CPN: NYSE 15.09
-0.03 -0.2% Volume: 2,927,314 January 22, 2018
America’s Premier Power Generation Company
... Creating Power for a Sustainable Future

Calpine Corp. Reports Solid Third Quarter 2011 Results,
Affirms 2011 Guidance, Provides 2012 Guidance

10/28/2011

Summary of 2011 Financial Results:

Three Months Ended
September 30, 2011

Nine Months Ended
September 30, 2011

(in millions)
Operating Revenues $ 2,209 $ 5,341
Commodity Margin $ 825 $ 1,921
Adjusted EBITDA $ 638 $ 1,347
Adjusted Recurring Free Cash Flow $ 361 $ 381

Net Income (Loss)1

$ 190 $ (177 )

Net Income, As Adjusted2

$ 195 $ 30

Affirming 2011 Full Year Guidance and Providing 2012 Full Year Guidance:

2011 2012
(in millions)
Adjusted EBITDA $ 1,700 - 1,750 $ 1,550 - 1,750
Adjusted Recurring Free Cash Flow $ 475 - 525 $ 375 - 575

Recent Achievements:

  • Operations:
    - Produced 29 million MWh3 of electricity in the third quarter of 2011
    - Delivered excellent forced outage factor: Fleet-wide (1.9%), Texas (0.9%)
    - Achieved 99% fleet-wide starting reliability

  • Commercial:
    - Signed new contract with Southern California Edison at our Pastoria Energy Center from 2013 - 2015

  • Capital Structure:
    - Secured approximately $373 million credit facility to finance the upgrade of our Los Esteros Critical Energy Facility
    - Completed distribution of remaining bankruptcy reserve shares
    - Announced and commenced $300 million share repurchase program
    - Achieved S&P corporate secured debt rating upgrade to BB-

HOUSTON, Oct 28, 2011 (BUSINESS WIRE) -- Calpine Corporation (NYSE:CPN): Calpine Corporation (NYSE:CPN) today reported third quarter 2011 Adjusted EBITDA of $638 million, compared to $663 million in the prior year period, and third quarter 2011 Adjusted Recurring Free Cash Flow of $361 million, compared to $381 million in the prior year period. Net Income1 for the third quarter of 2011 was $190 million, or $0.39 per diluted share, compared to $217 million, or $0.45 per diluted share, in the prior year period. The declines in the third quarter of 2011 as compared to the prior year period were primarily due to the sale of our Colorado plants and a 25% interest in our Freestone plant in December 2010. Net Income, As Adjusted2, for the third quarter of 2011 was $195 million compared to $221 million in the prior year period.

"Our clean, efficient power generation fleet performed exceptionally well during the peak summer period, producing 29 million MWh3 of power, while achieving starting reliability of 99%, the highest third quarter on record," said Jack Fusco, Calpine's President and Chief Executive Officer. "This is especially noteworthy because it was achieved with the greatest number of third quarter turbine starts on record, which exemplifies the flexibility of our modern generation fleet. Consistent with this performance, we are affirming our 2011 full-year guidance for Adjusted EBITDA and Adjusted Recurring Free Cash Flow at $1,700 million to $1,750 million and $475 million to $525 million, respectively.

"Meanwhile, this is an unprecedented time in the power generation industry on both the environmental and competitive market fronts. On the environmental front, the EPA's Cross-State Air Pollution Rule is being challenged by a group of coal generators and states seeking to stay the rule from becoming effective on January 1, 2012. Calpine has intervened to fully support the EPA in its efforts to timely enforce this well-publicized rule, for which the environmental control technologies have been available for decades. On the competitive power market front, Calpine continues to advocate for the opportunity for markets to operate free of interference. Our regulatory and legislative initiatives include structural market reform in Texas, compensation for existing and flexible generation in California and a commitment to maintaining the integrity of competitive power markets in PJM.

"We are initiating our 2012 full-year guidance for Adjusted EBITDA and Adjusted Recurring Free Cash Flow at $1,550 million to $1,750 million and $375 million to $575 million, respectively. This is a wider range than normal due to the more open hedge position we will take into 2012, as well as the environmental and market uncertainties. We anticipate our financial performance to resume its upward trajectory in 2013 with the addition of Russell City and Los Esteros, higher RPM capacity payments and the implementation of carbon regulation in California."

Zamir Rauf, Calpine's Chief Financial Officer, added, "We have continued to stay focused on enhancing shareholder value through effective capital allocation using a variety of levers. For example, during the third quarter, we completed a $373 million project financing for the Los Esteros Critical Energy Facility, minimizing the equity capital required for this valuable upgrade, and we commenced a $300 million share repurchase program, allowing us to opportunistically return capital to shareholders at price levels that we believe provide investors with meaningful long-term return. Lastly, it is worth noting that we completed the distribution of the remaining bankruptcy reserve shares during the quarter, thus fulfilling our remaining bankruptcy obligations."

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2011 was $638 million compared to $663 million in the prior year period.

  • The year-over-year decrease was primarily due to a $27 million decline in Commodity Margin to $825 million in the third quarter of 2011 from $852 million in prior year period. The year-over-year Commodity Margin decline was primarily due to:
    - Southeast segment: Decrease of $15 million largely due to the expiration of certain hedge contracts that benefited the third quarter of 2010 as well as the negative impact of an unscheduled outage at one of our power plants in the third quarter of 2011,
    - West segment: Decrease of $9 million, primarily resulting from weaker price conditions resulting from increased hydroelectric generation in California in the third quarter of 2011, and
    - Texas segment: Decrease of $3 million due to the sale of a 25% undivided interest in our Freestone plant in December 2010, which was largely offset by significantly higher power prices driven by extreme heat and drought conditions that increased spark spreads during the third quarter of 2011 on our relatively small open position.

  • Adjusted EBITDA was also negatively impacted by a $20 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010.

  • These decreases were partially offset by a $15 million decrease in plant operating expense4 due to fewer unplanned outages in the third quarter of 2011 compared to the prior year period.

Net Income1 declined to $190 million for the third quarter of 2011, compared to $217 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted, was $195 million in the third quarter of 2011 compared to $221 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
- an increase in plant operating expense due largely to higher major maintenance expense resulting from our plant outage schedule, partially offset by
+ lower depreciation and amortization expense driven primarily by assets that are now fully depreciated, and
+ lower interest expense resulting from a decrease in our annualized effective interest rate.

Year-to-Date Results

Adjusted EBITDA for the nine months ended September 30, 2011, was $1,347 million as compared to $1,326 million in the prior year period.

  • The year-over-year increase in Adjusted EBITDA was primarily the result of a $106 million increase in Commodity Margin to $1,921 million in the nine months ended September 30, 2011, from $1,815 million in the prior year period, which was due in large part to:
    + North segment: Increase of $188 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 $43 million due primarily to unplanned outages during an extreme cold weather event in early February 2011, as well as the aforementioned Freestone sale, partially offset by significantly higher power prices driven by extreme summer weather in the third quarter of 2011 on our relatively small open position, and
    - Southeast segment: Decrease of $28 million due to the expiration of certain hedge contracts that benefited 2010.

  • Partially offsetting the year-over-year increase in Commodity Margin, Adjusted EBITDA was negatively impacted by a $61 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010.

  • Plant operating expense4 from our legacy plants decreased by $28 million in the first nine months of 2011, although this decrease was offset by plant operating expense incurred for our Mid-Atlantic fleet, which was acquired as of July 1, 2010.

  • Lastly, sales, general and administrative expense5 increased by $8 million in the 2011 period, primarily as a result of a $10 million bad debt allowance reversal recorded in the first quarter of 2010 that did not recur in the current year period.

Net Loss1 was $177 million for the nine months ended September 30, 2011, compared to net income of $55 million in the prior-year period. As detailed in Table 1, Net Income, As Adjusted, was $30 million in the first nine months of 2011 compared to $25 million in the prior year period. The year-over-year increase in Net Income, As Adjusted, was primarily due to:
+ higher Commodity Margin, as previously discussed, and
+ lower depreciation and amortization expense due largely to assets that are now fully depreciated, as well as a revision in the expected settlement dates of the asset retirement obligations of our power plants, partially offset by
- an increase in plant operating expense, driven by higher major maintenance expenses and the addition of our Mid-Atlantic assets acquired as of July 1, 2010.

__________

1

Reported as net income (loss) attributable to Calpine on our Consolidated Condensed Statements of Operations.

2

Refer to Table 1 for further detail of Net Income, 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 and nine months ended September 30, 2011 and 2010.

5

Increase 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 nine months ended September, 2011 and 2010.

Table 1: Summarized Consolidated Condensed Statements of Operations

(Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
(in millions)
Operating revenues $ 2,209 $ 2,130 $ 5,341 $ 5,074
Operating expenses (1,811 ) (1,558 ) (4,749 ) (4,257 )
Impairment losses -- 19 -- 19
(Income) loss from unconsolidated investments in power plants (5 ) (1 ) (12 ) (14 )
Income from operations 403 554 604 812
Net interest expense, (gain) loss on interest rate derivatives, debt extinguishment costs, and other (income) expense 193 335 825 750
Income (loss) before income taxes and discontinued operations 210 219 (221 ) 62
Income tax expense (benefit) 20 21 (45 ) 38
Income (loss) before discontinued operations 190 198 (176 ) 24
Discontinued operations, net of tax expense -- 19 -- 31
Net income (loss) $ 190 $ 217 $ (176 ) $ 55
Net income attributable to the noncontrolling interest -- -- (1 ) --
Net income (loss) attributable to Calpine $ 190 $ 217 $ (177 ) $ 55

Discontinued operations, net of tax expense

-- (19 ) -- (31 )
Debt extinguishment costs(1) (4 ) 20 94 27
Unrealized MtM (gains) losses on derivatives(1)(2) (35 ) (35 ) 42 (97 )

Other items(1)(3)

44 38 71 71
Net Income, As Adjusted(4) $ 195 $ 221 $ 30 $ 25

__________

(1)

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

(2)

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.

(3)

Other items include realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps totaling $44 million and $147 million for the three and nine months ended September 30, 2011, respectively, and $13 million and $27 million for the three and nine months ended September 30, 2010, respectively. Other items for the nine months ended September 30, 2011, also include a $(76) million federal deferred income tax benefit associated with our election to consolidate our CCFC subsidiary for tax reporting purposes. Other items for the three and nine months ended September 30, 2010, also include $6 million and $25 million, respectively, in costs associated with the acquisition of our Mid-Atlantic fleet and $19 million in impairment of development costs related to a pre-bankruptcy project.

(4)

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 September 30, Nine Months Ended September 30,
2011 2010 Variance 2011 2010 Variance
West $ 329 $ 338 $ (9 ) $ 798 $ 809 $ (11 )
Texas 162 165 (3 ) 357 400 (43 )
North 259 259 -- 578 390 188
Southeast 75 90 (15 ) 188 216 (28 )
Total $ 825 $ 852 $ (27 ) $ 1,921 $ 1,815 $ 106

West Region

Third Quarter: Commodity Margin in our West segment decreased by $9 million for the third quarter of 2011 compared to the prior year period. Primary drivers included:
- lower spark spreads resulting from an increase of hydroelectric generation in California during the third quarter of 2011, partially offset by
+ higher Commodity Margin contribution from hedges and
+ the positive impact of origination activities for the third quarter of 2011 compared to the prior year period.

Year-to-Date: Commodity Margin in our West segment for the nine months ended September 30, 2011, was comparable to the prior year period. Primary drivers included:
- lower spark spreads resulting from an increase of hydroelectric generation in California in 2011 and
- 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

Third Quarter: Commodity Margin in our Texas segment for the third quarter of 2011 was comparable to the prior year period. Primary drivers included:
- the sale of a 25% undivided interest in the assets of our Freestone power plant, largely 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.

Year-to-Date: Commodity Margin in our Texas segment decreased by $43 million for the nine months ended September 30, 2011, compared to the prior year period. 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

Third Quarter: Commodity Margin in our North segment for the third quarter of 2011 was comparable to the prior year period. Primary drivers included:
+ an increase in Commodity Margin at our York Energy Center, which achieved commercial operations in March 2011, offset by
- lower spark spreads in the PJM market resulting from milder weather during the third quarter of 2011 compared to the same period in 2010.

Year-to-Date: Commodity Margin in our North segment increased by $188 million for the nine months ended September 30, 2011, compared to the prior year period. 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.

Southeast Region

Third Quarter: Commodity Margin in our Southeast segment decreased by $15 million for the third quarter of 2011, compared to the prior year period. Primary drivers included:
- the expiration of certain hedge contracts that benefited the third quarter of 2010 and
- the negative impact of an unscheduled outage at one of our power plants in the third quarter of 2011.

Year-to-Date: Commodity Margin in our Southeast segment decreased by $28 million for the nine months ended September 30, 2011, compared to the prior year period. The nine-month results were largely impacted by the same factors that drove performance for the third quarter, as previously discussed, along with unscheduled outages in the second quarter of 2011.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Liquidity

September 30, December 31,
2011 2010
(in millions)
Cash and cash equivalents, corporate(1) $ 977 $ 1,058
Cash and cash equivalents, non-corporate 308 269
Total cash and cash equivalents 1,285 1,327
Restricted cash 238 248
Revolving facility(ies) availability(2) 598 623
Letter of credit availability(3) 37 35
Total current liquidity availability $ 2,158 $ 2,233
__________

(1)

Includes $5 million and $6 million of margin deposits held by us posted by our counterparties at September 30, 2011, and December 31, 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 by the 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 Calpine Development Holdings, Inc.

Liquidity remained strong at $2.2 billion as of September 30, 2011, consistent with our liquidity levels as of December 31, 2010.

Cash flows provided by operating activities for the nine months ended September 30, 2011, resulted in net inflows of $536 million compared to $810 million for the prior year period. The change in cash flows from operating activities was primarily due to a reduction in margin requirements during the prior year period.

Cash flows from investing activities resulted in a net outflow of $660 million in the nine months ended September 30, 2011, driven largely by capital expenditures, including our growth projects at Russell City, Los Esteros and York Energy Centers and our turbine upgrade program.

Cash flows from financing activities resulted in a net inflow of $82 million, 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. Each of these project debt facilities provides a construction loan that converts to a ten-year term loan when the related project achieves commercial operation designation.

Adjusted Recurring Free Cash Flow was $381 million for the nine months ended September 30, 2011, compared to $499 million for the prior year period. Despite a $21 million increase in Adjusted EBITDA during the period, Adjusted Recurring Free Cash Flow declined primarily due to a $132 million increase in major maintenance costs (including expense and capital expenditures) resulting from our plant outage schedule and unscheduled outages.

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 October 27, 2011, we have executed approximately 10% of the program, having repurchased a total of 2.1 million shares of our common stock at an average price of $13.65 per share. The shares repurchased as of October 27, 2011, were purchased in open market transactions.

PLANT DEVELOPMENT

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. The project's Prevention of Significant Deterioration permit is currently the subject of an ongoing appeal at the U.S. Court of Appeals for the Ninth Circuit brought by Chabot-Las Positas Community College District against the EPA. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under 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 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.

Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through September 30, 2011, we have completed the upgrade of eight Siemens and five GE turbines and have agreed to upgrade approximately eight 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.

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; however, permitting challenges have emerged that we are continuing to resolve, and 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 near term, we will connect the 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.

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:

  • Edge Moor (Delaware): Recent completion of the feasibility study by PJM for the addition of 300 MW of combined-cycle capacity at our existing site, leveraging existing infrastructure. The study results are being analyzed, and the decision to proceed to system impact study phase is under consideration.

  • 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 and the feasibility study for the second phase will be completed shortly. Environmental permitting, site development planning and development engineering are underway.

  • Talbert (Maryland): Existing interconnect agreement for 200 MW of new simple-cycle capacity at a development site secured by a lease option. Discussions regarding construction of natural gas lateral to the project are in progress.

  • Powell (Maryland): Existing interconnect agreement for up to 500 MW of new simple-cycle capacity at a development site that is owned by Calpine. Fuel supply options are being pursued with potential suppliers.

  • Other locations that we feel provide similar opportunity to position us for growth within the region.

Mankato Power Plant Expansion Proposal: In March 2011, Xcel Energy Inc. (Xcel) filed a proposal 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 MPUC is expected to make a decision in 2012.

Channel and Deer Park Expansion: We continue to evaluate the ERCOT market for expansion opportunities based on tightening reserve margins and the potential impact of EPA regulations on generation in Texas. At both our Deer Park and Channel Energy Centers, we have the ability to install an additional combustion turbine generator and connect to the existing steam turbine generator to expand the capacity of these facilities and to improve the overall efficiency. In September 2011, we submitted 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. We anticipate filing similar permits in the fourth quarter of 2011 with the TCEQ and the EPA to expand the Channel Energy Center by approximately 275 MW.

OPERATIONS UPDATE

Third Quarter 2011 Power Operations Achievements:

  • Safety Performance:
    - First quartile lost-time incident rate of 0.24 year-to-date
    - No lost time incidents during third quarter
  • Availability Performance:
    - 96% fleet-wide availability
    - Achieved strong quarter fleet-wide starting reliability of 99%
    - Texas fleet forced outage factor of 0.9%

  • Geothermal Generation:
    - Achieved 100% starting reliability and provided approximately 1.5 million MWh of renewable baseload generation with 94% capacity factor
  • Natural Gas-fired Generation:
    - Channel, Deepwater, Edge Moor, Stony Brook, California Peakers6: 0% forced outage factor + 100% starting reliability

Third Quarter 2011 Commercial Operations Achievements:

  • Customer-oriented Growth:
    - Signed new contract with Southern California Edison for our Pastoria Energy Center: Added energy toll (750 MW, 2013 - 2015); Extended resource adequacy (715 MW, 2014 - 2015)

__________

6

Includes Yuba City, Feather River, Creed, Goose Haven, and Lambie.

FINANCIAL OUTLOOK

Full Year 2011 Full Year 2012
(in millions)
Adjusted EBITDA $ 1,700 - 1,750 $ 1,550 - 1,750
Less:
Operating lease payments 30 35
Major maintenance expense and capital expenditures(1) 390 350
Recurring cash interest, net 780 770
Cash taxes 15 10
Other 10 10
Adjusted Recurring Free Cash Flow $ 475 - 525 $ 375 - 575
Non-recurring interest rate swap payments(2) $ (175 ) $ (150 )
Growth Capital Expenditures (net of debt funding) $ (155 ) $ (10 )
Riverside sale proceeds $ 375
__________

(1)

Includes projected Major Maintenance Expense of $235 million and $185 million in 2011 and 2012, respectively, and maintenance Capital Expenditures of $155 million and $165 million in 2011 and 2012, respectively. 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, we are affirming our 2011 guidance of $1,700 million to $1,750 million of Adjusted EBITDA and $475 million to $525 million of Adjusted Recurring Free Cash Flow. We are also affirming our estimates of growth capital expenditures for the year. We expect to invest $155 million, net of debt funding, in growth-related projects during the year, including our York Energy Center (now complete), our construction projects at Russell City and Los Esteros and our ongoing turbine upgrade program.

Today, we are also initiating 2012 guidance. We expect Adjusted EBITDA of $1,550 million to $1,750 million and Adjusted Recurring Free Cash Flow of $375 million to $575 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 have already 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 secured for these projects earlier this year. Finally, we also expect to receive approximately $375 million during the fourth quarter of 2012 as a deposit from one of our customers toward 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 third quarter of 2011 on Friday, October 28, 2011, at 10 a.m. ET / 9 a.m. CT. A listen-only webcast of the call may be accessed through our website at http://www.calpine.com, or by dialing 888-771-4371 in the U.S. or 847-585-4405 outside the U.S. The confirmation code is 30885847. An archived recording of the call will be made available for a limited time on our website or by dialing 888-843-7419 (or 630-652-3042 outside the U.S.) and providing confirmation code 30897052#. Presentation materials to accompany the conference call will be made available on our website on October 28, 2011.

ABOUT CALPINE

Founded in 1984, Calpine Corporation is a major U.S. power company, currently capable of delivering approximately 28,000 megawatts of clean, cost-effective, reliable and fuel-efficient power from its 92 operating plants to customers and communities in 20 U.S. states and Canada. Calpine 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 athttp://www.calpine.com for more information.

Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC's website athttp://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 U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this report, including without limitation, "Management's Discussion and Analysis." 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 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 2010 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 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 CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
(in millions, except share and per share amounts)
Operating revenues $ 2,209 $ 2,130 $ 5,341 $ 5,074
Operating expenses:
Fuel and purchased energy expense 1,401 1,143 3,470 3,016
Plant operating expense 212 199 711 630
Depreciation and amortization expense 143 152 405 423
Sales, general and other administrative expense 33 41 99 113
Other operating expenses 22 23 64 75
Total operating expenses 1,811 1,558 4,749 4,257
Impairment losses -- 19 -- 19
Income from unconsolidated investments in power plants (5 ) (1 ) (12 ) (14 )
Income from operations 403 554 604 812
Interest expense 192 230 575 635
(Gain) loss on interest rate derivatives, net 3 84 149 87
Interest (income) (2 ) (2 ) (7 ) (8 )
Debt extinguishment costs (4 ) 20 94 27
Other (income) expense, net 4 3 14 9
Income (loss) before income taxes and discontinued operations 210 219 (221 ) 62
Income tax expense (benefit) 20 21 (45 ) 38
Income (loss) before discontinued operations 190 198 (176 ) 24
Discontinued operations, net of tax expense -- 19 -- 31
Net income (loss) 190 217 (176 ) 55
Net income attributable to the noncontrolling interest -- -- (1 ) --
Net income (loss) attributable to Calpine $ 190 $ 217 $ (177 ) $ 55
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 486,420 486,088 486,363 486,023
Income (loss) before discontinued operations attributable to Calpine $ 0.39 $ 0.41 $ (0.36 ) $ 0.05
Discontinued operations, net of tax expense attributable to Calpine -- 0.04 -- 0.06
Net income (loss) per common share attributable to Calpine - basic $ 0.39 $ 0.45 $ (0.36 ) $ 0.11
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) 489,062 487,443 486,363 487,199
Income (loss) before discontinued operations attributable to Calpine $ 0.39 $ 0.41 $ (0.36 ) $ 0.05
Discontinued operations, net of tax expense attributable to Calpine -- 0.04 -- 0.06
Net income (loss) per common share attributable to Calpine - diluted $ 0.39 $ 0.45 $ (0.36 ) $ 0.11

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

September 30, December 31,
2011 2010
(in millions, except
share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 1,285 $ 1,327
Accounts receivable, net of allowance of $8 and $2 755 669
Margin deposits and other prepaid expense 224 221
Restricted cash, current 195 195
Derivative assets, current 690 725
Inventory and other current assets 281

292
Total current assets 3,430 3,429
Property, plant and equipment, net 13,010 12,978
Restricted cash, net of current portion 43 53
Investments 75 80
Long-term derivative assets 134 170
Other assets 539 546
Total assets $ 17,231 $ 17,256
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 558 $ 514
Accrued interest payable 166 132
Debt, current portion 101 152
Derivative liabilities, current 779 718
Other current liabilities 269 273
Total current liabilities 1,873 1,789
Debt, net of current portion 10,303 10,104
Deferred income taxes, net of current 1 77
Long-term derivative liabilities 303 370
Other long-term liabilities 232 247
Total liabilities 12,712 12,587
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding -- --
Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 490,552,649 and 444,883,356 shares issued, respectively, and 489,779,285 and 444,435,198 shares outstanding, respectively 1 1
Treasury stock, at cost, 773,364 and 448,158 shares, respectively (9 ) (5 )
Additional paid-in capital 12,299 12,281
Accumulated deficit (7,686 ) (7,509 )
Accumulated other comprehensive loss (147 ) (125 )
Total Calpine stockholders' equity 4,458 4,643
Noncontrolling interest 61 26
Total stockholders' equity 4,519 4,669
Total liabilities and stockholders' equity

$

17,231 $ 17,256

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30,

2011 2010
(in millions)
Cash flows from operating activities:
Net income (loss) $ (176

)

$ 55
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense(1) 431 464
Debt extinguishment costs 82 27
Deferred income taxes (56 ) 40
Impairment losses -- 19
Loss on disposal of assets 18 11
Unrealized mark-to-market activity, net 42 (97 )
Income from unconsolidated investments in power plants (12 ) (14 )
Return on unconsolidated investments in power plants 6 11
Stock-based compensation expense 18 18
Other 5 1
Change in operating assets and liabilities:
Accounts receivable (87 ) 34
Derivative instruments, net (6 ) (42 )
Other assets 27 241
Accounts payable and accrued expenses 95 (1 )
Liabilities related to non-hedging interest rate swaps 147 27
Other liabilities 2 16
Net cash provided by operating activities 536 810
Cash flows from investing activities:
Purchases of property, plant and equipment (511 ) (191 )
Purchase of Conectiv assets -- (1,634 )
Cash acquired due to consolidation of OMEC -- 8
Purchases of deferred transmission credits (16 ) --
Decrease in restricted cash 9 228
Settlement of non-hedging interest rate swaps (147 ) (27 )
Other 5 4
Net cash used in investing activities (660 ) (1,612 )
Cash flows from financing activities:
Repayments of project financing, notes payable and other $ (476 ) $ (472 )
Borrowings from project financing, notes payable and other 223 1,272
Repayments on NDH Project Debt (1,283 ) --
Borrowings under Term Loan and New Term Loan 1,657 --
Issuance of First Lien Notes 1,200 1,491
Repayments on First Lien Credit Facility (1,191 ) (1,507 )
Capital contributions from noncontrolling interest holder 34 --
Financing costs (78 ) (67 )
Refund of financing costs -- 10
Other (4 ) --
Net cash provided by financing activities 82 727
Net decrease in cash and cash equivalents (42 ) (75

)

Cash and cash equivalents, beginning of period 1,327 989
Cash and cash equivalents, end of period $ 1,285 $ 914
Cash paid during the period for:
Interest, net of amounts capitalized $ 509 $ 488
Income taxes $ 15 $ 11
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable $ (13 ) $ (5 )
Purchase of Conectiv assets included in accounts payable $ --

$

6

__________

(1)

Includes depreciation and amortization that is also recorded in fuel and purchased energy expense, interest expense and discontinued operations on our Consolidated Condensed 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, debt extinguishment costs, 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 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 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 (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 table reconciles our Commodity Margin to its U.S. GAAP results for the three months ended September 30, 2011 and 2010:

Three Months Ended September 30, 2011
(in millions)

Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin

$

329 $ 162 $ 259 $ 75 $ -- $ 825

Add: Mark-to-market commodity activity, net and other(1)(2)

20 (21 ) (11 ) -- (8 ) (20 )
Less:
Plant operating expense 94 50 44 33 (9 ) 212
Depreciation and amortization expense 52 34 36 22 (1 ) 143
Sales, general and other administrative expense 10 10 7 7 (1 ) 33
Other operating expenses(3) 11 (1 ) 7 -- 2 19
Income from unconsolidated investments in power plants -- -- (5 ) -- -- (5 )
Income from operations

$

182 $ 48 $ 159 $ 13 $ 1 $ 403

Three Months Ended September 30, 2010
(in millions)

Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin

$

338 $ 165 $ 259 $ 90 $ -- $ 852
Add: Mark-to-market commodity activity, net and other(1) 42 62 18 18 (6 ) 134
Less:
Plant operating expense 86 55 38 28 (8 ) 199
Depreciation and amortization expense 52 37 37 28 (2 ) 152
Sales, general and other administrative expense 10 13 12 5 1 41
Other operating expenses(3) 14 -- 6 -- 2 22
Impairment losses -- -- -- 19 -- 19
(Income) from unconsolidated investments in power plants -- -- (1 ) -- -- (1 )
Income from operations

$

218 $ 122 $ 185 $ 28 $ 1 $ 554

The following table reconciles our Commodity Margin to its U.S. GAAP results for the nine months ended September 30, 2011 and 2010:

Nine Months Ended September 30, 2011
(in millions)

Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 798 $ 357 $ 578 $ 188 $ -- $ 1,921

Add: Mark-to-market commodity activity, net and other revenue(1)(2)

36 (54 ) (12 ) (4 ) (23 ) (57

)

Less:
Plant operating expense 297 193 136 107 (22 ) 711
Depreciation and amortization expense 140 99 102 67 (3 ) 405
Sales, general and other administrative expense 29 33 19 18 -- 99
Other operating expenses(3) 30 2 23 3 (1 ) 57
(Income) from unconsolidated investments in power plants -- -- (12 ) -- -- (12

)

Income (loss) from operations $ 338 $ (24 ) $ 298 $ (11 ) $ 3 $ 604

Nine Months Ended September 30, 2010
(in millions)

Consolidation
And
West Texas North Southeast Elimination Total
Commodity Margin $ 809 $ 400 $ 390 $ 216 $ -- $ 1,815
Add: Mark-to-market commodity activity, net and other revenue(1) 60 148 18 31 (20 ) 237
Less:
Plant operating expense 264 217 83 87 (21 ) 630
Depreciation and amortization expense 155 113 76 84 (5 ) 423
Sales, general and other administrative expense 36 29 37 11 -- 113
Other operating expenses(3) 43 2 21 2 1 69
Impairment losses -- -- -- 19 -- 19
(Income) from unconsolidated investments in power plants -- -- (14 ) -- -- (14 )
Income from operations $ 371 $ 187 $ 205 $ 44 $ 5 $ 812
__________

(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 Condensed Statements of Operations.

(2)

Includes $11 million and $15 million of lease levelization and $4 million and $5 million of contract amortization for the three and nine months ended September 30, 2011, respectively, related to contracts that became effective in 2011.

(3)

Excludes $3 million and $1 million of RGGI compliance costs and other environmental costs for the three months ended September 30, 2011 and 2010, respectively, and $7 million and $6 million for the nine months ended September 30, 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 Loss for the three and nine months ended September 30, 2011 and 2010, as reported under U.S. GAAP.

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
(in millions)
Net income (loss) attributable to Calpine $ 190 $ 217 $ (177 ) $ 55
Net income attributable to noncontrolling interest -- -- 1 --
Discontinued operations, net of tax expense -- (19 ) -- (31 )
Income tax expense (benefit) 20 21 (45 ) 38
Other (income) expense and debt extinguishment costs, net -- 23 108 36
(Gain) loss on interest rate derivatives, net 3 84 149 87
Interest expense, net 190 228 568 627
Income from operations $ 403 $ 554 $ 604 $ 812
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1) 143 151 406 424
Impairment losses -- 19 -- 19
Major maintenance expense 33 13 169 111
Operating lease expense 9 11 26 33
Unrealized (gain) loss on commodity derivative mark-to-market activity 9 (131 ) 48 (212 )
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2) 9 10 30 25
Stock-based compensation expense 6 6 18 18
Loss on dispositions of assets 8 2 17 7
Conectiv acquisition-related costs -- 6 -- 25
Contract amortization 4 -- 5 --
Other 14 2 24 3
Adjusted EBITDA from continuing operations 638 643 1,347 1,265
Adjusted EBITDA from discontinued operations -- 20 -- 61
Total Adjusted EBITDA $ 638 $ 663 $ 1,347 $ 1,326
Less:
Lease payments 9 11 26 33
Major maintenance expense and capital expenditures(3) 72 69 335 203
Cash interest(4) 194 200 587 582
Cash taxes 1 2 11 10
Other 1 -- 7 (1 )
Adjusted Recurring Free Cash Flow(5) $ 361 $ 381 $ 381 $ 499
_________

(1)

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

(2)

Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized losses on mark-to-market activity of $1 million for both the three and nine months ended September 30, 2011 and 2010.

(3)

Includes $35 million and $174 million in major maintenance expense for the three and nine months ended September 30, 2011, respectively, and $37 million and $161 million in maintenance capital expenditures for the three and nine months ended September 30, 2011, respectively. Includes $5 million and $110 million in major maintenance expense for the three and nine months ended September 30, 2010, respectively, and $64 million and $93 million in maintenance capital expenditures for the three and nine months ended September 30, 2010, respectively.

(4)

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

(5)

Excludes increase in working capital of $166 million and $21 million for the three and nine months ended September 30, 2011, respectively, and a decrease in working capital of $48 million and an increase in working capital of $32 million for the three and nine months ended September 30, 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 and nine months ended September 30, 2011 and 2010. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
(in millions)
Commodity Margin $ 825 $ 852 $ 1,921 $ 1,815
Other revenue 4 2 11 24
Plant operating expense(1) (166 ) (181 ) (512 ) (504 )
Sales, general and administrative expense(2) (30 ) (31 ) (85 ) (77 )
Other operating expense(3) (11 ) (10 ) (30 ) (33 )
Adjusted EBITDA from unconsolidated investments in power plants(4) 15 11 42 39
Adjusted EBITDA from discontinued operations(5) -- 20 -- 61
Other 1 -- -- 1
Adjusted EBITDA $ 638 $ 663 $ 1,347 $ 1,326
_________

(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 $3 million and $1 million of RGGI compliance costs and other environmental costs for the three months ended September 30, 2011 and 2010, respectively, and $7 million and $6 million for the nine months ended September 30, 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 power plants, which were sold in December 2010.

Adjusted EBITDA and Adjusted Recurring Free Cash Flow Reconciliation for Guidance

Full Year 2011 Range: Low High
(in millions)
GAAP Net Income (Loss)(1) $ (150 ) $ (100 )
Plus:
(Gain) loss on interest rate derivatives, net 149 149
Debt extinguishment costs 94 94
Interest expense, net of interest income 760 760
Depreciation and amortization expense 560 560
Major maintenance expense 230 230
Operating lease expense 35 35
Other(2) 22 22
Adjusted EBITDA $ 1,700 $ 1,750
Less:
Operating lease payments 30 30
Major maintenance expense and maintenance capital expenditures(3) 390 390
Recurring cash interest, net(4) 780 780
Cash taxes 15 15
Other 10 10
Adjusted Recurring Free Cash Flow $ 475 $ 525
Non-recurring interest rate swap payments(5) 175 175

__________

(1)

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

(2)

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

(3)

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

(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. Does not include $17 million in interest rate swap breakage costs related to the repayment of project debt in June 2011.

Full Year 2012 Range: Low High
(in millions)
GAAP Net Income (Loss)(1) $ (80 ) $ 120
Plus:
Interest expense, net of interest income 765 765
Depreciation and amortization expense 555 555
Major maintenance expense 185 185
Operating lease expense 35 35
Other(2) 90 90
Adjusted EBITDA $ 1,550 $ 1,750
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 $ 375 $ 575
Non-recurring interest rate swap payments(5) 150 150
__________

(1)

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

(2)

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

(3)

Includes projected major maintenance expense of $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 nine months ended September 30, 2011 and 2010:

Nine Months Ended September 30,

2011 2010
(in millions)
Beginning cash and cash equivalents $ 1,327 $ 989
Net cash provided by (used in):
Operating activities 536 810
Investing activities (660 ) (1,612 )
Financing activities 82 727
Net increase (decrease) in cash and cash equivalents (42 ) (75

)

Ending cash and cash equivalents $ 1,285 $ 914

OPERATING PERFORMANCE METRICS

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

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010

Total MWh generated (in thousands(1))

28,400 28,208 65,921 67,813
West 6,540 8,093 16,189 22,795
Texas 10,833 9,533 24,019 24,419
Southeast 5,918 6,065 14,489 13,712
North 5,109 4,517 11,224 6,887
Average availability 95.9 % 95.9 % 89.8 % 91.5 %
West 91.2 % 92.9 % 86.4 % 91.5 %
Texas 98.2 % 96.5 % 88.8 % 89.1 %
Southeast 96.6 % 97.4 % 92.0 % 93.4 %
North 97.5 % 96.8 % 92.3 % 93.1 %
Average capacity factor, excluding peakers 53.8 % 54.3 % 42.9 % 47.9 %
West 47.4 % 58.7 % 39.6 % 55.7 %
Texas 70.1 % 60.0 % 52.5 % 51.9 %
Southeast 48.9 % 49.3 % 41.0 % 38.4 %
North 43.4 % 43.7 % 34.4 % 36.8 %
Steam adjusted heat rate (mmbtu/kWh) 7,464 7,415 7,434 7,328
West 7,479 7,345 7,488 7,315
Texas 7,296 7,305 7,256 7,222
Southeast 7,344 7,366 7,323 7,331
North 8,003 7,865 7,939 7,773
________

(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