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Calpine Reports Third Quarter 2012 Results, Narrows 2012 Guidance, Provides 2013 Guidance and Announces Sale of Broad River Energy Center

Tuesday, November 06, 2012

Calpine Reports Third Quarter 2012 Results, Narrows 2012 Guidance, Provides 2013 Guidance and Announces Sale of Broad River Energy Center06:00 EST Tuesday, November 06, 2012 HOUSTON (Business Wire) -- Calpine Corporation (NYSE: CPN): Summary of Third Quarter 2012 Financial Results (in millions):     Three Months Ended September 30,   Nine Months Ended September 30,2012   2011   % Change2012   2011   % Change     Operating Revenues $ 1,996 $ 2,209 (9.6)% $ 4,111 $ 5,341 (23.0)% Commodity Margin $ 897 $ 825 8.7% $ 2,023 $ 1,921 5.3% Adjusted EBITDA $ 706 $ 638 10.7% $ 1,434 $ 1,347 6.5% Adjusted Recurring Free Cash Flow $ 463 $ 361 28.3% $ 523 $ 381 37.3%Per Share (diluted)$0.99$0.7433.8%$1.10$0.7841.0% Net Income (Loss)1 $ 437 $ 190 $ 99 $ (177 ) Net Income, As Adjusted2 $ 215 $ 195 $ 164 $ 30   Narrowing 2012 Full Year Guidance and Providing 2013 Full Year Guidance:         20122013(in millions) Adjusted EBITDA $1,725 - 1,775 $1,760 - 1,960 Adjusted Recurring Free Cash Flow $525 - 575 $575 - 775 Per Share Midpoint (diluted) $1.16 $1.45 Note: 2013 guidance range reflects all pending acquisition and divestiture activity, including today's announced sale of Broad River Energy Center, which we estimate would have contributed approximately $40 million of Adjusted EBITDA in 2013.Recent Achievements: Operations:— Generated more than 33 million MWh3 of electricity in the third quarter of 2012, a record for the period and a 14% increase compared to the third quarter of 2011— Held year-to-date plant operating expense4 essentially flat, despite a 31% increase in generation3— Delivered lowest year-to-date fleetwide forced outage factor on record: 1.6%— Produced highest year-to-date fleetwide starting reliability on record: 98.5%  — Achieved best year-to-date safety performance on record Commercial:— Announcing sale of Broad River Energy Center, an 847 MW simple-cycle power plant in South Carolina, for $427 million5, or $504/kW— Announced acquisition of Bosque Energy Center, an 800 MW combined-cycle power plant in Central Texas for $432 million5, or $540/kW— Signed 15-year PPA for 260 MW of capacity, energy and ancillary services from our Oneta Energy Center commencing in June 2016 Capital Structure:— Simplified capital structure by entering into $835 million first lien term loan at an attractive rate, using proceeds to redeem 10% of existing first lien notes and retire project-level BRSP debt Calpine Corporation (NYSE: CPN) today reported third quarter 2012 Adjusted EBITDA of $706 million, compared to $638 million in the prior year period, and Adjusted Recurring Free Cash Flow of $463 million, or $0.99 per diluted share, compared to $361 million, or $0.74 per diluted share, in the prior year period. Net Income1 for the third quarter was $437 million, or $0.94 per diluted share, compared to $190 million, or $0.39 per diluted share, in the prior year period. Net Income, As Adjusted2, for the third quarter of 2012 was $215 million compared to $195 million in the prior year period. Year-to-date 2012 Adjusted EBITDA was $1,434 million, compared to $1,347 million in the prior year period, and Adjusted Recurring Free Cash Flow was $523 million, or $1.10 per diluted share, compared to $381 million, or $0.78 per diluted share, in the prior year period. Net Income1 for the first nine months of 2012 was $99 million, or $0.21 per diluted share, compared to a Net Loss1 of $177 million, or $0.36 per diluted share, in the prior year period. Net Income, As Adjusted2, for the first nine months of 2012 was $164 million compared to $30 million in the prior year period. “Calpine's power plants continue to deliver record operating results,” said Jack Fusco, Calpine's President and Chief Executive Officer. “Our versatile fleet generated nearly 90 million MWhs through the first nine months of 2012 – 31% more than last year – while holding plant operating expenses essentially flat. This was due in large part to our focus on operational excellence and preventive maintenance, which yielded our best year-to-date forced outage factor and starting reliability on record. In addition, our commercial optimization efforts resulted in significant contribution from our Texas segment during the third quarter due to our seasonal hedging activity, which captured margin above what ultimately proved to be weak market prices driven by mild weather. As a result, we are able to maintain the midpoint of our full-year 2012 Adjusted EBITDA and Adjusted Recurring Free Cash Flow guidance while narrowing the range. “Consistent with our disciplined capital allocation program, Calpine continues to make significant progress across the board, from acquisitions and divestitures to organic growth to share repurchases. With respect to acquisitions and divestitures, I am pleased to report that we have taken another meaningful step forward in our initiative to realign our portfolio by monetizing non-core assets and redeploying capital to enhance long-term shareholder value. Today, we are announcing the divestiture of our Broad River Energy Center, a contracted peaking plant in South Carolina, for $427 million, which complements our recently announced $432 million acquisition of Bosque, a merchant CCGT in the attractive Texas market. In addition, we expect to receive $392 million by year-end for the sale of our Riverside Energy Center, a CCGT in Wisconsin. Meanwhile, we plan to bring almost 800 MW of contracted growth projects in California online by mid-2013 and continue to advance more than 800 MW of development projects in Texas and Delaware. Finally, we have completed approximately $427 million of our previously announced $600 million share repurchase program.” Zamir Rauf, Calpine's Chief Financial Officer, added, “We've had a great year to date, as evidenced by our 41% growth in Adjusted Recurring Free Cash Flow Per Share, which I believe is the best measure for evaluating shareholder value creation. Free cash flow per share represents cash available for capital allocation and captures value created through asset monetizations, debt portfolio optimization, our substantial NOL tax position and share repurchases. Therefore, in addition to our 2013 guidance, we are initiating an Adjusted Recurring Free Cash Flow Per Share growth target rate of 15-20% compounded annually, which we also believe represents potential annual total shareholder return.” SUMMARY OF FINANCIAL PERFORMANCEThird Quarter Results Adjusted EBITDA for the third quarter of 2012 was $706 million compared to $638 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $72 million increase in Commodity Margin, which was driven primarily by:             +   higher contribution from hedges in our Texas segment, and + higher regulatory capacity revenue in the Mid-Atlantic market. Net Income1 was $437 million for the third quarter of 2012, compared to $190 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $215 million in the third quarter of 2012 compared to $195 million in the prior year period. The year-over-year improvement was driven largely by:             +   higher Commodity Margin, as previously discussed, and + lower interest expense, primarily resulting from a decrease in our annual effective interest rate, partially offset by – increased income tax expense due primarily to an increase in various state and foreign jurisdiction income taxes. Year-to-Date Results Adjusted EBITDA for the nine months ended September 30, 2012, was $1,434 million compared to $1,347 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $102 million increase in Commodity Margin, partially offset by modest increases in plant operating expense4 and sales, general and administrative expenses6. The increase in Commodity Margin was primarily due to:             +   higher contribution from hedges, primarily in our Texas segment during the third quarter of 2012 compared to the prior year period + higher generation due to increased market opportunities, primarily driven by lower natural gas prices in all segments during the first half of 2012 compared to the same period in 2011, as well as lower hydroelectric generation and a nuclear power plant outage in California during the nine months ended September 30, 2012, and + an extreme cold weather event in Texas in February 2011 that negatively impacted our Commodity Margin in that period, which did not recur in the current year, partially offset by – lower regulatory capacity revenues during the first half of 2012 compared to the prior year period and – the expiration of contracts. Net Income1 was $99 million for the nine months ended September 30, 2012, compared to a Net Loss1 of $177 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $164 million in the nine months ended September 30, 2012, compared to $30 million in the prior year period. The year-over-year improvement was driven largely by:             +   higher Commodity Margin, as previously discussed, and + lower interest expense, primarily resulting from a decrease in our annual effective interest rate. ___________ 1Reported as net income (loss) attributable to Calpine on our Consolidated Condensed Statements of Operations.2Refer to Table 1 for further detail of Net Income, As Adjusted.3Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants.4Increase 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 nine months ended September 30, 2012 and 2011.5Amounts subject to adjustments upon close.6Increase in sales, general and administrative expense excludes changes in stock-based compensation expense, amortization and other items. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the nine months ended September 30, 2012 and 2011.Table 1: Net Income, As Adjusted   Three Months Ended September 30,   Nine Months Ended September 30,2012   20112012   2011(in millions) Net income (loss) attributable to Calpine $ 437 $ 190 $ 99 $ (177 ) Debt extinguishment costs(1) — (4 ) 12 94 Unrealized MtM (gain) loss on derivatives(1) (2) (222 ) (35 ) (103 ) 42 Other items (1) (3) —   44   156   71   Net Income, As Adjusted(4) $ 215   $ 195   $ 164   $ 30   __________ (1) Shown net of tax, assuming a 0% effective tax rate for these items.(2) In addition to changes in market value on derivatives not designated as hedges, changes in unrealized (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.(3) Other items include realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps totaling nil and $156 million for the three and nine months ended September 30, 2012, respectively, and $44 million and $147 million for the three and nine months ended September 30, 2011, respectively. Other items for the nine months ended September 30, 2011, also include a $76 million federal deferred income tax benefit associated with our election to consolidate our CCFC subsidiary for tax reporting purposes.(4) See “Regulation G Reconciliations” for further discussion of Net Income, As Adjusted.REGIONAL SEGMENT REVIEW OF RESULTSTable 2: Commodity Margin by Segment (in millions)   Three Months Ended September 30,   Nine Months Ended September 30,2012   2011   Variance2012   2011   Variance West $ 330 $ 329 $ 1 $ 748 $ 798 $ (50 ) Texas 218 162 56 472 357 115 North 266 259 7 591 578 13 Southeast 83   75   8   212   188   24   Total $ 897   $ 825   $ 72   $ 2,023   $ 1,921   $ 102   West RegionThird Quarter: Commodity Margin in our West segment increased by $1 million in the third quarter of 2012 compared to the prior year period. Primary drivers were:             +   increased generation and higher spark spreads driven primarily by lower hydroelectric generation and a nuclear power plant outage in California during 2012, largely offset by – lower contribution from hedges associated with our Geysers assets. Year-to-Date: Commodity Margin in our West segment decreased by $50 million for the nine months ended September 30, 2012, compared to the prior year period. Primary drivers were:             –   lower contribution from hedges associated with our Geysers assets – lower revenue due to the expiration of contracts and – lower Commodity Margin associated with our Sutter Energy Center, which did not run in the first half of 2012, partially offset by + increased generation and higher spark spreads resulting from lower hydroelectric generation and a nuclear power plant outage in California during 2012. Texas RegionThird Quarter: Commodity Margin in our Texas segment increased by $56 million in the third quarter of 2012 compared to the prior year period. The primary driver was:             +   higher contribution from hedging activities that secured favorable pricing despite lower market prices driven by milder weather. Year-to-Date: Commodity Margin in our Texas segment increased by $115 million for the nine months ended September 30, 2012, compared to the prior year period. Primary drivers were:             +   higher contribution from hedging activities that secured favorable pricing despite lower market prices driven by milder weather in the third quarter of 2012 compared to the prior year period + higher generation driven by increased market opportunities primarily due to lower natural gas prices and + an extreme cold weather event in Texas in February 2011 that negatively impacted our Commodity Margin in the first quarter of the prior year, which did not recur in the current year. North RegionThird Quarter: Commodity Margin in our North segment increased by $7 million in the third quarter of 2012 compared to the prior year period. Primary drivers were:             +   higher regulatory capacity revenues and + to a far lesser extent, increased generation, the impact of which was mitigated by contracted plants that generated higher volumes, as well as lower margins experienced by the remaining plants. Year-to-Date: Commodity Margin in our North segment increased by $13 million in the nine months ended September 30, 2012, compared to the prior year period. Primary drivers were:             +   higher contribution from hedges + York Energy Center achieving commercial operation in March 2011 and + increased generation driven by increased market opportunities primarily due to lower natural gas prices, partially offset by – lower regulatory capacity revenues during the nine months ended September 30, 2012, compared to the prior year period. Southeast RegionThird Quarter: Commodity Margin in our Southeast segment increased by $8 million in the third quarter of 2012 compared to the prior year period. Primary drivers were:             +   higher contribution from hedges associated with lower natural gas prices, partially offset by – the expiration of a contract. Year-to-Date: Commodity Margin in our Southeast segment increased by $24 million in the nine months ended September 30, 2012, compared to the prior year period. Primary drivers were:             +   higher contribution from hedges and + higher generation resulting from increased market opportunities due to lower natural gas prices . LIQUIDITY AND CAPITAL RESOURCESTable 3: Liquidity   September 30,   December 31,20122011(in millions) Cash and cash equivalents, corporate(1) $ 886 $ 946 Cash and cash equivalents, non-corporate 211   306 Total cash and cash equivalents 1,097 1,252 Restricted cash 226 194 Corporate Revolving Facility availability 720 560 Letter of credit availability(2) 25   7 Total current liquidity availability $ 2,068   $ 2,013 __________ (1) Includes $9 million and $34 million of margin deposits held by us posted by our counterparties at September 30, 2012, and December 31, 2011, respectively.(2) Includes availability under our CDHI letter of credit facility. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016. Liquidity remained strong at over $2 billion as of September 30, 2012. Cash flows from operating activities for the nine months ended September 30, 2012, resulted in net inflows of $608 million compared to $536 million in the prior year period. The increase in cash provided by operating activities was primarily due to an increase in income from operations (adjusted for non-cash items), partially offset by an increase in cash paid for interest due to timing of interest payments on our debt. Cash flows used in investing activities increased to $701 million for the nine months ended September 30, 2012, compared to $660 million in the prior year period, driven largely by the termination of our legacy interest rate swaps and by an increase in restricted cash associated with 2011 changes in project related debt that did not recur in the nine months ended September 30, 2012. Cash flows used in financing activities were $62 million for the nine months ended September 30, 2012, and were primarily related to the payments we made under our share repurchase program, offset by the receipt of proceeds from project financings related to our Russell City and Los Esteros construction projects. In addition, we incurred lower financing costs and lower repayments on project debt due in part to the refinancing activities we completed during the nine months ended September 30, 2011. Adjusted Recurring Free Cash Flow was $523 million for the nine months ended September 30, 2012, compared to $381 million for the prior year period. Adjusted Recurring Free Cash Flow increased during the period primarily due to an $87 million increase in Adjusted EBITDA, as previously discussed. Lower maintenance capital expenditures related to our plant outage schedule and lower interest expense further contributed to the increase compared to the prior year period. Consistent with our efforts to optimize and simplify our capital structure, on October 9, 2012, we announced that we had entered into a $835 million term loan, the proceeds of which we intend to use to redeem 10% (or approximately $590 million) of our senior secured notes and to retire variable rate project-level BRSP debt (approximately $218 million remaining balance). The term loan, which amortizes at a rate of 1% per year, matures in 2019. The term loan bears interest at LIBOR plus 3.25% per annum (subject to a LIBOR floor of 1.25%) and is expected to produce annual interest savings of approximately $25 million. “As a result of this opportunistic refinancing,” said Zamir Rauf, Calpine's Chief Financial Officer, “we have improved our capital structure while reducing our cost of debt, delivering Adjusted Recurring Free Cash Flow accretion.” CAPITALALLOCATIONPortfolio Optimization Today, we are announcing that we have entered into an agreement with Broad River Power, LLC, a wholly owned subsidiary of Energy Capital Partners, LLC, to sell our Broad River Energy Center, an 847 MW natural gas-fired, simple-cycle power plant in South Carolina, for $427 million plus adjustments, or approximately $504/kW. We expect the transaction to close in December 2012, subject to regulatory approvals. On October 3, 2012, we agreed to purchase the Bosque Energy Center, an 800 MW natural gas-fired, combined-cycle power plant in Central Texas, for $432 million plus adjustments, or approximately $540/kW. The acquisition will increase our capacity in Texas, one of our key markets. We expect the transaction to close in November 2012 and will fund the acquisition with cash on hand. In addition, on May 18, 2012, our customer exercised its option to purchase our Riverside Energy Center for approximately $392 million. The sale is expected to close in December 2012. Share Repurchase Program On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common stock. The announced share repurchase program did not specify an expiration date. The repurchases may be commenced or suspended from time to time without prior notice. Through the filing of this release, a total of 25.6 million shares of our outstanding common stock have been repurchased under this program for approximately $427 million at an average price of $16.66 per share. The shares repurchased as of the date of this release were purchased in open market transactions. PLANT DEVELOPMENTWest:Russell City Energy Center: Construction at our Russell City Energy Center continues to move forward. Upon completion, this project will bring online approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a 10-year PPA. Construction is ongoing and COD is expected during the summer of 2013. 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. The existing 188 MW simple-cycle facility was shut down at the end of 2011 to allow for major maintenance on the combustion turbines and installation of the new heat recovery steam generators and a steam turbine generator in connection with the new PPA. Construction is ongoing and COD is expected during the summer of 2013. Texas:Channel and Deer Park Expansions: We are actively permitting the addition of 520 MW7 of combined-cycle capacity at existing sites in ERCOT, based on tightening reserve margins and the potential impact of EPA regulations on generation in Texas. At both our Deer Park and Channel Energy Centers, we have the ability to install an additional combustion turbine generator and connect to the existing steam turbine generator to expand the capacity of these facilities and to improve overall plant efficiency. In September and November 2011, we filed air permit applications with the Texas Commission on Environmental Quality (TCEQ) and the EPA to expand the Deer Park and Channel Energy Centers by approximately 260 MW each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September and October 2012, respectively, and we executed engineering, procurement and construction agreements during the third quarter of 2012. We expect COD in summer 2014 for these expansions. We are currently evaluating funding sources, including, but not limited to, nonrecourse financing, corporate financing or internally generated funds. North:Garrison Energy Center: We are actively permitting 618 MW of new combined-cycle capacity at a development site secured by a long-term lease with the City of Dover. For the first phase (309 MW), PJM has completed a feasibility study and a system impact study and is currently conducting a facility study. For the second phase (309 MW), a feasibility study has been completed and a system impact study is ongoing. Environmental permitting, site development planning and development engineering are underway, and the first phase's capacity cleared PJM's 2015/2016 base residual auction. We expect to receive the air permit in the fourth quarter of 2012 and expect COD for the first phase by the summer of 2015. We are currently evaluating funding sources, including but not limited to nonrecourse financing, corporate financing or internally generated funds. All Segments:Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through September 30, 2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have agreed to upgrade approximately three additional turbines (and may upgrade additional turbines in the future). ___________ 7 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 UPDATEThird Quarter 2012 Power Operations Achievements: Safety Performance:— Maintained stellar safety metrics— Recognized 10 years with no lost time incidents: Westbrook Energy Center, Pine Bluff Energy Center, Baytown Energy Center, Geysers plants – Aidlin, Sonoma, Cobb Creek, Quicksilver, Socrates Availability Performance:— Delivered lowest year-to-date fleetwide forced outage factor on record: 1.6%— Maintained impressive third quarter fleetwide starting reliability: 98.8% Cost Performance:— Held year-to-date plant operating expense4 essentially flat, despite a 31% increase in generation3 Geothermal Generation:— Provided over 1.5 million MWh of renewable baseload generation with a record 0.5% forced outage factor during the third quarter of 2012 Natural Gas-fired Generation:— Increased combined-cycle capacity factor in the first nine months of 2012 to 54.3% compared to 40.9% in the prior year period— Santa Rosa Energy Center: 100% starting reliability, 0.00% forced outage factor Third Quarter 2012 Commercial Operations Achievements: Customer-oriented Growth:— Entered into a 15-year PPA with Public Service Company of Oklahoma to provide 260 MW of capacity, energy and ancillary services from our Oneta Energy Center commencing in June 2016 through May 2031 FINANCIAL OUTLOOK   Full Year 2012       Full Year 2013(1)(in millions) Adjusted EBITDA $ 1,725 - 1,775       $ 1,760 - 1,960 Less: Operating lease payments 35 35 Major maintenance expense and maintenance capital expenditures(2) 350 370 Accelerated parts purchases to support upgrades(3) 30 - Recurring cash interest, net(4) 770 755 Cash taxes 10 15 Other   5           10   Adjusted Recurring Free Cash Flow $ 525 - 575 $ 575 - 775 Per Share Midpoint $ 1.16 $ 1.45   Non-recurring interest rate swap payments(5) $ (156 ) $ - Growth capital expenditures (net of debt funding) $ (100 ) $ (250 ) Debt amortization $ (115 ) $ (140 ) Asset purchases $ (432 ) $ - Asset sale proceeds(6) $ 819 $ - ________ (1) 2013 guidance range reflects all pending acquisition and divestiture activity, including today's announced sale of Broad River Energy Center, which we estimate would have contributed approximately $40 million of Adjusted EBITDA in 2013.(2) Includes projected major maintenance expense of $200 million and $210 million and maintenance capital expenditures of $150 million and $160 million in 2012 and 2013, respectively. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt. 2013 figures exclude non-recurring IT system upgrade.(3) Incremental impact on 2012 maintenance capital expenditures related to acceleration of future turbine upgrades into 2012 and deferral of use of on-hand parts to post-2012 periods.(4) Includes fees for letters of credit, net of interest income.(5) Interest payments related to legacy LIBOR hedges associated with floating rate first lien credit facility, which has been retired.(6) Amounts subject to adjustments upon close. As detailed above, today we are narrowing our 2012 guidance. We now project Adjusted EBITDA of $1,725 million to $1,775 million and Adjusted Recurring Free Cash Flow of $525 million to $575 million. We also expect to invest $100 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, as well as our ongoing turbine upgrade program. (Though our construction projects at Russell City and Los Esteros continue through 2012, we met our equity contribution requirements on these projects in 2011, such that all costs incurred in 2012 and beyond will be funded from the project debt we have secured for these projects.) Finally, during the fourth quarter of 2012, we expect to close on the sales of our Broad River and Riverside Energy Centers and the purchase of Bosque Energy Center. Today, we are also initiating 2013 guidance. We expect Adjusted EBITDA of $1,760 million to $1,960 million and Adjusted Recurring Free Cash Flow of $575 million to $775 million. The 2013 guidance range reflects all pending acquisition and divestiture activity, including today's announced sale of Broad River Energy Center, which we estimate would have contributed approximately $40 million of Adjusted EBITDA in 2013. We also expect to invest $250 million, net of debt funding, in our ongoing growth-related projects during the year. INVESTOR CONFERENCE CALL AND WEBCAST We will host a conference call to discuss our financial and operating results for the third quarter of 2012 on Tuesday, November 6, 2012, at 11 a.m. ET / 10 a.m. CT. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (888) 895-5271 in the U.S. or (847) 619-6547 outside the U.S. The confirmation code is 33421254. 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 33421254. Presentation materials to accompany the conference call will be available on our website on November 6, 2012. ABOUT CALPINE Calpine Corporation is the largest independent power producer in the U.S., with a fleet of 93 power generation plants representing more than 28,000 megawatts of generation capacity. Last year our plants generated more than 94 million megawatt hours of power for our wholesale customers in 20 states and Canada. Our 91 operating plants as well as two under construction consist primarily of natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our modern, clean, efficient and cost-effective fleet stands ready to respond to the increased need for cleaner and more affordable power as the economy recovers, as new environmental rules are implemented and force older, dirtier plants to retire or reduce generation, as variable renewable power generation from wind and solar grows and with it the need for flexible natural gas generation to assure firm supply to the grid, and finally, as natural gas becomes economically competitive with coal as a fuel for power generation. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today. Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, 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 INFORMATIONIn 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, 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;The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, 2019 First Lien Term Loan, CCFC Notes and other existing financing obligations;Risks associated with the continued economic and financial conditions affecting certain countries in Europe including financial institutions located within those countries and their ability to fund their financial commitments;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;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; andOther risks identified in this press release and in our 2011 Form 10-K.Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.CALPINE CORPORATION AND SUBSIDIARIES   CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS(Unaudited)     Three Months Ended September 30,   Nine Months Ended September 30,2012   20112012   2011(in millions, except share and per share amounts) Operating revenues $ 1,996 $ 2,209 $ 4,111 $ 5,341 Operating expenses: Fuel and purchased energy expense 893 1,401 2,137 3,470 Plant operating expense 207 212 699 711 Depreciation and amortization expense 140 143 418 405 Sales, general and other administrative expense 36 33 104 99 Other operating expenses 22   22   67   64   Total operating expenses 1,298   1,811   3,425   4,749   (Income) from unconsolidated investments in power plants (7 ) (5 ) (21 ) (12 ) Income from operations 705 403 707 604 Interest expense 183 192 552 575 Loss on interest rate derivatives — 3 14 149 Interest (income) (2 ) (2 ) (7 ) (7 ) Debt extinguishment costs — (4 ) 12 94 Other (income) expense, net 6   4   14   14   Income (loss) before income taxes 518 210 122 (221 ) Income tax expense (benefit) 81   20   23   (45 ) Net income (loss) 437 190 99 (176 ) Net income attributable to the noncontrolling interest —   —   —   (1 ) Net income (loss) attributable to Calpine $ 437   $ 190   $ 99   $ (177 ) Basic earnings (loss) per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 462,307   486,420   470,589   486,363   Net income (loss) per common share attributable to Calpine — basic $ 0.95   $ 0.39   $ 0.21   $ (0.36 )   Diluted earnings (loss) per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 465,953   489,062   474,131   486,363   Net income (loss) per common share attributable to Calpine — diluted $ 0.94   $ 0.39   $ 0.21   $ (0.36 )   CALPINE CORPORATION AND SUBSIDIARIES   CONSOLIDATED CONDENSED BALANCE SHEETS(Unaudited)     September 30,   December 31,20122011(in millions, except share and per shareamounts)ASSETS Current assets: Cash and cash equivalents $ 1,097 $ 1,252 Accounts receivable, net of allowance of $10 and $13 500 598 Margin deposits and other prepaid expense 143 193 Restricted cash, current 163 139 Derivative assets, current 487 1,051 Inventory and other current assets 297   329   Total current assets 2,687 3,562 Property, plant and equipment, net 13,129 13,019 Restricted cash, net of current portion 63 55 Investments 79 80 Long-term derivative assets 146 113 Other assets 489   542   Total assets $ 16,593   $ 17,371   LIABILITIES & STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 361 $ 435 Accrued interest payable 163 200 Debt, current portion 105 104 Derivative liabilities, current 457 1,144 Other current liabilities 265   279   Total current liabilities 1,351 2,162 Debt, net of current portion 10,567 10,321 Long-term derivative liabilities 286 279 Other long-term liabilities 275   245   Total liabilities 12,479 13,007 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, 492,072,137 and 490,468,815 shares issued, respectively, and 465,572,396 and 481,743,738 shares outstanding, respectively 1 1 Treasury stock, at cost, 26,499,741 and 8,725,077 shares, respectively (439 ) (125 ) Additional paid-in capital 12,327 12,305 Accumulated deficit (7,600 ) (7,699 ) Accumulated other comprehensive loss (237 ) (178 ) Total Calpine stockholders' equity 4,052 4,304 Noncontrolling interest 62   60   Total stockholders' equity 4,114   4,364   Total liabilities and stockholders' equity $ 16,593   $ 17,371     CALPINE CORPORATION AND SUBSIDIARIES   CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS(Unaudited)     Nine Months Ended September 30,2012   2011(in millions) Cash flows from operating activities: Net income (loss) $ 99 $ (176 ) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization expense(1) 449 431 Debt extinguishment costs — 82 Deferred income taxes (7 ) (56 ) Loss on disposition of assets 10 18 Unrealized mark-to-market activities, net (103 ) 42 (Income) from unconsolidated investments in power plants (21 ) (12 ) Return on unconsolidated investments in power plants 20 6 Stock-based compensation expense 19 18 Other 1 5 Change in operating assets and liabilities: Accounts receivable 96 (87 ) Derivative instruments, net (114 ) (6 ) Other assets 97 27 Accounts payable and accrued expenses (119 ) 95 Settlement of non-hedging interest rate swaps 156 147 Other liabilities 25   2   Net cash provided by operating activities 608   536   Cash flows from investing activities: Purchases of property, plant and equipment (509 ) (511 ) Settlement of non-hedging interest rate swaps (156 ) (147 ) Return of investment in unconsolidated investment in power plants 5 — (Increase) decrease in restricted cash (32 ) 9 Purchases of deferred transmission credits (12 ) (16 ) Other 3   5   Net cash used in investing activities $ (701 ) $ (660 ) Cash flows from financing activities: Repayment of First Lien Term Loans $ (12 ) $ — Borrowings under First Lien Term Loans — 1,657 Repayments on NDH Project Debt — (1,283 ) Issuance of 2023 First Lien Notes — 1,200 Repayments on First Lien Credit Facility — (1,191 ) Borrowings from project financing, notes payable and other 312 223 Repayments of project financing, notes payable and other (53 ) (476 ) Capital contributions from noncontrolling interest holder — 34 Financing costs (6 ) (78 ) Stock repurchases (308 ) — Other 5   (4 ) Net cash provided by (used in) financing activities (62 ) 82   Net decrease in cash and cash equivalents (155 ) (42 ) Cash and cash equivalents, beginning of period 1,252   1,327   Cash and cash equivalents, end of period $ 1,097   $ 1,285     Cash paid during the period for: Interest, net of amounts capitalized $ 565 $ 509 Income taxes $ 14 $ 15   Supplemental disclosure of non-cash investing and financing activities: Change in capital expenditures included in accounts payable $ (3 ) $ (13 ) Additions to property, plant and equipment through assumption of long-term note payable $ 8 $ — __________ (1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations.REGULATION G RECONCILIATIONS Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Recurring 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, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, 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 Recurring 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, working capital and other adjustments. Adjusted Recurring Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies. Commodity Margin Reconciliation The following table reconciles our Commodity Margin to its U.S. GAAP results for the three months ended September 30, 2012 and 2011 (in millions):   Three Months Ended September 30, 2012         Consolidation   AndWestTexasNorthSoutheastEliminationTotal Commodity Margin(1) $ 330 $ 218 $ 266 $ 83 $ — $ 897 Add: Mark-to-market commodity activity, net and other(2)(3) (40 ) 249 (26 ) 27 (8 ) 202 Less: Plant operating expense 88 49 51 29 (10 ) 207 Depreciation and amortization expense 52 35 33 21 (1 ) 140 Sales, general and other administrative expense 9 12 8 8 (1 ) 36 Other operating expenses(4) 10 1 6 (1 ) 2 18 (Income) from unconsolidated investments in power plants —   —   (7 ) —   —   (7 ) Income from operations $ 131   $ 370   $ 149   $ 53   $ 2   $ 705     Three Months Ended September 30, 2011ConsolidationAndWestTexasNorthSoutheastEliminationTotal Commodity Margin(1) $ 329 $ 162 $ 259 $ 75 $ — $ 825 Add: Mark-to-market commodity activity, net and other(2)(3) 20 (21 ) (11 ) — (8 ) (20 ) Less: Plant operating expense 94 50 44 33 (9 ) 212 Depreciation and amortization expense 52 34 36 22 (1 ) 143 Sales, general and other administrative expense 10 10 7 7 (1 ) 33 Other operating expenses(4) 11 (1 ) 7 — 2 19 (Income) from unconsolidated investments in power plants —   —   (5 ) —   —   (5 ) Income from operations $ 182   $ 48   $ 159   $ 13   $ 1   $ 403   Commodity Margin Reconciliation (continued) The following table reconciles our Commodity Margin to its U.S. GAAP results for the nine months ended September 30, 2012 and 2011 (in millions):   Nine Months Ended September 30, 2012         Consolidation   AndWestTexasNorthSoutheastEliminationTotal Commodity Margin(1) $ 748 $ 472 $ 591 $ 212 $ — $ 2,023 Add: Mark-to-market commodity activity, net and other(2)(5) (80 ) 66 (17 ) (5 ) (22 ) (58 ) Less: Plant operating expense 281 189 154 98 (23 ) 699 Depreciation and amortization expense 151 104 100 66 (3 ) 418 Sales, general and other administrative expense 23 36 22 23 — 104 Other operating expenses(4) 30 4 21 2 1 58 (Income) from unconsolidated investments in power plants —   —   (21 ) —   —   (21 ) Income from operations $ 183   $ 205   $ 298   $ 18   $ 3   $ 707     Nine Months Ended September 30, 2011ConsolidationAndWestTexasNorthSoutheastEliminationTotal Commodity Margin(1) $ 798 $ 357 $ 578 $ 188 $ — $ 1,921 Add: Mark-to-market commodity activity, net and other(2)(5) 36 (54 ) (12 ) (4 ) (23 ) (57 ) Less: Plant operating expense 297 193 136 107 (22 ) 711 Depreciation and amortization expense 140 99 102 67 (3 ) 405 Sales, general and other administrative expense 29 33 19 18 — 99 Other operating expenses(4) 30 2 23 3 (1 ) 57 (Income) from unconsolidated investments in power plants —   —   (12 ) —   —   (12 ) Income (loss) from operations $ 338   $ (24 ) $ 298   $ (11 ) $ 3   $ 604   __________ (1) Our North segment includes Commodity Margin related to Riverside Energy Center, LLC, of $32 million and $31 million for the three months ended September 30, 2012 and 2011, respectively, and $64 million and $62 million for the nine months ended September 30, 2012 and 2011, respectively.(2) Mark-to-market commodity activity represents the change in the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.(3) Includes $16 million and $11 million of lease levelization for the three months ended September 30, 2012 and 2011, respectively, and $4 million of amortization expense for each of the three months ended September 30, 2012 and 2011.(4) Excludes $4 million and $3 million of RGGI compliance and other environmental costs for the three months ended September 30, 2012 and 2011, respectively, and $9 million and $7 million for the nine months ended September 30, 2012 and 2011, respectively, which are components of Commodity Margin.(5) Includes $7 million and $15 million of lease levelization and $11 million and $5 million of amortization expense for the nine months ended September 30, 2012 and 2011, respectively.Consolidated Adjusted EBITDA Reconciliation In the following table, we have reconciled our Adjusted EBITDA and Adjusted Recurring Free Cash Flow to our net income (loss) attributable to Calpine for the three and nine months ended September 30, 2012 and 2011, as reported under U.S. GAAP.   Three Months Ended September 30,   Nine Months Ended September 30,2012   20112012   2011(in millions) Net income (loss) attributable to Calpine $ 437 $ 190 $ 99 $ (177 ) Net income attributable to the noncontrolling interest — — — 1 Income tax expense (benefit) 81 20 23 (45 ) Debt extinguishment costs and other (income) expense, net 6 — 26 108 Loss on interest rate derivatives — 3 14 149 Interest expense, net of interest income 181   190   545   568   Income from operations $ 705 $ 403 $ 707 $ 604 Add: Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization expense, excluding deferred financing costs(1) 140 143 419 406 Major maintenance expense 31 33 158 169 Operating lease expense 9 9 26 26 Unrealized (gain) loss on commodity derivative mark-to-market activity (219 ) 9 49 48 Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) 7 9 23 30 Stock-based compensation expense 6 6 19 18 Loss on dispositions of assets 5 8 9 17 Acquired contract amortization 4 4 11 5 Other 18   14   13   24   Total Adjusted EBITDA $ 706   $ 638   $ 1,434   $ 1,347   Less: Lease payments 9 9 26 26 Major maintenance expense and capital expenditures(4) 43 72 298 335 Cash interest, net(5) 190 194 571 587 Cash taxes (1 ) 1 10 11 Other 2   1   6   7   Adjusted Recurring Free Cash Flow(6) $ 463   $ 361   $ 523   $ 381     Weighted average shares of common stock outstanding (diluted, in thousands) 465,953   489,062   474,131   486,363   Adjusted Recurring Free Cash Flow Per Share (Diluted) $ 0.99   $ 0.74   $ 1.10   $ 0.78   _________ (1) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets.(2) Included on our Consolidated Condensed Statements of Operations in (income) from unconsolidated investments in power plants.(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2012, and $1 million for each of the three and nine months ended September 30, 2011.(4) Includes $19 million and $150 million in major maintenance expense for the three and nine months ended September 30, 2012, respectively, and $24 million and $148 million in maintenance capital expenditures for the three and nine months ended September 30, 2012, respectively. Includes $36 million and $174 million in major maintenance expense for the three and nine months ended September 30, 2011, respectively, and $36 million and $161 million in maintenance capital expenditures for the three and nine months ended September 30, 2011, 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 $4 million and a decrease in working capital of $16 million for the three and nine months ended September 30, 2012, respectively, and increases in working capital of $166 million and $21 million for the three and nine months ended September 30, 2011, respectively. Adjusted Recurring Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance.Consolidated Adjusted EBITDA Reconciliation (continued) In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and nine months ended September 30, 2012 and 2011. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.   Three Months Ended September 30,   Nine Months Ended September 30,2012   20112012   2011(in millions) Commodity Margin $ 897 $ 825 $ 2,023 $ 1,921 Other revenue 3 4 9 11 Plant operating expense(1) (167 ) (166 ) (518 ) (512 ) Sales, general and administrative expense(2) (34 ) (30 ) (94 ) (85 ) Other operating expenses(3) (9 ) (11 ) (30 ) (30 ) Adjusted EBITDA from unconsolidated investments in power plants(4) 14 15 44 42 Other 2   1   —   —   Adjusted EBITDA $ 706   $ 638   $ 1,434   $ 1,347   _________ (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, RGGI compliance 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 Recurring Free Cash Flow Reconciliation for GuidanceFull Year 2012 Range:        Low                 High     (in millions) GAAP Net Income (1) $ 250 $ 300 Plus: Debt extinguishment costs 12 12 Loss on interest rate derivatives 14 14 Interest expense, net of interest income 760 760 Depreciation and amortization expense 575 575 Major maintenance expense 205 205 Operating lease expense 35 35 (Gain) on sale of assets (210 ) (210 ) Other(2) 84   84   Adjusted EBITDA $ 1,725 $ 1,775 Less: Operating lease payments 35 35 Major maintenance expense and maintenance capital expenditures(3) 350 350 Accelerated parts purchases to support upgrades(4) 30 30 Recurring cash interest, net(5) 770 770 Cash taxes 10 10 Other 5   5   Adjusted Recurring Free Cash Flow $ 525   $ 575   Non-recurring interest rate swap payments(6) $ (156 ) $ (156 ) _________ (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 $200 million and maintenance capital expenditures of $150 million. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt.(4) Incremental impact on 2012 maintenance capital expenditures related to acceleration of future turbine upgrades into 2012 and deferral of use of on-hand parts to post-2012 periods.(5) Includes fees for letters of credit, net of interest income.(6) Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been retired.Full Year 2013 Range1:     Low                 High     (in millions) GAAP Net Income (2) $ 135 $ 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(3) 65   65 Adjusted EBITDA $ 1,760 $ 1,960 Less: Operating lease payments 35 35 Major maintenance expense and maintenance capital expenditures(4) 370 370 Recurring cash interest, net(5) 755 755 Cash taxes 15 15 Other 10   10 Adjusted Recurring Free Cash Flow $ 575 $ 775 _________ (1) 2013 guidance range reflects all pending acquisition and divestiture activity, including today's announced sale of Broad River Energy Center, which we estimate would have contributed approximately $40 million of Adjusted EBITDA in 2013.(2) For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil.(3) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items.(4) 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 non-recurring IT system upgrade.(5) Includes fees for letters of credit, net of interest income.OPERATING PERFORMANCE METRICS The table below shows the operating performance metrics for continuing operations:   Three Months Ended September 30,   Nine Months Ended September 30,2012   20112012   2011Total MWh generated (in thousands)(1) 32,291 28,400 87,027 65,921 West 9,817 6,540 24,211 16,189 Texas 10,025 10,833 28,257 24,019 Southeast 5,821 5,918 17,744 14,489 North 6,628 5,109 16,815 11,224   Average availability 97.7 % 95.9 % 91.5 % 89.8 % West 98.5 % 91.2 % 91.2 % 86.4 % Texas 97.2 % 98.2 % 90.4 % 88.8 % Southeast 98.3 % 96.6 % 94.4 % 92.0 % North 96.9 % 97.5 % 90.5 % 92.3 %   Average capacity factor, excluding peakers(1) 61.0 % 53.8 % 55.7 % 42.9 % West 70.7 % 47.4 % 58.7 % 39.6 % Texas 64.7 % 70.1 % 61.3 % 52.5 % Southeast 48.4 % 48.9 % 49.6 % 41.0 % North 56.1 % 43.4 % 49.7 % 34.4 %   Steam adjusted heat rate (mmbtu/kWh) 7,404 7,464 7,357 7,434 West 7,313 7,479 7,267 7,488 Texas 7,211 7,296 7,149 7,256 Southeast 7,325 7,344 7,302 7,323 North 7,943 8,003 7,918 7,939 ________ (1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us. Calpine CorporationNorma F. Dunn, 713-830-8883 (Media Relations)norma.dunn@calpine.comBryan Kimzey, 713-830-8777 (Investor Relations)bryan.kimzey@calpine.com