financing activities          (207        )      (62       )
Net decrease in cash and cash equivalents      (260        )      (155      )
Cash and cash equivalents, beginning of        1,284             1,252     
period
Cash and cash equivalents, end of period       $   1,024         $  1,097  
                                                                  
Cash paid during the period for:
Interest, net of amounts capitalized           $   547            $  565
Income taxes                                   $   22             $  14
                                                                  
Supplemental disclosure of non-cash
investing activities:
Change in capital expenditures included in     $   10             $  (3     )
accounts payable
Additions to property, plant and equipment     $   —              $  8
through assumption of long-term note payable

__________

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

REGULATION G RECONCILIATIONS

Net Income, 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, As Adjusted, represents net income 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, 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, As Adjusted, is
not intended to represent net income, 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 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, adjustments to exclude the
Adjusted EBITDA related to the noncontrolling interest, 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 and any extraordinary, unusual or
non-recurring items plus 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 September 30, 2013 and 2012 (in millions):

                Three Months Ended September 30, 2013
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 337     $ 328     $ 242     $  78       $    —          $ 985
Margin
Add:
Unrealized
mark-to-market   16        (5    )   (3    )   6           (8        )     6
commodity
activity, net
and other^(1)
Less:
Plant
operating        80        60        40        27          (7        )     200
expense
Depreciation
and              57        42        33        18          —               150
amortization
expense
Sales, general
and other        4         17        6         5           1               33
administrative
expense
Other
operating        11        2         9         1           (3        )     20
expenses
(Income) from
unconsolidated   —        —        (9    )   —          —              (9    )
investments in
power plants
Income from      $ 201    $ 202    $ 160    $  33      $    1         $ 597 
operations
                                                                                 

                Three Months Ended September 30, 2012
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 330     $ 218     $ 266     $  83       $    —          $ 897
Margin^(2)(3)
Add:
Unrealized
mark-to-market   (40   )   249       (26   )   27          (8        )     202
commodity
activity, net
and other^(1)
Less:
Plant
operating        88        49        51        29          (10       )     207
expense
Depreciation
and              52        35        33        21          (1        )     140
amortization
expense
Sales, general
and other        9         12        8         8           (1        )     36
administrative
expense
Other
operating        10        1         6         (1     )    2               18
expenses
(Income) from
unconsolidated   —        —        (7    )   —          —              (7    )
investments in
power plants
Income from      $ 131    $ 370    $ 149    $  53      $    2         $ 705 
operations
                                                                                 

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

                Nine Months Ended September 30, 2013
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 737     $ 537     $ 543     $  162      $    —          $ 1,979
Margin
Add:
Unrealized
mark-to-market   (2    )   18        (8    )   20          (24       )     4
commodity
activity, net
and other^(4)
Less:
Plant
operating        261       224       130       92          (23       )     684
expense
Depreciation
and              160       129       98        55          (1        )     441
amortization
expense
Sales, general
and other        11        55        18        17          1               102
administrative
expense
Other
operating        31        4         23        2           (2        )     58
expenses
(Income) from
unconsolidated   —        —        (25   )   —          —              (25     )
investments in
power plants
Income from      $ 272    $ 143    $ 291    $  16      $    1         $ 723   
operations
                                                                                   

                Nine Months Ended September 30, 2012
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 748     $ 472     $ 591     $  212      $    —          $ 2,023
Margin^(2)(3)
Add:
Unrealized
mark-to-market   (80   )   66        (17   )   (5      )   (22       )     (58     )
commodity
activity, net
and other^(4)
Less:
Plant
operating        281       189       154       98          (23       )     699
expense
Depreciation
and              151       104       100       66          (3        )     418
amortization
expense
Sales, general
and other        23        36        22        23          —               104
administrative
expense
Other
operating        30        4         21        2           1               58
expenses
(Income) from
unconsolidated   —        —        (21   )   —          —              (21     )
investments in
power plants
Income from      $ 183    $ 205    $ 298    $  18      $    3         $ 707   
operations

_________

^(1) Includes $44 million and $16 million of lease levelization and $4 million
and $4 million of amortization expense for the three months ended
September30, 2013 and 2012, respectively.

^(2) Our North segment includes Commodity Margin of $32 million and $64
million for the three and nine months ended September 30, 2012, related to
Riverside Energy Center, LLC, which was sold in December 2012.

^(3) Our Southeast segment includes Commodity Margin of $20 million and $44
million for the three and nine months ended September 30, 2012, related to
Broad River, which was sold in December 2012.

^(4) Includes $17 million and $7 million of lease levelization and $11 million
and $11 million of amortization expense for the nine months ended
September30, 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 income attributable to Calpine for the three and
nine months ended September 30, 2013 and 2012, as reported under U.S. GAAP.

                                  Three Months Ended     Nine Months Ended
                                   September 30,           September 30,
                                   2013       2012        2013       2012
                                                                       
Net income attributable to         $  306      $  437      $ 111       $ 99
Calpine
Income tax expense                 110         81          12          23
Debt extinguishment costs and      7           6           83          26
other (income) expense, net
Loss on interest rate              —           —           —           14
derivatives
Interest expense, net of           174        181        517        545
interest income
Income from operations             $  597      $  705      $ 723       $ 707
Add:
Adjustments to reconcile income
from operations to Adjusted
EBITDA:
Depreciation and amortization
expense, excluding deferred        149         140         441         419
financing costs^(1)
Major maintenance expense          33          31          182         158
Operating lease expense            9           9           26          26
Unrealized (gain) loss on
commodity derivative               (43     )   (219    )   (15     )   49
mark-to-market activity
Adjustments to reflect Adjusted
EBITDA from unconsolidated         —           7           13          23
investments and exclude the
noncontrolling interest^(2)
Stock-based compensation expense   8           6           28          19
Loss on dispositions of assets     1           5           5           9
Acquired contract amortization     4           4           11          11
Other                              44         18         17         13
Total Adjusted EBITDA              $  802     $  706     $ 1,431    $ 1,434
Less:
Operating lease payments           9           9           26          26
Major maintenance expense and      62          43          303         298
capital expenditures^(3)
Cash interest, net^(4)             173         190         528         571
Cash taxes                         1           (1      )   18          10
Other                              1          2          5          6
Adjusted Free Cash Flow^(5)        $  556     $  463     $ 551      $ 523
                                                                       
Weighted average shares of
common stock outstanding           438,493    465,953    448,546    474,131
(diluted, in thousands)
Adjusted Free Cash Flow Per        $  1.27    $  0.99    $ 1.23     $ 1.10
Share (diluted)

_________

^(1) Depreciation and amortization expense on our Consolidated Condensed
Statements of Operations excludes amortization of other assets.

^(2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments
include unrealized (gain) loss on mark-to-market activity of nil for each of
the three and nine months ended September30, 2013 and 2012.

^(3) Includes $34 million and $185 million in major maintenance expense for
the three and nine months ended September 30, 2013, respectively, and $28
million and $118 million in maintenance capital expenditures for the three and
nine months ended September 30, 2013, respectively. Includes $19 million and
$150 million in major maintenance expense for the three and nine months ended
September 30, 2012, respectively, and $24 million and $148 million in
maintenance capital expenditure for the three and nine months ended September
30, 2012, respectively.

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

^(5) Excludes an increase in working capital of $76 million and $380 million
for the three and nine months ended September 30, 2013, respectively, and an
increase in working capital of $4 million and a decrease in working capital of
$16 million for the three and nine months ended September 30, 2012,
respectively. 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 nine
months ended September 30, 2013 and 2012. Reconciliations for both Adjusted
EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided
above.

                      Three Months Ended        Nine Months Ended September
                       September 30,              30,
                       2013         2012         2013           2012
                                                  
Commodity Margin       $  985        $  897       $  1,979        $  2,023
Other revenue          3             3            9               9
Plant operating        (160    )     (167    )    (480      )     (518      )
expense^(1)
Sales, general and
administrative         (28     )     (34     )    (87       )     (94       )
expense^(2)
Other operating        (11     )     (9      )    (32       )     (30       )
expenses^(3)
Adjusted EBITDA from
unconsolidated         15            14           44              44
investments in power
plants^(4)
Other                  (2      )     2           (2        )     —         
Adjusted EBITDA        $  802       $  706      $  1,431       $  1,434  

_________

^(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)                                         $ 87      $ 112
Plus:
Debt extinguishment costs                                      68        68
Interest expense, net of interest income                       700       700
Depreciation and amortization expense                          615       615
Major maintenance expense                                      230       230
Operating lease expense                                        35        35
Other^(2)                                                      65       65
Adjusted EBITDA                                              $ 1,800   $ 1,825
Less:
Operating lease payments                                       35        35
Major maintenance expense and maintenance capital              390       390
expenditures^(3)
Cash interest, net^(4)                                         700       700
Cash taxes                                                     20        20
Other                                                          10       10
Adjusted Free Cash Flow                                      $ 645     $ 670

_________

^(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.

Full Year 2014 Range:                                          Low       High
                                                               (in millions)
GAAP Net Income ^(1)                                         $ 150     $ 250
Plus:
Interest expense, net of interest income                       695       695
Depreciation and amortization expense                          610       610
Major maintenance expense                                      215       215
Operating lease expense                                        35        35
Other^(2)                                                      95       95
Adjusted EBITDA                                              $ 1,800   $ 1,900
Less:
Operating lease payments                                       35        35
Major maintenance expense and maintenance capital              380       380
expenditures^(3)
Cash interest, net^(4)                                         675       675
Cash taxes                                                     20        20
Other                                                          5        5
Adjusted Free Cash Flow                                      $ 685     $ 785

_________

^(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 $220 million and
maintenance capital expenditures of $160 million. Capital expenditures exclude
major construction and development projects.

^(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      Nine Months Ended     
                             September 30,             September 30,
                             2013         2012        2013         2012
Total MWh generated (in      29,688        32,291      76,025        87,027
thousands)^(1)
West                         10,185        9,817       25,751        24,211
Texas                        9,924         10,025      25,224        28,257
Southeast                    4,597         5,821       12,092        17,744
North                        4,982         6,628       12,958        16,815
                                                                     
Average availability         97.6    %     97.7    %   92.0    %     91.5    %
West                         97.9    %     98.5    %   91.9    %     91.2    %
Texas                        97.8    %     97.2    %   89.5    %     90.4    %
Southeast                    97.4    %     98.3    %   95.6    %     94.4    %
North                        97.3    %     96.9    %   92.6    %     90.5    %
                                                                     
Average capacity factor,     55.7    %     61.0    %   49.0    %     55.7    %
excluding peakers^(1)
West                         68.5    %     70.7    %   61.1    %     58.7    %
Texas                        57.7    %     64.7    %   49.5    %     61.3    %
Southeast                    40.7    %     48.4    %   36.0    %     49.6    %
North                        50.0    %     56.1    %   45.4    %     49.7    %
                                                                     
Steam adjusted heat rate     7,414         7,404       7,402         7,357
(Btu/kWh)
West                         7,317         7,313       7,335         7,267
Texas                        7,226         7,211       7,193         7,149
Southeast                    7,388         7,325       7,364         7,302
North                        8,046         7,943       7,994         7,918

________

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

Contact:

Calpine Corporation
Media Relations:
Brett Kerr, 713-830-8809
brett.kerr@calpine.com
or
Investor Relations:
Bryan Kimzey, 713-830-8777
bryan.kimzey@calpine.com