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Calpine Corporation (NYSE:CPN)

Q1 2012 Earnings Call

April 27, 2012 10:00 AM ET

Executives

Bryan Kimzey – VP, IR

Jack Fusco – President and CEO

Thad Hill – EVP and COO

Zamir Rauf – EVP and CFO

Thad Miller – Chief Legal Officer and Secretary

Analysts

Ameet Thakkar – Banc of America

Paul Fremont – Jefferies

Stephen Byrd – Morgan Stanley

Angie Storozynski – Macquarie Research Equities

Brian Chin – Citigroup

Julien Dumoulin-Smith – UBS

Ali Agha – SunTrust

Ted Durbin – Goldman Sachs

John Cohen – ISI

Keith Stanley – Deutsche Bank

James Dobson – Wunderlich Securities

Brandon Blossman – Tudor Pickering Holt

Gregg Orrill – Barclays

Operator

Good morning, and welcome to the Calpine Corporation First Quarter 2012 Earnings Release Conference Call. My name is Brandon, and I’ll be the operator for today’s call. (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.

Bryan Kimzey

Thank you, operator, and good morning, everyone. I’d like to welcome you to Calpine’s Investor Update Conference Call covering our first quarter 2012 results. Today’s call is being broadcast live over the phone and via webcast, which can be found on our website at www.calpine.com. You will find the access to the webcast, and a copy of the accompanying presentation materials, in the Investor Relations section of our website.

Joining me for this morning’s call are Jack Fusco, our President and Chief Executive Officer; Thad Hill, our Chief Operating Officer; and Zamir Rauf, our Chief Financial Officer. Thad Miller, our Chief Legal Officer, is also with us to address any questions you may have on 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 2011 annual report on Form 10-K, which is on file with the SEC. Additionally, we would like to advise you that the statements made during this call are made as of this date, and listeners to any replay should understand that the passage of time by itself will diminish the quality of these statements.

After our prepared remarks, we’ll open the lines for questions. In the interest of time, each caller will be allowed one question and one follow-up only. I’ll now turn the call over to Jack to lead our presentation.

Jack Fusco

Thank you, Bryan, and good morning, everyone. Thank you for joining us and for your continued interest in Calpine. As we highlighted on our last earning’s call, the current low natural gas price environment is driving opportunities for Calpine that have not existed in the history of the company. Additionally, as you all have witnessed, our strategy has been to deliver to our customers an affordable, reliable and flexible complement of wholesale electric products and services.

The first quarter of 2012 will go down in Calpine history for demonstrating that the combination of our superior asset base, intensive focus on operational excellences, and the strategic geographic positioning of our fleet should accrue to a long-term benefit for our shareholders. As you will note, during the first quarter of 2012, we capitalized on the opportunity by producing record-breaking operating results. We generated the highest-ever first quarter volume of 29 billion kilowatt hours, 52% higher than the first quarter of 2011 despite exceptionally mild winter weather this year.

To put that into perspective, 29 billion kilowatt hours is the same level that we produced during last year’s peak summer period. We achieved these historic results through our continued focus on operational excellence as exemplified by our best-in-class employees. My hat’s off to those men and women of Calpine who delivered a 98% starting reliability with only a 1% forced outage factor, and no lost time incidents.

During the first quarter, natural gas prices continued to decline to levels that now make the Calpine fleet very competitive not only with Central Appalachian but also the cheaper Powder River Basin coals. The relative spread between coal generation and gas generation, combined with our strong operating performance, resulted in solid financial performance of $325 million of adjusted EBITDA, up 7% from the first quarter of 2011. Importantly, you should note that this occurred despite the backdrop of mild winter weather across America resulting in lower-than-normal overall electricity demand. Zamir will cover our financial results in detail later on this call.

On the strategic front, we have stayed focus on pursuing financially disciplined growth in our core markets. Our construction projects in the San Francisco Bay area are on schedule and budget, and we have advanced the development of over 800 megawatts of additional expansion and new power plant development projects in Texas and the Mid-Atlantic. I’ve asked Thad to cover the specifics of our growth initiatives later on this call.

In addition, we achieved several favorable regulatory outcomes during the first quarter that are listed on this slide. Of special note, the Wisconsin Public Service Commission approved Alliant Energy’s proposed purchase of our Riverside plant for approximately $392 million. Alliant has until May 31st to exercise their option to purchase the plant with an estimated closing by year-end.

Based upon the success of our first quarter, improvements in the forward curves in our efficient fleet, we are raising our 2012 adjusted EBITDA guidance range to $1.675 billion to $1.8 billion as shown on the following slide. We are keeping the range $125 million wide, given how early it is in the year and given how we are still open to high-price volatility, particularly in the summer months. Our commercial operations team, led by Steve Pruett, is off to a good start and I have confidence in their continued success. That having been said, we do not anticipate adjusting annual guidance on future first quarter earnings calls. This is a unique situation where the U.S. power generation dispatch profile has experienced some dramatic changes in the past six months, since we first issued our original 2012 guidance.

As I mentioned, a portion of our decision to update guidance is based upon our first quarter results. You’ll hear more about them from Zamir, later in the call. But for now, I’ll simply state that we benefited from a significant increase in generation volume among our merchant fleet, due to unprecedented coal to gas switching. We expect to have the opportunity to capitalize on further coal to gas switching over the balance of the year, primarily in the second and the fourth quarters, based upon a normal weather forecast. Price volatility from extreme weather or supply shortages represents further upside to our projections. As you know, we have historically run our combined cycle power plants most of the time during the summer months, so we would not expect significant on peak volume expansion during the third quarter.

On the following slide, we have refreshed our capital allocation outlook based upon a disciplined review of our business prospects, our credit metrics and available investment opportunities. During the first quarter, we gained increased clarity and confidence in our competitive position in this low natural gas environment, hence our increased guidance for 2012. We have strong liquidity and minimal near-term debt maturities and our projected excess cash balance continues to build, especially with the expected Riverside divestiture.

However, one area in which I’m not pleased with our first quarter performance was our inability to repurchase any shares since our last earnings call, due to an overly conservative execution strategy. As we said when we announced the original $300 million program last August, our intent was to be opportunistic with the execution of the program. However, our price target expectations proved to be too aggressive given the strong share price performance since that call. As a result, we did not take full advantage of the opportunity to repurchase shares at lower prices.

After reviewing our short and long-term financial models, in light of the trends that have developed over the last few months, we are reinvigorated to put more capital to work for our shareholders and have decided to expand our original share repurchase program, in order to return an incremental $300 million of capital. It is very important to put this capital to work and we are reevaluating our execution of the program. The expansion renews our commitment to share repurchases, while balancing growth in liquidity, in order to create long-term shareholder value, bringing our total announced share repurchase program to $600 million, of which $476 million remains to be completed.

Wrapping up my prepared remarks, you may recall last quarter, when I discussed several factors that were trending in Calpine’s favor. I’d like to pick back up on that theme on the following slide, where we list four near and long-term observations that continue to support Calpine’s modern, flexible fleet.

First, the power markets in general are shaping up favorably for efficient natural gas fire generation. Heat rates for this summer in both Texas and the mid-Atlantic, are robust, and California is noticeably improved year-over-year, as hydro levels have been closer to normal. In the Southeast, we remain encouraged by the increased interest of utilities and municipalities in our power plants. Part of these favorable power market trends are the direct result of a sustained shift in fuel cost fundamentals.

Natural gas prices are at lows not seen in a decade. Meanwhile, coal prices continue to clear well above natural gas on a delivered basis. It is important to remember that it’s the spread between coal and gas and not the absolute gas or power price that remains a key economic driver of our business in a low natural gas price environment. Similarly, state actions are trending in our favor and are also influencing the near-term power markets, most notably in Texas, where regulators are content to let the energy only market work and are making progress towards letting scarcity signals be reflected in market prices.

Lastly, with respect to environmental regulations, we remain supportive of regulatory efforts that encourage responsible, yet economic decisions, as we plan for the future of our sector. At the federal level, the EPA has continued to press forward with regulation, most recently having introduced the draft greenhouse gas new source performance standards. Even still, there is more to come with coal combustion byproducts and water intake regulations on the drawing board. As other industry participants consider how to deal with one of more of these issues, Calpine remains well positioned to respond to these regulations, particularly when viewed against the backdrop of low natural gas prices, something few of our peers can claim.

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

Thad Hill

Thank you, Jack. Good morning, to everyone, on the call. As Jack described, we had a strong first quarter both operationally and commercially. Before turning to the point performance let me dwell for a minute on our most important operating statistic; safety. As you can see we finished the first quarter with no employee loss time accidents. Nothing is more important than the safety and well being of our employees. We’re very proud of this achievement and will be celebrating it across the company. A related benefit is of the detailed oriented and diligent approach that comes from a strong safety program also results in our overall improved operations.

As you can see in the upper-right and as Jack mentioned, low gas prices led to record production from our fleet across all regions. One additional point worth mentioning, you’ll note that we’ve listed our first quarter combined cycle capacity factors by region on this chart. While they are considerably higher than in years past you can see we still have ample head room to produce even more. With the dramatic gas price decline in the economy capacity factor of our fleet we have been asked many times what this means for our operations, both from a cost and a reliability standpoint.

On unit availability our fleet turned in an impressive 1.1% force outage factor. Our total operations spend has been roughly flat year-over-year despite the increased megawatt hours. Cost for our non-fuel consumables, primarily chemicals and water have increased but have been offset by reduced maintenance cost. Per megawatt hour fuel cost also benefits from base loaded operations. This quarter our fuel efficiency was nearly 100 heat rate points for almost 1.5% better which meant over $8 million of fuel savings were multiplied through our total production. In short, more and longer run times and fewer stops and starts are like putting highway miles versus city miles on your car. We’re running more, but more efficiently, reliably and with less wear and tear on our machines.

These safety cost and production liability statistics do not come easily, whatever the operating profile as a result of hard work, creativity and perseverance from our Calpine professionals. Slide 21 in the appendix features the honor roll of our clients that have achieved both exceptional availability and safety statistics for the quarter. It is a long list and we are very proud of their strong performance. In light of the strong operational performance we received a number of offset questions around how to think about the economic contribution from our increased run time and the next slide addresses those questions.

So to start, a couple of key market observations, first, as you know our dispatch profile has changed dramatically as demonstrated in the example graph in the upper left. Many of our units shifted from running for a portion of the on peak hours turning for all of the on peak and the off peak. Although overnight we may not be running at maximum output. With lower gas prices it is simply economic to run more. Secondly, the key to understanding the margins is to deconstruct them by time of day.

This is demonstrated by the graph, in the upper right, which breaks out the off-peak, the super peak, and the rest of the on-peak. Put simply, margins are very thin overnight; positive enough to keep the units running and to contribute, but not large. In the super peak for the first quarter, margins were thinner than they were a year-ago, in most regions driven by the extremely mild weather, and the resulting lower-peak electric demand. Meanwhile, in the rest of the on-peak, margins were much higher driven by the lower gas price and competition against coal which was setting the price.

The key financial results of these market observations are, one, more run time in the on-peak with associated margin, particularly outside the super peak periods. And two, to a meaningful but lesser extent, higher off-peak margins on our must-run cogeneration obligations, particularly in Texas where we were previously running through the night at a loss but now are experiencing positive margins.

Zamir will review our quarterly financial performance shortly. Although there are both puts and takes, including capacity market pricing and hedging, the dynamics described on this page benefited us by approximately $40 million in the first quarter.

On the next slide, we update you on our current hedge profile for 2012 through 2014. This slide can also be used to help those of you, so inclined, to model our forward energy margin. In that case, there are a set of modeling tips included in the appendix. Be sure to refer to updates we’ve made since the last quarter.

To simplify the messages contained in the data on this page, I would say three things. First, our 2012 hedge percentage remains at around 80%. Our production expectations have certainly increased, and with it, we have sold into run ups to hearken value. But as we described in the past, we’re maintaining material, but not absolute exposure, to the potential for a Texas summer. We do remain open in other parts of our portfolio, but only the most swing either way, up for down, is likely to come from Texas weather this summer.

Second, for 2012 and beyond, we have sold very little that is not covered in a long-term PPA with the exception of some sales in California so we’ll remain very open heat rates. Third, our position as a result of both the hedges we have put on and the way our portfolio behaves over our gas prices, a short gas 2012, modestly short gas prices for 2013, and roughly neutral gas for 2014. You may recall that we invested considerable time on our last earnings calls discussing the way our portfolio reacts to various gas price environments, as we’ve highlighted with the reminder on this slide.

The next slide provides a brief update on the current outlook for our core markets. First, much has been said about the Texas market. Load is growing, generation is tight, and there are concerns that because through the markets structures, fission generation investment is not occurring. Last year, some of the original protocols for the non-oil market, when combined with generator’s concerns over the risk of enforcement for more aggressive bidding, led to lower pricing that might be expected given supply and demand fundamentals.

Dampening price is, of course, a critical flaw in an energy joule market where you have to produce a megawatt hour to get compensated. After carefully observing the Texas regulators over the last year, we believe this issue is being substantially resolves as the PUCT has been actively addressing some of the shortcomings of the initial nodal protocols and raising price caps. Given this commitment to a functioning and healthy wholesale market, we’ve announce today we are embarking upon expansions at our Deer Park and Channel plants which I’ll discuss in more detail shortly.

Likewise in the Mid-Atlantic, we continue to have confidence that despite some of the activity by certain states, a combination of a well-functioning wholesale market, and attractive fundamentals will not only provide benefit to our existing fleet but is also worthy of additional investment. Longer-term, the older and uncontrolled coal fleet in the mid-Atlantic will feel keenly the impact of lower gas prices and new environmental rules at both the state and federal levels. FERC and PJM have both shown commitment to the minimum offer pricing rule as well as other activities to allow our fair market to work. We think the now more narrowing efforts and the prior New Jersey efforts are in and of themselves unlikely to create significant new market entry. Given this view we plan to bid our 309 megawatt Garrison Energy Center into the upcoming PJM auction. And I’ll provide more information on this momentarily.

Finally, in California, the dominant longer term question is when our market reform. As you know we are very engaged in that discussion with the PUC, the ISO and other market participants with recent discussions around our Sutter plant and how the compensation schemes are failing in modern theme of flexible combined cycle asset and what needs to change over the medium term. Regardless of the Sutter outcome we’re thankful that after the previous two summer, one among the coldest and the other among the wettest on record, that there was opportunity for more interesting energy market this summer.

On the next slide I’d like to provide a few more details on the projects that we have announced today. We have set off that there are only two ways to grow our business profitably. Either one, build under a long term contract. Or two, build or acquire assets at deep discounts to replacement cost. Our announcements today fall into the second category in both Texas and in Mid-Atlantic our unique build economics are better than any buying opportunities in the market.

In Texas, given the use of existing sites, combustion turbans we already own and plants with existing oversized steam turbans where there is room for an additional combustion turban. We will be adding capacity to under $550.00 a kW. Not only will the capacity come cheaply but we will also receive a material benefit to the efficiency of the overall plant by having an additional source of steam versus relying as we sometimes do today on auxiliary blowers and other less efficient steam production methods. In fact, when including those efficiencies on the calculation we were adding new 7,000 heat rate megawatts at closer to $400 per kW. Our commercial and technical teams have worked very hard to bring forward these exceptional opportunities and position us for commercial operations by the summer of 2014.

In Delaware, this story has a twist. There too, we are using an existing owned combustion turbine, as well as a gray market steam turbine purchased at a large discount, but one that has been well cared for and never used. The difference in PJM is that, unlike Texas, generators are required to fund all of the required upgrades to the transmission system. There are PJM development projects that are burdened with nine-figured grid upgrade charges.

A real advantage of our garrison project is that our transmission upgrade costs will be minimal. This did not come accidentally, but because of the acquisition of our mid-Atlantic fleet, we’ve had the opportunity to build a strong team that has invested much time and effort on the ground in the mid-Atlantic, from which this special opportunity emerged. Should we be selected in the eminent PJM option, we expect to complete this project by June 2015 at an all-in cost in the $700 per kW range. For all of these investments, we are essentially acquiring capacity at a five to six times EBITDA multiple.

We’re under no allusions about our business. It is cyclical and although we are very bullish generally from where we are today, we know over the lives of these assets, that it will be good years and bad years. But at the cost basis, we will have in these new facilities. We are comfortable that they were wise investments for our shareholders, not just in the near term, but over the long term.

With that, I’ll turn things over to Zamir.

Zamir Rauf

Thank you, Thad, and good morning, everyone. As you have already heard from Jack, our strong first quarter results, and positive outlook for the balance of the year have allowed us to substantially raise our 2012 guidance.

The chart on the upper-right details some of the big picture drivers for this quarter’s performance, compared to the first quarter of 2011. As you may remember, last February, some of our units in Texas were negatively impacted by extreme winter weather, the financial impact of which is shown in the first green bar.

In addition, and as you have heard Thad describe earlier, this year we benefited by approximately $40 million from improving energy market conditions, primarily through incremental production and higher margins on our overnight must-run commitments. These improvements were offset by lower regulatory capacity revenues, which we discussed with you when we initially provided 2012 guidance in October of last year, along with certain contract expirations and lower hedged margins.

In addition to delivering on our financial guidance, we have continued to make progress towards simplifying our capital structure, most notably by terminating all of the legacy corporate interest rates swaps for $156 million. We accelerated cash settlements for these swaps, that otherwise would have spanned five quarters and in doing so, have removed the final relic of the bankruptcy from our capital structure. Meanwhile, we also completed an unwind of the sale leaseback financing at our Agnews plant and closed on the buyout of some equity holders in our California peaker subsidiary.

Finally, we remain focused on capital allocation. Our strong liquidity, further clarity on the sale of Riverside and the absence of near-term debt maturities, allow us to advance the growth program mentioned earlier, while also doubling our share repurchase program, as Jack mentioned.

Going forward, as a normal course of capital allocation decision making, this may evolve into a continuous share repurchase program, in which we may not announce incremental share repurchase targets, but we would update you on our progress quarterly.

Before we leave this slide, I would also like to mention that as an additional step towards simplifying our balance sheet and providing more transparency to our investors, effective as of this quarter, we have discontinued the application of hedge accounting treatment for our commodity derivative transactions. Many of these transactions already did not receive hedge accounting treatment, so this does not represent a material departure from prior practice. Please note that this change has absolutely no impact on adjusted EBITDA or adjusted recurring free cash flow, both of which have always excluded all unrealized mark-to-market activity.

At Calpine, we have always believed that having a geographically diversified portfolio is important to providing stability of cash flows. The following slide takes a look at our first quarter financial results across all our regions. As you’ve already heard, generation across our regions has increased dramatically, despite a warmer than normal winter. In the West, adjusted EBITDA declined modestly year-over-year, primarily due to the expiration of regulatory capacity contracts and a PPA at the end of 2011. In addition, we received lower contributions from our Geyser hedges, which are linked to absolute power prices.

Moving to Texas. Adjusted EBITDA increased by 145%, due to low natural gas prices and strong operating performance again despite the mild weather. Meanwhile, adjusted EBITDA in the North increased by 6%, also due to strong operations and the lower natural gas price environment, partially offset by the impact of the lower PJM capacity prices. Finally, in the Southeast, adjusted EBITDA was roughly flat. Incremental margin associated with increased output was offset by the negative impact from a PPA that expired as of the end of last year. We remain excited about the potential opportunities to capture tremendous value from our Southeast assets and it is in this region that our commercial origination team is the busiest, as they work hard with our customers to capture value for our assets.

On the following slide, we detail how these results, along with our positive outlook for the balance of the year, translate into our updated guidance. As of today, we are projecting 2012 adjusted EBITDA of $1.675 billion to $1.8 billion and adjusted recurring free cash flow of $470 million to $595 million.

As we work our way down the slide here, a couple of items worth noting. First, you will see that we have added a line item to our adjusted recurring free cash flow related to a one-time acceleration of the purchase of certain turbine parts. Due to the success of our origination efforts last year we secured a contract that provides upside upon the addition of incremental capacity at that related plant.

This is a classic win/win situation where we are adding capacity at an approximately three times adjusted EBITDA multiple. As such we have decided to accelerate upgrades to the plant into 2012 that were originally planned for in future years. The purchase of the parts for this upgrade is what you see in this line item.

Meanwhile, parts in inventory that were previously reserved for regular maintenance this year will be deferred for use in future periods. In sum this is a one-time impact to our 2012 maintenance capital expenditures that will benefit us in future periods.

Towards the bottom of the slide you will notice that we have updated our forecast for growth CapEx which is shown net of any debt financing that we may put in place. We are not projecting to invest approximately $100 million of net growth CapEx this year representing a $90 million increase over our prior guidance.

This increase is related to the Deer Park and Channel expansions as well as the Garrison that Thad previously described. These projects along with the ongoing turbine upgrades represent the type of high-return opportunities that we look to identify across our fleet as part of our disciplined approach to capital allocation.

The following slide refreshes our outlook on sources and uses of capital incorporating all of the announcements we have made today. The cash sources bar on the far left reflects our updated adjusted recurring free cash flow guidance of $470 million to $595 million. With strong liquidity, no material near-term debt maturity and our positive outlook for this year and beyond we feel comfortable in our debt levels and our ability to achieve a 4.5 times net debt to adjust EBITDA ratio. Thus we do not feel any need to aggressively pay down debt beyond the required amortizations and cash sweeps that are reflected on this slide.

Moving further to the right, we’ve incorporated the CapEx related to today’s announced high return growth projects, along with the expansion of our share repurchase program, both of which we have sufficient liquidity to support. You’ll that the growth CapEx currently assumes on balance sheet funding, though we may see construction financing in the future, which would have a positive impact on liquidity.

To the extent that we’re able to monetize additional plans similar to the Riverside example shown here, we will have further opportunities to deploy capital in ways that provide the highest return to our shareholders. As we’ve mentioned in the past, we evaluate all opportunities to deploy capital against the returns of buying back stock. We remain disciplined in our approach to capital allocation and will continue to abide by these principles going forward.

As I’ve mentioned in the past, our capital allocation decisions are not dictated for us. The flexibility of our capital structure and the cleanliness of our modern fleet, allows us to deploy capital in ways that maximize shareholder value. We do not have any material environmental CapEx or pension liabilities. Calpine’s unique position, particularly with respect to our resilience to a lower gas price environment, makes us a generation ahead today.

With that, I’d like to thank you all once again for your time this morning and for your interest in Calpine. Operator, we will now open the lines for questions.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. (Operator Instructions) From Banc of America, we have Ameet Thakkar on line. Please, go ahead.

Ameet Thakkar – Banc of America

Good morning, and congratulations.

Jack Fusco

Oh, thank you, Ameet.

Ameet Thakkar – Banc of America

Just a couple real quick questions, on the – I guess when you guys think about the $75 million increase in 2012 guidance, it looks like you have pickup from I guess not having adverse weather impact in Texas, as you did last year. It looks like your hedged energy margin is actually a couple dollars a megawatt hour lower than what you showed last quarter? Is some of this, I guess the increase in guidance attributable to I guess improvements in your realized O&M costs? Is your kind of not cycling off plants as often?

Jack Fusco

No, well – Ameet, this is Jack. So I would say most – are you talking about the quarter or the guidance overall? I think the guidance overall, we’re very optimistic about where the heat rates have expanded, as gas prices have continued to drop in this market. We’re also optimistic of, in particular, the Texas market and as Jack mentioned California because as well all know California is probably at 65% or 70% of its hydro conditions. So the more analytics we do around our budget and our fleet and the better we are at operating I think we get much more excited about where 2012 could be for us. In particular, but for the quarter, in particular outlets is a mirror answer to the question.

Zamir Rauf

For the quarter, Ameet, yes there was the impact of Texas but it was a very mild winter as we all know and despite that we ran a lot more. As Jack mentioned that just translates into a very optimistic year for us.

Jack Fusco

Specifically to your own end question, when we run more there are regulatory fees associates with the missions. There’s more water. There are more chemicals. In the first quarter we offset those with lower maintenance and we hope to see that continue. I don’t think we expect overall lower on impulse for the year but hopefully we can keep them down to something comparable as we’ve seen before.

Ameet Thakkar – Banc of America

Okay. And then you guys mentioned that you see opportunities for additional incremental volume in 2012 for the second and fourth quarter. Is that relative to what you did in the first quarter or just a year-on-year basis?

Zamir Rauf

It’s the year-on-year basis.

Ameet Thakkar – Banc of America

All right. Thank you very much.

Operator

From Jefferies we have Paul Fremont on line. Please go ahead.

Paul Fremont – Jefferies

Thank you very much. When we think about to cogen facilities and the fact that they’re obviously running all the time and have a steam requirement, how much flexibility is there for you to vary the level of output coming out of those plants?

Thad Hill

Thanks, Paul. It’s Thad. It depends on the plant. In some of the facilities we have the ability at very low prices to not produce or even use auxiliary boilers. There is a number of- last year all peak production was about five million megawatt hours in the first quarter of last year, and that probably pretty good indication of how it was a lot more this year with the lower gas prices. It’s probably pretty good quarterly off peak production just given our requirements.

Jack Fusco

And I’ll just add, Paul, what excites me about the cogen facilities is steam demand. Steam demand from our industrial host is pretty close to where it was pre-recessionary periods back in 2008. So I’m very optimistic about the cogen fleet going forward.

Paul Fremont – Jefferies

And so the two questions, the 147% type margin that you guys talked about on steam sales has that number changed as a result of the low absolute level of gas price?

Zamir Rauf

Steam margin which is based on gas price would be modestly down scaled with gas price that is true. But we’re still very comfortable that our steam contracts are priced very nicely.

Paul Fremont – Jefferies

And the last question there is the expansion of the cogen facilities in Texas, all of that would be available for electric production, right? So you could essentially – you have total flexibility on the expansion part?

Jack Fusco

That is correct. The two new combustion turbines will be merchant and dispatchable as we want to dispatch them.

Paul Fremont – Jefferies

Thank you.

Operator

From Morgan Stanley we have Stephen Byrd online, please go ahead.

Stephen Byrd – Morgan Stanley

Good morning? Zamir, I was wondering if you could just talk a little bit about the state of the construction financing market. You had mentioned earlier the potential over time to possibly using that market to fund part of the CapEx for these new projects. Would you mind just talking broadly to how you see that – how viable an alternative it is in terms of funding part of the CapEx?

Zamir Rauf

It’s very viable Stephen. We have great relationships with some of the project finance banks. A lot of them are partially shut down for business, especially to some of the Europeans, but a lot of them also have some capital for their preferred clients; for lack of a better word. And so if we decide that we need to raise project financing for the construction here it will be a very straightforward process for us. We’re really confident of our ability to do that at attractive rates.

Stephen Byrd – Morgan Stanley

Okay, great. And then just more for Jack and Thaddeus, you think about the southeast and the changes to that market given EPA rules. Could you just talk a little bit more about how you’re seeing that market in terms of the kind of demand you’re seeing for your assets, timing for that demand given there’s MATS coming into full effect in April of 2015. Can you talk a little bit more to how that market is shaping up?

Jack Fusco

Yeah, Stephen. I’ll start and then we’ll have Thad chime in. But I think that scenario where what we call the southeast is very broad. So we tend to deal with our southeast portfolio on a one-by-one basis so we don’t lump in the whole southeast portfolio as being created equal; for lack of a better word. Lot of interest in the southeast right now on our power plants, the origination team is working overtime but it takes time over there and we’re working through – individually and in hand with our customers on what they desire. And it’s our goal to try to monetize those assets as close to replacement values as we possibly can. Thad, I don’t know if you have anything to add.

Stephen Byrd – Morgan Stanley

Great. Thank you very much.

Operator

From Macquarie Research Equities, we have Angie Storozynski on line. Please, go ahead.

Angie Storozynski – Macquarie Research Equities

Thank you. My first questions about the stock buy-back program. You said, Jack, that you were too conservative in the first quarter. Should we imply simply that you’re interested in buying the stock at a lower price than currently in the market?

Jack Fusco

Yes, Angie. That’s a good way to sum up at least the first quarter for us. We, as you know, we had a couple of calls almost back-to-back, right, between our annual call and then the first quarter call. We also ran into our insider trading blackout period, so we weren’t able to modify our program and we were, quite frankly, too aggressive on our share price for the program. So we’re evaluating the program overall, so could try to deploy more capital quickly.

Angie Storozynski – Macquarie Research Equities

But we shouldn’t infer from that, that you think that the stock is overvalued for stock buy-backs?

Jack Fusco

I wouldn’t infer that at all, but I’m not going to get into details on our program though.

Angie Storozynski – Macquarie Research Equities

Okay. The second question is about – you mentioned Entergy joining MISO as a potential positive for yourself, the Eastern assets. Could you talk a little bit more about it?

Jack Fusco

Hey, I’ll let Thad answer that one.

Thad Hill

Hey, Angie. The – we have two assets that are in the Entergy service territory. One of them is under a longer-term contract with Entergy, one of the assets located in Arkansas, the Pine Bluff, a cogeneration facility. When we think the ability to both move power into the Midwest, as well as the potential for capacity payments represent our upside, so we’ll just have to see how it plays out. But it’s generally around – at least in the shorter term, would be around our Pine Bluff facility.

Angie Storozynski – Macquarie Research Equities

And lastly, the incremental steam from those expansions in Texas, would that be sold then, under existing steam contracts?

Jack Fusco

No, Angie. The incremental steam will be used to spin the steam turbine to make more power. So we already have sufficient steam capacity to serve our cogen customers at all of those fleets.

Angie Storozynski – Macquarie Research Equities

Great. Thank you.

Operator

From Citigroup, we have Brian Chin on line. Please, go ahead.

Brian Chin – Citigroup

Hi. Good morning.

Jack Fusco

Hi, Brian.

Brian Chin – Citigroup

First off, the three-plant or expansion announcements, does that exhaust the turbines that you’ve held in inventory now for a little while? Or are there more turbines that you’ve got in storage that you could further deploy beyond these three?

Jack Fusco

Let’s say we’re getting down to the short strokes on amount of available equipment we have leftover. So we still have, I believe on the one other turbine that we can deploy.

Brian Chin – Citigroup

Okay, great. Secondly, you guys have made comments to this in the past that as your plants run more in essence your operating and maintenance costs per megawatt hour are falling. Could you give a sense of just roughly what that dollar per megawatt hour decline has been year-over-year?

Thad Hill

Yeah. Brian, this is – that’s a great question. I would say that it’s probably between, for the O&M, somewhere between $0.05 and $1.

Brian Chin – Citigroup

Somewhere between $0.05 and $1. Okay, great.

Thad Hill

We’ll do probably some more work on that, but I think that’s pretty close.

Brian Chin – Citigroup

Okay, great. And then lastly more of an industry question. There’s been a lot of chatter out there not just from ourselves, a lot of other observers, about whether the utilities might have to execute forced coal burns because inventory levels are very high. Most of the utilities that we have seen comment this quarter have seemed to signal that their individual inventory levels are actually quite manageable here. Are you guys seeing the need for some of the other coal-fired generators out there to do forced coal burns? Kind of what’s your perspective on this?

Thad Hill

Yeah, Brian, I would – at a high level I think it depends on the individual plants. I think the owners of unregulated plants will very aggressively manage because, as you know, when they burn the coals into (inaudible) fuel they’ll drag through their EBITDA. So we suspect they will be very aggressive in managing these coal inventories before they end up with too much. In some of the regulated utilities it is potential you could see some of that, but we’ll just have to wait and see.

Brian Chin – Citigroup

Okay. Thank you.

Operator

Of UBS we have Julien Dumoulin-Smith online. Please, go ahead.

Julien Dumoulin-Smith – UBS

Hi. Good morning. Can you hear me?

Jack Fusco

Yes, Julien.

Julien Dumoulin-Smith – UBS

Excellent. So following up on a question from last quarter here, curious to hear what the latest is on Sutter. As far as I understand, is there some near-term development to be expecting here in terms of your negotiations with the IOUs out there?

Jack Fusco

Julien, thanks for asking question because Mr. Miller here, our Chief Legal Officer, has been waiting to answer a question. Thad?

Thad Miller

Yeah, Julien, as we talked about on the last call the CISO had started an action at FERC which prompted the PUC to look at the issue of Sutter. Since our last call that prompted the PUC to issue an order for the utilities there, the three main utilities, to negotiate with us for Sutter for the balance of this year and perhaps beyond, and we are in fact fulfilling that order by negotiating with the utilities. The deadline for us to report back to the PUC with the utilities and with the independent examiner who is part of that process is on Monday. Those discussions at this point are confidential. But stay tuned.

Julien Dumoulin-Smith – UBS

Great. Perhaps could you comment more broadly where do you see this market going in the back half of the year in terms of depression? I know there’s a number of different avenues this could take but as you see those discussions evolving and perhaps more broadly here how do you see capacity markets structurally in California moving forward?

Jack Fusco

As we also mentioned on the last call, Julien, we see Sutter as a catalyst to get the regulators and the market operators there to focus on those longer term solutions. And there’s two proceedings under way, the long-term power procurement process at the PUC, and the resource adequacy process at the PUC. In parallel we see the ISO working at the product level to create flexibility products.

In the two PUC proceedings that I mentioned, they are still in the process of formulating what issues are going to be addressed in the context of those proceedings. We obviously are advocating strongly to have the longer-term solution for existing assets addressed in those proceedings this year. You can argue which proceeding it’s better to be addressed in. Quite frankly we’re agnostic. We just want it to be addressed in one or the other and I think we’re just going to have to see how that plays out over the balance of this year.

Julien Dumoulin-Smith – UBS

Great. Last question I need on California, with respect to AB 32, we saw some pretty material developments last week. My measure is probably sparks are up about $4.00 megawatt hours over the course of this month. Does that fully reflect at this point in your mind the expectation for implementation next year? And how do you see that panning out into the power markets at this point?

Thad Hill

I’ll talk about the power markets and then I’ll let Mr. Miller discuss implementation. But in our view, given the recent remarks on ton of carbon in California we feel that the current power price pretty fully reflects implementation of AB 32 in 2013.

Thad Miller

In the process, Julien, it’s pretty well publicized. The CARB has changed its schedule a bit by saying it will be a trial run of the auction in August pushing the actual auction off to November. But otherwise from what we can observe CARB is moving full speed ahead. We know the administration there in California is supporting it obviously for the revenues that were approved from the auction. There is also in parallel the CARB looking at linking the Quebec program into the California program, which ultimately could have some effect on pricing as well. We see it basically on track at this point.

Julien Dumoulin-Smith – UBS

Great. Perhaps shifting over to another market here in Texas, I’d be curious. We’ve seen a number of forms adopted over the course of the quarter here.

Bryan Kimzey

Julien, sorry. This is Bryan. We’re going to have to move on to the other question in the queue.

Julien Dumoulin-Smith – UBS

Sure. Go for it.

Operator

From SunTrust we have Ali Agha on line. Please, go ahead.

Ali Agha – SunTrust

Thank you. Good morning.

Jack Fusco

Hi, Ali. Good morning.

Ali Agha – SunTrust

Morning. Jack, you alluded to in your opening remarks that the key gas to coal spread has been one of the key drivers obviously to that extra capacity that you’re able to sell at output. Remind us again from your analysis what’s that rig even going to? What’s that key gas/coal spread that causes the switchover from your analysis?

Jack Fusco

It varies in the different markets, Ali. In Texas I would say it’s around $3.00 in MMBtu or below. In the east coast because of some transportation and distribution costs and other things it’s about $4.00 in MMBtu. I think when we look at the rest of this year and into next year more gases trading, we’re very optimistic about increasing our volumes.

Ali Agha – SunTrust

Okay. My second question, going back to your thought on the capital allocation and as you’re looking at these new projects you talked about what kind of investment to EBITDA, what kind of market poles you’re putting in there. I was just curious. When you talk about EBITDA, particularly in the denominator, are you looking at normalized EBITA? Are you looking at the forward curves at the time the plant comes online? How are you defining that in that analysis?

Zamir Rauf

We’re looking at the forward curves, Ali. We’re looking at the forward view of the market.

Ali Agha – SunTrust

Okay.

Jack Fusco

Some of these plants come on Ali, in 2014.

Ali Agha – SunTrust

Right. Just to clarify, the plant in the PJM, you’re saying if you cleared the auction then you’ll build it, otherwise you won’t go ahead with it. Did I hear that right?

Jack Fusco

You did hear that right. Because of our creativity and the low capital cost of that plant, we’re comfortable and optimistic that it will clear. We’ll find out in a couple of weeks.

Ali Agha – SunTrust

Got it. Thank you.

Jack Fusco

Thank you.

Operator

From Goldman, we have Ted Durbin on the line. Please go ahead.

Ted Durbin – Goldman Sachs

Yes, my question is actually very related to the last one on Garrison there. Are you saying that if you look at the forwards here and maybe where we cleared last year for PJM that would be a go-forward for the project?

Thad Hill

We feel very comfortable with that, yes. Just to address it specifically, yes, kind of the past few prices around were clear to last year, plus the current forwards gets you to the multiple that was just asked in the previous question. But, yes, we’re very comfortable in that kind of environment at this time.

Ted Durbin – Goldman Sachs

Okay. That’s helpful. Then if I can just come back, and I know we’ve been through this before, but you had a pretty material change in the hedge profile there. For the sensitivity gas prices, it looks like $60 million, $80 million. I guess that’s just a function of the higher dispatch. Maybe you could just walk us through the change there versus the prior guidance slide on hedging?

Thad Hill

Sure. So what happens on this page is when heat rates go up, our gas sensitivity increases. When heat rates decline, our gas sensitivity goes the other way. So what’s happened is gas prices dropped, heat rates have rallied in all of our markets, so therefore without changing anything else, our gas sensitivity will increase. So what you’re seeing there on that page in 13 and 14 in the moves, although there are some hedging differences, primarily the big changes have nothing more to do than with kind of heat rate and gas, they’ve moved against each other.

Ted Durbin – Goldman Sachs

Got it. Okay. Thanks. That’s it for me.

Operator

From ISI, we have John Cohen on line. Please, go ahead.

John Cohen – ISI

Thanks. When I look at your hedge profile on Page 11, it looks like you haven’t added very much at all during the quarter for 13 and 14, despite a pretty big run up in heat rates. Should we infer from that, that you think they have more to go or that it’s just not a very liquid market here?

Thad Hill

No, I’m not quite sure. Let me interpret the slide a little differently. As heat rates have expanded, and they have expanded in 2013 and 2014, our delta on expected production off of our assets has increased as well. We have sold a little more in 2013, so the hedge profile doesn’t look that different, but it’s about a similar hedge position but on more volume. And in 2014, the same thing happened in 14. One of the contracts that we’re very proud of is our Oneida contract. We’ve had several transactions off of Oneida we’ve answered. And we have a new PPA beginning in 2014. So again, volume expanded, but the hedge percentage was offset by the fact that we have more megawatts under contract with the new Oneida contract, which kind of, again, makes it look the same. So you should think of similar hedge percentages, but on more volume with 2013 and 2014.

Jack Fusco

Yes, John. Some of our peers give you a hedge percentage off their base-load fleet so they don’t have that flexibility of volume expansion. And ours is based off of our forecast generation.

John Cohen – ISI

I just was asking the question because in your modeling, it looks like you’re pointing people towards using the same volumes in 2013, 2014, but that’s fine. And then I guess the other question I had was – I remember last quarter or maybe two quarters ago you showed a slide calculating the heat rate required for new entry, and I think that was $1,000 kW CGGT. At 550 kW or 400 kW, you’d presume that, that heat rate’s going to be a lot lower. Can you just explain – I mean are there a lot of other opportunities in the Texas market for people that do what you’ve done and at low cost megawatts?

Thad Hill

No, we don’t think so. Certainly, there will be some opportunities for some upgrades that others – we think these are probably among the, if not the most material that are out there by a long shot. Besides steam turbines, we can essentially add a CT and pick up more base loaded 400 intermediate megawatts is a real advantage. I’m not aware of any other plant that has that same opportunity in the market. But, you’re right, I mean we would say the Forbes spark right now in Texas do not yet approach or come that close to approaching what you would need to have a new build and replacement costs. So that’s one of the reasons why these projects are so exciting to us.

John Cohen – ISI

Thank you.

Operator

From Deutsche Bank we have Keith Stanley online. Please, go ahead.

Keith Stanley – Deutsche Bank

Good morning. To follow-up on the guidance increase, should we think of the higher guidance as more a function of Q1 results and volume upside for the fleet, for the balance of the year, given low gas prices? Or should we think of it as more a function of much higher summer heat raise or account in PJM in your decision to stay open in those markets? So I guess my question is there a higher outlook based more in changes in price or volume expectations?

Jack Fusco

I think it’s a little bit of both, Keith. It’s the way I would summarize it but it’ll have Zamir give his view.

Zamir Rauf

No, absolutely a little bit of both. And we have, as we come into the year, our year has been robust for the remainder of the year. Q1 was great. We ran well. We continue to run well and we expect to run well the rest of the year. So all that put together gives us much, more robust view of 2012.

Keith Stanley – Deutsche Bank

Okay. And one other one on the hedging, if you don’t mind. The 19% on hedge position for the balance of 2012, should we assume that relates more to on peak periods in the summer or should we think of that as a balance mix off on peak and off peak volumes?

Jack Fusco

Keith, we don’t get into particular allocations of our hedge and non hedge for obviously commercial reasons. We do have links in all of the areas but as we said on the call, we actually think the spike in all the areas, the biggest swing either way is going to come from Texas and the south.

Keith Stanley – Deutsche Bank

Okay, thank you.

Operator

From Wunderlich Securities we have J. Dobson online, please go ahead.

James Dobson – Wunderlich Securities

Hey, good morning. Hill, I was hoping to revisit the concept of the impact of fewer starts on O&M and maintenance CapEx and I think in a previous question you began to answer these sort of O&M per megawatt hour impact but I’m still struggling with the impact on maintenance CapEx. You recall in the fourth quarter call you sort of described it might push out some but actually pull in others due to longer run times. So I was hoping you could help us understand the impact on maintenance CapEx.

Jack Fusco

Here is what I would say. Overall our run profile where units have been run before absolute pushes out major maintenance and CapEx. Ours will ultimately mean – it will stretch our major maintenance and CapEx but parts of the country where we haven’t run nearly as much as we’ve run before like the southeast for example, where you could pull major maintenance and CapEx in not because of more or less starts or not but just because those machines are now being used more than they were before. So I think overall we stated that the net impact was modest to positive, but I’d still say that. It’s very positive where we’re running a lot – where we used to run a lot and now we’re running a lot more base loaded. But we’ll pull some maintenance in where there are parts of our fleet that just never ran before but are now seeing some action.

James Dobson – Wunderlich Securities

Got you, now that’s really helpful. And then thinking about the second quarter, imagine in history you’d have done sort of your setup maintenance for third quarter in the first and second quarter. Would you expect that there’d be more O&M in the second quarter as we set up and make sure we’re fully ready to run per Jack’s instructions for third quarter or isn’t that stuff you were able to do in first quarter as well?

Jack Fusco

Our outage schedule for this year stood between first and second quarter. I don’t know the exact balance but we’re doing everything we need to do to make sure that we are ready per Jack’s instructions, I promise you that.

James Dobson – Wunderlich Securities

Exactly. But what I’m thinking is relative to history so you would have set up anticipating more run time in first quarter this year. So was more of that shifted to the second quarter relative to the first quarter a year ago or are they really about the same and you’re able to do that despite higher run times?

Jack Fusco

Our major maintenance schedule is set prior to that and – there is part in the first and part in the second – this is our planned maintenance schedule and we’re sticking with our planned maintenance schedule.

James Dobson – Wunderlich Securities

So not really different than history?

Jack Fusco

It shouldn’t be.

James Dobson – Wunderlich Securities

Okay, great. Thank you so much.

Operator

From Tudor Pickering Holt we have Brandon Blossman online, please go ahead.

Brandon Blossman – Tudor Pickering Holt

Morning, guys?

Jack Fusco

Hi, Brandon.

Brandon Blossman – Tudor Pickering Holt

I guess I’ll help out Julian here and finish up his question. On ERCOT market obviously some progress there on market structure and it’s probably through Thad and perhaps Jack too but how far along the past are we for our cut being able to kind of reflect new build economics once the supply demand gets into place to make that happen?

Jack Fusco

All right, Brandon, I’m going to have Thad Miller answer that part of that question. I think he can give you more of an update where we are in the regulatory front.

Thad Miller

Yeah, Brandon, as others on the phone know and we reported on the first quarter call that there were some changes that we had advocated for made in the first quarter on non-spin reserve, responsive reserve right up codifying a process of recalling the multiple units for RMR . Since then we’ve also had them shift 500 megawatts of non-spin route to responsive reserve and a protocol in for proper pricing of the route units so two more definitive steps of progress there.

On the bigger issues which is the system-wide offer cap and the power balance penalty curve they’ve decided to do a Texas two-step there, if you will. This year they have the objective of implementing a new price cap by August 1st that’s going through a combined PUC rule making process and or cut stakeholder process. At the same time but on a longer term basis for implementation in 2013 they’re looking at higher price caps than the $4,500 price cap or the first step of that Texas two-step. And so we think that progress has been made. I’ll let Thad specifically talk to the market impact but we think progress has been made but it’s very important that both ERCOT and the PUC continue to pressure toward the additional changes that I talked about. Thad?

Thad Hill

Sure. In response to what Thad Miller just spoke about we certainly seen sparks increase. So clearly we’ve got confident enough to make some new investments so we’re thankful to the Texas commissioners and the whole regulatory infrastructure for working on making an energy-only market very viable. At afford prices, I think I mentioned this earlier, you need a number in the low-30’s as spikes below 30’s to set forth investment. You have to believe that for 20 years. The Forbes are working their way into the mid-20’s but are still not quite where they will need to be so we view there’s upside still.

Brandon Blossman – Tudor Pickering Holt

The market structure still needs to change a bit to get there.

Jack Fusco

Yes.

Brandon Blossman – Tudor Pickering Holt

All right. Well good progress there at least. Then just a real quick follow-up to the new building competitors out there. Garrison, what does the competition landscape look like on that project versus where you’re able to come in at on a cost basis?

Jack Fusco

I’m not going to discuss where we think other competitors are. As you know, it’s a very complicated environment with the utility self build, with the Maryland RFP, with other merchants. I would just simply say for ours we are extremely pleased with what we think the all-in cost will be on this project. We think it’ll be competitive with anybody under these circumstances.

Zamir Rauf

We think it’s in the right location, Brandon, to ensure that the plant is going to be needed for the long-term. It’s basically in Dover, Delaware.

Brandon Blossman – Tudor Pickering Holt

Okay. That’s helpful. Thank you.

Operator

From Barclays we have Gregg Orrill on line. Please go ahead.

Gregg Orrill – Barclays

Hi. Thanks.

Jack Fusco

Hi, Gregg.

Gregg Orrill – Barclays

Hi. Regarding the work that the Texas PUC is doing to look at the Texas price caps and will probably raise them to $4,500 for this year and then continue to work on that ongoing, how did you think about that from a guidance perspective as you raised the 2012 adjusted EBITDA guidance? Was it in there? Do you think it’s in the forward curves? How did you consider that?

Jack Fusco

No. Brandon, we didn’t get into hourly expectations. Greg. I’m sorry. We didn’t get into hourly expectations. We used our forward curves to help us formulation what our guidance was going to be.

Gregg Orrill – Barclays

Okay. Then I’m not sure if you have this number handy but how much gas did you use in the first quarter? How would that have compared to last year?

Jack Fusco

I don’t think we’ve got that number handy. That’s probably a good number to have handy on these calls. I will tell you for much of the quarter, and this is anecdotal and (inaudible) can follow up with this. We probably burned $700 a day more than we did year-over-year. That’s anecdotal based on a lot of conversations. We’ll do the math.

Gregg Orrill – Barclays

Okay. Thanks a lot.

Jack Fusco

All right. Thank you. Bryan, do you want to...

Operator

Thank you. I will now turn the conference over to Mr. Bryan Kimzey for any final remarks.

Bryan Kimzey

Thanks to 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. Thanks again for your interest in Calpine Corp.

Operator

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

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