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America’s Premier Power Generation Company
... Creating Power for a Sustainable Future

Calpine Corp. Reports Solid Fourth Quarter and Year-End 2010 Results, Reaffirms 2011 Guidance

02/18/2011

Recent Achievements:

  • Increased our power generation to 94 million MWh1 during 2010, 3% higher than 2009
  • Closed on the strategic sales of our Colorado plants and an undivided interest in our Freestone Energy Center, enhancing liquidity and retiring debt in the process
  • Successfully issued $1.2 billion of Senior Secured Notes, allowing us to fully retire our First Lien Credit Facility and eliminate its related covenants
  • Closed on a new $1.0 billion Senior Secured Revolving Credit Facility
  • Began construction of the Russell City Energy Center and received all necessary permits to begin upgrading our Los Esteros Critical Energy Facility, expanding our role in providing clean, efficient and reliable power in the state of California
Full Year 2010 Financial Results:
  • $1,712 million of Adjusted EBITDA
  • $558 million of Adjusted Recurring Free Cash Flow
  • $2,391 million of Commodity Margin
  • $31 million of Net Income2
Fourth Quarter 2010 Financial Results:
  • $386 million of Adjusted EBITDA
  • $86 million of Adjusted Recurring Free Cash Flow
  • $576 million of Commodity Margin
  • $24 million of Net Loss2
Reaffirming 2011 Full Year Guidance:
  • 2011 Adjusted EBITDA guidance of $1,700 - $1,800 million
  • 2011 Adjusted Recurring Free Cash Flow guidance of $440 - $540 million

HOUSTON, Feb 18, 2011 (BUSINESS WIRE) -- Calpine Corporation (NYSE:CPN) today reported 2010 Adjusted EBITDA of $1,712 million, compared to $1,782 million in the prior year. The company also reported 2010 Adjusted Recurring Free Cash Flow of $558 million, compared to $602 million in 2009. Net income2 for the year was $31 million, or $0.06 per diluted share, compared to $149 million, or $0.31 per diluted share, in 2009.

"We had a successful year in 2010: we executed on our strategic initiatives, strengthened our balance sheet, achieved solid operating performance and enhanced shareholder value. Additionally, we increased market share despite significant challenges posed by the overall economic environment and related impacts on power markets. The combination of our ability to execute, mounting optimism on economic recovery and increasing environmental pressure on the country's aging power generation fleet should trend towards even greater utilization of our modern, clean, efficient natural gas-fired plants. Indeed, I believe that we are at the crossroads of a structural change in wholesale power generation that should bode well for the future of Calpine," said Jack Fusco, Calpine's President and Chief Executive Officer.

"On the operating front, in 2010, we had an impressive fleet-wide availability of 91% and starting reliability of 98%, enabling us to generate over 94 million MWh1 of power for our customers. On the strategic and growth front, in 2009 we made clear our strategic goal to achieve scale in a third region to provide better geographic and weather diversity, and in July 2010 we acquired 19 plants in the Mid-Atlantic giving us that foothold in PJM, an acquisition that has proven to be even more accretive than expected. But that is not the end of our growth story - we continued to invest in high-return upgrade projects and, after the successful culmination of the permitting processes, our Russell City Energy Center and the upgrade to our Los Esteros Energy Center, both of which are now under construction. We are also well on the way to an early completion of our York Energy Center. Finally, in 2010 we also began an effort to reposition our asset base by opportunistically shedding non-core assets or monetizing core assets where economically sensible. During the year, we successfully divested non-core assets in Colorado and an undivided interest in our North Texas Freestone plant at very attractive prices.

"On the financing front, we have now completed the refinancing of the First Lien Credit Facility and, in the process, achieved an investment grade-like covenant structure while improving our capital allocation flexibility by, among other things, adding the ability to return capital to shareholders under appropriate conditions. Overall, we have made significant progress in positioning Calpine for the future."

SUMMARY OF FINANCIAL PERFORMANCE

Full Year Results

Adjusted EBITDA for the year ended December 31, 2010, was $1,712 million, compared to $1,782 million in the prior year period. The year-over-year decline in Adjusted EBITDA was primarily caused by a $70 million decrease in Commodity Margin, due in large part to our West and Texas segments, where Commodity Margin decreased by $165 million and $140 million, respectively. Lower average hedge margins, as well as lower realized spark spreads on open positions due to lower realized heat rates attributable to weaker market conditions resulting from milder weather and an overall increase in installed generation capacity, impacted both regions. In addition, the year-over-year Commodity Margin variance in the West segment was negatively impacted by a $102 million decrease attributable to the expiration of the PCF arrangement at the end of 2009, offset, in part, by Commodity Margin increases of $80 million from Otay Mesa Energy Center (OMEC), which achieved commercial operation in October 2009 and was consolidated on January 1, 2010, and $50 million related to higher renewable energy credit (REC) revenue from new contracts associated with our Geysers power plants. The Commodity Margin declines in the West and Texas segments were offset, in part, by a $267 million increase in Commodity Margin from our North segment, which was primarily driven by the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010, as well as strong performance from our incumbent plants in the region which benefited from weather-driven demand increases in 2010.

Aside from the decline in Commodity Margin, Adjusted EBITDA in 2010 was also negatively impacted by a $25 million year-over-year increase in plant operating expense3, most of which was due to the addition of our Mid-Atlantic plants in July 2010 and the start-up of OMEC in October 2009. This increase was offset by a $43 million decrease in sales, general and administrative expense4 that resulted primarily from lower personnel and consulting expenses, as well as a contract settlement that benefited the first quarter of 2010.

Cash flows provided by operating activities for the twelve months ended December 31, 2010, improved to $929 million compared to $761 million for the same period in 2009. The improvement in cash provided by operating activities was primarily due to a decrease of approximately $188 million in working capital employed and a decrease of $126 million of cash paid for interest (inclusive of interest rate swaps in hedging relationships). These improvements were partially offset by a $43 million decrease in income from operations, adjusted for non-cash items, and a $54 million increase in net cash paid for taxes.

Net income2 decreased to $31 million for the year ended December 31, 2010, from $149 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted, was unchanged year-over-year at $87 million. Though offset, we experienced negative year-over-year variances that include a $70 million decline in Commodity Margin, as previously discussed, as well as a $114 million increase in depreciation expense associated with the acquisition of our Mid-Atlantic fleet, the consolidation of OMEC and revisions in certain areas of our depreciation methods and asset lives. In addition, income from unconsolidated investments in power plants declined $34 million year-over-year, primarily as a result of the consolidation of OMEC as of January 1, 2010. Offsetting these declines was an $83 million decline in income tax expense, primarily resulting from a decrease of $129 million related to non-cash intraperiod tax allocation partially offset by an increase in federal income tax of $43 million for the CCFC group for the year ended December 31, 2010 compared to the year ended December 31, 2009. In addition, interest expense (excluding unrealized mark-to-market (gains) losses) decreased by $55 million in 2010 compared to 2009 due to the repayment of our PCF financing, the refinancing of our CCFC debt, and a decrease in the annualized effective interest rates on our consolidated debt (excluding the impacts of capitalized interest), offset, in part, by increases related to the 2010 addition of a term loan that was used to fund our Mid-Atlantic fleet acquisition as well as the consolidation of OMEC on January 1, 2010. Finally, sales, general and administrative expenses (net of acquisition-related costs incurred in 2010), declined by $49 million year-over-year, due to factors previously discussed.

Fourth Quarter Results

Adjusted EBITDA declined to $386 million in the fourth quarter of 2010 compared to $408 million in the prior year period. The year-over-year decline was primarily due to a $14 million decrease in Commodity Margin, which was largely driven by declines of $56 million and $35 million in our West and Texas segments, respectively. The declines in the West resulted from the expiration of the PCF arrangement in the fourth quarter of 2009, as well as lower average hedge prices and lower realized spark spreads associated with weaker market conditions in the fourth quarter of 2010 as compared to the same period in 2009. Partially offsetting these declines, the West region benefited from an $11 million increase related to higher REC revenue from new contracts associated with our Geysers plants and an increase of $24 million related to the consolidation of our OMEC facility as of January 1, 2010. Meanwhile, Commodity Margin in our Texas segment declined due to lower average hedge prices in the fourth quarter of 2010 compared to the prior year period. The declines in our West and Texas segments were offset, in part, by improvements in our North segment, where Commodity Margin increased $92 million in 2010, due largely to the integration of our Mid-Atlantic fleet as of the third quarter and strong performance by our legacy plants associated with cold weather late in the fourth quarter of 2010.

Net loss2 decreased to $24 million for the three months ended December 31, 2010, compared to $43 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted, improved from a net loss of $34 million in 2009 to net income of $51 million in 2010. The improvement was primarily attributable to a $104 million increase in income tax benefit in the fourth quarter of 2010 compared to the prior year period, which was largely due to the application of intraperiod non-cash tax allocation. In addition, interest expense (excluding unrealized mark-to-market (gains) losses) decreased by $15 million in the fourth quarter of 2010, due largely to the same factors that influenced the full-year period, while sales, general and administrative expenses (net of acquisition-related costs in 2010) declined by $14 million, due primarily to lower personnel and consulting expenses. These benefits were partially offset by a $21 million decline in income from unconsolidated investments in power plants, primarily resulting from the consolidation of OMEC as of January 1, 2010; a $15 million increase in depreciation expense, driven by the same factors that influenced the full-year period; and a $14 million decrease in Commodity Margin, as previously discussed.

1 Includes generation from unconsolidated power plants, plants owned but not operated and discontinued operations.
2 Reported as net income (loss) attributable to Calpine on our Consolidated Statements of Operations.
3 Increase 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 and twelve months ended December 31, 2010 and 2009.
4 Decrease in sales, general and administrative expense excludes changes in stock-based compensation and acquisition-related costs. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the three and twelve months ended December 31, 2010 and 2009.

Table 1: Summarized Consolidated Statements of Operations

(Unaudited)

Three Months Ended December 31,

Year Ended December 31,
2010 2009 2010 2009
(in millions)
Operating revenues $ 1,471 $ 1,544 $ 6,545 $ 6,463
Operating expenses 1,406 1,366 5,663 5,496

Impairment losses, net gain on sale of assets, and (income) loss from unconsolidated investments in power plants

(24 ) (19 ) (19 ) (46 )
Income from operations 89 197 901 1,013
Net interest expense, debt extinguishment costs, loss on interest rate derivatives, and other (income) expense 381 243 1,131 889
Income (loss) before reorganization items, income taxes and discontinued operations (292 ) (46 ) (230 ) 124
Reorganization items -- 1 -- (1 )
Income tax expense (benefit) (106 ) (2 ) (68 ) 15
Income (loss) before discontinued operations (186 ) (45 ) (162 ) 110
Discontinued operations, net of tax expense 162 1 193 35
Net income (loss) (24 ) (44 ) 31 145
Net loss attributable to the noncontrolling interest -- 1 -- 4
Net income (loss) attributable to Calpine $ (24 ) $ (43 ) $ 31 $ 149
Discontinued operations, net of tax expense (162 ) (1 ) (193 ) (35 )

Reorganization items(1)

-- 1 -- (1 )
Debt extinguishment costs(1)(2) 64 27 91 57

Gain on sale of assets, net(1)

(119 ) -- (119 ) --

Impairment losses(1)

97 4 116 4
Unrealized MtM (gains) losses on derivatives(1)(3) 153 (22 ) 56 (87 )

Other items(1)(4)

42 -- 105 --
Net Income (Loss), As Adjusted(5) $ 51 $ (34 ) $ 87 $ 87

(1)Shown net of tax, assuming a 0% effective tax rate for these items (other than those referenced in note 2 below).

(2)Debt extinguishment costs in the full year 2009 period include $49 million associated with the refinancing of CCFC, shown net of tax assuming a 38.4% effective tax rate.

(3)Represents unrealized mark-to-market (MtM) (gains) losses 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.

(4)Other items for the three and twelve months ended December 31, 2010, include $11 million and $36 million, respectively, in costs related to the Mid-Atlantic fleet acquisition and $31 million and $69 million, respectively, in realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps.

(5)See "Regulation G Reconciliations" for further discussion of Net Income, As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

Three Months Ended December 31, Year Ended December 31,
2010 2009 2010 2009
West $ 271 $ 327 $ 1,080 $ 1,245
Texas 104 139 504 644
North 145 53 535 268
Southeast 56 71 272 304
Total $ 576 $ 590 $ 2,391 $ 2,461

West: Commodity Margin in our West segment decreased by $165 million in 2010 compared to 2009, primarily resulting from a decrease of $102 million related to the expiration of the PCF arrangement in the fourth quarter of 2009. In addition, the year-over-year variance was impacted by lower average hedge prices in 2010 compared to 2009 and lower realized spark spreads on our open positions due to lower market heat rates caused primarily by cooler temperatures in 2010 compared to 2009 and an overall increase in installed generation capacity and higher hydroelectric generation volumes in California in 2010. Also contributing to the unfavorable period-over-period change was a decrease of $11 million for the sale of surplus emission allowances in the first quarter of 2009, which did not reoccur in the same period in 2010. The decrease in Commodity Margin was partially offset by an increase of $50 million related to higher REC revenue from new contracts associated with our Geysers assets; $80 million from OMEC, which achieved commercial operation in October 2009 and was consolidated on January 1, 2010; and a $12 million credit recognized in the second quarter of 2010 related to overcharges associated with a gas transportation contract.

Commodity Margin in our West segment decreased by $56 million for the three months ended December 31, 2010, compared to the same period in 2009, primarily resulting from a decrease of $25 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices for the fourth quarter of 2010 compared to 2009, and lower realized spark spreads on our open positions primarily driven by lower gas prices in the fourth quarter of 2010. The decrease in Commodity Margin was partially offset by increases of $11 million related to higher REC revenue from our Geysers assets and $24 million from OMEC.

Texas: Commodity Margin in our Texas segment decreased by $140 million in 2010 compared to 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions. The lower realized spark spreads were due to lower market heat rates, particularly with regard to June 2010, which did not benefit from the extreme heat, congestion-driven pricing and tighter reserve margin that occurred in June 2009, as well as an overall increase in installed generation capacity in ERCOT.

Commodity Margin in our Texas segment decreased by $35 million for the three months ended December 31, 2010, compared to the same period in 2009, primarily resulting from lower average hedge prices for the fourth quarter of 2010 compared to the same period in 2009.

North: Commodity Margin in our North segment increased by $267 million in 2010 primarily due to the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010, and higher realized spark spreads on open positions driven by much warmer weather in the second and third quarters of 2010, as well as colder weather in the latter fourth quarter of 2010 compared to the same periods in 2009.

Commodity Margin in our North segment increased by $92 million for the three months ended December 31, 2010, compared to the same period in 2009. The three-month results were largely impacted by the Mid-Atlantic fleet acquisition and the strong performance of our legacy plants driven by a very cold late fourth quarter.

Southeast: Commodity Margin in our Southeast segment decreased by $32 million in 2010 compared to 2009. Our power plants in the western half of the region experienced lower realized spark spreads on open positions, driven by lower market heat rates. Partially offsetting these negative impacts, our power plants in the eastern half of the region experienced higher realized spark spreads on open positions, driven by higher market heat rates caused primarily by warmer weather in May and June 2010 and cooler weather in the fourth quarter of 2010 compared to the same periods in 2009. In addition, the overall decrease in Commodity Margin was partially offset by the non-recurring negative impact from the settlement of a disputed steam contract in the second quarter of 2009.

Commodity Margin in our Southeast segment for the three months ended December 31, 2010, decreased by $15 million compared to the same period in 2009. The modest decrease resulted primarily from lower average hedge prices for the three months ended December 31, 2010, compared to the same period in 2009.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

December 31, December 31,
2010 2009
(in millions)
Cash and cash equivalents, corporate(1) $ 1,058 $ 725
Cash and cash equivalents, non-corporate 269 264
Total cash and cash equivalents 1,327 989
Restricted cash 248 562
Letter of credit availability(2) 35 34
Revolver availability(3) 623 794
Total current liquidity availability $ 2,233 $ 2,379

(1)Includes $6 million and $9 million of margin deposits held by us posted by our counterparties as of December 31, 2010 and 2009, respectively.

(2)Additional available balances for Calpine Development Holdings, Inc. letter of credit were increased by $50 million to $200 million on June 30, 2010.

(3)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 and allows for up to $750 million of availability for the issuance of letters of credit and up to $50 million as a swingline subfacility. At December 31, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by Deutsche Bank AG New York Branch. Our letters of credit under our Corporate Revolving Facility as of December 31, 2010 include those that were back-stopped of approximately $83 million; however, we expect that the back-stopped letters of credit will be returned and extinguished in early 2011.

Liquidity at December 31, 2010 remained strong at $2.2 billion, down modestly from $2.4 billion at December 31, 2009. As previously discussed, operating activities for 2010 resulted in net cash proceeds of $929 million, compared to $761 million in 2009. Meanwhile, cash flows from investing activities resulted in a net outflow of $831 million during 2010 compared to an outflow of $250 million in 2009. The 2010 activity was driven largely by the previously mentioned purchase of our Mid-Atlantic fleet during the third quarter, offset in part by cash inflows from the strategic sales of our Colorado plants and Freestone equity interest, which collectively generated $954 million in cash proceeds during December 2010, and reduced restricted cash balances associated primarily with the maturity of our PCF project financing instrument. Cash flows from financing activities for the twelve months ended December 31, 2010, resulted in a net inflow of $240 million, primarily as a result of the addition of a term loan whose proceeds were used to fund a portion of our Mid-Atlantic acquisition, offset primarily by our repayment of project-level debt associated with the Colorado plants that we sold, our repayment of the PCF financing, and other payments that we made under project debt waterfall provisions.

During 2010, we generated $558 million of Adjusted Recurring Free Cash Flow, compared to $602 million in 2009. The year-over-year decline was primarily the result of the $70 million decrease in Adjusted EBITDA, as previously discussed, and a $22 million increase in cash taxes, net, due primarily to the addition, through our Mid-Atlantic acquisition, of operations in states where we do not have state-level net operating losses. These decreases were partially offset by a $32 million decrease in major maintenance expense and capital expenditures from 2009 to 2010 as a result of year-over-year differences in maintenance project requirements as dictated by our plant maintenance cycle and a $14 million decrease in cash interest, net, primarily due to the refinancing of our First Lien Term Loan, which was replaced with fixed rate bonds.

CORPORATE DEBT REFINANCING

Over the course of 2010 and early 2011, we strengthened our capital structure through the opportunistic placement of $4.7 billion in Senior Secured Notes and the replacement of our $1.0 billion revolver, which allowed us to fully retire our First Lien Credit Facility. "As a result of the successful refinancing of the First Lien Term Loan and Revolver, we now have a flexible, investment grade-like covenant package that provides us with a wider array of capital allocation options, placing us in a stronger position to enhance shareholder value," said Zamir Rauf, Calpine's Chief Financial Officer.

PLANT DEVELOPMENT

York Energy Center: We acquired the 565 MW dual-fuel, combined-cycle power plant under construction in Peach Bottom Township, Pennsylvania, formerly referred to as the Delta Project, as part of our acquisition of our Mid-Atlantic fleet. All permits have been received and COD is expected in March 2011, three months early and approximately $20 million under budget. The plant will sell its power under a six-year Power Purchase Agreement (PPA) with a third party beginning in June 2011.

Russell City Energy Center: In December 2010, we began construction on this 619 MW natural gas-fired, combined-cycle power plant in Hayward, California. We are currently in possession of all material permits, subject to ongoing judicial appeals, and are now in the process of obtaining project financing. The Russell City Energy Center is contracted to deliver its full output to PG&E under a ten year PPA and the expected COD is in 2013. We are a majority partner in this project; our minority partner, a General Electric affiliate, currently owns a 35% interest, though they are currently funding their construction obligations at 25%. Our partner's ownership interest will no longer fluctuate and will finalize upon closing of construction financing in 2011. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our expected 75% share.

Los Esteros Expansion: 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 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, but the appeal period has not yet expired. In addition, we are in the process of procuring equipment and selecting the engineering, procurement and construction contractors. We expect COD during the third quarter of 2013.

Turbine Upgrades: We continue to move forward with our turbine upgrade program and have entered an agreement to upgrade select GE and Siemens turbines. We have completed the upgrade of six Siemens turbines and have agreed to upgrade approximately 15 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. These upgrades began in the fourth quarter of 2009 and are scheduled through 2014. The upgraded turbines have been operating with heat rates falling in line with expectations.

Geysers Assets Expansion: We continue to look to expand 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; however, permitting delays have emerged that we are working to resolve. We were planning to target a 2013 COD for an expansion of our Geysers assets and had been, in parallel, negotiating commercial arrangements to support that, but the permitting delay has increased the risk we will not meet a target 2013 COD. We continue to believe our northern Geysers assets have potential for development. In the near term, we will work to connect the test wells we have drilled over the last year to our existing power plants and will work to capture incremental MW from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion target COD subsequent to 2013.

OPERATIONS UPDATE

2010 Power Operations Achievements:

  • Safety Performance: Achieved eighth consecutive year of top-quartile safety performance with 2010 lost-time incident rate of 0.23
  • Availability Performance:
    • Maintained 2010 fleet-wide average availability factor of nearly 91%
    • Achieved fleet-wide natural gas-fired starting reliability of 98% in 2010, compared to 97% in 2009
  • Cost Management Performance: Maintained flat plant operating expense year-over-year, despite addition of Mid-Atlantic fleet and full-year operation at OMEC
  • Geothermal Generation: Provided approximately 6 million MWh of renewable baseload generation with 94% capacity factor, 98% availability factor and 0.23% forced outage factor in 2010
  • Natural Gas-fired Generation:
    • Increased production from gas-fired plants by over 3 million MWh1, or 4%, in 2010
    • Achieved 100% availability and 100% starting reliability at Carville Energy Center during the fourth quarter of 2010
    • Achieved 100% starting reliability and 0% forced outage factor at Los Medanos Energy Center during the fourth quarter of 2010
    • Began construction of our Russell City Energy Center in December 2010
    • Earned OSHA Star Worksite designation at the Westbrook Energy Center under the stringent federal Voluntary Protection Program, recognizing the plant's exemplary workplace health and safety efforts

2010 Commercial Operations Achievements:

  • Customer-oriented Growth:
    • Received approval of our PPA contracts totaling 1,250 MW with SDG&E and PG&E from the California Public Utility Commission
    • Entered into a seven-year PPA with Xcel Energy to provide 200 MW of power generated by our Oneta Energy Center to Southwestern Public Service Company
    • Signed a PPA with Bonneville Power Administration to provide up to 75 MW of wind power generation flexibility
  • Portfolio Optimization:
    • Completed the sale of a 25% undivided interest in 1,038 MW Freestone Energy Center for $215 million ($830/kW) plus operating and energy management fees
    • Completed the sale of Blue Spruce Energy Center and Rocky Mountain Energy Center to PSCo. for $739 million ($794/kW)

FINANCIAL OUTLOOK

Table 4: Adjusted EBITDA and Adjusted Recurring Free Cash Flow Guidance

Full Year 2011
(in millions)
Adjusted EBITDA $ 1,700 - 1,800
Less:
Operating lease payments 30
Major maintenance expense and capital expenditures(1) 390
Recurring cash interest, net 825
Cash taxes 15
Adjusted Recurring Free Cash Flow $

440 - 540

Non-recurring interest rate swap payments(2) 165

(1)Includes projected Major Maintenance Expense of $235 million and maintenance Capital Expenditures of $155 million. Capital Expenditures exclude major construction and development projects.

(2)Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been refinanced.

We are reaffirming our 2011 guidance, which includes Adjusted EBITDA of $1,700 million to $1,800 million and Adjusted Recurring Free Cash Flow of $440 million to $540 million. We expect to invest approximately $155 million5 in growth-related projects during the year, including our ongoing turbine upgrade program, our 565 MW York Energy Center, our 619 MW Russell City Energy Center and the 120 MW upgrade of our Los Esteros plant.

5 Growth capital expenditure projections shown net of financing, assuming project financing for Russell City and Los Esteros is completed in 2011. Actual amounts spent during 2011 may exceed our current projections depending upon the timing and terms of financing.

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 2010 on Friday, February 18, 2011, at 10 a.m. ET/9 a.m. CT. A listen-only webcast of the call may be accessed through our website at www.calpine.com or by dialing 888-364-3108 at least 10 minutes prior to the beginning of the call. An archived recording of the call will be made available for a limited time on our website. The recording also can be accessed by dialing 888-203-1112 or 719-457-0820 for international listeners and providing Confirmation Code 4461703. Presentation materials to accompany the conference call will be made available on our website at www.calpine.com on February 18, 2011.

ANNUAL MEETING DATE

Calpine's Annual Meeting of Shareholders will be held on Wednesday, May 11, 2011, at 10:00 a.m. CT in Houston, Texas, at a location to be announced. Shareholders as of March 14, 2011, will be eligible to vote at this year's meeting.

ABOUT CALPINE

Founded in 1984, Calpine Corporation is a major U.S. power company, currently capable of delivering approximately 27,500 megawatts of clean, cost-effective, reliable and fuel-efficient power from its 91 operating plants to customers and communities in 20 U.S. states and Canada. Calpine Corporation is committed to helping meet the needs of an economy that demands more and cleaner sources of electricity. Calpine owns, leases and operates primarily low-carbon, natural gas-fired and renewable geothermal power plants. Using advanced technologies, Calpine generates power in a reliable and environmentally responsible manner for the customers and communities it serves. Please visit our website at www.calpine.com for more information.

Calpine's Annual Report on Form 10-K for the year ended December 31, 2010, may be found on the Securities and Exchange Commission's (SEC) website at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this Report contains "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. 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, 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 climate change, GHG emissions and derivative transactions;
  • The unknown impact on our business from the Dodd-Frank Wall Street Reform and Consumer Protection Act and the rules to be promulgated under it;
  • Our ability to manage our significant liquidity needs and to comply with covenants under our First Lien Credit Facility, First Lien Notes, NDH Project Debt, CCFC Notes and other existing financing obligations;
  • Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
  • Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
  • Competition, including risks associated with marketing and selling power in the evolving energy markets;
  • The expiration or termination of our Power Purchase Agreements and the related results on revenues;
  • Future capacity revenues may not occur at expected levels;
  • Natural disasters, such as hurricanes, earthquakes and floods, or acts of terrorism that may impact our power plants or the markets our power plants serve;
  • 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 release or in our reports and registration statements filed with the SEC, including, without limitation, the risk factors identified in our Annual Report on Form 10-K for the year ended December 31, 2010.

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 hereof. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

Three Months Ended December 31,

Year Ended December 31,
2010 2009 2010 2009
(in millions, except share and per share amounts)
Operating revenues $ 1,471 $ 1,544 $ 6,545 $ 6,463
Operating expenses:
Fuel and purchased energy expense 958 930 3,974 3,897
Plant operating expense 238 230 868 868
Depreciation and amortization expense 147 132 570 456
Sales, general and other administrative expense 38 50 151 174
Other operating expense 25 24 100 101
Total operating expense 1,406 1,366 5,663 5,496
Impairment losses 97 4 116 4
(Gain) on sale of assets, net (119 ) -- (119 ) --
(Income) loss from unconsolidated investments in power plants (2 ) (23 ) (16 ) (50 )
Income from operations 89 197 901 1,013
Interest expense 165 211 789 815
(Gain) loss on interest rate derivatives, net 149 -- 247 --
Interest (income) (3 ) (3 ) (11 ) (16 )
Debt extinguishment costs 64 27 91 76
Other (income) expense, net 6 8 15 14
Income (loss) before reorganization items, income taxes and discontinued operations (292 ) (46 ) (230 ) 124
Reorganization items -- 1 -- (1 )
Income (loss) before income taxes and discontinued operations (292 ) (47 ) (230 ) 125
Income tax expense (benefit) (106 ) (2 ) (68 ) 15
Income (loss) before discontinued operations (186 ) (45 ) (162 ) 110
Discontinued operations, net of tax expense 162 1 193 35
Net income (loss) (24 ) (44 ) 31 145
Net loss attributable to the noncontrolling interest -- 1 -- 4

Net income (loss) attributable to Calpine

$ (24 ) $ (43 ) $ 31 $ 149
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 486,106 485,776 486,044 485,659
Income (loss) before discontinued operations attributable to Calpine $ (0.38 ) $ (0.09 ) $ (0.33 ) $ 0.24
Discontinued operations, net of tax expense, attributable to Calpine 0.33 -- 0.39 0.07
Net income (loss) per common share - basic $ (0.05 ) $ (0.09 ) $ 0.06 $ 0.31
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 487,589 485,776 487,294 486,319
Income (loss) before discontinued operations attributable to Calpine $ (0.38 ) $ (0.09 ) $ (0.33 ) $ 0.24
Discontinued operations, net of tax expense, attributable to Calpine 0.33 -- 0.39 0.07
Net income (loss) per common share - diluted $ (0.05 ) $ (0.09 ) $ 0.06 $ 0.31

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2010 and 2009
2010 2009
(in millions, except
share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 1,327 $ 989
Accounts receivable, net of allowance of $2 and $14 669 750
Margin deposits and other prepaid expense 221 490
Restricted cash, current 195 508
Derivative assets, current 725 1,119
Inventory and other current assets 292 243
Total current assets 3,429 4,099
Property, plant and equipment, net 12,978 11,583
Restricted cash, net of current portion 53 54
Investments 80 214
Long-term derivative assets 170 127
Other assets 546 573
Total assets $ 17,256 $ 16,650
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 514 $ 578
Accrued interest payable 132 54
Debt, current portion 152 463
Derivative liabilities, current 718 1,360
Income taxes payable 5 7
Other current liabilities 268 287
Total current liabilities 1,789 2,749
Debt, net of current portion 10,104 8,996
Deferred income tax liability, net of current 77 54
Long-term derivative liabilities 370 197
Other long-term liabilities 247 208
Total liabilities 12,587 12,204
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 100,000,000 shares; none issued and outstanding at December 31, 2010 and 2009 -- --
Common stock, $.001 par value per share; authorized 1,400,000,000 shares; 444,883,356 shares issued and 444,435,198 shares outstanding at December 31, 2010, and 443,325,827 shares issued and 442,998,255 shares outstanding at December 31, 2009 1 1
Treasury stock, at cost, 448,158 and 327,572 shares, respectively (5 ) (3 )
Additional paid-in capital 12,281 12,256
Accumulated deficit (7,509 ) (7,540 )
Accumulated other comprehensive loss (125 ) (266 )
Total Calpine stockholders' equity 4,643 4,448
Noncontrolling interest 26 (2 )
Total stockholders' equity 4,669 4,446
Total liabilities and stockholders' equity $ 17,256 $ 16,650

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2010 and 2009
2010 2009
(in millions)
Cash flows from operating activities:
Net income $

31

$ 145
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 615 556
Debt extinguishment costs 91 37
Deferred income taxes (26 ) 16
Impairment loss 116 4
(Gain) loss on sale of power plants and other, net (314 ) 37
Unrealized mark-to-market activities, net 56 (89 )
(Income) loss from unconsolidated investments in power projects (16 ) (50 )
Return on investment in unconsolidated subsidiaries 11 11
Stock-based compensation expense 24 38
Reorganization items --

(6

)

Other

1

6
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable

91

108

Derivative instruments (52 ) (118 )
Other assets 277 235
Accounts payable, LSTC and accrued expenses 26 (19 )
Other liabilities (2 ) (150 )
Net cash provided by operating activities 929 761
Cash flows from investing activities:
Purchases of property, plant and equipment (369 ) (179 )
Proceeds from sale of power plants, interests and other 954 --
Purchase of Conectiv assets and BRSP, net of cash acquired (1,680 ) --
Cash acquired due to reconsolidation of OMEC 8 --
Contributions to unconsolidated investments -- (19 )
Return of investment from unconsolidated investments -- 9
Settlement of non-hedging interest rate swaps (69 ) --
(Increase) decrease in restricted cash 322 (59 )
Other 3 (2 )
Net cash (used in) investing activities (831 ) (250 )
Cash flows from financing activities:
Repayments of project financing, notes payable and other (937 ) (1,361 )
Borrowings from project financing, notes payable and other 1,272 1,034
Repayments on First Lien Credit Facilities (3,477 ) (785 )
Contributions from noncontrolling interest holder 17 --
Issuance of First Lien Notes 3,491 --
Financing costs (136 ) (65 )
Refund of financing costs 10 --
Other -- (2 )
Net cash provided by (used in) financing activities 240 (1,179 )
Net increase (decrease) in cash and cash equivalents 338 (668 )
Cash and cash equivalents, beginning of period 989 1,657
Cash and cash equivalents, end of period $ 1,327 $ 989
Cash paid (received) during the period for:
Interest, net of amounts capitalized $ 635 $ 761
Income taxes $ 21 $ 7
Reorganization items included in operating activities, net $ -- $ 5
Supplemental disclosure of non-cash investing and financing activities:
Settlement of commodity contract with project financing $ -- $ 79
Change in capital expenditures included in accounts payable $ 1 $ 6
Liabilities assumed in BRSP acquisition $ 85 $ --
Conversion of Project Debt to Noncontrolling Interest $ 11 $ --
Issuance of First Lien Notes in exchange for First Lien Credit Facility term loans $ -- $ 1,200
Amended Steamboat project debt $ -- $ 448

(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, 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, 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, reorganization items, debt extinguishment costs, gain on sale of assets, net, impairment losses, unrealized mark-to-market (gains) losses on derivatives, and other adjustments. Net Income, 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, 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 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 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 gross profit (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.

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 (i) 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; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; and (iii) 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 tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended December 31, 2010 and 2009 (in millions):

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 revenue(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 expense(2) 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

Three Months Ended December 31, 2009
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 327 $ 139 $ 53 $ 71 $ -- $ 590
Add: Mark-to-market commodity activity, net and other revenue(1) 23 8 9 (7 ) (9 ) 24
Less:
Plant operating expense 98 69 30 40 (7 ) 230
Depreciation and amortization expense 49 37 20 29 (3 ) 132
Sales, general and other administrative expense 23 18 4 5 -- 50
Other operating expense(2) 16 1 7 4 (4 ) 24
Impairment losses 4 -- -- -- -- 4
(Income) from unconsolidated investments in power plants (19 ) -- (4 ) -- -- (23 )
Income (loss) from operations $ 179 $ 22 $ 5 $ (14 ) $ 5 $ 197

(1)Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, for the three months ended December 31, 2010 and 2009, included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations.

(2)Excludes $3 million and nil of RGGI compliance and other environmental costs for both the three months ended December 31, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the twelve months ended December 31, 2010 and 2009 (in millions):

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 revenue(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 expense(2) 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
Year Ended December 31, 2009
Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 1,245 $ 644 $ 268 $ 304 $ -- $ 2,461
Add: Mark-to-market commodity activity, net and other revenue(1) 143 (40 ) 46 (5 ) (44 ) 100
Less:
Plant operating expense 408 232 91 134 3 868
Depreciation and amortization expense 188 129 67 80 (8 ) 456
Sales, general and other administrative expense 66 63 18 27 -- 174
Other operating expense(2) 73 14 30 11 (32 ) 96
Impairment losses 4 -- -- -- -- 4
(Income) from unconsolidated investments in power plants (32 ) -- (18 ) -- -- (50 )
Income from operations $ 681 $ 166 $ 126 $ 47 $ (7 ) $ 1,013

(1)Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, for the years ended December 31, 2010 and 2009, included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations.

(2)Excludes $9 million and $5 million of RGGI compliance and other environmental costs for the years ended December 31, 2010 and 2009, respectively, which are included as a component 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 attributable to Calpine for the three and twelve months ended December 31, 2010 and 2009, as reported under U.S. GAAP.

Three Months Ended December 31, Year Ended December 31,
2010 2009 2010 2009
(in millions)
Net income (loss) attributable to Calpine $ (24 ) $ (43 ) $ 31 $ 149
Net loss attributable to noncontrolling interest -- (1 ) -- (4 )
Discontinued operations, net of tax expense (162 ) (1 ) (193 ) (35 )
Income tax expense (benefit) (106 ) (2 ) (68 ) 15
Reorganization items -- 1 -- (1 )
Other (income) expense and debt extinguishment costs, net 70 35 106 90
(Gain) loss on interest rate derivatives, net 149 -- 247 --
Interest expense, net 162 208 778 799
Income from operations $ 89 $ 197 $ 901 $ 1,013
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 149 133 573 459
Impairment loss 97 4 116 4
Major maintenance expense 46 42 157

163

Operating lease expense 12 12 45 47
Unrealized (gains) losses on commodity derivative mark-to-market activity 69 (19 ) (143 ) (79 )
Gain on sale of assets (119 ) -- (119 ) --
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) 9 6 34 17
Stock-based compensation expense 6 8 24 38
Non-cash loss on dispositions of assets 3 3 10 32
Conectiv acquisition-related costs 11 -- 36 --
Other(4) -- 3 3

6

Adjusted EBITDA from continuing operations 372 389 1,637 1,700
Adjusted EBITDA from discontinued operations 14 19 75 82
Total adjusted EBITDA $ 386 $ 408 $ 1,712 $ 1,782
Less:
Lease payments 12 12 45 47
Major maintenance expense and capital expenditures(5) 106 76 317 349
Cash interest, net(6) 167 213 768 782
Cash taxes(7) 7 -- 17 (5 )
Other 8 -- 7 7
Adjusted Recurring Free Cash Flow(8) $ 86 $ 107 $ 558 $ 602

(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 (gains) losses on mark-to-market activity of nil and $(13) million for the three months ended December 31, 2010 and 2009, respectively, and $1 million and $(47) million for the years ended December 31, 2010 and 2009, respectively.

(4)Includes fees for letters of credit.

(5)Includes $51 million and $171 million in major maintenance expense for the three and twelve months ended December 31, 2010, respectively, and $55 million and $146 million in maintenance capital expenditures for the three and twelve months ended December 31, 2010, respectively. Includes $51 million and $183 million in major maintenance expense for the three and twelve months ended December 31, 2009, respectively, and $25 million and $166 million in maintenance capital expenditures for the three and twelve months ended December 31, 2009, 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)Cash taxes for the twelve months ended December 31, 2009 excludes a $32 million tax refund related to our foreign operations.

(8)Excludes decrease in working capital of $76 million and $44 million for the three and twelve months ended December 31, 2010, and $79 million and $70 million for the three and twelve months ended December 31, 2009.

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 twelve months ended December 31, 2010 and 2009. 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,
2010 2009 2010 2009
(in millions)
Commodity Margin $ 576 $ 590 $ 2,391 $ 2,461
Other revenue 3 5 27 21
Plant operating expense(1) (178 ) (181 ) (682 ) (657 )
Sales, general and administrative expense(2) (31 ) (44 ) (108 ) (151 )
Other operating expense(3) (10 ) (14 ) (43 ) (46 )
Adjusted EBITDA from unconsolidated investments in power plants(4) 11 29 50 67
Adjusted EBITDA from discontinued operations(5) 14 19 75 82
Other 1 4 2 5
Adjusted EBITDA $ 386 $ 408 $ 1,712 $ 1,782

(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, reorganization items and acquisition-related costs.

(3)Excludes $3 million and nil of RGGI compliance and other environmental costs for the three months ended December 31, 2010 and 2009, respectively, and $9 million and $5 million for the years ended December 31, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

(4)Amount is comprised of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBTIDA 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 2011 Range: Low High
(in millions)
GAAP Net Income (Loss) $ (25 ) $ 75
Plus:
Interest expense, net of interest income 820 820
Depreciation and amortization expense 560 560
Major maintenance expense 230 230
Operating lease expense 35 35
Other(1) 80 80
Adjusted EBITDA $ 1,700 $ 1,800
Less:
Operating lease payments 30 30
Major maintenance expense and maintenance capital expenditures(2) 390 390
Recurring cash interest, net(3) 825 825
Cash taxes 15 15
Adjusted Recurring Free Cash Flow $ 440 $ 540
Non-recurring interest rate swap payments(4) 165 165

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

(2)Includes projected major maintenance expense of $235 million and maintenance capital expenditures of $155 million. Capital expenditures exclude major construction and development projects.

(3)Includes fees for letters of credit, net of interest income.

(4)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, 2010 and 2009:

2010 2009
(in millions)
Beginning cash and cash equivalents $ 989 $ 1,657
Net cash provided by (used in):
Operating activities 929 761
Investing activities (831 ) (250 )
Financing activities 240 (1,179 )
Net decrease in cash and cash equivalents 338 (668 )
Ending cash and cash equivalents $ 1,327 $ 989

OPERATING PERFORMANCE METRICS

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

Three Months Ended December 31, Year Ended December 31,
2010 2009 2010 2009

Total MWh generated (in thousands)(1)

20,510

20,901 88,323 84,376
West 8,114 9,204 30,909 32,070
Texas

5,750

6,629 30,169 29,687
Southeast 4,275 3,529 17,987 17,370
North

2,371

1,539 9,258 5,249
Average availability 87.5% 90.3% 90.4% 92.1%
West 91.2% 94.3% 91.5% 92.1%
Texas 83.1% 83.9% 87.6% 90.0%
Southeast 89.9% 92.9% 92.5% 93.2%
North 86.7% 92.5% 90.7% 94.7%
Average capacity factor, excluding peakers 40.8% 47.6% 46.0% 48.2%
West 59.2% 73.2% 56.5% 64.0%
Texas 36.6% 42.0% 48.1% 47.4%
Southeast 36.8% 31.0% 38.0% 37.9%
North 25.1% 36.3% 32.8% 31.1%
Steam adjusted heat rate (mmbtu/kWh) 7,374 7,255 7,338 7,264
West 7,319 7,305 7,316 7,314
Texas 7,292 7,118 7,236 7,142
Southeast 7,264 7,331 7,315 7,299
North 7,947 7,441 7,819 7,614

(1)Does not include 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:
Andre K. Walker, 713-830-8775
andrew@calpine.com