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Calpine (NYSE:CPN)

Q4 2013 Earnings Call

February 13, 2014 10:00 am ET

Executives

W. Bryan Kimzey - Vice President of Investor Relations

Jack A. Fusco - Director

John B. Hill - Chief Executive Officer and President

Zamir Rauf - Chief Financial Officer and Executive Vice President

Analysts

Neil Mehta - Goldman Sachs Group Inc., Research Division

Stephen Byrd - Morgan Stanley, Research Division

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

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

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

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Gregg Orrill - Barclays Capital, Research Division

Operator

Good morning, and welcome to the fourth quarter earnings call. My name is Brandon, and I'll be your operator for today. [Operator Instructions] Please note that this conference is being recorded. I will now turn it over to Mr. Bryan Kimzey, Vice President of Investor Relations. Mr. Kimzey, you may begin.

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 fourth quarter and full year 2013 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 Chief Executive Officer; Thad Hill, our President and Chief Operating Officer; and Zamir Rauf, our Chief Financial Officer. In addition, 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 to those of you joining us on the call this morning, thank you for your continued interest in Calpine.

With another successful year behind us, we're already hard at work in 2014, and as you will note, making significant progress. Indeed the past 6 weeks have been unmatched in recent memory, especially in the terms of extreme weather conditions, natural gas supply shortages and 4 consecutive monthly load records in Texas, including a new overall winter peak load record.

In short, the power markets are more volatile than ever, and our employees, power plants and organization have responded very well to the challenges. I want to thank all of the Calpine professionals for the hard work to deliver reliable electric power to our customers.

But before we begin discussing 2014, I would first like to look back at 2013, another year during which Calpine delivered on its financial commitments. With as dramatic a winter as we are currently experiencing, it is almost hard to recall the mild summer conditions in 2013 that challenged the sector as a whole, yet Calpine persevered.

Our team achieved record operating performance in 2013, including our lowest-ever forced outage factor and our highest-ever starting reliability. When our customers needed us, we were there. My thanks and congratulations to the entire team for a job well done. Their hard work and effort translated into a full year adjusted EBITDA of $1.83 billion, adjusted free cash flow of $677 million and adjusted free cash flow per share of $1.52, up 27% versus the prior year.

Meanwhile, we have made some key advancements in terms of our disciplined capital allocation program. On our last earnings call, we announced the authorization of a new $1 billion multi-year share repurchase program. And since then, we have repurchased approximately 240 million of additional shares.

In addition, we continue to grow the portfolio with the announced accretive acquisition of the Guadalupe generating station in Texas.

In sum, we have continued to position ourselves well for the power markets as a whole and for 2014 in particular. Our relentless focus over the past 5 years on plant and commercial operations is beginning to pay significant dividends.

Based upon our year-to-date performance and the pending close of the Guadalupe acquisition, I am pleased to report that we are raising our 2014 guidance even at this early stage in the year. We now expect adjusted free cash flow per share of $1.85 to $2.10, a 30% year-over-year increase at the midpoint of our range; adjusted free cash flow of $785 million to $885 million, a 23% year-over-year increase at the midpoint; and adjusted EBITDA of $1.9 billion to $2 billion, a 7% year-over-year increase at the midpoint.

The following slide further highlights our progress in 2013 and more importantly, shows where we will focus our efforts in 2014. As always, we remain committed to delivering best-in-class operating performance. Having raised the bar in 2013, we continue to work towards the goal of managing our fleet to provide outstanding availability for our customers while ensuring the safety of our people. We will also strive to execute our effective hedging program, recognizing that the ongoing contraction of the market participants brings new challenges for liquidity and credit.

Given these new dynamics of market liquidity, customer relationships have become even more important. We remain steadfastly focused on our efforts to demonstrate the value of our fleet through monetization, including contracting or sell [ph]. We will work to innovatively offer customers, old and new, our ability to provide flexible, reliable wholesale power generation.

Meanwhile, through execution of our financially disciplined growth program, we will continue to enhance our position in core markets. Our scale in these regions is an important part of our regulatory success, and we continue to advocate for design changes that will level the playing field, allow appropriate price formation and improve the competitiveness of these markets.

Most importantly, we strive to enhance shareholder value, and each of the proceeding objectives directly impacts our ability to do so. In addition, we have the opportunity to further create value through portfolio management, balance sheet optimization and opportunistic share repurchases.

With these goals in mind for 2014, it is important that we place them into the broader context of the competitive wholesale power markets and how they are transforming before our very eyes. While it may manifest in different ways in different regions, the very constant threat of change that is being woven across the country's diverse power markets is the prioritization of flexibility and reliability by our customers.

More and more, our customers want to pay for the products they need, not just for steel in the ground. And with increasing reliance on intermittent renewables and localized natural gas supply constraints, chief among their concerns, customers need products like flexible, quick-ramping generation, block-start capabilities and dual-fuel resources that can burn either natural gas or fuel oil.

To the extent that customers continue to increasingly value these attributes, markets will have to evolve to differentiate those generators capable of providing them and to compensate them accordingly, either through capacity payments aimed at securing resources with these features or through energy markets or ancillary service products.

A fleet like Calpine's is uniquely and ideally positioned to respond to these conditions. Our ability to cycle overnight, to ramp quickly in response to variable loads and in the case of PJM, to do so reliably as a result of our dual-fuel capabilities, mean that the transformation that is underway on our nation's power markets is one that trends once again in our favor.

Given our advantaged position, Calpine features the right fleet at the right place at the right time. On the following slide, I'd like to highlight that Calpine is a multifaceted investment and cash flow generator. It is bigger than just one market, one trend or one financial driver.

Our geographic diversity across the nation's key competitive wholesale power markets helps to balance our exposure to any one particular area, while our technologically diverse portfolio offers the flexibility and the reliability our customers need.

We also benefit from our position relative to the secular trends that are shaping our industry. New generation, whether to replace retiring units or to satisfy growing demand, will be needed. And the flexibility, reliability and affordability of natural gas-fired generation makes it the compelling choice.

Existing generation that offers the attributes customers need, flexibility and reliability, also needs to be compensated to stay online to support the increasing volatility in our markets. Calpine stands on the right side of these trends.

And finally, our position is enhanced by our ability to continue effectively allocating capital in a disciplined and balanced manner. Over the past several years, we have shown our willingness and ability to buy strategically positioned assets at attractive prices while selling noncore assets also at attractive prices. We believe these types of opportunities still exist.

In addition, we will continue to opportunistically return capital to shareholders, thus far having repurchased approximately 15% of our outstanding shares. In sum, these investment attributes drive our ability to deliver strong adjusted free cash flow per share growth, which we believe differentiates Calpine from its peers and makes for a compelling value proposition.

With that, let me now turn it over to Thad for a more detailed review of our markets.

John B. Hill

Thanks, Jack, and good morning to everyone on the call. As Jack mentioned, we finished 2013 strong and are off to a great start in 2014 from a commercial, market and operational standpoint. Much of 2013 was challenging from a market perspective, but a continued focus on solid operations and controlling our costs until opportunity appeared in late 2013 and then much more dramatically at the start of this year, we were poised to take advantage of it.

On the key statistics of safety and power plant availability for 2013, we delivered a great year of performance, equal to or better than last year's performance depending on the metric, and much better than our 3-year average or any relative benchmarks. We also continue to tightly manage cost despite operating a much bigger fleet.

On the chart, we show our progress over the last 5 years against these key metrics. We continue to take ground on the goal of being the premier power generation operating company, and I am thankful to our operations team, both those at the plants and those in the support organizations here in Houston.

Much of the generation output differences year-over-year shown in the upper right were driven by portfolio changes in all of our key gas operating regions. Aside from that, the most notable market conditions were in the West or drier conditions during the year, and a burst of cold weather in December proved helpful to our fleet. And in Texas where much stronger year-over-year market conditions were driven by a combination of a 3% increase from weather-normalized demand or wind output in colder weather.

Finally, at the Geysers, the modestly lower output was driven by an outage at one of our units there where we were building a new cooling tower. Earlier Jack discussed capital allocation, including our deployment of growth capital. Our announced acquisition of Guadalupe should close before the end of the first quarter. And the 3 projects currently under construction, the cogent expansions in Texas and our new plant in Dover, Delaware, continue on track and on budget.

Our development team continues their work on providing the next slate of opportunities for growth. As we've discussed, we deployed growth capital when we can build under a long-term contract or when we think we have the opportunity to build or buy merchant capacity at a deep discount to market replacement cost. We believe we have stayed true to this principle, and our discipline has paid off with some very good projects and acquisitions over the last several years.

In the bottom right of the slide are 4 general opportunities we are working, 2 in each category. We will provide updates on these as appropriate.

On the next page, we give a brief perspective on some of the puts and takes that are impacting our core organized markets. In the West, and more specifically California, near-term fundamentals are being driven by what appears to be shaping up as a remarkably low hydro year despite some recent rains. Obviously this can be helpful to us.

However, perhaps counterintuitively, much of the near-term upside to us will come from increased production runs overnight and during the second quarter, rather than the absolute higher summer on peak pricing. The water that is there will be saved to be released during the summer on peak hours where there's also the impact of new solar.

Beyond the current year, the California story is dominated by the increased penetration of photovoltaic solar and the requirement that a portion of the revenue received by merchant generators shift from energy payments to capacity payments.

There are various regulatory proceedings and discussions underway that could formalize the mechanism to do that. It is critical for investors to remember though that the underlying fundamentals and need for flexible fossil generation is increasing, not decreasing.

From now through 2017, there will be more than 5,000 megawatts of fossil plant retirements, with only around 1,000 megawatts of fossil plant additions. As an aside, that number in northern California, where many of our plants are, will be roughly 3,000 megawatts of fossil retirements with no fossil additions.

More broadly, the procurement efforts in Southern California are targeting only a fraction of the capacity that CAISO estimates it needs and an even smaller fraction of the expected retirements. Through ongoing commercial efforts, having a flexible and modern fleet and some regulatory reforms, we're comfortable with our prospects in the West.

I'll return in more detail in Texas and PJM in a minute. But let me make a couple of broader points first. There are 2 major trends that we think structurally will be very helpful to Calpine in the coming years.

First, after several years of very low volatility in both power and gas, it appears that an era of volatility is returning. We've seen it clearly this winter, but it is more than a short-term weather phenomenon. Although by any account, there's plenty of shale gas, the deliverability issues of getting gas to the right places at the right times will continue to drive regional volatility.

Power volatility will also continue not just because of fuel supply, but because of underlying power dynamics in the core regions: In the east, driven by large retirements and regulatory efforts to encourage price formation; in Texas, a much tighter supply environment with unprecedented price caps; and in California, a much more fragile operating structure.

Second, although there continues to be considerable regulatory debate, generally speaking FERC has been responsive to petitions seeking to assure the viability of fair and competitive markets, including when individual jurisdictions have proposed market changes not consistent with its objectives.

Adding to this are decisions by the Federal District Courts in New Jersey and Maryland that made it clear that state-mandated procurement seeking to manipulate federally regulated power markets is not allowed. Again, there will be lots of to and fro on protecting and improving competitive markets, but we are pleased with the developments over the last couple of years.

Before turning the page, just a quick comment on the Southeast. While most of our discussion about 2014 year-to-date performance has been focused on the Mid-Atlantic, our plants in the Southeast also benefited from the strong market conditions. We continue our origination and monetization efforts there.

Turning quickly to our standard hedge disclosures. I will make 2 points. First, 2014 is now 73% hedged. This is up from 59% during our last call. As forwards have risen, as you can see on the lower right, we have taken advantage of the opportunity to sell more of our output forward.

Although for competitive reasons, we do not disclose our regional hedge positions, I would say that we continue to see more balance to the year upside in PJM, followed by Texas.

Second, on our gas position. Our portfolio continues to be geared along in 2015 and '16. One dynamic that is worth noting though is how our fleet in the Mid-Atlantic reacts. Because the Mid-Atlantic gas price is now at an approximate $0.75 discount to Henry Hub during the summer even while we can be long gas overall, our PJM fleet can pick up much more run time should that spread continue to widen. In other words, a drop in the local Mid-Atlantic gas prices from these levels is only helpful to our fleet.

As a final note on gas, in the front end, as our hedge positions change, we tend to be pretty nimble in managing the resulting gas exposure and shifting positions as appropriate.

The next page shows Texas, a popular topic among many investors. In our view outside of Austin, not much has changed over the last couple of months. New investment is required and probably soon. Much of the intense dialogue around the CDR, what an optimal reserve margin is, et cetera, really misses the main point.

Things are pretty simple. The reports of the depth of load growth have been much exaggerated. Very limited new capacity will be constructed in the current environment of high regulatory uncertainty, and there's reason to believe that without a dramatic change in the gas price or other appropriate market structure change, many older units will be under increased margin pressure and could face more mothballing or even retirements, a point of view that has not been considered at all in the recent dialogue. In other words, the fundamentals continue to be very strong.

On the load topic, as the chart in the upper left shows, the weather-normalized load growth accelerated in the back half of the year. Clearly nothing near to the second half of 2013 experience is contemplated in the new draft ERCOT forecast. In fact, the recent draft peak load growth prediction that has garnered so much news is a mere 1.3%.

This is remarkable given the current economic boom and recent history. In fact, it is 30% below the 1.8% actual weather-normalized load growth in Texas since 2009.

With the last gasp of the production tax credit, there will be an increase in the amount of wind projects that begin operating over the next 2 years. Most of these projects will be in West Texas where the wind patterns win themselves to more nighttime and shoulder season production versus daytime or summer production. Our flexible fleet can continue to operate during the day and cycle off at night. So we're there for the peak prices without having to operate at a loss overnight.

This dynamic could have a different and negative effect on units to have less flexibility, however. Additionally, there are many older steam and combustion turbine plants. And in fact, there are 10,000 megawatts of plants that are more than 30 years old with under a 10% capacity factor.

Many of these units are only marginally covering their fixed O&M today and have no economic room for any major maintenance or required CapEx should something break. We continue to advocate for a capacity market as the best construct to drive needed new investment in Texas power generation over the coming years.

That said, there continues to be a need to also make adjustments to the energy market to make sure energy prices appropriately reflect the market conditions as well. Regardless of what the ultimate choice of the PUC is, whether a capacity market or an energy market design that encourages more appropriate price formation, we encourage quick action. No consultant report or Austin debate event can forestall the impact of a strong and expanding Texas economy on electric reliability.

In PJM, the story is all about volatility as we discuss on the next slide. As several analysts have pointed out, the PJM story has evolved into one of flattish capacity prices and higher, more volatile energy pricing.

The PJM capacity markets have been very successful in attracting new resources. As approximately 25,000 megawatts of older and dirtier generation has begun retiring, it has been replaced in part by demand response and in part by new generation. Demand response now represents approximately half of the reserve margin as can be seen in the chart in the upper left. When it is called [ph], the resulting market clearing price tends to be much higher than the dispatch cost to conventional generation.

As can be seen in the lower left, in the last month, demand response has been required for reliability. And based on the forward view in the upper left, it will continue to be needed.

The second and more recent source of volatility in PJM has been gas price related. Although there is plenty of gas, a confluence of events has created significant volatility this winter. In the case of the most recent winter event, very high gas prices actually created negative spark spreads and very positive power to oil spreads.

As can be seen in the upper right, on many days not only was gas generation out of the money, but burning oil was much cheaper than gas. 90% of our PJM fleet has oil-fired capacity, which we used extensively during the polar vortex events to our benefit.

Over the next several years, both the demand response induced price volatility and in cases of extreme cold weather, the winter gas price volatility are likely to persist. But there is also a possibility of another round of solid-fuel retirements in the region, given the growing discount on Marcellus hub pricing to Henry Hub outside of winter. We think this discount will continue to pressure many older plants.

So the PJM outlook, flattish capacity pricing and increasing volatility driven not by the market design itself but by the unique confluence of high amounts of demand response resources, a gas network that could be undersized for winter events in an era of higher home heating needs and the good fortune of having plentiful, cheap local gas.

The right portfolio to benefit from these conditions is a modern combined-cycle fleet that has the ability to burn cheap Marcellus gas for much of the year and the ability to burn fuel oil during extreme winter weather. We like our position very much.

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

Zamir Rauf

Thank you, Thad, and good morning, everyone. So last quarter, we introduced Calpine's operating and financial leverage as core drivers behind the strength of our adjusted free cash flow per share growth. And in 2013, we saw both of these forces in action.

Our investments in growth, excellent operations, effective hedging and cost management efforts translated into a 5% increase in adjusted EBITDA year-over-year. This solid performance, when combined with our share repurchase program and refinancing efforts, resulted in an impressive 27% increase in adjusted free cash flow per share.

We are similarly positioned as we head into 2014, where, based upon our updated guidance, we are projecting a solid increase in adjusted EBITDA, coupled with a significant increase in adjusted free cash flow per share. Our updated guidance reflects not only the pending acquisition of Guadalupe, but also the strength of our year-to-date performance.

In 2015 we will benefit from a full year of operations at Guadalupe, along with Deer Park and Channel that will come online later this year. 2015 drivers also include the COD of our Garrison energy center and higher rate [ph] prices at the Geysers, offset in part by lower capacity revenues.

The Guadalupe acquisition builds upon our disciplined growth program, and you can see its contribution to our 2014 capital allocation efforts in the graph on the bottom of the left of the slide. Here, we bridge our excess cash as of December 2013 to our projected excess cash as of December 2014, which, you will note, remains strong at approximately $700 million at the midpoint of our guidance. You may note that the chart assumes we financed approximately 50% of the Guadalupe acquisition.

In addition, while this graph assumes no further share repurchases or investment in growth, we are projecting more than sufficient excess cash to continue supporting both activities.

Moving to the following slide. Let's review our 2013 financial performance with a closer look at our regional results for the fourth quarter. Most notably, we continue to experience the impacts of portfolio changes across all our segments.

Capacity additions benefited our West and Texas regions, with the addition of Russell City and Los Esteros in August of 2013 and the acquisition of Bosque in November of 2012. Meanwhile, strong financial results in our north and southeast regions were partially mitigated by the sales of Riverside and Broad River, respectively, in December of 2012.

Beyond portfolio changes, in 2013 we continue to benefit from the impact of favorable contracts in the West and Southeast and from higher regulatory capacity payments in the North. We also benefited from stronger market conditions in Texas and the West, driven by the early stages of the weather we've continued to experience in the first part of 2014, offset in part by lower contribution from hedges.

The following slide shows our track record of effectively and strategically deploying capital in order to deliver our targeted adjusted free cash flow per share growth. As you will see from the graph on the left, we have consistently deployed over $1 billion of capital for each of the past 3 years, pursuing a balance of organic growth, acquisitions, debt repayment and share repurchases.

As you can see, 2014 will be no different, and we intend to continue this level of deployment going forward. Aside from the robust adjusted free cash flow generated by our business, we also have the potential to pursue accretive asset divestitures and to redeploy that capital. These efforts demonstrate the financial multiplier that underscores the Calpine growth paradigm, as shown on the right.

As I have mentioned before, the ability for modest changes in adjusted EBITDA to drive meaningful changes in adjusted free cash flow and significant changes in adjusted free cash flow per share is arguably unmatched in the industry and illustrates Calpine's true value proposition.

As Jack mentioned at the beginning of the call, Calpine has become a real cash flow generator. At the same time, investors are beginning to realize that all EBITDA is not created equal. It is free cash flow and the ability to return capital to shareholders that ultimately drives value. Hence, our relentless focus on adjusted free cash flow per share. As such, we think it's time to take the next step in evaluating our adjusted free cash flow per share metric.

The following slide shows our adjusted free cash flow per share, along with utilities earnings per share, MLPs, distributable cash flow per share and REIT adjusted funds from operations per share. Each of these metrics is presented after interest and maintenance, or D&A in the case of EPS, but before any capital allocation, including debt amortization, growth and the return of capital through share repurchases or dividends. As such, the comparison is apples-to-apples.

I realize that the relative business models and risk profiles vary, but we have shown over time that Calpine's business model can be very stable. We believe our growth in adjusted free cash flow per share is sustainable and plan to continue deploying capital with that goal in mind.

In addition, by virtue of our substantial NOLs, Calpine does not pay any federal income taxes, similar to MLPs and REITs. While we don't pay a dividend, we do return a significant amount of capital to our shareholders in the form of share repurchases.

At these prices, we believe share buybacks create the most value for our shareholders. The chart on the top right shows the comparison between Calpine and representative groups from each of these other sectors. Calpine's total return as approximated by our targeted adjusted free cash flow per share growth rate is 15% to 20% compounded annually, which is superior to the total returns offered by MLPs, REITs and utilities.

I have said this before and I will continue to say that through the worst financial crisis in my lifetime, our adjusted EBITDA and adjusted free cash flow has been incredibly stable. With a recovering economy and robust capital allocation strategy, we have more than delivered on our adjusted free cash flow per share growth target and remain committed to doing so. As such, I believe that Calpine offers a compelling total return at a very attractive relative valuation.

With that, I thank you all again for your time. Operator, please open the lines for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And from Goldman Sachs, we have Neil Mehta online.

Neil Mehta - Goldman Sachs Group Inc., Research Division

On Slide 9, you talked through new developments. Can you specifically give us an update on where you stand with Mankato, the California solicitation and then also Texas upgrades?

John B. Hill

Well, I will start with Mankato because that's probably the only one where we will provide a lot of -- or any visibility. There's -- we are waiting for a PUC decision, which will come in the first quarter about whether or not XL will proceed to enter a PPA for an expansion offer on Mankato. We went through a competitive process -- have sorted through the competitive process and various government entities have -- are pushing for that. But we won't know until the commission decides. We'll know that this quarter, Neil. And obviously without a commission approved PPA, we wouldn't plan to expand in MISO given the market rules and conditions there. On California, I'm really -- other than the fact that we're participating, we're really not prepared today to give any other information on that. And then in Texas, it's all about what the development market rules when they're completed will look like, and so we're keeping our powder dry on that one. And we're prepared to invest, but only under the right conditions.

Neil Mehta - Goldman Sachs Group Inc., Research Division

All right. And then the second question, I recognize there will be, in a sense, some sensitivity around this as well, but any early thoughts on puts and takes going into the upcoming capacity auctions in PJM?

John B. Hill

Yes. So in my prepared remarks, we're pretty clear we have a generally flattish view of capacity markets. If I break that down a little more, it's probably a little more constructive in the RT [ph] and a little flattish in kind of MAAC. There's been some speculation that regions -- subregions could separate. And it's certainly possible. There were some calls about New England as well, and of course, it didn't. And so I think our bias is against the separating, but I think the real story in PJM to keep in mind is that we expect the upside there for the next several years to be on the energy side in our capacity markets there.

Operator

From Morgan Stanley, we have Stephen Byrd on the line.

Stephen Byrd - Morgan Stanley, Research Division

I wanted to talk through the excess cash, Zamir, that you had laid out. And just wanted to get a sense for your appetite to deploy that excess cash this year just given the opportunities you see, both in terms of share buybacks as well as growth opportunities. Is this something we should expect as likely at the end of the year you would have somewhere in that range of excess cash that you laid out, or are you more sort of aggressively biased to trying to deploy that this year?

Zamir Rauf

Yes. Stephen, we plan to put our cash to work. Now whether -- how much we put this year, how much we put next year remains to be seen. Remember, as part of the capital allocation strategy, we do not only have cash from operations, but we've also sold plants over the years. And so looking at the whole picture, we do plan to put our capital to work. Remember, this is excess cash above the $1 billion. So we don't need to keep it on the balance sheet. Our goal is to return it to shareholders in the most accretive manner, and we will do so.

Stephen Byrd - Morgan Stanley, Research Division

Great. And then just wanted to talk about potential asset sales beyond the Southeast. You have a number of assets with long-term output contracts that will look to be pretty good monetization opportunities. I'm thinking about California in particular. Can you speak to your appetite or lack of appetite for thinking about selling your sort of lower risk assets?

Jack A. Fusco

Yes. Stephen, this is Jack. And I'll say we are constantly looking at the portfolio and evaluating how we can create the most value for our shareholders. So we're not adverse to selling any of our assets, even those assets that may be in a core market if we can get attractive prices for our shareholders.

And I think we've got a track record of doing that already, and I think that would be a fair expectation for our investors.

Operator

From Tudor, Pickering, Holt, we have Neel Mitra on the line.

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

Quick question on the CDR, Thad. So when you think that the outlook is conservative -- or is the CDR in your view kind of double counting reserves and energy efficiency demand response? And then also how do you factor in industrial demand in the forecast? And do you think [indiscernible] underestimation?

John B. Hill

Yes. No, thanks, Neel. So first I'll start with the demand forecast, and I'll come back to the -- which is a technical point for probably a lot of people in the call, which is whether it's a net or a gross number, so I'll touch that lightly [ph] and how we're happy to follow up on that on. But first, since 2009, weather-adjusted load is currently at 1.8% in Texas. And so we struggle to understand why that's going to be 1.3% now even while industrial demand appears to be picking up in the state. And you all know industrial use a lot of power here, and that's increasing. So we would at least want to thoughtfully challenge the load forecast that's embedded there. The second point you mentioned -- and so we are much more bullish than the official number. And again, I don't know why anybody would think that load growth in the state is slowing over the last couple of years into the next couple of years. As far as the other point you raised, we're generally for people in this call -- the load forecast that is out there, the 1.3%, includes incremental energy efficiency in that number. However, the CDR already assumed net-net a couple of thousand megawatts of energy efficiency and other things. So there's been that bit of confusion around whether or not this forecast went into the net line or went into the top line. So -- and ultimately we'll figure that out with ERCOT as we go forward. But I think our point is that load is growing at 1.8% or even 1.3% regardless of which one it goes on, and so we'll see how things play out. We think the markets can be tighter than what we think the CDR will show and finally, we'd also argue the CDR doesn't show many retirements. And we think there's there's risk of that in the current environment. So we're much more bullish than what the CDR will show for a couple of different reasons, Neel. We'll just see how that plays out.

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

Okay, great. And secondly, just a follow-up on your comments about MAAC being flattish. It seems like there are some retirements, and there are some plants that maybe bid in the last auction that won't get built. Do you expect incremental new builds on top of the Marcellus to kind of flatten out the price? Or is there something else that's kind of bringing down the price that would offset the retirements?

John B. Hill

Well, we'll ease down in the upcoming thing. The capacity imports and the MAAC are larger than they were the year before. And there could likely be some incremental new build. So again we're not bearish at all. I just -- I would not expect -- we're not expecting huge uptick and really are trying to point people towards the energy markets where we think we'll see years of robustness.

Operator

From UBS, we have Julien Dumoulin-Smith.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

So a quick question here, and you started to cover it a little bit. But what are your thoughts about fuel -- firm fuel commitments in PJM as it's being called here. Is that an opportunity for you all in New Jersey and Delaware where you all are with Conectiv?

John B. Hill

Well, absolutely it's an opportunity for us, Julian. As we pointed out in the slide, 90% of our Mid-Atlantic fleet already has dual fuel. And so there are multiple market mechanisms that can get used to encourage whether -- well, first off, you can be certain if you have FT, firm transmission, delivery on gas or you can have backup fuel, either one probably works. And then the real question to us is what the mechanism could look like should that be encouraged going forward. And there's a range from paying people for having dual fuel to -- certainly number of megawatts that PJM requires to even higher penalties should you actually not show up, which means if your fuel gets cut, you're paying a bigger penalty for nonperformance. So there are a range of rule changes, which could be discussed, but we'd certainly like our -- whichever one it is, if it goes forward, we certainly like our fleet because we do have backup.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

What do you think it looks like potentially is? Do you have any sense? And also if you could elaborate a little bit, what would it cost you for FT if you could?

John B. Hill

Yes. No I'm not going to get in -- I mean, it's still early in the debate about kind of what that could mean. I mean -- look, we have FT at some of our plants, and we have fuel backup at 90% of our plants. In other places, FT is a reasonable price trade-off. Other times, it's not. So it's really, Julien, probably too hard to call. The good news is we've got our mix. We're already going to be -- and meet whatever standard is almost certainly applied [ph].

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

And a quick clarification, this going to the same subject. In January or year-to-date, how much of the increase in guidance is attributable to what you've seen thus far versus just what you're seeing in forwards and market-to-market your portfolio?

Zamir Rauf

We're not going to get that specific, Julien. This is Zamir. It's a combination. We're definitely very pleased with how we've performed so far this year and how the rest of the year looks, and all that, along with the acquisition, is reflected in our guidance.

John B. Hill

But we're 44 days into a 365-day year.

Operator

From SunTrust, we have Ali Agha on the line.

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

Jack, if I think about -- just conceptually think about your power plant output for this year, you've got obviously Guadalupe coming in, end of Q1 or so, and then higher gas prices. So just conceptually, relative to the 104 million or so megawatt hours you produced last year, how should I think about directionally the output for this year?

Jack A. Fusco

So I'm going to start, and then I'll turn it over to Thad to chime in on it, Ali. But we have Guadalupe, but we have a full year now of Russell City and a full year of Los Esteros. Both of those power plants in California have been generating a lot of megawatt-hours for us. We're also going to have a 0.5 year of the Deer Park expansion and 0.5 year of the Channel expansion again, so it's a major physical portfolio shifts for us that will generate a lot of megawatt-hours. And then I would say just theoretically with little higher gas prices, you'd expect the rest of the portfolio to come down a little bit. And I don't know, Thad...

John B. Hill

Look, our current expectations are, compared to the 2013 number, the production will be up modestly, kind of low single digit millions of megawatts of hours kind of thing. Up on the new assets and down on the higher gas price. That, of course, doesn't assume that there is, as we've suggested, there's upside should the bases continue to widen out in the Mid-Atlantic for our gas fleet there. But kind of while we see things currently, that's about where it is.

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

Okay. And my second question, Jack, I wanted to drill in a little further into your M&A thoughts right now. I mean, the sense was late last year that there was a monetization in the Southeast that was fairly imminent. Haven't heard anything on that front, so has that been pushed back, or where we are on that? And then with regards to the fleet as a whole, if you're looking for opportunities to add, is Texas still your #1 priority or would it be more PJM? Can you just give a little more color on that?

Jack A. Fusco

I guess -- probably first on the Southeast. We continue to work on our monetization efforts there. They've taken -- they take a while. There hasn't been a sense of urgency from some of the offtakers in that region since the EPA has kind of backed off on their initial aggressive views of coal, ash and went through cooling and air emissions. We would expect though, as the EPA begins to put out some new tougher rules, that we'll see a whole another pickup in discussions there in the Southeast. As far as target markets, we've talked before in the past, we're pretty full out in the West. Our position in Texas with Guadalupe we're pleased with, but we've got a little bit of room that we can grow, but I think we have some very low cost development opportunities there that Thad mentioned already with some of our upgrades. And then in PJM, we're a real small fish, and I like that market. I like the world changes that they're proposing in the market. I like where they're headed, with transparency and competition in trying to level the playing field there, and I think you should expect that to be a real focus of ours.

Operator

From Wolfe Research, we have Steve Fleishman online.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Yes. A couple of questions. First, just on Guadalupe. How much is that represented in the higher guidance for 2014?

Zamir Rauf

Yes, Steve, this is Zamir. We are not really getting into how much is Guadalupe and how much is the market. It's definitely reflected in there. And as I mentioned earlier, we're very pleased with how the year started and where we see it going. But it's a combination of market and Guadalupe.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Okay. And then on the drought impacts in California, obviously -- could you just maybe elaborate a little more on the potential benefits for your fleet? And do we need to worry about any risks in terms of like cooling plants at all?

John B. Hill

Yes, Steve, we'll see ultimately how things play out. The Pacific Northwest is knocking around par for expected generation up there. In California, it's somewhere less than half right now. So we'll have to see how rainfall moves going forward. I think the point is that it's the second year in a row we pull [ph] a hydro up there, so kind of multiple-years things do get more severe. On the flip side, as I mentioned in my prepared remarks, there are -- the water will probably be conserved to run in the super peaks. So we think we'll get a lot more overnight runs and probably some second quarter upside, but if the water is there and it's running in third quarter and on peak, there may be less upside there. So I think you just kind of have to balance through that, and we're not expecting right now any operational issues.

Jack A. Fusco

Steve, was yours more on the technological side? Because, as you know, a lot of our fleet is air cooled in California, as well as we use reclaimed water for cooling like at Russell City, for instance.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Okay, great. And one other question. I thought that slide was really great on that comparison of free cash flow to other sectors. I mean, obviously, as you know, one difference to you versus those others is they do pay a big dividend. I know this is Jack's favorite question, but just to the degree that you don't start getting the valuation, is that something you'd consider? And maybe just update us on the thought of how you -- I remember you went through this in detail a year or so ago on share buyback being the best use of cash. Maybe just give us kind of the thought process there.

Zamir Rauf

Sure, Steve. This is Zamir. Our view really hasn't really changed. We've always said, and we still believe that share buyback is the best use of our capital at this point, barring any more accretive investments in growth and M&A. Look, we continuously look at all our options. Every year, we look at the benefits of share buybacks. We look at dividends. We look at our growth, and we make the decision. And that's going to continue over time. But at this point in time, our shares are a bargain, and we believe that buybacks create the most value for our shareholders.

Operator

From Barclays, we have Gregg Orrill online.

Gregg Orrill - Barclays Capital, Research Division

Just a follow up on California. Interested in your outlook on carbon prices over the next few years, and then just kind of squaring that up with the disclosure on spark spreads on Page 11, that carbon is a negative impact of $3 to $4 a megawatt hour in spark spreads.

John B. Hill

Yes. No, first, the spark spread that we have listed on Page 11 is a clean spark spread, which we've already backed out the cost occurred in that number just to get to the fact point first. As far as the outlook goes, CO2 in California has continued to kind of bounced above and then back to the floor, with the primary issue being the amount imports that are coming through from the Pacific Northwest and the lack of really pointing to resources in a really firm way there. Those rules have been considered and the question whether that will continue or not. There is also the tie in on, Greg, coming up with Québec, which has not occurred yet. And we view as Québec as a little shorter than California. So there's probably some uplift there. So I think the conservative case is to keep the demand [ph] as demands [ph] rise over the years. I think there's some upside there both from Québec, as well as depending on potential shifts and how to save resources are accounted. So we're watching that and obviously we're involved in the advocacy side.

Gregg Orrill - Barclays Capital, Research Division

That should benefit you over the next few years, and are there changes to the way your contracts work that could impact your margins there with regard to carbon pass-throughs?

John B. Hill

No, materially all of our contracts have carbon pass-through through them. So we contract foreign amount of total price or PPA price, and we get made whole in whatever carbon we have to acquire.

Operator

We will now turn it back to Bryan Kimzey for closing remarks.

W. Bryan Kimzey

Thanks to everyone for participating in our call today. For those of you that joined late, an archive recording of the call will be made available for a limited time on our website. And if you have any further questions, please don't hesitate to call Investor Relations. Thanks again for your interest in Calpine.

Operator

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

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