31.10.11

Calpine: Q3 Results

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Calpine Corporation 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.

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 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)

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 at http://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 at http://www.sec.gov.

SOURCE: Calpine Corporation

Calpine Corporation
Investor Relations:
Bryan Kimzey, 713-830-8777
bryan.kimzey@calpine.com
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