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Calpine Reports Fourth Quarter and Full Year 2011 Results, Tightens 2012 Guidance

02/10/2012

Summary of 2011 Financial Results (in millions):

Three Months Ended December 31, Year Ended December 31,
2011 2010 % Change 2011 2010 % Change
Operating Revenues $ 1,459 $ 1,471

(0.8

)

%

$ 6,800 $ 6,545 3.9 %
Commodity Margin $ 553 $ 576

(4.0

)

%

$ 2,474 $ 2,391 3.5 %
Adjusted EBITDA $ 379 $ 386

(1.8

)

%

$ 1,726 $ 1,712 0.8 %
Adjusted Recurring Free Cash Flow $ 108 $ 59 83.1 % $ 489 $ 558

(12.4

)

%

Net Income (Loss)1 $ (13 ) $ (24 ) $ (190 ) $ 31
Net Income (Loss), As Adjusted2 $ (43 ) $ 62 $ (13 ) $ 87

Tightening 2012 Full Year Guidance:

Prior Guidance

(as of October 2011)

Current Guidance
(in millions)
Adjusted EBITDA $1,550 - 1,750 $1,600 - 1,725
Adjusted Recurring Free Cash Flow $375 - 575 $ 425 - 550

Recent Achievements:

  • Operations:
    — Produced 94 million MWh3 of electricity in 2011
    — Delivered excellent 2011 fleetwide forced outage factor of 2.5%
    — Achieved 98% fleetwide starting reliability in 2011
  • Commercial:
    — Signed five-year contract for the full output of our Auburndale Peaking Energy Center
  • Capital Structure:
    — Continued execution of share repurchase program: $124 million (more than 40%) complete
    — Increased CDHI letter of credit facility by $100 million and extended its maturity to 2016
    — Resolved and formally closed bankruptcy case

HOUSTON--(BUSINESS WIRE)--Feb. 10, 2012-- Calpine Corporation (NYSE:CPN): Calpine Corporation(NYSE:CPN) today reported fourth quarter 2011 Adjusted EBITDA of $379 million, compared to $386 million in the prior year period, and Adjusted Recurring Free Cash Flow of $108 million, compared to $59 million in the prior year period. Net Loss1 for the fourth quarter narrowed to $13 million, or $0.03 per diluted share, compared to $24 million, or $0.05 per diluted share, in the prior year period. Net Loss, As Adjusted2, for the fourth quarter of 2011 was $43 million compared to Net Income, As Adjusted2, of $62 million in the prior year period, a decline primarily related to a reduction in income tax benefit associated with non-cash intraperiod tax allocations and an increase in various state and foreign jurisdiction income taxes.

Full year 2011 Adjusted EBITDA was $1,726 million, compared to $1,712 million in the prior year. Full year 2011 Adjusted Recurring Free Cash Flow was $489 million, compared to $558 million in the prior year, a decrease mainly due to higher scheduled major maintenance expense and capital expenditures in 2011 compared to 2010. Net Loss1 for the year was $190 million, or $0.39 per diluted share, compared to Net Income1 of $31 million, or $0.06 per diluted share, in the prior year. Net Loss, As Adjusted2, for 2011 was$13 million compared to Net Income, As Adjusted2, of $87 million in the prior year, a decline primarily due to a reduction in income tax benefit, as previously discussed.

“We successfully delivered on our 2011 financial and operational commitments to our shareholders and have effectively positioned the company for continued growth in long term shareholder value,” said Jack Fusco , Calpine's President and Chief Executive Officer. “Our focus on operational excellence, commercial optimization of our fleet of power plants and efficient capital allocation has enabled us to continue to deliver results during a period of volatility in the power and commodity markets and lethargic economic recovery.

“With the successes of 2011 behind us, we have turned our attention to 2012. It has been our thesis that unlike generators dependent on dark spreads resulting from higher natural gas prices in power markets where gas price is on the margin, Calpine's modern, efficient and cost-effective fleet of natural gas-fired plants allows it to benefit even in extended periods of low natural gas prices due to the efficiency of our fleet and the increase in generation volume as customers switch from coal to gas for economic reasons. For 2012, we expect to offset the collapse in natural gas prices with increased generation volume due to unprecedented levels of coal-to-gas switching and through opportunistic hedging, thus demonstratingCalpine's resilience despite low natural gas prices. In short, we have seen our thesis begin to play out during the recent steep decline in natural gas prices. As a result and due to solid execution by our plants and commercial operations group, we are able to tighten our 2012 full year guidance for Adjusted EBITDA to a range of $1,600 million to $1,725 million and for Adjusted Recurring Free Cash Flow to a range of $425 million to $550 million. Finally, in 2012 we will continue to make financially disciplined capital allocation decisions to enhance shareholder value through additional growth opportunities or additional share repurchases.”

SUMMARY OF FINANCIAL PERFORMANCE

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2011 was $379 million compared to $386 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily due to:

  • A $23 million decline in Commodity Margin, driven largely by a North segment decrease of $19 millionprimarily due to a decline in capacity payments received for our Mid-Atlantic portfolio as determined by the PJM capacity auction and
  • A $14 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010, partially offset by
  • A $24 million decrease in plant operating expense4 related to lower routine maintenance expense compared to the prior year period and insurance recoveries recognized in the fourth quarter of 2011.

Net Loss1 declined to $13 million for the fourth quarter of 2011, compared to $24 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, was $43 million in the fourth quarter of 2011 compared to Net Income, As Adjusted, of $62 million in the prior year period. The year-over-year decline in Net Income, As Adjusted, was driven largely by:

lower Commodity Margin, as previously discussed, and
a reduction in income tax benefit related to the application of non-cash intraperiod tax allocations and an increase in various state and foreign jurisdiction income taxes, offset in part by
+ a decrease in major maintenance expense resulting from our plant outage schedule in the fourth quarter of 2011 versus the prior year period.

2011 Full Year Results

Adjusted EBITDA for the year ended December 31, 2011, was $1,726 million compared to $1,712 million in the prior year. The year-over-year increase in Adjusted EBITDA was primarily the result of:

  • An $83 million increase in Commodity Margin, which was due in large part to:
+ North segment: Increase of $169 million, primarily driven by the acquisition of our Mid-Atlantic plants which closed on July 1, 2010, and York Energy Center achieving commercial operations in March 2011, partially offset by
Texas segment: Decline of $35 million due primarily to unplanned outages during an extreme cold weather event in early February 2011, as well as the sale of a 25% undivided interest in our Freestone power plant in December 2010, partially offset by significantly higher power prices driven by extreme heat and drought conditions in the third quarter of 2011 on our relatively small open position, and
Southeast segment: Decrease of $32 million due to the expiration of certain hedge contracts that benefited 2010 and the negative impact of unscheduled outages that occurred during the second and third quarters of 2011.
  • In addition, normal recurring plant operating expense4 declined by $16 million, largely driven by lower expenses among our legacy plants, partially offset by a full year of expense incurred by our Mid-Atlantic fleet, which was acquired as of July 1, 2010.
  • Partially offsetting these year-over-year improvements, Adjusted EBITDA was negatively impacted by a $75 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of ourColorado plants in December 2010.

Net Loss1 was $190 million for the year ended December 31, 2011, compared to Net Income1 of $31 million in the prior year. As detailed in Table 1, Net Loss, As Adjusted, was $13 million in 2011 compared to Net Income, As Adjusted, of $87 million in the prior year. The year-over-year decrease was primarily due to:

a reduction in income tax benefit, as previously discussed, and
higher major maintenance expense in connection with our plant outage schedule, partially offset by
+ higher Commodity Margin, as previously discussed, and
+ a decrease in depreciation and amortization expense due to rotable parts being fully depreciated for some of our units, which was partially offset by an increase related to our Mid-Atlantic assets acquired in 2010.

____________

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 unconsolidated power plants and plants owned but not operated by Calpine.

4 Decrease in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and acquisition-related 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, 2011and 2010.

Table 1: Summarized Consolidated Condensed Statements of Operations

(Unaudited)
Three Months Ended December 31, Year Ended December 31,
2011 2010 2011 2010
(in millions)
Operating revenues $ 1,459 $ 1,471 $ 6,800 $ 6,545
Operating expenses 1,272 1,406 6,021 5,663
Impairment losses, net gain on sale of assets, and (income) loss from unconsolidated investments in power plants (9 ) (24 ) (21 ) (19 )
Income from operations 196 89 800 901
Net interest expense, (gain) loss on interest rate derivatives, net, debt extinguishment costs, and other (income) expense 186 381 1,011 1,131
Income (loss) before income taxes and discontinued operations 10 (292 ) (211 ) (230 )
Income tax expense (benefit) 23 (106 ) (22 ) (68 )
Loss before discontinued operations (13 ) (186 ) (189 ) (162 )
Discontinued operations, net of tax expense 162 193
Net income (loss) $ (13 ) $ (24 ) $ (189 ) $ 31
Net income attributable to the noncontrolling interest (1 )
Net income (loss) attributable to Calpine $ (13 ) $ (24 ) $ (190 ) $ 31
Discontinued operations, net of tax expense (162 ) (193 )
Debt extinguishment costs(1) 64 94 91
(Gain) on sale of assets, net(1) (119 ) (119 )
Impairment losses(1) 97 116
Unrealized MtM (gain) loss on derivatives(1) (2) (72 ) 153 (30 ) 56
Other items(1) (3) 42 53 113 105
Net Income (Loss), As Adjusted(4) $ (43 ) $ 62 $ (13 ) $ 87

____________

(1)

Shown net of tax, assuming a 0% effective tax rate for these items.

(2)

Represents unrealized mark-to-market (MtM) (gain) loss on contracts that did not qualify as hedges under the hedge accounting guidelines or qualified under the hedge accounting guidelines and the hedge accounting designation had not been elected.

(3)

Other items include realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps totaling $42 million and $189 million for the three months and year ended December 31, 2011, respectively, and $42 million and $69 million for the three months and year ended December 31, 2010, respectively. Other items for the year ended December 31, 2011, also include a $(76) million federal deferred income tax benefit associated with our election to consolidate our CCFC subsidiary for tax reporting purposes. Other items for the three months and year ended December 31, 2010, also include $11 million and $36 million, respectively, in costs associated with the acquisition of our Mid-Atlantic fleet.

(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,
2011 2010 Variance 2011 2010 Variance
West $ 263 $ 271 (8 ) $ 1,061 $ 1,080 (19 )
Texas 112 104 8 469 504 (35 )
North 126 145 (19 ) 704 535 169
Southeast 52 56 (4 ) 240 272 (32 )
Total $ 553 $ 576 (23 ) $ 2,474 $ 2,391 83

West Region

Fourth Quarter: Commodity Margin in our West segment decreased by $8 million in the fourth quarter of 2011 compared to the prior year period. Primary drivers included:

lower average hedge prices in the fourth quarter of 2011 and
lower generation volume associated with weaker market conditions, partially offset by
+ the positive impacts from origination activities in 2011.

Full Year: Commodity Margin in our West segment declined by $19 million in 2011 compared to 2010. Primary drivers included:

lower spark spreads resulting from an increase in hydroelectric generation in California in 2011,

an unscheduled outage at OMEC during the second quarter of 2011, partially offset by
+

higher Commodity Margin contribution from hedges and

+ the positive impacts from origination activities in 2011.

Texas Region

Fourth Quarter: Commodity Margin in our Texas segment increased by $8 million in the fourth quarter of 2011 compared to the prior year period. Primary drivers included:

+ higher Commodity Margin contribution from hedges in the fourth quarter of 2011 and
+ higher generation volume during off-peak hours associated with higher market heat rates, partially offset by

a decrease in Commodity Margin from our steam products, largely driven by an outage experienced by one of our steam hosts during the quarter.

Full Year: Commodity Margin in our Texas segment decreased by $35 million in 2011 compared to 2010. Primary drivers included:

unplanned outages at some of our power plants caused by an extreme cold weather event in February 2011 that required us to purchase physical replacement power at prices substantially above our hedged prices, and

the sale of a 25% undivided interest in the assets of our Freestone power plant, as previously noted, partially offset by
+ significantly higher power prices driven by extreme heat and drought conditions, which increased spark spreads during the third quarter of 2011 on our relatively small open position, and
+ higher Commodity Margin contribution from hedges.

North Region

Fourth Quarter: Commodity Margin in our North segment decreased by $19 million in the fourth quarter of 2011 compared to the prior year period. Primary drivers included:

a decline in capacity payments received for our Mid-Atlantic portfolio as determined by the PJM capacity auction and

a decline in Commodity Margin related to sales of natural gas in the fourth quarter of 2010, when natural gas prices temporarily rose high enough that selling a portion of our natural gas inventory was more profitable than producing power, partially offset by
+ an increase in Commodity Margin at our York Energy Center, which achieved commercial operations in March 2011.

Full Year: Commodity Margin in our North segment increased by $169 million in 2011 compared to 2010. Primary drivers included:

+ the acquisition of our Mid-Atlantic fleet as of July 1, 2010, and
+ York Energy Center achieving commercial operations in March 2011, as previously discussed, partially offset by

lower capacity prices in the second half of 2011 compared to the same period in 2010.

Southeast Region

Fourth Quarter: Commodity Margin in our Southeast segment declined by $4 million in the fourth quarter of 2011 compared to the prior year period. Primary drivers included:

the expiration of certain hedge contracts that benefited the fourth quarter of 2010 and

lower spark spreads resulting from milder weather in the fourth quarter of 2011 as compared to the prior year period.

Full Year: Commodity Margin in our Southeast segment decreased by $32 million in 2011 compared to 2010. Primary drivers included:

the expiration of certain hedge contracts that benefited 2010 and

the negative impact of unscheduled outages that occurred during the second and third quarters of 2011.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity

December 31, December 31,
2011 2010
(in millions)
Cash and cash equivalents, corporate(1) $ 946 $ 1,058
Cash and cash equivalents, non-corporate 306 269
Total cash and cash equivalents 1,252 1,327
Restricted cash 194 248
Revolving facility(ies) availability(2) 560 623
Letter of credit availability(3) 7 35
Total current liquidity availability $ 2,013 $ 2,233

__________

(1)

Includes $34 million and $6 million of margin deposits held by us posted by our counterparties at December 31, 2011 and 2010, respectively.

(2)

On December 10, 2010, we executed our $1.0 billion Corporate Revolving Facility, which replaced our $1.0 billion revolver under our First Lien Credit Facility. At December 31, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued under our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010, include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. The balance at December 31, 2010, includes availability under the NDH Project Debt, which was retired on March 9, 2011.

(3)

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 $2.0 billion as of December 31, 2011, down modestly from $2.2 billion atDecember 31, 2010.

Cash flows provided by operating activities for the year ended December 31, 2011, resulted in net inflows of $775 million compared to $929 million for the prior year. The change in cash flows from operating activities was primarily due to a decrease in working capital during 2010 resulting from reduced margin requirements on commodity transactions, partially offset by an increase in income from operations, adjusted for non-cash items.

Cash flows used in investing activities were $836 million in 2011, compared to $831 million in 2010. The activity in 2011 was driven largely by capital expenditures, including our growth projects at our Russell City, Los Esteros and York Energy Centers and our turbine upgrade program. In addition, in 2011 we paid$189 million associated with the settlement of non-hedging interest rate swaps.

Cash flows used in financing activities were $14 million in 2011, primarily due to the corporate and subsidiary debt refinancings completed in the first half of 2011, as well as the issuance of project debt to fund our Russell City and Los Esteros construction projects. In addition, during 2011 we repurchased$119 million of common stock under our share repurchase program.

Adjusted Recurring Free Cash Flow was $489 million for the year ended December 31, 2011, compared to$558 million for the prior year. Despite a $14 million increase in Adjusted EBITDA during the year, Adjusted Recurring Free Cash Flow declined primarily due to an $80 million increase in major maintenance costs (including expense and capital expenditures) resulting from our plant outage schedule.

We continue to improve the quality of our liquidity, most recently by increasing our CDHI letter of credit facility from $200 million to $300 million and extending its maturity from December 2012 to January 2016. In addition, in an effort to further simplify our capital structure, during the fourth quarter, we executed purchase agreements to purchase two of the third party equity interests in our subsidiary associated with our California peaking plants. The closing of these transactions are subject to FERC approval and the terms of the agreements.

SHARE REPURCHASE PROGRAM

During the third quarter of 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. The announced program did not specify an expiration date. Through the issuance of this release, we had repurchased approximately $124 million of stock, completing more than 40% of the aggregate amount authorized under the program, having repurchased a total of 8.5 million shares of our common stock at an average price of $14.60 per share.

PLANT DEVELOPMENT

North:

PJM: Given our view of the potential need for new generation in the PJM region, driven both by market growth and the expected impacts of environmental regulations on older, less efficient generation within the region, we view the PJM region as a market with an attractive growth profile. In order to capitalize on this outlook, we are actively pursuing a set of development options, including projects at:

  • Garrison (Delaware) : Actively permitting 618 MW of new combined-cycle capacity at a development site secured by a lease option with the City of Dover. PJM's system impact study for the first phase (309 MW) and the feasibility study for the second phase (309 MW) have been completed. Both studies are being reviewed internally. Environmental permitting, site development planning and development engineering are underway.
  • Edge Moor (Delaware): A nominal 300 MW combined-cycle development project located at our Edge Moor facility which will leverage existing infrastructure. PJM is currently conducting a system impact study which will provide a detailed report on the project's interconnection costs.

Mankato Power Plant Expansion Proposal: In March 2011, Xcel Energy Inc. (Xcel) filed an application with the Minnesota Public Utilities Commission (MPUC) to construct a new 700 MW natural gas-fired, combined-cycle facility to be located at its existing Black Dog site. The MPUC required Xcel to also seek potential third party alternatives so that MPUC could compare any offers to Xcel's proposal. We proposed to expand our Mankato power plant, a 375 MW natural gas-fired, combined-cycle power plant, by 345 MW under a PPA with Xcel. We believe that our proposal is less expensive, environmentally preferable and a closer match to Xcel's demand forecast than its self-build proposal. The matter was referred to a contested case hearing. Xcel subsequently filed to withdraw its application for the Black Dog expansion, which may affect the status of our proposed Mankato expansion. Xcel's request is currently pending review by an administrative law judge. A decision is not expected until the second quarter of 2012.

West:

Russell City Energy Center: The Russell City Energy Center is under construction and continues to move forward with expected COD in 2013. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. We are in possession of all required approvals and permits, and we closed on construction financing on June 24, 2011. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&Eunder a ten-year PPA.

Los Esteros: 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 308 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 ten-year PPA and related agreements with PG&E have received all of the necessary approvals and licenses, which are now effective. The California Energy Commission has renewed our license and emission limits, which is final. The Bay Area Air Quality Management District issued its renewal of the Authority to Construct. We began construction in the second quarter of 2011 and obtained construction financing on August 23, 2011. We expect to achieve COD in 2013.

Geysers Assets Expansion: We continue to look to expand our production from our Geysers assets. Beginning in the fourth quarter of 2009, we conducted an exploratory drilling program, which effectively proved the commercial viability of the steam field in the northern part of our Geysers assets. We have received Conditional Use Permits from Sonoma County and are pursuing the additional required permitting. We are pursuing commercial arrangements which will need to be in place prior to commencing expansion activities. We continue to believe our northern Geysers assets have potential for development. In the meantime, we have connected certain test wells to our existing power plants to capture incremental production from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion.

ERCOT:

Channel and Deer Park Expansions: We continue to evaluate the ERCOT market for expansion opportunities based on tightening reserve margins and potential impact of EPA regulations on generation inTexas. 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 the overall efficiency. In September 2011, we filed an air permit application with the Texas Commission on Environmental Quality (TCEQ) and the EPA to expand the Deer Park Energy Center by approximately 275 MW. In November 2011, we filed similar permits with the TCEQ and the EPA to expand the Channel Energy Center by approximately 275 MW.

All Markets:

Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through December 31, 2011, we have completed the upgrade of ten Siemens and five GE turbines and have agreed to upgrade approximately six additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 275 MW. This upgrade program began in the fourth quarter of 2009 and is scheduled through 2014. The upgraded turbines have been operating with heat rates consistent with expectations.

OPERATIONS UPDATE

2011 Power Operations Achievements:

  • Safety Performance:
    — First quartile lost-time incident rate of 0.27
  • Availability Performance:
    — Met fleetwide forced outage factor target of 2.5% in 2011
    — Achieved strong fourth quarter fleetwide starting reliability of 99%
  • Cost Performance:
    — Reduced 2011 normal, recurring plant operating expense for legacy fleet by $32 million compared to 2010
  • Geothermal Generation:
    — Provided approximately 6 million MWh of renewable baseload generation with 94% capacity factor during 2011
  • Natural Gas-fired Generation:
    — Increased fleetwide capacity factor in fourth quarter of 2011 to 49% compared to 41% in the prior year period
    — Achieved 100% starting reliability and 0.14% forced outage factor at Hidalgo Energy Center for full year 2011
    — Achieved 100% starting reliability and 0% forced outage factor at the King City Cogeneration Plant during the fourth quarter of 2011

2011 Commercial Operations Achievements:

  • Customer-oriented Growth:
    — Signed ten-year contract with Entergy Texas, Inc., to provide 485 MW of power from our Carville Energy Center
    — Signed new contract with Southern California Edison for our Pastoria Energy Center: Added energy toll (750 MW, 2013 - 2015) and extended resource adequacy (715 MW, 2014 - 2015)
    — Signed a five-year contract with Tampa Electric Company for the full output of our Auburndale Peaking Energy Center

FINANCIAL OUTLOOK

Full Year 2012
(in millions)
Adjusted EBITDA $ 1,600 - 1,725
Less:
Operating lease payments 35
Major maintenance expense and capital expenditures(1) 350
Recurring cash interest, net 770
Cash taxes 10
Other 10
Adjusted Recurring Free Cash Flow $ 425 - 550
Non-recurring interest rate swap payments(2) $ 150
Growth capital expenditures (net of debt funding) $ 10
Riverside sale proceeds $ 392

__________

(1)

Includes projected major maintenance expense of $185 million and maintenance capital expenditures of $165 million in 2012. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt.

(2)

Interest payments related to legacy LIBOR hedges associated with floating rate first lien credit facility, which has been refinanced.

As detailed above, today we are tightening our 2012 guidance, including raising the lower end. We now project Adjusted EBITDA of $1,600 million to $1,725 million and Adjusted Recurring Free Cash Flow of$425 million to $550 million. We also expect to invest $10 million, net of debt funding, in growth-related projects during the year. Though our construction projects at Russell City and Los Esteros will 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, we also expect to receive approximately $392 million during the fourth quarter of 2012 from one of our customers related to their intended exercise of a call option to purchase our Riverside Energy Center in 2013.

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 2011 on Friday, February 10, 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 (800) 447-0521 in the United States or (847) 413-3238 outside the United States. The confirmation code is 31536947. 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 United States or (630) 652-3042 outside the United States and providing confirmation code 31536947. Presentation materials to accompany the conference call will be available on our website on February 10, 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 andCanada. 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 Annual Report on Form 10-K for the year ended December 31, 2011, has been filed with theSecurities 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, 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;
  • Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regional laws and regulations including those related to the environment and derivative transactions;
  • The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated under it;
  • Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, Term Loan, New Term Loan, CCFC Notes and other existing financing obligations;
  • Risks associated with the continued economic and financial conditions affecting certain countries inEurope 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; and
  • Other risks identified in this press release and 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 STATEMENTS OF OPERATIONS
(in millions, except share and per share amounts)
(Unaudited)
Three Months Ended December 31, Year Ended December 31,
2011 2010 2011 2010
Operating revenues $ 1,459 $ 1,471 $ 6,800 $ 6,545
Operating expenses:
Fuel and purchased energy expense 879 958 4,349 3,974
Plant operating expense 193 238 904 868
Depreciation and amortization expense 145 147 550 570
Sales, general and other administrative expense 32 38 131 151
Other operating expenses 23 25 87 100
Total operating expenses 1,272 1,406 6,021 5,663
Impairment losses 97 116
(Gain) on sale of assets, net (119 ) (119 )
(Income) from unconsolidated investments in power plants (9 ) (2 ) (21 ) (16 )
Income from operations 196 89 800 901
Interest expense 185 178 760 813
(Gain) loss on interest rate derivatives, net (4 ) 136 145 223
Interest (income) (2 ) (3 ) (9 ) (11 )
Debt extinguishment costs 64 94 91
Other (income) expense, net 7 6 21 15
Income (loss) before income taxes and discontinued operations 10 (292 ) (211 ) (230 )
Income tax expense (benefit) 23 (106 ) (22 ) (68 )
Income (loss) before discontinued operations (13 ) (186 ) (189 ) (162 )
Discontinued operations, net of tax expense 162 193
Net income (loss) (13 ) (24 ) (189 ) 31
Net (income) attributable to the noncontrolling interest (1 )
Net income (loss) attributable to Calpine $ (13 ) $ (24 ) $ (190 ) $ 31
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 482,468 486,106 485,381 486,044
Income (loss) before discontinued operations attributable to Calpine $ (0.03 ) $ (0.38 )

$

(0.39 ) $ (0.33 )
Discontinued operations, net of tax expense attributable to Calpine 0.33 0.39
Net income (loss) per common share attributable to Calpine - basic $ (0.03 ) $ (0.05 )

$

(0.39 ) $ 0.06
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 482,468 487,589 485,381 487,294
Income (loss) before discontinued operations attributable to Calpine $ (0.03 ) $ (0.38 )

$

(0.39 ) $ (0.33 )
Discontinued operations, net of tax expense attributable to Calpine 0.33 0.39
Net income (loss) per common share attributable to Calpine - diluted $ (0.03 ) $ (0.05 )

$

(0.39 ) $ 0.06
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2011 and 2010
(in millions, except share and per share amounts)
2011 2010
ASSETS
Current assets:
Cash and cash equivalents $ 1,252 $ 1,327
Accounts receivable, net of allowance of $13 and $2 598 669
Margin deposits and other prepaid expense 193 221
Restricted cash, current 139 195
Derivative assets, current 1,051 725
Inventory and other current assets 329 292
Total current assets 3,562 3,429
Property, plant and equipment, net 13,019 12,978
Restricted cash, net of current portion 55 53
Investments 80 80
Long-term derivative assets 113 170
Other assets 542 546
Total assets $ 17,371 $ 17,256
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 435 $ 514
Accrued interest payable 200 132
Debt, current portion 104 152
Derivative liabilities, current 1,144 718
Income taxes payable 3 5
Other current liabilities 276 268
Total current liabilities 2,162 1,789
Debt, net of current portion 10,321 10,104
Deferred income tax liability, non-current 77
Long-term derivative liabilities 279 370
Other long-term liabilities 245 247
Total liabilities 13,007 12,587
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, 2011 and 2010
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 490,468,815 shares issued and 481,743,738 shares outstanding at December 31, 2011, and 444,883,356 shares issued and 444,435,198 shares outstanding at December 31, 2010 1 1
Treasury stock, at cost, 8,725,077 and 448,158 shares, respectively (125 ) (5 )
Additional paid-in capital 12,305 12,281
Accumulated deficit (7,699 ) (7,509 )
Accumulated other comprehensive loss (178 ) (125 )
Total Calpine stockholders' equity 4,304 4,643
Noncontrolling interest 60 26
Total stockholders' equity 4,364 4,669
Total liabilities and stockholders' equity $ 17,371 $ 17,256

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2011 and 2010

(in millions)

2011 2010
Cash flows from operating activities:
Net income (loss) $ (189 ) $ 31
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense(1) 587 615
Debt extinguishment costs 82 91
Deferred income taxes (21 ) (26 )
Impairment losses 116
(Gain) loss on sale of power plants and other, net 13 (314 )
Unrealized mark-to-market activity, net (30 ) 56
(Income) from unconsolidated investments in power plants (21 ) (16 )
Return on unconsolidated investments in power plants 6 11
Stock-based compensation expense 24 24
Other 6 1
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable 74 91
Derivative instruments, net 15 (52 )
Other assets 1 277
Accounts payable and accrued expenses 28 (43 )
Settlement of non-hedging interest rate swaps 189 69
Other liabilities 11 (2 )
Net cash provided by operating activities 775 929
Cash flows from investing activities:
Purchases of property, plant and equipment (683 ) (369 )
Proceeds from sale of power plants, interests and other 13 954
Purchase of Conectiv assets and BRSP, net of cash acquired (1,680 )
Cash acquired due to consolidation of OMEC 8
Settlement of non-hedging interest rate swaps (189 ) (69 )
Decrease in restricted cash 54 322
Purchase of deferred transmission credits (31 )
Other 3
Net cash used in investing activities

(836 )

(831 )
Cash flows from financing activities:
Borrowings under Term Loan and New Term Loan

1,657

Repayments on NDH Project Debt (1,283 )
Issuance of First Lien Notes 1,200 3,491
Repayments on First Lien Credit Facility (1,195 ) (3,477 )
Borrowings from project financing, notes payable and other 327 1,272
Repayments of project financing, notes payable and other (550 ) (937 )
Capital contributions from noncontrolling interest holder 33 17
Financing costs (81 ) (136 )
Stock repurchases (119 )
Refund of financing costs 10
Other (3 )
Net cash provided by (used in) financing activities (14 ) 240
Net increase (decrease) in cash and cash equivalents (75 ) 338
Cash and cash equivalents, beginning of period 1,327 989
Cash and cash equivalents, end of period $ 1,252 $ 1,327
Cash paid during the period for:
Interest, net of amounts capitalized $ 656 $ 635
Income taxes $ 18 $ 21
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable $ (24 ) $ 1
Liabilities assumed in BRSP acquisition $ $ 85

Conversion of project debt to noncontrolling interest

$ $ 11

__________

(1)

Includes depreciation and amortization included in fuel and purchased energy expense, interest expense and discontinued operations on our Consolidated 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 discontinued operations, net of tax expense, 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 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 earnings before 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 presented because our management uses this measure, among others, to make decisions about capital allocation. Adjusted Recurring Free Cash Flow is not intended to represent cash flows from operations 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.

Commodity Margin Reconciliation

The following table reconciles our Commodity Margin to its U.S. GAAP results for the three months endedDecember 31, 2011 and 2010 (in millions):

Three Months Ended December 31, 2011
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 263 $ 112 $ 126 $ 52 $ $ 553
Add: Mark-to-market commodity activity, net and other(1)(2) 77 (48 ) (1 ) 5 (9 ) 24
Less:
Plant operating expense 83 42 41 34 (7 ) 193
Depreciation and amortization expense 52 36 36 23 (2 ) 145
Sales, general and other administrative expense 14 10 5 4 (1 ) 32
Other operating expenses(3) 11 1 7 2 (1 ) 20
(Income) from unconsolidated investments in power plants (9 ) (9 )
Income (loss) from operations $ 180 $ (25 ) $ 45 $ (6 ) $ 2 $ 196
Three Months Ended December 31, 2010
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 271 $ 104 $ 145 $ 56 $ $ 576
Add: Mark-to-market commodity activity, net and other(1) 9 (59 ) 3 (9 ) (10 ) (66 )
Less:
Plant operating expense 87 68 55 36 (8 ) 238
Depreciation and amortization expense 52 37 35 25 (2 ) 147
Sales, general and other administrative expense 19 9 8 1 1 38
Other operating expenses(3) 16 7 2 (3 ) 22
Impairment losses 97 97
(Gain) on sale of assets, net (119 ) (119 )
(Income) from unconsolidated investments in power plants (2 ) (2 )
Income (loss) from operations $ 9 $ 50 $ 45 $ (17 ) $ 2 $ 89

The following table reconciles our Commodity Margin to its U.S. GAAP results for the years endedDecember 31, 2011 and 2010 (in millions):

Year Ended December 31, 2011
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 1,061 $ 469 $ 704 $ 240 $ $ 2,474
Add: Mark-to-market commodity activity, net and other(1)(2) 113 (102 ) (13 ) 1 (32 ) (33 )
Less:
Plant operating expense 380 235 177 141 (29 ) 904
Depreciation and amortization expense 192 135 138 90 (5 ) 550
Sales, general and other administrative expense 43 43 24 22 (1 ) 131
Other operating expenses(3) 41 3 30 5 (2 ) 77
(Income) from unconsolidated investments in power plants (21 ) (21 )
Income (loss) from operations $ 518 $ (49 ) $ 343 $ (17 ) $ 5 $ 800
Year Ended December 31, 2010
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 1,080 $ 504 $ 535 $ 272 $ $ 2,391
Add: Mark-to-market commodity activity, net and other(1) 69 89 21 22 (30 ) 171
Less:
Plant operating expense 351 285 138 123 (29 ) 868
Depreciation and amortization expense 207 150 111 109 (7 ) 570
Sales, general and other administrative expense 55 38 45 12 1 151
Other operating expenses(3) 59 2 28 4 (2 ) 91
Impairment losses 97 19 116
(Gain) on sale of assets, net (119 ) (119 )
(Income) from unconsolidated investments in power plants (16 ) (16 )
Income from operations $ 380 $ 237 $ 250 $ 27 $ 7 $ 901

__________

(1)

Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations for the three months and years ended December 31, 2011 and 2010.

(2)

Includes $(3) million and $12 million of lease levelization and $3 million and $8 million of contract amortization for the three months and year ended December 31, 2011, respectively, related to contracts that became effective in 2011.

(3)

Excludes RGGI compliance and other environmental costs of $3 million for each of the three months ended December 31, 2011 and 2010, respectively, and $10 million and $9 million for the years ended December 31, 2011 and 2010, respectively, which are components of Commodity Margin.

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 months and years ended December 31, 2011and 2010, as reported under U.S. GAAP.

Three Months Ended December 31, Year Ended December 31,
2011 2010 2011 2010
(in millions)
Net income (loss) attributable to Calpine $ (13 ) $ (24 ) $ (190 ) $ 31
Net income attributable to the noncontrolling interest 1
Discontinued operations, net of tax expense (162 ) (193 )
Income tax expense (benefit) 23 (106 ) (22 ) (68 )
Other (income) expense and debt extinguishment costs, net 7 70 115 106
(Gain) loss on interest rate derivatives, net (4 ) 136 145 223
Interest expense, net 183 175 751 802
Income from operations $ 196 $ 89 $ 800 $ 901
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 146 149 552 573
Impairment losses 97 116
Major maintenance expense 36 46 205 157
Operating lease expense 9 12 35 45
Unrealized (gain) loss on commodity derivative mark-to-market activity (23 ) 69 25 (143 )
Gain on sale of assets (119 ) (119 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) 6 9 36 34
Stock-based compensation expense 6 6 24 24
(Gain) loss on dispositions of assets (1 ) 3 16 10
Conectiv acquisition-related costs(4) 11 36
Contract amortization 3 8
Other 1 25 3
Adjusted EBITDA from continuing operations 379 372 1,726 1,637
Adjusted EBITDA from discontinued operations 14 75
Total Adjusted EBITDA $ 379 $ 386 $ 1,726 $ 1,712
Less:
Lease payments 9 12 35 45
Major maintenance expense and capital expenditures(5) 62 114 397 317
Cash interest, net(6) 194 186 781 768
Cash taxes 2 7 13 17
Other 4 8 11 7
Adjusted Recurring Free Cash Flow(7) $ 108 $ 59 $ 489 $ 558

_________

(1)

Depreciation and amortization expense in the income from operations calculation on our Consolidated Statements of Operations excludes amortization of other assets.

(2)

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

(3)

Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three months ended December 31, 2011 and 2010, and $1 million for each of the years ended December 31, 2011 and 2010.

(4)

Includes $2 million and $26 million included in sales, general and other administrative expenses and $9 million and $10 million included in plant operating expense for the three months and years ended December 31, 2010, respectively.

(5)

Includes $27 million and $201 million in major maintenance expense for the three months and year ended December 30, 2011, respectively, and $35 million and $196 million in maintenance capital expenditures for the three months and year ended December 30, 2011, respectively. Includes $49 million and $159 million in major maintenance expense for the three months and year ended December 31, 2010, respectively, and $65 million and $158 million in maintenance capital expenditures for the three months and year ended December 31, 2010, respectively.

(6)

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

(7)

Excludes decrease in working capital of $8 million and increase in working capital of $13 million for the three months and year ended December 31, 2011, respectively, and a decrease in working capital of $76 million and $44 million for the three months and year ended December 31, 2010, 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. 2010 Adjusted Recurring Free Cash Flow has been recast to conform with current year presentation, which excludes settlements of non-hedging interest rate swaps.

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 years ended December 31, 2011 and 2010. 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,
2011 2010 2011 2010
(in millions)
Commodity Margin $ 553 $ 576 $ 2,474 $ 2,391
Other revenue 2 3 13 27
Plant operating expense(1) (154 ) (178 ) (666 ) (682 )
Sales, general and administrative expense(2) (28 ) (31 ) (113 ) (108 )
Other operating expense(3) (10 ) (10 ) (40 ) (43 )
Adjusted EBITDA from unconsolidated investments in power plants(4) 15 11 57 50
Adjusted EBITDA from discontinued operations(5) - 14 - 75
Other 1 1 1 2
Adjusted EBITDA $ 379 $ 386 $ 1,726 $ 1,712

_________

(1)

Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and acquisition-related costs.

(2)

Shown net of stock-based compensation expense and acquisition-related costs.

(3)

Excludes RGGI compliance and other environmental costs of $3 million for each of the three months ended December 31, 2011 and 2010, respectively, and $10 million and $9 million for the years ended December 31, 2011 and 2010, respectively, which are components of Commodity Margin.

(4)

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

(5)

Represents Adjusted EBITDA from Blue Spruce and Rocky Mountain.

Adjusted EBITDA and Adjusted Recurring Free Cash Flow Reconciliation for Guidance

Full Year 2012 Range: Low High
(in millions)
GAAP Net Income (Loss)(1) $ (50 ) $ 75
Plus:
Interest expense, net of interest income 765 765
Depreciation and amortization expense 575 575
Major maintenance expense 185 185
Operating lease expense 35 35
Other(2) 90 90
Adjusted EBITDA $ 1,600 $ 1,725
Less:
Operating lease payments 35 35
Major maintenance expense and maintenance capital expenditures(3) 350 350
Recurring cash interest, net(4) 770 770
Cash taxes 10 10
Other 10 10
Adjusted Recurring Free Cash Flow $ 425 $ 550
Non-recurring interest rate swap payments(5) 150 150

__________

(1)

For purposes of Net Income (Loss) 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 $185 million and maintenance capital expenditures of $165 million. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt.

(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 refinanced.

CASH FLOW ACTIVITIES

The following table summarizes our cash flow activities for the years ended December 31, 2011 and 2010:

2011 2010
(in millions)
Beginning cash and cash equivalents $ 1,327 $ 989
Net cash provided by (used in):
Operating activities 775 929
Investing activities (836 ) (831 )
Financing activities (14 ) 240
Net increase (decrease) in cash and cash equivalents (75 ) 338
Ending cash and cash equivalents $ 1,252 $ 1,327

OPERATING PERFORMANCE METRICS

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

Three Months Ended December 31, Year Ended December 31,
2011 2010 2011 2010
Total MWh generated (in thousands)(1) 24,954 20,510 90,875 88,323
West 7,634 8,114 23,823 30,909
Texas 8,533 5,750 32,552 30,169
Southeast 4,494 4,275 18,983 17,987
North 4,293 2,371 15,517 9,258
Average availability 91.4 % 87.5 % 90.1 % 90.4 %
West 95.8 % 91.1 % 88.2 % 91.5 %
Texas 89.4 % 83.1 % 89.0 % 87.6 %
Southeast 91.5 % 89.9 % 91.9 % 92.5 %
North 89.4 % 86.7 % 91.6 % 90.7 %
Average capacity factor, excluding peakers 48.7 % 40.7 % 44.3 % 46.0 %
West 55.3 % 59.1 % 43.6 % 56.5 %
Texas 55.2 % 36.6 % 53.2 % 48.1 %
Southeast 39.2 % 36.8 % 40.6 % 38.0 %
North 40.3 % 25.1 % 35.9 % 32.8 %
Steam adjusted heat rate (mmbtu/kWh) 7,358 7,374 7,412 7,338
West 7,287 7,319 7,418 7,316
Texas 7,203 7,292 7,243 7,236
Southeast 7,279 7,264 7,312 7,315
North 7,867 7,947 7,919 7,819

________

(1)

Excludes generation from unconsolidated power plants, plants owned but not operated and discontinued operations.

Source: Calpine Corporation

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