Calpine Reports Strong Fourth Quarter and Full Year 2013 Results, Raises 2014 Guidance

  Calpine Reports Strong Fourth Quarter and Full Year 2013 Results, Raises
  2014 Guidance

Business Wire

HOUSTON -- February 13, 2014

Calpine Corporation (NYSE:CPN)

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

                                              
              Three Months Ended December 31,    Year Ended December 31,
              2013       2012       % Change   2013      2012      %
                                                                       Change
                                                                       
Operating     $ 1,438     $ 1,367     5.2    %   $ 6,301    $ 5,478    15.0  %
Revenues
Commodity     $ 589       $ 515       14.4   %   $ 2,568    $ 2,538    1.2   %
Margin
Adjusted      $ 399       $ 315       26.7   %   $ 1,830    $ 1,749    4.6   %
EBITDA
Adjusted
Free Cash     $ 126       $ 41        207.3  %   $ 677      $ 564      20.0  %
Flow
Per Share     $ 0.29      $ 0.09      222.2  %   $ 1.52     $ 1.20     26.7  %
(diluted)
Net Income    $ (97   )   $ 100                  $ 14       $ 199
(Loss)^1
Per Share     $ (0.23 )   $ 0.22                 $ 0.03     $ 0.42
(diluted)
Net Income
(Loss), As    $ 5         $ (86   )              $ 170      $ 78
Adjusted^2
                                                                       

Raising 2014 Full Year Guidance (in millions, except per share amounts):

                              2014 Prior Guidance   2014
                               (as of Nov. 7, 2013)   Current Guidance
                                                      
Adjusted EBITDA                $1,800 - 1,900         $1,900 - 2,000
Adjusted Free Cash Flow        $685 - 785             $785 - 885
Per Share Estimate (diluted)   $1.60 - 1.80           $1.85 - 2.10

Recent Achievements:

  *Operations:
    — Generated approximately 104 million MWh^3 of electricity in 2013
    — Achieved record-low annual fleetwide forced outage factor: 1.6%
    — Delivered impressive annual fleetwide starting reliability: 98.5%

  *Commercial:
    — Announced acquisition of Guadalupe Energy Center, a 1,050 MW
    combined-cycle power plant in Texas, for approximately $625 million, or
    $595/kW
    — Advanced construction of growth projects totaling approximately 700 MW
    in Texas and the Mid-Atlantic
    — Entered into new ten-year PPA with Sonoma Clean Power Authority to
    provide 10 MW of renewable power from our Geysers assets

  *Capital Management:
    — During the fourth quarter, completed cumulative $1.1 billion of
    previously announced share repurchase authorizations
    — Subsequently completed approximately $239 million of share repurchases
    under recently announced $1 billion multi-year authorization
    — During 2013, refinanced or repriced approximately $6 billion of our
    debt, achieving material interest savings and extending maturities

Calpine Corporation (NYSE: CPN) today reported fourth quarter 2013 Adjusted
EBITDA of $399 million, compared to $315 million in the prior year period, and
Adjusted Free Cash Flow of $126 million, or $0.29 per diluted share, compared
to $41 million, or $0.09 per diluted share, in the prior year period. Net
Loss^1 for the fourth quarter of 2013 was $97 million, or $0.23 per diluted
share, compared to Net Income^1 of $100 million, or $0.22 per diluted share,
in the prior year period. Net Income, As Adjusted^2, for the fourth quarter of
2013 was $5 million compared to a Net Loss, As Adjusted^2, of $86 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 portfolio changes, higher regulatory capacity payments
and new contracts.

Full year 2013 Adjusted EBITDA was $1,830 million, compared to $1,749 million
in the prior year period, and Adjusted Free Cash Flow was $677 million, or
$1.52 per diluted share, compared to $564 million, or $1.20 per diluted share,
in the prior year period. Net Income^1 for 2013 was $14 million, or $0.03 per
diluted share, compared to $199 million, or $0.42 per diluted share, in the
prior year period. Net Income, As Adjusted^2, for 2013 was $170 million
compared to $78 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 the same factors that drove favorable performance in the fourth
quarter, as well as lower interest expense due to a decrease in our annual
effective interest rate as a result of the refinancing activities of 2012 and
2013.

“We are proud to report that Calpine successfully delivered on its 2013
financial commitments, achieving $1.52 of Adjusted Free Cash Flow Per Share, a
year-over-year increase of approximately 27%,” said Jack Fusco, Calpine’s
Chief Executive Officer. “Calpine’s best-in-class fleet and dedicated
personnel provided the foundation for our solid performance. In 2013, we
achieved a record-low fleetwide forced outage factor and impressive starting
reliability, thanks in large part to our ongoing preventative maintenance
program. This fleet optimization enabled us to deliver on our customer
commitments and commercial obligations, while maintaining strict cost
management.

“Our strong financial results were also driven by opportunistic portfolio
management, customer-oriented origination, prudent risk management and
disciplined capital allocation. These factors, along with operational
excellence, are the hallmarks of a premier power generation company, and in
our view, will continue to drive sustainable growth for our shareholders over
the long term,” said Fusco. “Toward this end, we are raising our 2014 Adjusted
EBITDA guidance range by $100 million to $1.9 billion to $2.0 billion. This
results in an increase in our Adjusted Free Cash Flow Per Share guidance range
to $1.85 to $2.10, representing approximately 30% year-over-year growth based
on the midpoint. This revised guidance reflects our pending acquisition of the
1,050 MW Guadalupe CCGT in Texas, which we expect to close during the first
quarter, coupled with a good start to the year and the repurchase of
approximately 13 million shares since our last update.

“Finally, I would like to note that in the face of extreme cold weather during
the first six weeks of this year, our versatile Mid-Atlantic and Northeast
dual-fueled fleet performed exceptionally well, providing essential power to
the grid during times of scarcity and extreme price volatility,” said Fusco.
“This weather has highlighted the importance of flexible and reliable
generation as the power grid shifts away from old, uneconomic coal and nuclear
plants and becomes increasingly reliant upon intermittent renewable generation
and demand response. Grid operators continue to refine energy and capacity
markets in an effort to identify market-driven solutions that result in
nondiscriminatory investment signals for generating units with the right
characteristics to balance the grid of the future.”

__________

^1 Reported as Net Income (Loss) attributable to Calpine on our Consolidated
Statements of Operations.

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

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

SUMMARY OF FINANCIAL PERFORMANCE

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2013 was $399 million, compared to
$315 million in the prior year period. The year-over-year increase in Adjusted
EBITDA was primarily related to a $74 million increase in Commodity Margin,
which was primarily due to:

                our Russell City and Los Esteros power plants commencing
                commercial operations during the third quarter of 2013 and the
      +  acquisition of Bosque Energy Center in November 2012,
                partially offset by the sale of our Broad River and Riverside
                Energy Centers in December 2012
            +   higher regulatory capacity revenue in the North and
                higher revenue from contracts in our West and Southeast
            +   segments which became effective in January 2013, partially
                offset by
            –   lower contribution from hedges in our West and Texas segments.

Net Loss^1 was $97 million for the fourth quarter of 2013, compared to Net
Income^1 of $100 million in the prior year period. As detailed in Table 1, Net
Income, As Adjusted^2, was $5 million in the fourth quarter of 2013 compared
to a Net Loss^1, As Adjusted^2, of $86 million in the prior year period. The
year-over-year improvement was driven largely by:

      +  higher Commodity Margin, as previously discussed, and
                lower plant operating expense primarily due to a decrease in
            +   mainly production-related expenses and salaries and benefits,
                partially offset by
                higher depreciation and amortization expense due to the
            –   acquisition of Bosque Energy Center in November 2012 and the
                commencement of commercial operations at our Russell City and
                Los Esteros power plants in August 2013.

Adjusted Free Cash Flow was $126 million in the fourth quarter of 2013
compared to $41 million in the prior year period. Adjusted Free Cash Flow
increased during the period primarily due to an increase in Adjusted EBITDA,
as previously discussed.

Full Year Results

Adjusted EBITDA in 2013 was $1,830 million compared to $1,749 million in the
prior year period. The year-over-year increase was primarily due to a $47
million decrease in plant operating expense^4, driven by factors similar to
those discussed in the results for the fourth quarter, ^ and a $30 million
increase in Commodity Margin. The increase in Commodity Margin was primarily
due to:

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

Net Income^1 was $14 million in 2013 compared to $199 million in the prior
year period. As detailed in Table 1, Net Income, As Adjusted^2, was $170
million in 2013 compared to $78 million in the prior year period. The
favorable year-over-year improvement in Net Income, As Adjusted^2, reflects:

      +  lower interest expense due to a decrease in our annual
                effective interest rate
            +   higher Commodity Margin, as previously discussed
                lower income tax expense resulting primarily from the
            +   expiration of applicable statutes of limitation related to
                uncertain tax positions and
                lower plant operating expense, primarily due to a decrease in
                mainly production-related costs, salaries and benefits and the
            +   reversal of previously recognized regulatory fees for which we
                determined that we have no current or retroactive fee
                obligation as well as lower equipment failure costs, partially
                offset by
                higher depreciation and amortization expense due to the
            –   acquisition of Bosque Energy Center in November 2012 and the
                commencement of commercial operations at our Russell City and
                Los Esteros power plants in August 2013.

Adjusted Free Cash Flow was $677 million for 2013 compared to $564 million in
the prior year period. Adjusted Free Cash Flow increased during the period
primarily due to higher Adjusted EBITDA and lower interest expense, as
previously discussed.

^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 months and
years ended December 31, 2013 and 2012.

Table 1: Net Income (Loss), As Adjusted

                                                               
                         Three Months Ended December   Year Ended December 31,
                         31,
                         2013             2012         2013          2012
                         (in millions)                 (in millions)
Net income
attributable to          $   (97   )      $  100       $  14         $  199
Calpine
Debt extinguishment      76               18           144           30
costs^(1)
(Gain) on sale of        —                (222    )    —             (222    )
assets, net^(1)
Unrealized MtM
(gain)/loss on           26               31           12            (72     )
derivatives^(1)(2)
Other items ^ (1) (3)    —               (13     )    —            143     
Net Income (Loss), As    $   5           $  (86  )    $  170       $  78   
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 for the year ended December 31, 2012, include realized
mark-to-market losses associated with the settlement of non-hedged interest
rate swaps totaling $156 million. Other items for the three months and year
ended December 31, 2012, include a $13 million tax refund (including interest)
associated with our 2004 amended federal income tax return.

^(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 December 31,   Year Ended December 31,
            2013         2012      Variance   2013        2012        Variance
West        $  283       $ 246     $  37      $ 1,020     $ 994       $  26
Texas       95           98        (3     )   632         570         62
North       169          138       31         712         729         (17    )
Southeast   42          33       9         204        245        (41    )
Total       $  589      $ 515    $  74     $ 2,568    $ 2,538    $  30  
                                                                             

West Region

Fourth Quarter: Commodity Margin in our West segment increased by $37 million
in the fourth quarter of 2013 compared to the prior year period. Primary
drivers were:

                our contracted Russell City and Los Esteros power plants
      +  commencing commercial operations during the third quarter of
                2013
            +   higher revenue from a tolling contract that became effective
                in January 2013 and
                stronger market conditions resulting from lower hydroelectric
            +   generation, warmer weather and the impact of the January 1,
                2013, implementation of the AB 32 carbon market, partially
                offset by
            –   lower contribution from hedges.

Full Year: Commodity Margin in our West segment increased by $26 million in
2013 compared to the prior year period. Full year results were largely
impacted by the same factors that drove comparative performance for the fourth
quarter, as previously discussed.

Texas Region

Fourth Quarter: Commodity Margin in our Texas segment decreased by $3 million
in the fourth quarter of 2013 compared to the prior year period. Primary
drivers were:

      –  lower contribution from hedges, partially offset by
            +   the acquisition of Bosque Energy Center in November 2012 and
            +   higher spark spreads resulting from stronger market conditions
                due to comparatively colder weather.

Full Year: Commodity Margin in our Texas segment increased by $62 million in
2013 compared to the prior year period. Primary drivers were:

      +  higher contribution from hedges
            +   the acquisition of Bosque Energy Center in November 2012 and
                higher spark spreads during the fourth quarter of 2013
            +   resulting from stronger market conditions due to colder
                weather, partially offset by
                lower spark spreads resulting from weaker market conditions
            –   during the first nine months of 2013 compared to the
                corresponding prior year period.

North Region

Fourth Quarter: Excluding a $9 million decrease from the sale of our Riverside
Energy Center in December 2012, Commodity Margin in our North segment
increased by $40 million in the fourth quarter of 2013 compared to the prior
year period, primarily as a result of higher regulatory capacity revenues.

Full Year: Excluding a $73 million decrease from the sale of our Riverside
Energy Center in December 2012, Commodity Margin in our North segment
increased by $56 million in 2013 compared to the prior year period. Primary
drivers were:

      +  higher regulatory capacity revenues, partially offset by
                weaker market conditions driven by milder weather and a
            –   reversal of coal-to-gas switching due to higher natural gas
                prices.

Southeast Region

Fourth Quarter: Excluding an $8 million decrease from the sale of our Broad
River Energy Center in December 2012, Commodity Margin in our Southeast
segment increased by $17 million in the fourth quarter of 2013 compared to the
prior year period. Primary drivers were:

      +  higher revenue from a new contract that became effective in
                January 2013 and
            +   higher contribution from hedges.

Full Year: Excluding a $52 million decrease from the sale of our Broad River
Energy Center in December 2012, Commodity Margin in our Southeast segment
increased by $11 million in 2013, compared to the prior year period. Primary
drivers were:

      +  higher revenue from a new contract that became effective in
                January 2013 and
            +   higher contribution from hedges, 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.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

                                          
                                            December 31,  December 31,
                                            2013           2012
                                            (in millions)
Cash and cash equivalents, corporate^(1)    $  649         $    1,153
Cash and cash equivalents, non-corporate    292           131
Total cash and cash equivalents             941            1,284
Restricted cash                             272            253
Corporate Revolving Facility availability   758            757
CDHI letter of credit availability^(2)      7             —
Total current liquidity availability        $  1,978      $    2,294

__________

^(1) Includes $5 million and $11 million of margin deposits posted with us by
our counterparties at December31, 2013 and 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 December31, 2013, we had no outstanding
letters of credit issued in excess of $225 million under our CDHI letter of
credit facility that were collateralized by cash.

Liquidity was approximately $2 billion as of December 31, 2013. Cash and cash
equivalents declined during 2013 due largely to our deployment of capital,
including the repurchase of $623 million of our common stock, in addition to
the funding of construction payments related to our Russell City, Los Esteros
and Garrison Energy Centers and the expansion of our Deer Park and Channel
Energy Centers. These expenditures were partially offset by $549 million in
cash provided by operations earned during the year as well as $303 million in
net proceeds from borrowings.

Table 4: Cash Flow Activities

                                                               
                                                   December 31,   December 31,
                                                   2013           2012
                                                   (in millions)
Beginning cash and cash equivalents                $  1,284      $  1,252  
Net cash provided by (used in):
Operating activities                               549            653
Investing activities                               (593      )    (470      )
Financing activities                               (299      )    (151      )
Net increase (decrease) in cash and cash           (343      )    32        
equivalents
Ending cash and cash equivalents                   $  941        $  1,284  
                                                                            

Cash flows from operating activities in 2013 resulted in net inflows of $549
million compared to $653 million in 2012. The decrease in cash provided by
operating activities was primarily due to an increase in working capital
employed, largely as a result of higher net accounts receivable and accounts
payable balances due to increased revenues in December 2013. Also contributing
to the decrease were higher debt extinguishment costs in 2013 due to payments
associated with the redemption of our CCFC notes and a portion of certain
First Lien Notes. Partially offsetting the decrease were higher income from
operations (adjusted for non-cash items) and lower cash paid for interest due
to the refinancing activity of 2013.

Cash flows used in investing activities were $593 million in 2013 compared to
$470 million in 2012. The increase in outflows was primarily due to net
proceeds from asset sale and purchase activity in 2012 that did not recur in
2013, partially offset by $156 million in non-hedging interest rate swap
settlements in 2012 that did not recur this year.

Cash flows used in financing activities were $299 million and were primarily
related to the execution of our share repurchase program, partially offset by
net proceeds received from the refinancing activity of 2013 related to our
CCFC notes, First Lien Notes and First Lien Term Loans.

CAPITAL ALLOCATION

Share Repurchase Program

Having previously authorized $600 million in repurchases of our common stock,
our Board of Directors authorized the repurchase of an additional $400 million
in shares of our common stock in February 2013 and an additional $100 million
in August 2013. Under the aggregate $1.1 billion of authorizations, we
repurchased a total of 60,139,816 shares of our outstanding common stock at an
average price of $18.29 per share. In November 2013, our Board of Directors
authorized a new $1.0 billion multi-year share repurchase program, under which
we have repurchased a total of 12,459,919 shares of our common stock for
approximately $239 million at an average price of $19.15 per share as of the
date of this release.

PLANT DEVELOPMENT

West:

Russell City Energy Center: Our Russell City Energy Center commenced
commercial operations in August 2013, which 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 Pacific Gas and Electric Company (PG&E) under a
ten-year PPA.

Los Esteros Critical Energy Facility: During 2009, we and PG&E negotiated a
new ten-year 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 in August 2013.

Texas:

Channel and Deer Park Expansions: In the fourth quarter of 2012, we began
construction to expand the baseload capacity of our Deer Park and Channel
Energy Centers by approximately 260 MW^5 each. Each power plant features an
oversized steam turbine that, along with existing plant infrastructure, allows
us to add capacity and improve the power plant’s overall efficiency at a
meaningful discount to the market cost of building new capacity. We expect
commercial operations on the expansions of our Channel and Deer Park Energy
Centers to commence during the second quarter of 2014.

Guadalupe Energy Center: On December 2, 2013, we announced an agreement to
purchase a natural gas-fired, combined-cycle power plant with a nameplate
capacity of 1,050 MW located in Guadalupe County, Texas for approximately $625
million, which will increase capacity in our Texas segment. The purchase price
does not include $15 million in consideration for the rights we also acquired
to an advanced development opportunity for an approximately 400 MW
quick-start, natural gas-fired peaker, if market conditions warrant. We are
currently evaluating funding sources for the acquisition of this power plant
including, but not limited to, nonrecourse financing, corporate financing or
internally generated funds.

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 commercial
operations to commence during the second quarter of 2015. The project’s
capacity cleared PJM’s 2015/2016 and 2016/2017 base residual auctions. We are
currently evaluating funding sources for the construction of this project
including, but not limited to, nonrecourse financing, corporate financing or
internally generated funds. 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
for approximately 500 MW of new capacity established by the Minnesota Public
Utilities Commission (MPUC). The initial stage of the proceeding was managed
via a contested case hearing. On December 31, 2013, the Administrative Law
Judge (ALJ) in the contested case issued a non-binding recommendation to the
MPUC that the state should secure approximately 100 MW of distributed solar
resources at this time and defer procurement of new thermal resources. Xcel
Energy (Northern States Power) and the Minnesota Department of Commerce
subsequently filed exceptions to the ALJ decision and continue to advocate in
support of new, natural gas-fired generation resources. The MPUC will hold
deliberations and decide whether to accept, reject or modify the ALJ
recommendation in early 2014.

PJM Development Opportunities: We are currently evaluating opportunities to
develop more than 1,000 MW in the PJM market area that feature cost advantages
such as existing infrastructure and favorable transmission queue positions.
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 December 31, 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 turbine modernizations to add as much as 500 MW of
incremental capacity across the region at attractive prices. In addition, we
have begun a program to update our dual-fueled turbines at certain of our
power plants in our North segment. Our decision to invest in these
modernizations depends upon, among other things, further clarity on market
design reforms currently being considered.

___________

^5 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

2013 Power Operations Achievements

  *Safety Performance:
    — Maintained top quartile^6 safety metrics: 0.88 Total Recordable Incident
    Rate

  *Availability Performance:
    — Delivered record-low annual fleetwide forced outage factor: 1.6%
    — Achieved remarkable fleetwide starting reliability: 98.5%

  *Geothermal Generation:
    — Provided approximately 6 million MWh of renewable baseload generation
    for 13th consecutive year

  *Natural Gas-fired Generation:
    — Otay Mesa Energy Center: 100% starting reliability
    — Kennedy International Airport Power Plant: 100% starting reliability

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 PG&E
    — Entered into a new three-year PPA with South Carolina Electric and Gas
    Company to provide 200 MW of power generated by our Columbia Energy
    Center, commencing in January 2014
    — Entered into two new resource adequacy contracts with PG&E 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 the Marin Energy Authority consisting of
    a one-year contract to provide 3 MW of renewable power during 2014 and a
    ten-year contract to provide 10 MW of renewable power commencing in
    January 2017. The renewable power to be delivered under both contracts
    will be generated from our Geysers assets
    — Entered into a 100 MW financial PPA with a counterparty in PJM which
    commenced in November 2013 and extends through 2016
    — Entered into a new five-year PPA commencing in 2014 for approximately 50
    MW and extended the existing steam agreement for ten years beyond 2016
    with Celanese Ltd for power and steam generated from our Clear Lake Power
    Plant
    — Entered into a new ten-year PPA with the Sonoma Clean Power Authority to
    provide 10 MW of renewable power from our Geysers assets commencing in May
    2014. The capacity under contract will increase in increments each year,
    up to a maximum of 18 MW for years 2020 through 2023

___________

^6 According to EEI Safety Survey (2012).

2014 FINANCIAL OUTLOOK
(in millions, except per share amounts)

                                                            
                                                                Full Year 2014
Adjusted EBITDA                                               $ 1,900 - 2,000
Less:
Operating lease payments                                        35
Major maintenance expense and maintenance capital               380
expenditures^(1)
Cash interest, net^(2)                                          675
Cash taxes                                                      20
Other                                                          5        
Adjusted Free Cash Flow                                       $ 785 - 885
Per Share Estimate (diluted)                                  $ 1.85 - 2.10
                                                                
Debt amortization                                             $ (200     )
Growth capital expenditures (net of debt funding)             $ (200     )
Guadalupe Energy Center acquisition^(3)                       $ (640     )

________

^(1) Includes projected major maintenance expense of $220 million and
maintenance capital expenditures $160 million. Capital expenditures exclude
major construction and development projects.

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

^(3) Includes $15 million in consideration for the rights we also acquired to
an advanced development opportunity for an approximately 400 MW quick-start,
natural gas-fired peaker, if market conditions warrant, exclusive of
adjustments relating to working capital.

As detailed above, today we are raising our 2014 guidance. We now project
Adjusted EBITDA of $1,900 million to $2,000 million and Adjusted Free Cash
Flow of $785 million to $885 million. Similarly, we are raising our Adjusted
Free Cash Flow Per Share guidance to $1.85 to $2.10. We expect to invest $200
million (net of debt funding) 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. We also expect to invest $625 million^7 in the acquisition of
Guadalupe Energy Center, which is expected to close in the first quarter of
2014 and $15 million in consideration for the rights we will concurrently
acquire to an advanced development opportunity for an approximately 400 MW
quick-start, natural gas-fired peaker, if market conditions warrant. We are
currently evaluating funding sources for the acquisition including, but not
limited to, nonrecourse financings, corporate financing or internally
generated funds.

___________

^7 Exclusive of adjustments relating to working capital.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results
for the fourth quarter and full year of 2013 on Thursday, February 13,2014,
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 36388664. 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 36388664.
Presentation materials to accompany the conference call will be available on
our website on February 13,2014.

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 Annual Report on Form 10-K for the year ended December 31, 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;
  *Structural changes in the supply and demand of power, resulting from the
    development of new fuels or technologies and demand-side management tools;
  *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 2013 Form 10-K.

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

CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF OPERATIONS

                  (Unaudited)                                  
                   Three Months Ended December 31,   Year Ended December 31,
                   2013              2012           2013          2012
                   (in millions, except share and per share amounts)
Operating
revenues:
Commodity          $   1,507          $  1,339       $ 6,374       $ 5,417
revenue
Unrealized
mark-to-market     (72          )     24             (86       )   48
gain (loss)
Other revenue      3                 4             13           13        
Operating          1,438             1,367         6,301        5,478     
revenues
Operating
expenses:
Fuel and
purchased energy
expense:
Commodity          899                821            3,808         2,894
expense
Unrealized
mark-to-market     (43          )     57            (72       )   130       
(gain) loss
Fuel and
purchased energy   856               878           3,736        3,024     
expense
Plant operating    211                223            895           922
expense
Depreciation and
amortization       168                144            609           562
expense
Sales, general
and other          34                 36             136           140
administrative
expense
Other operating    23                20            81           78        
expenses
Total operating    1,292             1,301         5,457        4,726     
expenses
(Gain) on sale     —                  (222       )   —             (222      )
of assets, net
(Income) from
unconsolidated     (5           )     (7         )   (30       )   (28       )
investments in
power plants
Income from        151                295            874           1,002
operations
Interest expense   174                184            696           736
Loss on interest   —                  —              —             14
rate derivatives
Interest           (1           )     (4         )   (6        )   (11       )
(income)
Debt
extinguishment     76                 18             144           30
costs
Other (income)     5                 1             20           15        
expense, net
Income (loss)
before income      (103         )     96             20            218
taxes
Income tax
expense            (10          )     (4         )   2            19        
(benefit)
Net income         (93          )     100            18            199
(loss)
Net income
attributable to
the                (4           )     —             (4        )   —         
noncontrolling
interest
Net income
(loss)             $   (97      )     $  100        $ 14         $ 199     
attributable to
Calpine
Basic earnings
(loss) per
common share
attributable to
Calpine:
Weighted average
shares of common
stock                 429,331         459,304     440,666     467,752 
outstanding (in
thousands)
Net income
(loss) per
common share       $   (0.23    )    $  0.22       $ 0.03       $ 0.43    
attributable to
Calpine — basic
Diluted earnings
(loss) per
common share
attributable to
Calpine:
Weighted average
shares of common
stock                 429,331         463,291     444,773     471,343 
outstanding (in
thousands)
Net income
(loss) per
common share       $   (0.23    )     $  0.22       $ 0.03       $ 0.42    
attributable to
Calpine —
diluted
                                                                             
                                                                             

CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS

December 31, 2013 and 2012

(in millions, except share and per share amounts)
                                                                 
                                                       2013         2012
ASSETS
Current assets:
Cash and cash equivalents                              $ 941        $ 1,284
Accounts receivable, net of allowance of $5 and $6     552          437
Margin deposits and other prepaid expense              309          244
Restricted cash, current                               203          193
Derivative assets, current                             445          339
Inventory and other current assets                     406         335      
Total current assets                                   2,856        2,832
Property, plant and equipment, net                     12,995       13,005
Restricted cash, net of current portion                69           60
Investments in power plants                            93           81
Long-term derivative assets                            105          98
Other assets                                           441         473      
Total assets                                           $ 16,559    $ 16,549 
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable                                       $ 462        $ 382
Accrued interest payable                               162          180
Debt, current portion                                  204          115
Derivative liabilities, current                        451          357
Income taxes payable                                   7            11
Other current liabilities                              245         273      
Total current liabilities                              1,531        1,318
Debt, net of current portion                           10,908       10,635
Long-term derivative liabilities                       243          293
Other long-term liabilities                            309         247      
Total liabilities                                      12,991       12,493
                                                                    
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value per share;
authorized 100,000,000 shares, none issued and         —            —
outstanding at December 31, 2013 and 2012
Common stock, $0.001 par value per share; authorized
1,400,000,000 shares, 497,841,056 shares issued and
429,038,988 shares outstanding at December 31, 2013,   1            1
and 492,495,100 shares issued and 457,048,970 shares
outstanding at December 31, 2012
Treasury stock, at cost, 68,802,068 and 35,446,130     (1,230   )   (594     )
shares, respectively
Additional paid-in capital                             12,389       12,335
Accumulated deficit                                    (7,486   )   (7,500   )
Accumulated other comprehensive loss                   (160     )   (228     )
Total Calpine stockholders’ equity                     3,514        4,014
Noncontrolling interest                                54          42       
Total stockholders’ equity                             3,568       4,056    
Total liabilities and stockholders’ equity             $ 16,559    $ 16,549 
                                                                             
                                                                             

CALPINE CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2013 and 2012

(in millions)

                                                         2013      2012
Cash flows from operating activities:
Net income                                                $ 18       $ 199
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization expense^(1)                 654        605
Debt extinguishment costs                                 43         —
Deferred income taxes                                     14         1
(Gain) loss on sale of power plants and other, net        4          (212    )
Unrealized mark-to-market activity, net                   12         (72     )
(Income) from unconsolidated investments in power         (30    )   (28     )
plants
Return on unconsolidated investments in power plants      25         24
Stock-based compensation expense                          36         25
Other                                                     (3     )   1
Change in operating assets and liabilities, net of
effects of acquisitions:
Accounts receivable                                       (113   )   159
Derivative instruments, net                               (7     )   (52     )
Other assets                                              (148   )   (57     )
Accounts payable and accrued expenses                     (1     )   (86     )
Settlement of non-hedging interest rate swaps             —          156
Other liabilities                                         45        (10     )
Net cash provided by operating activities                 549       653     
Cash flows from investing activities:
Purchases of property, plant and equipment                (575   )   (637    )
Proceeds from sale of power plants, interests and other   1          825
Purchase of Bosque Energy Center, net of cash             —          (432    )
Return of investment from unconsolidated investments in   2          5
power plants
Settlement of non-hedging interest rate swaps             —          (156    )
(Increase) in restricted cash                             (18    )   (59     )
Purchases of deferred transmission credits                —          (12     )
Other                                                     (3     )   (4      )
Net cash used in investing activities                      (593 )    (470  )
Cash flows from financing activities:
Borrowings under First Lien Term Loans                    390        835
Repayments of First Lien Term Loans                       (25    )   (19     )
Borrowings from CCFC Term Loans                           1,197      —
Repayments under CCFC Term Loans                          (6     )   —
Repayment of CCFC Notes                                   (1,000 )   —
Borrowings under First Lien Notes                         1,234      —
Repayments of First Lien Notes                            (1,550 )   (590    )
Borrowings from project financing, notes payable and      182        389
other
Repayments of project financing, notes payable and        (66    )   (289    )
other
Financing costs                                           (53    )   (20     )
Stock repurchases                                         (623   )   (463    )
Proceeds from exercises of stock options                  20         5
Other                                                     1         1       
Net cash used in financing activities                     (299   )   (151    )
Net increase (decrease) in cash and cash equivalents      (343   )   32
Cash and cash equivalents, beginning of period            1,284     1,252   
Cash and cash equivalents, end of period                  $ 941     $ 1,284 
                                                                     
Cash paid during the period for:
Interest, net of amounts capitalized                      $ 672      $ 719
Income taxes                                              $ 24       $ 16
                                                                     
Supplemental disclosure of non-cash investing
activities:
Change in capital expenditures included in accounts       $ 27       $ 19
payable
Other non-cash additions to property, plant and           $ —        $ 13
equipment

__________

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

REGULATION G RECONCILIATIONS

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

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

Commodity Margin includes our power and steam revenues, sales of purchased
power and physical natural gas, capacity revenue, revenue from renewable
energy credits, sales of surplus emission allowances, transmission revenue and
expenses, fuel and purchased energy expense, fuel transportation expense,
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, non-cash
GAAP-related adjustments to levelize revenues from tolling contracts, 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.

During the fourth quarter of 2013, we changed the methodology previously used
during 2013 for allocating corporate expenses to our segments. This change had
no impact to our Consolidated Statements of Operations for any period in 2013;
however, amounts previously reported for income (loss) from operations by
segment for the first three quarterly periods in 2013 were impacted by
immaterial amounts.

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 December 31, 2013 and 2012 (in millions):

               
                 
                 Three Months Ended December 31, 2013
                                                      Consolidation 
                                                          And
                 West      Texas    North     Southeast   Elimination     Total
Commodity        $ 283     $ 95     $ 169     $  42       $    —          $ 589
Margin
Add:
Unrealized
mark-to-market   (48   )   33       13        2           (7        )     (7    )
commodity
activity, net
and other^(1)
Less:
Plant
operating        94        55       43        28          (9        )     211
expense
Depreciation
and              79        40       32        18          (1        )     168
amortization
expense
Sales, general
and other        13        13       4         4           —               34
administrative
expense
Other
operating        12        (1   )   7         1           4               23
expenses
(Income) from
unconsolidated   —        —       (5    )   —          —              (5    )
investments in
power plants
Income (loss)
from             $ 37     $ 21    $ 101    $  (7   )   $    (1   )     $ 151 
operations
                                                                                
                                                                                
                 Three Months Ended December 31, 2012
                                                          Consolidation
                                                          And
                 West      Texas    North     Southeast   Elimination     Total
Commodity        $ 246     $ 98     $ 138     $  33       $    —          $ 515
Margin^(2)(3)
Add:
Unrealized
mark-to-market   (13   )   21       3         (28     )   (9        )     (26   )
commodity
activity, net
and other^(1)
Less:
Plant
operating        87        58       52        33          (7        )     223
expense
Depreciation
and              52        38       34        19          1               144
amortization
expense
Sales, general
and other        13        11       6         6           —               36
administrative
expense
Other
operating        12        1        8         3           (4        )     20
expenses
(Gain) on sale   —         —        (7    )   (215    )   —               (222  )
of assets, net
(Income) from
unconsolidated   —        —       (7    )   —          —              (7    )
investments in
power plants
Income from      $ 69     $ 11    $ 55     $  159     $    1         $ 295 
operations
                                                                                
                                                                                

The following table reconciles our Commodity Margin to its U.S. GAAP results
for the years ended December 31, 2013 and 2012 (in millions):

               
                 
                 Year Ended December 31, 2013
                                                          Consolidation 
                                                              And
                 West        Texas      North     Southeast   Elimination     Total
Commodity        $ 1,020     $ 632      $ 712     $  204      $    —          $ 2,568
Margin
Add:
Unrealized
mark-to-market   (50     )   51         5         22          (31       )     (3      )
commodity
activity, net
and other^(4)
Less:
Plant
operating        365         269        172       120         (31       )     895
expense
Depreciation
and              243         165        130       73          (2        )     609
amortization
expense
Sales, general
and other        37          56         21        21          1               136
administrative
expense
Other
operating        45          3          29        4           —               81
expenses
(Income) from
unconsolidated   —          —         (30   )   —          —              (30     )
investments in
power plants
Income from      $ 280      $ 190     $ 395    $  8       $    1         $ 874   
operations
                                                                                      
                                                                                      
                 Year Ended December 31, 2012
                                                              Consolidation
                                                              And
                 West        Texas      North     Southeast   Elimination     Total
Commodity        $ 994       $ 570      $ 729     $  245      $    —          $ 2,538
Margin^(2)(3)
Add:
Unrealized
mark-to-market   (93     )   87         (14   )   (33     )   (31       )     (84     )
commodity
activity, net
and other^(4)
Less:
Plant
operating        368         247        206       131         (30       )     922
expense
Depreciation
and              203         142        134       85          (2        )     562
amortization
expense
Sales, general
and other        36          47         28        29          —               140
administrative
expense
Other
operating        42          5          29        5           (3        )     78
expenses
(Gain) on sale   —           —          (7    )   (215    )   —               (222    )
of assets, net
(Income) from
unconsolidated   —          —         (28   )   —          —              (28     )
investments in
power plants
Income from      $ 252      $ 216     $ 353    $  177     $    4         $ 1,002 
operations

_________

^(1) Includes $(11) million and $(6) million of lease levelization and $3
million and $3 million of amortization expense for the three months ended
December31, 2013 and 2012, respectively.

^(2) Our North segment includes Commodity Margin of $9 million and $73 million
for the three months and year ended December 31, 2012, related to Riverside
Energy Center, LLC, which was sold in December 2012.

^(3) Our Southeast segment includes Commodity Margin of $8 million and $52
million for the three months and year ended December 31, 2012, related to
Broad River, which was sold in December 2012.

^(4) Includes $6 million and $1 million of lease levelization and $14 million
and $14 million of amortization expense for the years ended December31, 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 (loss) attributable to Calpine for the three
months and years ended December 31, 2013 and 2012, as reported under U.S.
GAAP.

                                                    
                                                       
                               Three Months Ended      Year Ended December 31,
                               December 31,
                               2013       2012        2013         2012
                                                                     
Net income (loss)              $  (97  )   $  100      $  14         $ 199
attributable to Calpine
Net income attributable to     4           —           4             —
the noncontrolling interest
Income tax expense             (10     )   (4      )   2             19
Debt extinguishment costs
and other (income) expense,    81          19          164           45
net
Loss on interest rate          —           —           —             14
derivatives
Interest expense, net of       173        180        690          725     
interest income
Income from operations         $  151      $  295      $  874        $ 1,002
Add:
Adjustments to reconcile
income from operations to
Adjusted EBITDA:
Depreciation and
amortization expense,          168         145         609           564
excluding deferred financing
costs^(1)
Major maintenance expense      42          42          224           200
Operating lease expense        9           8           35            34
Unrealized (gain) loss on
commodity derivative           29          33          14            82
mark-to-market activity
(Gain) on sale of assets,      —           (222    )   —             (222    )
net
Adjustments to reflect
Adjusted EBITDA from
unconsolidated investments     1           8           14            31
and exclude the
noncontrolling interest^(2)
Stock-based compensation       8           6           36            25
expense
(Gain) loss on dispositions    (1      )   3           4             12
of assets
Acquired contract              3           3           14            14
amortization
Other                          (11     )   (6      )   6            7       
Total Adjusted EBITDA          $  399     $  315     $  1,830     $ 1,749 
Less:
Operating lease payments       8           8           34            34
Major maintenance expense      89          77          392           375
and capital expenditures^(3)
Cash interest, net^(4)         172         186         700           757
Cash taxes                     1           1           19            11
Other                          3          2          8            8       
Adjusted Free Cash Flow^(5)    $  126     $  41      $  677       $ 564   
                                                                     
Weighted average shares of
common stock outstanding       429,331    463,291    444,773      471,343 
(diluted, in thousands)
Adjusted Free Cash Flow Per    $  0.29    $  0.09    $  1.52      $ 1.20  
Share (diluted)

_________

^(1) Depreciation and amortization expense on our Consolidated 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 twelve months ended December 31, 2013 and 2012.

^(3) Includes $43 million and $228 million in major maintenance expense for
the three months and year ended December 31, 2013, respectively, and $46
million and $164 million in maintenance capital expenditure for the three
months and year ended December 31, 2013, respectively. Includes $42 million
and $192 million in major maintenance expense for the three months and year
ended December 31, 2012, respectively, and $35 million and $183 million in
maintenance capital expenditure for the three months and year ended December
31, 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 a decrease in working capital of $250 million and an increase in
working capital of $130 million for the three months and year ended December
31, 2013, respectively, and a decrease in working capital of $91 million and
$107 million for the three months and year ended December 31, 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 months
and year end December 31, 2013 and 2012. Reconciliations for both Adjusted
EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided
above.

                                                    
                                                       
                         Three Months Ended December   Year Ended December 31,
                         31,
                         2013            2012         2013         2012
                         (in millions)                 (in millions)
Commodity Margin         $   589          $  515       $  2,568      $ 2,538
Other revenue            3                3            12            12
Plant operating          (165      )      (174    )    (645      )   (692    )
expense^(1)
Sales, general and
administrative           (30       )      (33     )    (117      )   (127    )
expense^(2)
Other operating          (10       )      (11     )    (42       )   (41     )
expenses^(3)
Adjusted EBITDA from
unconsolidated           14               14           58            58
investments in power
plants^(4)
Other                    (2        )      1           (4        )   1       
Adjusted EBITDA          $   399         $  315      $  1,830     $ 1,749 

_________

^(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 2014 Range:                                          Low       High
                                                               (in millions)
GAAP Net Income ^(1)                                         $ 270     $ 370
Plus:
Interest expense, net of interest income                       675       675
Depreciation and amortization expense                          610       610
Major maintenance expense                                      215       215
Operating lease expense                                        35        35
Other^(2)                                                      95       95
Adjusted EBITDA                                              $ 1,900   $ 2,000
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                                      $ 785     $ 885

_________

^(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 December  Year Ended December 31,
                         31,
                         2013            2012         2013         2012
Total MWh generated      25,585           25,189       101,610       112,216
(in thousands)^(1)
West                     10,359           9,179        36,110        33,390
Texas                    8,119            7,689        33,343        35,946
Southeast                3,248            3,404        15,340        21,148
North                    3,859            4,917        16,817        21,732
                                                                     
Average availability     91.2     %       90.9    %    91.7     %    91.3    %
West                     92.9     %       93.9    %    92.2     %    91.9    %
Texas                    90.6     %       93.1    %    89.8     %    91.1    %
Southeast                93.2     %       90.6    %    95.0     %    93.4    %
North                    88.2     %       86.0    %    91.5     %    89.3    %
                                                                     
Average capacity
factor, excluding        48.0     %       48.0    %    48.7     %    53.7    %
peakers^(1)
West                     66.7     %       66.2    %    62.6     %    60.6    %
Texas                    47.2     %       46.6    %    48.9     %    57.4    %
Southeast                28.7     %       29.5    %    34.2     %    44.6    %
North                    41.5     %       46.2    %    44.4     %    48.8    %
                                                                     
Steam adjusted heat      7,339            7,378        7,386         7,361
rate (Btu/kWh)
West                     7,241            7,306        7,308         7,278
Texas                    7,214            7,139        7,198         7,147
Southeast                7,314            7,345        7,353         7,309
North                    7,864            7,900        7,963         7,914

________

^(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
 
Press spacebar to pause and continue. Press esc to stop.