Calpine Reports First Quarter 2013 Results, Reaffirms 2013 Guidance

  Calpine Reports First Quarter 2013 Results, Reaffirms 2013 Guidance

Business Wire

HOUSTON -- May 02, 2013

Calpine Corporation (NYSE: CPN):

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

                         Three Months Ended March 31,
                          2013       2012       % Change
                                                  
Operating Revenues        $ 1,241     $ 1,236     0.4   %
Commodity Margin          $ 461       $ 517       (10.8 )%
Adjusted EBITDA           $ 286       $ 325       (12.0 )%
Adjusted Free Cash Flow   $ (43   )   $ (27   )
Per Share (diluted)       $ (0.10 )   $ (0.06 )
Net Loss^1                $ (125  )   $ (9    )
Per Share (diluted)       $ (0.28 )   $ (0.02 )
Net Loss, As Adjusted^2   $ (70   )   $ (65   )
                                                  

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

                              2013
                               
Adjusted EBITDA                $1,800 - 1,960
Adjusted Free Cash Flow        $615 - 775
Per Share Estimate (diluted)   $1.50
                               

Recent Achievements:

  *Operations:
    — Generated approximately 25 million MWh^3 of electricity in the first
    quarter of 2013
    — Delivered exceptionally low fleetwide forced outage factor: 1.5%
    — Maintained remarkable first quarter fleetwide starting reliability: 98%

  *Capital Management:
    — Commenced construction on the first phase of Garrison Energy Center in
    April 2013
    — Launched refinancing of our CCFC notes to extend maturity and capture
    material interest savings
    — Repurchased approximately $58 million of our common stock under current
    $400 million authorization, bringing the cumulative total to $658 million
    of our $1 billion total authorized program

  *Regulatory:
    — Maintained active advocacy efforts at state and federal levels

Calpine Corporation (NYSE: CPN) today reported first quarter 2013 Adjusted
EBITDA of $286 million, compared to $325 million in the prior year period, and
Adjusted Free Cash Flow of $(43) million, or $(0.10) per diluted share,
compared to $(27) million, or $(0.06) per diluted share, in the prior year
period. Net Loss^1 for the first quarter was $125 million, or $0.28 per
diluted share, compared to a Net Loss^1 of $9 million, or $0.02 per diluted
share, in the prior year period. Net Loss, As Adjusted^2, for the first
quarter of 2013 was $70 million compared to $65 million in the prior year
period. The declines in first quarter Adjusted EBITDA, Adjusted Free Cash Flow
and Net Loss, As Adjusted^2 in the first quarter of 2013 compared to 2012 were
consistent with previous disclosures and were driven primarily by lower
Commodity Margin, largely as a result of changes in our portfolio, a move
towards seasonal hedging in 2013 compared to annual hedging in 2012 and lower
generation due to the reversal of coal-to-gas switching that occurred during
the first quarter of 2012.

“Our first quarter results were in line with our expectations, driven by a
meaningful increase in the price of natural gas that put gas-fired plants back
on the margin in Texas and the Southeast,” said Jack Fusco, Calpine’s Chief
Executive Officer. “It is worth noting that the quarterly distribution of our
2013 Adjusted EBITDA performance will be different than in past years due to
previously announced portfolio changes. Late last year, we sold two non-core
contracted plants and bought a merchant plant in Texas; this summer, we will
place in service two new contracted plants in California. As a result of these
portfolio changes, when combined with a more summer-weighted hedge profile and
expected increases in regulatory capacity payments later this year, we expect
that a higher proportion of our Adjusted EBITDA will be realized in the second
half of 2013. Therefore, we reaffirm our 2013 full-year guidance ranges for
Adjusted EBITDA and Adjusted Free Cash Flow of $1,800 million to $1,960
million and $615 million to $775 million, respectively, and our Adjusted Free
Cash Flow Per Share estimate of $1.50.”

SUMMARY OF FINANCIAL PERFORMANCE

First Quarter Results

Adjusted EBITDA for the first quarter of 2013 was $286 million, compared to
$325 million in the prior year period. The year-over-year decrease in Adjusted
EBITDA was primarily due to a $56 million decrease in Commodity Margin,
partially offset by a $16 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,
      –  partially offset by the acquisition of Bosque Energy Center in
                the fourth quarter of 2012
                lower spark spreads and generation output resulting from a
            –   reversal of coal-to-gas switching primarily in our Texas,
                North and Southeast segments and
                lower contribution from hedges due to a shift from the use of
            –   annual hedges in 2012 to more seasonal hedges in 2013,
                primarily in our Texas segment, partially offset by
            +   higher revenue from tolling contracts in our West and
                Southeast segments.

The decrease in plant operating expense^4 was primarily due to the reversal of
retroactive regulatory fees for which we determined the likelihood of payment
was not probable based on the actions of regulatory officials.

Net Loss^1 was $125 million for the first quarter of 2013, compared to a Net
Loss^1 of $9 million in the prior year period. As detailed in Table 1, Net
Loss, As Adjusted^2, was $70 million in the first quarter of 2013 compared to
$65 million in the prior year period. The year-over-year decline was driven
largely by:

      –  lower Commodity Margin, as previously discussed, partially
                offset by
            +   higher income tax benefit primarily related to a decrease in
                various state and foreign jurisdiction income taxes.

___________

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

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

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

^4 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
ended March 31, 2013 and 2012.

                                                
Table 1: Net Loss, As Adjusted
                                                  
                                                  Three Months Ended March 31,
                                                  2013             2012
                                                  (in millions)
Net loss attributable to Calpine                  $   (125   )      $  (9   )
Debt extinguishment costs^(1)                     —                 12
Unrealized MtM (gain) loss on derivatives^(1)     55                (224    )
(2)
Other items ^ (1) (3)                             —                156     
Net Loss, As Adjusted^(4)                         $   (70    )      $  (65  )

__________

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

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

^(3) Other items include realized mark-to-market losses associated with the
settlement of non-hedged interest rate swaps totaling nil and $156 million for
the three months ended March 31, 2013 and 2012, respectively.

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

           
REGIONAL SEGMENT REVIEW OF RESULTS


Table 2: Commodity Margin by Segment (in millions)
              
              Three Months Ended March 31,
              2013         2012         Variance
West          $  202        $  208        $  (6  )
Texas         76            109           (33    )
North         142           144           (2     )
Southeast     41           56           (15    )
Total         $  461       $  517       $  (56 )
                                                 

West Region

First Quarter: Commodity Margin in our West segment decreased by $6 million in
the first quarter of 2013 compared to the prior year period. Primary drivers
were:

      –  lower contribution from hedges, partially offset by
            +   higher revenue from a tolling contract and
            +   higher spark spreads on our open position driven by improved
                market conditions.

Texas Region

First Quarter: Commodity Margin in our Texas segment decreased by $33 million
in the first quarter of 2013 compared to the prior year period. Primary
drivers were:

      –  lower spark spreads and lower generation output resulting from
                a reversal of coal-to-gas switching and
            –   lower contribution from hedges primarily due to a shift from
                annual to seasonal hedging activity, partially offset by
            +   the acquisition of Bosque Energy Center in November 2012.

North Region

First Quarter: Commodity Margin in our North segment was comparable in the
first quarter of 2013 to the prior year period. Primary drivers were:

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

Southeast Region

First Quarter: Commodity Margin in our Southeast segment decreased by $15
million in the first quarter of 2013 compared to the prior year period.
Primary drivers were:

      –  the sale of Broad River Energy Center in December 2012 and
            –   lower spark spreads and lower generation output resulting from
                a reversal of coal-to-gas switching, partially offset by
            +   a new tolling contract effective in January 2013 and
            +   higher contribution from hedges.

                                          
LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity
                                            
                                            March 31,  December 31,
                                            2013              2012
                                            (in millions)
Cash and cash equivalents, corporate^(1)    $   786           $    1,153
Cash and cash equivalents, non-corporate    176              131
Total cash and cash equivalents             962               1,284
Restricted cash                             199               253
Corporate Revolving Facility availability   778               757
Letter of credit availability^(2)           —                —
Total current liquidity availability        $   1,939        $    2,294

__________

^(1) Includes $1 million and $11 million of margin deposits posted with us by
our counterparties at March31, 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 March31, 2013, we had $25 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 remained strong at approximately $1.9 billion as of March 31, 2013.

Cash flows from operating activities in the first quarter of 2013 resulted in
net outflows of $157 million compared to net inflows of $71 million in the
first quarter of 2012. The difference was primarily due to an increase in
working capital employed resulting from increased margin requirements
associated with higher commodity prices. In addition, a decrease in income
from operations, adjusted for non-cash items, further contributed to the
period-over-period decline. These decreases in cash flows from operating
activities were partially offset by less cash paid for interest due to the
refinancing activities during the fourth quarter of 2012 and first quarter of
2013, as well as lower debt extinguishment costs, which were incurred in the
first quarter of 2012 and did not recur in the first quarter of 2013.

Cash flows used in investing activities were $122 million in the first quarter
of 2013 compared to $314 million in the prior year period. The decrease was
driven largely by the termination of legacy interest rate swaps in the prior
year period that did not occur in the first quarter of 2013, as well as a
larger decrease in restricted cash in 2013 as compared to 2012, primarily due
to a release of cash collateral related to lower exposure on letter of credit
facilities and reduced major maintenance reserve requirements resulting from
our plant outage schedule.

Cash flows used in financing activities were $43 million in the first quarter
of 2013, largely driven by share repurchases and repayments on project debt,
partially offset by the receipt of proceeds from project debt related to our
Russell City and Los Esteros construction projects.

Adjusted Free Cash Flow was $(43) million for the first quarter of 2013
compared to $(27) million for the prior year period. Adjusted Free Cash Flow
decreased during the period primarily due to the decrease in Adjusted EBITDA,
as previously discussed. Partially offsetting this decline were lower interest
expense associated with a decrease in our annual effective interest rate on
consolidated debt and lower major maintenance capital expenditures related to
our plant outage schedule.

Consistent with our focus on delivering Adjusted Free Cash Flow Per Share
growth, on April 22, 2013, we announced that CCFC, our indirect, wholly owned
subsidiary, is pursuing a potential debt refinancing whereby CCFC will enter
into a new senior secured term loan and the funds will be used to repay the
CCFC Notes. The timing, size and terms of any potential refinancing and the
use of proceeds thereof are subject to market and other conditions and we make
no assurance that such actions will take place.

CAPITAL ALLOCATION

Share Repurchase Program

In February 2013, our Board of Directors authorized the repurchase of an
additional $400 million in shares of our common stock, bringing the cumulative
authorization total to $1 billion. As of the date of this release, we have
repurchased a total of approximately 3 million shares of our outstanding
common stock under the additional $400 million authorization for approximately
$58 million at an average price paid of $18.97 per share.

PLANT DEVELOPMENT

West:

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

Los Esteros Critical Energy Facility: During 2009, we and PG&E negotiated a
new PPA to replace the existing California Department of Water Resources
contract and facilitate the upgrade of our Los Esteros Critical Energy
Facility from a 188 MW simple-cycle generation power plant to a 309 MW
combined-cycle generation power plant, which will also increase the efficiency
and environmental performance of the power plant by lowering the heat rate.
Construction is ongoing and COD is expected in the third quarter of 2013.

Texas:

Channel and Deer Park Expansions: In September and November 2011, we filed air
permit applications with the Texas Commission on Environmental Quality (TCEQ)
and the EPA to expand the baseload capacity of our Deer Park and Channel
Energy Centers by approximately 260 MW^5 each. We received air permit
approvals from the TCEQ for our Deer Park and Channel expansion projects in
September and October 2012, respectively, and from the EPA in November 2012.
Construction on these expansion projects commenced in the fourth quarter of
2012. We expect COD during the second quarter of 2014 for these expansions and
are currently evaluating funding sources including, but not limited to,
nonrecourse financing, corporate financing or internally generated funds.

North:

Garrison Energy Center: We continue to advance the development of as much as
618 MW of combined-cycle capacity in Delaware at a site secured by a long-term
lease with the City of Dover.We are pursuing the development of this project
in two separate phases.The capacity from the first phase (309 MW) cleared
PJM’s 2015/2016 base residual auction. Construction on the first phase
commenced in April 2013, and we expect COD by the second quarter of 2015. We
are currently evaluating funding sources for this phase of development,
including, but not limited to, nonrecourse financing, corporate financing or
internally generated funds.With respect to the second phase (309 MW), we are
in early stages of development. PJM has completed a feasibility study for this
phase and the system impact study is currently underway.

Deepwater Energy Center: We are currently evaluating our Deepwater facility
since the existing 158 MW fossil fuel steam-based power plant will be
decommissioned by May 1, 2015. The Deepwater development opportunity would add
approximately 350 MW of new combined-cycle capacity and leverage existing
infrastructure. Several outstanding early development issues must be resolved
before the project will be advanced.

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

All Segments:

Turbine Modernization: We continue to move forward with our turbine
modernization program. Through March 31, 2013, we have completed the upgrade
of eleven Siemens and eight GE turbines totaling approximately 200 MW and have
committed to upgrade approximately five 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.

OPERATIONS UPDATE

First Quarter 2013 Power Operations Achievements:

  *Safety Performance:
    — Maintained top quartile^6 safety metrics, recording a 0.9 Total
    Recordable Incident Rate

  *Availability Performance:
    — Delivered remarkable fleetwide forced outage factor: 1.5%
    — Maintained impressive fleetwide starting reliability: 98%

  *Geothermal Generation:
    — Provided more than 1.5 million MWh of renewable baseload generation with
    a remarkable 0.22% forced outage factor

  *Natural Gas-fired Generation:
    — Hermiston Power Project: Produced a fleet-best 91% capacity factor, 100%
    availability factor
    — Commenced construction on the first phase of Garrison Energy Center in
    April 2013

___________

^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.

^6 According to EEI Safety Survey (2011). Includes generation companies only.

                                                                
FINANCIAL OUTLOOK

(in millions, except per share amounts)
                                                                
                                                               Full Year 2013
                                                                
Adjusted EBITDA                                               $ 1,800 - 1,960
Less:
Operating lease payments                                        35
Major maintenance expense and maintenance capital               370
expenditures^(1)
Cash interest, net^(2)                                          755
Cash taxes                                                      15
Other                                                          10       
Adjusted Free Cash Flow                                       $ 615 - 775
Per Share Estimate (diluted)                                  $ 1.50
                                                                
Growth capital expenditures (net of debt funding)             $ (250     )
Debt amortization                                             $ (140     )

________

^(1) Includes projected major maintenance expense of $210 million and
maintenance capital expenditures of $160 million. Capital expenditures exclude
major construction and development projects. 2013 figures exclude 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 reaffirming our 2013 guidance, having recently
raised the lower end of the range. We project Adjusted EBITDA of $1,800
million to $1,960 million and Adjusted Free Cash Flow of $615 million to $775
million. We expect to invest $250 million, net of debt funding, in
growth-related projects during the year, including our Garrison Energy Center
development project and the expansion of our Deer Park and Channel Energy
Centers. (Though our construction projects at Russell City and Los Esteros
continue into 2013, we met our equity contribution requirements on these
projects in 2011, such that all costs incurred in 2013 will be funded from the
project debt we have secured for these projects.)

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results
for the first quarter of 2013 on Thursday, May 2,2013, at 10 a.m. ET / 9 a.m.
CT. A listen-only webcast of the call may be accessed through our website at
www.calpine.com, or by dialing (800) 447-0521 in the U.S. or (847) 413-3238
outside the U.S. The confirmation code is 34608176. 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 34608176. Presentation materials to accompany the
conference call will be available on our website on May 2, 2013.

ABOUT CALPINE

Calpine Corporation generates more electricity than any other independent
power producer in America, with a fleet of 93 power plants in operation or
under construction, representing more than 27,000 megawatts of generation
capacity in operation. Serving customers in 20 states and Canada, we
specialize in developing, constructing, owning and operating natural gas-fired
and renewable geothermal power plants that use advanced technologies to
generate power in a low-carbon and environmentally responsible manner. Our
clean, efficient, modern and flexible fleet is uniquely positioned to benefit
from the secular trends affecting our industry, including the abundant and
affordable supply of clean natural gas, stricter environmental regulation,
aging power generation infrastructure and the increasing need for dispatchable
power plants to successfully integrate intermittent renewables into the grid.
We focus on 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 March 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, fluctuations in prices for commodities
    such as natural gas and power, changes in U.S. macroeconomic conditions,
    fluctuations in liquidity and volatility in the energy commodities markets
    and our ability to hedge risks;
  *Laws, regulation and market rules in the markets in which we participate
    and our ability to effectively respond to changes in laws, regulations or
    market rules or the interpretation thereof including those related to the
    environment, derivative transactions and market design in the regions in
    which we operate;
  *Our ability to manage our liquidity needs and to comply with covenants
    under our First Lien Notes, Corporate Revolving Facility, First Lien Term
    Loans, CCFC Notes and other existing financing obligations;
  *Risks associated with the operation, construction and development of power
    plants including unscheduled outages or delays and plant efficiencies;
  *Risks related to our geothermal resources, including the adequacy of our
    steam reserves, unusual or unexpected steam field well and pipeline
    maintenance requirements, variables associated with the injection of
    wastewater to the steam reservoir and potential regulations or other
    requirements related to seismicity concerns that may delay or increase the
    cost of developing or operating geothermal resources;
  *The unknown future impact on our business from the Dodd-Frank Act and the
    rules to be promulgated thereunder;
  *Competition, including risks associated with marketing and selling power
    in the evolving energy markets;
  *The expiration or early termination of our PPAs and the related results on
    revenues;
  *Future capacity revenues may not occur at expected levels;
  *Natural disasters, such as hurricanes, earthquakes and floods, acts of
    terrorism or cyber attacks that may impact our power plants or the markets
    our power plants serve and our corporate headquarters;
  *Disruptions in or limitations on the transportation of natural gas, fuel
    oil and transmission of power;
  *Our ability to manage our customer and counterparty exposure and credit
    risk, including our commodity positions;
  *Our ability to attract, motivate and retain key employees;
  *Present and possible future claims, litigation and enforcement actions;
    and
  *Other risks identified in this press release and in our 2012 Form 10-K.

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


CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(in millions, except share and per share amounts)
                                                
                                                  (Unaudited)
                                                  Three Months Ended March 31,
                                                  2013            2012
Operating revenues:
Commodity revenue                                 $   1,308        $ 1,212
Unrealized mark-to-market gain (loss)             (71         )    22
Other revenue                                     4               2         
Operating revenues                                1,241           1,236     
Operating expenses:
Fuel and purchased energy expense:
Commodity expense                                 835              691
Unrealized mark-to-market (gain)                  (14         )    (56       )
Fuel and purchased energy expense                 821             635       
Plant operating expense                           227              221
Depreciation and amortization expense             146              140
Sales, general and other administrative expense   33               33
Other operating expenses                          18              21        
Total operating expenses                          1,245           1,050     
(Income) from unconsolidated investments in       (8          )    (9        )
power plants
Income from operations                            4                195
Interest expense                                  176              185
Loss on interest rate derivatives                 —                14
Interest (income)                                 (2          )    (3        )
Debt extinguishment costs                         —                12
Other (income) expense, net                       5               2         
Loss before income taxes                          (175        )    (15       )
Income tax benefit                                (50         )    (6        )
Net loss                                          (125        )    (9        )
Net income attributable to the noncontrolling     —               —         
interest
Net loss attributable to Calpine                  $   (125    )    $ (9      )
                                                                             
Basic and diluted loss per common share
attributable to Calpine:
Weighted average shares of common stock              451,706      478,106 
outstanding (in thousands)
Net loss per common share attributable to         $   (0.28   )    $ (0.02   )
Calpine — basic and diluted
                                                                             


CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)
                                                         
                                      March 31,         December 31,
                                      2013                    2012
                                      (in millions, except share and per share
                                      amounts)
ASSETS
Current assets:
Cash and cash equivalents             $     962               $   1,284
Accounts receivable, net of           483                     437
allowance of $2 and $6
Margin deposits and other prepaid     303                     244
expense
Restricted cash, current              142                     193
Derivative assets, current            514                     339
Inventory and other current assets    352                    335          
Total current assets                  2,756                   2,832
Property, plant and equipment, net    13,052                  13,005
Restricted cash, net of current       57                      60
portion
Investments in power plants           92                      81
Long-term derivative assets           149                     98
Other assets                          463                    473          
Total assets                          $     16,569           $   16,549   
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable                      $     437               $   382
Accrued interest payable              134                     180
Debt, current portion                 144                     115
Derivative liabilities, current       595                     357
Other current liabilities             203                    284          
Total current liabilities             1,513                   1,318
Debt, net of current portion          10,633                  10,635
Long-term derivative liabilities      289                     293
Other long-term liabilities           257                    247          
Total liabilities                     12,692                  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, 494,762,280 and 492,495,100   1                       1
shares issued, respectively, and
455,000,065 and 457,048,970 shares
outstanding, respectively
Treasury stock, at cost, 39,762,215   (675            )       (594         )
and 35,446,130 shares, respectively
Additional paid-in capital            12,351                  12,335
Accumulated deficit                   (7,625          )       (7,500       )
Accumulated other comprehensive       (236            )       (248         )
loss
Total Calpine stockholders’ equity    3,816                   3,994
Noncontrolling interest               61                     62           
Total stockholders’ equity            3,877                  4,056        
Total liabilities and stockholders’   $     16,569           $   16,549   
equity
                                                                           

                                                
CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)
                                                  
                                                  Three Months Ended March 31,
                                                  2013           2012
                                                  (in millions)
Cash flows from operating activities:
Net loss                                          $   (125  )     $  (9     )
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation and amortization expense^(1)         158             151
Deferred income taxes                             (7        )     (1        )
Loss on disposition of assets                     2               2
Unrealized mark-to-market activity, net           55              (224      )
(Income) from unconsolidated investments in       (8        )     (9        )
power plants
Stock-based compensation expense                  8               6
Other                                             (2        )     —
Change in operating assets and liabilities:
Accounts receivable                               (45       )     211
Derivative instruments, net                       (36       )     (66       )
Other assets                                      (73       )     20
Accounts payable and accrued expenses             (91       )     (153      )
Settlement of non-hedging interest rate swaps     —               151
Other liabilities                                 7              (8        )
Net cash provided by (used in) operating          (157      )     71        
activities
Cash flows from investing activities:
Purchases of property, plant and equipment        (176      )     (181      )
Settlement of non-hedging interest rate swaps     —               (151      )
Decrease in restricted cash                       54              23
Purchases of deferred transmission credits        —               (8        )
Other                                             —              3         
Net cash used in investing activities                (122  )       (314   )
Cash flows from financing activities:
Repayment under First Lien Term Loans             (6        )     (4        )
Borrowings from project financing, notes          73              114
payable and other
Repayments of project financing, notes payable    (36       )     (34       )
and other
Financing costs                                   (9        )     (5        )
Stock repurchases                                 (75       )     (6        )
Proceeds from exercises of stock options          9               —
Other                                             1              (4        )
Net cash provided by (used in) financing          (43       )     61        
activities
Net decrease in cash and cash equivalents         (322      )     (182      )
Cash and cash equivalents, beginning of period    1,284          1,252     
Cash and cash equivalents, end of period          $   962        $  1,070  
                                                                  
Cash paid during the period for:
Interest, net of amounts capitalized              $   213         $  226
Income taxes                                      $   5           $  6
                                                                  
Supplemental disclosure of non-cash investing
activities:
Change in capital expenditures included in        $   17          $  47
accounts payable

__________

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

REGULATION G RECONCILIATIONS

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

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

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

Adjusted EBITDA represents net income (loss) attributable to Calpine before
net (income) loss attributable to the noncontrolling interest, interest,
taxes, depreciation and amortization, adjusted for certain non-cash and
non-recurring items as detailed in the following reconciliation. Adjusted
EBITDA is presented because our management uses Adjusted EBITDA as a measure
of operating performance to assist in comparing performance from period to
period on a consistent basis and to readily view operating trends, as a
measure for planning and forecasting overall expectations and for evaluating
actual results against such expectations, and in communications with our Board
of Directors, shareholders, creditors, analysts and investors concerning our
financial performance. We believe Adjusted EBITDA is also used by and is
useful to investors and other users of our financial statements in evaluating
our operating performance because it provides them with an additional tool to
compare business performance across companies and across periods. We believe
that EBITDA is widely used by investors to measure a company’s operating
performance without regard to items such as interest expense, taxes,
depreciation and amortization, which can vary substantially from company to
company depending upon accounting methods and book value of assets, capital
structure and the method by which assets were acquired. Adjusted EBITDA is not
a measure calculated in accordance with U.S. GAAP and should be viewed as a
supplement to and not a substitute for our results of operations presented in
accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash
flows from operations or net income (loss) as defined by U.S. GAAP as an
indicator of operating performance and is not necessarily comparable to
similarly titled measures reported by other companies.

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

Commodity Margin Reconciliation

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

                Three Months Ended March 31, 2013
                                                       Consolidation 
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 202     $ 76      $ 142     $  41       $    —          $ 461
Margin
Add:
Unrealized
mark-to-market   (37   )   (11   )   7         7           (7        )     (41   )
commodity
activity, net
and other^(1)
Less:
Plant
operating        93        68        44        30          (8        )     227
expense
Depreciation
and              51        43        33        19          —               146
amortization
expense
Sales, general
and other        4         17        6         5           1               33
administrative
expense
Other
operating        9         1         7         2           (1        )     18
expenses
(Income) from
unconsolidated   —        —        (8    )   —          —              (8    )
investments in
power plants
Income (loss)
from             $ 8      $ (64 )   $ 67     $  (8  )    $    1         $ 4   
operations
                                                                           
                                                                           
                 Three Months Ended March 31, 2012
                                                           Consolidation
                                                           And
                 West      Texas     North     Southeast   Elimination     Total
Commodity        $ 208     $ 109     $ 144     $  56       $    —          $ 517
Margin^(2)(3)
Add:
Unrealized
mark-to-market   36        34        12        10          (8        )     84
commodity
activity, net
and other^(1)
Less:
Plant
operating        81        68        45        33          (6        )     221
expense
Depreciation
and              50        35        33        23          (1        )     140
amortization
expense
Sales, general
and other        8         11        6         8           —               33
administrative
expense
Other
operating        11        2         9         1           (2        )     21
expenses
(Income) from
unconsolidated   —        —        (9    )   —          —              (9    )
investments in
power plants
Income from      $ 94     $ 27     $ 72     $  1       $    1         $ 195 
operations

_________

^(1) Includes $(16) million and $(8) million of lease levelization and $4
million and $4 million of amortization expense for the three months ended
March31, 2013 and 2012, respectively.

^(2) Our North segment includes Commodity Margin of $8 million for the three
months ended March 31, 2012, related to Riverside Energy Center, which was
sold in December 2012.

^(3) Our Southeast segment includes Commodity Margin of $11 million for the
three months ended March 31, 2012, related to Broad River Energy Center, which
was sold in December 2012.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted
Free Cash Flow to our net loss attributable to Calpine for the three months
ended March 31, 2013 and 2012, as reported under U.S. GAAP.

                                                 Three Months Ended March 31,
                                                  2013           2012
                                                
Net loss attributable to Calpine                  $  (125   )     $  (9     )
Income tax benefit                                (50       )     (6        )
Debt extinguishment costs and other (income)      5               14
expense, net
Loss on interest rate derivatives                 —               14
Interest expense, net of interest income          174            182       
Income from operations                            $  4            $  195
Add:
Adjustments to reconcile income from operations
to Adjusted EBITDA:
Depreciation and amortization expense,            146             141
excluding deferred financing costs^(1)
Major maintenance expense                         66              46
Operating lease expense                           9               9
Unrealized (gain) loss on commodity derivative    57              (78       )
mark-to-market activity
Adjustments to reflect Adjusted EBITDA from       6               7
unconsolidated investments^(2)(3)
Stock-based compensation expense                  8               6
Loss on dispositions of assets                    2               2
Acquired contract amortization                    4               4
Other                                             (16       )     (7        )
Total Adjusted EBITDA                             $  286         $  325    
Less:
Operating lease payments                          9               9
Major maintenance expense and capital             136             146
expenditures^(4)
Cash interest, net^(5)                            180             191
Cash taxes                                        3               4
Other                                             1              2         
Adjusted Free Cash Flow^(6)                       $  (43    )     $  (27    )
                                                                  
Weighted average shares of common stock           451,706        478,106   
outstanding (diluted, in thousands)
Adjusted Free Cash Flow Per Share (diluted)       $  (0.10  )     $  (0.06  )

_________

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

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

^(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments
include unrealized (gain) loss on mark-to-market activity of nil for each of
the three months ended March, 2013 and 2012.

^(4) Includes $66 million and $47 million in major maintenance expense for the
three months ended March 31, 2013 and 2012, respectively, and $70 million and
$99 million in maintenance capital expenditures for the three months ended
March 31, 2013 and 2012, respectively.

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

^(6) Excludes an increase in working capital of $183 million and a decrease in
working capital of $76 million for the three months ended March 31, 2013 and
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
ended March 31, 2013 and 2012. Reconciliations for both Adjusted EBITDA and
Commodity Margin to comparable U.S. GAAP measures are provided above.

                                                 Three Months Ended March 31,
                                                  2013             2012
                                                  
Commodity Margin                                  $   461           $  517
Other revenue                                     3                 3
Plant operating expense^(1)                       (154      )       (170    )
Sales, general and administrative expense^(2)     (29       )       (30     )
Other operating expenses^(3)                      (10       )       (11     )
Adjusted EBITDA from unconsolidated investments   15                16
in power plants^(4)
Other                                             —                —       
Adjusted EBITDA                                   $   286          $  325  

_________

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

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

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

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


Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance
                                                                         
Full Year 2013 Range:                                         Low        High
                                                              (in millions)
GAAP Net Income ^(1)                                       $  175      $ 335
Plus:
Interest expense, net of interest income                      745        745
Depreciation and amortization expense                         575        575
Major maintenance expense                                     205        205
Operating lease expense                                       35         35
Other^(2)                                                     65        65
Adjusted EBITDA                                            $  1,800    $ 1,960
Less:
Operating lease payments                                      35         35
Major maintenance expense and maintenance capital             370        370
expenditures^(3)
Cash interest, net^(4)                                        755        755
Cash taxes                                                    15         15
Other                                                         10        10
Adjusted Free Cash Flow                                    $  615     $ 775

_________

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

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

^(3) Includes projected major maintenance expense of $210 million and
maintenance capital expenditures of $160 million. Capital expenditures exclude
major construction and development projects. 2013 figures exclude a
non-recurring IT system upgrade.

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

OPERATING PERFORMANCE METRICS

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

                                                Three Months Ended March 31,
                                                 2013            2012
Total MWh generated (in thousands)^(1)           23,998           28,055
West                                             8,337            8,203
Texas                                            8,030            9,143
Southeast                                        3,722            5,722
North                                            3,909            4,987
                                                                  
Average availability                             90.1     %       90.3     %
West                                             88.5     %       93.5     %
Texas                                            87.2     %       85.7     %
Southeast                                        94.1     %       94.1     %
North                                            92.3     %       89.1     %
                                                                  
Average capacity factor, excluding peakers^(1)   47.6     %       54.9     %
West                                             61.6     %       60.3     %
Texas                                            47.8     %       59.8     %
Southeast                                        33.7     %       48.7     %
North                                            43.2     %       47.1     %
                                                                  
Steam adjusted heat rate (Btu/kWh)               7,345            7,272
West                                             7,287            7,140
Texas                                            7,162            7,081
Southeast                                        7,269            7,271
North                                            7,911            7,818

________

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

Contact:

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