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Calpine Corporation: Q2 Results
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Calpine Corporation reported second quarter 2011 Adjusted EBITDA of $406 million, compared to $381 million in the prior year second quarter, and second quarter 2011 Adjusted Recurring Free Cash Flow of $41 million, compared to $131 million in the second quarter of 2010. Net Loss2 for the quarter improved to $70 million, or $0.14 per diluted share, compared to a Net Loss of $115 million, or $0.24 per diluted share, in the 2010 period.
“We are pleased to report solid operating and financial results during the second quarter, demonstrating our consistent focus on serving customers, enhancing our balance sheet and delivering financially disciplined growth,” said Jack Fusco, Calpine’s President and Chief Executive Officer. “From an operating perspective, we produced 20 million MWh1 of power while achieving second quarter and year-to-date starting reliability of 98%, the highest on record. This achievement was that much more remarkable because it was achieved against the backdrop of the highest number of turbine starts on record, showing that our reliable and flexible fleet of efficient, modern generation assets continues to deliver when our customers need us. On the expense side, we reduced second quarter plant operating expense3 for our legacy fleet compared to the same period in 2010, and sales, general and administrative expense4 was flat despite a net capacity increase of nearly 3,400 MW across the portfolio year over year. Commodity Margin was up significantly and Adjusted EBITDA increased by 7% versus last year’s second quarter, in each case primarily due to the strategic acquisition of the Mid-Atlantic plants last July. As a result of this performance, we are updating and tightening our 2011 guidance – we now project full year Adjusted EBITDA of $1,700 million to $1,750 million, within the guidance range we provided late last year, and we are raising our Adjusted Free Cash Flow guidance to $475 million to $525 million.
“In addition, it is worth mentioning some developments that could positively impact Calpine in the future. On the environmental regulatory front, we note that the EPA’s proposed Toxics Rule and the more recently issued CSAPR rule are likely to have a meaningful impact on the shape of the industry over the next several years. These rules are, in our view, long overdue and justified. Indeed, Calpine’s investment thesis has, at its core, long anticipated these and other changes that should position the company well for the new landscape. That said, there will be continued attempts to delay, amend or override these rules. We have been and will continue to be a voice of reason in the debate. On the competitive markets front, we have observed efforts that will challenge competition, ranging from state subsidization of new construction to demand response mechanisms that carry little disincentive to abuse. We will continue to strenuously oppose these encroachments so that competitive markets can continue to deliver lower prices than fully regulated markets. More positively, we see signs that markets are beginning to understand the value of the flexibility that modern, clean and efficient natural gas-fired combined-cycle generation provides, particularly given the need to integrate renewable generation into the grid. On balance, we believe the march toward environmental change is relentless and the commitment to competitive markets, while still maturing, remains steadfast.”
Zamir Rauf, Calpine’s Chief Financial Officer, added, “From a balance sheet perspective, we successfully refinanced $360 million of project level debt at the corporate level, simplifying our capital structure and releasing restricted cash. We also closed on the project financing to fund construction of our Russell City Energy Center. Construction efforts are well underway at Russell City, as well as at Los Esteros, where project financing is in advanced stages. We remain on budget and on schedule for both of these significant growth projects. On the bankruptcy front, we made meaningful headway toward closing the book by settling all outstanding disputed claims. As a consequence we have issued over half of the remaining reserve shares that had been set aside to satisfy bankruptcy claims, and we expect to distribute the remaining shares over the next several months. It is important to recall that the sale and distributions have no dilutive effect, as they have always been included in our calculation of outstanding shares.
“Also during the second quarter and since, we conducted the initial phases of an auction process for our Broad River and Mankato Energy Centers. As we explained when we announced the auction, we would be financially disciplined and sell the assets only if the value offered exceeded the value of the assets to us, including the associated long-term contracts and the optionality for growth at the sites. The bids did not meet these criteria and, as a result, we have concluded the auction process and are pleased to retain these quality plants as part of the Calpine fleet.”
SUMMARY OF FINANCIAL PERFORMANCE
Second Quarter Results
Adjusted EBITDA for the second quarter of 2011 increased to $406 million compared to $381 million in the second quarter of 2010. The increase was primarily due to a $69 million improvement in Commodity Margin, to $602 million in the second quarter of 2011 from $533 million in the second quarter of 2010. The year-over-year increase was primarily due to our North segment, where Commodity Margin increased by $100 million due largely to the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010. This increase was offset, in part, by a $22 million decrease in Commodity Margin from our West segment. Despite higher average hedge prices year-over-year, Commodity Margin in the West declined primarily as a result of a decrease of $10 million in renewable energy credit (REC) revenue relating to the timing of the receipt of CPUC approval of new contracts associated with our Geysers assets in the second quarter of 2010, as well as lower market heat rates on our off-peak open position driven by increased hydroelectric generation in California and from an unscheduled outage at Otay Mesa Energy Center (OMEC) during the second quarter of 2011.
Offsetting the year-over-year increase in Commodity Margin, Adjusted EBITDA was negatively impacted by a $20 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010. Also contributing to the offset, other revenue decreased by $16 million compared to the first quarter of 2011 due to favorable major maintenance contract revenue adjustments that were recognized in the second quarter of 2010.
Net Loss2 was $70 million for the three months ended June 30, 2011, compared to a Net Loss of $115 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, was $55 million in the second quarter of 2011 compared to $43 million in the second quarter of 2010. Though Commodity Margin increased, as previously discussed, this improvement was offset by increases in plant operating expense associated with the acquisition of our Mid-Atlantic fleet as well as higher major maintenance resulting from our plant outage schedule. In addition, income tax expense increased by $12 million year-over-year, primarily as a result of an increase of $49 million related to the application of intraperiod tax allocation partially offset by a decrease in federal income tax of $20 million and various state and foreign jurisdiction income taxes of $16 million.
Year-to-Date Results
Adjusted EBITDA for the six months ended June 30, 2011, was $709 million as compared to $663 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily the result of a $128 million increase in Commodity Margin due in large part to our North segment, where Commodity Margin increased by $183 million primarily driven by the acquisition of our Mid-Atlantic plants, higher spark spreads on open positions at our legacy power plants due to higher market heat rates, and higher average hedge prices during the first half of 2011. Partially offsetting the increase in the North region, our Texas segment experienced a $40 million decline in Commodity Margin. Despite an increase in average hedge prices, our Texas segment was negatively impacted by unplanned outages during an extreme cold weather event in early February 2011, as well as lower average availability in the first quarter influenced by more scheduled outages.
Partially offsetting the year-over-year increase in Commodity Margin, Adjusted EBITDA was negatively impacted by a $41 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010. In addition, although plant operating expense3 increased by $23 million year-over-year, this increase was primarily driven by the addition of our Mid-Atlantic plants in July 2010; consistent with our focus on efficiencies, plant operating expense3 for our legacy fleet decreased $11 million year-over-year. Sales, general and administrative expense4 remained comparable year-over-year, with the exception of a $10 million credit related to the reversal of a bad debt allowance in the first half of 2010 that did not recur in the current period. Also contributing to the offset, as previously discussed, was a $15 million favorable adjustment in other revenue recognized during the first half of 2010 related to a major maintenance contract.
Net loss2 increased to $367 million for the six months ended June 30, 2011, from $162 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, was $165 million in the first half of 2011 compared to $196 million in the first half of 2010. The improvement was primarily due to the increase in Commodity Margin, as previously discussed, offset by increases in plant operating expense associated with the acquisition of our Mid-Atlantic fleet and higher major maintenance expense associated with our plant outage schedule, as well as a $10 million bad debt allowance reversal recognized in the first half of 2010 that did not recur in the first half of 2011, as previously discussed.
1 Includes generation from unconsolidated power plants and plants owned but not operated by Calpine.
2 Reported as net loss attributable to Calpine on our Consolidated Condensed 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 six months ended June 30, 2011 and 2010.
4 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 six months ended June 30, 2011 and 2010.
West: Commodity Margin in our West segment decreased by $22 million for the three months ended June 30, 2011, compared to the same period in 2010, primarily resulting from a decrease of $10 million in REC revenue relating to the timing of revenue recognized during the second quarter of 2010 associated with the receipt of CPUC approval of new contracts related to our Geysers assets. In addition, Commodity Margin decreased due to lower market heat rates on our off-peak open position resulting from an increase in hydroelectric generation in California which is forecast to be significantly higher in 2011 compared to 2010, and from an unscheduled outage at OMEC during the second quarter of 2011. The decrease was partially offset by higher average hedge prices for the second quarter of 2011 compared to 2010.
Commodity Margin in our West segment was comparable for the six months ended June 30, 2011 compared to the same period in 2010. During the first half of 2011, we experienced higher average hedge prices as well as positive impacts from origination activities. The increase was partially offset by lower market heat rates on our open position resulting from an increase in hydroelectric generation in California, as previously discussed, and lower Commodity Margin resulting from an unscheduled outage at OMEC during the second quarter of 2011.
Texas: Commodity Margin in our Texas segment was comparable for the three months ended June 30, 2011, compared to the same period in 2010. During the second quarter of 2011, we realized higher average hedge prices and higher market heat rates on our open position, which was largely offset by lower Commodity Margin associated with the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010.
Commodity Margin in our Texas segment decreased by $40 million for the six months ended June 30, 2011 compared to the same period in 2010. Despite an increase in average hedge prices, Commodity Margin was negatively impacted by unplanned outages at some of our power plants caused by an extreme cold weather event which occurred on February 2, 2011. Power prices increased dramatically as a result of the cold weather event and the plant outages, which required us to purchase physical replacement power at prices substantially above our hedged prices. Lower average availability in the first quarter of 2011, influenced by higher scheduled outages, as well as the aforementioned sale of an undivided interest in the assets of our Freestone power plant, also contributed to the period over period decrease in Commodity Margin.
North: Commodity Margin in our North segment increased by $100 million for the three months ended June 30, 2011, compared to the same period in 2010, primarily due to the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010.
Commodity Margin in our North segment increased by $183 million, for the six months ended June 30, 2011, compared to the same period in 2010, primarily due to the Mid-Atlantic acquisition, as previously discussed. The increase in Commodity Margin also resulted from higher realized spark spreads on open positions among our legacy power plants driven by an increase in market heat rates, and higher average hedge prices for the six months ended June 30, 2011 compared to the six months ended June 30, 2010.
Southeast: Commodity Margin in our Southeast segment decreased by $9 million for the three months ended June 30, 2011, compared to the same period in 2010 largely due to the expiration of certain hedge contracts which benefited the second quarter of 2010 as well as lower Commodity Margin that resulted from unscheduled outages that occurred during the second quarter of 2011.
Commodity Margin in our Southeast segment decreased by $13 million for the six months ended June 30, 2011 compared to the same period in 2010. The six-month results were largely impacted by the same factors that drove performance for the second quarter, as previously discussed.
Liquidity remained strong at over $2.0 billion as of June 30, 2011, down modestly from $2.2 billion at December 31, 2010. Cash flows provided by operating activities for the six months ended June 30, 2011, resulted in net inflows of $239 million compared to $170 million for the same period in 2010. The change in cash flows from operating activities was primarily due to income from operations, which increased by $55 million during the period after adjusting for non-cash items. In addition, cash paid for interest decreased by $70 million due to the timing of interest payments on our new bonds and term loans compared to the previously outstanding First Lien Credit Facility and project debt. These improvements were partially offset by an increase in working capital employed of $19 million, after adjusting for debt related balances that did not impact cash provided by operating activities, as well as prepayment premiums of $13 million incurred during the six months ended June 30, 2011. Cash flows from investing activities resulted in a net outflow of $421 million in the six months ended June 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 $2 million, primarily as a result of the net impact of refinancing activities, as further discussed below.
Adjusted Recurring Free Cash Flow was $20 million for the six months ended June 30, 2011, compared to $118 million for the prior year period. Despite a $46 million increase in Adjusted EBITDA, Adjusted Recurring Free Cash Flow declined primarily as a result of a $129 million increase in major maintenance expense and capital expenditures resulting from our plant outage schedule and unscheduled outages. We remain on track with our annual maintenance program, which is reflected in our raised 2011 Adjusted Recurring Free Cash Flow guidance.
During the second quarter of 2011, we continued to improve the quality of our liquidity by securing a $360 million term loan to retire project debt associated with our Metcalf and Deer Park Energy Centers. This refinancing allowed us to migrate project debt to the corporate level, further simplifying our capital structure and alleviating cash restrictions. During the period, we also obtained an approximately $845 million credit facility to finance the construction of the 619 MW combined-cycle Russell City Energy Center, in which we own a 75% interest. The credit facility provides a construction loan that converts to a ten-year term loan when commercial operations begin.
PLANT DEVELOPMENT
York Energy Center: We acquired the York Energy Center, a 565 MW dual fuel, combined-cycle power plant under construction as part of the acquisition of our Mid-Atlantic portfolio. York Energy Center achieved COD on March 2, 2011, three months early. The York Energy Center sells power under a six-year PPA with a third party which commenced on June 1, 2011.
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 have executed contracts for all major equipment and have selected and contracted with the engineering, procurement and construction contractor. We began construction in the second quarter of 2011 and are in the process of obtaining project financing which is expected to be completed in the third quarter of 2011. We expect COD in 2013.
Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through June 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 falling in line 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 expect to receive the Sonoma County permit in the second half of 2011. 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 due to the permitting challenges, we may not meet a 2013 COD. 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 by both 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): Feasibility study under way with PJM for the addition of 300 MW of combined-cycle capacity at our existing site, leveraging existing infrastructure;
• Garrison (Delaware): Actively permitting 309 MW of new combined-cycle capacity at a development site secured by a lease option;
• Talbert (Maryland): Existing interconnect agreement for 200 MW of new simple-cycle capacity at a development site secured by a lease option;
• Powell (Maryland): Existing interconnect agreement for 300 – 500 MW of new simple-cycle capacity at a development site that we are currently in the process of purchasing; and
• Other locations that we feel provide similar opportunity to position us for growth within the region.
OPERATIONS UPDATE
Second Quarter 2011 Power Operations Achievements:
Safety Performance:
First quartile lost-time incident rate of 0.36 year-to-date
Availability Performance:
Achieved record second quarter fleet-wide starting reliability of over 98%
Geothermal Generation: Provided approximately 1.5 million MWh of renewable baseload generation with 92% capacity factor
Natural Gas-fired Generation:
Mankato Energy Center: Achieved 100% starting reliability and 0% forced outage factor during second quarter of 2011
Second Quarter 2011 Commercial Operations Achievements:
Customer-oriented Growth:
Signed ten-year contract with Entergy Texas, Inc. to provide 485 MW of power from Carville Energy Center
Signed additional seasonal originated contract in the Southeast
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 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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov.
Contact:
Calpine Corporation
Investor Relations:
Christine Parker, 713-830-8775
[email protected]
Calpine Corporation reported second quarter 2011 Adjusted EBITDA of $406 million, compared to $381 million in the prior year second quarter, and second quarter 2011 Adjusted Recurring Free Cash Flow of $41 million, compared to $131 million in the second quarter of 2010. Net Loss2 for the quarter improved to $70 million, or $0.14 per diluted share, compared to a Net Loss of $115 million, or $0.24 per diluted share, in the 2010 period.
“We are pleased to report solid operating and financial results during the second quarter, demonstrating our consistent focus on serving customers, enhancing our balance sheet and delivering financially disciplined growth,” said Jack Fusco, Calpine’s President and Chief Executive Officer. “From an operating perspective, we produced 20 million MWh1 of power while achieving second quarter and year-to-date starting reliability of 98%, the highest on record. This achievement was that much more remarkable because it was achieved against the backdrop of the highest number of turbine starts on record, showing that our reliable and flexible fleet of efficient, modern generation assets continues to deliver when our customers need us. On the expense side, we reduced second quarter plant operating expense3 for our legacy fleet compared to the same period in 2010, and sales, general and administrative expense4 was flat despite a net capacity increase of nearly 3,400 MW across the portfolio year over year. Commodity Margin was up significantly and Adjusted EBITDA increased by 7% versus last year’s second quarter, in each case primarily due to the strategic acquisition of the Mid-Atlantic plants last July. As a result of this performance, we are updating and tightening our 2011 guidance – we now project full year Adjusted EBITDA of $1,700 million to $1,750 million, within the guidance range we provided late last year, and we are raising our Adjusted Free Cash Flow guidance to $475 million to $525 million.
“In addition, it is worth mentioning some developments that could positively impact Calpine in the future. On the environmental regulatory front, we note that the EPA’s proposed Toxics Rule and the more recently issued CSAPR rule are likely to have a meaningful impact on the shape of the industry over the next several years. These rules are, in our view, long overdue and justified. Indeed, Calpine’s investment thesis has, at its core, long anticipated these and other changes that should position the company well for the new landscape. That said, there will be continued attempts to delay, amend or override these rules. We have been and will continue to be a voice of reason in the debate. On the competitive markets front, we have observed efforts that will challenge competition, ranging from state subsidization of new construction to demand response mechanisms that carry little disincentive to abuse. We will continue to strenuously oppose these encroachments so that competitive markets can continue to deliver lower prices than fully regulated markets. More positively, we see signs that markets are beginning to understand the value of the flexibility that modern, clean and efficient natural gas-fired combined-cycle generation provides, particularly given the need to integrate renewable generation into the grid. On balance, we believe the march toward environmental change is relentless and the commitment to competitive markets, while still maturing, remains steadfast.”
Zamir Rauf, Calpine’s Chief Financial Officer, added, “From a balance sheet perspective, we successfully refinanced $360 million of project level debt at the corporate level, simplifying our capital structure and releasing restricted cash. We also closed on the project financing to fund construction of our Russell City Energy Center. Construction efforts are well underway at Russell City, as well as at Los Esteros, where project financing is in advanced stages. We remain on budget and on schedule for both of these significant growth projects. On the bankruptcy front, we made meaningful headway toward closing the book by settling all outstanding disputed claims. As a consequence we have issued over half of the remaining reserve shares that had been set aside to satisfy bankruptcy claims, and we expect to distribute the remaining shares over the next several months. It is important to recall that the sale and distributions have no dilutive effect, as they have always been included in our calculation of outstanding shares.
“Also during the second quarter and since, we conducted the initial phases of an auction process for our Broad River and Mankato Energy Centers. As we explained when we announced the auction, we would be financially disciplined and sell the assets only if the value offered exceeded the value of the assets to us, including the associated long-term contracts and the optionality for growth at the sites. The bids did not meet these criteria and, as a result, we have concluded the auction process and are pleased to retain these quality plants as part of the Calpine fleet.”
SUMMARY OF FINANCIAL PERFORMANCE
Second Quarter Results
Adjusted EBITDA for the second quarter of 2011 increased to $406 million compared to $381 million in the second quarter of 2010. The increase was primarily due to a $69 million improvement in Commodity Margin, to $602 million in the second quarter of 2011 from $533 million in the second quarter of 2010. The year-over-year increase was primarily due to our North segment, where Commodity Margin increased by $100 million due largely to the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010. This increase was offset, in part, by a $22 million decrease in Commodity Margin from our West segment. Despite higher average hedge prices year-over-year, Commodity Margin in the West declined primarily as a result of a decrease of $10 million in renewable energy credit (REC) revenue relating to the timing of the receipt of CPUC approval of new contracts associated with our Geysers assets in the second quarter of 2010, as well as lower market heat rates on our off-peak open position driven by increased hydroelectric generation in California and from an unscheduled outage at Otay Mesa Energy Center (OMEC) during the second quarter of 2011.
Offsetting the year-over-year increase in Commodity Margin, Adjusted EBITDA was negatively impacted by a $20 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010. Also contributing to the offset, other revenue decreased by $16 million compared to the first quarter of 2011 due to favorable major maintenance contract revenue adjustments that were recognized in the second quarter of 2010.
Net Loss2 was $70 million for the three months ended June 30, 2011, compared to a Net Loss of $115 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, was $55 million in the second quarter of 2011 compared to $43 million in the second quarter of 2010. Though Commodity Margin increased, as previously discussed, this improvement was offset by increases in plant operating expense associated with the acquisition of our Mid-Atlantic fleet as well as higher major maintenance resulting from our plant outage schedule. In addition, income tax expense increased by $12 million year-over-year, primarily as a result of an increase of $49 million related to the application of intraperiod tax allocation partially offset by a decrease in federal income tax of $20 million and various state and foreign jurisdiction income taxes of $16 million.
Year-to-Date Results
Adjusted EBITDA for the six months ended June 30, 2011, was $709 million as compared to $663 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily the result of a $128 million increase in Commodity Margin due in large part to our North segment, where Commodity Margin increased by $183 million primarily driven by the acquisition of our Mid-Atlantic plants, higher spark spreads on open positions at our legacy power plants due to higher market heat rates, and higher average hedge prices during the first half of 2011. Partially offsetting the increase in the North region, our Texas segment experienced a $40 million decline in Commodity Margin. Despite an increase in average hedge prices, our Texas segment was negatively impacted by unplanned outages during an extreme cold weather event in early February 2011, as well as lower average availability in the first quarter influenced by more scheduled outages.
Partially offsetting the year-over-year increase in Commodity Margin, Adjusted EBITDA was negatively impacted by a $41 million decrease in Adjusted EBITDA from discontinued operations associated with the sale of our Colorado plants in December 2010. In addition, although plant operating expense3 increased by $23 million year-over-year, this increase was primarily driven by the addition of our Mid-Atlantic plants in July 2010; consistent with our focus on efficiencies, plant operating expense3 for our legacy fleet decreased $11 million year-over-year. Sales, general and administrative expense4 remained comparable year-over-year, with the exception of a $10 million credit related to the reversal of a bad debt allowance in the first half of 2010 that did not recur in the current period. Also contributing to the offset, as previously discussed, was a $15 million favorable adjustment in other revenue recognized during the first half of 2010 related to a major maintenance contract.
Net loss2 increased to $367 million for the six months ended June 30, 2011, from $162 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted, was $165 million in the first half of 2011 compared to $196 million in the first half of 2010. The improvement was primarily due to the increase in Commodity Margin, as previously discussed, offset by increases in plant operating expense associated with the acquisition of our Mid-Atlantic fleet and higher major maintenance expense associated with our plant outage schedule, as well as a $10 million bad debt allowance reversal recognized in the first half of 2010 that did not recur in the first half of 2011, as previously discussed.
1 Includes generation from unconsolidated power plants and plants owned but not operated by Calpine.
2 Reported as net loss attributable to Calpine on our Consolidated Condensed 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 six months ended June 30, 2011 and 2010.
4 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 six months ended June 30, 2011 and 2010.
West: Commodity Margin in our West segment decreased by $22 million for the three months ended June 30, 2011, compared to the same period in 2010, primarily resulting from a decrease of $10 million in REC revenue relating to the timing of revenue recognized during the second quarter of 2010 associated with the receipt of CPUC approval of new contracts related to our Geysers assets. In addition, Commodity Margin decreased due to lower market heat rates on our off-peak open position resulting from an increase in hydroelectric generation in California which is forecast to be significantly higher in 2011 compared to 2010, and from an unscheduled outage at OMEC during the second quarter of 2011. The decrease was partially offset by higher average hedge prices for the second quarter of 2011 compared to 2010.
Commodity Margin in our West segment was comparable for the six months ended June 30, 2011 compared to the same period in 2010. During the first half of 2011, we experienced higher average hedge prices as well as positive impacts from origination activities. The increase was partially offset by lower market heat rates on our open position resulting from an increase in hydroelectric generation in California, as previously discussed, and lower Commodity Margin resulting from an unscheduled outage at OMEC during the second quarter of 2011.
Texas: Commodity Margin in our Texas segment was comparable for the three months ended June 30, 2011, compared to the same period in 2010. During the second quarter of 2011, we realized higher average hedge prices and higher market heat rates on our open position, which was largely offset by lower Commodity Margin associated with the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010.
Commodity Margin in our Texas segment decreased by $40 million for the six months ended June 30, 2011 compared to the same period in 2010. Despite an increase in average hedge prices, Commodity Margin was negatively impacted by unplanned outages at some of our power plants caused by an extreme cold weather event which occurred on February 2, 2011. Power prices increased dramatically as a result of the cold weather event and the plant outages, which required us to purchase physical replacement power at prices substantially above our hedged prices. Lower average availability in the first quarter of 2011, influenced by higher scheduled outages, as well as the aforementioned sale of an undivided interest in the assets of our Freestone power plant, also contributed to the period over period decrease in Commodity Margin.
North: Commodity Margin in our North segment increased by $100 million for the three months ended June 30, 2011, compared to the same period in 2010, primarily due to the acquisition of our Mid-Atlantic fleet, which closed on July 1, 2010.
Commodity Margin in our North segment increased by $183 million, for the six months ended June 30, 2011, compared to the same period in 2010, primarily due to the Mid-Atlantic acquisition, as previously discussed. The increase in Commodity Margin also resulted from higher realized spark spreads on open positions among our legacy power plants driven by an increase in market heat rates, and higher average hedge prices for the six months ended June 30, 2011 compared to the six months ended June 30, 2010.
Southeast: Commodity Margin in our Southeast segment decreased by $9 million for the three months ended June 30, 2011, compared to the same period in 2010 largely due to the expiration of certain hedge contracts which benefited the second quarter of 2010 as well as lower Commodity Margin that resulted from unscheduled outages that occurred during the second quarter of 2011.
Commodity Margin in our Southeast segment decreased by $13 million for the six months ended June 30, 2011 compared to the same period in 2010. The six-month results were largely impacted by the same factors that drove performance for the second quarter, as previously discussed.
Liquidity remained strong at over $2.0 billion as of June 30, 2011, down modestly from $2.2 billion at December 31, 2010. Cash flows provided by operating activities for the six months ended June 30, 2011, resulted in net inflows of $239 million compared to $170 million for the same period in 2010. The change in cash flows from operating activities was primarily due to income from operations, which increased by $55 million during the period after adjusting for non-cash items. In addition, cash paid for interest decreased by $70 million due to the timing of interest payments on our new bonds and term loans compared to the previously outstanding First Lien Credit Facility and project debt. These improvements were partially offset by an increase in working capital employed of $19 million, after adjusting for debt related balances that did not impact cash provided by operating activities, as well as prepayment premiums of $13 million incurred during the six months ended June 30, 2011. Cash flows from investing activities resulted in a net outflow of $421 million in the six months ended June 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 $2 million, primarily as a result of the net impact of refinancing activities, as further discussed below.
Adjusted Recurring Free Cash Flow was $20 million for the six months ended June 30, 2011, compared to $118 million for the prior year period. Despite a $46 million increase in Adjusted EBITDA, Adjusted Recurring Free Cash Flow declined primarily as a result of a $129 million increase in major maintenance expense and capital expenditures resulting from our plant outage schedule and unscheduled outages. We remain on track with our annual maintenance program, which is reflected in our raised 2011 Adjusted Recurring Free Cash Flow guidance.
During the second quarter of 2011, we continued to improve the quality of our liquidity by securing a $360 million term loan to retire project debt associated with our Metcalf and Deer Park Energy Centers. This refinancing allowed us to migrate project debt to the corporate level, further simplifying our capital structure and alleviating cash restrictions. During the period, we also obtained an approximately $845 million credit facility to finance the construction of the 619 MW combined-cycle Russell City Energy Center, in which we own a 75% interest. The credit facility provides a construction loan that converts to a ten-year term loan when commercial operations begin.
PLANT DEVELOPMENT
York Energy Center: We acquired the York Energy Center, a 565 MW dual fuel, combined-cycle power plant under construction as part of the acquisition of our Mid-Atlantic portfolio. York Energy Center achieved COD on March 2, 2011, three months early. The York Energy Center sells power under a six-year PPA with a third party which commenced on June 1, 2011.
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 have executed contracts for all major equipment and have selected and contracted with the engineering, procurement and construction contractor. We began construction in the second quarter of 2011 and are in the process of obtaining project financing which is expected to be completed in the third quarter of 2011. We expect COD in 2013.
Turbine Upgrades: We continue to move forward with our turbine upgrade program. Through June 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 falling in line 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 expect to receive the Sonoma County permit in the second half of 2011. 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 due to the permitting challenges, we may not meet a 2013 COD. 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 by both 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): Feasibility study under way with PJM for the addition of 300 MW of combined-cycle capacity at our existing site, leveraging existing infrastructure;
• Garrison (Delaware): Actively permitting 309 MW of new combined-cycle capacity at a development site secured by a lease option;
• Talbert (Maryland): Existing interconnect agreement for 200 MW of new simple-cycle capacity at a development site secured by a lease option;
• Powell (Maryland): Existing interconnect agreement for 300 – 500 MW of new simple-cycle capacity at a development site that we are currently in the process of purchasing; and
• Other locations that we feel provide similar opportunity to position us for growth within the region.
OPERATIONS UPDATE
Second Quarter 2011 Power Operations Achievements:
Safety Performance:
First quartile lost-time incident rate of 0.36 year-to-date
Availability Performance:
Achieved record second quarter fleet-wide starting reliability of over 98%
Geothermal Generation: Provided approximately 1.5 million MWh of renewable baseload generation with 92% capacity factor
Natural Gas-fired Generation:
Mankato Energy Center: Achieved 100% starting reliability and 0% forced outage factor during second quarter of 2011
Second Quarter 2011 Commercial Operations Achievements:
Customer-oriented Growth:
Signed ten-year contract with Entergy Texas, Inc. to provide 485 MW of power from Carville Energy Center
Signed additional seasonal originated contract in the Southeast
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 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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov.
Contact:
Calpine Corporation
Investor Relations:
Christine Parker, 713-830-8775
[email protected]