Description
Filed with the SEC from Aug 30 to Sep 05:
Calpine (CPN)
Luminus Management decreased its holdings to 54,547,851 shares (11.7%) after it sold 20 million on Sept. 6 for $17.80 each. Luminus said the shares were sold "in order to better align the size" of its investment in Calpine with its portfolio of investments; it also said it wouldn't sell additional shares for 45 days from Sept. 6.
BUSINESS OVERVIEW
Business
We aspire to be recognized as the premier independent wholesale power producer in the U.S. We seek to achieve this objective by delivering long-term shareholder value, operational excellence, effectively executing our hedging strategy, focusing on our customer origination program and completing on schedule and on budget, our growth capital projects. We are the largest independent wholesale power company in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. Since our inception in 1984, we have been a leader in environmental stewardship. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. Our portfolio is primarily comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily efficient combined-cycle plants, and renewable geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation portfolio in the U.S. and produced approximately 20% of all renewable energy in the state of California during 2010. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, including utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and power marketers. We purchase natural gas and fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
Our portfolio, including partnership interests, includes 93 power plants, including 2 under construction, located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 28,155 MW and 584 MW under construction. Our generation capacity includes 77 natural gas-fired power plants, 15 geothermal plants and 1 photovoltaic solar plant. We are one of the largest consumers of natural gas in North America and in 2011 we consumed 715 Bcf (billion cubic feet) or approximately 9% of the total estimated natural gas consumed for power generation in the U.S. We believe that having scale and geographic diversity is important in our business. Scale provides us the opportunity to have meaningful regulatory input, an ability to leverage our procurement negotiations for better price, terms and conditions on our goods and services and allows us to develop and offer a wide array of products and services to our customers. Geographic diversity helps us manage price fluctuations across our different markets.
The environmental profile of our power plants reflects our commitment to environmental leadership and stewardship. We have invested the necessary capital to develop a power generation portfolio that has substantially lower air pollutant emissions compared to our competitors’ power plants using other fossil fuels, such as coal. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, our combined-cycle power plants use cooling towers with a closed water cooling system, or air cooled condensers and do not employ “once-through” water cooling, which uses large quantities of water from adjacent waterways negatively impacting aquatic life. Since our plants are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste. We believe that we will be less adversely impacted by cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air pollutant emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or older, less efficient technologies.
We remain focused on creating long-term shareholder value through making effective capital allocation decisions, increasing our earnings and generating cash flow sufficient to maintain adequate levels of liquidity in order to service our debt, meet our collateral needs and fund our operations and growth. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage and optimize our various physical assets and contractual obligations, we will continue to execute commodity hedging agreements within the guidelines of our Risk Management Policy.
We sell a substantial portion of our power and other products under PPAs with a duration greater than one year. The contracted sale of power, steam and capacity from our cogeneration power plants, combustion turbine power plants and geothermal power plants, as well as the sale of renewable energy credits, or RECs, from our geothermal and solar power plants, provide a stable source of revenue. Our portfolio also affords us the flexibility to sell power and other products forward for shorter terms or on a merchant basis into the spot markets, where we are able to realize attractive pricing particularly during peak demand periods. Additionally, we sell capacity or similar products to retail power providers, utilities, municipalities and others required to acquire capacity and similar products by regulatory or market rules, and we sell ancillary services to independent system operators and utilities to support power transmission system reliability.
Our principal offices are located in Houston, Texas with regional offices in Dublin, California and Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena, Texas and government affairs offices in Washington D.C., Sacramento, California and Austin, Texas. We operate our business through a variety of divisions, subsidiaries and affiliates.
Reserve Margins
Reserve margin, a measure of how much excess generation capacity is present in a market, is a key indicator of the competitive conditions in the markets in which we operate. For example, a reserve margin of 15% indicates that supply is 115% of expected peak power demand under normal weather conditions. Holding other factors constant, lower reserve margins typically lead to higher power prices because the less efficient capacity in the region is needed more often to satisfy power demand. Markets with tight demand and supply conditions often display price spikes and improved bilateral contracting opportunities. Typically, the market price impact of reserve margins, as well as other supply/demand factors, is reflected in the Market Heat Rate calculated as the local market power price divided by the local natural gas price.
The Price and Supply of Natural Gas
Our fuel requirements are predominantly met with natural gas. We have approximately 725 MW of capacity from our Geysers Assets and our expectation is that the steam reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future as our steam flow decline rates have become very small over the past several years. We also have approximately 371 MW of capacity from power plants where we purchase fuel oil to meet these generation requirements if required, but do not expect fuel oil requirements to be material to our portfolio of power plant assets. Additionally, we have 4 MW of capacity from solar power generation technology with no fuel requirement.
We procure natural gas from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages (especially in extreme weather conditions), transportation availability and supplier financial stability issues can and do occur.
Lower gas prices over the past three years have had a significant impact on power markets. Beginning in 2009, there was a significant decrease in NYMEX Henry Hub natural gas prices from a range of $6/MMBtu — $13/MMBtu during 2008 to an average natural gas price of $4.16, $4.38, and $4.03 during 2009, 2010 and 2011, respectively. Natural gas prices in some parts of the country for parts of 2009, 2010 and 2011 were low enough that modern combined-cycle natural gas-fired generation became less expensive on a marginal basis than coal-fired generation. The result was that natural gas displaced coal as a less expensive generation resource resulting in what the industry describes as coal-to-gas switching.
Although some of this lower pricing dynamic can be attributed to the economic recession, the availability of non-conventional natural gas supplies, in particular shale natural gas, has also kept natural gas prices low. Access to significant deposits of shale natural gas has altered the natural gas supply landscape in the U.S. and could have a longer-term and profound impact on both the outright price of natural gas and the historical regional natural gas price relationships (basis differentials). The U.S. Department of Energy estimates that shale natural gas production has the potential of 3 trillion to 4 trillion cubic feet per year and may be sustainable for decades with enough natural gas to supply the U.S. for the next 90 years. Accordingly, there is an emerging view that lower priced natural gas will be available for the medium to long-term future.
The relative price of natural gas can have varying results on our Commodity Margin and liquidity. The impact of changes in natural gas prices differs according to the time horizon and regional market conditions and depends on our hedge levels and other factors discussed below.
Much of our generating capacity is located in California (included in our West segment), Texas and the Mid-Atlantic (included in our North segment) where natural gas-fired units set power prices during most hours or most “peak” hours. “Peak” hours are generally considered between the hours of 7:00 a.m. and 11:00 p.m., with the remaining hours considered “off-peak.” In California and Texas, natural gas-fired units set prices during most hours, although incremental renewable generation and coal-to-gas switching have moderated this dynamic somewhat in off-peak hours over the last year. In the Mid-Atlantic, natural gas-fired units set prices during most peak hours. Outside of our California, Texas and Mid-Atlantic markets, coal-fired power plants tend to set power prices more often.
When natural gas is the price-setting fuel, which is often the case in Texas, California and the Mid-Atlantic, increases in natural gas prices may increase our unhedged Commodity Margin because our combined-cycle power plants in those markets are more fuel-efficient than conventional natural gas-fired technologies and peaker power plants. Conversely, decreases in natural gas prices tend to decrease our unhedged Commodity Margin. In these instances, our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis.
Natural gas-fired combined-cycle units in many markets are now frequently cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant).
Where we operate under long-term contracts, changes in natural gas prices can have a neutral impact on us in the short-term. This tends to be the case where we have entered into tolling agreements under which the customer provides the natural gas and we convert it to power for a fee, or where we enter into indexed-based agreements with a contractual Heat Rate at or near our actual Heat Rate for a monthly payment.
Changes in natural gas prices may also affect our liquidity. During periods of high or volatile natural gas prices, we could be required to post additional cash collateral or letters of credit.
Over the long-term, we expect lower natural gas prices to increase coal-to-gas switching, thus enhancing the competitiveness of our modern natural gas fleet and making investments in coal less attractive. Despite these short-term dynamics, over the long run, we expect lower natural gas prices to enhance the competitiveness of our modern, natural gas-fired fleet by making investment in other technologies such as coal, nuclear, or renewables less economic.
Weather Patterns and Natural Events
Weather could have a significant short-term impact on supply and demand for power and natural gas. Historically, demand for and the price of power is higher in the summer and winter seasons when temperatures are more extreme, and therefore, our unhedged revenues and Commodity Margin could be negatively impacted by relatively cool summers or mild winters. Additionally, a disproportionate amount of our total revenue is usually realized during the summer months of our third fiscal quarter. We expect this trend to continue in the future as U.S. demand for power generally peaks during this time.
Operating Heat Rate and Availability
Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and earn incremental margin in markets where less efficient natural gas units frequently set the power price. In such cases, our unhedged Commodity Margin is positively correlated with how much more efficient our fleet is than our competitors’ fleets and with higher natural gas prices. Efficient operation of our fleet creates the opportunity to capture Commodity Margin. However, unplanned outages during periods when Commodity Margin is positive can result in a loss of that opportunity. We measure our fleet performance based on our operating Heat Rate and availability factors. The higher our availability factor, the better positioned we are to capture Commodity Margin. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin.
Competition
Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other independent power producers, power marketers and trading companies, including those owned by financial institutions, retail load aggregators, municipalities, retail power providers, cooperatives and regulated utilities to supply power and power-related products to our customers in major markets in the U.S. and Canada. In addition, in some markets, we compete against some of our customers.
In less regulated markets, such as California, Texas and the Mid-Atlantic, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2011, 24% of the power generated in the U.S. was fueled by natural gas and that approximately 62% of power generated in the U.S. was produced by coal and nuclear facilities, which generated approximately 43% and 19%, respectively. The EIA estimates that the remaining 14% of power generated in the U.S. was fueled by hydroelectric, fuel oil and other energy sources. We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change. The federal government is expected to continue to take further action on many air pollutant emissions such as NO X , SO 2 , Hg and acid gases as well as on once-through cooling and coal ash disposal. Although we cannot predict the ultimate effect any future environmental legislation or regulations will have on our business, as a clean energy provider, we believe that we are well positioned for almost any increase in environmental rule stringency. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters.”
As environmental regulations evolve, the proportion of power generated by natural gas and other low emissions resources is expected to increase because older coal-fired power plants will likely have to install costly emission control devices, limit their operations or be retired. Meanwhile, the federal government and many states are considering or have already mandated that certain percentages of power delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy.
Competition from other sources of power, such as nuclear energy and renewables, is expected to increase in the future, but at a lower rate than had been expected in 2008 or 2009. The nuclear incident in March 2011 at the Fukushima Daiichi nuclear power plant introduced substantial uncertainties around new nuclear power plant development in the U.S. In addition, the combination of emerging air emissions regulations, federal and state financial incentives and RPS requirements for renewables and their impact of expected increased investment in cleaner sources of generation will be somewhat counteracted by a lower natural gas price environment, which, should it persist, makes new investment in these types of power generation generally uneconomical. Thus, it is doubtful that generation from new nuclear power plants and renewable sources will be available in the quantities needed to meet future energy demand. Beyond economic issues, there are concerns over the reliability and adequacy of transmission infrastructure to transmit certain renewable generation from its source to where it is needed. Consequently, longer-term, natural gas is likely still needed as baseload and “back-up” generation.
MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES
Our hedging strategy and commercial efforts attempt to maximize our risk adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our commodity price risk with a variety of tools, including PPAs and other long-term contracts for the sale of power and steam. We also pursue other long-term sales opportunities, as well as shorter term market transactions, including bilateral originated sales contracts, and purchase and sale of exchange-traded instruments. We actively monitor risks such as Market Heat Rate and natural gas price exposure, as well as other risks related to the value of our generation such as capacity and geographic locational risk in both power and natural gas, REC and emission credit pricing. The relative quantity of our products hedged or sold under longer term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales or through hedging. It is our strategy to seek stronger bilateral relationships under long-term contracts with load serving entities that can benefit us and our customers.
The majority of our marketing, hedging and optimization activities are related to risk exposures that arise from our ownership and operation of power plants. We are one of the largest consumers of natural gas in the U.S. having consumed approximately 715 Bcf during 2011. Most of the power generated by our power plants is sold to entities such as utilities, municipalities and cooperatives, as well as to retail power providers, commercial and industrial end users, financial institutions, power trading and marketing companies and other third parties. We enter into physical and financial purchase and sale transactions as part of our marketing, hedging and optimization activities. We actively seek to manage and limit the commodity risks of our portfolio, utilizing multiple strategies of buying and selling power, natural gas and Heat Rate contracts to manage our Spark Spread and products that manage geographic price differences (basis differential). We have approximately 371 MW of capacity from power plants that have flexibility as to fuel source where we purchase fuel oil to meet these generation requirements if required; however, we have not currently entered into any hedging or optimization transactions for our fuel oil requirements as we do not expect fuel oil requirements to be material to us, but may elect to do so in the future.
Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often act as economic hedges to our asset portfolio, but do not qualify for or we elect not to designate as hedges under hedge accounting guidelines, such as commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points. While our selling and purchasing of power and natural gas is mostly physical in nature, we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in nature. We use derivative instruments, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances to manage commodity price risk and to maximize the risk-adjusted returns from our power and natural gas assets. We conduct these hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk measurement and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for or we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings within operating revenues in the case of power transactions, and within fuel and purchased energy expense, in the case of natural gas transactions. Our future hedged status, and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior management and Board of Directors.
We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we remain susceptible to significant price movements for 2012 and beyond. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels. We use a combination of PPAs and other hedging instruments to manage our variability in future cash flows. At December 31, 2011, the maximum length of time that our PPAs extended was approximately 23 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 3 and 12 years, respectively.
We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is presented separately from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. On January 14, 2011, we repaid the remaining balance under the First Lien Credit Facility term loans with the proceeds received from the issuance of the 2023 First Lien Notes and the unrealized losses related to these interest rate swaps of approximately $91 million previously recorded in AOCI were reclassified out of AOCI and into income as additional loss on interest rate derivatives during 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to loss on interest rate derivatives during 2011 resulting from the repayment of project debt in June 2011. During 2010, we reclassified approximately $206 million out of AOCI and into income as additional loss on interest rate derivatives related to interest rate swaps formerly hedging our First Lien Credit Facility term loans.
CEO BACKGROUND
Frank Cassidy became a director of the Company on January 31, 2008. From 1969 to his retirement in 2007, Mr. Cassidy was employed at Public Service Enterprise Group, Inc. (“PSEG”), an energy and energy services company. From 1999 to 2007, Mr. Cassidy served as President and Chief Operating Officer of PSEG Power LLC, the wholesale energy subsidiary of PSEG. From 1996 to 1999, Mr. Cassidy was President and Chief Executive Officer of PSEG Energy Technologies, Inc. Prior to 1996, Mr. Cassidy held various positions of increasing responsibility at the Public Service Electric and Gas Company. Mr. Cassidy obtained a Bachelor of Science degree in Electrical Engineering from the New Jersey Institute of Technology and a Master of Business Administration degree from Rutgers University. Mr. Cassidy is the Chairman of the Compensation Committee. Mr. Cassidy's almost 40 years of diversified experience in the power generation and energy industries in various positions of increasing responsibility with PSEG provide him with strong insight, particularly with regard to power operations, power sector strategy, management and corporate governance matters, and make him a qualified member of our Board and effective Chairman of our Compensation Committee.
Jack A. Fusco has served as President and Chief Executive Officer of the Company and as a member of its Board of Directors since August 10, 2008. From July 2004 to February 2006, Mr. Fusco served as the Chairman and Chief Executive Officer of Texas Genco LLC. From 2002 through July 2004, Mr. Fusco was an exclusive energy investment advisor for Texas Pacific Group. From November 1998 until February 2002, he served as President and Chief Executive Officer of Orion Power Holdings, Inc. Prior to his founding of Orion Power Holdings, Inc., Mr. Fusco was a Vice President at Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Prior to joining Goldman Sachs, Mr. Fusco was employed by Pacific Gas & Electric Company or its affiliates in various engineering and management roles for approximately 13 years. Mr. Fusco served as a director on the board of Foster Wheeler Ltd., a global engineering and construction contractor and power equipment supplier, until February 2009 and Graphics Packaging Holdings, a paper and packaging company, until 2008. Mr. Fusco obtained a Bachelor of Science degree in Mechanical Engineering from California State University, Sacramento. Mr. Fusco's current management and leadership roles in the operation of Calpine Corporation coupled with more than 30 years of experience in the power industry, including as former Chief Executive Officer of two independent power companies, provide him with strong insight, particularly with regard to commercial and power operations, power sector strategy, commodities and management matters and make Mr. Fusco a valuable member of our Board.
Robert C. Hinckley became a director of the Company on January 31, 2008. From 1999 to 2001, Mr. Hinckley was an advisor to Xilinx, Inc., a supplier of programmable logic devices, and from 1991 to 1999 he was the Vice President, Strategic Plans and Programs as well as General Counsel and Secretary of Xilinx, Inc. In 1994, he also served as Xilinx's Chief Operating Officer. Prior to joining Xilinx, Mr. Hinckley was the Senior Vice President and Chief Financial Officer of Spectra Physics, Inc. Mr. Hinckley spent 11 years on active duty in the U.S. Navy. Mr. Hinckley obtained a Bachelor of Science degree from the U.S. Naval Academy. Mr. Hinckley is an adjunct Professor of Law at Tulane Law School and is a member of the Law School Dean's Advisory Board. He earned his Juris Doctorate degree from Tulane University Law School. Mr. Hinckley currently serves as the Chairman and Managing Director of MCL Intellectual Property LLC and participates as a member of the board of directors and advisory boards of several privately held companies. Mr. Hinckley is a member of both the Audit Committee and the Nominating and Governance Committee. Mr. Hinckley's legal expertise, including service as corporate general counsel and as a member of other boards of directors provide him with strong insight, particularly with regard to legal and corporate governance matters, and make him a valuable member of our Board and of our Audit Committee and Nominating and Governance Committee.
David C. Merritt became a director of the Company on February 8, 2006. Mr. Merritt is President and owner of BC Partners, Inc. and served as Senior Vice President and Chief Financial Officer of iCRETE LLC from October 2007 to March 12, 2009. From October 2003 until September 2007, he served as Managing Director of Salem Partners LLC, an investment banking firm. Mr. Merritt was an audit and consulting partner of KPMG LLP from 1985 to 1999. Mr. Merritt also serves as a director of Outdoor Channel Holdings, Inc., where he serves as a member of the Audit Committee; Charter Communications, Inc., where he also serves as a member of the Audit Committee; and Buffets Restaurants Holdings, Inc. Mr. Merritt obtained a Bachelor of Science degree in Business and Accounting from California State University, Northridge. Mr. Merritt's knowledge and expertise in accounting developed during his 14 years as a partner in a major accounting firm and his service on other boards of directors, including as chairman of other board audit committees provide him with strong insight, particularly with regard to accounting and financial matters, and make him a valuable member of the Board and effective Chairman of our Audit Committee.
W. Benjamin Moreland became a director of the Company on January 31, 2008. Since 1999, Mr. Moreland has been employed by Crown Castle International Corp., a provider of wireless communications infrastructure in Australia, Puerto Rico and the U.S., in various capacities, including his current position as President and Chief Executive Officer and, prior to that, as Executive Vice President and Chief Financial Officer. Mr. Moreland is also a director at Crown Castle International. Prior to joining Crown Castle International, he held various positions in corporate finance and real estate investment banking with Chase Manhattan Bank from 1984 to 1999. Mr. Moreland obtained a Bachelor of Business Administration degree from the University of Texas and a Master of Business Administration degree from the University of Houston. Mr. Moreland is a member of the Audit Committee. Mr. Moreland's successful leadership and executive experience as a Chief Executive Officer and Chief Financial Officer provide him with strong insight, particularly with regard to finance, equity markets, valuation and management matters, and make him a valuable member of our Board and of our Audit Committee.
Robert A. Mosbacher, Jr. has been a director of the Company since February 11, 2009. Mr. Mosbacher is the Chairman of Mosbacher Energy Company, a privately-held independent oil and gas exploration and production company located in Houston, Texas. Prior to that, Mr. Mosbacher was appointed by President George W. Bush in 2005 as the President and Chief Executive Officer of the Overseas Private Investment Corporation (“OPIC”), an independent U.S. government agency that helps small, medium and large American businesses expand into developing nations and emerging markets around the globe; he served in that position through January 2009. From 1986 until 2005, he served as President and Chief Executive Officer of Mosbacher Energy Company. From 1995 to 2003, Mr. Mosbacher also served as Vice Chairman of Mosbacher Power Group LLC. From August 1999 to October 2005, Mr. Mosbacher served as a Director of the Devon Energy Corporation. He also served on Devon's Compensation Committee from June 2003 to October 2005. In April 2009, Mr. Mosbacher resumed his role as a director of Devon, and in June 2009 he resumed his role as a member of Devon's Compensation Committee and the Nominating and Governance Committee.
Mr. Mosbacher obtained a Bachelor of Arts degree in Political Science from Georgetown University and a Juris Doctorate from Southern Methodist University. Mr. Mosbacher is a member of the Compensation Committee and the Nominating and Governance Committee. Mr. Mosbacher's extensive and varied management experience in the energy sector including natural gas and independent power generation, his experience with the Federal government at OPIC, and his service as a member of other boards and board committees provide him with strong insight, particularly with regard to energy, management and government and community relations matters, and make him a valuable member of our Board and of our Compensation Committee and Nominating and Governance Committee.
William E. Oberndorf was appointed by the Board to become a director of the Company on January 1, 2011. Mr. Oberndorf is a founding partner of SPO Advisory Corp., which is an owner of a number of businesses in a broad range of industries with an asset orientation. Mr. Oberndorf has served on the boards of numerous public and private companies. He currently serves as chairman of the board of Aggregates U.S.A. and Rosewood Hotels & Resorts. Mr. Oberndorf is also a member of the investment committee of Hotel Equity Funds and is a director emeritus of Plum Creek Timber Co. Mr. Oberndorf is a former board member of Taft Broadcasting Company, Voyager Learning Company, where he served as chairman, and Wometco Cable Television Corporation. Mr. Oberndorf received his Bachelor of Arts degree from Williams College and his Master of Business Administration from the Stanford Graduate School of Business. Mr. Oberndorf is a member of the Compensation Committee. Mr. Oberndorf's knowledge and understanding of capital markets as a result of his experiences as a private equity and a venture capital investor as well as his experience serving as a director and member of committees of other boards of directors provide him with strong insight, particularly with regard to capital allocation financing, capital markets and business strategy, and make him a valuable member of our Board and of our Compensation Committee.
Denise M. O'Leary became a director of the Company on January 31, 2008. Since 1996, she has been a private venture capital investor in a variety of early stage companies. From 1983 to 1996, Ms. O'Leary was an associate, then general partner, at Menlo Ventures, a venture capital firm providing long-term capital and management services to development stage companies. From 2002 to 2006, Ms. O'Leary was a member of the Board of Directors of Chiron Corporation, at which time the company was sold to Novartis AG. Ms. O'Leary is also a director of U.S. Airways Group, Inc., where she serves as a member of the Compensation Committee, and Medtronic, Inc., where she also serves as a member of the Compensation Committee. She obtained a Bachelor of Science degree in Industrial Engineering from Stanford University and obtained a Master in Business Administration from Harvard Business School. Ms. O'Leary is the Chairman of the Nominating and Governance Committee and a member of the Compensation Committee. Ms. O'Leary's knowledge and understanding of capital markets as a result of her experiences as a venture capital investor as well as her experience serving as a director and member of committees of other boards of directors provide her with strong insight, particularly with regard to corporate governance, ethics and financial matters, and make her a valuable member of our Board and of our Compensation Committee and Chair of our Nominating and Governance Committee.
J. Stuart Ryan became a director of the Company on January 31, 2008. In July 2011, Mr. Ryan became the Chief Executive Officer of Aggregates USA. He is also the founding owner and President of Rydout, LLC, a private investment firm focused on the energy and power industries since February 2003. He also has been a venture partner with SPO Advisory Corp. since 2003. In 2010, Mr. Ryan joined the Advisory Board of Banyan Energy, Inc., a venture stage company developing optical concentrators for solar modules. From 1986 through 2003, Mr. Ryan held various management positions with The AES Corporation, a global power company, including Executive Vice President from February 2000 and Chief Operating Officer from February 2002. Mr. Ryan earned a Bachelor of Science degree from Lehigh University and a Master of Business Administration degree from Harvard University. Mr. Ryan serves on the Lehigh University Board of Trustees and its Engineering Advisory Counsel. Mr. Ryan was appointed Chairman of the Board effective November 3, 2010. Mr. Ryan is also a member of the Nominating and Governance Committee. Mr. Ryan's extensive industry knowledge and experience spanning more than 20 years in the power and energy industries provide him with strong insight, particularly with regard to power sector, strategy, commodities, management and financial matters, and make him an effective Chairman of our Board and a valuable member of our Nominating and Governance Committee.
MANAGEMENT DISCUSSION FROM LATEST 10K
Our Business
We are the largest independent wholesale power generation company in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. We purchase natural gas and fuel oil as fuel for our power plants, engage in related natural gas transportation and storage transactions, and we purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants. Our goal is to be recognized as the premier independent power company in the U.S. as measured by our employees, customers, regulators, shareholders and communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets and contractual obligations, we will continue to execute commodity agreements within the guidelines of our Risk Management Policy.
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Our reportable segments are West (including geothermal), Texas, North (including Canada) and Southeast.
Our portfolio, including partnership interests, includes 93 power plants, including 2 under construction, located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 28,155 MW and 584 MW under construction. Our generation capacity includes 77 natural gas-fired power plants, 15 geothermal plants and 1 photovoltaic solar plant consisting of approximately 725 MW of baseload capacity from our Geysers Assets and 4,561 MW of baseload capacity from our cogeneration power plants, 16,393 MW of intermediate load capacity from our combined-cycle combustion turbines and 6,476 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability, which includes approximately 4 MW of capacity from solar, photovoltaic power generation technology located in New Jersey. Our segments have an aggregate generation capacity of 6,919 MW with an additional 584 MW under construction in the West, 7,239 MW in Texas, 7,914 MW in the North and 6,083 MW in the Southeast. Our Geysers Assets, included in our West segment, have generation capacity of approximately 725 MW from 15 operating geothermal power plants, and we have begun expansion efforts to increase our generation capacity at our Geysers Assets.
Current Year Operational Developments
We continue to make significant progress to maintain financially disciplined growth, to enhance shareholder value and to set the foundation for continued growth and success with the following achievements during the year ended December 31, 2011:
•Our York Energy Center, a 565 MW dual fuel, combined-cycle power plant achieved COD on March 2, 2011, and began selling power under a six-year PPA with a third party which commenced on June 1, 2011.
•Construction of our Russell City Energy Center, which closed on construction financing in June 2011, and upgrades at our Los Esteros Critical Energy Facility, which closed on construction financing in August 2011, continue to move forward with expected completion dates in 2013.
•We continue to move forward with our turbine upgrade program. Through December 31, 2011, we have completed the upgrade of ten Siemens and five GE turbines and have agreed to upgrade approximately six additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 275 MW. This upgrade program began in the fourth quarter of 2009 and is scheduled through 2014. The upgraded turbines have been operating with Heat Rates consistent with expectations.
•We continue to look to expand our production from our Geysers Assets. Beginning in the fourth quarter of 2009, we conducted an exploratory drilling program, which effectively proved the commercial viability of the steam field in the northern part of our Geysers Assets. We have received Conditional Use Permits from Sonoma County and are pursuing the additional required permitting. We are pursuing commercial arrangements which will need to be in place prior to commencing expansion activities. We continue to believe our northern Geysers Assets have potential for development. In the meantime, we have connected certain test wells to our existing power plants to capture incremental production from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion.
•Throughout 2011, our plant operating personnel achieved the first quartile performance for employee lost time incident rate for fossil fuel electric power generation companies with 1,000 or more employees.
•We produced over 94 billion KWh in 2011.
•Our entire fleet achieved a forced outage factor of 2.5%.
•We achieved 98.4% fleet-wide starting reliability in 2011.
•During 2011, our Turbine Maintenance Group completed 16 major inspections and 15 hot gas path inspections.
•For the past eleven consecutive years, our Geysers Assets have reliably generated approximately 6 million MWh per year and, in 2011, achieved an exceptional availability factor of approximately 98%.
Enhancing Shareholder Value
We continue to make significant progress to maintain financially disciplined growth, to enhance shareholder value through our capital allocation and share repurchases and to set the foundation for continued growth and success. Given our strong cash flow from operations, we are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2011 was marked by the following accomplishments:
•Our total shareholder return for 2011 was 22.4% (measured by the year over year change in our stock price).
•On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. Through the filing of this Report, a total of 8,524,576 shares of our outstanding common stock have been repurchased under this program for approximately $124 million at an average price paid of $ 14.60 per share.
•We issued our 2023 First Lien Notes, terminated our First Lien Credit Facility and extended our corporate debt maturities. Together, these changes eliminated the more restrictive of our debt covenants, resulting in increased operational, strategic and financial flexibility in managing our capital resources including the flexibility to reinvest more earnings for organic growth, issue and/or buyback shares of our common stock and incur additional debt, if needed, for acquisitions or development projects. Additionally, we achieved attractive yields and a maturity schedule stretching from 2017 to 2023 with no more than $2.0 billion of corporate debt maturing in any given year.
•We have further continued to reduce our overall cost of debt and simplify our capital structure by refinancing subsidiary level debt with corporate level term loans eliminating the need for subsidiary level reporting and the potential for cash to be temporarily trapped at the subsidiary level. On March 9, 2011, we closed on the $1.3 billion Term Loan and used the net proceeds received, together with operating cash on hand, to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan.
•On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City Energy Center and on August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility.
•During the fourth quarter of 2011, the U.S. Bankruptcy Court issued an order dismissing the Chapter 11 cases that remained open against the U.S. Debtors; thus, all matters related to our voluntary petitions for relief under Chapter 11 of the Bankruptcy Code filed in 2005 and 2006 are resolved and closed.
For a further discussion of our significant financing transactions completed in 2011, see “— Liquidity and Capital Resources.”
Our Regulatory and Environmental Profile
We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. The EPA is moving forward on climate change regulation, and has already promulgated regulations related to other air pollutant emissions, and some states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Item 1. of this Report. Although we cannot predict the ultimate effect future climate change regulations or legislation could have on our business, we believe that we will be less adversely impacted by potential cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air emissions, as well as water use or emissions, than compared to our competitors who use other fossil fuels or steam condensation technologies.
Since our inception in 1984, we have been a leader in environmental stewardship and have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power plants results in substantially lower emissions of these gases compared to our competitors’ power plants using other fossil fuels, such as coal. Consequently, our power generation portfolio has the lowest GHG footprint per MWh of any major independent power producer in the U.S. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we primarily use cooling towers with a closed water cooling system, or air cooled condensers. Since our plants are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste.
Our Market and Our Key Financial Performance Drivers
The market Spark Spread, sales of RECs, revenues from our PPAs and steam sales and the results from our marketing, hedging and optimization activities are the primary drivers of our Commodity Margin and contribute significantly to our financial results. The market Spark Spread is primarily impacted by fuel prices, weather and reserve margins, which impact both our supply and demand fundamentals. Those factors, plus the relationship between our operating Heat Rate compared to the Market Heat Rate, our power plant operating performance and availability are key to our financial performance.
Fluctuations in natural gas price levels affect our Commodity Margin (depending on our hedge levels and holding other factors constant). When less efficient, higher cost natural gas-fired units set power prices in our regional markets, higher natural gas prices tend to increase our Commodity Margin. In these instances, while our production costs increase when gas prices are higher, our competitors’ costs (and power prices) increase at a greater rate, leading to higher Commodity Margin. Similarly, when natural gas prices decline, our Commodity Margin tends to decline.
Natural gas prices have declined substantially in recent years, and natural gas-fired combined-cycle units are now frequently cheaper to dispatch than coal-fired power plants. This has led to coal-to-gas switching (greater use of natural gas-fired units and lower production from coal-fired units) during many hours. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant).
Efficient operation of our fleet creates the opportunity to capture Commodity Margin in a cost effective manner. However, unplanned outages during periods when Commodity Margin is positive could result in a loss of that opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture Commodity Margin. The less natural gas we must consume for each MWh of power generated, the lower our Heat Rate. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin. Holding all other factors constant, our Commodity Margin increases when we are able to lower our operating Heat Rate compared to the Market Heat Rate and conversely decreases when our operating Heat Rate increases compared to the Market Heat Rate. See also “— The Market for Power — Our Power Markets and Market Fundamentals” in Item 1. of this Report for additional information on how these factors impact our Commodity Margin.
Depreciation and amortization expense decreased for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily resulting from a decrease of $39 million due to rotable parts being fully depreciated for some of our units, a decrease of $17 million related to a revision in the expected settlement dates of the asset retirement obligations of our power plants and a decrease of $5 million due to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. The decrease was partially offset by an increase of $24 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition, an increase of $6 million related to York Energy Center which achieved COD in March 2011 and an increase of $11 million related to depreciation for assets placed into service during 2011.
Sales, general and other administrative expense decreased for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily resulting from $26 million in Conectiv acquisition-related costs incurred during the year ended December 31, 2010. The decrease was partially offset by $10 million due to the reversal of a bad debt allowance in the first quarter of 2010 as a result of Lyondell Chemical Co.'s emergence from Chapter 11 bankruptcy and the bankruptcy court's acceptance of our claim in the first quarter of 2010.
Other operating expenses decreased for the year ended December 31, 2011, compared to the year ended December 31, 2010, resulting from a decrease of $10 million in operating lease expense due to our purchase from a third party of the entity that held the lease of our South Point power plant in December 2010 and a decrease of $3 million in royalty expense due to lower revenues from our Geysers Assets resulting from lower prices in 2011 compared to 2010.
Impairment losses for the year ended December 31, 2010 consisted of an impairment of approximately $95 million related to South Point (see Note 3 of the Notes to Consolidated Financial Statements for further information related to our acquisition of the South Point lease and subsequent impairment of our South Point assets) and approximately $21 million associated with two development projects that originated prior to our Chapter 11 bankruptcy proceedings. During the third quarter of 2010, we learned the projects would not receive PPAs that would support their continued development and made the determination that continued development was unlikely.
Gain on sale of assets, net consists of a $119 million gain recorded in the fourth quarter of 2010 related to the sale of a 25% undivided interest in the assets of our Freestone power plant. See Note 3 of the Notes to Consolidated Financial Statements for further information.
Income from unconsolidated investments in power plants had a favorable variance for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to a $4 million period over period increase in operating income for Greenfield LP related to mechanical issues which impacted plant performance during the third quarter of 2010.
Interest expense decreased for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to a $45 million favorable change in unrealized mark-to-market activity related to the interest rate swaps hedging our variable rate debt that do not qualify for hedge accounting and a decrease of $7 million due to capitalized interest related to project debt for two of our facilities under construction. Also contributing to the favorable period over period change in interest expense was a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, which decreased to 7.6% for the year ended December 31, 2011, from 7.9% for the year ended December 31, 2010.
Loss on interest rate derivatives had a favorable change of $78 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily resulting from a period over period decrease of $115 million in historical unrealized losses previously deferred in AOCI and reclassified into income related to interest rate swaps formerly hedging our First Lien Credit Facility term loans. See Note 8 of the Notes to Consolidated Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility term loans. The favorable change was partially offset by an unfavorable period over period change of approximately $20 million due to realized interest rate swap settlements and changes in fair value subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans. Also contributing to the unfavorable period over period change was an increase of $17 million resulting from interest rate swap breakage costs related to the repayment of project debt in June 2011.
Debt extinguishment costs for the year ended December 31, 2011, primarily consisted of $74 million associated with the repayment of the NDH Project Debt in March 2011, $19 million associated with the retirement of the First Lien Credit Facility term loans in January 2011 in connection with the issuance of the 2023 First Lien Notes and $5 million related to the write-off of unamortized deferred financing costs related to the repayment of project debt in June 2011. See Note 6 of the Notes to Consolidated Financial Statements for further information regarding the issuance of the 2023 First Lien Notes, the repayment of the NDH Project Debt and the repayment of other project debt. Debt extinguishment costs for the year ended December 31, 2010, consisted of $61 million associated with the retirement of term loans under the First Lien Credit Facility in May, July and October 2010 in connection with the issuance of the 2019, 2020 and 2021 First Lien Notes and $30 million associated with the acquisition of the Broad River lease which was accounted for as a refinancing of existing debt under U.S. GAAP. See Note 3 of the Notes to Consolidated Financial Statements for further information regarding our acquisition of the Broad River lease.
During the year ended December 31, 2011, we recorded an income tax benefit of $22 million compared to $68 million for the year ended December 31, 2010. The period over period change primarily resulted from an unfavorable variance in income tax expense of $128 million related to the application of intraperiod tax allocation and an increase in various state and foreign jurisdiction income taxes of $19 million for the year ended December 31, 2011, compared to the year ended December 31, 2010. The unfavorable variance in income tax expense was partially offset by a decrease in federal income tax of $101 million due primarily from a one-time $76 million benefit to reduce our valuation allowance due to the election to consolidate the CCFC group with the Calpine group for 2011 for federal income tax reporting purposes and a decrease of $14 million due to the expiration of a statute of limitation related to an uncertain tax position. See Note 10 of the Notes to Consolidated Financial Statements for further discussion of the election to consolidate the CCFC group and the Calpine group for federal tax reporting purposes.
Income from discontinued operations for the year ended December 31, 2010, primarily consisted of $160 million associated with the gain, net of tax, on the sale of our 100% ownership interests in Blue Spruce and Rocky Mountain in December 2010. Also included in the income from discontinued operations for the year ended December 31, 2010, are the results of operations for Blue Spruce and Rocky Mountain. See Note 3 of the Notes to Consolidated Financial Statements for further discussion of our discontinued operations.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Legislative and Regulatory Update
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as within the RTO and ISO markets in which we participate in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is regulated. We are actively participating in these debates at the federal, regional and state levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2011 Form 10-K.
Mercury and Air Toxics Standards
On December 21, 2011, the EPA issued the National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Ins titutional, and Small Industrial-Commercial-Ins titutional Steam Generating Units, otherwise known as the Mercury and Air Toxics Standards (“MATS”). These rules limit emissions of mercury, acid gases and other metals from coal- and oil-fired power plants. The EPA estimates that there are approximately 1,400 units affected by MATS consisting of approximately 1,100 existing coal-fired units and 300 oil-fired units at about 600 power plants.We are not directly affected by the rule because it does not apply to natural gas-fired units, peaker units or units that use fuel oil as a backup fuel. We believe that the proposed emission standards are sufficiently stringent to force coal units without emissions controls to be retired or to install acid gas, mercury, and particulate matter controls by April 16, 2015, which could benefit our competitive position. On February 16, 2012, three parties filed petitions for review with the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) challenging MATS. These petitions were consolidated under one docket number, along with two other petitions. On March 19, 2012, Calpine filed a motion for leave to intervene in the consolidated case on behalf of the EPA. Prior to the April 16, 2012 petition filing deadline, at least 25 additional lawsuits, including petitions filed by 24 states, have been filed challenging MATS. On July 3, 2012, Calpine along with several others in the industry who are similarly situated filed a Notice of Intervention in the pending litigation.
Cross-State Air Pollution Rule
On July 6, 2011, the EPA finalized rules to control interstate transportation of fine particulate matter (PM-2.5) and ozone. The Cross-State Air Pollution Rule (“CSAPR”) requires substantial emissions reductions of NOx and SO 2 from electric generating units in 27 states primarily in the eastern U.S. The rule sets up three distinct cap-and-trade programs: annual NOx and SO 2 trading programs to control fine particles, and a NOx trading program from May through September (the ozone season) to control ozone. Emissions reductions were scheduled to take effect starting January 1, 2012 for SO 2 and annual NOx reductions and May 1, 2012 for ozone season NOx reductions. Significant additional SO 2 emissions reductions in Group 1 states will be required in 2014. Compared to 2005, the EPA estimates that by 2014 this rule and other federal rules will lower power plant annual emissions in the CSAPR region by 6.4 million tons per year of SO 2 (a 73% reduction) and 1.4 million tons per year of NOx (a 54% reduction). The rule established an unlimited intrastate and limited interstate trading program with allowances allocated to sources based on historic heat input but capped at maximum annual emissions from 2003 to 2010. At current capacity factors, Calpine will be allocated sufficient allowances; thus, CSAPR is not expected to have a material impact on our operations. We expect the overall impact of this rule to be positive to Calpine as the significant emissions reductions require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations.
On October 14, 2011, the EPA proposed revisions to CSAPR to address discrepancies in unit-specific modeling assumptions that affect state emissions budgets in Texas, Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York and Wisconsin. In addition, the EPA proposed delaying implementation of the assurance provisions, which were established to ensure that states’ emissions do not exceed their emissions budgets plus a variability allowance. The proposed two-year delay in the assurance provisions would allow unlimited interstate trading of CSAPR allowances, thereby providing more compliance options for affected sources. In addition, the EPA finalized a supplemental rule that includes five additional states - Iowa, Michigan, Missouri, Oklahoma and Wisconsin - in CSAPR’s seasonal NOx emission trading program.
A number of power generation companies, states and other groups have filed petitions for review in the D.C. Circuit challenging CSAPR including requests for full or partial stays of the Rule. Calpine and other power generation companies have been granted intervenor status on behalf of respondent EPA. On December 30, 2011, the D.C. Circuit stayed CSAPR pending the court’s review of the merits of the challenges to CSAPR but restored CSAPR’s predecessor, CAIR, for the 2012 compliance year. Oral arguments on the merits took place on April 13, 2012 and a decision is expected this year. Calpine continues to participate as a respondent intervenor in the court proceedings.
California: GHG — Cap-and-Trade Regulation
California's AB 32 creates a statewide cap on GHG emissions and requires the state to return to 1990 emissions levels by 2020. To meet these levels CARB has approved the implementation of a number of measures including a cap-and-trade program. In late 2011, CARB adopted final cap-and-trade and mandatory reporting regulations which took effect on January 1, 2012. The first compliance period for covered sources like Calpine is 2013-2015; however, in 2012, CARB is implementing other requirements of the cap-and-trade regulation including registering covered entities and testing the necessary auction infrastructure. CARB will conduct one practice auction in August 2012 to test the auction system and conduct the first real auction in November 2012. Litigation challenging the implementation of CARB's AB 32 Scoping Plan has been resolved. However, on March 28, 2012, two environmental organizations filed a lawsuit challenging the cap-and-trade regulation, seeking to enjoin the use of emissions offsets to meet covered entities' compliance obligations. We cannot predict the ultimate success of this lawsuit. Because the cap-and-trade regulation includes a severability clause, even if the lawsuit is successful, it should not prevent the program from being implemented with respect to capped sectors. We cannot predict whether there will be any additional legal challenges filed against the regulation or what the associated impacts of any such litigation would be.
A number of parties continue to seek further refinements to improve the regulation. Concurrent with the adoption of the regulations, in October 2011, CARB also adopted Resolution 11-32 outlining the issues it will continue to address including, but not limited to, issues raised by Calpine on the market's auction purchase and holding limit provisions of the cap-and-trade regulation and issues involving long-term contracts executed prior to AB 32. On June 28, 2012, the CARB Board adopted only minor amendments to the cap-and-trade regulation and postponed the adoption of proposed amendments that would facilitate the linkage of California's and Quebec's cap-and-trade programs until it can meet certain requirements set forth by recently enacted legislation. At its June 2012 meeting, the Board directed the staff to continue to work on issues identified in Resolution 11-32. Overall, we support AB 32 and believe we are positioned to comply with these regulations.
New Jersey: NO X
New Jersey has enacted air regulations that further limit NOx emissions from turbines and boilers beginning in 2015. These regulations will require future investment in emissions controls on some of our peaking power plants. We have provided notice to PJM that our 158 MW Deepwater Energy Center, 68 MW Cedar Energy Center and 60 MW Missouri Avenue Energy Center will be physically unable to perform in the delivery year 2015 as a result of these air regulations and that we plan to retire the units before the commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. We received PJM's response in May 2012 in which PJM indicated its agreement with our deactivation request provided certain planned transmission upgrades are completed as scheduled. In the event the transmission upgrades are not completed as planned, PJM may require one or more of the plants to continue to operate for a period of time but we would be entitled to full cost recovery. We plan to install emissions controls equipment at our 73 MW Carll's Corner Energy Center and 67 MW Mickleton Energy Center as these power plants cleared PJM's 2015/2016 base residual auction. Our 77 MW Middle Energy Center did not clear PJM's 2015/2016 base residual auction and we are currently evaluating our options related to this power plant. All six of our power plants impacted by the air regulations will be fully depreciated by June 2015. The retirement of these power plants or installation of emissions controls will not have a material impact on our financial condition, results of operations or cash flows.
Clean Water Act and Water Intake Rule
Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. The EPA proposed rules in March 2011 and subsequent revisions in June 2012 (the “Water Intake Rule”) that would allow states to require power plants employing older once-through cooling systems, particularly along biologically productive estuaries and rivers, to undertake major modifications to their cooling water intake structures or even install cooling towers to reduce impingement (where fish and other aquatic life get trapped against the intake screens) and entrainment (where small aquatic life passes through the intake screens and goes through the condenser at high temperatures). Calpine continues to participate in the rulemaking process, however, while these rules will likely affect our competitors, we do not expect these rules to have a material impact on our operations because we have only two peaking power plants that employ once-through cooling systems.
California RPS
On April 12, 2011, California's governor signed into law legislation establishing a new and higher RPS. The new law requires implementation of a 33% RPS by 2020, with intermediate targets between now and 2020. The previous RPS legislation required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal utilities that are not CPUC-jurisdictional. Under the new law, there are limits on different "buckets" of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on the use of “firmed and shaped” transactions and unbundled RECs – claims to the renewable aspect of the power produced by a renewable resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped” transactions and unbundled RECs becomes more limited over the course of the implementation period. On December 1, 2011, the CPUC issued a decision on intermediate RPS procurement targets between the present and 2020. On December 15, 2011, the CPUC issued a decision clarifying exactly what transactions will fall into which bucket. Important additional details of the implementation of the 33% RPS are the subject of ongoing regulatory proceedings at both the CPUC and the California Energy Commission.
QFs and California State Regulation of Power
A recently implemented CPUC settlement changes significant aspects of policy towards California QFs, including our non-renewable QF facilities. The settlement resolves issues related to QFs under existing QF contracts. Most existing California QFs are under QF contracts. The settlement establishes new energy pricing options for QFs under QF contracts, including the option to shed QF host and efficiency obligations and become dispatchable, and specifies mechanisms for the California IOUs to procure both existing combined heat and power (“CHP”) that is not otherwise under contract and new CHP. Pursuant to the QF Settlement, we have converted one of our former QFs to a dispatchable non-QF unit and are exploring similar opportunities for some of our other California QFs. In addition, we offered some of our resources into the IOUs’ recent CHP solicitations. In certain instances, the IOUs selected our offers and the deals are now awaiting regulatory approval. The impact of the larger CHP settlement has been positive to Calpine.
PJM Capacity Market
Certain states in the PJM market region have taken actions that could impact the PJM capacity market. In New Jersey, legislation enacted in 2011 required the New Jersey Board of Public Utilities (“BPU”) to issue a request for proposals (“RFP”) for new generation. As a result of the RFP, the BPU directed New Jersey's four public utilities to enter into standard offer capacity agreements with the winning generators for new capacity to be built in New Jersey. Several entities have appealed the BPU's order directing the public utilities to enter into long-term contracts with those generators. On February 9, 2011, we joined a group of generators and utilities in filing a complaint in federal district court challenging the constitutionality of the New Jersey legislation. The court proceeding is continuing. The BPU has also initiated a proceeding and held hearings to investigate whether there is a need for New Jersey to pursue additional generation capacity beyond the 2,000 MW already contracted for pursuant to the legislation.
On September 29, 2011, the Maryland Public Service Commission (“MPSC”) issued a “Notice of Approval of Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies” (“the Notice”). The Notice required the state's IOUs to issue RFPs for up to 1,500 MW of capacity. The Notice specifies that proposals must be for new natural gas-fired capacity capable of delivery into the PJM Southwest Mid-Atlantic Area Council (“SWMAAC”) delivery area. On April 12, 2012, the MPSC issued a further order in this proceeding, directing certain Maryland IOUs located in the SWMAAC area to enter into a contract for differences with CPV Maryland, LLC (“CPV”), a generation developer that is currently developing a 661 MW natural gas-fired, combined-cycle generation plant in SWMAAC. The facility is scheduled to have a COD of June 1, 2015. In May 2012, we filed with the Circuit Court of Baltimore County, Maryland a Petition for Review of the MPSC's order, asking the court to review the order and declare it invalid. The proceeding continues.
Meanwhile, in response to a filing by PJM that was intended in part to address the negative implications from these state actions by revising the Minimum Offer Price Rule (“MOPR”) in its tariff, FERC issued an order on April 12, 2011 approving PJM's MOPR tariff changes in time for PJM's 2015/2016 base residual auction in May 2012. FERC's MOPR order is currently on appeal before the Court of Appeals for the Third Circuit. In addition, we expect PJM to review the MOPR as it applies to future auctions.
CONF CALL
Bryan Kimzey - VP, IR
Thank you, operator, and good morning everyone. I'd like to welcome you to Calpine's investor update conference call, covering our second quarter of 2012 results. Today's call is being broadcast live over the phone and via webcast, which can be found on our website at www.calpine.com. You will find the access to the webcast and a copy of the accompanying presentation materials in the Investor Relations Section of our website.
Joining me for this morning's call are Jack Fusco, our President and Chief Executive Officer; Thad Hill, our Chief Operating Officer; and Zamir Rauf, our Chief Financial Officer. Thad Miller, our Chief Legal Officer is also with us to address any questions you may have on legal and regulatory issues.
Before we begin the presentation, I encourage all listeners to review the Safe Harbor Statement included on Slide 2 of the presentation which explains the risks of forward-looking statements, and the use of non-GAAP financial measures. For additional information, please refer to our most recent SEC filings which are on file with the SEC and on Calpine’s website. Additionally, we would like to advise you that statements made during this call are made as of this date and listeners to any replay should understand that the passage of time by itself will diminish the quality of these statements. After our prepared remarks, we'll open the lines for questions. In the interest of time, each caller will be allowed one question and one follow-up only.
I'll now turn the call over to Jack to lead our presentation.
Jack A. Fusco
Thank you, Bryan, and thank you everyone for your continued interest in Calpine. The combined cycle gas turbine recovery continues to take hold during the second quarter of 2012. According to the Energy Information administration, during April of 2012 natural gas fire power generation virtually equaled coal fire generation in America for the first time ever. As a result of our excellent operations the beneficial market conditions and the flexibility and competitiveness of our fleet, we produced a record 27 million megawatt hours during the quarter bringing our 2012 year-to-date generation to approximately 56 million megawatt hours. A 44% increase compared to the same period last year and a remarkable 60% of the total generation we produced in 2011 before we even get to the summer period, historically our best quarter of the year.
Our increased productivity drove a 30% comparable reduction in our per megawatt hour operating cost for the first half of 2012 as we held the line on non-fuel plant operating expenses despite the significant increase in generation. I’d like to take this opportunity to thank our plant, engineering and maintenance personnel for their vital contribution to our success. Their focus on our operational excellence yielded our best year-to-date forced outage factor and starting reliability on record, while also achieving the best year-to-date safety performance. I am very proud of these dedicated men and women and I appreciate the vital role they play for our company, our customers and our investors. Thad Hill, will cover our operational performance in more detail later.
Meanwhile, our commercial, regulatory and legal teams have been hard at work managing the volatility in our commodity markets. Optimizing our asset portfolio and defending the integrity of wholesale competitive power markets. As evidenced by their continued progress in the second quarter.
We successfully executed nearly 900 megawatts of new contracts in California and the South East, which will provide reliable capacity in energy for our customers and predictable financial results for our investors. In addition, we were able to achieve a constructive near term resolution for our Sutter Plant in California, while advancing the longer term issue of compensation for flexible capacity procurement in an increasingly intermittent renewable market. In PJM, Calpine cleared just over 4200 megawatts in the 2015, and ’16 capacity auction, at increased prices despite the attempts of two States to subsidize new capacity, exemptions to the minimum offer price rule and questionable demand response initiatives. Efforts are currently underway that should mitigate the impact of those activities in future auctions.
Finally, ERCOT began to address its eminent resource adequacy issues by raising the system wide offer cap as of August 1, while also initiating proceedings to evaluate structural market changes. In each case furthering their efforts to address forecast to declining reserve margins.
Lastly, I would be remiss for not thanking the professionals here at our Houston headquarters for their dedication and hard work behind the scenes that has not only resulted in Calpine leading the IPP sector with their timely financial filings, but also developed the processes and tools to forecast our business going forward.
The combination of favorable secular trends and outstanding operational performance delivered solid financial results during the second quarter. Calpine produced adjusted EBITDA of $403 million for the quarter and $728 million year-to-date. An adjusted recurring free cash flow of $87 million and $60 million respectively. Adjusted recurring free cash flow in the first half of the year is impacted by relatively higher scheduled major maintenance during the shoulder season, such that our cash flow projections are expected to increase substantially during the balance of the year. In fact, based on our strong first half performance and our outlook for the rest of 2012, today we are increasing the lower end of our guidance range by $25 million, tightening the range to $1.7 billion to $1.8 billion of adjusted EBITDA, and $500 million to $600 million of adjusted recurring free cash flow. Zamir, will speak more about our financial results and updated guidance later on the call.
Calpine continues to capitalize of the secular shift towards greater utilization of natural gas technology for power generation. Natural gas generation is becoming the preferred generation of choice since it is cheaper, more efficient, more flexible and environmentally cleaner than coal. Coal fire generation is in the secular decline, facing pressure from both environmental regulations and low natural gas prices. Approximately 40 Gigawatts of coal plants have already announced retirements, much of which are smaller, older, less efficient units. Though many of these retirements have been attributed to the pending environmental regulation, like the Mercury and Air toxic standard, a closer look at the facts suggest that retirement decisions may have nothing to do with environmental regulations at all, and everything to do with economics brought about by sustainable lower natural gas prices. For example, on average the coal plants that have announced in PJM are approximately 58 years old. Some even dating back to the Truman administration. In the current natural gas price environments, coal plants are financially challenged even before considering the installation of expensive environmental retrofits like scrubbers, SCRs and baghouses. As a result, Calpine forecast that coal plant retirement should increase significantly from today’s announced levels as companies re-evaluate the economics of their compliance decisions, especially since the more costly environmental rules like once-through cooling and coal ash disposal are still in their infancy in Washington.
Meanwhile, the energy only power markets in Texas is tightening due to increase load which is expected to grow at twice the national average. Electricity demand in ERCOT is projected to grow up to 3000 megawatts annually, roughly equivalent to four new CCGT plants per year. However, only a few plants are expected to be built during the next couple of years since forward power prices have not risen to the level needed to compensate new build economics, causing projected reserve margin to fall to the mid-single digits by 2015 and increasing the risk to electric reliability.
As the largest operator of combined cycle gas turbines in America, Calpine stands to benefit as a fundamental of these circular trends increase the demand in margins for our existing fleet. Our mid-Atlantic and South-East fleets have already benefited from coal-to-gas switching, but a substantial headroom for increased utilization from coal retirement and demand growth. In addition, power prices must rise in order to incentivize development of new capacity to address tightening power markets. Regulators in Texas already recognize this and have begun raising price caps in order to allow returns to approach new-build economics.
The supply driven market recovery in the East and the demand driven market recovery in Texas are poised to drive value to our existing combined cycle gas fleet. In other words, we are in a great position.
In addition to the secular fundamentals driving an increasing value of our business. The management team has been focused on maximizing long term value for our shareholders through discipline allocation of our investment capital. So far in 2012, we have announced $1.3 billion of capital allocation activities including two Texas power plant expansions, a new Greenfield mid-Atlantic combined cycle power plant and a divestiture of our Riverside Energy Center later this year.
In addition, we‘ve been working to deploy significant capital by buying back our shares. Last quarter we announced the doubling of our share repurchase program to a total of $600 million. At that time, I also told you that I was not satisfied with the execution of the program to that point. Today, I am pleased to announce that we’ve invested a total of approximately $409 million into our share repurchase program, demonstrating significant progress since our last call. During the second quarter, we repurchased approximately 16 million shares of our common stock, bringing our cumulative repurchases to 24.5 million shares. I am encouraged by this progress and we will continue to evaluate further capital allocation opportunities, prioritizing my shareholder’s interest first and foremost.
With that, I will now hand it over to Thad Hill, for a review of our operations and our market outlook.
Thad Hill - EVP and COO
Thank you, Jack, and good morning to all of you on the call. I am pleased to provide you the second quarter operational update. In summary, I am happy to report that we’ve continued our strong track record of operating our assets so effectively and safely. Commercially, Steve Pruett and our commercial operations team have been agile enough to position us to meet our financial objectives despite a dramatic increase in gas prices in our last call and a much milder summer in Texas we’ve forecast so far.
Our customer effort continuous successfully with new key contracts in the South Eastern California and more in the works and our development in construction efforts are continuing and on track for two California projects, our two Texas projects and our Delaware project.
This slide shows our operational statistics. Safety-wise, we’ve continued to invest considerable resources to create the safest possible work environment for our employees. In the first half of the year we had only one-lost time accident. Exceptional safety performance by any objective measure. But above our goal is zero.
Our fleet has operated with a 2% forced outage factor year-to-date, which is better than our target of 2.5% and far better than last year. We’ve talked about how the greater amount of baseload dispatch that we've experienced this year did oil, gas prices has benefitted our operations. The analogy we use is putting highway miles versus city miles on a car. While that is true, I do not want to take any credit away from John Adams, and the men and women that operate and maintain our plants.
As we’ve matured as an operating organization, changes on how we operate including a step change in our preventive maintenance efforts, more proactive inspections, expanded best practice sharing and a key eye for detail have contributed to this strong performance.
Once again, our megawatt hour production is up year-over-year. This quarter by 37%. In April, the year-over-year production differential was even greater, but as the quarter progress gas prices did rise and summer weather begin to arrive, which means our fleet outside of the west overall begin trending towards more historical seasonal operating parameters. We expect this to hold true for the third quarter as well. In summer, our competitor’s coal units will be running all the time given their inability to turn on and off so that they do not miss peak load.
Looking more closely at our gas fleet in the west, volumes more than doubled in the second quarter, driven largely by more normal hydro conditions in California as well as the nuclear outage.
Finally, we have continued to hold the line on cost. With the higher dispatch comes higher consumable cost. We have more than offset that with our strong operational performance. When the plants run well, not only are they more available to boost revenue, but you don’t spend money to fix them. On a dollar per megawatt basis you can see that our costs has declined by 30% year-to-date, holding costs flat and producing more megawatt hours as they did then.
Turning to our evolving perspectives on the markets on the next slide, in Texas the summer weather has certainly not lived up to expectations. Although, we had some extremely hot days at the end of June and consequently set a new all-time June load record, consistent rain in July and cold weather has prevailed. That said, two points are worth making. One near term and one long term. Near term, our hedging efforts has protected our ability to deliver financial results. In Texas, it has provided protection from downside cases like we have experienced with the weather through July, but leaves us modestly open to upside for which we are still hopeful in August. Longer term, our Texas thesis remains intact. Weather-normalized load growth continues and the regulatory environment continues to improve, with the PUC having largely fixed many of the issues that artificially suppressed prices last year and raising the price caps, while meanwhile kicking off and proceeding to consider other needed and more far reaching market reforms.
We are hopeful that these reforms taken together will provide enough incentive for sufficient resources to make sure there no reliability events. Some of the initial investment most notably our recently launched new-build effort in Central Texas that have cost approaching the $1000 per KW, demonstrates how our existing fleet with no development risk could be valued. In the mid-Atlantic unfortunately, the hottest weather so far this year followed storms that had knocked out much load because of downed power lines in early July. However, we continue to see pricing volatility on high-temperature days and have continued to enjoy that upside.
There’s the much written said around the results of the recent capacity market auction. Given our view that all assets, new and existing should compete fairly we obviously are poised for two State mandate new assets contracting processes that occurred in New Jersey and Maryland. That said, there are several very positive dynamics of the recent auction that are worth exploring. First, demand response in the East actually declined from the last auction. We have expressed concerned around overdependence on a potentially unreliable resource and it does appear it has achieved maximum penetration in the area of PJM, where our assets are primarily located. Further, it is possible this declining trend may continue given the increasing environmental concerns or what we call dirty DR. That is the use of old environmentally uncontrolled diesel gen sets behind the meter.
Secondly, more retirements are likely in PJM. Given the design of the capacity markets, owners of generation are intending to go ahead and bid as a price taker if there is anything but absolute certainty that their asset will retire. So if an asset owner is hopeful for a stay in environmental rule or thinks that the price set may change, they simply bid into the auction. If ultimately they decide to retire the asset, they will have several opportunities to buy back their commitment or otherwise manage their exposure to a modest portion at a clear auction price.
Third, States are through with RFPs at least for now. There is substantial challenges to all three of the projects awarded in Maryland and New Jersey. However, those challenges are ultimately resolved, it is our view that for now at least we are unlikely to see any further efforts. Fourth, PJM appears interested in adjusting MOPR rule to prevent gaming and controversy going forward, which we view as a positive.
The California and South East storage remain regulatory engagement and bi-lateral customer origination respectively. Since the last quarter we’ve had some success with the near term contract for Sutter, mid-term contracts off of Gilroy and Los Medanos, and another contract off of Oneta, which has become one of our most sought after assets. Our regulatory and commercial teams continue to work hard and in particular will be very active in upcoming California proceedings around the future of the market there. And in the South East with our customers on solutions to meet their load needs.
As far as our hedging profile is concerned as you’ll see in the next slide, from an absolute open position on megawatt hours, our position is largely hedged in ’12, but remains open in ’13 and ’14 given our fundamental views, which remain well above the stubbornly depressed forward curves.
Within ’12, much of our remaining exposure is in ERCOT, although I would now characterize that as relatively modest. Meanwhile, given the nature of our fleet in the mid-Atlantic, which is some higher heat rate units in addition to our combined cycles, we tend to produce more megawatt hours, and are implied in this chart when the weather is hot there. So in high temperature days we benefit there as well.
We have re-centered our gas position a bit since last quarter. On the last run down in gas prices, we took positions that had been described as short in 2012 and 2013 and moved them back closer to neutral. We remain long in 2014.
In the next slide, I will return to the topic of how gas prices impact our portfolio.
Finally, it is worth mentioning that we recognize that even with the disclosures on this page and the modeling tips in the appendix, their portfolio is a difficult one to model. We’ve provided updated modeling tips in the appendix that provide some clues on how to think about sparks spreads based on the expected volumes output of our fleet, which we believe will be helpful as you think about generation 2013 and beyond.
On the next slide I want to come back to a topic that has received a fair amount of discussion since gas prices began their precipitous collapse last fall. The economics of our fleet without hedges under different gas price environments. In the first quarter, we disclosed that we benefitted from increased dispatch by our plants due to low gas prices and our gas price displaced coal units in many of our markets despite the mild winter. As demonstrated in the chart on the upper left, this continued through much of the second quarter as well, although it has begun to slow as gas prices have risen and as coal plants began to turn on for the summer.
We have been very pleased with how our fleet and our economics have responded in this lower gas price environment, and we are always going to make more money rather than less money.
We also think it is important to put this incremental margin in context. The investment thesis for Calpine is not the gas prices will be low, but for that matter like many of our competitors, the gas prices will be high. Rather it is that, as markets recover almost the whole new generation will be gas for generation and market prices will rise to incent that investment. As we’ve said, we’d like to put a spade in some of that new required investment but more importantly through rise in market price and we’ll provide our existing fleet with the opportunity to produce much more electricity and more margin than it has today. We demonstrate this important points in the charts in this page and the graph in the lower left, we’ve shown how the average spark spread changes with gas price holding everything else constant in our fleet today. As you can see there is a positive impact from more gas prices. That said the data shows that in the greater scheme we are materially gas price agnostic. Importantly, the incremental margin we do or do not earn at different gas prices is dwarfed by the upside potential from current market signals versus what is required to incent new generation as represented by the orange shading in the graph on the right.
As we’ve described, we think that Texas is in the verge of this type of pricing and believe PJM will be in a similar place around the middle of the decade. This is the investment thesis for Calpine. Some growth from new investment, but large upside to our existing fleet from market recovery.
With that, I’ll turn it over to Zamir.
Zamir Rauf - EVP and CFO
Thank you, Thad, and good morning everyone. I’d like to start today by reviewing some of this quarters key financial achievements. First, as you’ve already heard, we delivered solid results. The chart in the upper right captures some of the main drivers for the first half of 2012 compared to the first half of 2011. The primary ones being improvements in energy markets associated with lower natural gas prices and higher sparks spreads, partially offset by lower regulatory capacity payments and lower contribution from hedges and contracts.
Meanwhile, our continued strong financial performance and positive outlook for the remainder of the year has enabled us to raise the lower end of our 2012 guidance by $25 million. We are now projecting adjusted EBITDA of $1.7 billion to $1.8 billion, an adjusted recurring free cash flow $500 million to $600 million.
Along with delivering exceptional operating results, we have also continued our focus on capital allocation and have made great progress on that front. This year, as Jack mentioned earlier, we have put a significant amount of capital to work. We have invested $238 million in higher return growth projects including ongoing projects financed construction at Russell City and Los Esteros, expansions at Deer Park and Channel, and the construction of Garrison.
At the same time we have bought back $290 million of our stock, bringing the total repurchases to $409 million out of the $600 million program that we announced on our first quarter call. To date, we have repurchased approximately 24.5 million shares and about 5% of total outstanding shares when we launched the program.
With the progress we have made over the past year, we now view buy back as a normal part of our capital allocation process such that we are unlikely to make discreet announcement about increases to the program going forward. You should assume however that we will continue to be opportunistic in deploying our capital. Our capital structure and efficient fleet provides us the flexibility needed to deploy capital efficiently and effectively.
As you can see from the chart on the bottom right, we have no material near term debt maturity that limit our ability to make these decisions. Similarly, we have no significant environmental compliance CapEx and no underfunded pension liability standing in the way of our continued progress.
Before leaving this slide, I’d like to call your attention to the note on the bottom left. Some of you may have noticed that we reported a net loss this quarter of $329 million, compared to $70 million in last year’s second quarter. The largest driver of this year-over-year variance is unrealized or non-cash mark-to-market losses, which primarily resulted from a temporary spike in near term forward prices in Texas during the last week of June in response to extreme heat.
Given our expectation for increase price volatility in Texas over the coming months and years and as we continue to hedge our open positions for future periods, we expect that we will continue to experience similar revenue and earnings volatility. However, please keep in mind that unrealized mark-to-market adjustments have no impact and have always been excluded from adjusted EBITDA and adjusted recurring free cash flow.
With that, let’s turn to the following slide and begin our review of the regional dynamics for this quarter’s results. Overall, second quarter adjusted EBITDA was relatively flat this year compared to last year. Across the country, we benefited from higher utilization of our fleet given the generally low gas prices, particularly in April and May. And given improved spark spreads in several of our markets. Offsetting the benefits of this increased generation, contract expirations and lower contributions from our hedges negatively impacted the west compared to last year’s second quarter. Meanwhile, in the North and similar to the first quarter, lower PJM capacity payments for our mid-Atlantic portfolio impacted this year’s second quarter compared to the prior year period.
Finally, as you’ve already heard we were able to keep planned operating expense essentially flat during the second quarter, while generating significantly more electricity. A true reflection of our focus and excellent operations and prudent cost control.
The following slide shows a similar comparative for the six month period. Adjusted EBITDA increased $19 million to $728 million compared to last year’s first six months. The year-over-year improvement was largely due to an increase in generation volumes across the fleet. Meanwhile, lower capacity revenue in the mid-Atlantic and the expiration of contracts in California and the South East partially offset this year-over-year benefit. Overall, I am very pleased with our performance for the first half of the year.
Turning to the following slide, we continue to focus on liquidity management and capital allocation. As I mentioned in the past, we look to maintain a minimum liquidity balance of $1 billion to conservatively manage the business. With more than twice that available to us at year end 2011, we deployed significant capital over the first half of the year. Most notably in connection with our share buyback program.
During the first half of the year we also retired our legacy interest rate swaps and doing so rid ourselves of the last vestige of the bankruptcy. In addition, we saw a temporary increase in margin associated with the second quarter power price spikes in Texas.
As we look over the rest of the year we project that liquidity will trend back to us at $2 billion level. The majority of our adjusted recurring free cash flow is earned in the back half of the year and as we mentioned, the sale of Riverside is expected to close in the fourth quarter.
In summary, our disciplined approach to capital allocation has allowed us to put a significant amount of capital to work at higher returns for our shareholders. Looking forward, we expect to continue to build liquidity and generate strong adjusted recurring free cash flow and as I have said in the past, we will put our excess capital to work.
The following slide captures how our capital allocation approach supports the Calpine investment thesis, which is about delivering our operating excellence; generating strong financial results supported by favorable industry fundamentals and financially disciplined capital allocation. Over the past year, we have reduced the number of shares outstanding, while continuing to deliver solid financial results, thereby enhancing the value of the remaining shares. Over time, we expect that the rigor we apply to our capital allocation decisions will continue to drive value for the business. Whether to accretive growth, attractively priced divestitures or additional returns of capital to shareholders.
Combining this discipline with favorable industry fundamentals we believe will enhance the per share value of our equity. Our capital allocation decisions have always been driven by returns to equity and free capital per share accretion is the primary metric we have always used. As such, we thought it appropriate to share the same view with you and are today reporting for the first time adjusted recurring free cash flow per share. As you can see on the slide, for the first six months of 2012, we delivered $0.13 of adjusted recurring free cash flow per share compared to $0.04 in the prior year period. More importantly, for the full year, we are expecting a range based on our updated guidance of $1.07 to $1.29 per share compared to a $1.01 per share in 2011.
As we continue to deliver strong free cash flow and opportunistically repurchase our shares, we believe that we will continue to enhance these power share metrics over time and continue to deliver impressive total shareholder returns.
As you’ve heard from us today, we remain focused on operational excellence and disciplined capital allocation. We remain committed to our core business and we remain well positioned for the secular trends that are shaping our industry today.
With that, I’d like to thank you all for your time this morning and for your interest in Calpine. Operator, please open the lines for questions.
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