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Executives

Bryan Kimzey – VP, IR

Jack Fusco - President, CEO

Thad Hill - EVP, COO

Zamir Rauf - EVP, CFO

Thad Miller - Chief Legal Officer

Analysts

Paul Fremont - Jefferies & Co., Inc.

Stephen Byrd - Morgan Stanley

Angie Storozynski - Macquarie Research

Dave Katz - JPMorgan

Julien Dumoulin-Smith - UBS Investment Research

Ameet Thakkar - Bank of America – Merrill Lynch

Brandon Blossman - Tudor Pickering Holt & Co.

Gregg Orrill - Barclays Capital

Ted Durbin - Goldman Sachs

Ali Agha - SunTrust Robinson Humphrey

James Dobson - Wunderlich Securities

Keith Stanley - Deutsche Bank

Calpine Corporation (CPN) Q4 2011 Earnings Call February 10, 2012 11:00 AM ET

Operator

Welcome to the Calpine Corporation Fourth Quarter and Full Year 2011 Investor Update Conference Call. My name is Mitchell and I will be your operator for today’s call. (Operator Instructions) Please note that this conference is being recorded. I will now turn the call over to the Vice President of Investor Relations, Mr. Bryan Kimzey. Mr. Kimzey, you may begin.

Bryan Kimzey

Thank you, operator, and good morning, everyone. I’d like to welcome you to Calpine’s investor update conference call covering our fourth quarter and full year 2011 results. Today’s call is being broadcast live over the phone and via webcast, which can be found on our website at www.calpine.com. You will find the access to the webcast and a copy of the accompanying presentation materials in the Investor Relations section of our website.

Joining me for this morning’s call are Jack Fusco, our President and Chief Executive Officer; Thad Hill, our Chief Operating Officer; and Zamir Rauf, our Chief Financial Officer. Thad Miller, our Chief Legal Officer is also with us to address any questions you may have on regulatory issues.

Before we begin the presentation, I encourage all listeners to review the Safe Harbor statement included on slide two of the presentation, which explains the risks of forward looking statements and the use of non-GAAP financial measures. For additional information, please refer to our 2011 annual report on Form 10-K which is now on file with the SEC. After our prepared remarks, we will open the lines for questions. In the interest of time, each caller will be allowed one question and one follow-up only.

I’ll now turn the call over to Jack to lead our presentation.

Jack Fusco

Thank you, Bryan and good morning everyone. Thank you for joining us and for your continued interest in Calpine. Traditionally our earnings calls focus heavily on a recap of historical performance and financial results. However, today we find ourselves in non-traditional times or what I would like to call, uncharted territory, especially given the extremely low natural gas price environment, resulting in high demand for our competitive fleet. I understand that investors are challenged to understand the opportunities that these market forces present to Calpine, especially when a sector overall is struggling.

So today, after we discuss a few of the 2011 highlights, we will spend much more time during our prepared remarks highlighting one of Calpine’s key differentiating factors, our resilience in an extremely low gas environment. What I like to do before setting the state for the conversation is to briefly summarize my take on 2011 and our positioning for 2012.

In 2011, we continued to deliver solid operating and financial performance and maintained our commitment to effective capital allocation. We produced over 94 billion kilowatt hours of electricity. We executed nearly 1400 megawatts of long-term power contracts and advanced on our strategic growth initiatives. Throughout the organization, we are continuing to position Calpine for the future.

With respect to the near term, I am pleased to announce that we are tightening our 2012 guidance range, including raising the bottom end. We now project adjusted EBITDA of $1.6 billion to $1.725 billion, and adjusted recurring free cash flow of $425 million to $550 million. We were able to narrow this range as a result of opportunistic hedging activity done in the fourth quarter of 2011 as well as a behaviour of our fleet under low gas price conditions, including benefits from coal to gas switching, which leads to the following slide.

Shifting fuel cost fundamentals is one of the four primary forces that are shaping the power sector today, and certainly among the most topical. Thinking back to 2008 when I joined Calpine, natural gas was viewed as a commodity with limited domestic supply whose prices were tied to oil, and coal was cheaper, more abundant and entirely domestic. Since then the tables have turned with shale discoveries that have provided us with an abundant, affordable domestic supply of natural gas.

Clearly, this paradigm shift has become even more pronounced in recent months as gases dropped below $3 an mmbtu and stayed there. I have asked Thad Hill to discuss in detail what this means to our market position later on in this call.

Meanwhile the power generation sector is also coming to grips with stricter environmental regulations and aging infrastructure with limited replacement capacity under construction and an overall return to fiscal discipline on behalf of tax payers and rate payers. Amid these forces, Calpine remains well positioned for the future of the industry.

Over the last three years, we have successfully stayed the course, effectively reengineered our internal organization and processes and repositioned our portfolio of plants and balance sheet to capitalize on future opportunities. The future is upon us.

The following slide provides a closer look at coal and gas price dynamics and how our fleet has responded under these conditions. As you can see from the chart on the left, natural gas prices began dropping below Eastern coal back in 2009, which corresponds to an uptick in capacity factors among our Southeast and Mid-Atlantic combined cycle fleet as shown in the chart on the right.

In our opinion, the overall effects of this dynamic were muted by long term rail and take or pay coal commodity contracts. As gas prices continued to decline in late 2011, we began to experience even higher utilization among our fleet. Since then we have seen natural gas prices decline to levels where it has displaced PRB coal generation and ERCOT such that our January 2012 capacity factors for our Texas fleet were 59% compared to 34% in January 2011, despite much milder weather.

While the margins on these incremental megawatt hours may be less attractive than the on-peak margins we traditionally earn, they are, by nature, incrementally positive. Or else, we simply would not run.

In sum, the current low natural gas price environment drives opportunity for the volume expansion among our fleet in the off-peak hours. Theoretically, we should see fewer starts and stops resulting in more baseload operation and less variable maintenance expense. This phenomenon has never existed for Calpine and quite frankly, we’re excited to verify our operational thesis. In other words, our efficient fleet continues to take market share from our competitors and should result in stronger financial performance.

Another opportunity for volume expansion over the more medium term comes from the retirement of aging uneconomic and environmentally obsolete equipment. The next slide shows the magnitude of expected retirements by several analysts, with which our estimates largely coincide. With only a small fraction of the replacement capacity currently under construction, particularly in markets where it’s needed most, there is additional opportunity for incremental generation from existing environmentally responsible, affordable generation like ours.

In addition to the Russell City and Los Esteros construction projects in California, we have continued to aggressively develop, permit and seek off-take contracts for a number of development sites in the Mid-Atlantic and Texas markets.

I will now turn the call over to Thad for a deeper dive into the natural gas perspective along with an overview of operations.

Thad Hill

Thank you, Jack. Good morning everyone. I am happy to be here today wrapping up our 2011 efforts and discussing the 2012 outlook. Before beginning my more normal quarterly updates and market observations, I want to pick up where Jack left off from the topic of gas price and the impact on the Calpine portfolio.

Over the last three years, we’ve worked very hard to make the message clear to investors that the economics of our fleet are not like many of our competitors. Calpine is not a simple synthetic long natural gas play, rather as gas prices drop, we actually can produce more megawatt hours and more commodity margin.

On the top left, although we could have used the Southeast or PJM, we show the Texas supply stack in February of 2012. As you can see from the arrows, many of the coal plants have shifted to the right from where they were a year ago while the gas plants have shifted to the left, given both the relative pricing of coal versus gas and the relative efficiency of modern gas combined cycle plants versus older steam turbine coal facilities. The result can be seen in the chart below.

Although on-peak, but coal and combined cycle gas units were run off-peak, market heat rates have risen steadily as gas plants like ours have displaced coal plants. And in fact, we have seen many of our competitors cycling their coal plants daily since the start of the year. This means that many of our combined cycles are now running baseload not only in Texas but also the East. And it prevents wear and tear on our machines.

The chart on the top right demonstrates the broader relationship between gas price and market heat rates. Although market heat rates are certainly impacted by other factors, primarily supply and demand fundamentals or the impacts of regulatory changes, they are also impacted by gas price. As we’ve just shown, lower gas prices can lead to higher off-peak market heat rates as gas is being used to displace coal. But they can also lead to higher market heat rates during the on-peak hours because generators have fixed charges they incur for starting and running plants. And with the lower gas price, a higher market heat rate is required to cover this cost.

In this chart, we show PJM West, and although the slope of this curve will vary by market, the trend is generally consistent. How this dynamic plays out across our fleet is shown in the graph in the lower right. This graph shows our modeling of the slope of heat rate changes for corresponding opposite move of $1 in gas price at any given gas price. As you can see, our fleet responds well under these low gas price conditions. The net impacts that we actually get effectively shorter gas, how does gas prices fall at these low levels? Again, the big picture is we’re far less negatively exposed to lower gas prices than any of our peers. And in fact, Calpine’s clean, modern and flexible fleet can benefit from lower gas prices.

On the next slide, our standard hedge disclosures reveal a bit more detail about our gas and heat rate positions. For those of you that are new to following Calpine, we update this page quarterly along with corresponding modeling tips in the appendix. To help our investors to maintain models, understand how our hedge positions impact for commodity and margins under different scenarios, we are happy to spend as much time with investors as you would like to run how to interpret these disclosures. So please feel free to call our investor relations department.

For the sake of this call, I will point out two more thematic points. First, 2012 was 14 pecentage points more hedged since our third quarter call. As summer prices begin to run, we did take additional megawatts off the table. Secondly, on our effective overall gas position, we were short in 2012, in 2013, we’re closer to neutral, although with regulatory issues and other macro factors that are certainly not exact, and in 2014, still have link, some hedges right at before the recent gas price drop.

The charts on the right hand side of the page show the isolated impact of a $1 move in gas or a 500 point move in market heat rate, each of which is treated as an independent variable in this respective chart. As we discussed on the previous slide, there is often an inverse relationship were offset between gas prices and market heat rates, the extent of which varies over time and by region.

The next slide shows our 2011 operating statistics. On safety we have continued to operate well by any objective measure. We continue to hold ourselves to higher standard. Last year across our fleet, we experienced six lost time accidents. We believe that with the ongoing focus and effort, we can improve upon this. One is too many.

In that vein, special mention to the current and former employees of Agnews power plant in California, tomorrow we will be celebrating 20 years of operation without a single lost time incident. Congratulations to you all.

In the lower left, you can see that our fleet met our stated forced outage factor goal of 2.5% with a very strong third and fourth quarter despite the historic freeze events in Texas early last February. The power operations team, including the plants, our turbine maintenance group and our engineering department have successfully continued to demonstrate that we are among the best operators of industrial gas turbines in the world and that we can do so while watching the cost line very carefully.

On the cost front, we have delivered similarly impressive results. Normally recurring plant operating expenses in our legacy fleet, we’re moving the impact in the Mid-Atlantic acquisition were down more than $30 million year over year, while the costs for the Mid-Atlantic have improved nearly 50% compared to their 2009 levels under prior ownership.

Exemplifying this kind of excellent operational performance in the lower right is on the rule of our individual plants they were exceptional on both safety and availability. The volumes by region for 2011 in the upper right complete the operations story. Zamir will cover them in more detail later in the call.

On the next slide, we share some market observations beginning with ERCOT, including the current supply demand fundamentals and importantly, some of the market reforms that are underway. There is no secret that in the summer of 2011, ERCOT almost ran out of power supply to match demand, due in part to absolutely brutal summer weather but also due in part to the fact that investment in new power plants has not kept up with demand growth, as Texas accelerated out of the grave recession, had a pace ahead of other markets.

As you know, there is an energy only market in Texas, which means that you are only paid when you generate versus compensated for being available and you don’t run as is the case in many other capacity based markets. Energy only markets are the clear and continuing choice of Texas regulators and that they can’t work but only if there is the available for true scarcity pricing to result when things get tight, thankfully the public utility commission understands this, so they’ve begun taking steps to ensure markets are fair and that they will work.

In the upper left, you can see that the forecast for reserved margins has been dropping for the last year and a half, and it’s now materially below the targeted minimum beginning in 2014. For informational value, you can also see the blue bar which is where the actual operating margin was in the summer of 2011 before any actual planned outages.

Weather normalization is not a science. But we interpret this information that even in normalized weather the market will be increasingly tighter over the next couple of years. And There is a trend of how weather continues they will be very tight.

At the bottom left is the map which shows why the investment is not occurred today. The solid blue line shows the floor market heat rates in Texas, although 2012 is inexplicably above 2013 and ‘14, the overall curve is well above where it was a year ago, which is good news. That said, the straight line across the page show you what you must believe out of market heat rates for given gas price unit to make a new investment in the combined cycle. So currently if someone were to use market curves to finance and build a new gas plant, they would have to belief 2012 natural gas prices would average around $5.50 and that these economics would continue into the future.

As the gas price expectation drops, the market heat rate curve required to make an investment increases. So what will it take for the blue line to continue to rise to incent new investment in an even lower gas price? It will require that the market continues to believe the scarcity will be reflected in the power price when it occurs.

On the right hand side of this page are the initiatives that are working their way through the stakeholder process at ERCOT. Taken together, had they been placed in 2011, they would have resulted in a much higher price. Ultimately this shows a firm commitment to the market by Texas regulators, a commitment that will mean first, higher prices that we feel are not currently reflected in the forward curves, and ultimately, new investment.

Finally, on the next slide, I would like to address the most important dynamics facing California and PJM, two more of our key markets. First in California, many of you have heard that there are proceedings at both the California public utility commission and the California ISO to construct a Sutter, Sutter Energy Center in Yuba City. Simply put, in California if there is not a capacity contract and the asset is merchant, the energy market does not provide sufficient margin to fully cover plant’s operating costs, including major maintenance.

Fortunately, we have been very successful keeping almost all of our facilities continually contracted. But Sutter is not contracted and we will not operate it at loss. So we have instructed the authorities to that with all the change in the short term economic outlook we will be ceasing commercial operations at that facility. In a very positive step for our California business, both the ISO and the public utility commission have recognized that the absence of fair compensation for existing assets is a default that needs immediate attention. The most flexible assets that are needed the most given the increasing amounts of new intermediate resources being brought online may not be receiving sufficient compensation.

Both the ISO and public utility commission has suggested shorter term mechanisms to keep the Sutter plant active while work continues around the long-term structural fix for the state. We are hopeful that a solution will be reached for Sutter and in any event, it is clear Sutter is acted as a catalyst for longer term more fundamental market reform to occur.

Moving across the continent to PJM, the headlines are little different. As jack discussed, coal plant retirement announcements are considerable and we will be spending some time in our new earnings call to talk about the upcoming auction. But in addition to the EPA turbine activity, there is also a local New Jersey rule which could have a meaningful impact. In 2015, New Jersey will implement a higher energy to man-day or head rule which will require either an installations of Nox controls on the closure of around 4000 megawatts of generation.

While it does stand the impacts some of our smaller older generating units, overall it is another positive sign that taken together with the new MATS rule and the elimination of double counting by demand response providers it portends an ongoing positive operating environment for Mid-Atlantic fleet.

Also in the news in PJM is the Maryland proposal to pursue an out of market capacity procurement effort. They have proposed to require the state utilities to enter into contracts with generation developers for new generation which can negatively impact existing generation units, much of New Jersey is done.

We believe similarly the challenges of involving federal pre-emption in a potential violation of the interstate commercial quash that led a federal district court to decide here the case against New Jersey could be raised against Maryland. As a result, we think it’s unlikely that the Maryland process would continue in anything closer to its current scale or proposed timing.

Thank you for your time and attention. With that, I will turn it over to Zamir.

Zamir Rauf

Thank you, Thad and good morning everyone. As you have already heard from Jack this morning, we are narrowing our guidance range due primarily to the positive effects of the coal to gas switching we are experiencing at low gas prices as well as the incremental hedging we were able to complete during the fourth quarter when we saw heat rates rally.

We are now projecting adjusted EBITDA of $1600 million to $1,725 million, and adjusted recurring free cash flow of $425 million to $550 million in 2012. I will come back to this shortly but first, let’s take a look at some of our notable accomplishments of 2011.

We had a strong year in 2011, and adjusted EBITDA increased to $1,726 million from a $1,712 million in 2010. For the fourth quarter of 2011, adjusted EBITDA of $379 million was roughly comparable to $386 million in the prior year’s fourth quarter. In addition to meeting our financial guidance and achieving key operating metrics, we also completed our $7 billion corporate refinancing initiative and embarked upon a $300 million share repurchase program, which as of the end of this week, we have repurchased approximately 9 million shares totaling approximately $124 million.

We also continued to enhance our liquidity, increased the CDHI LC facility by $100 million, further simplified our capital structure by unwinding a couple of small legacy complex financings and secured very attractive construction and permanent financing for our California growth projects. As such, we’ve continued to make great progress on the key initiatives you heard me talk about in the past.

Moving to the following slide, we can take a closer look at the financial performance for the fourth quarter year over year. Across the board, our plants incurred lower operating expense in the fourth quarter of 2011 as we continued our focus on operating efficiencies and incurred fewer outages this year.

In Texas, positive contributions from hedges and an increase in off-peak volumes helped drive our year over year improvement. We further benefited from the addition of our York Energy Center in the north region which achieved commercial operations in March of 2011. These benefits were partially offset by the impact from the sale of our Colorado plants in the west region in December of 2010 and lower capacity payments at our Mid-Atlantic fleet in the north region, as a result of lower PJM capacity market rates that took effect in June of 2011.

Within the north region, you will notice that our generation was up significantly during the fourth quarter of 2011 without a corresponding change in adjusted EBITDA. Aside from the capacity payment impact I just mentioned, the weather in our north region was significantly milder during the fourth quarter of 2011 compared to 2010.

In summary, the low gas price environment at higher availability factor of our fleet enabled us to generate additional volume in 2011, compensating for the milder temperatures.

On the next slide, we show a similar comparative for the full year 2011 results against 2010. Overall adjusted EBITDA increased to $1,726 million compared to 1,712 million last year. The largest driver of our year over year improvement came from a full year of operations of our Mid-Atlantic fleet compared to only a half year in 2010. This increase was partially offset by the absence of our Colorado plants in 2011 compared to nearly a full year of operations in 2010.

Elsewhere extreme hydro projects in the west and the winter freeze in Texas unfavorably impacted 2011 results compared to the prior year. As a fleet, we benefitted from lower plant operating expenses as I previous mentioned. Overall, we continue to demonstrate solid financial performance in 2011 and successfully delivered on our targets.

Turning our focus to 2012, the following slide has been updated to reflect our outlook on capital allocation and reinforces the fact that we have and will continue to build substantial excess cash this year and beyond. The cash sources bar on the left reflects our updated range for adjusted recurring free cash flow of $425 million to $550 million.

Moving across the chart, we continue to show approximately $150 million of payments on our legacy interest rate swaps which, as you may remember, substantially expire this year. And we continue to evaluate the option of paying them off early. We have also updated the amounts of share repurchases to reflect the remaining balance on our $300 million as of December 31, 2011.

Please note that since then, we have repurchased approximately 6 million of additional shares. Lastly, the amount on the Riverside reflects public filings made by our customer that indicates a purchase price of $392 million.

With all these changes, we are now projecting our excess cash balance at the end of the year to be between $700 million and $1.2 billion. Generating this level of excess cash means that we will maintain our ability to pursue a disciplined yet comprehensive approach to capital allocation.

As such, we are able to pursue development opportunities, such as the expansion opportunities in Texas and the potential greenfield opportunity in PJM that you’ve heard us discuss and which we continue to advance. At the same time, we are able to actively observe all the M&A activity within our industry and are positioned to respond quickly if the right prospects were to come our way.

Meanwhile, we continue to delever as the amortizations and cash flow sweeps inherent in some of our financings continue to pay down debt. In sum, our capital allocation decisions are not dictated to us. We do not have any lingering environmental liabilities to fund and we do not have any material environmental compliance expenditures to make. We have a robust list of alternatives to consider in putting our capital to work. And these alternatives are not mutually exclusive in light of the substantial levels of excess cash we expect to deliver this year and beyond.

You should expect us to continue putting our capital to work in a disciplined fashion that seeks to provide the highest return to our shareholders. With that, I thank you again for your time today and will now turn the call back to Jack for his closing remarks.

Jack Fusco

Thank you, Zamir. In closing, we remain steadfastly focused on being the premier independent power producer and are concentrating our efforts around that objective. I want to personally thank the employees of Calpine for having the trust in me during these past three years and tolerating the amount of change that I have asked of you, to position us for the future.

This slide shows our goals for 2012. We have not waivered since last year. The only change I will mention is that we have reordered the list, moving enhancing shareholder value up a notch. Thanks to the flexibility afforded by Zamir and his team’s efforts through 2011 and with the strength of our projected cash flows, this is a fitting move. We are on track, well positioned heading into this year and beyond.

Thank you for your time. And operator, we will now open the line for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Paul Fremont from Jefferies. Please go ahead.

Paul Fremont - Jefferies & Co., Inc.

Really two questions; one, with respect to the increase in the hedge percent from the third quarter, I think at the time of the third quarter conference call, you guys had said that you were purposefully going long the Texas summer, should we assume now that Texas is mostly hedged? And it looks like hedge price number actually went down $1 from where it was in the third quarter for 2012.

Thad Hill

Hey Paul, it’s Thad. We are not going to give, that’s obviously commercial since they are better hedged positioned by region. And I will just say this, should there be meaningful upside in Texas in summer, we plan to participate in it. As far as the dollar on the – lower dollar on the graph, there has been – our hedging is typically done in the current market at prices that are below the all-in number, because the all-in number also includes long-term life of asset, PPAs and the like. So typically you will see that number drop as you start hedging with more market based rates versus the long-term PPA rate. So that phenomenon has happened over the last several years. Nothing different there.

Paul Fremont - Jefferies & Co., Inc.

Second question, you talked in your press release about insurance recoveries as being part of the driver for lower O&M. Can you quantify what the contribution of insurance recoveries were to the quarter?

Thad Hill

Sure. There are insurance recoveries that offset both costs incurred during the year as well as some costs that were incurred in the prior year, which is really I think probably the right question. And so as a round number, $10 million might be a reasonable place to be.

Paul Fremont - Jefferies & Co., Inc.

And that’s the delta quarter over quarter?

Thad Hill

No, that would be the amount of insurance proceeds that were recognized in 2011 that were not for events that occurred in 2011.

Operator

Our next question comes from Stephen Byrd from Morgan Stanley. Please go ahead.

Stephen Byrd - Morgan Stanley

On page nine, you talked about the impacts of the heat rate as gas prices continued to fall. And there was an interesting nuance there that I think was not well appreciated, and that relates as gas prices fall, a lot of coal and other units will have more start-up costs as they essentially cycle on and off more often. Can you talk a little bit more about that dynamic? How meaningful has that been? Is that in your view fully playing out, or is that more of that to come in the future?

Thad Hill

I think it’s meaningful. And just to correct, it is coal units but it’s also gas units as well. You have fixed start-up charges, you also have all-in, that’s fixed when you actually run your units. And if gas price is lower, then heat rates have to be higher to allow you to recover that. The best way to show it is on the graph on the upper right hand of that page is actually on-peak PJM data, right. And so there is also some coal to gas switching mix. And so a market like Texas the curve would probably show you little better.

But as you work your way down, you will get higher heat rates to offset that. The off-peak was, just to correct, stronger on a percentage basis as you can see in the chart on the left. But it is material on peak as well.

Operator

Our next question comes from Angie Storozynski from Macquarie. Please go ahead.

Angie Storozynski - Macquarie Research

I look through your presentation and to be very honest, I thought it was a bit tamed, even how low natural gas prices are and I would have expected probably more disclosure on your capacity factors during January for a number of your plants. Could you comment – you made some comments about Texas. How about Southeast, or PJM?

Jack Fusco

Angie, this is Jack. It’s only February. There is a lot of year left. And we are on uncharted territory. So while we are very optimistic about what this year can bring, I still want to under-promise and over-deliver for all of you. With all that said, answer directly the different capacity factors for the different regions.

Thad Hill

As Jack mentioned, in January, I think the number was, and I don’t have them right here, 59% versus 34% last year, capacity factor in Texas. I don’t have those specific number right in front of me. But in that order of magnitude, would be similar more in PJM. Our combined cycles in PJM and our combined cycles in Texas are, they are in baseloads since the start of the year.

In the Southeast, it’s a little more of a mixed bag, anywhere you are in the Southeast. But those capacity factor will be up as well. They just won’t be up at the same order of magnitude as we are seeing in Texas and PJM.

Jack Fusco

And we’re excited about California because the snow pack in northern California is about 35% in normal, which should be real positive for our fleet in the summer.

Angie Storozynski - Macquarie Research

Okay. So if that’s the case, why would you lower the high end of guidance?

Jack Fusco

Again, we are trying to be conservative and realistic. This is a very difficult market right now. Even with gas prices have dropped, real power prices have come down also even though the heat rates have expanded. So we don’t want to get into a situation, Angie, where we are having to guide people down. So I feel very comfortable with our guidance ranges that we’ve given all of you. And I feel comfortable that, they are achievable this point and it’s early in the year. But you should stay tuned, as things get to be clearer. I feel very good about our positioning in this market.

Angie Storozynski - Macquarie Research

Okay. The last question from us. Would you bid those expansions of your assets in PJM into the upcoming auction?

Thad Hill

Angie, we are working through one project in particularly that we think has great promise. And we are not prepared at this point to talk in more detail about it. There is a lot of work going on.

Operator

Our next question comes from Dave Katz from JPMorgan. Please go ahead.

Dave Katz – JPMorgan

Hi, I had two questions actually. The first was to deal with the PJM capacity auctions. Would you be able to detail the megawatts that you guys have sold for in the ‘14, ‘15 as kind of the guide of what you might have in ‘15, ‘16?

Thad Hill

The real question in ’15, ’16 for us given our fleet is going to be the units in New Jersey that are impacted by that HEDD rule. Overall there are about 4000 megawatts in New Jersey, we represent about 500 of those 4000 megawatts in New Jersey, our units that are impacted by this rule. Just to put that in perspective for a minute, we got about 5000 megawatts in PJM. So it’s 500 megawatts over 5000.

We are working through that, some of those units from no brainers where we expect the retrofit to make a lot of sense. Others could be a little more challenged and again, we expect to – at first quarter call, which is (indiscernible) often talk about it but we wouldn’t expect any difference with the possible exception of – thinking through how we are going to supply (ph) from the megawatts in New Jersey.

Jack Fusco

And these are – all of the units that are impacted are peaking units. They generate very little energy in their age – the older fleet that we inherited with the Conectiv acquisition.

Dave Katz – JPMorgan

Okay, but to clarify in ‘14 and ’15, what was the amount that was sold?

Thad Hill

I don’t have it right here with me. It’s going to be – in the east 4000 and then we also have Zion probably 4000 megawatts because we do not have control of our – at this time of our own York plant which is under contract with another customer. And then we also have our Zion plant out in Chicago area. And that is in the RTO pricing. And again, part of that is under contract and part of that we bid. But we can get that for a follow-up.

Dave Katz – JPMorgan

Okay. Thank you. And then on the slide which details natural gas price sensitivity, it moved substantially from the amounts that you guys have put in third quarter, specifically on the downside exposure, it lessens substantially. I was curious what was behind that lessening?

Thad Hill

And this could stack a little bit to a question asked a couple of times ago about our portfolio behaves at lower gas price and what the upside is. Obviously there is hedging transactions we do, but I think I mentioned on the third quarter call that we were roughly neutral on natural gas prices. As gas price drops, we actually begin to get shorter. So as you look at the page before that, you can actually see what happens to the gas heat rate relationship as gas price rose.

Jack Fusco

Gas price lowers, volume increases. And the hedge disclosures base off of what we expect our volume to be. So those numbers are going to change.

Thad Hill

As gas price drops, we will end up with more volume, which will therefore increase. So you should see gas price moves, how much of our portfolio produces will change as well and that will impact the disclosure.

Operator

Our next question comes from Julien Dumoulin-Smith from UBS.

Julien Dumoulin-Smith - UBS Investment Research

Hey, first with regards to Sutter in California, just wanted to kind of get a sense of timing, perhaps what your expectations are. I know that there was sort of a CPM settlement conference ongoing. How does that relate to Sutter, what’s the timing and does this have a precedence for other plants in California should you be able to get compensation here?

Jack Fusco

Julien, I want to thank you for asking that question. I am going to ask Thad Miller to answer that for us here.

Thad Miller

So Julien, in connection with Sutter there is two different proceedings working their way forward in parallel. One is as you alluded to at FERC, and that’s an application by the California ISO to use its CPM mechanism to compensate Sutter for a one-year period on the basis that it meets Sutter in ’17. In parallel with that proceeding, the PUC in California has put on its calendar for the ’15 a resolution that would require the utilities, the IOUs in California to negotiate with us for capacity from that plant.

We think that probably that PUC will decide on whether or not to pass that resolution before the FERC action comes to fruition or meaningful next steps. If the outcome at the PUC meeting next week is positive, then we would expect to enter negotiations with the IOUs on capacity payments for Sutter, CPM payments for Sutter, for the coming year. Just to take a step back, if we look at this overall in the context of the California market, this is skirmish or battle in the context of a longer-term -- war is probably too much of a strong term but a line of progression towards a more robust long term market. As you know the big issue in California is when the plants come off, their initial 10-year contracts getting those plants picked up in the market, they are relatively new plants, there is no need to build newer plants to replace those plants. But the market structure in California doesn’t yet address that.

So the CPM ruling at FERC last year was the first step in giving California one tool to address it and the long term procurement and RA proceedings at the PUC which are separate and apart from the resolution I referred to, are two more initiatives that are underway. And we would expect action to recur in those two proceedings during the course of this year – early next year latest.

Julien Dumoulin-Smith - UBS Investment Research

Great. Maybe a quick follow up to that, to what extent do you have other assets in California that aren’t contracted similar to Sutter, and I understand if that’s sensitive?

Thad Hill

We will get into that. And I think the simple way to think about it is most of our other assets are contracted. Those contracts do have end dates on them and do roll off. And so generally speaking, market reform in California is very important to us. We feel very positive about the direction that this is going. And there is no more I would say immediacy tomorrow but we have time to get the market working the right way. And we think the portions are shaping up that way.

Julien Dumoulin-Smith - UBS Investment Research

And then secondly, with regards to ERCOT and developments there, you’ve kind of alluded to some of the various reforms contemplated. What do you see the timeline as being for the balance of these reforms out there? I mean, is there a laundry list of them?

Thad Hill

We think all of this, or most of it anyway, we will get done within the next 60 to 90 days.

Julien Dumoulin-Smith - UBS Investment Research

Great. Anything in particular you are kind of eyeing in terms of the list that as particularly impactful?

Thad Hill

Probably the most impactful was month’s end reserve that is already occurred which is very, very helpful. As we said, even with that alone, if we were to have a repeat of 2011 but for that would have had a material higher impact on power prices. So not that we’d get a repeat of 2011 but it would have. And so we are very pleased and think the regulators are taking the resource adequacy issue seriously.

Julien Dumoulin-Smith - UBS Investment Research

And then maybe just a last quick follow up on what was asked before around the HEDD rule in New Jersey, you talk about 4 gigawatts, do you have any kind of sense as to in your mind, what seems more certain to shut in kind of a total gigawatt framework?

Thad Hill

No, I don’t want to go there. We represent only 1/8 of that and I mentioned some of our units have been no brainers and others are different. But I think there are other larger players that will have a better perspective given the size of their fleet than we own.

Operator

Our next question comes from Ameet Thakkar from Merrill Lynch.

Ameet Thakkar - Bank of America Merrill Lynch

Most of my questions have been asked and answered, but just – appreciate the additional, I guess, information on some of the off-peak in the coal to gas switching. But Jack, you mentioned that one of the benefits of this is from kind of less starts and stops for your assets. And there is a benefit on a variable O&M. And if I look at like off-peak power prices in Texas, they are in the teens in the off-peak hours right now, and PJM they are in 20s. Is that really the lion’s share of the – that kind of the bottom line and the (indiscernible) EBITDA is coming from O&M versus energy margin?

Jack Fusco

Well, I will handle part of the question, then let me turn it over to Thad for the other part. The first half, Ameet, is we historically have had 300 starts and stops per engine on our equipment. And every hour, every start penalizes you approximately 30 hours and it depends on the technology and manufacturer. But so it moves up your major maintenance cost and quite frankly the thermal shock and stresses and strain damage your equipment more frequently, the city driving versus highway driving on an automobile, right. So ideally, you want to keep the units running and for us, we aren’t going to take a loss, so we would shut down.

So now that the off-peak hours are still positive, they are low but they are still positive for us. It makes more sense for us to keep the equipment on and ensure that it’s going to be there for the next day, for the on-peak hours, than it is to take that extra cycle. And we should periodically see our costs decrease over time. But I will turn it over to Thad.

Thad Hill

Jack is exactly right. Most of the cost in the starting and stopping will show up ultimately in our major maintenance and CapEx versus in the short term variable margins which flow through the EBITDA in the current year. Probably we look at what happened in December, as an example, we believe we take up margin mid single digit dollars per megawatt hour incremental margin in both PJM and Texas. Texas a little lower than PJM will be little higher. So the low dollar is there with margin in addition to the variable component.

Ameet Thakkar - Bank of America Merrill Lynch

And then just as a quick follow up to I guess the prior questions on some of the market reforms in ERCOT. Just again, just trying to get a sense for I guess what kind of the potential impact is to your fleet. If you go back in time that and think about where your delta hedge position was last year, and these reforms were in place, do you have a rough approximation on how that would have kind of helped the bottom line last year?

Thad Hill

I am not going to talk about what could have been or not with our fleet. I will try and answer the question this way. We look at the rules that are effective so far without incorporating some of the lines that are not yet effective, we think that prices could have been higher mid single digit dollars per megawatt hour and across the entire on-peak over the calendar year.

Operator

Our next question comes from Brandon Blossman from Tudor Pickering Holt.

Brandon Blossman - Tudor Pickering Holt & Co.

Let’s see. Coal to gas competition, just a little bit more detail and probably the big picture view, given you look at the dispatch curve and where you ran, say over the last four months, theoretically should the capacity factors have been even higher?

Thad Hill

No, I don’t think so. These are very loose rules of thumb. But gas drops below $4 in the eastern interconnect, you start to see the switching begin to kick in. When gas drops below the $3 in Texas, we’ve started to see the switching kick in. Now obviously all that can change, depending on what happens to underlying coal prices or rail rates and all that, these are very loose rules of thumb. And when you look at that, and we look at kind of how the market evolve, we think things would behave as we would have expected.

Jack Fusco

Other than the Southeast, Brandon, I will just add – I think the Southeast we should have seen more generation coming out of the Southeast here for where gas prices were.

Brandon Blossman - Tudor Pickering Holt & Co.

That was probably my follow on is, looks like Southeast is kept at least short term and capacity factors, I think that you had mentioned long term rail contracts and take or pay coal contracts, is that the factor that you should see contributing to that?

Thad Hill

Yeah, I think that’s true. I think you also can contrast behaviour there as well. I mean, some of our competitors here in Texas they are – you can tell they are making absolutely sure they’re making all the right short term decisions around economics. And those decisions may occur at slightly slower pace than other parts of the country.

Brandon Blossman - Tudor Pickering Holt & Co.

Secondly, can you probably contrast the forward price curve on power with the originated market? What do you think as far as the dynamic in the originated market, whatever you’re comfortable commenting on but probably most interested in the Southeast on that one?

Thad Hill

Sure, no, there we’re seeing prices above the forward curve. Now when people contract with us in that part of the world, there is also of course typically the (indiscernible) type contract, they have also regulatory capacity needs with their public utility commissions. So as we’ve – I believe it’s got before, typically in a contract, when we get into throughout the Southeast, when we enter the contract at prices that are above the absorbable forward market.

Operator

Our next question comes from Gregg Orrill from Barclays Capital.

Gregg Orrill - Barclays Capital

Zamir touched on a couple of potential uses of the excess cash in your capital allocation outlook. In terms of the way you are thinking about it, is there sort of a base case that you are considering and then there would be other alternatives just looking to explore some of the options there a little bit more?

Zamir Rauf

So Gregg, no, there is not a base case. Obviously when you look at deploying your capital you look at transactions that are most equity to your shareholders. And that includes development opportunities that we’ve talked about. Those are somewhat limited in nature that potential acquisitions, but those few and far between and then of course the stock buyback and I think you look at – we just look across the board, and we look at the fact that we are building a lot of cash and we are not going to be sitting on cash, or just holding cash forever. So we will put our capital to work and whether that means more stock buyback or whether it means more internal growth, it all depends on what returns are highest to the shareholders. Rest assured, we will be putting our capital to work over time here.

Operator

Our next question comes from Ted Durbin from Goldman Sachs.

Ted Durbin - Goldman Sachs

I was actually just curious little bit more on your press release on demand response in some of the diesel generators. Is this any indication you have on concerns about DR in the upcoming auction itself or is it just more of a policy matter that you are trying to highlight?

Jack Fusco

It’s definitely more of a policy matter that we are trying to highlight. And the rules of the game there were not laid out to be fair and competitive. And I will let Thad Miller to chime in.

Thad Miller

And what it basically goes to is that behind the meter resources that are being put in to the demand resource pool and essentially what you have is a bunch of emergency back up generators on the tops of building some cities and in rural areas that are environmentally uncontrolled. And so for us knowing that we have always thematically pushed the environmentally responsible approach, it doesn’t make sense that on the hottest days of the year that these emergency generators would be turned on and spilling uncontrolled emissions into the air, and yet paid the same as new clean generation resources that we would be willing to build or utilize the unused portion of our capacity to serve the needs of that market.

And so we thought that this proposed settlement between EPA and demand response providers is inappropriate compromise which is why we have challenged it and even if the settlement goes odd what the settlement requires is rules making by the EPA and we will of course actively participate in that.

Ted Durbin - Goldman Sachs

And then my other question was just maybe just update us on the Geysers where you are on commercial contract potentially for expansion there.

Thad Hill

As we – prior disclosed we do have – now have our permits that are required for the Geysers, and we are actively marketing the potential expansion outside the Geysers, and there is really no update on whether or not we will be successful on that effort at this point.

Operator

Our next question comes from Ali Agha from SunTrust.

Ali Agha - SunTrust Robinson Humphrey

Just putting the whole coal to gas switching and in another context, looking at it from a different perspective, you folks produced just over 94 million megawatt hours in ’11. What should we assume should be the production given the dynamics that you have laid out in ’12? In other words, what is embedded in that guidance you have given us?

Jack Fusco

Yeah, Ali, we have not given any volume guidance at all, and I don’t think we are prepared to do that on this call either. And I know that’s probably frustrating to you all but I think it’s still early days and but we are excited at what we are seeing. I mean, you all can make your own estimates with where daily curves are claring.

Thad Hill

I think the most important thing to add to Jack’s comment is that coal to gas switching is and has provided incremental megawatt hours. It does mean more commodity margin but first and foremost, it means that on a rolling gas price world, we did it very differently than our peers and it is in essence a very real forward gas price.

Jack Fusco

It’s the portfolio capacity factors in the low 40% range, we could easily technically double that.

Ali Agha - SunTrust Robinson Humphrey

And to that point, I guess another question, Jack, I mean you look at your portfolio and you look at the markets and you mentioned that these are unusual market conditions. And despite those positive benefits, your ’12 numbers are obviously suggesting flat to down versus ’11. So if you think about market recovery and markets getting more normalized kind of spreads et cetera, can you just remind us again what is the EBITDA potential that your portfolio should be generating assuming more normalized market conditions?

Jack Fusco

That was a very good try, Ali, but we haven’t given any open EBITDA type guidance. I mean Thad had shown some charts of where we think the markets need to go to incentivize new build, so you can extrapolate from those charts of where market heat rates need to go at whatever your view of natural gas prices are to figure out what the potential could actually generate.

Zamir Rauf

Ali, our cost structure is pretty fixed, we don’t need to double our workforce to double our generation. So we definitely got that benefit.

Thad Hill

The only kind of hint or maybe allowing people to do a little math, I would just point to slide 12 in Texas. Sparks in Texas, and I will use 2013 at this point are probably $15 to $20 a megawatt hour, in order to incent new build, you need to believe over time, you are going to get $30 a megawatt hour. And that, which is a very large percentage increase, obviously gets levered up on the fixed cost structure Zamir mentioned. So I think there is a lot of upside should markets begin to pay for new generation.

Operator

Our next question comes from James Dobson from Wunderlich Securities.

James Dobson - Wunderlich Securities

Wanted to go back and get my head around the start/stop issue, a little bit more maybe sort of quantitatively, I think you mentioned in response to another question that I think you meant an average unit had about 300 starts stops in the year. Although I appreciate it’s early in the year, if we saw what we are seeing right now continue, what would that start stop number be?

Thad Hill

I don’t miss that. I don’t have the exact number up for you. We are seeing a lot more megawatt hours and lots here starts and stops. And let me just describe the dynamic, maybe a little bit more. Because of the rules Jack mentioned, every start counts as 30 hours, it depends on how the units run but this was a potential for pushing out some major maintenance and CapEX over time. But some units it could actually pull it in because they are running more, in places like the Southeast, places like Texas where we are stopping and starting everyday, it should be pushing it out.

So we don’t quite yet have a handle on this other than I would tell you, our plant manners (ph) are more comfortable with these machines without having to bring them up and down every day. And they are very thankful for new dynamic.

James Dobson - Wunderlich Securities

But if we are trying to get our head around sort of the impact to your, appreciate it’s early but I think you just mentioned some will be drawn out, some will be sort of brought in, should we think about it as roughly neutral, sort of Jack’s comments earlier in the presentation, seem to suggest this was a benefit. But I sort of hear you saying it’s less of a benefit. Thad, can I just have a little clarity?

Thad Hill

I will tell you, when you do the forma major maintenance starts, stops hours on that, it is neutral to modestly positive. When you talk to our plant managers, it is all positive.

James Dobson - Wunderlich Securities

And then Zamir, I think you addressed this implicitly but you financing plans for balance of ’12?

Zamir Rauf

Yeah, there is really not that much left to do. We have done all the major stuff, there is a little bit on the fringes. We have a few project financing that we could get some benefit from. We are looking at maybe this further simplification, and we did – we took out a couple of complex, very busy type of financings that have been put in place years ago. Just last year. And so I think it’s just around the fringes, but there is nothing large. The majority of this is done, the maturities are pushed, there is nothing coming due. Now it’s just making things little more efficient and maybe releasing some additional restricted cash so that we have more cash on our capital allocation bucket to put to work.

Operator

Our last question comes from Keith Stanley from Deutsche Bank. Please go ahead.

Keith Stanley - Deutsche Bank

Could you just provide an update in California, how much of your carbon exposure at this point for 2013 and ’14 as hedged? And then also it seems there has been – that there are some details that still need to be worked out as it relates to the ability to pass through carbon costs on some of the long-term contracts? So how confident are you at this point that that will be resolved favorably and what are some of the milestones to watch there?

Jack Fusco

Keith, you don’t really want us to disclose commercially sensitive data on the amount of carbon that we’ve actually hedged in ’13 and ’14, do you? Is that the first half of that question?

Keith Stanley - Deutsche Bank

Well, at the analyst day, you had provided a sense that you were fully hedged for 2012 before cap-and-trade got postponed a year. So I thought it was possible.

Jack Fusco

No, we are not going to go there, Keith. And then on the second part, I will let Thad – do you remember the question?

Thad Hill

No, can you repeat the second part of the question?

Keith Stanley - Deutsche Bank

The details, it seems some details still need to be worked as to the ability to pass through the carbon cost on the long term contracts, I guess, how confident are you guys on that and are there some milestones to watch?

Thad Hill

Yes, so they are both the rules and there is also the impact of the builds – the contracts with our customers. I would just simply leave it as we don’t view ourselves as having any material risk to long term contract exposure, we are having to buy carbon and not being able to pass through. It won’t be material for us however the rules come out.

Keith Stanley - Deutsche Bank

And when do you expect it to be finalized some of those rules around that?

Jack Fusco

I think over the course of this year and into early next year, Keith.

Operator

Thank you. At this time, I would now like to turn the call over to Mr. Bryan Kimzey for any closing remarks.

Bryan Kimzey

I would like to thank everyone for participating in our call today. For those of that joined late, an archived recording of the call will be made available for a limited time on our website. If you have any further questions, please don’t hesitate to call us at investor relations. Thanks again for your interest in Calpine Corporation.

Operator

Thank you ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.

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