News Column

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

February 13, 2014

HOUSTON--(BUSINESS WIRE)--

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   % Change2013   2012   % Change
 
Operating Revenues $ 1,438 $ 1,367 5.2% $ 6,301 $ 5,478 15.0%
Commodity Margin $ 589 $ 515 14.4% $ 2,568 $ 2,538 1.2%
Adjusted EBITDA $ 399 $ 315 26.7% $ 1,830 $ 1,749 4.6%
Adjusted Free Cash Flow $ 126 $ 41 207.3% $ 677 $ 564 20.0%
Per Share (diluted)$0.29$0.09222.2%$1.52$1.2026.7%
Net Income (Loss)1 $ (97 ) $ 100 $ 14 $ 199
Per Share (diluted)$(0.23)$0.22$0.03$0.42
Net Income (Loss), As Adjusted2 $ 5 $ (86 ) $ 170 $ 78
 


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

 

2014 Prior Guidance

(as of Nov. 7, 2013)

 

2014

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 MWh3 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 Loss1 for the fourth quarter of 2013 was $97 million, or $0.23 per diluted share, compared to Net Income1 of $100 million, or $0.22 per diluted share, in the prior year period. Net Income, As Adjusted2, for the fourth quarter of 2013 was $5 million compared to a Net Loss, As Adjusted2, of $86 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, 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 Income1 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 Adjusted2, 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 Adjusted2, 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 Loss1 was $97 million for the fourth quarter of 2013, compared to Net Income1 of $100 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $5 million in the fourth quarter of 2013 compared to a Net Loss1, As Adjusted2, 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 expense4, 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 Income1 was $14 million in 2013 compared to $199 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $170 million in 2013 compared to $78 million in the prior year period. The favorable year-over-year improvement in Net Income, As Adjusted2, 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 31,Year Ended December 31,
    2013201220132012
    (in millions)(in millions)
    Net income attributable to Calpine $ (97 ) $ 100 $ 14 $ 199
    Debt extinguishment costs(1) 76 18 144 30
    (Gain) on sale of assets, net(1) (222 ) (222 )
    Unrealized MtM (gain)/loss on derivatives(1)(2) 26 31 12 (72 )
    Other items (1) (3)   (13 )   143  
    Net Income (Loss), As Adjusted(4) $ 5   $ (86 ) $ 170   $ 78  


    __________

    (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,
    20132012Variance20132012Variance
    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,
    20132012
    (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 December 31, 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 December 31, 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,
    20132012
    (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 equivalents (343 ) 32  
    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.

    CAPITALALLOCATION

    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 MW5 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 quartile6 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 expenditures(1) 380
    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 million7 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, Section 27A of the Securities Act, and Section 21E 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   201220132012
    (in millions, except share and per share amounts)
    Operating revenues:
    Commodity revenue $ 1,507 $ 1,339 $ 6,374 $ 5,417
    Unrealized mark-to-market gain (loss) (72 ) 24 (86 ) 48
    Other revenue 3   4   13   13  
    Operating revenues 1,438   1,367   6,301   5,478  
    Operating expenses:
    Fuel and purchased energy expense:
    Commodity expense 899 821 3,808 2,894
    Unrealized mark-to-market (gain) loss (43 ) 57   (72 ) 130  
    Fuel and purchased energy expense 856   878   3,736   3,024  
    Plant operating expense 211 223 895 922
    Depreciation and amortization expense 168 144 609 562
    Sales, general and other administrative expense 34 36 136 140
    Other operating expenses 23   20   81   78  
    Total operating expenses 1,292   1,301   5,457   4,726  
    (Gain) on sale of assets, net (222 ) (222 )
    (Income) from unconsolidated investments in power plants (5 ) (7 ) (30 ) (28 )
    Income from operations 151 295 874 1,002
    Interest expense 174 184 696 736
    Loss on interest rate derivatives 14
    Interest (income) (1 ) (4 ) (6 ) (11 )
    Debt extinguishment costs 76 18 144 30
    Other (income) expense, net 5   1   20   15  
    Income (loss) before income taxes (103 ) 96 20 218
    Income tax expense (benefit) (10 ) (4 ) 2   19  
    Net income (loss) (93 ) 100 18 199
    Net income attributable to the noncontrolling interest (4 )   (4 )  
    Net income (loss) attributable to Calpine $ (97 ) $ 100   $ 14   $ 199  

    Basic earnings (loss) per common share attributable to Calpine:

    Weighted average shares of common stock outstanding (in thousands)

     

    429,331

       

    459,304

       

    440,666

       

    467,752

     

    Net income (loss) per common share attributable to Calpine — basic

    $

    (0.23

    )

     

    $

    0.22

     

    $

    0.03

     

    $

    0.43

     

    Diluted earnings (loss) per common share attributable to Calpine:

    Weighted average shares of common stock outstanding (in thousands)

     

    429,331

       

    463,291

       

    444,773

       

    471,343

     

    Net income (loss) per common share attributable to Calpine — diluted

    $

    (0.23

    )

    $

    0.22

     

    $

    0.03

     

    $

    0.42

     
     
     

    CALPINE CORPORATION AND SUBSIDIARIES

     

    CONSOLIDATED BALANCE SHEETS

    December 31, 2013 and 2012

    (in millions, except share and per share amounts)

       
    20132012
    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, and 492,495,100 shares issued and 457,048,970 shares outstanding at December 31, 2012 1 1
    Treasury stock, at cost, 68,802,068 and 35,446,130 shares, respectively (1,230 ) (594 )
    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 plants (30 ) (28 )
    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 power plants 2 5
    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 other 182 389
    Repayments of project financing, notes payable and other (66 ) (289 )
    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 payable $ 27 $ 19
    Other non-cash additions to property, plant and equipment $ $ 13


    __________

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


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


    _________

    (1) Includes $(11) million and $(6) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended December 31, 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 December 31, 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

    December 31,

    Year Ended December 31,
    2013   20122013   2012
     
    Net income (loss) attributable to Calpine $ (97 ) $ 100 $ 14 $ 199
    Net income attributable to the noncontrolling interest 4 4
    Income tax expense (10 ) (4 ) 2 19
    Debt extinguishment costs and other (income) expense, net 81 19 164 45
    Loss on interest rate derivatives 14
    Interest expense, net of interest income 173   180   690   725  
    Income from operations $ 151 $ 295 $ 874 $ 1,002
    Add:
    Adjustments to reconcile income from operations to Adjusted EBITDA:
    Depreciation and amortization expense, excluding deferred financing costs(1) 168 145 609 564
    Major maintenance expense 42 42 224 200
    Operating lease expense 9 8 35 34
    Unrealized (gain) loss on commodity derivative mark-to-market activity 29 33 14 82
    (Gain) on sale of assets, net (222 ) (222 )
    Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2) 1 8 14 31
    Stock-based compensation expense 8 6 36 25

    (Gain) loss on dispositions of assets

    (1 ) 3 4 12
    Acquired contract amortization 3 3 14 14
    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 and capital expenditures(3) 89 77 392 375
    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 (diluted, in thousands) 429,331   463,291   444,773   471,343  
    Adjusted Free Cash Flow Per Share (diluted) $ 0.29   $ 0.09   $ 1.52   $ 1.20  


    _________

    (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 31,Year Ended December 31,
    2013   20122013   2012
    (in millions)(in millions)
    Commodity Margin $ 589 $ 515 $ 2,568 $ 2,538
    Other revenue 3 3 12 12
    Plant operating expense(1) (165 ) (174 ) (645 ) (692 )
    Sales, general and administrative expense(2) (30 ) (33 ) (117 ) (127 )
    Other operating expenses(3) (10 ) (11 ) (42 ) (41 )
    Adjusted EBITDA from unconsolidated investments in power plants(4) 14 14 58 58
    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:LowHigh
    (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 expenditures(3) 380 380
    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 31,   Year Ended December 31,
    2013   20122013   2012
    Total MWh generated (in thousands)(1) 25,585 25,189 101,610 112,216
    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 peakers(1) 48.0 % 48.0 % 48.7 % 53.7 %
    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 rate (Btu/kWh) 7,339 7,378 7,386 7,361
    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.



    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


    Source: Calpine Corporation


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