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Executives

W. Bryan Kimzey - Vice President of Investor Relations

Jack A. Fusco - Chief Executive Officer, President and Director

John B. Hill - Chief Operating Officer and Executive Vice President

Zamir Rauf - Chief Financial Officer and Executive Vice President

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

Analysts

Angie Storozynski - Macquarie Research

Keith Stanley - Deutsche Bank AG, Research Division

Neil Mehta - Goldman Sachs Group Inc., Research Division

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

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

Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Brian Chin - Citigroup Inc, Research Division

Gregg Orrill - Barclays Capital, Research Division

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

James L. Dobson - Wunderlich Securities Inc., Research Division

Jonathan Cohen - ISI Group Inc., Research Division

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Calpine (CPN) Q3 2012 Earnings Call November 6, 2012 11:00 AM ET

Operator

Good morning, and welcome to the Calpine Corporation Third Quarter 2012 Earnings Release Conference. My name is Brandon, and I will be the operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Bryan Kimzey. You may begin, sir.

W. Bryan Kimzey

Thank you, operator, and good morning, everyone. I'd like to welcome you to Calpine's investor update conference call covering our third quarter 2012 results and 2013 guidance.

Today's call is being broadcast live over the phone and via webcast which can be found on our website at www.calpine.com. You will find the access to the webcast and a copy of the accompanying presentation materials in the Investor Relations section of our website. Joining me for this morning's call are Jack Fusco, our President and Chief Executive Officer; Thad Hill, our Chief Operating Officer; and Zamir Rauf, our Chief Financial Officer. Thad Miller, our Chief Legal Officer, is also with us to address any questions you may have on legal and regulatory issues.

Before we begin the presentation, I encourage all listeners to review the Safe Harbor statement included on Slide 2 of the presentation, which explains the risks of forward-looking statements and the use of non-GAAP financial measures. For additional information, please refer to our most recent SEC filings, which are on file with the SEC and on Calpine's website. Additionally, we would like to advise you that statements made during this call are made as of this date, and listeners to any replay should understand that the passage of time, by itself, will diminish the quality of these statements.

After our prepared remarks, we'll open the lines for questions. [Operator Instructions]

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

Jack A. Fusco

Thank you, Bryan, and thank you, everyone, for your continued interest in Calpine. Before we begin, I want to extend my sympathies to those who are still dealing with the effects of Hurricane Sandy from last week, and my thanks go out to our plant personnel who worked tirelessly and proactively to ensure that our people stayed safe and that we were able to operate under unprecedented conditions in the affected areas.

During the third quarter, Calpine continued to deliver record operating results. Our versatile fleet, generated nearly 90 million megawatt-hours through the first 9 months of 2012, 31% more compared to last year, while holding plant operating expenses essentially flat. Our outstanding performance was due in large part to our intense focus on operational excellence and preventive maintenance, which yielded our best year-to-date forced outage factor and starting reliability on record. In addition, as you will note from our financial results, our commercial optimization efforts delivered significant upside this quarter, particularly within our Texas segment. Finally, our plant personnel achieved our best year-to-date safety performance on record.

As a result of all of these efforts, 2012 is shaping up to be a good year for Calpine and our shareholders. At this stage, we are narrowing the range, while maintaining the midpoint of our full year 2012 adjusted EBITDA and adjusted recurring free cash flow guidance. Meanwhile, on the capital allocation front, we made significant progress this quarter across-the-board, including acquisitions, divestitures, contracts, development and share repurchases. Most notable, we recently announced the acquisition of the Bosque plant in Texas and today, are announcing the sale of our Broad River plant in South Carolina. I'll speak more about this acquisition and divestiture activity in a moment. But in the context of capital allocation would say that I expect us to continue to reposition our asset base and our share count over the next few years, with an eye towards ensuring that our portfolio is in line with our shareholders' long-term interest.

One of the metrics that I rely on to make capital allocation decisions is adjusted recurring free cash flow per share, which I believe is the best tool for measuring return on investment for Calpine. As you will note, our 2013 adjusted recurring free cash flow per share guidance shows a 25% increase from midpoint to midpoint compared to 2012. While we are excited about our prospects in 2013, we thought it would also be important to share with you our target for growing adjusted recurring free cash flow per share by 15% to 20%, compounded annually.

Our internal plans and capital allocation decisions will be centered around the achievement of this goal. With respect to our 2013 guidance, we project adjusted EBITDA of $1.76 billion to $1.96 billion and adjusted recurring free cash flow of $575 million to $775 million. This guidance reflects our pending M&A activity, including the sale of Broad River, which we estimate would have contributed approximately $40 million next year, such that without the transaction, our adjusted EBITDA range would have been $1.8 billion to $2 billion.

Turning to the following slide. I'd like to highlight the strategic rationale behind the realignment and capital redeployment progress we've made this quarter. As we've previously stated, a key element of our near-term strategy is to monetize noncore investments, while redeploying capital into core markets, both at attractive prices. Today's announcement of the divestiture of Broad River, combined with the recently announced acquisition of Bosque, exemplifies that strategy. Our sale of Broad River, a contracted peaking plant with limited upside in the highly regulated Southeast allows us to redeploy capital into Bosque, a merchant combined cycle plant in Texas, where we have a bullish view of market fundamentals and the potential for structural market reform. And since we have recently paid off the project debt associated with Broad River through our latest refinancings, we will be able to redeploy substantially all of the sale proceeds into Bosque, which we expect to close this week.

As a reminder, we are also scheduled to close, by year-end, on the divestiture of our Riverside plant, a contracted combined cycle in Wisconsin. The contract at Riverside was set to expire in May 2013 and our customer exercised their option to buy the plant and add it to the state-regulated rate base. We believe that the completion of the Broad River and Riverside sales, along with our strong free cash flow projections, will leave us with ample excess cash to deploy as part of our continuous capital allocation process.

Finally, on the following slide, I would like to briefly update you on the status of wholesale competitive power markets in each of our core regions. It's hard to believe, but for an industry labeled as deregulated, it certainly seems that regulatory matters are among the most topical and most pressing in our space. As you probably have noted, we have become a strong advocate of competitive power market reforms to ensure reliable, cost-effective electric energy, while maintaining a level playing field between incumbent utilities, intermittent renewables and independent wholesale generators.

At the federal level, FERC continues its efforts to promote fair, interstate commerce and prevent buyer-side market power. Meanwhile, Calpine fully supports the EPA in its efforts to enforce the Clean Air and Clean Water Acts, for which environmental control technologies have been available for decades. We are also optimistic that the EPA will work to restrict the exportation of behind-the-meter uncontrolled diesel generation as an acceptable source of demand response.

In Texas, where the market is tightening due to increased electric demand, we are encouraged by the regulators' willingness to consider structural market reforms to send a stable price signal to the market in order to incentivize investment in new generation. However, while we are pleased with the recent increase in the price caps, since theoretically, this should result in an increase in price volatility, whereby existing generators like Calpine should see a benefit, this alone is not enough to ensure long-term electric reliability for the Texas economy. I've asked Thad Hill to speak in more detail on this topic in a moment.

Meanwhile, in PJM, we are committed to maintaining the integrity of competitive interstate power markets without state interference through subsidies for their favored projects. We are optimistic that PJM will move forward with its proposed revisions to the Minimum Offer Price Rule in order to ensure state subsidized plants do not negatively impact bid prices in future auctions. Additionally, we are optimistic on our legal challenges against those projects that were awarded contracts in the past.

In California, efforts are underway in multiple regulatory proceedings. We are pursuing the addition of new products that compensate flexible fossil generation that is needed to provide reliability in an increasingly intermittent renewable market. In addition, we are actively pursuing regulations that would prohibit discrimination between existing and new power plants.

Our message is consistent across all of the wholesale markets. We are pursuing market-based solutions that permit efficient and transparent price discovery, provide forward price signals for new investment and are nondiscriminatory towards existing generators.

With that, I will now hand it over to Thad Hill for a review of our operations and our market outlook.

John B. Hill

Thank you, Jack, and good morning to all of you on the call. I'm happy to be here today with the third quarter operational and commercial update. I'll start with the more traditional operations and hedge disclosures, and then wrap up with updates on a couple of topics that we're getting many questions around, Texas and the Southeast.

On operations, we've turned in another strong quarter on the relevant dimensions of safety, availability and cost. Just recently, Jack, the operations team and I visited our Westbrook Plant in Portland, Maine, where we celebrated 10 years without a lost-time accident with the plant employees. They're not the only plant to reach this significant achievement. Others having reached this milestone this year are listed on the slide. I mention this because, although we are working hard to ensure from a corporate perspective that our employees have access to the best programs, safety equipment and training, safety begins and ends with the people in the field. Our heartfelt congratulations to these teams and to the rest of our employees that are taking ground every day on making Calpine the safest possible place to work.

Our commercial availability again was very high. Our forced outage factor year-to-date is an exceptional 1.6%. Even more impressive was our Q3 forced outage factor of 0.9%. Meanwhile, we've continued the discipline of holding the line on cost. Our engineering group's focus on preventative maintenance and our outage services group's focus on turbines and generators, when combined with the professionals at our plants, have truly built a best-in-class and entrepreneurial operating regime, and it shows in these availability statistics and cost data.

Our year-over-year production data shows that with the traditionally higher operating hours in the third quarter, and a modestly higher gas price environment, we're producing roughly the same number of megawatt-hours this year as last in Texas and across the Southeast. Higher run times continued in the North due to the ongoing coal-to-gas switching; and in the West, we benefited from a more normal hydro year compared to last year, as well as a nuclear outage.

The next page shows our standard hedge disclosures. There's a lot of information on this page and our IR team stands ready to support you in its interpretation and in your modeling efforts. Let me first call your attention to the changes we've made in terms of plant footprints since the last quarter, which are shown in the middle left of this slide. Today's disclosures reflect, for the first time, the sale of Broad River, which has a long-term contract, and the addition of merchant positions though our Bosque acquisition, our 2 Texas expansion projects and our Garrison project. Our previously announced sale of Riverside and the addition of Los Esteros and Russell City were included in our prior disclosures. The recent changes result in more open positions in 2013 and more meaningfully in 2014 than we reported on our second quarter call. Net-net, we have added material expected megawatt-hours in markets with upside potential, which has reduced our overall hedge percentage.

Beyond that fundamental change, I would simply make the following observations: First, the balance of 2012 remains substantially hedged, both on power and gas; second, 2013 remains fairly open from a market heat rate perspective. As was the case when we first initiated 2012 guidance, our open position for next year is one of the reasons for our $200 million range. Although I'll come back to our 2013 outlook in more detail on the next slide, I'll simply say that our net gas exposure of 2013 remains roughly flat, considering the inverse relationship between gas prices and heat rates; third, 2014 is very open. We are long, heat rates and gas price; fourth, we have added 2015 to the disclosure for the first time and like 2014, we are long.

The next page provides a little more perspective on our outlook for 2013 energy prices in our key markets. In Texas, our outlook for 2013 is bullish from the current trading levels, although ultimately much will be determined by the summer weather. As you can see on this page, spark spreads are up in 2013 versus 2012 realized, primarily in our view due to mild 2012 summer, a tightening supply and demand balance, higher gas prices and higher price caps. However, heat rates are down year-over-year. Directionally, the year-over-year forward heat rate relationship, with 2013 currently trading above 2012 actuals does not seem justified; hence our bullish view.

In the mid Atlantic, we take a similar view, although the higher 2013 gas prices have undoubtedly had a negative impact on heat rates and spark spreads. Given how pervasive coal-to-gas switching has been, the current forward spark spreads in 2013 are also below those of 2011 and 2012 and flat to 2010, when there was more limited coal-to-gas switching.

In California and the Southeast, we are more neutral. A positive factor in California is AB 32, but that will be offset by some incremental fossil generation that will come online this year, including around Russell City and Los Esteros plants, as well as the potential for part of the San Onofre nuclear plant to return to service. It is also important to note that this fall, market liquidity has been lower, particularly in the west in Texas, given some regulatory uncertainty. We believe it will return, though liquidity in markets is important to how we operate our business.

As a quick commentary on gas prices and its impact on our fleet next year across Texas, the mid Atlantic and Southeast regions, the currently higher forward gas curves versus 2012, should they materialize, are likely to lead to lower production volumes in this year, particularly in the off-peak and shoulder months. Overall, the views on this page are important to note, because they generally drive the scope of our EBITDA and free cash flow guidance range. Our ranges are informed by the forwards in the lower half, and the fundamentals in the upper half.

On the next page, I'll provide a bit more of a glimpse into our Southeast portfolio and progress we're making there. First and foremost, as Jack described, we have now captured full value for Broad River with the resale to Energy Capital Partners. I'm proud to say that all employees at the plant will have jobs, with either the acquirer or with Calpine. We expect the transaction to close before the end of the year.

As has been our stated strategy in the Southeast, we have been seeking to capture value either by, one, contracting the head of market tightness, which will occur in many utility service areas by the middle of the decade; or two, in the case where there is a buyer that values the asset more than we do, selling the asset, as we have done in Colorado and Texas and as we are now doing in Wisconsin and South Carolina.

In addition to the Broad River sale, we have continued to execute on our strategy in the Southeast, with contracting our Oneta plant in Oklahoma, our Carville plant in Louisiana and, although shorter-term, our Auburndale peaker plant and our Santa Rosa plant in Florida. Meanwhile, we continue to have discussions and are making some progress around our other facilities.

As far as asset sales go, recent marks on merchant combined cycle asset values in the Southeast had been around the $400 per kW range, which, to be fair, if we were to sell our portfolio at such a level, it would be free cash flow accretive in the short-term. However, we think that either through contracting or sales, we can do much better than that on this portfolio over the next 2 to 3 years. The benchmark as to what is achievable here will not approach that in other markets like PJM or Texas, but we are starting from a very low base and believe there is upside.

Finally, I'll end on a discussion about Texas, which is entirely appropriate, given the incredible amount of regulatory process and investor attention that it has garnered over the last year. First, with our recent announced acquisition of Bosque and our Houston Ship Channel expansion efforts, we will be bring our Texas capacity to about 8,500 megawatts, although, as a reminder, just over 1,100 of those megawatts are behind the fence; that is, either the long-term contracted, or serving households that are steam customer sites.

As an update on the Texas regulatory process, as many of you know, Texas has reached a point where new investment in generation is required to protect electric liability in arguably, the most robustly growing economy in the United States. However, just recently, ERCOT published an updated reserve margin analysis, which stirred some confusion about the pace of that growth by introducing a low-growth forecast. A closer look at their math suggests that peak load next year would be roughly equivalent to 2010, which was a normal summer, and several hundred megawatts below this year, which was a mild summer by all accounts. This scenario simply doesn't add up to us, given the still vibrant economy. The time for action in Texas on market design issues is ripe, and we feel the regulators and legislators understand this.

The required new investment to serve this growth has not yet begun to broadly materialize at nearly the levels that will be needed. Although it's been said many ways, the chart in the upper right shows that the current market, taken in perpetuity, supports evaluation of roughly $500 to $600 a kW, similar to our basis in our new Bosque plant, and well above our call spaces for the channel and Deer Park expansions. That said, it's far below the nearly $1,000 per kW the media has reported for recently announced new construction. In Texas, this is called the missing money problem. We've been actively engaged with the public utility commission, the legislature and the statewide-elected officials. The debate continues around what the ultimate solution will be. What is clear is that the status quo will not provide the reliability the state needs. There are overwhelming indicators that the market must change. So what will be the change?

There are 2 revised fundamental proposals before the PUC. First, a traditional forward capacity market similar to PJM, although with some Texas distinctions. For example, there could be one zone, and there would not need to be the minimum offer pricing rule or MOPR rule. The other option under consideration is an energy-only market, the one where price caps are raised, reserve requirements are raised and demand response is implemented, but when called upon, done so at a very high price. While this debate over market design continues, we're encouraged that the PUC has taken the interim step of further increasing the systemwide offer caps.

However, the urgency to resolve the debate with a long-term solution remains. Raising the price caps likely means increased market volatility, which could be favorable to Calpine and other generators in the short-term; in fact, potentially more favorable than a centralized capacity market. But we are not looking for short-term profits; we are advocating for a stable market, one they can deliver reliable and fairly priced power for Texas over the long-term.

With that, I'll turn it over to Zamir.

Zamir Rauf

Thank you, Thad, and good morning, everyone. As you can see from the chart on the top left, we are continuing to deliver strong financial results. During the third quarter, we benefited from our commercial operations team's hedging efforts, given weak market conditions that were driven by mild weather in Texas and lower gas prices overall. As we approached the summer and dynamically throughout, we opportunistically locked in margin that was higher than where day-ahead prices ultimately cleared.

Looking at the balance of the year, please note that the relationship between our third and fourth quarter earnings is expected to be different this year from last. As a result of seasonal hedges that favor this year's third quarter, lower hedged margins in the West and a contract expiration in the Southeast, we expect our fourth quarter to be lower than the fourth quarter of last year. We are however, very pleased with our performance thus far, and are well positioned to achieve our 2012 guidance.

In addition to delivering solid financial results, we have also continued to opportunistically manage our debt. Last month, we announced the issuance of a 7-year, $835 million term loan, the proceeds of which were used to call 10% of our senior secured notes and to fully retire Broad River's project debt. This opportunistic refinancing lowered our effective interest rate, generating approximately $25 million of expected annual interest savings that accretes directly to adjusted recurring free cash flow per share. We will continue to seek similar opportunities where we can simplify capital structure, and more importantly, increase our adjusted recurring free cash flow per share.

Overall, we continue to focus on a disciplined and well-balanced approach to capital allocation. Thanks to the strength of our cash flow, and the flexibility of our capital structure, we have continued to reposition and optimize our portfolio, invest in higher return growth projects and streamline our debt, all while returning meaningful capital to our shareholders.

Turning to the following slide. Let's review the quarterly results in more detail. Overall, adjusted EBITDA increased $68 million in the third quarter of 2012 compared to the prior year, despite generally weaker market prices and milder weather. As I mentioned on the previous slide, our effective hedging, particularly in Texas, enabled us to lock in prices well above where the market actually cleared. Our adjusted EBITDA was also favorably impacted by increased volumes in the West, driven by more normal hydro conditions and a sustained nuclear outage in California. These benefits were offset by lower contributions from hedges associated with the Geysers.

Meanwhile, in the North, adjusted EBITDA benefited from higher RPM capacity payments, and to a lesser extent, from increased volumes. These benefits were mitigated by the contracted nature of several of our North Region plants, along with lower realized spark spreads among our merchant plants that experienced higher dispatch.

Finally, across the fleet, we continue to diligently manage our plant operating expenses, which remained essentially flat despite overall higher volumes. In sum, our excellent operations, prudent hedging and focus on cost management has left us well positioned towards achieving our 2012 guidance.

Now let's turn to the following slide for a comparative of our 2012 and 2013 adjusted EBITDA guidance. The chart on the top of the slide is a bridge between the midpoint of our 2 ranges. As you'll note from the chart, we expect to benefit by approximately $100 million next year from higher regulatory capacity revenues, primarily in PJM as a result of higher RPM capacity option payments. Also, our view of 2013 market prices, including net change in contract value, is generally higher than 2012. We expect that these improved market conditions would largely offset the 2012 higher benefits we experienced from hedging.

The chart on the bottom of the slide shows that our announced M&A activity, along with our strong cash flow, will position us well with respect to excess cash for the foreseeable future. It is important to note that this cash balance is after setting aside $1 billion of liquidity to run the business and as such, is available for capital allocation without any restrictions. This excess cash will allow us to continue pursuing our diversified capital allocation strategy and you should expect us to continue deploying our excess cash in a very disciplined fashion, and in ways that are most accretive to our shareholders on an adjusted, recurring free cash flow per share basis.

On the following slide, we provide more detail on our adjusted EBITDA and adjusted recurring free cash flow guidance, both for this year and next. I'll call out a few items worth mentioning. First, you'll note that the 2013 guidance we are presenting today reflects all pending acquisitions and divestiture activity, including today's announced sale of Broad River, which we estimate would have contributed approximately $40 million of adjusted EBITDA next year. As Jack mentioned earlier, without the sale, the midpoint of our 2013 adjusted EBITDA guidance would have been $1.9 billion, with the high end at $2 billion. However, as you've heard us say in the past, we are not chasing a particular level of absolute adjusted EBITDA. Instead, we are focused on enhancing value per share and our recent activities build upon our track record of proving that out. I'll speak a bit more on that in just a moment.

Meanwhile, you'll also note that we expect to begin benefiting next year from the interest savings generated by our recent refinancings.

Finally, we are reaffirming our growth CapEx expectations for 2012, and are announcing the investment of approximately $250 million net of debt funding in growth projects next year. This figure includes our contracted projects in California that are scheduled to come online midyear, which are now fully funded with project debt. It also includes meaningful headway on our 3 development projects in Texas and Delaware.

Again, our strong cash flow leaves us well positioned to continue pursuing a diversified and balanced capital allocation program through next year and beyond.

Finally, on the following slide, I'd like to add some additional comments about our adjusted recurring free cash flow per share guidance that Jack referenced at the beginning of the call. As I've said before, we believe that adjusted recurring free cash flow per share is the appropriate yardstick for measuring the performance of each of our investments. And feel that it is similarly relevant for measuring our performance as a company.

Given portfolio changes over time, it is also a more accurate representation of shareholder value than looking at absolute adjusted EBITDA of free cash flow. Unlike these 2 metrics, adjusted recurring free cash flow per share captures value created by asset monetizations, such as the Broad River transaction we announced today, debt portfolio optimization, such as those achieved by our recent refinancing, the application of our substantial NOL position, by virtue of our minimal cash taxes and share repurchases.

In addition, we believe that adjusted recurring free cash flow per share growth, which we are targeting at 15% to 20% compounded annually, is representative of total shareholder return, since we view adjusted recurring free cash flow per share as a proxy for earnings per share.

The table on the right walks through some of the noncash and other reconciling items between the 2. In sum, we are focused on delivering long-term shareholder value, which we believe comes from continued operational excellence, prudent hedging and disciplined allocation of capital.

I thank you, all, once again for your time this morning. Operator, please open the lines for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] From Macquarie, we have Angie Storozynski.

Angie Storozynski - Macquarie Research

First of all, congratulations on your Texas hedges. I definitely did not expect that one. Well, I wanted to start with the 2013 guidance. You keep referring to the Broad River sale that reduces your EBITDA expectations by $40 billion. But how about Bosque acquisition; how much of a contribution is this one? I mean, on a net basis, I would still expect the -- an upside to EBITDA?

Jack A. Fusco

Well first off, Angie, thank you for recognizing that we did have a great quarter in the third quarter of this year and the team's been extremely busy with all of the [indiscernible] operations and strategy, et cetera. [indiscernible] I'll turn it over to Zamir to answer the Bosque question.

Jack A. Fusco

Yes, Angie, we haven't given specific guidance on Bosque EBITDA, but it's definitely built into our guidance, and we believe that the Texas market provides much more upside to us over the long-term here, than a contracted asset with steady cash flow. So we're very optimistic about Bosque and are very excited about its addition to the portfolio.

Angie Storozynski - Macquarie Research

But net -- but Bosque minus Broad River should be accretive to EBITDA.

John B. Hill

It depends on the curve that you use, Angie, or the like. This is Thad. We said on -- in my prepared remarks, that we guided $200 million range, and there's a view of – toward the current markets are there’s a view of what they have been and that's the reason for the $200 million range.

Angie Storozynski - Macquarie Research

Okay. And the high end of that range is your view on the heat rates, the points that you were making about upsides for heat rates?

John B. Hill

I think the upper half of that range start to reflect what we think fundamentally is plausible this next year. And the lower half of that range reflects kind of where the current markets are, and we'll just have to see how it plays out. We all know that weather and others things can impact that but we'll [indiscernible].

Angie Storozynski - Macquarie Research

Okay. My second question about volumes, I mean, I'm struggling a little bit with projecting your volumes now that gas prices have recovered. I mean, can you give us a sense of what's, I mean, what type of volumes we -- you'll, you expect to reach for this year? And what type of volumes, say for, 2013 and also, how it links to your modeling suggestions? And you're clearly, there has been some reduction in those super peak premia, and which is linked to volumes, and if you could give us any sense of what kind of volumes you expect for next year.

Jack A. Fusco

Sure. Here's the best that I can probably do. In the first half of this year, when gas was level at $3, we saw coal-to-gas switching everywhere across our fleet, including in Texas. At the current gas mark for next year, we expect we'll see some coal-to-gas switching in the East, but probably none in Texas. So the best, and obviously, there's our [indiscernible] some [indiscernible]. So unless gas price returns to the levels where it was last year, I wouldn't expect us to achieve the same volumes we achieved last year, or this year. On the other hand, I mean that we still got gas [indiscernible], we got switching in the East, so I would expect some work on it, maybe between 2010 -- excuse me, 2011 and 2012. If the current gas will liquidate; we'll just have to kind of see how it liquidates.

Angie Storozynski - Macquarie Research

And you mentioned in those modeling assumptions that there's been a change in your expected premium to on-peak spark spreads, while those premia are lower. Can you explain why that is, versus the second quarter of the disclosure?

John B. Hill

Yes, Angie, I don't -- there is no real change. The premium is going to be driven by what the amount of volume is that's driven. And so within any volume range, there shouldn't be a big change. But you'll have to decide how much volume we think we'll produce, which will be based on our gas price view. But to be clear, as we talked about last quarter, at a higher volume, the premium, because what -- we're guiding everybody off of the on-peak pricing, will be lower because more of those megawatt hours will come overnight. At lower volumes, more of those -- more of our production will be on peak, and so we think the premium will be appropriate.

Operator

From Deutsche Bank, we have Keith Stanley online.

Keith Stanley - Deutsche Bank AG, Research Division

Can you talk a little bit to the level of major maintenance expense and CapEx, the $370 million for 2013? Would you say that represents a relatively higher year in the maintenance cycle? Or is that an average year to think about, going forward in the future?

John B. Hill

Well, Keith, hey, we would recommend that $350 million on, in real terms be the continued view of major maintenance and CapEx. So that $370 million is a little bit higher. On – there are -- the maintenance cycle's actually, the next year, similar to this year, however, there's a little bit more the year after, depending on our run times, and you have to spend the capital to procure the parts, kind of at the year ahead of time, for spring outages. So I will tell you, in our own internal models, $350 million is still where it all punches out, with some variation between the years. So the $350 million real number is what I would use.

Keith Stanley - Deutsche Bank AG, Research Division

And one other, if I could. You talked about your view on the 2013 demand forecast in ERCOT and interestingly, comparing it to some of the historical data. Do you also have an opinion on the level of growth that they are projecting over the next few years, which I think is about 3% to 4% per year? Is that level of growth off a 2013 base consistent with your fundamental view, more optimistic, more pessimistic?

John B. Hill

We're very optimistic in Texas. And just to be clear, the curve that I was referring to was, ERCOT put out a report in the middle of October that actually had a downside case, and we found -- and it was used -- it was talked about a lot, but the downside case, we thought, were at levels that were just really hard to believe. It is our view that load growth in Texas is continuing at north of 3%. You can look at weather-adjusted months, and depending on which vendor you use. Our vendor had 3% for the second quarter, had above 2% for the third quarter, but there were months in there that were over 3%. But there are 35 new commercial high-rises planned for Texas. The port is expanding here, and we have a lot of anecdotal information. So and I think we're fairly comfortable that a load growth expectation that just long as the economy here holds at north of 3% is well within reason.

Operator

From Goldman Sachs, we have Neil Mehta.

Neil Mehta - Goldman Sachs Group Inc., Research Division

On your adjusted recurring free cash flow growth, the 15% to 20%, what period of time does that relate to? And what do you see is the biggest driver here? Is it organic EBITDA growth, deleveraging, acquisitions?

Jack A. Fusco

Yes, I'll take the first part of that. And then I'll ask Zamir to fill in the holes for you. So on the adjusted recurring cash flow, we used 2011 as our base year, as we -- I think we've noted that on the slide. That's the first full year that we got to pull all of our capital allocation levers, and we felt that, that was probably the best year or best representative year for Calpine and for you all to look at. When we talk about our target of 15% to 20%, my crystal ball is probably clearer in the 3- to 5-year range than it is 5 years and out. So our planning horizon is more in the 3- to 5-year range than it is longer term, just for that reason. All right, Zamir, do you have anything to add?

Zamir Rauf

Yes, I mean, Neil, we've got, as you know, a whole toolkit of capital allocation decisions that we can make and you've seen us do this over time with share repurchases, with acquisitions, with divestitures. And so I think you'll see us continue to pull those levers to create this type of value going forward.

Neil Mehta - Goldman Sachs Group Inc., Research Division

Got it. And then the second question relates to Texas here. I mean so much of the economics at the higher-price caps relates to scarcity pricing here. In 2011, we had 27 hours of scarcity pricing; in 2012, we had almost none. Based on your view of supply and demand in Texas, what do you think is the normal level, assuming normal weather conditions, of scarcity hours?

John B. Hill

Yes, well and obviously, we'll see where the weather comes out. I'll say this as an answer because we've already said that we're bullish from here for Texas. That if you assume that the on-peak heat for summer, there's at a 12.5 heat rate, that implies just around 4 hours of scarcity pricing across the entire summer. And so while we don't know what the weather is going to be, in kind of a moderately hot summer we think that 4 hours or more is imminently achievable. And then, with keeping to 12.5, through the balance of their on-peak hours, which we think is relatively conservative. So we're pretty comfortable with, in our view, here; again, it’ll all be in the weather. Hopefully, that was helpful.

Operator

From UBS, we have Julien Dumoulin-Smith online.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Just wanted to first go back to something I've asked several times here, but Sutter recontracting into 2013, how does that feel, how does that look, kind of a comparable pricing? Or, in general, how does that market regulation look like it's shaping up for next year?

Jack A. Fusco

Maybe I'll start commercial and then let Thad Miller talk a little bit more about the regulatory side, Julien. As far as Sutter itself goes, I don't want get too specific. We're not expecting a grand outside government solution, at Sutter. We've been hard at work looking to do more immediate contracting on Sutter and are comfortable with the plant as economically viable through 2013. I would say that our concerns beyond 2013, including for that plant, exist with the need for regulatory reform, which Thad can talk about here in one second. But as far as Sutter itself goes, we have achieved some level of capacity contract on the unit, and we will be operating that unit for 2013.

John B. Hill

Yes, in the market, Julien, we have outlined our initiatives previously on the last call, and again, Jack alluded to them in his introductory remarks today. There continues to be a lot of dialogue, both at the ISO and at the PUC, and I think even probably more importantly, among the stakeholders about the need for some change in that market that reflects the flexibility requirements that are going to be needed to integrate the renewables and the market structure change that's going to be needed to address the discrimination issue. We think it will probably take a couple of turns, but we think it's moving forward in earnest, and we're hoping that the first half of next year sees some good progress.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And then maybe a follow-up to, perhaps the last question here with regards to capital allocation. Incidentally, looking at share buybacks, is there any way you could frame that, in terms of that, achieving your free cash flow per share growth? I mean, obviously, it's kind of fungible with other elements here, but is there some way you could say, status quo, share buybacks would account for x percent of this?

John B. Hill

If you look at the guidance that we've given you Julien, the $1.45, it's right at the midpoint of our free cash flow range, and with our current level of outstanding stocks. So I'll let you do the math from that point going forward, but that's what that guidance implies.

Operator

From Jefferies, we have Paul Fremont online.

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

Just to sort of follow up on your statement, it looks like the current share count gets you to both the $1.16 and the $1.45. Should we assume no share repurchase through the end of next year, based on that number? Or would that be incorrect?

Zamir Rauf

That would be incorrect, Paul. I mean what you should assume is that we're not announcing anything on this call today.

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

So then, if you were to do more share repurchase, then obviously the number would be -- the number for '13 would be better than the number that you're showing in the chart.

Jack A. Fusco

Theoretically, yes. That's a fair statement.

Zamir Rauf

I mean Paul, if you just look at it, we have a wide range on our free cash flow guidance, right? And so that wide range implies a wide range on free cash flow per share as well. And to extent that we purchase more shares, then it gets even better. But as Jack mentioned, I mean you should expect us to be opportunistic when it comes to share buybacks. We didn't do a lot this quarter, but we had a lot of capital allocation activity going on. And there was a large part of the quarter when we were blacked out because of insider information we had on these transactions that were going on. So from quarter-to-quarter, it will vary. There will be some quarters, maybe, where we buy more shares; there'll be some quarters where we have possibly more M&A, but it is a, what we call a toolkit, that we will deploy over time, and we believe that share repurchases is something that we strongly believe in, and will continue with going forward. And how much, in which quarter, in which year, that remains to be seen.

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

And then I guess my next question would be given sort of the backward dated nature of market heat rates, as you look out the forward curve, is it fair to state that, given sort of where forwards are right now that the trajectory of EBITDA would be relatively flat during the same period?

John B. Hill

Yes. And Paul, it's Thad. The -- we, obviously, take a longer-term view based on fundamentals. We talked on our call several times about how we don't think that forward market heat rates are necessarily a good indication of fundamentals, given imperfections in the market. So we've given guidance for 2013 and I don't think we're prepared to talk about '14 or beyond, other than our general ballpark range of free cash flow per share.

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

Right. But if I look at the – if I look at that projection, should we assume that the underlying assumption in that projection is existing forwards or Calpine's view of the market? And I'm assuming from your answer, it's more Calpine's view of the market.

John B. Hill

We – I’m trying to think how to answer that question the best way I can, without redoing anything. I would say, let me just simply say this, in the free cash flow per share expansion, there is contribution for capital allocation. There's also contributions for underlying growth in our core business that we feel strongly will occur under a range of scenarios.

Operator

From Tudor, Pickering, Holt, we have Brandon Blossman online.

Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Let's see, general question, on a year-over-year basis, bilateral willingness to enter into capacity deals or longer-term contracts for CCGTs, does it look like it's better on a year-over-year basis? And is that partially driven by kind of comfort with coal-to-gas switching, and I'm thinking Southeast and mid Atlantic.

John B. Hill

Yes, Brandon, there are a couple things happening in the Southeast. Once, the lower gas price on a lot of the Southeast utilities just patches the change, and some of them are very public about that; others haven't, but that is a large part of it. A second component in the Southeast is the fact that a lot of these individual companies, IRPs, if you got to look at them, show the utilities getting short in the 2015 or '16 range, hopeful with load growth, but also given retirements. The retirements are obviously driven by environmental CapEx, as well as loaded gas. So, I would say there are 2 drivers in the Southeast, but current dispatch, as well as the core IRPs, and both are taking us the right way. And so hopefully, we'll be able to convert some of these assets into our longer-term solutions.

Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's helpful and positive, obviously. Right, and then Thad, how about a best guess on an ERCOT time line for the missing dollars there to find a solution?

John B. Hill

Well, I'll let Thad Miller go spring this since you asked that and he's here, and I don't -- and then, go ahead, Thad.

W. Thaddeus Miller

Yes, Brandon, I think the next bench, or the next marker along the way will be in December, when the CDR and a couple of other reports are due out of ERCOT. And I think those will inform the sense of urgency that the PUC has about moving forward more rapidly or slower. In either case, we're expecting something to happen in '13. The issue is whether it happens before the summer or after the summer.

Operator

From, Citigroup, we have Brian Chin online.

Brian Chin - Citigroup Inc, Research Division

My questions are asked and answered.

Operator

From Barclays, we have Gregg Orrill online.

Gregg Orrill - Barclays Capital, Research Division

Just going back to Slide 12, the missing margin slide. I was wondering if it was your view that the conditions, reserve margins that you believe exist in 2015, in Texas, really do imply that, that missing margin should be there. And if so, could you convert that deficit to dollars per megawatt hour?

John B. Hill

Yes. Hey, Gregg, that's a good question. I mean, any given year, obviously, is driven by things like weather and the like. It is our view that the reserve margin will continue to tighten in 2015. We will be approaching a critical stage in Texas for the reserve margin. Obviously, the market rules that are in place at the time, what the price cap is, as you know in 2015, it's now $9,000 a megawatt hour, what the response of reserve and how many megawatts are required there or not, all of that will play in. And then all of that is subject to shift as we actually continue with the capacity market range. So again, we believe that the fundamentals will be -- well what is absolutely consistent in Texas is that the market will be allowed to work. What is less clear is, whether it will be all energy or some combination. So with that said, the number is probably something like $15 a megawatt hour. I'll have to go back and do the exact math, but it will be some number approaching that would our expectation as kind of on-peak power per megawatt hour or spark spread; that is probably the missing money in 2015. So obviously, that represents a material upside. And again, we'll do that math offhand and get it back to you to make sure that I'm right. I'm losing real time here, but I think that'll be the right order of magnitude.

Operator

From SunTrust, we have Ali Agha online.

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

Thad, I wanted to be clear, I think you had made this remark earlier, and I just want to be clear. I heard you right, I think you said is, if we look at the latest forward curves, and use that in our analysis, that would equate to the lower end of your '13 guidance. If we looked at the current forward curves for '13. Did I hear that right?

John B. Hill

I said the lower half.

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

Lower half, yes, okay, got it. And then separately, Jack, a question for you. Are you getting any sense or having any conversations with the 2 largest shareholders about their shared sale plans? And is there a way for that to happen in the most smooth fashion, given your own plans for capital allocation to cause less disruption? Anything along those lines, in general, that you could share with us?

Jack A. Fusco

Ali, first, thanks, and but, no. I do not know the plans of the 2 largest shareholders. And I've said this before. If I thought that I could get them out entirely, it would be more strategic for us and we would look for ways to do that more efficiently and effectively. But I have no idea of what their overall plans are, with their holdings in the company. So at this point, when they sell, we intend to use that as a buying opportunity like you all do.

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

And last question, coming back on the Texas situation, given what you guys have been hearing as we have been on the testimonies and where the commissioners are on their positions, at least what's been stated publicly, how confident are you that a capacity market does end up being the solution here, given what you've heard so far?

Jack A. Fusco

Yes, and I'll start, and Thad Miller can finish. I think that it is a real likelihood, it is a consideration out there, and there's a lot of work being done around 2 options. One of those, which is a capacity market. I think the fundamental question for the state is whether or not they want to reserve margin target. Hinging on the answer to that question, we think will drive a lot of the answers. Thad Miller mentioned the CDR, which will be out in December. There are a couple other pieces of work that are going on right now, which will inform this. One is, there is a firm calculating the value of lost load, and the third component is, given the change in hotter weather over the last several years. If you want a 1 in 10 protection from outages, what the new reserve margin target will be, and there's a lot of focus that number will lift from 13.75% north ports. So I think all 3 of those pieces of analysis should be complete close to the end of this year, and we'll see how things play out. But look, the capacity market is very much in the mix. It's just really hard to handicap right now what will come out.

Operator

From Wunderlich Securities, we have Jay Dobson online.

James L. Dobson - Wunderlich Securities Inc., Research Division

Jack, wanted to talk a little about operating expenses and obviously you've had a good experience, 2012 to date, just sort of how you're looking at that as you look out into 2013, given the guidance you provided today.

Jack A. Fusco

Jay, I'm going to let -- I'll let Thad Hill talk about the operating expense side of the business, but we've been -- I'm proud of what we've been able to achieve and accomplish, overall, not only on the expense side, but with our performance side. I mean, we've got record-breaking performance. We've been able to maintain our expenses flat, even with additions and deletions in the portfolio. But, Thad?

John B. Hill

Yes. Hey Jay, just to kind of get down to it, I would not expect us to continue to -- or to have operating expenses go down. I would also say there's not a lot of risk to the upside. I'm talking about O&M expenses, not other G&A expenses, but the plants have run very well on -- in this environment. A lot of what we've done is gotten much more active in preventive maintenance. We’ve had a lot fewer failures this year, showing up in a higher commercial availability factor, and that's provided a lot of benefits. We've also had a lot more consumables this year. So there's opportunity, should we run less next year if we could continue to hold the line on our maintenance by continuing the preventive maintenance programs. There is the ability to offset other things like healthcare costs and labor costs. So we're going to do the best we can to hold the line, but I would not expect going forward a big reduction in pops.

James L. Dobson - Wunderlich Securities Inc., Research Division

Okay, that's great. And then maybe Jack, one for you and you can pass it off as you feel. Appreciating that Bosque was an acquisition, and that the plants you’re building, at least in Texas and in Delaware are using some advantage to cost turbines, maybe talk a little bit about sort of how you're feeling right now about acquisition versus newbuild, particularly to the Texas and PJM markets.

Jack A. Fusco

Yes, and Jay, from my past, too, there's a time to buy and there's a time to build. And right now, in Texas, we prefer buying. We've been able to buy Bosque, which is a relatively new combined cycle gas plant at deep discount to where we think the newbuild costs are, with some of the competitors, at least what's been announced in the press. And we'll do that all day long. In some of the other markets, like in Delaware, even though we're building at a discount, it just -- it makes sense for us for what we're looking for specifically in the PJM that we would build out our portfolio there rather than take on someone else's legacy environmental liabilities. So it's different in each of the different markets, and I would say, for us though, as you know, we look at all of the acquisitions and the divestitures and we're very mindful about how we allocate that capital for our shareholders.

James L. Dobson - Wunderlich Securities Inc., Research Division

Would it be fair to characterize Texas as a buy market and PJM as a build market for you right now? And if that's true, where would West sort of fit between those 2?

Jack A. Fusco

The West, we're, as you know, we're building but we're building under contract. And at the end of that, we'll have 39 power plants in California. So I'm not sure for a company like Calpine having many more power plants in one state is a good thing from a risk perspective. So it just depends. It depends on price, Jay.

Operator

From ISI Group, we have Jon Cohen online.

Jonathan Cohen - ISI Group Inc., Research Division

Thad, just a quick question on your 4 hours in 2013, on the 12.5 peak heat rate; what does that imply for the average peak heat rate, excluding the scarcity hours?

John B. Hill

Well, the excluding the scarcity hours, we would be 12.5 heat rate, excluding the scarcity. And what I was doing is I was just taking the existing on forward heat rates, which for next year, and these are ballpark numbers, are around 14,000, 20,000 and 13,000 for the third quarter months. So you kind of back out at 12.5, and you can do the math, and get to how many scarcity hours are implied.

Jonathan Cohen - ISI Group Inc., Research Division

Okay. So that would assume without the scarcity hours, you'd be at 12.5?

Jack A. Fusco

Yes, sir.

Jonathan Cohen - ISI Group Inc., Research Division

And then, just a question, I don't what you can say about this, but on the Bosque acquisition, why wasn't there more competition for that, given this picture on Page 12. I mean, can you say anything about the competitive dynamics around that particular acquisition?

Jack A. Fusco

Yes, John, I don't think we want to comment on that. It's probably better directed towards the owners, the previous owners of Bosque than it is to us, as far as the process they ran and why they chose Calpine.

Jonathan Cohen - ISI Group Inc., Research Division

Okay. And my last question on this Page 12, you have 12 -- 1,157 megawatts of behind-the-fence capacity. Is all of that, if there were to be a capacity market, do the contracts stipulate that you would not receive capacity payments on that capacity?

W. Thaddeus Miller

That's right. That capacity is either behind-the-fence, and so that load in capacity behind-the-fence does not show up in the ERCOT supply-demand markets and in the capacity market. And the contract, it is – one of the requirements on the contract we have in Texas, and so the capacity will be delivered under that contract.

Operator

From Bank of America, we have Steve Fleishman online.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Just a question on the recurring free cash flow metric. How are you treating asset sales in that metric? Is that kind of included in there, like net of kind of a net gain from asset sales? Are you excluding that?

Zamir Rauf

We exclude -- we typically exclude those sort of gains and losses. This is just purely a cash flow to the bottom line as close as we can get it to real cash. That's how we look at it, Steve. So it's really – Yes, the we have the EBITDA from sales and the EBITDA from purchases, obviously, flows through that number, but not the actual gains or losses on the sale of the asset.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Got you. So it's the ongoing impacts after the sale is all done that matters when you say captures the value created by asset sales?

Zamir Rauf

Exactly. It's more the accretion that's created by selling the assets. Some assets have more or less debt on them so that plays into the interest savings and they sort of -- all those other factors count in, but the actual gain from the sale does not. So that's cash that we have on our balance sheet that we can deploy for capital allocation, but it doesn't impact this calculation. This is purely recurring cash.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Okay, and then just one other question. I know, I think in the second quarter and continuing this quarter, you've kept the portfolio beyond '13 more long gas. Do you have any kind of stronger point of view, bullish gas after '13? Or what's the thinking in terms of gas hedging?

John B. Hill

We are looking at our portfolio for '14, now Steve. I mean, obviously, we’d be managing our portfolio in '14. It just remains long gas at this point. So while I would say there are plenty of reasons to be bullish gas, '15 and beyond, the next year or 2, we think will largely depend on this winter and what happens to produce our volumes the next 6 months, and so we'll wait and see.

Operator

I will now turn it back over to Bryan Kimzey for any final remarks.

W. Bryan Kimzey

Thanks, everyone, for participating in our call today. For those of you 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 in Investor Relations. And thanks again for your interest in Calpine Corporation.

Operator

And this concludes today's conference. Thank you for joining. You may now disconnect.

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