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Calpine Corporation (NYSE:CPN)

April 10, 2013 2:00 pm ET

Executives

W. Bryan Kimzey - Vice President of Investor Relations

Jack A. Fusco - Chief Executive Officer and Director

John B. Hill - President and Chief Operating Officer

Caleb Stephenson

Steven D. Pruett - Senior Vice President of Commercial Operations

Todd Thornton - Vice President of Commercial Development

John Adams - Senior Vice President of Power Operations

Ron Macklin

Tom Long

Ron Hall

W. Thaddeus Miller - Chief Legal Officer, Executive Vice President and Secretary

Steve Schleimer

Randy Jones

Mark Smith

Yvonne A. McIntyre - Vice President of Federal Legislative Affairs

Zamir Rauf - Chief Financial Officer and Executive Vice President

Analysts

Neil Mehta - Goldman Sachs Group Inc., Research Division

Paul B. Fremont - Jefferies & Company, Inc., Research Division

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Keith Stanley - Deutsche Bank AG, Research Division

Stephen Byrd - Morgan Stanley, Research Division

Angie Storozynski - Macquarie Research

Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Gregg Orrill - Barclays Capital, Research Division

Jonathan Cohen - ISI Group Inc., Research Division

W. Bryan Kimzey

All right. We're going to get started in just about 2 minutes, 2-minute warning.

All right. Let's get started. Welcome to Calpine's Biannual Investor Day here at Minute Maid Park in Houston, Texas. My name is Bryan Kimzey, and I'm the Vice President of Investor Relations at Calpine Corporation.

Today's meeting is being webcast live, which can be found on our webcast at www.calpine.com. You'll find access to the webcast and a copy of the accompanying presentation materials in the Investor Relations section of our website.

We would like to thank everyone who made the trip here to Houston, as well as everyone who is listening. We appreciate all your support and interest in the Calpine investment thesis. In addition, we would like to thank the Houston Astros for allowing us to use their wonderful facilities.

And speaking of facilities I'd like to just draw your attention to the restrooms are behind the side over here, back by the -- there's an elevator and some restrooms back there. And in case of emergency, the exits are on the side, on the -- on your right and your left out to the Crawford Street. Now just a reminder, if you go out those doors, I don't think there's any reentry. So only in case of emergency.

Finally, we would appreciate it if you would turn your phones and BlackBerrys to silent for the duration of this afternoon's presentation.

Before we begin the presentation, I encourage all attendees and 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 meeting 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.

Turning to Slide 3. I'd like to draw your attention to this afternoon's agenda. We have marshaled all our resources here for today's event. You will hear from 15 members of Calpine management, who will be introduced throughout the afternoon. Their bios are in the back of your presentation materials. In addition, we are joined by an additional 15 members of Calpine, who are seated in the audience.

Our agenda is divided into 5 primary sections, each followed by brief Q&A. So we'd appreciate it if you could hold your questions for the appropriate times. We have a break scheduled for approximately 2:45 p.m. Central Time depending upon how we are doing on time. Finally, we plan to conclude today's presentation by 5 p.m. Central Time.

With that, I am proud to turn the presentation over to Jack Fusco, our Chief Executive Officer, who will begin with our value proposition.

Jack A. Fusco

Thank you, Bryan. Maybe we can do a mic check, because up here, I'm getting -- we're getting a lot of feedback. Can you all hear me fine? All right. Excellent.

So first, let me introduce the executive team that's up on stage with me today. So it's Thad Hill, our President, Chief Operating Officer; we've got Thad Miller, our Chief Legal Officer; and then Zamir Rauf, our Chief Financial Officer, for those of you who don't know.

I want to thank all of you for coming today and, I really want to thank you for all of your support and interest in Calpine. So first, before we get too far, I want to thank you, all, and the investment community, for our recent honors and recognition. I have to tell you, I'm truly humbled to represent such a great company and especially such great employees like you all are going to meet today. But since I began my work at Calpine, I've tried really hard to earn your trust and respect. And I have to tell you receiving these awards for me just highlights the fact that I think we're on -- right on track, and we're making good progress with all of you. And today I hope marks our renewed emphasis in our IR efforts to increase our transparency and help you all understand why we are so excited to be at Calpine and where we think the significant value proposition is in our stock.

So on the next slide. So over the last 5 years, we've been internally focused. So we've been streamlining our business processes, enhancing our operations and maintenance management, and we're realigning our organizational structure to prepare ourselves for the future. The future is upon us today. So I believe Calpine is the best-positioned power company to benefit from the transformative secular shift that's underway today in the U.S. power sector, and that is the natural gas fuel power generation is the preferred solution for the electric power industry.

Shale gas is here to stay, and we're blessed in America to have it. And by all accounts, there's at least 100 years, and in one account, we saw a number that exceeded 400 years of supply. As a result, you'll hear from Steve Pruett that our expectations for that natural gas will stay range bound between the $3 to $5 in mmbtu price range. And this is going to make it extremely hard for other forms of power generation to compete like nuclear, coal, solar or wind, especially on the backdrop of a very efficient, reliable and flexible natural gas combined-cycle fleet.

In addition, the U.S. is facing an aging, technically-obsolete and environmentally-challenged power generation industry. The investment requirements are staggering, and by most accounts, will require up to 10 Calpine's worth of new power plants to be built over the next decade or 2. So our long-term growth prospects are very good, and we only need a small percentage of the new build market share to have a big impact on our top line growth.

Having said that, we will not make the mistakes of the past. You have my word. In other words, at Calpine today, we're working with our customers, our legislators and our regulators to ensure that the market reforms are in place, and new investments are incentivized to be built prior to us spending any money. And as you're going to hear from Thad Miller and his team, while none of us are satisfied with the pace of change, we're right on track with where we think we need to be going forward.

So I continue to hear and read about the negative comments that some of my colleagues are saying about the secular shift in natural gas. And as all of you know, I tend to rely on data to make informed decisions and judgments. So let's analyze the data and debunk these myths around the overreliance of nat gas in the power generation sector.

First, as this graph shows, from the Energy Information Association, the utilization of the current natural gas fleet in America equals less than a 30% capacity factor in most years during the last decade. There's an abundant excess available of energy production capability from the existing natural gas fleet.

Second, the U.S. pipeline industry is responding with significant investments in new infrastructure to support natural gas demand. $46 billion has been invested in the U.S. pipeline infrastructure in America over the last decade. There's been over 2 dozen gathering stations built and brought online in the Marcellus Shale alone over the last 2 years. There's dozens more that are actively being permitted and planned for.

Third, even with natural gas generation gaining market share, the U.S. power generation sector is projected to maintain a diversified and balanced fuel source -- production profile for the next 30 years. So abundant, affordable domestic supply of natural gas is here to stay, and the natural gas fired power is the preferred generation of source.

Okay, turning to Slide 8. Calpine is a strong generator of free cash flow and growing. I've asked Zamir to cover our capital management program in greater detail later today. Our guiding principle, we will be good stewards of your investment in Calpine. Our long-term shareholders invest in Calpine today to gain exposure to the wholesale power sector and because they believe we are the best company in this space to succeed in America's shift to natural gas fired generation.

But just for the skeptics on our cash flow, we're not Apple. It's our intent to invest the capital wisely or return it to our shareholders. And today after funding all of our high-return growth projects, the most value-creating investment for excess cash flow is to buy back our stock. We will be discerning and disciplined in our capital allocation decisions. We believe strongly in our growth prospects going forward, and will not muck that up with what looks like near-term accretion for longer-term liabilities. Additionally, we're not interested in fads nor flavor of the month. We're a competitive wholesale power generation company that develops, builds, owns and operates power plants.

On Slide 9, I'm pleased to report that we're beginning to get more clarity on how our power markets are shaping up for 2013. Based on the positive movement upwards on our forward power curves, our ability to hedge, we're raising the lower end of the 2013 guidance from $1.76 billion to $1.8 billion. Additionally, what you're going to hear from Steve Pruett is based on our hedging profile and our fundamental view of our markets, we believe there is asymmetrical risk to the upside on our EBITDA guidance.

On the lower left part of this slide just to remind you all in our disciplined share repurchase program, approximately 20 months ago, I announced our first $300 million program and I've since increased it twice for a cumulative total of $1 billion, $600 million of which we completed earlier this year. Also, what you'll note on this slide is on the bar chart, we've already invested $58 million of the $400 million program we announced 2 months ago. So we're making steady progress, and we're only just beginning.

Finally, our EBITDA has leveraged the energy commodity margin. Our adjusted free cash flow is levered to EBITDA, and our free cash flow per share is additionally levered to our share repurchase program. The result is a compelling forecasted CAGR of 22% in adjusted free cash flow per share as you'll see on the slide to the right.

On Slide 10, I'd like to take you through some back-of-the-envelope math. So despite our recent stock price performance, I believe there is significant valuation upside that remains in Calpine's stock. So without giving multiple years of guidance today, let me explain this chart. So let's start on the left. That's the midpoint of our 2013 EBITDA guidance. As you progress to the right of the bar chart, you add our growth projects and our new contracts that we've already disclosed, and you minus the reduction in the 2015 capacity payments. And what you -- what we have illustrated is that the 2015 consensus from the sell-side analyst community is very conservative. It implies only a $30 million uplift is required from our power markets from the 2013 number, which is currently below the forward curves in 2015. Additionally, that's before you factor in any of the fundamental supply and demand imbalance upside in our various markets, especially right here in Texas.

So the graph on the right is even a little more telling. It illustrates the theoretical potential stock price upside based on our targeted 15% to 20% adjusted free cash flow per share CAGR. So keep in mind that the adjusted free cash flow per share we believe is a proxy for cash earnings per share.

So holding our current price to adjusted free cash flow per share multiple constant, which today is around 13.7x, would yield a share price somewhere between the mid to the high 20s. Now I find this multiple to be very conservative compared to historic earnings multiples that are given to lower return regulated utilities. And as I've already discussed, we're currently on pace to exceed the high end of that original free cash flow per share CAGR target.

So with that, I'd like to thank you, all, again for your interest in Calpine and your support, and I'd now like to introduce Thad Hill, our President, Chief Operating Officer.

John B. Hill

Thanks, Jack. Jack spoke -- am I on? Can you hear me? No, it's fine, no? I'll step to the podium then. Jack spoke about capital allocation, he talked about macro trends and the business and stock price. What I'm going to talk about for a minute is really our regional strategies, which is where all these things are actually actualized. And as you know, the Calpine portfolio is in all different regions, and each of these regions are very distinct, in the microeconomics, the competition level even the market rules, and I'm going to start with Texas for a minute. Now I'm going to talk through the last couple of years in our forward view.

There are 2 things -- we're very bullish in Texas, as we've been clear about and, hopefully, a lot of you are as well. There are 2 things you have to believe to be bullish about Texas. Number one is you have to believe demand is growing; and number two, you have to believe that there's a political will to allow free markets to work in Texas. We believe both of these are true. I know there's some of you who were actually at the PUC in Austin yesterday and heard a similar message.

Steve Pruett and Caleb are going to talk about demand coming up, and Thad Miller and his team will actually talk about politics. So I'll leave it there, but we believe both of those. Given that, we actually think there's an opportunity in Texas to capitalize on demand-driven recovery, and we've been investing along with that.

Before I do that, let me do make a point though. You can see a little blue dot moving there. In 2010, we sold 25% of our Freestone Plant for $900/kW. Although we are bullish in Texas, I also -- when somebody else values one of our assets, wherever it is, more than we do, we will absolutely do the right thing for shareholders. And I think the Freestone example is a great one.

Back to growth in Texas. In the last year, we've announced beginning construction in our Deer Park and Channel facilities not but 12 miles from here, and we're adding capacity when you adjust for the efficiency on the whole plant at under $500/kW. We bought the Bosque facility 800 megawatts at $540/kW. And so we're very, very comfortable around the economics there.

Now I will say though that at this point, we put hundreds of millions of dollars to work in Texas over the last year, and now is the time for us to get a very clear signal out of Austin that -- what the market rules will be going forward before we do that, but there are opportunities for us here in Texas and we're convinced that the market will play out very well.

Moving along to the Southeast. The fundamentals are good there as well. There's return to demand growth, as well as a fair number of coal retirements that we don't have in Texas. However, unlike Texas, you can't capture that opportunity by waiting for a market price to come to you. You actually have to go out and contract with utilities, because if you don't do that, you won't ever get it. So we've been very busy contracting and doing the best we can with our customers in the Southeast. And we think, over the last years, we've delivered some value. There's 2,800 megawatts of capacity, mid- to long-term that we've done there, most recently with our Decatur announcement. But in the last 1.5 years, we've also contracted Carville as well as Oneta. And we are working on some other opportunities that we hope will get figured out this year in the Southeast, but very much the effort there is to capture the fundamentals. But it can't come to you there, you've got to go get it with customer contracts. So very different then.

We've also sold an asset in the Southeast, as you all in December, which was Broad River, which was a peaker plant under contract. In Texas, we sold an asset to somebody who's a load-serving entity. In the South Carolina it was actually contracted asset to a yield-seeking investor.

The North. When Thad, Jack and I arrived to Calpine, we were really missing what we call another leg on the stool, which was a presence in PJM, which was the most attractive and, in our view, friendliest to generators, most fairly competitive market in the United States. And we're successful in 2010 with our Conectiv acquisition. We also recently, at the end of last year, closed on the sale of a plant, again, to a load-serving entity in MISO, which was Riverside, at a price we found very attractive. We believe PJM will continue to be attractive going forward. It's a little bit of a different story. For Texas, this is led by demand growth and PJM is more of a supply shock, because of the retirements that are out there.

Yes, demand response has made up for a lot of the retired -- announced retirements and kept capacity markets flattish. However, we're very bullish in energy prices in the middle of the decade when those coal plants are retired or other types of plants, given rules in New Jersey, and what will be setting price is increasingly either well units or even demand response. We're very bullish in energy prices in the middle part of the decade there. As a result, we've invested in our Garrison project in Dover, Delaware. This is a new one by one that began construction last month, and we're looking at other portfolio opportunities there, but we'll be very disciplined about it, and I'll return to talk about that.

In the West, like other regions, there's also been an asset sale in the last couple of years, which was in Colorado. We sold 2 plants for $800/kW, one was a peaker, one was a combined-cycle to the utility. We also have taken advantage of the hybrid market in California to have growth opportunities under contract, and that was what Otay Mesa, one COD, and our 2 plants in Northern California, Russell City and Los Esteros, which will start operating in the summer

However, the story in the West is a lot different than the other parts of the country. We all know there are a lot of renewables that are getting -- put in place there, a lot of solar. The profile of earnings in California will change. There will be pressure on energy pricing, at least in the middle part of the day, but capacity values become a lot more valuable. We think the utilities understand that. We think the commission understands that. We've been fairly successful as you can see at contracting a fair number of our plants over the last couple of years in these types of lock-ins, and Steve will provide a lot for disclosure on that later, but we're working very hard in the West on getting assets under contract for capacity in a way that we think will be increasingly valued, and we've been successful with it. And of course, there'll be a lot to say on that from a regulatory standpoint as well.

So today, we're 27,300 megawatts with almost 1,500 under construction. On operations, we recognize, before we can do anything else, we have to operate our fleet well. And we've been working hard to do this, and we've been successful.

On the left is we've kept our cost flat despite adding many megawatts to our fleet and certainly on any kind of normalized basis, we've been very effective at driving our planned operating expense down. On the right, you can see a reduced forced outage factor. We've reduced our forced outage factor by 53% since the new management team came to Calpine. John Adams is going to talk about this and what we've done to get it done, but we recognize that job one is making sure the fleet is operating at the right cost and very available. So we're very pleased with what we've been able to accomplish here.

Commercially, Steve Pruett is going to talk about our commercial optimization. And certainly we do optimize our portfolio, but the most important thing that we do commercially is with customers. It's not trading, it's focused on customers. And the entire executive management team, since we got to Calpine, has been very focused. You see our success in the upper left, you can actually see the contracts we put in place the last 3 years. The upper right is actually new disclosure. The green bars actually show our forward contracted Toll/PPA capacity out through 2017. And again the team has been extremely busy on that.

I want to pause for a minute going to talk about the economics of customers versus just relying on the forward market. If you look at the graph at the lower left, real life example, and there've been several of these, can't tell you which one it is, but the blue line represents the merchant economics of the power plant of ours, both actual and then you can see the forward curve and, ultimately, we just extrapolated the forward curve, that's the blue line. The orange line represents our view of the fundamentals of that particular plant in a particular region. The green line represents the contract that we're actually able to enter into with a customer. A long way above the blue line.

So there are 2 points I want to make on that. First, this doesn't just happen. There's a team that works very closely with customers over a period of years, including executive management, to build the relationships, understand what the customers want and sometimes take a couple of runs at getting this thing done.

The second thing is, it's an obvious question, why would customers pay the green line if the blue line is market? Well, the reality is, is that most of our customers recognize the value of having steel on the ground. Either they've got a regulatory obligation or they're worried about risk or any number of things. And so when you actually have an asset you can typically do much better than whatever the forward curve would show, and that is really at the heart of our origination effort.

So our goals for 2013, I think, are worth mentioning. We think we need to continue to demonstrate to you value from our Southeast portfolio. As I mentioned before, we really need to be creative about commercial solutions to change in California economics and, lastly, Steve and his team are launching a public power effort that he can talk a little more about.

Finally, is our growth portfolio. I've already mentioned that Russell City and Los Esteros will be online this summer in California, both with 10-year contracts. In Texas, Deer Park and Channel will be online by the summer of 2014. So we expect to catch the summer here with both of those new assets. And Garrison is our new project in Dover, Delaware, which should be COD on the second quarter of 2015.

Three new items on the list that are worth mentioning. First, Deepwater, that's New Jersey, just right on the Delaware River. We have an existing plant that we're retiring in 2015. That plant has all the water, the gas and the electric interconnect that you need in order to put a new plant there or to repower the existing facility at a very attractive rate, and we're working hard on that. I will tell you though, it's not a foregone conclusion. There are a couple things we need to see before we proceed with that. It'd be very helpful to understand what happened with the New Jersey and Maryland lawsuits. It would also be very helpful to understand what the MOPR settlement ultimately looks like, but it's a great opportunity, very attractive given the existing plant that we'll be retiring and we're marching down that path.

Secondly, in Texas at our existing facilities, we have 300 megawatts of upgrade capacity, very cheap dollars per kW. And these are turbine upgrades and other modifications at our existing facilities. However, we will not pursue this until we get a little more regulatory certainty in Texas. We're comfortable it's going to play out the right way, but we think we put enough money on the table, and now we need to see a little more clarity from Austin.

Lastly, is Mankato. It's an existing plant in Minnesota that we operate, and there's an opportunity to expand that plant. Now, the plant expansion would happen -- there's an RPL [ph], and we're participating in the RFP process under a contract to the utility in Minnesota. This is a plant, given it's in MISO, where this would only go forward if we actually have a contract. So this would not be merchant. We'd only go forward with the contract given our view of the MISO competitive market.

Bigger point here as I wrap up. Jack talked about cash flow and capital allocation, and Zamir is going to come back to that. We believe there's ample cash flow to both return money to shareholders as well as to invest some money in new growth opportunities. And we think it's important and we've actually been able to, so far, identify and execute on some very high-value opportunities, and we think there are more out there, but they're not easy to get at, but they're there.

To recognize that, Todd Thornton, who's in the room and will be on the panel later, who was our Treasurer, and many of you know him as our Treasurer, was reassigned or graciously accepted a reassignment earlier in the year to lead our development efforts. Todd's years of experience in and around projects and project finance make him a great candidate, and it's a real sign of how committed we are to try to originate some great opportunities that Todd is in on -- is in that. And so as we turn to Q&A, from the operations and commercial perspective, 3 things: One, we recognize that we have an obligation to make sure, first and foremost, our plants operate effectively and that they're there when they need to be called on, and we understand the stable stakes; two, commercially, we'll optimize our assets, it's all about customers; and three and finally, we're going to go out and continue to try and originate some great opportunities, but before we pursue them, we will look at them and be absolutely fiscally disciplined before we commit any of your capital.

With that, I think we want to do Q&A.

Question-and-Answer Session

W. Bryan Kimzey

All right, so what we decided to do is take a short break -- not a break, but have a Q&A break right now, so you all can ask either Thad or I or any of the executives anything that you found compelling on this first series of slides. And if it's quiet, that's fine too, we'll continue to go on. Okay, here we go. So Norma, can you help me with the mics?

Neil Mehta - Goldman Sachs Group Inc., Research Division

Neil Mehta with Goldman Sachs. When we think about the new projects that you start to frame, your Deepwater, Texas and the Mankato, you've been able to build some plants which are currently under construction at a deep discount. How should we think about the capital costs for these plants if they ultimately materialize?

John B. Hill

I'll say this. Am I on? I'm on. I'll say this. The Texas upgrades are existing facilities, and they are cheap. Mankato, I'm not going to get into the economics right now. It is an existing expansion, which is a contract there. So before we build, the question is do we win the contract is more important than the actual costs in a lot of ways. And in New Jersey, we think the existing site gives us some real advantages. And Ron Hall later today will talk about our construction program. But we believe and we think we've demonstrated that we're able to do this faster and cheaper than most of our competitors given the approach that we've taken with the team that we have. So we're confident anything we do will be very competitive.

Paul B. Fremont - Jefferies & Company, Inc., Research Division

Paul Fremont with Jefferies. Looking at your Slide 8, which is the cash position at the beginning of the year starts with $1 billion of excess cash, and I guess my understanding is the excess cash is over and above whatever you think is cash needed to operate the business, and it ends with $1 billion. I had thought that you guys were sort of more targeting to try and use up that excess cash rather than maintain a $1 billion possession. At least that's what we had heard maybe at some of the earlier presentations. So does that represent a change here or...

Jack A. Fusco

Yes, Paul, I'll say if you look at the title of this chart, it says announced capital management. It's a living program. As I highlighted in my presentation, 20 months ago, we started with a $300 million program, and we made -- we've upped the size of it twice. So you all should expect as we continue to successfully implement the 400, if that's the most highest return opportunity that we have at the time, that we would continue to buy back our share. So and having the excess cash, it was a fine balancing line right now with us. We worry about our credit. We worry about our net debt-to-EBITDA coverage ratios. So we never want to get out of balance with where our rating agencies may be or with some of our investors. Is that fair enough?

John B. Hill

No, I think that's fair enough. As Jack said, look, we're not done with the year, right? You saw us with 300. Jack mentioned we raised it to 300. Now we've done 400. The year's not over. We just announced some new growth projects. So as Jack mentioned, we do plan to return capital to shareholders.

Paul B. Fremont - Jefferies & Company, Inc., Research Division

Also, I mean, as a follow-up on the growth project, I mean, it sounds like there are a lot of things that still have to come into place before you'd actually start spending serious capital on all 3 of those projects, right?

Jack A. Fusco

Yes, and those are pretty far out. But it's up to us now and it's up to Todd more specifically to start delivering those next round of growth projects that are going to have high returns that can compete with buying back our own stock, quite frankly. So we wanted to highlight to you that we have some modernization efforts underway. We have some more upgrades underway. We're not sitting back on our haunches. We do have 5 projects right now under construction. I think we're probably one of the only power companies that have 5 projects under construction at this time. So we have -- organizationally, we have the skills to handle that, and we want to make sure these markets start to send us the right signals for us to really invest some of that capital. But until then, we're going to put it to work.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Ali Agha, SunTrust. Jack, going back to -- I think you've said this in the past but I wanted to be clear of your focus when you're looking at capital allocation. I believe you said in the past that your first priority would be to see if there are good projects to add to your portfolio. And if that doesn't happen, then share buybacks and other things come into play. So given the 3 projects that you've listed there, new ones, is it simply a factor of if we think about the EBITDA that is ordered by those projects and the capital costs that the multiple that you would pay to generate that EBITDA would be lower than where your stock's trading at? Is that the way to think about it, given that those 3 are probably going to go forward assuming things, contracts stood in place and so on?

Jack A. Fusco

Yes, Ali. So we -- and in fact, as early as yesterday, we go through our potential list of potential sites that we can either build or modernize or upgrade, and we rank them by accretion, dilution or by EBITDA multiple, however, by cash. And everything -- every capital allocation decision we make is based off the same curves. Ultimately, Zamir controls the curves. The analyst’s report up through Zamir that have the pro formas and all of our decisions, whether they're buy or sell or build, are done by one entity. So we don't want to get out of whack with how we make decisions. And yes, so what we're highlighting for you is today with the price signals that we have, and I don't know if you want to call it the missing money that's in the forward curves or liquidity, or our discussions with our customers, these are the highest return projects that we can do for growth. But for me personally, tie goes to growth versus buying the stock.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

And one follow-up if I could. Thad, I think in the past when you folks talked about your '13 EBITDA guidance, you had said the forward curves at the time were reflective of the lower half of that guidance, but your fundamental view would be the upper half. So if you look at the forward curves today, has anything changed, or how are you looking at that?

John B. Hill

Steve Pruett will actually show the forward curves by region from October versus where they are today. So the curves are not in all that different place. But we've put a couple of months behind us in the year and we've also put positions on different places, and we were much more comfortable, which is why we're able to raise the bottom end. So Steve will show you the exact forward curves. The movement hasn't been as much as you might think. But through our efforts and through actually getting through part of the year, we're comfortable raising the bottom end.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Julien Dumoulin-Smith, UBS. First question, maybe this is preempting something later on, but with regards to Texas, what do you need to see happen to see those retrofits take place? Is it capacity or is there some energy solution that would be palatable?

John B. Hill

No, and I think Thad will handicap much more how it's going to go, or maybe not. I'm looking forward to hearing it, too. But I would say this. Either one can work for us, whether synergy only or whether it's capacity. With an energy only market, we think there could be less medium to longer term stability politically around it, which is why we're much more a fan of capacity markets. But what we need to know, Julien, is simply the rules. So any set of firm rules and we can do our evaluation and do a risk-rated return with Zamir's guys, run the numbers and make a decision, but we don't yet know what the rules are and so...

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

And how high it needs to go in order to be in energy, I mean...

John B. Hill

It's not about the price. I mean, they're all -- we're kind of beyond the price cap, and that's been decided. There are all kinds of rules around whether or not you're going to continue to have the digital outcomes or some sort of slip in curve if you go into the energy market and the like. So we just need to get a clear set of rules and we can make the decision. Again, we're deeply bullish, and I think we're going to get to the right place. We just don't know the rules, and we think we put enough capital to work given the fuzziness that's still existent.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And then just a quick clarification, Jack. When you talked about consensus '15 culpable, what is it that you think the Street's off on, if you will? Do you have a sense at all just where you're particularly bullish?

Jack A. Fusco

I told Bryan I'd be nicer and friendlier today. It's a little bit different on each year reports. But, I mean, the highlight here for us is just from the consensus number, it just doesn't seem to add up for me, for what we've all disclosed to all of you. So I would ask you each to take a look at where you're at and make sure you feel comfortable with your recommendations.

Keith Stanley - Deutsche Bank AG, Research Division

Keith Stanley from Deutsche Bank. Can I just -- a quick clarification on Slide 10, the chart on the left. The contracts hedges net bucket, you said it represents some of the new contracts you've signed recently. Does it also reflect any changes, and as contracts or hedges roll off into market pricing, is that reflected in the slide as well or in that bucket as well?

Jack A. Fusco

Yes, it's a net number.

Keith Stanley - Deutsche Bank AG, Research Division

That's net of all the roll-offs as well that may occur.

Jack A. Fusco

Yes.

W. Bryan Kimzey

Okay, we're about -- we're just about out of time for this Q&A. Thanks and now we'll move on to the next agenda item.

John B. Hill

Sure. And I'll introduce the next team, got to work my way back through here.

First, we're going to hear from our commercial operations team, 2 folks. So come on up, come on up, guys, all 3 of you. And so Caleb Stephenson, who many of you have met before, is our Vice President of Commercial Analytics. And Caleb is going to talk analytically about some national issues, load growth, where we really think the cost of a new combined cycle is, et cetera. Steve Pruett, who's our Senior Vice President, Commercial Operations. Steve is going to talk through our regional microeconomics, which should be a topic of interest. And finally, we're going to have a panel come -- we're going to do Q&A, and Todd Thornton who's joined the panel, Todd won't be presenting today, but Todd will be available for Q&A on our development program. So with that, I'll turn it over to Caleb.

Caleb Stephenson

Thanks, Thad. In this section, Steve and I will talk about the important trends that are affecting the value of the portfolio. I'll focus on national trends, and Steve will walk through each of the regions and talk about regional trends. First of all, and I'll cover 3 topics. First of all, I'll talk about load and what's happening with load growth and whether there's been a fundamental new disconnect between economic growth and load growth. We think the depth of load growth has been greatly exaggerated. The second topic, since the Texas market in particular is in need of new capacity, we'll talk about what price level is necessary to justify new investment. We refer to this as the new build spark spread. We think sometimes people, by using shorthand math, underestimate what this price level is, which means that there could be an underestimation of the potential returns for existing assets. Thirdly, we'll revisit the always important topic of how our portfolio responds to natural gas prices. Now that we've been operating under a variety of gas prices post the shale gas revolution, we think we've displayed that the fleet performs well at a variety of gas prices.

Let's start on Page 19 with the topic of load trends. Here we are, it's 2013, 4 years after a low point of the recession. While we have seen load pick back up, we haven't seen the kind of growth rates that we saw earlier in the last decade. Further, we've seen significant political, regulatory and market emphasis on energy efficiency lately. Lots of states now have efficiency targets and standards, and people are spending their weekends at home replacing incandescent light bulbs with CFLs. And a lot of technologists are very excited about the potential for appliance efficiencies and what that could mean for overall electric demand.

While we certainly recognize the new forms of efficiency that have and are reaching businesses and consumers, we want to try to put all this in context. In fact, efficiency improvements have been made consistently over the past 2 decades, and speaking more broadly, over the past centuries.

The chart on the left side of Page 19 depicts the electric intensity of GDP since 1990. The amount of electricity needed to produce a dollar of GDP in 2011 was 17% below the amount needed in 1990. That means on average, that electric intensity has declined by almost 1% per year. And to say that differently, that means that energy efficiency has improved by almost 1% per year, and the link between GDP and load growth has weakened as that has occurred. This is a substantial amount of efficiency improvement, and more is needed just to maintain the trend. In fact, and the math here is very simple, in the bottom left of the page, just to maintain the historical trend of 2.4% GDP growth and 1.5% load growth, we need another 1% every year. And if we ultimately could flatline load growth, what that would require is 2.5x the historical rate of progress on energy efficiency, we'd need 2.4% of efficiency gains every year.

This would mean that we'd have to create 300 billion of new economic growth every year without using any additional electricity. Is this kind of shift likely over the coming few years? When we look back at GDP and load growth 5 or 10 years from now, we'll be looking at this curve trending down and sharply turning to the south as efficiency rates increase dramatically. Maybe it's possible, but as we show on the right side of the page, there are some factors working against it. First of all, consider the impact on efficiency of underlying structural shifts in the economy. It's well understood, as the chart on the right shows, that industrial electric demand has become a much smaller portion of total electric demands over the past several years. The economy has shifted from energy-intensive manufacturing activities to less energy-intensive services industries, which by itself, has made the economy more efficient.

Looking forward, most people don't think that industry will continue to decline in the U.S. as a proportion of economic growth. In fact, a lot of people think that we're looking at industrial renaissance in this country. What this means for the efficiency debate is that a past source of efficiency gains may not be as available, which creates, in turn, a bigger burden on new sources of efficiency going forward. A second challenge to beating the historical rate of efficiency gains is the tendency for residential load to be resilient. The residential sector has been a clear soft spot in load growth since the recession. And the natural question is whether this trend is due to new light bulbs and air conditioners or if it's due to lingering recessionary concerns. And we think the latter explains a lot of it. One factor is slow housing starts, slow recovery of housing starts, which last year we're still roughly half of where housing starts were the 5 years preceding the recession. Further, we note that efficiency isn't new at the residential level either. Take central air-conditioning standards as an example, since air cooling represents the largest slice of residential demand. The 2006 and still current standard was 30% better than the prior standard. But the next round of standards is only 8% better than that standard. And in fact, if you want to use the ENERGY STAR logo for your air-conditioning, you need another only 4.5 -- 4% above that. So which begs the question of whether some of these efficiency gains' to low hanging fruit has already been captured.

We also think there's potential for larger houses and more and bigger appliances to further erode efficiency gains, but these things are contingent on economic growth and economic recovery, which puts it back toward the economy. Our point overall is not that efficiency gains won't bear fruit. We just question the sense that the impact is necessarily accelerating relative to a long history of already becoming more efficient. We still think economic growth will continue to drive load, especially regional economic growth.

And if regional economic strength is still key to load growth, then Texas is the place to be. On Page 20, we provide load data for our 3 top markets. Texas load is growing rapidly. ERCOT load exceeded 68 gigawatts in 2011 due to hot weather, and while it lowered last year due to milder weather, still are on track for a well and normalized growth trend of over 2%, with the ERCOT official forecast showing north of 3% in some years. Gross state product is helping drive this, which grows north of 4%. And in addition, the Texas population is growing at about twice the rate of the country, 2% per year. And peak kilowatts usage per person has actually gone up 2 of the past 3 years. Of course, in any given year, weather is the most important driver.

Trends in California are more neutral, although recent growth has actually been stronger than many were expecting. The economic growth outlook is much weaker than in Texas, but load and GDP continued to show a strong relationship, or GSP. Mid-Atlantic load growth expectations are fairly low despite the weather-driven uptick in 2011 even before accounting for official energy efficiency megawatts which are bid into the capacity market. This reflects fairly flat population trends and probably some degree of price elasticity.

I would also point out that the load forecast is just as important as what actually happens given the use of the load forecast to drive capacity prices. In all of these regions, load expectations generally match our intuitive sense of what's happening within the regional economies. We think energy efficiency will have an impact, but we're not convinced that we've seen a huge step change that makes load growth a thing of the past.

On Page 21, we shift to the second hot topic that has portfolio-wide ramifications, although I would note that this topic is particularly relevant for markets without capacity structures, capacity payment structures, like today's ERCOT market structure. This topic is the new build spark spread, where the spark spread level at which new combined-cycle projects make economic sense.

The new build spark spread is often used as a benchmark to estimate the amount of upside in the market. Just as one example, if today's forward curve for 2015 has spark spreads trading at $25 and a new plant becomes economic at $35, then that would suggest that there's another $10 of upside to the forward curve. What we've observed is that sometimes people take shortcuts to estimate the new build spark level, and these shortcuts tend to understate the amount of upside, and this, in turn, can understate the value of existing assets. Later this afternoon, John Adams and our operations team will talk about new plant technologies. My comments here relate to how to convert a construction cost into a spark spread level that makes a plant economic.

As noted on this page as factors typically considered, the usual way to estimate the new build spark spread starts with headline construction costs and then assumes recovery of returns and fixed O&M payments, divides all this by the number of on-peak hours in the year to come up with the spark spread level. But plant operational realities listed toward the bottom of this page also need to be considered, and these usually increase the spark spread level actually needed.

Let's take a look at an illustrative example on the next page. On the upper portion of Page 22, we show an illustration of the simple math. Note that we've included the more detailed but still relatively simple math in the appendix to help anyone who'd like to understand the assumptions. The simple math begins with a construction cost estimate from EIA and converts capital return plus fixed O&M costs into an implied spark level. The chart on the page illustrates the potential impacts of 7 refinements to this simple math. Let's walk through each of these items at a conceptual level, and interested people can take a closer look in the back.

The first adjustment is for interest during construction, which is often excluded from quoting construction costs that acts to drive up the amount of money that's needed to be recovered in the market. The second adjustment is for seasonal capacity, what the plant can actually produce net of auxiliary load and temperature deratings the summertime. Sometimes, gross nameplate capacities are quoted, and an adjustment is needed to reflect the actual output of the plant. And by the way, our SEC -- megawatts that we produce reflect all these types of adjustments, that are included in our filings. Third, sometimes the simple math only factors in return on capital. Given the finite life of the asset, return of capital is also needed, and the shorter the target recovery period, which sometimes is influenced by the structure of the market, the greater the upward adjustment that's needed.

Fourth, the plant is likely to earn margins during off-peak and weekend hours as well, which particularly because of the weekend peak hours, acts to reduce the required on-peak spark spread. Ballparking the off-peak impact is not easy because units sometimes run overnight at a loss or at higher heat rates, less efficient operating conditions. Next, plant availability is usually well below 100%. Assuming 5% for planned outages and 3% for forced outages, for example, raises the required on-peak spark spread by almost 10%.

You can see that availability is a pretty important swing factor. One reason why solid operations can be more important than shaving off a few heat rate points by using the latest generation of turbine technology. Second to last, realized delivered fuel costs are typically greater than Hub prices, meaning that the Hub spark spread has to be higher to make room for those additional costs. The final adjustment we've included here is an adjustment for variable cost and major maintenance reserves. We observe that sometimes people think of fixed O&M as total cost, but of course, this is not the case. Incremental dispatch costs are particularly higher for plants which lack the economies of scale that centralize procurement and outage services functions, like we have, can have an effect on that, too.

Note that smaller entities also often have to pay for energy management services, which can further drive up costs even relative to the adjustments that we've included here. This is not a comprehensive list of potential adjustments to the simple math. In reality, the new build spark spread level is determined by each incremental plant that's constructed. But all told, particularly if the cost of debt remains high in Texas and if equity returns remain high as well, or requirements remain high, then we think there's a lot of upside relative to some of the estimates that folks have put forward.

One last comment. By putting this illustrative spark spread level on the page, we're not giving a 2015 price view. In reality, we expect a lot of volatility in an energy-only market, but we do think the forward market needs to show a substantial upside to motivate an adequate level of new investment. Either that, or Texas needs to shift their capacity market design.

Now for the final fleet-wide topic. We've talked a lot over the years about Calpine and its sensitivity to natural gas prices. Now that we've performed well throughout the post-shale revolution range of gas prices, we think it's clear that Calpine is relatively immune to gas price levels.

On Page 23, we reiterate this message, spelling out the trade off our fleet's used between dispatch volumes and commodity margin. And we also make a technical comment for those who seek to use our hedge disclosures and associated modeling tips to forecast gross margin for the portfolio. The chart on the upper left of the page depicts actual generation volumes on the Y axis and NYMEX Henry-hub gas prices on the X axis. Each of the diamonds on the chart represents an actual set of results for a given year with the exception of the green diamond, which provides a onetime window, onetime-only window, into where our models predict that we could come out for this year, factoring in a few months in the history and then into the future, and then the balance of the year. And this holds everything else constant.

While we don't have a lot of data points with annual average gas prices much below $4, this chart shows a clear tendency for generation volumes to increase substantially at lower gas prices. This happens because gas-fired units, primarily in our Eastern markets, start to compete with coal-fired units in the mid-$4 range and begin to take substantially more market share at the $3 range, down through the $3 range. In contrast, as gas prices climb above the coal displacement zone, Calpine's generation volumes decline and then tend to become relatively stable. The yellow line on the chart, while not meant to be a modeled prediction, illustrates this point.

The chart on the right also shows sensitivity to gas prices on the X axis, but in this case, depicts commodity margin on the Y axis. On an unhedged basis, the portfolio's margin tends to increase as gas prices fall, and also as gas prices increase. The portfolio's volumes tend to increase as dispatch -- as gas prices fall. And even though the average margin per megawatt hour diminishes, overall margin increases. As gas prices increase, in contrast, volumes tend to decline but the margin per megawatt hour tends to increase because of the relative efficiency of our plants versus other gas-fired units in the market.

So moving upward, we gain, moving downward, we gain. There's a modeling tip implication to this. For anyone new to Calpine, we've created a series of simple steps to help people estimate Calpine's future EBITDA. You'll see these steps on Page 35. As gas prices decline and our volume expectations began to change noticeably over the past couple of years, we incorporated the table that's at the bottom of Page 23 into the tips.

The simplified point here is that as volumes increase and a larger share of generation volumes come from the off-peak periods, the premium to on-peak prices turns into a discount. You can alternatively model this by taking those additional volumes and pricing them at off-peak prices. We do this as a way to allow people to stick with a more simple approach and estimate the margin based on-peak prices. If you have any questions about the modeling tips in general, please feel free to reach out to Investor Relations or talk to us today.

The punchline is that gas price movement, holding everything else constant, is worth plus or minus $100 million to Calpine. While we'd love to have the $100 million in any given year, it's not critical to the Calpine investment thesis. The company and the investment thesis is really about market recovery, not so much about gas price.

Now Steve will talk about some of the regional trends.

Steven D. Pruett

Good afternoon. Thanks, Caleb. I'm going to go over some of the regional aspects of our markets, our primary markets. Let me get here.

So essentially, on the right-hand side, we've got a high level summary for you, we'll take a quick look at, which provides what are our opportunities and where our opportunities are for Calpine to utilize our fleet and achieve some of the things we think are possible as we go forward. You can see that we just did a little quick view of the value chain there. Energy in Texas we think is a positive capacity, have a question mark because we've got to wait and see what the commission is going to do. Ultimately, it'll be positive if they decide to do that, but it's a question mark because we don't know exactly what they're going to do.

PJM, we also think energy's understated currently. We think capacity will probably be a little more flat, and I'll get into more details here once we go through each one. Southeast, the energy is just kind of neutral because it's really not a market, it's so dominated by host utilities. But the capacity is going to have value in those markets, which as Thad alluded to, we're going after those and looking for opportunities to contract those plants. In California, we think the energy prices will probably, over time, are going to go down primarily because of the renewables, but it's going to give rise to an additional need for the capacity in order to meet what is going on with the renewables in California.

So Texas. Over on the right, the first thing we want to note is we need regulatory reform because we need new capacity in Texas. So I'm just going to take 2017, since it takes that long to build things. So I'll start in 2017. You can see CDR has about 5,000 megawatts out there. At low case, we need another 5,000. You get to another -- and then if you add the high case, you had another 5,000. So we need 15,000 for sure, and then maybe another 1,000 or 1,500 if they change the reserve margin. So a lot of stuff needs to happen in order to meet the load growth that's been occurring in Texas and as forecasted, and we show the variety of different load assumptions so that you could kind of see what it takes. So we're bullish on Texas for a variety of reasons, but one of them is the capacity needs to happen, and they've got to figure out what reforms to make that happen.

Bottom left, getting to the energy side, we have tightening reserve margins, which you can see where those are marked. As we go down, the actual scarcity hours are actually declining over the next 3 years, which is counterintuitive. You would think as the reserve margins go down, the probability of more scarcity hours would go up. And currently, the market is not pricing that in. Our methodology is described, but I'll briefly do it. Essentially, what we use to calculate that is we look at a 12,000 BTU heat rate times the gas price and then take the forward pro price and then the difference and back out using the cap, the systemwide offer cap in order to get to that. So it's just the market pricing is inefficient right now, it's just not making a lot of sense as you move forward based on where the reserve margins currently are.

The other thing I just want to kind of add on that is if you add $1 or -- I mean, sorry, not $1, but if you add an hour in 2014 to scarcity, it adds $20 a megawatt hour to summer prices. So you can see it's extremely, extremely sensitive to how many scarcity hours are going to occur over the next few summers. And obviously, it goes up a little bit more in '15 because the swap goes up, so it goes to $24 or $25 per every hour, more scarcity. So we think that the pricing is inefficient right now in the forward markets.

The bottom right is our voluntary mitigation plan that we just got approved by the PUC here recently. Here's how it works. On day ahead, we can do whatever we want, it's a voluntary market, so the BMP doesn't apply to that. It applies to the real-time market. So basically, we -- parameters have been set up for how we offer our units in, in the real-time now. And the biggest thing is on the blue line there, there's -- we run at min load, so we get our units dispatched. Those will be in at cost. Then we have the flexibility of 3,500 megawatts of our fleet. We can now offer out-of-pocket cost plus $50, and that's a change from where it's been in the past. Then we have -- you can see on the green, there's 250 or 300 megawatts, we can do 500, and then we -- there's some megawatts we can offer at systemwide offer cap. But the biggest thing, I think, that we got, the 2 things. One is we can go plus 50 on a large chunk of our megawatts, which we think may have -- does have a potential to influence the market over time. We'll have to see how other counterparties and other people that are in the market respond and see how the market's behaving and see if they start following along that there's -- we don't have to do everything at marginal cost. So we think that's an important change.

Now PJM. Kind of hit on that a little bit but starting left, go top left then go to right. Lot of retirements coming. There's going to be about 15 to 17 gigs of retirements. A good chunk of New Jersey environmental units are going to retire in '15, as well as a lot of coal units are going to retire. So as you move forward, those are going to happen. Most of that's being replaced by demand response in order to meet reserve margins. That's the current -- how the current PJM market looks and from a capacity standpoint. So as you move that way, you can see as you get out there to '15, '16, a large percent, almost half, not quite half, but almost half of the reserve margin is DR related. So what that then does on the energy side, because we think the energy is understated in forward price right now, if you replace those, those units are going to be replaced with DR, that they're there, you can see that diesel gen sets go $300. How does DR going to price, is it going to be $1,000, it's going to be $1,500, is it going to be $300? We don't know for sure, but we've seen indications they're going to be well above $500 a lot of times. The other clarifying thing on that is actually that DR now will set price. In the past, it has not. They just let it flow through, but DR will set price now in the marketplace. So the simple assumption we use is we took 40 hours at $500 as an illustrative point, but it's a possibility, it would add $18 a megawatt hour to summer prices. So this shift in resources is -- has the potential and to us, fundamentally, we believe it should be going higher as we march into the '15 timeframe, we think it's understated in the forwards.

As you can see on the right, we laid that out. The spark spreads on peak are basically flat as you march through time, through '15 and '16. And for those reasons, we think they're definitely understated on a forward basis right now.

California. We need flexible generation. Let me start with the near-term. On the right, the carbon regulation and nuclear outages are really what's influencing the current market price. You can see, the different points of where it's gone on as far as the forward curve here, this is FP 15 and Cal 13 for the full year. You can see the inflection points, but the market heat rate is higher, because of these 2 things, because SONGS is currently out with some expectation. Maybe some people think it's going to -- 1 unit is going to come back for the summer and some not. I would say the market is kind of assuming not right now from a price curve standpoint. But AB 32 has definitely had an influence. So AB 32, I think most of you probably know, I mean, it's been around $14, 14.25 per ton is what pricing has been, it's been fairly consistent. But the important point for us, there's 2 ways we really benefit by it. One is Geysers has no carbon, so the full impact of what AB 32 costs are in the forward curve are actually what flow through to us. So it's a big benefit to us.

The second benefit that we get is that our gas fleet is more efficient than what the total market is. So we have an efficiency gain so we actually benefit on our gas fleet also from AB 32 and what's built into the current market price.

Moving down to midterm, I don't know how many have seen this, but the duck chart from CAISO. Steve Birbeck [ph] is -- I think his favorite chart now as he's clicking into the future to figure out how he's going to operate the system in the future. But you can see how the ramp rates, et cetera, got to occur out there as they bring on more and more renewables and a lot of solar is included in this and just huge ramp rates. So operationally, there's a lot of issues in how they're going to make this work. But what does it tell Calpine? What does it tell us and how we approach it and how we regulatory and how we go out and try to figure out how to get money out of our generation? Energy prices are going to be challenged. They just will be because the renewables have a lot lower energy costs. Solar has almost 0. And in fact -- and what units they keep on to make it work. The second part of that is flexible generation is going to be important. Generation has to be there in order to ramp and meet what they need in order to operate the system in an efficient fashion. So we believe that they're -- which we're working in, and I'm sure the regulatory people, Thad's group will talk some about that, but that's a part of -- the key of making this -- the market work is getting that generation some capacity payments to be there to provide the stability of the system that they need to have.

The good news from -- happened to work through all this is on the right. We've been really successful at keeping our plans contracted. Obviously, we ought to continue to do that, but we have been successful doing it in the past and we're continuing to work at it and work very hard on the regulatory and origination side to make that work. That's the good news.

And you can -- the other thing I wanted to highlight, it's on the footnote, but I just want to highlight it. We laid out our contracts in time and you can see those. So there's 2 contracts that are CHP, the Gilroy Cogen and Los Medanos, that are subject to commission approval. We've got them on there but they're still subject to commission approval.

Okay. Moving to the Southeast. Thad covered it pretty well actually. Basically, we have to capture value through contracts. That's the way to do it, because the merchant energy side is never going to be particularly large, absent some major market redesign, which we don't see happening in there. But you can see we made a lot of progress. We have 3 plants that currently have no contracts on them. Obviously, we're working diligently to do that. And we've got a couple that are rolling off in the next couple of years, so we've got a lot of more work to do. The good news about that is we are engaged with people talking about some of these plants. As well as you can see on the right, there are a lot of shortages coming up. And these are all based on the IRPs that the different host utilities have put out there in the marketplace.

The final point I wanted to make on the Southeast and I have it on here, but just to highlight it, is Morgan. We have a little bit of it contracted for but only 135 megawatts. So we got another 600 plus megawatts that we can do something with. And right now, our current plan is to take it into the PJM capacity market in the '16, '17 timeframe. That's our current plan. Obviously, the auction is not until May, but that's the current plan. So just kind of letting people know that we are working on that.

The last slide for me is maximizing our value through hedging. And hedging is not just trading in the marketplace. Hedging is actually doing elongated contracts or medium term contracts. Hedging is all those things. Sometimes, people get caught in that hedging means trading or doing paper trades and financial trades. That's a part of it, but that's not all of it for us. Hedging is doing customer deals and customer contracts. It's the full scope of what we do. So we hedge to make sure we get full and fair value of our assets and maximum return that we can for our shareholders.

The position update here that we show is we were 49% hedged back in October, and now we're 68% hedged, so we've hedged quite a bit more over the last few months. The majority of that 68%, there's a good portion of that is actually still Texas, still being open. And you could probably tell from our fundamental view that we think Texas' energy prices are understated. But a lot of that open is actually Texas currently at the point at this time.

Moving over, well, I'll go ahead and do the bottom left. The bottom left does show the spark spreads that Thad mentioned earlier. Some of them moved a little bit, but nothing's really moved terribly large since October. The biggest move has been in California, and I think that has a lot to do with the carbon actually being implemented, and I think maybe in the fall, people weren't convinced it fully it was going to be there.

On the right side is our portfolio changes. You can see we laid out the quarter what percent of commodity margin we actually got from the different quarters over the past 4 years. '13 is different. I want to highlight the changes. First off, we sold Broad River and Riverside. They're being replaced by Russell City and Los Esteros, so we have the same number of contracts. However, the California contracts don't start until summertime. So we have -- the front half of the year does not have contracts that we had last year. The other thing is we acquired Bosque, so that's a totally emergent facility. And as you look at the Texas market, the summer is where most of the biggest spark spreads are, so that's what a merchant in Texas would look like, more like that now.

The other big change is in our hedge -- when our hedging that we did for '13, it's been much more seasonal than it was last year. When we did 2012 hedging, we did a lot of annual trading. And as that -- so that becomes levelized, so there's a lot of stuff that is more levelized. And this year, it's much, much more seasonal.

So from those changes, what you can expect in Q1 will be lower than historical, and Q3 will be higher than historical, and Q4 will be relatively the same, as what our expectation currently is.

The one -- the last thing I wanted to kind of highlight, 2 other points that Thad mentioned was we have invigorated our origination staff to hit our RMCs and co-ops and Munis a lot more than we have in the past. So we made a big effort in that across the north, as well as in Texas. So we're reconnecting with a lot of those, which is a strong thing to help us get contracts and also to help us with the development opportunities that Todd is working on. The other thing that I wanted to mention was in Texas, we have -- we raised it at the last call a little bit, liquidity. Liquidity has been less in Texas this year than in last and it's a variety of reasons. One, banks kind of pulled back. That's part of it. They're deciding how much are going to be in. But the second part, I think, the rules kept changing over the last year, 1.5 years, so people hadn't got comfortable with that the rules are stable that they want to participate as much as they did in the past. We have seen it start ticking up a little bit. More people are getting engaged, but it has been a little bit -- liquidity has been less than has been in the past.

With that, we're ready for questions. Bryan, are you going to moderate or you want me to?

W. Bryan Kimzey

All right. So we are actually running a little bit ahead of schedule, so that's good, so we'll try to stick to our 15 minutes of Q&A and take an early break. So with that, Stephen.

Stephen Byrd - Morgan Stanley, Research Division

Stephen Byrd with Morgan Stanley. Steve, as you look at the forward sparks in Texas around the 24, 25 level out of '14 and '15, what's your sense of what the power market is expecting in Texas in terms of design? Is there a general view that op should be plus and some form is going through and people are -- traders are viewing that as a slight uptick, is there just general uncertainty? What's your sense of what the market is reflecting?

Steven D. Pruett

I don't think it's really reflecting anything on -- particularly on that because I think it's -- in particular, the summers and the other months. I don't think they really reflect anything because I think the market is so uncertain in what the commission is going to do that they really aren't reflecting anything that would change on how the operating reserves would work right now.

Stephen Byrd - Morgan Stanley, Research Division

Just as a follow up, as you all look at Texas new build, there's a lot of sort of debate and uncertainty as to the actual level of new build activity, that's a constant topic of debate. There's one school thought that people are building in this market environment. The other school is that there's actually very limited true new build activity, not nearly enough to fill the void. Would you mind just weighing in a little bit as to what you see every day in Texas and the actual amount of development activity versus sort of the press release activity?

Caleb Stephenson

People are certainly working hard to create options, which we think reflects the bullish atmosphere here in Houston about the market structure. When you look at the CDR, there's an enormous amount of megawatt capacity that are required. And even if you take the projects that have been announced, the projects that have been financed, the activity that you see out there, it's not anywhere close to enough to meet that load growth. So there's certainly some activity, but not nearly enough to meet the load growth that we're seeing in the state.

W. Bryan Kimzey

Ali?

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Coming back to that last point on new build in Texas. I think, recently, there was an announcement by Panda Energy that they're putting another 700 roughly megawatts of new capacity and they've got another 1,400, 1,500 also in there. So in total, I think they've got over 2,000 that they're saying will be in construction. What is it that they're seeing in economics that don't support that new build calculation you showed us?

Caleb Stephenson

I don't think the construction decisions are being based on the forward curve. We can start there. So in some ways, it's a bullish sign that people expect more growth in the Texas electricity market. As to that, the individuals, I think that have made those decisions. I don't think we can really comment. We can talk about the development prospects that we see and how we're able to come in much lower on cost than some of the things we've heard from those projects.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

I guess, related to that, were you surprised by the fact that they also said that they have financing in place that lenders are willing to lend in this merchant environment?

Caleb Stephenson

There seems to be a pretty good appetite for a debt at 11% return for something that's worth 400 or 500 of kW ultimately. So there's some interest on the debt side. On the equity side, it's hard to gauge how deep that is and what kind of risk people want to take.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

One other question if I could. I was just looking at the appendix through these slides. And if I read this right, your contracted margin for '13, which is now, I think, showing at $20 a megawatt hour, did that come down? I think, last time, if I recall, it was like $23. Have you seen a reduction in the '13's hedge margin?

Steven D. Pruett

Yes, it did come down. Remember the -- is my mic on? I can't tell. It would come down because you're now -- you're taking contracts and now you're doing hedging in the forward markets and you do it -- when you do a lot of Q4 in the spring stuff, you have a lot lower spark spread. So naturally, it's very historical is what's happened, the sparks -- that margin comes down.

Caleb Stephenson

Just a follow-up on the Texas question and the appetite for the debt. If indeed the debt levels and the debt costs are that high then it suggests even higher equity requirements, which would take the required spark spread well above what we've shown on the illustrated map.

W. Bryan Kimzey

Angie?

Angie Storozynski - Macquarie Research

Angie Storozynski with Macquarie. On Texas, when I look at the economics, new build economics for the spark spread calculation, you're not accounting for any ancillary services, or operating reserves revenues that you currently receive, which would actually support the economics even without a pickup in the spark spread, right?

Caleb Stephenson

That's correct. In this particular example, we didn't recognize A.S. value specifically, as well as some of the other costs that could erode those values. And if you look at the U.S. markets today, there's not a particularly huge amount of money that's coming for this type of units that would materially change the picture.

Angie Storozynski - Macquarie Research

So when you come back to say 2000 or 2001, did you ever reach the level of on-peak -- or could ever actually show on peak spark spreads that were fully reflective of economics of new builds?

Caleb Stephenson

In history, I believe so. I think back in '07, '08 timeframe, we may have had spark spreads on average, driven by related factors, primarily driven by very high gas prices at the time. But I think there were occasions where price levels were at new build economics, just off the top of my head.

Angie Storozynski - Macquarie Research

Now, on PJM, you're showing the demand response was an expensive way to replace those retiring coal plants. How about what would you say about coal plants are actually not going away, but they're being repowered with gas and so you're actually getting a lot of new higher heat rate gas peak growth and those coal plants are not really disappearing?

Caleb Stephenson

The announcements that we've seen so far suggest that not a lot of plants are being converted to gas. There certainly are some, but there are site issues, there are locational issues that sometimes make converting to gas pretty difficult and maybe Todd can add comments on some of the competitors that we've seen.

Todd Thornton

Yes. So when you think about repowers, typically, in a very dense area and the ability to get gas there is a challenge, right? There's very densely populated area, there's right of ways needed to get fuel lines out there. And so, while, yes, some have been announced, and some make get done, we don't see a lot. And so we do believe the coal retirement story is real.

Angie Storozynski - Macquarie Research

And my last question, I promise. On California, you're mentioning that you see downside to energy prices but upside to capacity prices due to ramping needs. I mean, I would actually think that a peaker is more suitable for ramp up ability than a combined cycle gas plants, and you guys own CCGT's in California.

Steven D. Pruett

Yes, I mean, from an operation standpoint, it would be part of it, but it's a question of plants that are already there that are already environmentally sound that are already there. So new build is going to be much higher cost. That's going to be the -- you're right, that is a challenge that will have to be thought through. But from a -- if you're starting from scratch, maybe that's what you would do, but we're not starting from scratch.

Caleb Stephenson

Our own 6,000 fleet, certainly, can start very quickly in California or combined cycles can still start quickly though and there are additional investment, additional things we can do with the units to make them able to start even more quickly if the market structure supports it.

W. Bryan Kimzey

Julien?

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Julien, UBS again. First, on PJM, we've heard a lot of different commentary how much upside there is. I suppose, in your case, more peak pricing than ATC. How much do you see, right? You talked more about demand response of late and we've heard something about shortage pricing before. In aggregate, what is that range, not to pin you on something?

Steven D. Pruett

On the energy price range, what we think we might see. Is that what you're kind of asking?

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Right. And maybe even specify DR, shortage pricing retirements, how does that kind of -- how do you add up to it?

Steven D. Pruett

Well, the breakdown, I probably can't give you right now, but I would probably argue we're probably anywhere from $3 to $5 off on a pole calendar on-peak basis. Offpeak, I'm not sure how it's going to be influenced with the units retired, it's probably going to be more a function of gas price and based on our gas prices, you'd probably argue offpeak is probably understated, too.

Caleb Stephenson

And I would add to that, that as we see units convert to DSI, in fact, as we talked about 2 years ago, we'll see their variable cost go up so we can see a lot of opportunity for offpeak prices to increase as well.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

The timeline there, I mean, if it's not entirely driven by retirements, when do you start to see that. Is this actually sooner than '15 in your minds?

Steven D. Pruett

I think we'll start seeing it, I think it will start filtering into late '14. I think you'll start seeing it in Q4 of '14, but it'll definitely be there by '15.

Caleb Stephenson

Now all the retirements are waiting until 2015 before [indiscernible] so there's some upside there as plants retire. The load side is not really driving it as much in the mid-Atlantic as in other parts of the country. So it's really on the supply side and the core retirements but -- as well as the head retirements, New Jersey head retirements.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And then maybe second subject here, as far as contracting goes, you've talked about some of this projected deficit. When do you think we'll get more definitive data points out here? Are there specific RFP processes or RFPs that we should be looking towards wrapping up that could lead to something in particular?

Steven D. Pruett

I can't give you any timeframe but all I can tell you is we're diligently working toward getting things contracted.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Is there a specific asset or assets?

Steven D. Pruett

I don't want to get into that because we're -- as we respond to different things.

Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Neel Mitra, Tudor, Pickering. The economics you laid out for new build spark spreads in Texas, those are based on greenfield. What would you say the average brownfield spark spread or construction cost is for the average generator in Texas? And how big do you think that market is for lower cost new builds from existing sites?

Caleb Stephenson

Let me just make the first point that this is certainly illustrative math, so not meant to be reflecting any particular unit. And as to what the discount might be for different types of units, maybe Todd, you want to comment, or else our operations folks will talk about that, too.

Todd Thornton

Operationally, from an efficiency perspective, I can let the operations folks talk about it. But I think a brownfield development opportunity, not all brownfield development opportunities are created equal. So in this illustrative math, you'd obviously just bring down your cost of new build. And I think that as we've proven with our existing Channel and Deer Park expansions, you can do so at a very cheap dollar per kW. But I'm not going to sit here and tell you that all brownfield opportunities are created equal. But certainly, the spark spread would be cheaper to the extent that you can lower in this illustrative example, you're all-in cost to build.

W. Bryan Kimzey

All right. Well, we've got a few minutes left. Greg?

Gregg Orrill - Barclays Capital, Research Division

Greg Orrill with Barclays. Back to the PJM demand response, Slide 29. First, I think you make the point that the amount covered in the incremental auctions is declining and maybe why you think that is? And then second of all, just your general thoughts on the impact of DR in the upcoming auction bullish, bearish? And then third, any additional rule changes on DR that you think we should be paying attention to?

Caleb Stephenson

As to what's happening with the incremental auctions, the extent to which demand response has been covering its positions in incremental auctions, while as a percentage, has decreased, by megawatt, has actually picked up substantially. It was very influential in this last auction in driving the Eastern mac current price to 188. So demand response covering in the auctions is still a material factor. Now as the rules become more fixed and as the certification requirements for demand response participation ramp up, there's a chance that the viability projects, the projects laid, they become more crystallized and maybe it's easier for the commitments to be made and for them not to be to need to procure back out of those -- or buy back out of those commitments. Whereas to say that plays out on whether the demand response providers really are willing to step up to those certifications, which are now looking like they're going to be required.

Gregg Orrill - Barclays Capital, Research Division

Do you think we'll see an impact to that in the next auction?

Caleb Stephenson

Potentially, it's hard to say. But that's certainly a swing factor that we are very interested to see what happens in this next auction. And to the extent people become concerned about making commitments, then that would be a pretty bullish signal for this next auction.

W. Bryan Kimzey

We got time for one more question. Steve?

Unknown Analyst

Just a question with regard to the forecasted energy prices. So you're making a bullish view on pricing in most of these markets and we've heard that from other people as well based on good fundamental data here. But obviously, the prices haven't done that yet, and I'd say a lot of perspective on the forward markets is there's more sellers than buyers, there's not a lot of liquidity. I mean, what do you think needs to actually happen for prices to reflect these fundamentals? Do we need to see just a spot to jump up in the summer and then suddenly the whole curve moves? Or just what do you -- Steve, I know you've traded in the market a long time. What do you think is the issue and what needs to happen?

Caleb Stephenson

Before Steve answers, just 1 quick comment, and that's that I don't think it's necessarily been the case that these markets haven't displayed the tightness that we think is there. If you look at Texas 2 years ago, the Texas mortgage certainly showed that there were scarcity conditions and shot up in price. And that's true in PJM in the mid-Atlantic, 2 summers ago as well. So these markets do show signs of scarcity and really the question is what's happening with the forward markets and what might drive that up.

Steven D. Pruett

In the forward markets, I'll start with PJM. Essentially, I think there's 2 big factors that kind of get -- maybe 3, 1 is you're right, we need confirmation in the spot for people to really start getting interested. The second thing is PJM has predominantly had people generators that had 3-year hedge programs. So it keeps a suppression on the price because they're selling and the market knows it and so people got aware of that risk. And then the other side, the argument also with that is the load side has been typically a year or 1.5 years mostly. So they have had not a need to go out there to buy to kind of offset what the generators are doing. So I think it's a combination of just there's not as much liquidity in the forwards. There's selling pressure, loads don't go out there and then you need some confirmation in the prime. And then Texas is not dissimilar from that, from PJM in that. There's just not a lot of activity beyond the front year, 1.5 years.

W. Bryan Kimzey

All right. Actually, Maura, we'll take 1 final question and then we'll break.

Unknown Analyst

[indiscernible] I was just wondering, we've seen around the world at times when the renewables kind of run the world and there's no capacity market, pricing really gets smashed and I'm wondering if, in California, if there's not a capacity market, we could see another Germany or something. So how do you expect the California situation to evolve?

Caleb Stephenson

If we don't see a capacity, if we don't see a structure in California, and the regulatory folks can comment on this as well. They don't [indiscernible] but if we don't see a structure that pay for flexible units, then we'll see units exit the market. And there are a lot of older, higher heat rate units that won't be able to cover costs, fixed cost have been escalating, and will exit the market and the market will become tighter. And so one way or another, to the extent flexibility is required, the market will need show those symptoms and show those pricing. Different time schedules.

W. Bryan Kimzey

All right. Thank you, Steve, Caleb and Todd. And with that, we'll take a 15-minute break. If everybody could be back and ready to go at 10 till 3, 2:50. Thanks. Oh, and there's snacks out these doors in the foyer behind left field.

[Break]

W. Bryan Kimzey

All right, if folks in the break area could please return to your seats so we can get started. All right, I'll give everybody just a few more seconds to get seated. And up next, we have the Power Operations panel with John Adams, and I'll let him -- he's our senior VP of Power Operations, I'll let him introduce his team.

But before we get started, I would like to take one moment to thank the people responsible for putting this Investor Day together. First, Corporate Communications led by Norma Dunn and Debra Bullard, our magnificent event coordinators. And I think they're outside, so they can't hear me. But if you get a chance to thank Norma and Debra, I'd appreciate it. They've done an amazing job. And second, my Investor Relations team led by Christine Parker and Dan [indiscernible] who facilitated all the presentation materials. A round of applause to them because this is a herculean effort.

So thanks to everyone who -- and the management team as well, who cooperated with us over the past month. And with that, I'll turn it over to John Adams.

John Adams

Good afternoon, everybody. The focus of the Power Operations team is to take our 92 power plants and turn them into a fleet. But not just a fleet. We want to be the premier fleet out there. We want to be the premier operating company and the premier fleet in the industry. What does that mean? That means that we have to have the best maintenance, the best operations, the best engineering staff, the best construction staff. We need to be able to build our plants cheaper, quicker, better than anybody else out there. We need to be the most reliable and we need to be the most cost effective.

With that said, our organization for Power Operations is really divided into 2 areas. One is the regions. We've got 5 regions that really align themselves to the commercial groups that are out there. And those 5 regions really are experts within the area. The managers and regional VPs that run each of those regions, know all the issues and know all their plants. But the piece that we've added over the last couple of years is really shared services. And the ability for our shared services to take advantage of the fleet size that we've got, to take expertise and to really make us that premier operating company that we've wanted to become. So with me today on the panel are some of the people that really bring in these shared services. First, you'll hear from Ron Macklin, who runs our Outage Services group. Second will be Tom Long, who runs the Development & Optimization team. And then finally, we'll have Ron Hall that runs our Engineering & Construction team going forward.

Last year was a great year for us. It was actually the best year on history for Calpine. As Thad had talked about before, we set records in terms of our forced outage factor, and that translate right to being available when we need to be. We also generated more megawatts than we had ever generated before. So we did this, and at the same time, also set a record with regards to safety. And I would tell you all that this wasn't done accidentally. This was done on purpose. These shared services and teams that we have were able to put the discipline, the rigor and utilize the scale that we've got and really take the most advantage of it. But again, a really great disciplined, focused approach to things was what allowed us to be able to get there.

Now with that, we've implemented a number of fleet programs, we've taken advantage of our supply chain, we've really been able to buy better than anybody else out there in the industry. We've really been able to use our Outage Services group to predict the outages that we needed to take, to take them quicker than anybody else and to be able to manage issues before they become a problem to us.

Finally, as all of you know, having the largest fleet or one of the largest fleets out in the industry is a real benefit for us. We have 238 turbines. We're the biggest users of Siemens Westinghouse 501F turbines in the world, we're the second largest in all of GE, and that gives us a really big advantage over others. We're able to again have the experts, we're able to have the parts, the pieces that others wouldn't have.

For example, in our fleet at any one time, we have 2 501F rotors ready to go. If we were to ever have a failure in one of our gas turbines, we can immediately ship out one of our rotors, get back up again. Similarly, with GE, we have 2 rotors ready to go. Another advantage and another example of that would be our transformer program. At the end of this year, we'll have transformers available, ready to go, to cover 92% of our fleet should we ever have a failure. So this is some of the advantages that we've got having the fleet and really having the right shared services to be able to maximize the use of that.

So with that, I'm going to introduce Ron to talk a little bit about Outage Services and talk a little bit about his group, and we'll go from there.

Ron Macklin

Thank you, John. Outage Services is really responsible for the care and the maintenance of the entire fleet within Calpine, and they're our prime movers. So from the small arrows, the LM2500s up to the steam turbines to the Geysers, all the frame units and everything in between.

If you remember back, I think, on Slide 13 where Thad had talked about our forced outage rates, they've gone down 53%. Our number is actually 1.6%, which is a fleet percent reduction just of last year. So if you look at I think on Slide 43, but if you look at the right-hand side of the slide that's on the screen, you'll notice that this is how much that represents in a manner of spend for equipment failure. Where in 2010 we were spending over $40 million, in 2011, we were just over $20 million, and in 2012, we were just under $20 million. This is a pure savings. What that means is we have a low forced outage rate.

We also, from a safety standpoint, last year, we had 0 lost time injuries, and that's both for internally at Calpine and with our contractors.

Well, the question is how do we go about that? We have assembled some of the best technical experts in the country and to our technical team. We focused on outages. We focused on scheduling and planning and forecasting. And we work to make sure that we're always doing everything in a very, very safe manner. Safety we would be our #1 priority.

When you look at the size of our fleet, we've got the #1 amount of 501Fs in North America. We've got the #1 V84s in North America. We're the #2 in 7FAs. And what that allows us to do is to create a marketplace where people are competing to have our business. Over 80% of what we do, we have at least 2 competitors who are competing for our business. What that means is we're able to get about 45% discount off of what our competitors are paying for parts and services as we put together that approach to go forward on all of our outages.

There's really 4 kinds of outages that we do, I'll start with the left side of the screen. What you're looking at there, first, we'll start at the bottom, this is the most expensive. It's a major outage. The way to look at the major outages, we take the rotor completely out, we replace everything that needs to be replaced and repair it and put it back together. It is the most expensive outage we do, right?

Just above that is a hot gas paths. So the hot section of the turbine, we're going to open up those covers, replace the hot section of those parts. It's about 70% of the major. Most of the cost of the materials is inside the hot section. The majors are 48,000 hours. Now those are not calendar hours, those are operating hours. So each unit will actually be dispatched based on its market, and those hours are accumulated at different paces on different units.

The next to the -- and it's probably the smallest normal maintenance outage, which is a combustion inspection, where basically where the ignition sources are created for the turbine. We'll go in and look at those, and depending on what technology we have, either at the 8,000, 12,000, 16,000 and then the 24,000 hours, we actually go and replace those parts. Simply put, we open up the manways, we go inside, we look around, replace what needs to be replaced and come back out.

The last outage which is by far the lowest in price but we do the most of them, and that's CI. We do so many of them, it's really up on the chart. And what we do is we take out a plug that's about the size of a silver dollar. We stick a borescope in. We do this 2 or 3x a year. We do this at a pace so that we can catch when things are failing before they fail and cause consequential damage downstream.

Next there on the right side of the screen you're looking -- you'll see what we're looking at a 5-year maintenance budget. If you see the different outages and they're running at different paces and different marketplaces, what happens is they don't just smooth out. They actually start to jump up into big clumps as we go through. So in 2016, you'll notice the orange section and the green section, which those are majors and hot gas paths, those are the majority of our spend, right? When you look at the overall 5-year average, we're right now at $350 million, right? Now this include some changes from the last time, where we've actually had sold some units and bought some units, but we also include inside this number Russell City, Los Esteros, the 2 units at Deer Park and Channel and also at Garrison. So there's actually a lot bigger fleet inside this number than what we had last time. And this gives us an advantage to be able to predict when we're going to do maintenance and go forward so we know how to schedule out our parts and our services.

So with that, I'll turn it over to Tom.

Tom Long

Thanks, Ron. Appreciate it. I want to continue with the theme here on gas turbines, and 2 things I'd like to talk about. One is our F-Class gas turbine fleet, as well as some of the advancements in their technology and give a little bit of insight on to what some of the published numbers that you're seeing from the major manufacturers, what they really mean.

So let's start first with the -- our gas turbine fleet. Our F-Class, our 501Fs and 7FAs constitute around 50% of our fleet. These are modern, and they are competitive and they will remain competitive. There's advancements that are going on right now in the -- with the manufacturers that are making some tweaks to the gas turbines, whether it's in the compressor section or in the gas turbine section. These are incremental changes, they're not revolutionary changes, okay? And we remain competitive in that regard by being able to upgrade and close that gap to a certain extent. And I'll touch on that in here in a little bit.

But the key thing here in our fleet is very important to know. One is that they're very clean, right? And I think that's part because we're very, very efficient in burning natural gas. Secondly is that they're highly dispatchable. We can cycle these things on and off. We can run them at minimal load, we can run them up to maximum load. Highly dispatchable, highly valuable in that regard.

And lastly, and probably most importantly, we're very reliable. A lot of the advancements that are coming here don't really address the reliability. But as you can see on Slide 41 that John talked about earlier, at a 1.5% to 2% forced outage factor certainly demonstrates our reliability, and it's very, very important to us.

You're seeing a lot of headlines from a lot of the advancements in what we call the advanced technologies. And those include from Mitsubishi, from Siemens and from GE. And they're moving into the next letter of the alphabet in some of these regards. And some of the manufacturers, GE and Siemens in fact, have abandoned some of those old programs and have moved into totally new platforms of gas turbines, right? They -- and the biggest example, the best example I can give you is on General Electric, their series 7, what they call their series 7. GE 4 practically ever has been 3 turbine stages on the back end. This is the 4 stage. That may not mean a lot, but that's a significant path for change for any gas turbine manufacturer and GE. Now they're spending a lot of money in doing that, but it is a change for them.

These gas turbines that you're hearing, these gas turbines, are not necessarily -- Calpine's not necessarily the target audience for that. We're not the target customer right now. Yes, they are more efficient in the class they are today. But there is yet to be seen the proof in the ability to fully cycle. I don't think a lot of those things have been fully proven out, and there's a lot of peeving issues, I suppose, that have to occur over the time. We're not the target market there. High gas places like in Japan or Korea where the heat rate definitely will play a more -- an impact is where you'll see those types of engines appearing. And in the case of the United States, where some regulated utilities that can -- on a rate base, like kind of a baseload operation. That's not Calpine certainly for the course of the day.

So what I want to do is turn to the heat rates because they are interesting. They are -- they make great headlines, I guess, that's why they call them headlines. But as you realize as an owner and operator, you have to understand that those numbers have to get translated and adjustment need to be made to the real world.

So let's start on the left-hand side, and this is the 5,781. This is the GE -- it's a 2x1, their series 5 gas turbine.

5,781 is their heat rate that they publish for a 2x1 650-megawatt combine-cycle plant. But it's -- and that translates to about 59% efficiency.

They convert their energy based on a lower heating value. And not to bore you with any details, but as an owner and operator, consumer and buyer of natural gas, we don't get to buy on a lower heating value. We buy on a higher heating value. The difference is essentially the vaporization of water. So that's about an 11% increase or an adjustment that you need to make, okay? Also, this is just the equipment that they're supplying. To operate and build the power plant, you have a lot of worries. You've got cooling towers, you've got boiler feed pumps, you've got electrical motors, you've got all sort of things in the plant to actually put the megawatts out on the grid, not just this isolated 2 pieces of equipment. So there's an auxiliary load that have to add, then you then take that to another 200 points on the heat rate.

So if we just stop right there, that number translated HHV, there's 3 things you need to know, It's around 6,700. It's a nice number. 3 things -- 3 words you need to know. That's new, it's clean and it's at ISO conditions, okay? And there's -- the further adjustments on this that I'll discuss, take into account moving off of those 3 key points. One is they're new and clean, brand new, shiny new. As you look at operating and owning a power plant, compressors get dirty, seals get clearance, and there's all sorts of things we know. And over the long term, you're going to see a lot of 2% kind of heat rate impact. So that's another 130 heat rate points that we look at.

Not everything and certainly not in Texas is at ISO conditions, which is 59 degrees. We live in a world that's -- variant temperatures, so there is a heat rate adjustment. As it gets hotter, the heat rate, the efficiency gets worse. So there's an adjustment for that.

And then probably, the biggest one and it's -- that is not usually picked up on here is the cycling in effect. And I mentioned it earlier, but if we look at our plants, they can cycle 200x a year. We're doing that, we're shutting on and off at night. You're burning fuel but not making a whole lot of megawatts. Or you choose to run overnight and you're running at a minimum load. You're kind of crawling into the shell. Well, both of those implications impact your heat rate numbers, anywhere from 200 to 300 points is that line. And that's in fact what our plants are doing as well. So if you take a look at the far right-hand side, the 7,240 number is our equivalent type of configured plant, the fleet of about 40 engines, it's about half the fleet there. Realized, around 7,200. And if you aggregate all of the headline number, this 5,781, up to -- and include what you would think of as an owner and operator, you're sitting around 7,000, 7,100. The spread there is not that big, right? It's 100 heat rate points. And at $4 gas, it's $0.40, okay? It's measurable. It's not significant, right? So heat rate is important, but I wanted to provide some clarity around that. Also, I want to let you know that we have undergone a program, as you know, in upgrading some of our gas turbines, kind of closing the gap between our regime and kind of the new guard. And this represents, right now, we've only done around 25% of our fleet. And as the economics dictate, we will continue to work on that program. So the message here really is our fleet, it remains competitive even as these new technologies are being introduced into the marketplace.

So with that, I'm going to turn that over to Ron Hall, who's going to talk a little bit about the construction.

Ron Hall

Thank you, Tom. I'd like to spend a few moments this afternoon talking about construction costs. I know there's some questions out there earlier today, so maybe I'll address some of those that weren't completely answered. And also give you an update on the status of our existing projects we have in construction.

If you'll take a look at the graph here on the upper left-hand corner of the slide, what you see here is the cost of typical CCGT plants for various locations across the country. This is based on EIA data, and it's based on overnight cost.

Our view is generally consistent with these averages for the various areas. They range from just shy of $900 per megawatt -- or per kilowatt installed to $1,650 per kilowatt in New York. We've seen projects announced in the mid-Atlantic and a price range of just over $1,200 for greenfield facilities and as low as $935 for a brownfield facility. So the question earlier about the difference between brownfield and greenfield pricing, I want to be careful here because Todd summarized it real well. All brownfields are not created equal, as well as all greenfields are not created equal. So there's a potential in the difference between brownfield or greenfield to save anywhere from 15% to 30% on project costs. But each project will be an individual project, and those differences will depend on transmission interconnections, gas interconnections, water interconnections, those type of things. So you have to evaluate them all, all of them on an isolated basis.

Then in Texas, there's been some announced greenfield projects in the $800 to $900 per KW range. We think that price range is possible at this time. We do see the Texas cost increasing due to upward pressure on labor rates -- or labor shortages and productivity based on the number of petrochemical projects that are ramping up. So we'll pay attention to that. When you look at -- I guess there was another question earlier about cheap Texas power. We talked about Deer Park and Channel and the price range at which we're installing additional capacity. We've got a couple of hundred -- I mean about 300 megawatts additional capacity in our fleet where we could do upgrades or capacity additions. It's steeply discounted prices. When you look at what we did in Deer Park and Channel, the reason we were able to drive those prices so low is we had a steam turbine that was oversized and we were able to add a gas turbine and heat recovery steam generator, use that steam in that steam turbine. To our knowledge, that was the only 2 steam turbines that were significantly oversized in the state of Texas that we could use.

So we see there's potentially 1,000, half of that, maybe 2,000 additional megawatts from our competitors where they could do similar actions as far as capacity increases in the short term.

What I would like to do is call your attention to the 2 yellow stars here plotted on the graph, significantly left of the typical CCGT cost for the mid-Atlantic and for Texas. Those 2 stars represent the Calpine difference. What do I mean by the Calpine difference? Calpine is not your average developer or utility. We don't claim to be. We're very entrepreneurial. We're focused on in taking good -- in taking great pride in being able to complete projects leaner, faster and more cost effective than our competitors.

We currently have, I think you heard it earlier, 5 projects under construction. I'll talk about them in a moment, but let me step back. How can we complete these projects leaner, faster and more cost effective? Calpine has got a tried-and-true bench of expertise. We've got the expertise and the skill sets to perform all aspects of a project from development to execution well. When you start looking at project siting, equipment purchasing, EPC selection, construction oversight, startup and commissioning, and last but not least, premier operations and maintenance. All of these parameters impact overall project costs. And we've demonstrated our ability to execute better than our competitors by optimizing those -- that overall project approach and execution.

Other things that help us. We operate a very large fleet of F-Class equipment and steam turbines. So we certainly are not afraid to redeploy surplus equipment or purchase gray market equipment. We've been very successful at that, and that can tend to lower our project cost.

Secondly, the market is currently in our favor with EPC contractors. All the EPC contractors out there know that Calpine has the ability and has the skill set in-house to perform self-build. And what that does for us is it gives us a leverage with the EPC contractors to get the best contractors at the lowest price.

Our third notable advantage is the fact that we have facilities in PJM and across the country that can be repowered, upgraded or expanded, that are critically located. That means they've got good transmission interconnections. They've got good planned infrastructure that can provide overall project cost reductions. So that's some of the ways we're able to be -- to pass projects below what the typical costs are across the country.

Briefly here on the projects under construction, I think just between 1,400 and 1,500 megawatts, Russell City and Los Esteros will go commercial this summer. Right behind that is Deer Park and Channel, which will go commercial in the summer of '14. And just earlier this month, we started construction on our Garrison Energy Center, which is scheduled for construction the summer of '15. All the projects are forecasted to be within the approved project budgets and progressing well.

So in summary, what I want to leave you here with today is Calpine is uniquely qualified to develop and execute new generation construction better than our competitors. Leaner, faster and more cost effective, that's the Calpine difference. Thank you for your attention, and now the Power Operations panel will entertain your questions.

Unknown Analyst

As you look at additional equipment, turbines, excess turbines, excess equipment that you could deploy in brownfield, you've been very successful in doing this in the past. As you look at your inventory today and then potentially equipment, say, in the Southeast or elsewhere that you might be able to redeploy, can you just talk about your flexibility to pursue more development that would be at a deep discount to sort of even brownfield construction?

Ron Hall

Yes. So the question is as we look at what we have in inventory, but also what may be out there for us to be able to use to develop what approach or could we do that, I'll take the first stab at it, and then Tom will run from there. We have one complete GE 7FA that we could deploy anytime we want. We've got about 1/2 of another GE 7FA, but we have the rotors and the parts available to put it back together again. We're kind of in a unique position because, again, with Ron's team, we can take that engine and put it together and we don't really need the OEMs to go ahead and rewarrant [ph], which has been an issue where others have had to do that. So we can actually take and build them ourselves. Now, in addition to that, we know all the number of gray market equipment out there. Tom, do you want to take a little bit on it?

Tom Long

Sure. There is -- although it's a decreasing population, there is still out there a gray market on some of gas turbines, and they are in the same type of units that we own and operate today. And so we're going to look at those very carefully. I mean that is clearly one of those opportunities to come in at a reduced cost. I think if you also look at it, and Thad had announced this earlier, today our deepwater project, right, that's kind of, I guess, in some way a brownfield project, right? We have existing infrastructure on-site. We've got everything kind of laid out, ready to go. We've got pipe. We've got transmission, all access and discounts. So those types of opportunities, we're going to continue to capitalize and develop. And then as the markets allow for the returns, we're going to move forward with those.

Unknown Analyst

Just to sort of clarify, with the 7FA equipment that you have, that would mean you could deploy that. That's already essentially paid for, that's just -- that's inventory that we're not...

John Adams

We've got inventory ready to go. We'd have take it and send it from where it's centrally located right now and bring it to the next site. And we're constantly evaluating, is that the right way to do it? I mean -- and right now, actually the short term, it's actually a pretty good buyers market with OEMs. But that will change, we believe, going forward.

Any other questions for the ops team? Okay, thanks, great. Yes, just to introduce the team a little bit, this is all a relatively new team. I'm John Adams. I've been here -- this is entering my fourth year right now. And prior to coming here, I ran Mitsubishi's new equipment group, so everything from the new gas turbines to wind turbines to solar. Soup to nuts, I ran that business. And then prior to that, I was with an EPC contractor building power projects and engineering and building plants across the world actually, too. So for me, I've been in the industry over 30 years, so quite a while. With that, Ron, want to go ahead?

Ron Hall

I've been in the industry for about 26 years now. Before coming to Calpine, this is my second year. I ran fleet service North America organization for combine-cycle plants for Siemens. Before that, I was managing their operations in Europe, which was basically everything but North and South America. We're developing business inside of the Westinghouse design fleet. Before that, I was actually -- worked for as a vendor to Calpine, managing the national account for Siemens. And before that, I was a Project Manager and a civil service engineer for Westinghouse then Siemens.

Tom Long

I guess, in Calpine standards, I have the grayest of the hair. I've been here 13 years, and I've been involved in all aspects of the growth of the company and the operation of the company through EPC constructions and operations, through finance development, you name it, so continue to do that. I debate a lot of times with my CEO, who's got the cooler job, I won't contend that I do. But since he pays me, he's got the upper hand. That said, prior to that, I was -- I came to Calpine 13 years ago through an acquisition of a development company, SkyGen Energy, that was acquired in 2000, and I've been with them for a number of years. So what, 20 years in the industry.

Ron Hall

Yes, just real quickly, we were talking earlier and Jack was mentioned. He talked about at the Performance Engineer. And I kind of reminiscing, I started out at Florida Power & Light. Obviously, in the performance arena, as a performance engineer, worked several areas there. I was involved in the very first construction project for the 501 AF serial numbers 1 and 2. Over the years, I believe I've been involved in about 14 different construction projects, some of them from cradle to grave, some of them parts and pieces. But after leaving Florida Power & Light, all of my career, until joining Calpine, was in the utility sector. So when I say Calpine's not a utility, I know what it means and appreciate that. So I ran operations for a gas fleet for Tennessee Valley Authority for a number of years. That's been about 17 years running their gas fleet and new construction, as well as the last couple of years there, I ran their power service shop that did all the outages for the entire fleet, both the nuclear, hydro and fossil facilities, and joined Calpine in, I believe, October of '10.

W. Bryan Kimzey

Good. Any other questions? All right. The premier operating company is here and we're going to continue to drive the table stakes to even better standards. Thank you.

W. Thaddeus Miller

Well, some good news, Bryan tells me we have extra time. So those of you who brought your gloves and those of you who didn't, we have bats. We're going to take fielding practice and batting practice in a little bit. You don't look like you're ready for that. Well, what a great space. This is apparently the old Union Station in Houston. It's been closed for decades before the Astros built this stadium and had a great idea to make it a part of the stadium. And hopefully, some of you had a chance to peek at the ballpark behind us. But I find it interesting that we've been here now, 2 or 3 hours and none of us have alluded to either some train analogy or some baseball analogy. So we're going to have to spice it up a little bit for the Gov Reg section. And for folks like myself, who are baseball fans, Yogi Berra is great baseball legend. It turns out, Yogi Berra came to Houston and spent the last 3 years of his coaching career with the Astros as a bench coach. And those of you who might be familiar with baseball know that Yogi Berra was famous for what's affectionately called his Yogi-isms, which are basically witticisms, sometimes malaprops, but incredibly odd statements. For example, when he came to Houston initially, he said, somebody asked him, "Well, how do you like Houston?" And he said, "Well, if it isn’t the heat, it's the humility." I'm sure you all experienced that outside today. And in fact, he came when Bush 41 was running for office back in the late '80s. And he was asked, "Well, what do you think of his chances?" And his reply was, "Well, you know, Texas has a lot of electrical votes." So we tie it all back to what we're going to talk about here today. With me up here today, I have 4 of my team members in the Government & Regulatory Affairs group at Calpine. We're some 20 strong professionals in the East in our Delaware office, in our Washington D.C. office, here in Houston, as well as in Dublin, California, covering California and the West.

And incredibly well regarded, if I can brag a little bit about them, not about me and their colleagues. In the industry and we really do try to lead when it comes to advocating for the independent power sector and doing what we think is right, not only for Calpine, but for the long-term viability of our sector.

So let me take a moment to introduce my colleagues who will be talking up here today. Yvonne McIntyre is our head lobbyist in Washington D.C. Yvonne was front and center 2 years ago when we had this meeting because as everyone might recall, the EPA initiatives and the Obama administration cap-and-trade initiatives were front and center. A little less so this time, but we'll talk about that later. Steve Schleimer is sitting next to Yvonne. Yvonne has been with us, by the way, for 9 years. Steve Schleimer, sitting next to Yvonne, has been with Calpine for 9 years as well. However, that was interrupted with about 3 years for Barclays in New York and returned to us about 2.5 years ago. And we're very glad to have Steve back. Steve covers the North region. He is the head of the Government & Regulatory Affairs group there, so he has responsibility for PJM, New York, New England and MISO.

Next to Steve is Mark Smith. Mark Smith knows everything there is to know about the California ISO. Mark covers the California ISO for us and is very intimately involved in the discussions there about the products that are being developed to respond to the need for flexibility to integrate the renewables that we've all heard about. Mark has been with us for 5 years.

Next to Mark is Randy Jones, and essentially, Mark's equivalent with ERCOT. Randy covers ERCOT, has been with Calpine, Randy, 9 years as well -- 13 years, sorry. And Randy is truly regarded as one of the authorities on the innerworkings at ERCOT and understanding how that ISO works.

So today, we are going to have a little bit of a panel-type approach rather than having each of my colleagues come up here individually. I'm going to ask them questions. But first, I wanted to set the table thematically for you all and tell you what it is that we are focusing on at a high level at Calpine. And many of it is -- much of it is what we've sort of alluded to in earlier discussions today. So it'll be going over some old territory, but I think it's good to see it in the right light.

And obviously, first and foremost, in all regulatory themes is making sure that the market structures are correct. Now in an ideal world, that's a centralized capacity market as far as we're concerned because centralized capacity markets are, we believe, what will assure long-term price stability and reliability.

But we also realize that it's an imperfect world and that in some instances, you may not be able to achieve a centralized capacity market. Obviously, we haven't yet in Texas or California, although we have in and PJM. And so in those markets, we've got to make sure that they're operating in a transparent way and a fair way that makes sure the pricing signals get passed through, such as in Texas, and in California, that make sure they fairly compensate the different classes of generation.

And so we work within the framework of what is there to refine it, to make it better, to make sure that we're getting the proper compensation and that the rules work. But we are also always pushing to move those 2 markets, in particular, toward a capacity market.

And continuing with the baseball analogies, I would say that our approach on market structure and rules is small ball. And small ball is where you get singles, you bunt the batter over, maybe steals a base and you score your runs one at a time. And that's what we're doing in the energy-only market in Texas, that's what we're doing in California. You're not necessarily swinging for the fences, although you would welcome the occasional home run.

So since -- over the last 2 years, we've had some nice bunts and singles, we've moved runners along, we scored some runs in those markets. And when we get to each of the markets, we'll talk about that progress.

The second bubble that you see there, non-competitive subsidized generation. In competitive markets, obviously, buyer side, the exercise of markets -- buyer side market power by the states is a major concern for us. This is best -- the best example is this is obviously what New Jersey and Maryland have done over the last year.

In the less competitive markets, where this comes in is with the integrated, the vertically integrated utilities conducting RFPs for new generation to meet their future needs. And in that case, we're there advocating for a fairness of that RFP process because, as you heard, John Adams and Ron Hall say a little earlier, we can build it better, cheaper and more efficiently than they can. And so we want to make sure that we're not being excluded from those markets.

So if you're thinking about this portion of our advocacy and our themes, this is the defense. And we're playing defense on these issues.

And then we move to demand response. We've talked about that several times this morning. And demand response obviously over the last 3 years or so has become a more significant factor. You heard Steve Pruett this morning talk about the potential positive impacts in PJM of demand response on pricing. But DR, as we've also all read about, has what we call a dark and a dirty side. And this goes back really to the fairness of rules. The dark side is where it's treated the same as generation, but it's getting paid more. And in effect, it's undermining the real long-term viability of the market because it's replacing newer, more efficient, cleaner generation. The dirty side is obviously the behind-the-meter, backup diesel generators that are being treated as DR and being given extensions by the EPA to operate for longer hours.

Right now, this is primarily a threat in the PJM market. And Steve Schleimer has led the charge there for us over the last couple of years on those different fronts. And so, Steve, why don't you, number one, just tell us what the fuss is all about and then tell us what you've been doing?

Steve Schleimer

Sure. So with DR, as we talked about earlier in PJM, for '15, '16, it's like 10% of PJM's peak. So it's a significant resource in the stack. And there's a couple of things that have been going on. First of all, we had a slide earlier that 25% of the DR is buying out of its position. So there's a question of how much is real and how much is actually going to show up. And it's causing PJM to really look seriously and define some of its rules. There's a couple of things they're doing this year that are brand new. They're requiring officers of DR companies to certify when they submit their offers that they have the ability and the intention to meet their obligations and that it's not just the financial trade. The other thing which is new is in 3 zones, in ATSI, PPL and Penn Elec., what PJM is going to do is they're going to look at all of the offers that are coming from the DR providers for new resources in those zones. And if the amount of -- and what they're going to do in those zones is they're going to go line by line and look at what the DR providers are providing. And if there are conflicting or 2 DR providers have provided the same kind of customers or the same customers on their list, they're going to require one of them to come back with a Letter of Intent from that customer. Because one of the things that PJM's a little bit concerned about is you may have 3 or 5 DR providers looking at a zone and if there's really only, say, 1,500 megawatts of DR there, you can have 3 DR providers each think they're going to get 1,000 megawatts of the market. And so there's going to be 3,000 megawatts of DR offered in for what's really 1,500 megawatts. So those are new rules that are going in place this year. The other thing that PJM is getting concerned about is the impact of so-called limited DR. The vast majority of DR can only be called on for 6 hours at a time up to 10 calls per year. And so they previously put limits on the amount of that limited product that they're buying. And this year, they're ratcheting it down even further. So I'd say what's going on in PJM with relation to DR is that we're kind of slowly moving, turning the supertanker. I mean, it's -- we're -- it's been a huge increase over the past 3 years. But I think it's starting to turn around a little bit because of -- it's such a big impact on the resource mix right now.

W. Thaddeus Miller

Steve, where are we in terms of challenges to the changes to the environmental rules that allow the dirty DR to have increased hours?

Steve Schleimer

Sure. So let's take PJM for example. We showed that 25% of the DR is buying out its position. Turns out that another 25% to 30% that's actually showing up is not really what people think of as DR, customers actually turn their lights off. It's backup diesel-fired generators. It's like 25%, 30% or so. And we've been involved in a proceeding, along with others at the EPA over the last several years to where the EPA has been examining whether to limit the amount of hours that diesel generators can operate. It originally was 15 hours, and they entered into a settlement with the DR providers to up that amount and there's been a settlement proceeding and discussions or an actual formal proceeding over the past couple of years. The EPA came out with a rule upping the number of hours to 100 hours per year. And which we just think is the complete wrong way to go. In fact, there was some testimony submitted in that proceeding that if the EPA did this, all of the benefits from New Jersey's head rules would get undone by the backup diesels being allowed to run more.

W. Thaddeus Miller

That goes, Steve, for the New Jersey environmental rule?

Steve Schleimer

Yes, the New Jersey environmental rule that's causing a lot of shutdown, including some of our units in May of 2015. So we're joining with some other generators, Sierra Club, EDS has also filed a challenge. The Delaware Department of Natural Resources is filing a challenge in federal court, as well as asking the EPA to reconsider its rules, and that's all currently pending.

W. Thaddeus Miller

Right. And just to be clear, we're knocking some aspects of DR here. But Calpine is not opposed to DR. We understand the place that DR and energy efficiency has in the energy future of this country. But what we're saying, once again, is that you have to have the right rules, and they have to be fair rules. Our friend, Yogi Berra, once said, "You better cut the pizza in 4 pieces because I'm not hungry enough to eat 6." So in this case, we kind of have the converse of that, where we have public policymakers through the FERC pushing DR, through the EPA, for whatever reason, pushing more pollution, ironically. And what they're saying is, "We have a pie and we're going to cut an unequal slice for these DR guys." And we're saying, "Look, fine for them to have a slice. We understand the important part it plays in our future. But you've got to do it under the right rules that make sense to everybody." So let's move to capacity markets. First, an overarching comment. There's been a lot of debate about capacity markets and how quickly are California and Texas going to move toward capacity markets. But there's a lot of positive things that have been going on out there, some connected to Texas and California, some not, that give us an inkling as to where the FERC is or the federal government is on this issue. And we've seen favorable decisions, very supportive of capacity markets in New York, ISO case, in New England, capacity case. We've seen NERC, which is under FERC, sending a letter to ERCOT, expressing concerns about reliability in Texas and wanting to know what they're going to do about it. And just recently, we saw a couple of -- last week, maybe 2 weeks -- no, last week, right, Mark? 2 weeks ago, a decision by FERC and what's called the FLRR decision, and Mark will go into this in a lot more detail later. But in that decision, they basically said, "California, you need to create adorable market-based structure that's going to assure that you have flexible and long-term capacity in your market." And some would argue maybe we're reading too much into that decision, but there was one partial dissent in that decision. And the partial dissent was Commissioner Clark who said, "Gee, I think we should -- I agree but I think we should give California a little bit more time to work it out itself." Which is a pretty telling comment. And as I said, we'll come back to this later and Mark will fill out the picture in California. My point is that I think we have a FERC that as a policy matter is going to continue to support a move towards capacity or capacity-like compensation in these markets. And the more heightened its reliability concern becomes, I think the more forceful it would become in helping these other -- nudging these other markets along. So let's talk about Texas, there seemed to be a lot of interest in Texas earlier today. And again, Mr. Berra comes into the picture, and he said one time when he was giving directions to Joe Garagiola how to get to his house. He said, "When you come to the fork in the road, take it." So we have energy market, we have capacity market, okay? And as we heard from others earlier today and myself now, we are pushing for a capacity market. But we know we're going to get a long way there going down the other fork in the world, too, because the changes that are being made to the energy-only market, we think will help scarcity pricing show through. And you saw from Steve's charts earlier, where we think that should be in a couple of years. So Randy, a lot of the discussion in Texas when it starts out is in the form of resource adequacy. And do we have enough of a reserve margin in Texas or do we need new generation? And from that discussion, all these others issues of energy-only versus capacity sort of progenate. So can you first tell us where we are in reserve margin and where we might be going on that?

Randy Jones

Yes, currently, Thad, stakeholders have established an annual planning reserve margin value of 13.75%. And that has a couple years of history behind it. Actually the Board of Directors set that a couple of years ago. And on a 2-year cycle, ERCOT executes what's called a LOLE study, Loss of Load Expectation, which is a long name for a study that really only looks at what kind of contingencies can you have in a system, what can the impact be on system loading and the target is you don't want to have more than one loss of load event in 10 years or 0.1 event per year. And one of the products, the outcomes of that study is what the acceptable reserve margin, annual planning reserve margin should be in order to achieve the 1 in 10 year event criteria. And a recent study completed by Echo International says that we need a 16.1% annual planning reserve margin. Now last week, stakeholders coalesced around that number, and it's going to be brought forth to the rest of the stakeholder food chain starting Friday with the wholesale market subcommittee. Now for the May CDR, Capacity Demand and Reserve report, that's the biannual report comes out in May and December, you're going to see numbers reflecting the 13.75% target. And all the other inputs are going to be basically the same. ERCOT staff didn't have enough time to really update the CDR process. But in the December CDR, you're going to see a call for 16.1% reserve margin in 2014, and I believe it's 15.2% that's called for in 2016.

W. Thaddeus Miller

So we're going to see, you think, an increase in the reserve margin that would apply to '15 and '16? Each one incrementally more than the other?

Randy Jones

Absolutely.

W. Thaddeus Miller

Okay. And so just quickly, Randy, how does the reserve margin work? Right now, as I understand, it's a reserve margin target as opposed to a reserve margin requirement?

Randy Jones

Great question. I characterize it as a target because that's exactly what it is. Right now, it has no teeth in it. If we dip below 13.75%, nothing happens. There's no triggering event. And the key question, and I think it's characterized great by your Yogi-ism, were at that fork in the road. How are we going to maintain resource adequacy in this region if we don't make the reserve requirement mandatory? So the commission has 2 threshold issues on their plate right now that up-to-date they haven't really dealt with. Our hope is they'll deal with them after the legislature leaves town and once we get another commissioner appointed. But those 2 threshold issues are should the reserve margin value be a mandatory value that triggers something, presumably a capacity market? And the commission signal right now, as you got 2 diametrically opposed commissioners when it comes to discussions on capacity markets. One doesn't want to make it mandatory, the other one is open to a lot of discussion on it, and it appears to me that she would probably go that direction. The other question, threshold question, from the commission is, do we stick with an energy-only construct, where generators only get paid when they generate power, they're sitting on sidelines and make 0 revenue, or should we go with some kind of centralized forward capacity construct that ensures reliability? So those are the 2 threshold questions for the commission, and we hope that after the legislature leaves, we'll -- they'll set a date for some open discussion about that and solve those for the stakeholders.

W. Thaddeus Miller

Okay. We're going to come back in a minute, Randy, to the scarcity pricing in the energy-only market, but to cap off the capacity market discussion, 2 years ago, when we spoke to all of you and in the year or 2 before that, we used to say, you couldn't even whisper the word capacity market in the hallways in Austin. It was anathema to folks in Texas. Well, over the last 2 years, that whisper has developed into, I think it's fair to characterize it as a robust dialogue about the need for this. And small but positive indications yesterday, we had the former chair of the Texas commission and former chair for state, unequivocally, it's time for a capacity market in Texas. During the last 3 months or 2 months -- 3 months, when the legislature has been in session, there was a great deal of concern about whether or not the legislature would be urged by folks to get involved in this debate. And either pass legislation that would prevent a capacity market from being implemented, because most folks believe that the PUC has clear authority to implement whatever market design it thinks is appropriate. Or on the other hand, to advocate for a capacity market. And the legislators have basically deferred to the commission. So we think that's a very responsible and important response. It sends a signal to the commission, don't politicize this, let's look at it in a rational, deliberate way and examine what the true benefits of going to a different market design than we currently have. Now once again, singles and bunts, moving the runners over, okay? We're not going to hit a home run today. All of this, though, we think, Randy, check me on this, I think will begin to unfold after this summer, more robustly. We will have the new commissioner appointed to the commissioner. As Randy said, we have 2 diametrically opposed commissioners on this issue. I don't want to mischaracterize the Chairman, but we think she's favorably inclined toward a capacity market. And we all know Commissioner Anderson is a strong believer in the energy-only market and doesn't think the capacity market is necessary. So the appointment by the governor will obviously be a very important factor here, as well as the discussion and the analysis that unfolds. But our every expectation, Randy, I think is that, that will unfold this fall after we get through the summer here in Texas.

Randy Jones

I think that's correct. I think the timing will be perfect and we need a full bench at the commission to really make a meaningful decision.

W. Thaddeus Miller

Okay. So now let's move back to the energy-only market as we have it today. Over the past couple of years and I don't think we need to go through the changes, there have been a number of changes, including the lifting of the system-wide offer cap to, I believe, it's $9,000 effective this June 1. And subsequent increases in each of the next couple of years.

Randy Jones

$5,000 this June.

W. Thaddeus Miller

$5,000 this June. And we've had other smaller changes, but there's a couple of other changes that are still being worked through in the ERCOT rule-making system that would impact scarcity pricing. You want to just go into those a little bit, Randy?

Randy Jones

Sure. There's a couple of stakeholder initiatives that strike directly at some of the shortfalls in the no-to market design. One is a rule change that will reduce the amount of unnecessary mitigation when there's transmission congestion in the system. The consensus of the stakeholders, including the independent market monitor, is that we've got excessive mitigation going on in the market, and we've had it since the market began. And this protocol revision will lessen that and obviously, that has a lot of meaning for generator revenues, who -- particularly those generators adjacent to regularly constrained transmission elements. The other initiative by stakeholders is a system change on ERCOT's market management systems that will actually reduce the amount of overdeployment of reg up. Recall that our regulation service in Texas is bifurcated. We have a reg up service and a reg down service. And when somebody gets reg-ed up, they're basically a price taker. And if you overdeploy regulation up, what you do is you steal the opportunity for other generators providing energy to just move up their offer curves, and so that artificially depresses prices. If you overdeploy reg up, you depress prices. And this system change request will help balance that out so that regulation deployments are minimized and the energy providing units, hopefully, will have higher pricing points.

W. Thaddeus Miller

Great. Now in -- still in the context of the energy-only market, we heard some questions this morning about what's called Option B in connection with the operating reserves curve to again help capacity -- scarcity pricing. Would you explain that and then tell us where that is in the...

Randy Jones

Yes, I'd love to. I've been in so many discussions over it. Option B was really offered by Professor Bill Hogan from Harvard with the help of the ERCOT operations and in market design staff. And I guess it's fair that I make it clear that Option B that you hear gets tossed around a lot in the market is not a long-term resource adequacy mechanism. What it is, is a tool to enhance scarcity pricing in real time. And there's a big distinction to be made there. Now from a Calpine standpoint, we're all in favor of improving the scarcity pricing. There have been a lot of stakeholder initiatives over last 2 or 3 years to improve scarcity pricing, which is extremely important in an energy-only market. Our market is so sensitive, revenue-wise, to scarcity events because we only get, as I said earlier, we only get paid for energy. The B+ option essentially looks at how the system is using operating reserves. And as you deplete those reserves, it applies an adder to the system clearing price in the form of a reliability penalty, if you will. And if so the -- if you're going to use operating reserves to serve energy, then real-time system price ought to reflect that, that depletion, because you're effectively in some small sense, threatening reliability in the future. And option B+, it looks like it has a lot of support. It is a complex methodology to put into play. We believe that it'll probably be implemented, if it's approved, through the stakeholder chain, by next summer, summer of '14. And I think it, as I've said, we are appreciative of anything that rationalizes scarcity pricing in this energy-only construct. It is not a substitute for a capacity market. But it's a necessary adjunct to a capacity market in all the LNP markets, and we look forward to its implementation.

W. Thaddeus Miller

Great. Thanks, Randy. Now let's move on from Texas to California. Of course, Yogi had a saying about this too. And he was playing left field in Yankee Stadium, and for those of you who have been to Yankee, I know it's sacrilege to say that now that Houston is in the American League, but we'll say it anyway in these hallowed halls. But he used to once in a while play left field when he was getting on in his career, and his knees couldn't hold up in the catching position. And as the sun would set, the shadow of the stadium would go over left field first. So there was sun in part of the stadium and not in part of -- other parts of the stadium. And so when somebody said to him, "What's it like to play left field?" He says, "It gets late early out there."

And it's not unlike what might be happening in California. We've been pounding the drum for several years. We could see with the renewable portfolio standards that California had set that flexibility and providing proper compensation for existing generation that could provide those flexibility attributes would be important to what California has been doing. We were largely ignored for a while. And so we embarked on a strategy over the last year to 18 months. And you're all familiar with what we did with the Sutter Plant. More quietly, what was going on behind the scenes in addition to Sutter, which we were using as a catalyst to get this discussion started more in earnest. We were drafting a white paper that proposed a format of the capacity, a centralized capacity market for California. And we shopped it with the players, some of the other players shopped their proposals with us. And that ultimately led to a summit that Mark will talk about.

In parallel with that summit, we had some action by the CAISO, that Mark will talk about. And then we have the SLR decision that we're talking about. So again, singles, bunts, moving the runner ahead, seems to be working in California. Is it going to be a quick homerun? No. But we are moving forward. The trend, in our view, is clear. The solution is not so clear yet, but we're moving forward.

So with that, Mark, let me ask you, this renewed energy, tell us a little bit more, flesh out some of the things that I've said, and then tell us where you think we're going next.

Mark Smith

Yes, thanks Thad. And thanks to all, for attending today. I look forward to our conversations later.

I would say, first and foremost, the dialogue in California has changed just as the dialogue in Texas has changed. Unfortunately, the dialogue in California continues to change on a daily basis, it seems. But let me summarize, before I go into any detail, by saying that we're cautiously optimistic that a multiyear forward procurement obligation that's attribute-based will emerge in the not too distant future. As Thad says, it may not occur as quickly as we want it to emerge, but our confidence is growing. And our confidence is really bolstered by 3 growing acknowledgments by entities within California and FERC itself as well. So these 3 things are the duck chart that you saw earlier, right, a growing recognition that with the increasing penetration of renewables, that energy margins are going to be reduced and that there's going to be reliability impacts that are created as a result of that. Those reliability impacts have been studied fairly substantially at this point. Calpine's been involved very directly in a lot of that analysis. The kinds of changes that you see might not be directly apparent from the duck chart though, are increased ramping requirements are -- both in the morning and in the afternoon, it's going to drive to -- machines that are capable of starting quickly, that can ramp quickly, that can cycle quickly. Not necessarily peakers, because our combined cycles are very good at doing that today, and can be tuned to be even better at that, if the right price signal is out there. So the RPS standards are driving some of that.

The other thing, of course, that we haven't talked a whole lot about today is the once-through cooling standards that the Water Control Board is establishing in California, which will require rather substantial compliance, potentially retirements of once-through cool units over the next 3 to 5 years now -- and beyond.

And what -- that brings sort of the second aspect, I think, that again, most parties in California are recognizing now in that with the retirements of those OTC units, most parties in California, including the PFC and the ISO, are recognizing that a more forward look is very, very necessary to be able to secure the grid. So these 2 things conspire together. We have decreasing flexibility from the once-through cooling units and increasing flexibility demands from the RPS.

The third thing as that I also mentioned is compensation problems that are becoming evident and may become more evident as margins decrease and decline. So I think all of those conspire to this concept that a multiyear forward procurement obligation that's attribute-based is probably where we're going to head over time.

W. Thaddeus Miller

And so Mark, just to summarize or maybe elaborate a little bit more in a couple of points. We had the FERC issue, the decision we talked about, which we think encourages California to start doing something. And FERC, in that decision said 120 days hence, we're going to have a FERC technical conference, which is an unusually long period of time ahead to say we're going to have a conference, which kind of signaled to us that they're saying to that PUC and to the CAISO and to others in California, "Show us what you're doing." What are they doing now? What's the next steps?

Mark Smith

Yes, so as a result of the summit that you talked about, there is this, I'll call it a fragile but tangible agreement to work together between the ISO and the CPUC. It's fragile, in part, because the CPUC is very interested in self-governance. They're very fearful of what they characterize as losing jurisdiction to FERC. But nonetheless, we have the sort of a fragile coalition right now. That coalition is, in some ways, there's a catalyst to that coalition through the FERC order. The FERC order, at least in one reading, suggests that a forward market, the significance of that order is twofold. The first significance, of course is that it creates that catalyst. The second is, that maybe that it creates an opportunity, if no action is taken to move the issue forward to FERC. So then as a result of those agreements, the ISO is currently developing a forward market proposal. What I do know about it is that it's 60 pages long. I don't know fully what it involves yet. It's being shopped selectively. So there is some progress at least from the ISO. We also understand the PUC staff is working on a companion set of revisions. And those 2 will come together, I would say, in the next 6 months. The nearest term thing that's going to happen is, I think an unprecedented step is that the PUC and the ISO have agreed on a set of flexibility attributes, so how much a particular unit or a particular technology would get credit for its flexibility. And it's likely, I would say, that those attributes will be enrolling into, I would say, the California's annual RA program, maybe as soon as '14 compliance year or '15 compliance year. So it's these actions that are taking place now.

W. Thaddeus Miller

Thank you, Mark. Good progress. So Steve, you have the centralized capacity market there in PJM. And that great -- Yogi Berra apparently wandered into philosophy at one point, and he said, "If the world were perfect, it wouldn't be." Well, the world is perfect. What's not perfect about it?

Steve Schleimer

So some days I wake up and I wish I had never heard of the term MOPR. And it's not just PJM, but all the eastern markets, New York, [indiscernible] and PJM. There's the key issue over the last couple of years has been some states are unhappy with the capacity markets for whatever reason, and they're going out and they're accruing very large subsidies to bring new resources online in order to crash the capacity markets. And we saw this in New Jersey and Maryland, most recently. Several years ago, it was -- it happened in Connecticut. There's ongoing issues in New York as well, as I think many of you are well aware. So in terms of what's going on, we had one iteration in PJM of a MOPR settlement. And it went through the last auction, and from our perspective, and from a lot of other folks in the market, it didn't work, because a lot of highly subsidized units got in, because of what was called the unit-specific showing. So we have a second round of a MOPR settlement currently sitting before FERC. And hopefully, we're expecting them to issue a decision in early May on that. That would basically move away from a unit-specific showing and would have standardized MOPR numbers for different projects and different technologies.

The other 2 things that are going on, is there's still active litigation in both New Jersey and Maryland, with relation to the long-term subsidy programs they have there. In Maryland, the hearings have concluded. Oral argument is next week, and we're actually, in that one, I think most folks are expecting a decision prior to the upcoming RPM auction in New Jersey. We're actually hearing they're going on this week as we speak. And actually after we get done, some of us are going to New Jersey, in fact in early tomorrow morning, to testify in that proceeding. And that one is a little less likely or less likely to wrap up before this upcoming auction.

W. Thaddeus Miller

So the MOPR changes that Steve alluded to that are before FERC, we expect a decision in May. And those will go some way toward preventing this kind of abusive market, of a buyer side market power by the states. And hopefully, we will have some decisions, which are on constitutional grounds as well, basically interstate commerce, violations of the interstate commerce clause.

Yvonne, you thought we forgot about you, didn't you? So I think we have about 7 or 8 minutes left. So our friend Yogi, I know you're probably getting sick of Yogi-isms by now, but we'll carry it through it all. He says, "I never blame myself when I'm not hitting. I blame the bat. And if it keeps it up, I change bats. After all, I know it's not me. It's not my fault that I'm not hitting. How can I get mad at myself?"

So the Obama administration tried cap and trade when they first came in. And now they've switched bats, kind of mid-term last term, but kind of only halfway, because it was influenced by the upcoming election for a second term. So they pulled back the reins a little bit. What can we look forward to now? And what I'd like to focus on initially is GHG.

Yvonne A. McIntyre

Well, today, the President released his budget for fiscal year 2014. And he reiterated his support for addressing climate change and reducing greenhouse gas emissions. He had mentioned it both during his inaugural address and in the state of the union. He did say his preference was for Congress to pass some type of legislation to address climate change, but I think we all know with the dysfunctionality of the Congress right now, that is not likely to happen. You keep hearing things like carbon tax and other ways to potentially address climate, but there's just really no appetite to do anything in Congress. And so, as he said, if Congress doesn't do it, then I will go forward doing it. We had EPA start moving on the issue with a proposed new source performance standard for new sources last year in March. They set the standard of 1,000 pounds per megawatt-hour for all new electricity-generating units. They have had that proposal out for quite some time. They got over 2 million comments on it. And so at this stage of the game, they were supposed to finalize that rule by April 13. That's not going to happen. We also have a transition right now, with the former EPA administrator, Lisa Jackson, stepped down. We have Gina McCarthy, who was up. She will have a confirmation hearing tomorrow. And so there's some thought that they are kind of holding back on finalizing that rule, so she has a little bit of a smooth confirmation process. There's also speculation though, that it has never been done before for any EPA, new source performance standard, where they set a standard, a single standard for all fuel sources. So there is speculation that they are potentially pulling back on their proposal, on what they'll come out with this is a different proposal or a final rule that gives a different standard for coal and one for gas.

W. Thaddeus Miller

So if do they do give different standards, Yvonne, just explain how it would work in terms of the emissions limits and whether or not there would be any trading.

Yvonne A. McIntyre

Well, so it would be expected, then, that they would raise the limit for coal. I mean there's this argument right now and they actually admitted it, you cannot build a coal plant, a conventional coal plant for 1,000 pounds per megawatt-hour. And you can only achieve that by attaching CCS to it. So whatever they end up coming out with, there's a higher standard for coal, lower standard for natural gas. Once that's done, they basically set a standard. They'll probably put together a model rule, but it's actually the states that implement that standard. So it will be up to states to kind of to decide just how they're going to meet that. Or if it's -- the EPA puts together a model rule, whether or not they just go ahead and take the model rule. They're not quite sure at this point if they can do trading. I mean again, they can offer that as a means of achieving the standard. There's been some kind of weariness of actually putting cap and trade programs into any EPA rules because it was shut down by the courts and the clean air mercury rule, and also with cross-state pollution laws, the pay rule before that. So what they can do again is to suggest that in a modeled rule, but then it will be up to the states to make that determination.

Once they're done with that, and actually this is all part of the settlement agreement that they were under, where they were supposed to do a standard for both new sources and existing sources. All through the last year, and it was a matter of upcoming elections, the EPA kept insisting they were not working on an existing rule standard. And they have really not kind of said anything about -- publicly about what they're going to do once they finalize the final rule but today, when EPA acting administrator Bob Perciasepe was rolling out the EPA budget, he did confirm that once they finish and finalize the new source rule, that they will start working on an existing source standard. Not anything that you're going to see before the end of the year, but he did commit that they're going to work on it.

W. Thaddeus Miller

So it's on the horizon?

Yvonne A. McIntyre

It is on the horizon.

W. Thaddeus Miller

It'd be probably before the next mid-term election?

Yvonne A. McIntyre

Uh-huh.

W. Thaddeus Miller

Okay. And tell us what's going on, just very briefly on some of the other -- the slate of environmental regulations that we know EPA has.

Yvonne A. McIntyre

The mercury and air toxic standards, they finalized that in December 2011. They ended up having to pull out the standard for new sources and they -- and to reconsider it. And they just finalized that rule on March 29, but being litigated, and so that's -- the arguments for that are coming up. And hopefully we'll have a decision by the end of this year. We've got the 316B, the cooling modern intake structure rule that is slated to be finalized by June of this year. Their big concern in the industry in the industry that it would require that they all move to using cooling towers instead of once-through cooling. Although now we're hearing that they may just have a requirement for advanced rings as the best technology available. So they'll be less, less stringent for the industry. The coal ash regulations, they put out a proposed -- 2 proposals, actually, in 2010, one to classify coal ash as a hazardous waste, and one classifying it as nonhazardous waste. Uproar from the industry because they use coal ash. They sell coal ash for beneficial use into stuff like wellbore and concrete. EPA really has not decided how they're going to move forward. They just recently put out a notice of debit availability where they just kind of relooked at some of data that's out there. They've also started an analysis of the health risk for beneficial reuse, so that will kind of inform how they move forward from that.

W. Thaddeus Miller

Okay. So I'm just going to digress for a moment because we talked about GHG. And of course, if we're going to talk about carbon schemes, we have to talk about what's going on in California and Steve, a bit in the mid-Atlantic or Northeast. Mark, just quickly, bring us up to date on AB 32. It was launched at the first part of this year. How has it gone, and what are the latest developments?

Mark Smith

It was launched, we've had a couple of auctions, I think that you're all pretty well aware of. The regulations are likely to be tweaked a little bit this year, but probably no major changes to the obligations that are created. As Steve indicated, we're seeing the prices roll through the real-time market. And probably the most significant thing that happened very recently, yesterday, as a matter of fact, is that the governor signed a letter that allows, doesn't necessarily ensure, but allows the connection of the California cap and trade system to Québec.

W. Thaddeus Miller

And what impact do we think or does the CARB think will -- that will have on price? Because I think Montreal is, Québec is tighter than California.

Mark Smith

CARB's position, I think is, that they see it as bullish for prices, slightly bullish for prices. And I think we see it about the same way.

W. Thaddeus Miller

Okay, great. And Steve, we had some changes or some re-enrollments or reupping of Reg G recently. Tell us about that.

Steve Schleimer

Sure. So Reg G has been actually going since early 2009. And they, under the rules, were required to relook at every 3 years. They did look at it. And I think most people know the program is way long. It was set at 160 million tons a year, which is way above what the regions' emissions are. So the states that are still participating in Reg G got together, and they reset the allowances for all the states. I think it added up to about 92 million tons, 91 million, 92 million tons. And actually, last Reg G auction was the first auction where it cleared above the minimum price. So there's still some approvals that need to get done in the various states. But it looks like it's going to be -- move forward at new levels.

W. Thaddeus Miller

Great. And Yvonne, now moving back to the federal front. We know that during the first Obama administration, Senator Bingaman, who is now retired, had pushed for a clean energy standard, a national clean energy standard, which didn't get off the ground. He's retired. I think we feel -- not comfortable, but we understand that it's not going to have any legs in the Congress. And so really, the only meaningful thing on that front is the PTCs, the tax credits that the administration might try to push in the direction of renewables. And we know, at the end of last year as part of the fiscal resolution that the current PTCs were extended for 1 year. On the other hand, we see the IMF coming out with a report last week saying, "Countries around the world, you got to stop subsidizing these renewables." It's economically not long-term viable, and we're seeing sort of an underswell attack on subsidies for renewables because of the long-term economic impacts. We see North Carolina looking to modify existing legislation on RPS. We see Ohio doing the same thing, and we see several other states doing it. Where are we going to go with the production tax credit?

Yvonne A. McIntyre

Well, in addition to extending the tax credit for 1 year, they also modified the eligibility for the tax credit. So initially, it was, you had to be placed in service by the end of 2013. Now you just have to commence construction by the end of 2013. So now, Congress is looking at going through broad tax reform. So it will be within that context where they decide what they may do with renewable energy tax credits going forward. I mean at the beginning of the year, and going up and then talking about PTCs and ITCs, we have a lot of pushback, particularly from on the Senate side and Republicans are saying, "You just got a 1-year extension. You just got this modification. Why are you going to come back to me? We don't want to hear about this anymore." This said, the House is pretty much adamantly against any types of subsidies for renewables. They don't want to see any picking winners and losers. But we hear this every year. We hear there's a lot of pushback. And then at end of the year, we usually get some kind of an extension. So what we are hearing, even among those that are supportive of renewable energy tax credits, they're saying that, if they go forward and do something, then it's going to be a short term and it's going to have a sunset date. We will do a 3-year, 3-, 5-year extension, and it's going to ratchet down each year. And at the end of that extension, that's it, you're not going to get anything else. So they're just at the beginning of the process of looking at tax reform. They're all saying that there's just no way they're going to be done with it before the end of the year. So right now, the betting is that they're not going to get -- have any kind of extension before the end of the year.

W. Thaddeus Miller

Okay. Great. Thanks, Yvonne. Well, that concludes the government and regulatory affairs portion. We're going to start with the next, and I think Bryan, we're going to take Q&A at end, right? Okay, so you have opportunity to ask Yvonne, Steve, Mark and Randy questions then, Thank you.

Zamir Rauf

Just for the record, we don't allow Yogi types anywhere near our financial numbers, especially the corporate models, so no Yogi-isms for me.

Look, it's getting towards the end of the day. I know some of you may be tired. You've had a lot of good information here, so I'm only going to take an hour. No, I'm just kidding. 15 minutes from me and then another 15 minutes of Q&A, and I think we'll wrap up over here.

So really, 2 key messages I think that you heard today, right? You've had a lot of good information. You've met what I would call some of the brightest of the brightest in the industry between the gov reg panel between commercial and between the power operations, really impressive group of people. But what everyone is striving to do is we are all committed, and as Jack mentioned earlier, we are committed to be good stewards of your capital by allocating in a disciplined way. And everything we do in the company is driven towards increasing EBITDA, increasing commodity margin, increasing free cash flow, free cash flow per share. And free cash flow per share is a metric that we use to evaluate all capital allocation decisions. So let me get to my first slide here. I know it's somewhere. There we go. Great.

So speaking of free cash flow per share, we've already on the finance side, delivered $0.08 a share, just by the 2, the refinancings and the repricings that we've recently done. And there's a lot more in terms of opportunity for the remainder of the year. We've got $1 billion on CCFC. We got over $1 billion on the corporate bonds. And then we've got the 10% of the senior secured notes that will also be coming up towards the end of year. So over $2.5 billion of opportunity over here. And by the way, I'd like to introduce Stacey Peterson, who's sitting there in the corner, talking to Andre. She's our new treasurer, and she's going to make sure that we capture all this value. So Stacey, please wave to the group so they all know who you are.

Turning to the next slide. We are really very different than any of our peers. And I don't even know if you can really say that we truly have any peers, because we are very unique as a company. But some other things, strong liquidity, right? And we talked about that earlier. I know Paul made a comment about the fact that we are starting with a lot of cash and we're ending with a lot of cash. But I do want to reiterate that we, and you've heard this today, we have growth opportunities. We are looking at them. We're going to be deploying capital there. We are not going to be reckless and declare an oversized stock buyback program. There's rating agency implications to that. There's all kinds of credit implications. We do it in a very steady, methodical way. As I mentioned earlier, as Jack mentioned, we did 300. We did 300. Now we've done 400. And we look at this as a continuous program, not as a onetime, announce a big program and sit back. And so I think you will see over time that this capital will get put to work.

Virtually no near-term maturities, so that's great. It's all opportunistic and then something we've talked about in the past. On the top right is, and I think all of you already know this. But we really don't have any environmental, either legacy or current environmental liabilities in the company. There's no decommissioning liability, no unfunded pension liabilities. We have NOLs that I'll show you on the next page. So we're not going to be a taxpayer for a long time, either on the, just on the regular operations side or when we sell assets. And something I'm not sure if we've really pointed out in the past, but we do have a lot of debt amortizations and cash sweeps within our project finance facilities and our corporate term loan. And you see, so 2017, we actually pay down $1 billion of debt. Now yes, Russell City comes online and we add that, but we're also bringing in EBITDA. But we are actually amortizing a significant amount of debt over time, and I think that's just important to keep in mind.

On the NOL slide, Slide 63, I mean I think the key message here is these NOLs are not expiring for a long time, and we have a lot of them. We have federal and we have state. And that's great because as we look at asset monetization, we don't have to pay taxes on that, and that's a huge benefit. If you look at the bottom right in the little blue box, we have saved $250 million of cash since 2010 from asset sales mainly, where we've not had to pay taxes. And so you think about our stock buyback program, part of it, 1/3 of it has been funded by NOLs, which is really tremendous value. And I think as you look forward, there could be a lot more value there. I threw out the tax bases of the Southeast fleet just to show you that if we were to sell an asset in the Southeast on average at $200 per kW, you can put your own sale price in there. That's is a lot of value. So these NOLs are much more valuable than just projecting how much net income do we have over the next 20 years. It's also the asset sales that may occur in the future.

Slide 64, some of you may have seen this before. But I just wanted to reiterate, and Jack made the point, we have a very disciplined process to allocate capital. All decisions are based off of one corporate model, whether we're buying back stock, whether it's investment in green field and brown field, whether we're looking at paying down debt, even if we were to look at the dividend. Everything will be based on this one model that is controlled by my organization, and it's a very robust process to put this model together. So I just wanted to make sure that everyone understood that we are very ethically clean in terms of comparing one investment to another. It is one corporate model, and everything is free cash flow per share, and it all gets weighed against the economics of buying back stock.

Towards the right, I mean these are some of the capital allocation choices that you can make. And we've always said that if there's a tie, the tie goes to EBITDA, the tie goes to growth. But what we really have here is a very balanced program. We've got growth. We've got -- we've done M&A. We were returning capital to shareholders. We're paying down debt. So it's all of the above.

Turning to the -- to Slide 65. This is summing up a little bit about what we've been saying today is everything we do, as I said, is driven towards increasing free cash flow per share. Our growth, our acquisition to monetizations, everything we're doing on the capital structure, it all adds to that bottom line. And it results in a very powerful message. If you look to the right on the chart, I mean that is a very strong growth, just taking the 15% to 20% growth rate that we've announced actually results in pretty high numbers. So there's a lot of potential here in terms of our free cash flow per share growth. I just wanted to make sure that people kind of understood how powerful this could really be, a very impressive growth in my opinion.

I mean the merits of free cash flow per share. We've talked about -- we introduced it a while back. We've talked about it. It's -- we've always looked at all of our investments this way internally, but we've just recently started introducing it to the street. But we really view it as cash earnings per share. And really, it's a proxy for earnings per share in our mind. And we sort of showed a little reconciliation towards the right on why we -- how we get to that point. But we really believe that free cash flow per share is represented in the total shareholder return. It your cash earnings per share that we're delivering to our shareholders. That's the way we think about it, and that's the way we believe you should think of it as well.

In closing, I'll just say that everything you've heard today I think really, really indicates that we are the premier operating company in the U.S. We are focused on delivering long-term shareholder value through continued growth, through operating excellence, through all of the efforts that all of the folks you've heard today are doing. And at the end of the day, we are allocating capital in a very disciplined manner for our shareholders. So I'm not going to take a whole lot more time. I'll leave some time here for Q&A. So I'll ask Jack, Jack Adams to step up here, and maybe we'll just get a few more questions in that Bryan may or may not moderate.

Jack A. Fusco

Before we kick this off, I just wanted to give my thanks to what I think is one of the best IR teams in at least in the sector. So Bryan Kimzey, Christine Parker, Dan -- where's -- is Dan in the room? Where are you, Dan? Dan? Stand up. Let's give them a nice round of applause.

Unknown Executive

Are you moderating?

Jack A. Fusco

Sure. So we'll open it up to Q&A now. It looks like we've got a couple of usual suspects already. And it looks like Ali beat Steven to the mic.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Two separate questions, one for Zamir. Zamir, when we listen to folks talk about the fundamental markets and the difference that we're seeing in the forward curves and how that's not being reflected in the market. I'm just trying to put it all together. From your perspective, how do you see the core earnings power of your company? Let's say the fundamentals were to be realized in the forward curves, which is the argument that you guys are making. Let's assume you're right. What is the core earnings power, the EBITDA power of this company in your mind?

Zamir Rauf

I mean, Ali, we haven't talked about it in terms of EBITDA. But I think if you look at it in terms of free cash flow per share, it is tremendous in my opinion. I think if the fundamentals play out over the long term, which we believe they will, we can well exceed what we put out as our target in terms of free cash flow per share.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Would you like to put at least some quantification around that? And what kind of upside would that be rough percentage-wise or otherwise? Some sense?

Zamir Rauf

Oh, I mean, look I don't know if I'm going to be giving any kind of guidance here by doing this, but it could definitely be noticeable. I don't know if any -- I don't know if anyone else in here wants to take it a step further.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Okay. I'll move to my second question. I'll talk to you offline. Jack, when you benchmark yourself and look at it whether it's your stock, your evaluation, your portfolio performance, who do you -- who are your peers? Who do you really benchmark against? And given that you don't really have much in terms of public IPPs out there, I'm just curious how you look at yourselves relative to who?

Jack A. Fusco

Okay, good. We actually have to dissect our different business processes to do an effective benchmarking. So if we're looking at human resources or productivity of the employee base or whatever, we have to actually take a variety of different sources. So when we look at safety, we look at industrial safety in America, right? Because our safety statistics are so much better than what you would see in EEI, right, for instance. I don't think -- maybe now -- well, there's not a pure entity that I would call a direct peer. In our proxy statement, there is a set of companies that we look at from a compensation perspective. But there's not one set of companies that have the same focus as we do. And I'd like to keep it extremely simple and be the best at what we can do. So I don't get too distracted by getting into other lines of business other than the wholesale power generation business, and I'm not sure there's anybody, other than maybe Dynegy now that has a pure of a focus left in the sector. Yes, Neel?

Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Going back to the last panel, the regulatory panel, so thoughts on the third commissioner in terms of timing of appointment and then what the Governor is ultimately looking to achieve in terms of that appointment. And then a clarification on the CDR as well. Is it your expectation when the CDR comes out in May that there aren't going to be significant changes in this upcoming May CDR? Those changes would likely be reflected in December?

Jack A. Fusco

So on the last part, the answer is yes, Neel. I think I'm turned on. On the -- what was the first question?

Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Third commissioner.

Jack A. Fusco

Yes, third commissioner. I can assure you the Governor hasn't taken me in in close confidence to discuss this. But we think timing of it, as best as we can we read the tea leaves, is that with the legislature in session, if he made the appointment during the session, then he would need to go through a confirmation process. And if I had to guess, I would say he doesn't want to go through the confirmation process because right now, the things are in the hands of the PUC, and you don't want to introduce it into the legislative arena. So I would say after the session ends, which is end of May, beginning of June, he will begin looking at it. I'm guessing they're doing legwork on identifying folks. The Lieutenant Governor, who obviously is somebody that would also have some input in the process, is a former IPP sector individual, can appreciate some of these issues. So I can't -- my crystal ball isn't good enough to tell you that it's going to be someone who passes the litmus test of endorsing capacity markets. But if I had to guess, I would guess it's someone who is seriously open minded and is going to seriously look at that. I mean take it -- again, speculation on my part, if you were the governor, you've appointed a Chairman, the Chairman from all indications supports a capacity market. Wouldn't make sense to appoint somebody to -- who is in a different position than your Chairman, but stranger things have happened in politics.

Unknown Attendee

[indiscernible]

Jack A. Fusco

In my assess -- I thought I answered yes to that. Yes, yes. So no changes until the next round. Steven?

Unknown Attendee

In the first quarter, you all bought back about I guess $58 million in stock. And I was just wondering if you could talk a little bit about sort of dynamics, drivers behind that amount. And the reason I'm asking is I'm thinking about if you annualize that, that would get you to about $240 million. And when I look at excess cash plus cash flow less growth that you already have, you'd have about $1.4 billion. So I'm sort of trying to track between cash that you've deployed to share buyback, annualized it would be about $240 million versus the much larger number. How should we think about flexibility in the size of share buyback? And how much can you really put to work by share buyback?

Zamir Rauf

Well, I think we can actually put a lot to work. I mean, we've got, as you know, we've got all this liquidity, and it's a matter of balancing that with the growth project. But we also continue to generate free cash. You look at some of the asset sales that we've done over the past year or 2, which has gone into -- you could look at that as going into stock buyback. So how much -- I mean you probably won't want to do the whole thing, but I think you can do a very large chunk of it for sure. We keep leverage under consideration, too, but leverage is now trending down. So as you announce smaller programs, EBITDA's increasing, leverage is going down, you can start off exponentially. Maybe not exponentially, but you can definitely increase that size as you go further down. You've already seen us do the 3, 3 and now it's 4. So there's been a change in the standard of how we move forward.

Jonathan Cohen - ISI Group Inc., Research Division

Jon Cohen, ISI. I'm sorry, did you have a follow-up?

Unknown Executive

Yes, Jon I think you can go next.

Jonathan Cohen - ISI Group Inc., Research Division

I just had a clarification on Page 10 in the front section. Is this essentially saying that current consensus is $30 million too low at the current forward curve?

Zamir Rauf

No. What that slide says is to get from '13, the midpoint of our '13 guidance to the '15 consensus, you only need $30 million more in market earnings, for lack of a better word, in market EBITDA, okay? And the forward curves today are significantly above that $30 million.

Jonathan Cohen - ISI Group Inc., Research Division

So they're not in consensus is now your fundamental view of the markets. It's...

Zamir Rauf

I'm sorry. The acoustics....

Jonathan Cohen - ISI Group Inc., Research Division

I know, it echoes a lot. The bar that says not in consensus.

Jack A. Fusco

The bar that says not in consensus.

Jonathan Cohen - ISI Group Inc., Research Division

Part of that is forward curves and part of that is your fundamental view of markets?

Jack A. Fusco

Exactly.

Jonathan Cohen - ISI Group Inc., Research Division

Okay. And then I just had a question about your -- your current free cash flow yield now is like 7.1%, which is lower than what your cost of debt is. How do you stomach buying back stock at such a low free cash flow yield? It would seem to me that it would be easy to build even at cost approaching forward replacement cost if your cost of debt -- sorry, your cost of capital were less than 7%?

Zamir Rauf

Look, I think as far as whether it's economic or not to build at the placement cost, that's not the only component that plays into that. But yes, we are very competitive in terms of new build and our raising debt, if we need to at those very low rates. But the stock buyback, if you just look at our view of our business going forward, the returns that we see buying back stock is vastly superior to certain other opportunities that we have. And if it's greater, then we invested in those higher opportunity project like we just announced today, some of the new ones and some of the existing ones going on. So it's definitely an advantage to us, but it's not -- low-cost debt is not the only factor that you consider when you're looking at new build at replacement cost.

Unknown Executive

Maybe to take another crack at it, Jon. The current free cash flow yield is one thing. The free cash flow yield growth rate, which we've stated is 15% to 20%, takes you to a very different place. And if you thought you were going to have a free cash flow, you had 7.1% flat. The 15% to 20% growth fundamentally changes the math, and that's the point we've been trying to connect.

Jonathan Cohen - ISI Group Inc., Research Division

The one point you've made, that is how you get to that free cash flow growth is very important. So if it's commodity price improvement, that's very good. If it's you deploying a lot of capital to build more EBITDA essentially, that's not as good for value. So understanding where the growth is coming from matters a lot to what the ultimate valuation is, I think. That's just a comment. A question on your new projects. There's one -- your PJM project is in the 2016 time line category. Should we infer from that, that is being bid into the '16, '17 auction?

Unknown Executive

As I said earlier, whether we bid on 2016 or not, we need to see some things. We'd like more clarity on how we think all seats in Maryland and New Jersey are going, and also if we get any more insight into what the ultimate MOPR rule will be. So it is possible and we are able physically given the time line to bid it in 2016, so it's a definite possibility. But we're looking to hopefully, even in the next 3 weeks, to get a lot more information.

Jonathan Cohen - ISI Group Inc., Research Division

Okay. So the outcome of the Maryland court case and whether FERC approves the MOPR.

Unknown Executive

In New Jersey and to the degree those aren't decided how we think they're trending given the best information we have at the time.

W. Thaddeus Miller

Maura?

Unknown Attendee

Just a couple of questions, 2 on Texas and then 1 comment to what John said. First, just wondering, we're in this fork on the road, where does DR play in the fork? Does it -- do we hit a tree called DR and ERCOT, or where are we on that? Second question, just in the overall ERCOT market and the TXU financial debacle/ bankruptcy. In terms of their hedging in the Texas market, has that had much of an impact at all? And my comment, if you're doing projects that are earning above the cost of capital and driving returns, I'd sure as heck rather have you do those kind of projects than praying for commodity prices. So a little comment to Jon. Sorry, Jon.

Unknown Executive

Well I'll take a cut at the first one, which is there's a visual of the fork in the road. And I think Maura just backed up 100 people in the intersection to put a tree there. So DR we don't think will be an issue in Texas. But Commissioner Anderson -- a tree in the road. DR will become part of the solution in Texas, let me be clear about that. Both of the commissioners in PUC have been very clear. And again one of them in the last day or two told people in this room that every resource will compete on an even playing field. So if there's a capacity market, DR will be able to participate. If there's an energy market, DR will be able to participate. So the idea of there being a bifurcated market where DR gets capacity payments and generation doesn't, that will not happen, and both commissioners have been very, very clear about the principles behind that, which is just really important to us. As Thad in his panel talked about, we're fine with the DR as long as it plays on a level playing field. And we think that's the philosophy here. On the second question, remind me, Maura, I'm sorry. You also said -- yes, yes. So Steve Pruett mentioned in his presentation that liquidity has been a lot lower the first part of this year Texas. Now you can list the issues: regulatory uncertainty, some of the big banks with major enforcement actions in the commodity trading arms, the largest generator in the state that might or might not have credit issues coming forward. So we don't know what the mix is, but I would say we sold significantly lower liquidity in the first quarter and that impacted the ability for players, including us to move in and out of positions. I would say, however, the market liquidity has picked back up for the summer and the balance of the year to near normal levels. So for whatever was causing the material liquidity in the market, at least for now it seems to have been fixed. So whether that had to do anything with the guys in Dallas or not, I don't know, but it was lower and things have picked back up at this point.

Unknown Executive

Keith Stanley?

Keith Stanley - Deutsche Bank AG, Research Division

If I could -- if you could provide maybe some more color on what you're seeing as far as acquisition opportunities, what you expect to see over the next few years, how that breaks down by region. And then also tying that into capital allocation and just -- I mean recent transactions have been largely, call it, in the 500 per kW range or lower depending on the market and tying that to your slide from last quarter where you saw, based on some of your metrics, that the stock at the time was trading the combined-cycle fleet at about 500 per kW. It's obviously higher analysis stock has risen. So how has that balance evolved as far as the economics of buying assets versus buying back the stock?

Unknown Executive

I'll take a cut at the first part of that. It would be my expectations that at these natural gas prices and overall power prices that you should expect there to be a lot of distressed entities in the space. So you're starting to -- you heard about TXU, Mission, Edison. Anybody with a solid fuel portfolio is under a lot of pressure right now, price pressure. So I would expect there to be a lot of churn and a lot of trading going on between assets in the sector. As you heard from me earlier, we -- as we look at the stuff, and we'll value it, you shouldn't expect us to take on any long-term liability for short-term gain. That's not what we're here about -- here for. It's not what I think is prudent use of your all's capital, and I'm very excited about our growth prospects. To hit Jon's comment a little more directly, we have a management team that has under-promised and over-delivered. And we expect to do that. There's not a lot of smoke and mirrors in our model. If we didn't think we can hit the 15% to 20% free cash flow per share CAGR growth, we would have never put it out there. And our models are pretty bland as far as what we've seen in commodity price appreciation, other than we have a fundamental view, and I think Steve Pruett did a nice job of describing where he thinks the market is short and why. You've heard there have been some changes in some of the rules. So if I -- I'll step back and say look at PJM. So PJM today is -- this summer is probably trading a little bit better than it was last summer. But demand response and some of the changes that Steve Schleimer talked about, Steve Pruett talked about, aren't being reflected in the curves. So you should expect us to hold out until we get a fair price. But our models are very conservative in what we're willing to promise you all.

Unknown Executive

Look, I'd just say this on the M&A. We've worked it a lot, right? We've sold more than we bought. We worked it a lot, and we've gotten 2 acquisitions in the last 4.5 years. And I can think of one, and I'm not going to tell you what it is, that I wish we had done, but we've done 2 of the 3 that I think made sense for us to do. And we'll continue to be disciplined. So what that means -- so we'll see what happens to asset values, and maybe there's some deals out there that make sense for us or maybe it looks like the last 4.5 years, and when we get 2 done in the 5 years or nothing. So we'll just continue to be disciplined.

Jack A. Fusco

The other thing I'll add is I don't feel a sense of urgency to have to spend your money. Seriously. I don't -- the sense of urgency I feel is internally focused. I think we have to get the Southeast straightened out. So to me that means we have to drive and continue to do 1 of 3 things, and that's either contract those assets, sell those assets or put a freakin' padlock on the gate and move them. So when somebody asks about turbines and how many did you have left, I have a lot of them left because I can think of some good ones that would back the truck up and load them on the back of the truck and take them to somewhere it's going to make some money for us. And it's doable. We do it -- we've done it multiple times already. So the difference -- and we've had to highlight this for some of the folks in California. This is not like a big coal plant. These are skid mounted gas turbines that you can truck or barge to new locations so.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Julien, UBS, just sort of a follow-up on all of this quickly. On the subject of M&A, how pure do you consider your story, and you want to be going forward, right? We've seen growth in the sector sort of elsewhere, right? Renewables, retail, DR, et cetera. Going forward, given the cash balance, given your patience, do you really want to be a gas generator a couple years from now, still? And then maybe the secondary aspect of that is scale has been really achieved. There's been a lot of mergers thus far. Where's next, right? Is Texas satiated, California satiated? Is -- do you want to double down on PJM?

Jack A. Fusco

Boy, that's a loaded questions right there. Look, we have the best asset portfolio of anybody in this space. And hopefully, with a 17 -- 15 or 17 speakers that we've had, you can see why I'm so excited about the team I have in place to actually drive -- continue to drive further value. Are there parts of the business or the value chain that I think we need to be bigger in? Of course, I do. I would love to see us get closer to some of the large C&I customers, right? I mean we have -- we're the probably one of the world's largest cogeneration companies and nobody knows about it. And with those 4 or 5 petrochemical expansions here in the ship channel, I hope we get a part of it, and we ought to be competitively going after that line of business. Demand response. Demand response is another form of generation, if you will. It just -- it's shutting down, shaving peak, for lack of a better word. And that ought to be an area that we should be able to participate in. So I think there's other avenues for Calpine to get involved in without having to do anything really transformational and deliver a lot of growth, both top line growth as well as bottom line growth.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

And maybe a quick follow-up, if you will. You've talked about interjecting your perspective on the market, right, and the comment about consensus expectations. As you look at transformative deals or what have you, how do you think about the market evolution? How does that play into your thought process? Where do you see the market going that would be attractive? Not to show your hands or anything.

Jack A. Fusco

The markets or the sector overall?

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

I suppose in this case the market. Like, which market would be appealing to get into at this point in time?

Jack A. Fusco

Well, okay. So from a capital allocation perspective, we have a very large concentration of our portfolio in California, so 39 plants in California. So I get more excited about growing in Texas and in PJM than I do about California just from a diversification of capital. So from that perspective, I would say we're more leaning towards the mid-Atlantic in the north than we are equal either in Texas or in California. You want to add to that?

Unknown Executive

No, I think that's good.

Unknown Executive

We'll take one final question up front here.

Paul B. Fremont - Jefferies & Company, Inc., Research Division

Paul Fremont with Jefferies.

Unknown Executive

Paul? Okay, and then one last one.

Paul B. Fremont - Jefferies & Company, Inc., Research Division

Sure. Coming out of bankruptcy, I think one of the consultants had indicated the NOL value or estimated the NOL value in the range of let's say $1 billion. You've got sort of $7 billion of possible NOLs that you've identified. Can you give a sense of how much of that you think you can monetize, some sense in terms of over what period of time? And do you -- I mean, should investors basically provide much credit beyond sort of the estimated net income over the next several years?

Zamir Rauf

Yes, I think, Paul, you'll find as we look at our model, that the NOLs get monetized sooner rather than later. I think you'll see that over the next 10 years, we'll probably be utilizing a huge chunk of them. And some of them will be just through our regular earnings. And to the extent that we sell assets, some of it will be through that. I think what people -- when a lot of people look at our NOLs, they kind of look at it over a 20-year period, which is great because they don't really expire for a long time. But as far as usage goes, we see the uses to be both front-loaded and back-end loaded.

Unknown Executive

All right. Last question?

Unknown Attendee

Two quick ones. What growth rate should we assume beyond 2015? On the free cash flow per share growth, what would be a good -- should we assume that in reverting back to GDP after 2015?

Unknown Executive

Yes, the 15% to 20% was our mid-range target. It wasn't a 2015 drop dead.

Unknown Attendee

Okay. So how long would that growth rate last for?

Unknown Executive

We haven't guided to the end date of that.

Unknown Attendee

And then my second question is in the 15% to 20%, what is the amount of share buyback that is assumed in there?

Zamir Rauf

We haven't looked at in terms of how much share buyback and how much EBITDA. We've looked at it in terms of what we can deliver. Some of it will be through earnings growth, some of it may be through refinancing, but there's probably some upside to the extent that we have all these opportunities on the financing side. The more we can capture, the more upside there'll be. And share buybacks will just add to that.

Unknown Executive

It's not premised on share buyback.

Unknown Executive

Yes, it's not.

Unknown Executive

Correct.

Unknown Executive

All right.

Jack A. Fusco

As far as questions, right, we're going to be here with you all. I think there's a reception that way, and so we'll be around, so feel free to stop us and ask us.

W. Bryan Kimzey

I've got a few closing remarks. So I'd like to thank everyone for your interest in Calpine and for joining us today. For those of you that joined late, an archived recording of the meeting will be made available for a limited time on our website. If you have any further questions, please don't hesitate to call Investor Relations. With that, the webcast portion of our Investor Day is now concluded.

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