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Calpine Corp. (NYSE: CPN ) Q4 2014 Results Earnings Conference Call February 13, 2015 10:00 AM ET Executives Bryan Kimzey – Vice President, Investor Relations Thad Hill – President and CEO Steve Pruett – Chief Commercial Officer Zamir Rauf – Chief Financial Officer Thad Miller – Chief Legal Officer Andrew Novotny – SVP, Commercial Operations Analysts Neel Mitra – Tudor, Pickering, Holt Abe Azar – Deutsche Bank Julien Dumoulin-Smith – UBS Stephen Byrd – Morgan Stanley Greg Gordon – Evercore ISI Michael Lapides – Goldman Sachs Steven Fleishman – Wolfe Research Ali Agha – SunTrust Angie Storozynski – Macquarie Brian Chin – Merrill Lynch Gregg Orrill – Barclays Operator Good morning. And welcome to the Fourth Quarter Earnings Call. My name is Brandon, and I’ll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Bryan Kimzey, Vice President of Investor Relations. Mr. Kimsey, you many begin. Bryan Kimzey Thank you, Operator, and good morning, everyone. I’d like to welcome you to Calpine’s investor update conference call covering our fourth quarter and full year 2014 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 can access 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 Thad Hill, our President and Chief Executive Officer; Steve Pruett, our Chief Commercial Officer; and Zamir Rauf, our Chief Financial Officer. In addition, Thad Miller, our Chief Legal Officer; and Andrew Novotny, SVP, Commercial Operations are also with us to address any legal, regulatory or detailed commercial questions. Before we begin the presentation, I encourage all listeners to review the Safe Harbor statement included on slide two 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 Thad to lead our presentation. Thad Hill Thank you, Bryan, and good morning to all of you on the call. We thank you for interest in Calpine and for listening today. 2014 wrapped up in a fine fashion for Calpine, we are proud to report adjusted EBITDA of $1.949 billion, adjusted free cash flow of $830 million and adjusted free cash flow per share of $2.03. All three metrics achieved all-time highs for Calpine and finished in the top half of their respective guidance ranges, even after we effectively raised guidance twice during the year. Maybe more importantly for investors, despite vast dislocation in commodity markets over the last three months, we are reaffirming our 2015 guidance outlook of $1.9 billion to $2.1 billion of adjusted EBITDA, $810 million to $1.01 billion of adjusted free cash flow and $2.10 to $2.60 of adjusted free cash flow per share. Since our last call, some of the key items to contribute to our current year financial projectors have moved in opposite directions. We’ve seen lower natural gas prices and hedges that we have in place have been helpful. However, lower Taxes forward spark spreads have not been. Steve Pruett will cover this in more detail. We’ve continued to operate well with record safety statistics and our forced outage factor under our goal of 2%. We also continue to make progress in managing both our balance sheet and our portfolio. Last week we’ve successfully completed a $650 million nine-year unsecured debt offering of 5.5% used in part to payout some higher price debt and in part fund growth. We have secured a commission order in Minnesota to expand our Mankato plant under a 20-year contract. And in December, we executed a purchase and sale agreement with Duke for our Osprey plant in Central Florida. I will return to Mankato and Osprey in a few minutes. Finally, we have continued to return money to our shareholders by completing $277 million of buyback since the last quarterly call in November. As our stock price moved down with the recent commodity price fell off, we took advantage of it and stepped up our share repurchase program. Since beginning the program in 2011, we have repurchased approximately 25% of our outstanding shares for $2.4 billion. As I hope it is evident from this report, we continue to execute operationally, commercially, financially and strategically. Turning the page, I would like to reflect for a minute on what makes Calpine different from our peers. We believe that not only is our business unique among competitors but also that our way of operating our business differentiates us. First, on our business, there are several trends that are having a fundamental impact on the wholesale power sector. They are first, the EPA continuing tightening of our NO standards; second, enduring in low gas price through U.S. share revolution and third, a regulatory shift towards pricing schemes that compensate generators more when they perform in tight circumstances but penalize them when they don’t. All three of these are very positive for our modern flexible and reliable fleet of gas-fired power plants. Whisking on the page are several sweeping new air] rules. We understand the greenhouse gas regulation like the Clean Power Plan or 111(d) as it is called, will continue to be highly debated. That said, there is no scientific debate about nitrogen oxides, sulfur dioxide or mercury. Collectively they cause haze, respiratory issues, acid rain, birth defects and other human health issues. With these known facts, there’s simply no justification in 2015 for operating a 30-year old coal plant without a scrubber and other emissions controls. Since our last earnings call, the EPA has announced new nitrogen oxide standards and in February mandated implementation plan for Texas to control sulfur dioxide. These and the other rules on the page had a small direct impact on our own business and had major impact on our competitors. And we believe over time it will have a fundamental impact in this nation’s generation resource mix. Although much has been spoken about the imminent resource shifting to Eastern third of our nation, these changes will also materially impact Texas as the decade continues, a topic that Steve will address. A part of this emission resource shift will also include more renewables something that we are following closely. Perhaps adding to the stresses of the evolving of our mineral regulations, more intermittent resources needs the concept of base load generation is more challenging and the need for fast ramping in cycle machines will be even greater, something that we think plays into the strength of the plans that we build on and operate. Meanwhile the share revolution continues and natural gas supply continues to grow. Virtually every other major player in merchant generation sector is effectively a synthetics gas long play to lower their gas price, to lower their margins because power prices are generally tied to gas prices while their fuel costs are more static. For our fleet, our revenue in fuel cost is much more in tandem making us much more gas price gas price agnostic. Although ours is a complex business with many factors that impact longer term profitability, gas prices is not the one that we worry about, helping our way to the stable EBITDA profile on the graph. Finally, we are seeing sweeping changes in the way the regulators think about compensating generation resources for liability during scarcity events but only if the generator performance in our markets is stressed. This is a key part of the New England capacity structure where we recently saw higher pricing and the PJM capacity performance proposal pending before FERC. It is also implicit in the new higher Texas Power price gap as well as the price formation issue efforts underway at many of the independent system operators. Simply put, we are first and foremost operators of power plants and we welcome to trade off of higher compensation for good availability performance with the risk more downside if we can’t perform. Shifting to how we think about our business in a way that might be different from our competitors, as I just mentioned first and foremost, we are power plant builders, owners and operators. We run our business on a cash basis, seeking to maximize levered returns while being prudent on the balance sheet. We’re also very active managers of our portfolio. We believe we have demonstrated over time through patience and a clear view of value, real success in building our business in some areas and divestment parts of it in others. Last year, we largely executed southeast for very good value with the sale of six power plants and we put a total of $3.3 billion to work in a very balanced way, $1.1 billion of share repurchases, $1.5 billion on growth with the funding of two acquisitions on four different projects and almost $700 million of managing balance sheet between debt payoffs and launching our first unsecured financing. Overtime, you should expect us to continue to return money to shareholders to develop and buy power plants and yes, to monetize them when there is opportunity for value. With that in mind, on the next page, we discussed two new opportunities that we have advanced since our last call. First, we’ve signed a purchase and sale agreement with Duke to sell them our Osprey plant in Central Florida, with a target close date of January 3, 2017. As we announced last quarter, the plant is currently operating under a PPA that was put in place last October and will run up until the purchase date. I do want to stress the sale is subject to timely state and federal regulatory approvals. However, the PPA is not. Taking together, the PPA and sale contribute about $225 million to Calpine over the next three years that we otherwise would not have received. The plant sale itself accounts for approximately $166 million and the PPA and other adjustments account for the balance. Without the PPA, we project that this plant would generate negative cash flow and EBITDA, given the extremely difficult environment for merchant power plants in Florida, which is dominated by vertically integrated utilities. With this transaction, Duke gets an excellent operating asset and team, and we continue our evolution away from the Southeast. On the right-hand side of the page, we discussed our recently won right to expand our Mankato Plant in Minnesota. Currently, this plan is a one-by-one combined cycle with the capacity of 375 megawatts. However, the plan was originally built to accommodate a 2 x 1 configuration, so the steam turbine was oversized and the site is ready for a new combustion turbine. The Minnesota Public Utility Commission has authorized Xcel to execute an already negotiated contract with us for a 20-year PPA to support a 345 megawatt expansion of the plant. Given the synergies at the site, we have the ability to provide Xcel reliable power at great price, while earning a fair return for our shareholders. These transactions demonstrate the effectiveness of our advocacy for competition. In two states and two different markets where utility self-builds were proposed, we demonstrated the competition can provide the best solution. We’re very pleased with these two developments and will continue working hard to originate one. With that, it’s time to transition to our review of operations and markets. But before we do, I’d like to talk about Steve Pruett for just a minute. In 2011, Steve came out of retirement and joined our team at Calpine. For three and a half years, he has been a critical part of the team, possessing both the keen commercial mind and a passion for developing people. Steve will be reentering retirement this spring and we are sorry to see him go. But we are deeply thankful for his service and his efforts. Many of you have already gotten to know Andrew Novotny, our Senior Vice President of Commercial Operations, the result of his participation in several of our investor discussions. He will continue to manage our trading floor and I have every confidence that he will continue to do it successfully. As Brian mentioned at the start of the call, Andrew is with us today to take questions and our investors and analysts should continue to expect to spend time with him going forward. So to, Steve, thank you for all that you have done for Calpine and congratulations on our retirement. Steve Pruett Thank you, Thad. And let me also thank my colleagues here at Calpine, with whom I’ve had the pleasure of working for the past three and a half years. I take great pride in what we have collectively accomplished during that time and I know that there will be much more to come from this team moving forward. Turning now to review of operations, let me echo Thad’s earlier acknowledgment of the outstanding results our plant personnel delivered in 2014, led by John Adams. First and foremost, our safety record represents an all-time low in terms of our reportable incident rate. In fact, we did not encouraged single day of lost work due to injury over the course of the entire year, a true feet and a demonstration of our commitment to employee safety. Also in 2014, we achieved a fleet-wide forced outage factor of less than 2%, meeting our goal against this benchmark for the third consecutive year. Congratulations to the Calpine professionals who contributed to these results, particularly those noted on the 2014 honor roll listed on the bottom right. The graph in the top right shows our generation output year-over-year. Portfolio management activities accounted for the largest changes, including our acquisition of Guadalupe and expansions of Deer Park and Channel in Texas and our divesture of six plants in the East. In the West, our realized spark spreads increased year-over-year aided by higher heat rates during the evening peaks, which offset lower generation volumes at South Point, Arizona, the expiration of our Delta contract and the impact on our fleet of more hydro generations at the Pacific Northwest. I’ll cover the west in more detail in a moment. Turning the page to our standard and hedge disclosure slide, as Thad mentioned, we have reaffirmed today our 2015 guidance. Since the last earnings call, we have added new positions in 2015, such that we are now 63% hedged for the balance of the year. These hedges have been helpful in maintaining our outlook, given the generally lower spark spreads shown on the right hand side of the slide. We have also been helped by the unique nature of our fleet, where lower natural gas prices convened more run hours and more margin. As far as the lower spark spreads, the West and PJM have held relatively steady, while spark spreads in New England and Texas have declined more significantly. In New England, a case can be made that the 2015 spark spreads as of the third quarter were pricing at a scarcely premium for winter gas and that the recent correction was due. In Texas, however, the story is all about scarcity or the perceived lack thereof, but the fundamentals don’t support the sell-off. I will cover that more in a moment. In 2016 and ’17, we remain very open. Given the deliberate changes in our portfolio over the course of 2014, including the sale of contracted assets in the southeast and the redevelopment of capital into merchant plants in Texas and the East, this position is consistent with our strategic realignment to our competitive wholesale power markets. With our fleet of efficient combined cycle power plants, we remain resilient in the current low gas price environment with limited downside in 2016 and 2017 from further gas price declines. The following slide provides a more detailed look at our views on Texas. The graph in the top left illustrates what we call the systems economic reserve margin or the reserve margin beyond which point resources are dispatched at scarcity prices. As can be seen, 2015 and ’16 are tighter than 2014, which was even tighter than 2011 on the weather normalized basis. This analysis suggests to us that the market is balanced on a razor’s edge. Although a mild summer in Texas could result in weak liquidations, a heat wave, a dry low wind day and/or system operating issues could quickly push the market to insufficient resources to RDC at a $9,000 price cap. Low growth, which has been quite strong over the past five years, persists, although perhaps at a more moderate pace given the impact of low oil prices. While drilling has slowed, the petrochemical and LNG build out along the Gulf Coast continues and the Texas economy is much more diversified today than in years past. Despite the delicate market balance over the course of the past year, Texas spark spreads have declined significantly as shown by the chart in the bottom left. While this decline is partially due to lower natural gas prices, mild weather last summer followed by weak winter liquidation so far this year have led to lack of fear in the market. In just the last month alone, sparks for the upcoming summer have declined more than $10 per megawatt hour reflecting low expectations of scarcity pricing in the forwards, which under appreciates the relative tightness in the market demonstrated above. Certainly we continue to believe that the forward prices are insufficient to economically incentivize new build without a contract or a significant cost advantage. Meanwhile the merchant story is only other side of the fundamentals equation, the supply side, given the increasing pressure on the state’s coal plants, primarily from three key trends. First, steadily increasing the environmental regulations are forcing coal generators to wrestle with costly investment decisions to begin with CSAPR and MATS going to affect this year. On their own, these regulations are not expected to force significant compliance decisions. Yet, of the 10 gigawatts that have received compliance exchanges for MATS, 6 gigawatts were also be subject to regional Haze regulation in just a few years. And that rule is one that could require more substantial financial commitments, including the insulation of scrubbers. Layer on the ozone next and clean power plant rules isn’t difficult to see that, even though compliance deadlines are staggered over the back half this decade and into the next. Coal generators are being forced to decide today whether and how to invest in their plants to keep them operating over the next several years. If the environmental regulations don’t pose enough of a dilemma, inflexible baseload generation, including coal, is being further challenged by the growth of wind generation in the state. Already the nation’s largest Texas’ installed wind capacity is approximately 12.5 gigawatts with more on the way over the next two years. Since wind tends to blow more overnight than during the day, it disproportionately impacts all peak pricing and challenges resources that cannot cycle daily like our modern combined cycle plans can. And finally, since the price of power in Texas is highly correlated to the price of natural gas, sustained low natural gas prices present another hurdle for base load coal generators to experience lower revenues with our offsetting declines in their fuel cost. As it is, some coal plants in Texas are likely not covering fixed cost today based on current around the clock prices. For those who need it, investing in this scrubber to comply with environmental regulations, seems an economically unattractive prospect. In sum, while the Eastern third of the United States has already begun a supply driven transformation, resulting in significant coal retirement, Texas has not yet. As Texas supply, stack evolves in response to these factors, our modern efficient fleet is poised to benefit. On the following slide, let me wrap up with a brief overview of our East and California markets. In the East, regulatory focus remains centered on ensuring grid reliability. As Thad previously described, the emphasis on pay-for-performance is now well-established in both PJM and ISO-New England. PJM has submitted its capacity performance proposal to FERC in advance of the upcoming May auction, deposit from our perspective. Overall, with the capacity performance product and some more modestly favorable technical factors at work, we are optimistic about the auction, recognizing that the key remaining questions center around the demand response participation and risk premium bidding. In ISO New England, the 2018-2019 capacity market results were released last week and we’re quite robust. With our recent purchase of Fore River located in Southeastern Massachusetts or SEMA, we are encouraged by the strong fundamentals in this market and view the auction results as per the reinforcement four our investment decision. The SEMA zone separated and price that the administrator price of $11 a kilowatt month, nearly 60% higher than last year’s auction results. Meanwhile, the rest of the pool priced more than 30% higher year-over-year at $955 a kilowatt month, which benefits our Westbrook plant as well. In the energy markets, low natural gas prices are continuing to benefit efficient combined cycle resources in the East, despite a precipitous decline in natural gas prices. PJM spark spreads for the summer have remained resilient as efficient and low-cost natural gas resources continue to display coal-fired generation, our fleet benefits. As shown in the graph, capacity factors for our Hay Road, combined cycle power plant in PJM demonstrate this upside. We expect this trend will continue as announced coal retirement in this region take effect over the course of this year. Moving to California, we continue to see the growing need for flexible resources given the increase in solar generation. As predicted by the now famous duck chart, the peak that occurs each evening just as solar generation declines and power demand increases has resulted in a steep net load ramp. As shown in the chart on the right, we are observing similar ramping of market hit rates, which appears to be going steeper as more solar comes online. This occurred in the fourth quarter of 2014, despite much milder weather year-over-year a positive signal. The evening ramp has helped to preserve overall market hit rate, despite the solar influx and presents opportunity for the flexible generation like ours to demonstrate its value. With that, I thank you again for your time this morning. And we’ll now turn the call over to Zamir for his review of financial performance. Zamir Rauf Thank you, Steve. And let me also congratulate you on your time and good luck on your golf game. As Thad discussed in his opening remarks, 2014 results demonstrated our continued financial strength, delivering record adjusted EBITDA, adjusted free cash and adjusted free cash flow per share. These results were largely driven by a stellar operating performance during the polar vortex at the beginning of the year, effective hedging along with the creative and disciplined capital allocation. On the back of this performance, we are entering 2015 well-positioned and are reaffirming our guidance ranges for the year. Beyond delivering strong financial performance, we remain focused on our very active capital allocation program. Since our last earnings call, we closed on the acquisition of Fore River, issued 650 million of senior unsecured notes and completed an additional 277 million of share repurchases. For cumulative perspective, the chart in the lower right displays total share repurchases, since we began the program in 2011. A remarkable $2.4 billion or approximately 25% of the company has been returned to shareholders since then. Moving to the following slide, let’s review our 2014 financial performance from the regional perspective. Overall, three major drivers affected the year-over-year performance. First, 2014 was an active year on the portfolio management front. We benefited from a full year of operations at Russell City and Los Esteros in the West and partial year contributions from Guadalupe, Deer Park and Channel in Texas. These favorable variances were partially offset by the sale of the Southeast Six Pack in July. Next we benefited from stronger market conditions driven by extreme weather in Texas and the East during the first quarter of the year, and our ability to capture the value of our duel-fueled plant in the East. Also contributing to the positive variance was stronger market conditions in the West resulting from warmer weather and continued lower hydroelectric generation in California, despite increased hydro in the Pacific Northwest. Lastly, contract expirations at Delta in the West and Osprey in the East, partially offset the positives, although, you recall that the Osprey contract was replaced in the fourth quarter as Thad previously discussed. Overall, our financial performance in 2014 reflects the collective results of our strong operations, effective hedging and origination, and disciplined capital allocation, a true team effort. The last slide serves as a reminder of a key Calpine investment thesis, strong cash flow generation and active capital allocation. As we recently announced last month we see some opportunity in favorable capital markets to enhance our capital structure with the issuance of $650 million of 5.5% senior unsecured notes maturing in 2024. Proceeds were used to repurchase approximately $150 million of our more expensive 7.875% First Lien Notes maturing in 2023, as well as to partially fund the acquisition of Fore River that closed during the fourth quarter and our ongoing Garrison and York 2 growth projects. When looking at the full year run rate, adjusted EBITDA for these investments, we essentially added leverage to these projects at less than 3 times net debt to adjusted EBITDA. That said, given the current low interest rate environment, we are very comfortable carrying approximately 5 times net leverage, which is currently an efficient capital structure for our portfolio optimizing our cost of capital and free cash flow per share. Our target leverage though still remains 4.5 times, which we expect to achieve overtime through a combination of growth in the business and the built-in debt amortizations and cash flow suites that are inherent in some of our debt vehicles. Along with opportunistic and ongoing migration to a long maturity unsecured capital structure, we have managed to reduce our weighted average interest rate from 7.3% in 2012 to approximately 5.4% to-date, significantly reducing annual cash interest expense and further derisking the business. On the right hand of the slide, we update our 2015 excess cash bridge to reflect this financing. It once again demonstrates our track record for accretively deploying capital in a balanced and diversified manner, while continuing to generate strong adjusted free cash flow. Even after the record amount of capital allocated in 2014, we are projecting approximately $1.2 billion to $1.4 billion of excess cash by the end of this year prior to assuming any additional investment decisions in 2015. Given our capital deployment history, you can expect more of the same from us going forward. Strong cash flow generation, opportunistic but discipline portfolio management and returning capital to shareholders, all designed to drive total shareholder return. With that, I would like to thank you once again for your time this morning. Operator, please open the lines for Q&A. Question-and-Answer Session Operator Thank you, sir. [Operator Instructions] From Tudor, Pickering, Holt we have Neel Mitra online. Please go ahead. Neel Mitra Hi. Good morning. Thad Hill Good morning, Neel. Neel Mitra I wanted to focus on Texas. First, could you talk about the regulatory environment given that we have some news that there is legislation to stop a capacity market from ever happening and how you view that relationship at this point? And then, you guys mentioned the regional hays and possibility of how much coal could impact. Where do you see the timing of that, if that were to happen given that it’s already happened in Oklahoma? Thad Hill Maybe I will start and then I will let Thad Miller comment. We feel very good about the overall regulatory environment in Texas. There is clearly a belief that the market needs to work here. The high price caps in place and we think that the market will be allowed to continue to evolve without a lot of legislative or other type of interference. As you know we prefer to only capacity market to an energy only market, but we’re an energy only market now. And we think actions taken by the teams for the legislature are very clear, including unlikely that there will be storage mandates or anything else that we’ve seen in other markets. So I will let Thad maybe comment more directly. Thad Miller Yeah, Neel, I agreed with that. And I would say, look, it’s early days in the legislative session and you always see lots of bills proposed by particular interest. We think that the key leaders in Texas understand that the PUC was responsible last year and the year before when the discussions about whether they should consider a capacity market were being discussed, and thought that the PUC handle that in a proper manner. So we don’t think that this leadership is going to push these initiatives at this point of time. Neel Mitra And the regional Haze? Thad Miller On the regional Haze, I think, the TCEQ is going to have to work through that issue, but we don’t think that the legislature itself is going to actually pass some of these proposed initiatives. Thad Hill Neel, as far as the [indiscernible] as you mentioned we saw it play out in Oklahoma and it did lead ultimately to coal plant retirement decisions versus the alternative retrofits. And we think that will play out the same way here. Neel Mitra Okay. Perfect. And now that you basically almost exited the southeast, when you think about deploying capital in the other regions, where do you see the most attractive opportunities, is it PJM or New England? And with New England, do you think we’ve seen the top of the capacity market? Just wanted to know your thoughts of kind of how you rate the markets right now? Thad Hill Sure. We like — you mentioned PJM and New England, and those are two fantastic markets and we think for period of years that the compensation of generators there we will endure. So we are very, very happy and pleased about the investments that we had made so far. We very much like our Fore River investment and we are pleased with our York and Garrison investments that are ongoing in PJM. The question is, do we like the markets? The question is at what price? And we would love to grow in the two markets you mentioned. The question is at what price does that growth come and can we get comfortable with it? But we certainly like those markets and I would say continue to have a generally bullish view on this point. Neel Mitra Got it. Thank you very much. Thad Hill Thank you. Operator From Deutsche Bank, we have Abe Azar online. Please go ahead. Thad Hill Hi, Abe. Abe Azar Have you seen significant coal to gas switching in your regions in Q4 or year-to-date 2015? And are lower oil prices putting an effective cap on peak pricing in the new regions? Thad Hill I’m going to let Andrew Novotny answer that question. Andrew Novotny Great. Thanks, Thad. So far we’ve seen some coal to gas switching, probably not what we need for the country for 2015. Our estimates are in order for the storage to be at levels that are not overfilling, we would need to see between 13 and 5 Bcf a day of coal to gas switching in 2015. And we are just not quite there yet. So I think either the gas market will have to come down or coal plants will start behaving differently than they have this winter in order to facilitate that. On the question of oil, I think the region where we’ve seen the biggest impact from oil price it would be New England and that’s been twofold, one from the ability for all generation to run and two, in terms it’s tied to global LNG prices. So far, I don’t think that it’s fairly to say that we’ve seen an impact really elsewhere outside of the country in terms of oil pricing. And I don’t actually expect that to be significant in other regions. Thad Hill And I would like to highlight Andrew’s first comment, which is we expect that there will be more coal to gas switching over the course of the year, but we will have to wait and see if that does occur. But we’re hopeful. Abe Azar Thank you. Can I follow-up with one other question? Thad Hill Sure. Abe Azar In your 10-K you mentioned beginning a program to update the dual-fueled turbines at plants in the East segment? Can you elaborate on that a bit? Thad Hill Yes. I think, that is probably geared towards Fore River, our new plant in Boston. When we bought that plant, there was a decommission fuel oil system on the plant. One of the two units at the plant the combustion turbines, has been upgraded and in fact, I think today, in fact, is operating well. The other turbine will be upgraded in the Spring. The plants got very good gas connectivity. But given the performance rules, as well as wanted to make sure that we can perform when the weather shows up. We have chosen to go ahead and put the other turbine under oil. But the first one came when we bought the plant from Exxon ready to go. Abe Azar Thank you. Operator From UBS we have Julien Dumoulin-Smith on the line. Please go ahead. Julien Dumoulin-Smith Hi. Good morning. Thad Hill Good morning, Julien. Julien Dumoulin-Smith So I wanted to ask perhaps little bit off the wall, but what are you thinking about your strategic direction towards sort of a more gas-oriented strategy and then, specifically, I am curious, what are your latest thoughts on renewals, as part of the business mix here, if you could comment? Thad Hill Sure. Well, I mean, Julien, I wanted to be first incredibly clear. We like our business very much. We think our fleet and the way we have run our business given the way these markets should play out over the next three to five years, we are in a perfect position. Not one of our major markets will be — I would say, less fragile in a few years than it is today and that is a very good thing for us with coal plants retiring and gas staying low. So we are couldn’t be more thrilled with our business and we are sticking by it. I will tell you that without saying there is no strategy shift, overtime renewals will be a part of the investment, a big part of the investment that occurs and while today its driven by tax credits going forward, it cloud be driven by other things like a price carbon. So we certainly going to understand it and if appropriate invest there. But I also think that while and there have been some new stories on us looking at this, I guess, one address directly, I want to be very clear that our focus and strategy remains the same. We think we are playing this market exactly the right way the way we are today. Julien Dumoulin-Smith Fair enough. And I didn’t mean to discourage your existing strategy, not either. But turning to California, actually I would be curious, you talked a little bit coal to gas switching earlier? What are seeing in terms of dispatched volume this year, given the extent of the drought there? I mean, I know, you don’t want to talk to frequently about volumes year-over-year or actual nominal, here with all the dispatch. But could you give us any kind of sense there, I mean, how is that trending and what is the thought on the drought in California, just more broadly for your portfolio in ’15? Thad Hill Maybe I will start and then I’ll hand over Steve to add on. The drought in California has had bit of an impact, but generally, it’s only in the second quarter. By the time you get to this time a year, our production has been driven by the fundamentals, not by the water flow. Less water flows in the super peak in the third quarter and then, of course, to run a river stuff in the second have an impact. But in fourth quarter has far less of an impact and I think as Andrew and Steve said, things are playing pretty well. So I would argue that the drought has a bigger impact on summer on-peak pricing than it doesn’t, oh, sorry, has less impact on summer impact pricing than it does in the second quarter as well. I don’t know, Steve or Andrew if you want to say? Steve Pruett Yeah. I think, really, the message in California is that, it’s been relatively stable. The drought has had made a minor impact. I think that another major impact has just been the effect of the ramping hours and evening peak and the need for our capacity to be there in order to meet it. So stable is kind of the word for California. Julien Dumoulin-Smith Are we going to just be clear on the coal to gas switching and combined with California? It doesn’t seem to meaningful yet, just to makes sure, I understood the response in the last couple of questions there and maybe that? Steve Pruett Just to clarify, I think, I don’t understand what you are saying. But there is not really a major impact of coal to gas switching in California, that’s more from the East and our Mid-Atlantic fleet and at some point our Texas fleet and the overall country on Eastern interconnect. California has been driven more by the previous dynamic we mentioned. Thad Hill I think to response on the overall kind of financial performance and what I would say Julien on this is the drought certainly hasn’t hurt anything but California from energy market, whose story has been the evening peaks have continued to go higher as we saw in the chart. We also saw that in the first and the second quarter as well. So that’s a very helpful thing. And Coal to gas which I think you — which you said was appropriate. So far, we haven’t seen a lot of it, certainly not anywhere else. And I think Andrew’s point is the current prices have to come down to incent it or something else has to happen for the gas market to clear. So we’ll see how things play out. Julien Dumoulin-Smith Great. Thank you. Operator From Morgan Stanley, we have Stephen Byrd on the line. Please go ahead. Stephen Byrd Good morning. Thad Hill Good morning Stephen. Stephen Byrd Wanted to follow up on Mankato and congratulations on being able to move forward there. Can you give us a sense of the multiple of EBITDA, which you’re investing as we can get a better sense for how additive Mankato is to the business? Thad Hill Yeah. I don’t think we’re prepared to do that today. I’ve told you that our investment in Mankato we feel very good about the returns from that assets, both unlevered and levered to us. But given — for now, we’re just going to leave it at that. Stephen Byrd Okay. Totally understand. And one of the follow-up on Neil’s question’s on regional haze and just trying to think through the timeline over which we might see asset retirements. I appreciate thee are not your assets that are retiring. So it’s a little bit of guess work. But I guess what I’m struggling with is trying to understand the timeframe off of which that regulation really has teeth in it which the co-plant owners, in particular, will have to make kind of a fish or cut bait decision. Are there ways to think about the timeline that can get us a better sense of when we might start to see those decisions? Thad Hill Yeah. The issue with that is that next step, Texas will have to respond to the federal program. The federal implementation plan which were suggested by the EPA and then there will be response back and then probably would be litigation. So I think that we think probably best case is later in this decade that can certainly drift however, I think again Oklahoma shows a pretty good example. That was wrapped up and finished probably two years ago. And it’s obvious that the EPA wants to move pretty directly on this. So — but again these are other people’s assets. So I think asking that question is probably better thing to do. Stephen Byrd Understood. Thank you very much. Thad Hill Yeah. Thank you Stephen. Operator From Evercore ISI, we have Greg Gordon on line. Please go ahead. Greg Gordon Hi. Good morning. Thad Hill Hey Greg. Greg Gordon So I have a question with regard to the PJM, you pointed out that spot prices are down just very modestly over the course of the last several months even though power prices have fallen quite substantially. Is that — because the call is really moved up the dispatch order in many hours and if we were to see a big — if we were to see a recast of the lows of the natural gas prices, we saw let’s say back in 2012. How would you expect the spark spread — the market price in the spark spread to react, given that we’ve obviously got a tighter market now and could you comment also on what you think might happen in your current market under similar circumstances? Thad Hill Okay. I’ll let Andrew take that. Andrew Novotny Sure. I think at this point, looking at 2015, it’s fair to say that lower gas prices are going to be a benefit for Calpine. So in mid-Atlantic, as we see prices continue lower from here, it’s likely that the coal floor will just continue to expand spark spreads and not only will we make more money from a margin standpoint but we will have higher dispatch hour as well. In the [indiscernible] market, the gas market is not quite at that level that we need to see that yet, so move down to say $0.50 to $0.75 from a Henry Hub perspective. We’d start to see that sort of impact in Texas as well. Greg Gordon Great. Thank you. Thad Hill Thanks Greg. Operator From Goldman Sachs, we have Michael Lapides on the line. Please go ahead. Michael Lapides Hey guys. Couple of kind of basic questions or little bit unrelated. So I’ll throw them out and go from there. First of all California, can you remind us over the next few years, kind of what percent of your total net revenue whether energy or capacity in California is contracted versus how you think about what’s open out there. I mean, I asked this given the huge influx of solar coming both residential and centralized as well as kind of assuming that at some point, hydro normalizes? Thad Hill Michael, we’ll pick that first and I don’t think we’ve got the date in front of us. I’m going to go from memory. This is a disclosure last year in our second quarter call. We have initial 2014 numbers. The Geysers represented 43%. And I think Steve Pruett said in our call, we felt pretty good about the Geysers being able to maintain its contribution. There were 48% of the margin that was there, was contributed by where we had RA or contracts. And I think Steve said at the time that 7 percentage points of that 48 were about the current market but then we felt pretty good about things. And then a 9% of the margin in California actually came from the energy market, which was I think much worse than a lot of people thought. And then I think today as Steve and Andrew, have pointed out, the evening performance of spark spreads have been very, very good. So the sum total being that’s a pretty stable business. Michael Lapides Got it. Okay. Also trying to think about the Geysers a little bit, we saw a geothermal company announce a pretty interesting transaction over the last week or so, where they sold down a stake in some of the U.S. geothermal assets at something north of about $400,000 a KW. Just curios a, how are you thinking about whether monetization opportunities exists for the Geysers or whether the Geysers are a key component of the Calpine fleet and it would hurt value by separating the Geysers from the rest of Calpine? Thad Hill Michael, we view our California business as an integrated business. I think it’s very important to be — to operate as a scale business there with a range of product mixes and it served us very well in that state. We are in some kind of — the way they made sense to get more value of the Geysers while continuing to operate, then we will consider that at some point, maybe. But as we know, we’ve shied away from financial engineering in order to keep our business simpler and straight forward to understand and to run. So for now, it’s steady as she goes. Michael Lapides Yeah. Less thinking about financial engineering in that regard, more thinking about outright, are you the owner of the asset or does somebody else see more value in the asset than you could realize? Thad Hill Yeah. Sorry, to be clear. Today, we think that running our California business is an integrated business, has provided straight opportunities to contract and compete in that market in a very effective way and we don’t see that changing in the near term. Michael Lapides Got it. Thank you, guys. Much appreciate it. Operator From Wolfe Research, we have Steven Fleishman on line. Please go ahead. Steven Fleishman Yeah. Hi. Good morning. Just wanted to clarify in the reaffirming guidance, should we kind of, be okay to assume that you are reaffirming it based on the forwards that you show as of the end of January there? Thad Hill Yeah. Whenever we give guidance, Steve, it’s been our practice that the guidance is good for the period that which we are due to call. Obviously, a lot of things can happen on a go-forward basis, hopefully good things but our guidance is good as of today. We feel very good about it. Steven Fleishman Great. And then the year-end cash that Zamir showed was available as of the end of ’15. Wanted to make sure that’s really — all that really is available for investment that you don’t need to hold that any of that back? Zamir Rauf 100% of it. This is Zamir. 100% of that is available. Steven Fleishman Okay. Great. Thank you. Zamir Rauf Sure. Operator From SunTrust, we have Ali Agha on line. Please go ahead. Ali Agha Thank you. Good morning. First question, just for planning or modeling purposes, looking at where the gas prices are right now, should we assume that the plant output in ’15 should be fairly similar to what we saw in 2012, is that a fair assumption? Thad Hill Andrew? Andrew Novotny Yeah. This is Andrew. I think there’s, obviously been a lot of portfolio changes since 2012. But in general, the gas price is going to be favorable for our generations and certainly, I think it’s fair to assume that it will be more favorable than what we’ve seen in 2014. Ali Agha And then secondly, when you talked about the moves that we’ve seen in forward sparks spreads and you highlighted ERCOT and NEPOOL specifically, pulling down. But if you looked at all the regions that are relevant to you, what would you say is the difference between your fundamental view of the market as far as spark spreads are concerned, and what the forward market is currently showing us? Just to give us a sense of how much dislocation that is in the market right now. Thad Hill I will let Andrew take a crack at that. I would say that that certainly in my opinion the biggest dislocation would be in ERCOT. Andrew? Andrew Novotny Right. I would agree with that. The biggest dislocation is in ERCOT and an ERCOT, as Steve said, it’s all about scarcity. So the market is sitting on a razor’s edge, as Steve said. It just takes a few hard events and a few scarcity hours in order to have a forward curve end up being core enterprise. Right now we believe that the current forward curve for 2015 represents barely over 1 hour of scarcity at the cap. Ali Agha And Andrew just to understand, are we talking $5, $10, I mean just to give us some sense of where you think this market is off? Andrew Novotny Well, I don’t know if I can answer that. But just to throw out a rule of thumb, every hour at the cap at $12.75 in the summer ERCOT price. Ali Agha I see. Okay. Thank you. Operator From Macquarie, we have Angie Storozynski online. Please go ahead. Angie Storozynski Thank you. I wanted to ask about PJM capacity probably through the capacity performance product. So it seems like PJM is basically following New England’s playbook. We’ve seen already the AB auctions and prices that cleared in New England. So why do you think that nobody gives you or any power producer in PJM any credits for those likely higher capacity payments? And also, how do you think new build in PJM like the one that you’re proposing will actually impact those future capacity payments? Thad Hill Hey, Angie, I will start and then I will let Andrew maybe go on capacity payment. You asked kind of a bigger question and then a more market question. The only way I would — and this would be kind of a point of view in your question about why generators are not credit for the PJM capacity market is that, at the same time you’ve got incredibly bullish in our view and appropriately bullish on changes in capacity markets, because again there is a performance that they are going to be paying for that puts a lot of extra risk on the generators if they can’t perform. At the same, that’s getting more bullish. We also had gas prices collapse and that drags on a lot of generators. And I would say, I think we are pretty unique in a way which is gas being down, even over the long term it doesn’t really negatively impact us, although it impacts some of our competitors. So I am assuming that you’ve got payments going in different directions and so you are not getting the upside that certainly people might hope for. So that will obviously shake out over time. As far as the auction on a go forward basis, I would just say simply that we don’t think the marginal unit is likely to be new units under the CP program, but rather older units that have a higher risk of not performing. I don’t know Andrew if you would like to add to that. Andrew Novotny Yeah, I can add some details just to this upcoming auction in PJM. There is a variety of offsetting technical parameter changes that are probably net neutral to positive, including lower load, lower net CONE but offset by an improved demand curve shape and the elimination of short-term procurement target. But furthermore, there is changes to the transfer limits, which have a chance to be beneficial to zones that Calpine’s capacity is located, including the EMAAC, DPL South, and [Comet] [ph] zone. But potentially more significant than that of course, as all know, are changes to demand response. And whether the Supreme Court chooses to hear the pending case, there will be less demand response participation in the base auction and very limited participation in the capacity performance auction. Find out the capacity performance construct is that that we’re supportive of PJM’s transition to pay-for-performance construct. We believe our assets are well positioned to service products. And while we don’t know how much higher capacity performance prices will be than previous base auctions, there is clearly a risk premium there that all companies will have to consider before exposing themselves to significant penalties. Angie Storozynski But just one follow-up. So why do you think that new build is not going be a marginal plans, when those older coal plants don’t face the issues with supply certainly, etcetera, right because we are talking about coal plants. So wouldn’t the gas plant, the new gas plant be more vulnerable to firm gas contracts or build fuel capabilities… Thad Hill Well, I think… Angie Storozynski … capacity performance element here? Thad Hill No, no. I understood. I think that there are old gas plants that have only gas and have fuel supply issues. And I think some of the older coal plants show real issues last winter. I mean, if we back up to what occurred during the polar vortex, there were a lot of solid fuel plants that didn’t perform. And the companies are going to have to get very comfortable around signing up for the CP in a way that they put a lot of extra risk. By the way, I would also say interestingly enough, at least so far with PJM, it’s looking like they’re not allowing people to opt out of CP that are actually requiring a vast amount of assets to bid into the CP, where the price they bid would effectively opt them out if they didn’t clear into the regular capacity product, Angie. So, we think that will. Again, I think the marginal product — the marginal bid will absolutely be from older units that probably are bidding high to avoid necessarily being in CP. Angie Storozynski Awesome. Thank you. Operator From Merrill Lynch, we have Brian Chin on line. Please go ahead. Brian Chin Hi. Good morning. Thad Hill Good morning. Brian Chin Since the last time we’ve done an investor call, we’ve seen the emergence of a lower cost of capital vehicle for transmission lines development in Texas. Can you comment a little bit more on what does that mean in terms of Texas scarcity or not within regions of Texas and I understand you have some of the Texas information in the slide there? But just a little bit more color there on how you think that changes things if anything? Thad Hill I don’t think it changes anything in Texas. I will tell you this Brian. In Texas and we’ve said this all along that any basis differentials ultimately will be relatively fleeting. Transmission gets build here. It gets sited and funded. And so the lower cost of capital vehicle — look, the current cost of capital, the transmission companies are willing to put all the money to work, continues to actually put to work. So, I actually don’t think that it’s going to overall change dynamic here. Could make competition among the regulated entities interesting, but I don’t think it’s going to change the impact of the wholesale market. Brian Chin Got you. And then one question on your hedging. Your hedging as a percent of your energy margin is now at a fairly low level. Is there a natural level of hedging that you want to maintain, acts as a breakpoint as in terms of how low you can you can go? Zamir Rauf Are you talking about 2015, Brian? Brian Chin Yeah. Remainder of ‘15, ‘16 and ’17. Thad Hill Yeah. You want to talk about 2015 relative to our experiences. Andrew Novotny Sure. Right now, 2015 is up 15% from our last call but it is probably 10% down from the previous call. And right now the — previous year, excuse me, 10% down from the front year of the previous year. So it’s somewhere in between where it was last quarter and relative to benchmarks with previous year. There are few regions that of course, we sold the Southeast Six Pack, which was a fairly contracted bid of assets. And we’ve also acquired new additional merchant plants. That being said, look, there is some regions where we like to be hedged. There are some regions where we like to be somewhat unhegded. There are some areas where liquidity comes into play and I think that we are going to continue to target increasing hedges as we go through time and continue to pick the spots that make the most sense for our assets. Thad Hill Yeah. So, I mean, it’s generally view based but Brian, I think what Andrew said to highlight, compared to last year, we’ve got a lot of contracted assets and we bought more merchant assets. So part of this evolution of our portfolio, selling contracted assets for good value and being more merchant exposed. Brian Chin Understood. Thank you very much. Thad Hill Thank you. Operator And from Barclays, we have Gregg Orrill on the line. Please go ahead. Gregg Orrill Yes. Thank you. Maybe this has already being answered, but just kind of coming back to the issue of the markets forward. In a couple of your regions are really reflecting your view of the fundamentals and the environment rules. What are you seeing from potential to sign-up longer-term customer contracts or any market flavor around sort of one of new-builds on the gas side? And I would think of someone was interested in that, you would be a natural person to come to? Thad Hill Hey, Gregg, I’m having a hard time hearing you. I did get the point about longer-term contracts and you kind of faded from there. So let me address that quickly. And I know I understand there is another caller here at the top of the hour. So, I’ll try and answer and move us along quickly. So, I think we’ve already answered the question about kind of fundamental risk forwards. We’re continuing to see a pretty good contract on deal flow so to speak. Particularly, we’ve been active for some public power entities. We’ll have some more to say about that this year around the contracting efforts we’ve had. Prices have come down and I think people in some places are viewing as, maybe it makes more sense to contracting this environment to build new, which I think is a generally positive thing and if we can help that happen we will. And we are also currently talking to some industrials about agents. So all of that continues and again, I think, we already answered the question about forward relative to fundamentals. Gregg Orrill Yeah. I think that covers it. Thank you. Thad Hill Okay. Thank you. Operator Thank you. We will now turn it back to Mr. Bryan Kimzey for closing remarks. Bryan Kimzey Thank you and thanks to everyone for participating in our call today. For those of you who joined late, an archived recording of the call will be made available for a limited time on our website. If you have any further questions, please don’t hesitate to call us in Investor Relations. And thanks again for your interest in Calpine Corporation. Operator Ladies and gentlemen, this concludes today’s conference. Thank you for joining. You may now disconnect.