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Calpine Corporation (NYSE:CPN)

Q2 2012 Earnings Conference Call

July 27, 2012 10:00 AM ET

Executives

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

Neil Mehta – Goldman Sachs

Stephen Byrd – Morgan Stanley

Paul Fremont Jefferies & Company

Steve Fleishman – Bank of America Merrill Lynch

Gregg Orrill – Barclays

Angie Storozynski – Macquarie Research Equities

Brian Chin – Citigroup

Julien Dumoulin-Smith – UBS

Brandon Blossman – Tudor, Pickering, Holt

Jon Cohen – ISI Group

Ali Agha – SunTrust Robinson Humphrey

Operator

Good morning, and welcome to the Calpine Corporation Second Quarter 2012 Earnings Release Conference. My name is Brandon, and I will be the operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.

I will now turn the call 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 second quarter of 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 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. 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 A. Fusco

Thank you, Bryan, and thank you everyone for your continued interest in Calpine. The combined cycle gas turbine recovery continues to take hold during the second quarter of 2012. According to the Energy Information administration, during April of 2012 natural gas fire power generation virtually equaled coal fire generation in America for the first time ever. As a result of our excellent operations the beneficial market conditions and the flexibility and competitiveness of our fleet, we produced a record 27 million megawatt hours during the quarter bringing our 2012 year-to-date generation to approximately 56 million megawatt hours. A 44% increase compared to the same period last year and a remarkable 60% of the total generation we produced in 2011 before we even get to the summer period, historically our best quarter of the year.

Our increased productivity drove a 30% comparable reduction in our per megawatt hour operating cost for the first half of 2012 as we held the line on non-fuel plant operating expenses despite the significant increase in generation. I’d like to take this opportunity to thank our plant, engineering and maintenance personnel for their vital contribution to our success. Their focus on our operational excellence yielded our best year-to-date forced outage factor and starting reliability on record, while also achieving the best year-to-date safety performance. I am very proud of these dedicated men and women and I appreciate the vital role they play for our company, our customers and our investors. Thad Hill, will cover our operational performance in more detail later.

Meanwhile, our commercial, regulatory and legal teams have been hard at work managing the volatility in our commodity markets. Optimizing our asset portfolio and defending the integrity of wholesale competitive power markets. As evidenced by their continued progress in the second quarter.

We successfully executed nearly 900 megawatts of new contracts in California and the South East, which will provide reliable capacity in energy for our customers and predictable financial results for our investors. In addition, we were able to achieve a constructive near term resolution for our Sutter Plant in California, while advancing the longer term issue of compensation for flexible capacity procurement in an increasingly intermittent renewable market. In PJM, Calpine cleared just over 4200 megawatts in the 2015, and ’16 capacity auction, at increased prices despite the attempts of two States to subsidize new capacity, exemptions to the minimum offer price rule and questionable demand response initiatives. Efforts are currently underway that should mitigate the impact of those activities in future auctions.

Finally, ERCOT began to address its eminent resource adequacy issues by raising the system wide offer cap as of August 1, while also initiating proceedings to evaluate structural market changes. In each case furthering their efforts to address forecast to declining reserve margins.

Lastly, I would be remiss for not thanking the professionals here at our Houston headquarters for their dedication and hard work behind the scenes that has not only resulted in Calpine leading the IPP sector with their timely financial filings, but also developed the processes and tools to forecast our business going forward.

The combination of favorable secular trends and outstanding operational performance delivered solid financial results during the second quarter. Calpine produced adjusted EBITDA of $403 million for the quarter and $728 million year-to-date. An adjusted recurring free cash flow of $87 million and $60 million respectively. Adjusted recurring free cash flow in the first half of the year is impacted by relatively higher scheduled major maintenance during the shoulder season, such that our cash flow projections are expected to increase substantially during the balance of the year. In fact, based on our strong first half performance and our outlook for the rest of 2012, today we are increasing the lower end of our guidance range by $25 million, tightening the range to $1.7 billion to $1.8 billion of adjusted EBITDA, and $500 million to $600 million of adjusted recurring free cash flow. Zamir, will speak more about our financial results and updated guidance later on the call.

Calpine continues to capitalize of the secular shift towards greater utilization of natural gas technology for power generation. Natural gas generation is becoming the preferred generation of choice since it is cheaper, more efficient, more flexible and environmentally cleaner than coal. Coal fire generation is in the secular decline, facing pressure from both environmental regulations and low natural gas prices. Approximately 40 Gigawatts of coal plants have already announced retirements, much of which are smaller, older, less efficient units. Though many of these retirements have been attributed to the pending environmental regulation, like the Mercury and Air toxic standard, a closer look at the facts suggest that retirement decisions may have nothing to do with environmental regulations at all, and everything to do with economics brought about by sustainable lower natural gas prices. For example, on average the coal plants that have announced in PJM are approximately 58 years old. Some even dating back to the Truman administration. In the current natural gas price environments, coal plants are financially challenged even before considering the installation of expensive environmental retrofits like scrubbers, SCRs and baghouses. As a result, Calpine forecast that coal plant retirement should increase significantly from today’s announced levels as companies re-evaluate the economics of their compliance decisions, especially since the more costly environmental rules like once-through cooling and coal ash disposal are still in their infancy in Washington.

Meanwhile, the energy only power markets in Texas is tightening due to increase load which is expected to grow at twice the national average. Electricity demand in ERCOT is projected to grow up to 3000 megawatts annually, roughly equivalent to four new CCGT plants per year. However, only a few plants are expected to be built during the next couple of years since forward power prices have not risen to the level needed to compensate new build economics, causing projected reserve margin to fall to the mid-single digits by 2015 and increasing the risk to electric reliability.

As the largest operator of combined cycle gas turbines in America, Calpine stands to benefit as a fundamental of these circular trends increase the demand in margins for our existing fleet. Our mid-Atlantic and South-East fleets have already benefited from coal-to-gas switching, but a substantial headroom for increased utilization from coal retirement and demand growth. In addition, power prices must rise in order to incentivize development of new capacity to address tightening power markets. Regulators in Texas already recognize this and have begun raising price caps in order to allow returns to approach new-build economics.

The supply driven market recovery in the East and the demand driven market recovery in Texas are poised to drive value to our existing combined cycle gas fleet. In other words, we are in a great position.

In addition to the secular fundamentals driving an increasing value of our business. The management team has been focused on maximizing long term value for our shareholders through discipline allocation of our investment capital. So far in 2012, we have announced $1.3 billion of capital allocation activities including two Texas power plant expansions, a new Greenfield mid-Atlantic combined cycle power plant and a divestiture of our Riverside Energy Center later this year.

In addition, we‘ve been working to deploy significant capital by buying back our shares. Last quarter we announced the doubling of our share repurchase program to a total of $600 million. At that time, I also told you that I was not satisfied with the execution of the program to that point. Today, I am pleased to announce that we’ve invested a total of approximately $409 million into our share repurchase program, demonstrating significant progress since our last call. During the second quarter, we repurchased approximately 16 million shares of our common stock, bringing our cumulative repurchases to 24.5 million shares. I am encouraged by this progress and we will continue to evaluate further capital allocation opportunities, prioritizing my shareholder’s interest first and foremost.

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

Thad Hill

Thank you, Jack, and good morning to all of you on the call. I am pleased to provide you the second quarter operational update. In summary, I am happy to report that we’ve continued our strong track record of operating our assets so effectively and safely. Commercially, Steve Pruett and our commercial operations team have been agile enough to position us to meet our financial objectives despite a dramatic increase in gas prices in our last call and a much milder summer in Texas we’ve forecast so far.

Our customer effort continuous successfully with new key contracts in the South Eastern California and more in the works and our development in construction efforts are continuing and on track for two California projects, our two Texas projects and our Delaware project.

This slide shows our operational statistics. Safety-wise, we’ve continued to invest considerable resources to create the safest possible work environment for our employees. In the first half of the year we had only one-lost time accident. Exceptional safety performance by any objective measure. But above our goal is zero.

Our fleet has operated with a 2% forced outage factor year-to-date, which is better than our target of 2.5% and far better than last year. We’ve talked about how the greater amount of baseload dispatch that we've experienced this year did oil, gas prices has benefitted our operations. The analogy we use is putting highway miles versus city miles on a car. While that is true, I do not want to take any credit away from John Adams, and the men and women that operate and maintain our plants.

As we’ve matured as an operating organization, changes on how we operate including a step change in our preventive maintenance efforts, more proactive inspections, expanded best practice sharing and a key eye for detail have contributed to this strong performance.

Once again, our megawatt hour production is up year-over-year. This quarter by 37%. In April, the year-over-year production differential was even greater, but as the quarter progress gas prices did rise and summer weather begin to arrive, which means our fleet outside of the west overall begin trending towards more historical seasonal operating parameters. We expect this to hold true for the third quarter as well. In summer, our competitor’s coal units will be running all the time given their inability to turn on and off so that they do not miss peak load.

Looking more closely at our gas fleet in the west, volumes more than doubled in the second quarter, driven largely by more normal hydro conditions in California as well as the nuclear outage.

Finally, we have continued to hold the line on cost. With the higher dispatch comes higher consumable cost. We have more than offset that with our strong operational performance. When the plants run well, not only are they more available to boost revenue, but you don’t spend money to fix them. On a dollar per megawatt basis you can see that our costs has declined by 30% year-to-date, holding costs flat and producing more megawatt hours as they did then.

Turning to our evolving perspectives on the markets on the next slide, in Texas the summer weather has certainly not lived up to expectations. Although, we had some extremely hot days at the end of June and consequently set a new all-time June load record, consistent rain in July and cold weather has prevailed. That said, two points are worth making. One near term and one long term. Near term, our hedging efforts has protected our ability to deliver financial results. In Texas, it has provided protection from downside cases like we have experienced with the weather through July, but leaves us modestly open to upside for which we are still hopeful in August. Longer term, our Texas thesis remains intact. Weather-normalized load growth continues and the regulatory environment continues to improve, with the PUC having largely fixed many of the issues that artificially suppressed prices last year and raising the price caps, while meanwhile kicking off and proceeding to consider other needed and more far reaching market reforms.

We are hopeful that these reforms taken together will provide enough incentive for sufficient resources to make sure there no reliability events. Some of the initial investment most notably our recently launched new-build effort in Central Texas that have cost approaching the $1000 per KW, demonstrates how our existing fleet with no development risk could be valued. In the mid-Atlantic unfortunately, the hottest weather so far this year followed storms that had knocked out much load because of downed power lines in early July. However, we continue to see pricing volatility on high-temperature days and have continued to enjoy that upside.

There’s the much written said around the results of the recent capacity market auction. Given our view that all assets, new and existing should compete fairly we obviously are poised for two State mandate new assets contracting processes that occurred in New Jersey and Maryland. That said, there are several very positive dynamics of the recent auction that are worth exploring. First, demand response in the East actually declined from the last auction. We have expressed concerned around overdependence on a potentially unreliable resource and it does appear it has achieved maximum penetration in the area of PJM, where our assets are primarily located. Further, it is possible this declining trend may continue given the increasing environmental concerns or what we call dirty DR. That is the use of old environmentally uncontrolled diesel gen sets behind the meter.

Secondly, more retirements are likely in PJM. Given the design of the capacity markets, owners of generation are intending to go ahead and bid as a price taker if there is anything but absolute certainty that their asset will retire. So if an asset owner is hopeful for a stay in environmental rule or thinks that the price set may change, they simply bid into the auction. If ultimately they decide to retire the asset, they will have several opportunities to buy back their commitment or otherwise manage their exposure to a modest portion at a clear auction price.

Third, States are through with RFPs at least for now. There is substantial challenges to all three of the projects awarded in Maryland and New Jersey. However, those challenges are ultimately resolved, it is our view that for now at least we are unlikely to see any further efforts. Fourth, PJM appears interested in adjusting MOPR rule to prevent gaming and controversy going forward, which we view as a positive.

The California and South East storage remain regulatory engagement and bi-lateral customer origination respectively. Since the last quarter we’ve had some success with the near term contract for Sutter, mid-term contracts off of Gilroy and Los Medanos, and another contract off of Oneta, which has become one of our most sought after assets. Our regulatory and commercial teams continue to work hard and in particular will be very active in upcoming California proceedings around the future of the market there. And in the South East with our customers on solutions to meet their load needs.

As far as our hedging profile is concerned as you’ll see in the next slide, from an absolute open position on megawatt hours, our position is largely hedged in ’12, but remains open in ’13 and ’14 given our fundamental views, which remain well above the stubbornly depressed forward curves.

Within ’12, much of our remaining exposure is in ERCOT, although I would now characterize that as relatively modest. Meanwhile, given the nature of our fleet in the mid-Atlantic, which is some higher heat rate units in addition to our combined cycles, we tend to produce more megawatt hours, and are implied in this chart when the weather is hot there. So in high temperature days we benefit there as well.

We have re-centered our gas position a bit since last quarter. On the last run down in gas prices, we took positions that had been described as short in 2012 and 2013 and moved them back closer to neutral. We remain long in 2014.

In the next slide, I will return to the topic of how gas prices impact our portfolio.

Finally, it is worth mentioning that we recognize that even with the disclosures on this page and the modeling tips in the appendix, their portfolio is a difficult one to model. We’ve provided updated modeling tips in the appendix that provide some clues on how to think about sparks spreads based on the expected volumes output of our fleet, which we believe will be helpful as you think about generation 2013 and beyond.

On the next slide I want to come back to a topic that has received a fair amount of discussion since gas prices began their precipitous collapse last fall. The economics of our fleet without hedges under different gas price environments. In the first quarter, we disclosed that we benefitted from increased dispatch by our plants due to low gas prices and our gas price displaced coal units in many of our markets despite the mild winter. As demonstrated in the chart on the upper left, this continued through much of the second quarter as well, although it has begun to slow as gas prices have risen and as coal plants began to turn on for the summer.

We have been very pleased with how our fleet and our economics have responded in this lower gas price environment, and we are always going to make more money rather than less money.

We also think it is important to put this incremental margin in context. The investment thesis for Calpine is not the gas prices will be low, but for that matter like many of our competitors, the gas prices will be high. Rather it is that, as markets recover almost the whole new generation will be gas for generation and market prices will rise to incent that investment. As we’ve said, we’d like to put a spade in some of that new required investment but more importantly through rise in market price and we’ll provide our existing fleet with the opportunity to produce much more electricity and more margin than it has today. We demonstrate this important points in the charts in this page and the graph in the lower left, we’ve shown how the average spark spread changes with gas price holding everything else constant in our fleet today. As you can see there is a positive impact from more gas prices. That said the data shows that in the greater scheme we are materially gas price agnostic. Importantly, the incremental margin we do or do not earn at different gas prices is dwarfed by the upside potential from current market signals versus what is required to incent new generation as represented by the orange shading in the graph on the right.

As we’ve described, we think that Texas is in the verge of this type of pricing and believe PJM will be in a similar place around the middle of the decade. This is the investment thesis for Calpine. Some growth from new investment, but large upside to our existing fleet from market recovery.

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

Zamir Rauf

Thank you, Thad, and good morning everyone. I’d like to start today by reviewing some of this quarters key financial achievements. First, as you’ve already heard, we delivered solid results. The chart in the upper right captures some of the main drivers for the first half of 2012 compared to the first half of 2011. The primary ones being improvements in energy markets associated with lower natural gas prices and higher sparks spreads, partially offset by lower regulatory capacity payments and lower contribution from hedges and contracts.

Meanwhile, our continued strong financial performance and positive outlook for the remainder of the year has enabled us to raise the lower end of our 2012 guidance by $25 million. We are now projecting adjusted EBITDA of $1.7 billion to $1.8 billion, an adjusted recurring free cash flow $500 million to $600 million.

Along with delivering exceptional operating results, we have also continued our focus on capital allocation and have made great progress on that front. This year, as Jack mentioned earlier, we have put a significant amount of capital to work. We have invested $238 million in higher return growth projects including ongoing projects financed construction at Russell City and Los Esteros, expansions at Deer Park and Channel, and the construction of Garrison.

At the same time we have bought back $290 million of our stock, bringing the total repurchases to $409 million out of the $600 million program that we announced on our first quarter call. To date, we have repurchased approximately 24.5 million shares and about 5% of total outstanding shares when we launched the program.

With the progress we have made over the past year, we now view buy back as a normal part of our capital allocation process such that we are unlikely to make discreet announcement about increases to the program going forward. You should assume however that we will continue to be opportunistic in deploying our capital. Our capital structure and efficient fleet provides us the flexibility needed to deploy capital efficiently and effectively.

As you can see from the chart on the bottom right, we have no material near term debt maturity that limit our ability to make these decisions. Similarly, we have no significant environmental compliance CapEx and no underfunded pension liability standing in the way of our continued progress.

Before leaving this slide, I’d like to call your attention to the note on the bottom left. Some of you may have noticed that we reported a net loss this quarter of $329 million, compared to $70 million in last year’s second quarter. The largest driver of this year-over-year variance is unrealized or non-cash mark-to-market losses, which primarily resulted from a temporary spike in near term forward prices in Texas during the last week of June in response to extreme heat.

Given our expectation for increase price volatility in Texas over the coming months and years and as we continue to hedge our open positions for future periods, we expect that we will continue to experience similar revenue and earnings volatility. However, please keep in mind that unrealized mark-to-market adjustments have no impact and have always been excluded from adjusted EBITDA and adjusted recurring free cash flow.

With that, let’s turn to the following slide and begin our review of the regional dynamics for this quarter’s results. Overall, second quarter adjusted EBITDA was relatively flat this year compared to last year. Across the country, we benefited from higher utilization of our fleet given the generally low gas prices, particularly in April and May. And given improved spark spreads in several of our markets. Offsetting the benefits of this increased generation, contract expirations and lower contributions from our hedges negatively impacted the west compared to last year’s second quarter. Meanwhile, in the North and similar to the first quarter, lower PJM capacity payments for our mid-Atlantic portfolio impacted this year’s second quarter compared to the prior year period.

Finally, as you’ve already heard we were able to keep planned operating expense essentially flat during the second quarter, while generating significantly more electricity. A true reflection of our focus and excellent operations and prudent cost control.

The following slide shows a similar comparative for the six month period. Adjusted EBITDA increased $19 million to $728 million compared to last year’s first six months. The year-over-year improvement was largely due to an increase in generation volumes across the fleet. Meanwhile, lower capacity revenue in the mid-Atlantic and the expiration of contracts in California and the South East partially offset this year-over-year benefit. Overall, I am very pleased with our performance for the first half of the year.

Turning to the following slide, we continue to focus on liquidity management and capital allocation. As I mentioned in the past, we look to maintain a minimum liquidity balance of $1 billion to conservatively manage the business. With more than twice that available to us at year end 2011, we deployed significant capital over the first half of the year. Most notably in connection with our share buyback program.

During the first half of the year we also retired our legacy interest rate swaps and doing so rid ourselves of the last vestige of the bankruptcy. In addition, we saw a temporary increase in margin associated with the second quarter power price spikes in Texas.

As we look over the rest of the year we project that liquidity will trend back to us at $2 billion level. The majority of our adjusted recurring free cash flow is earned in the back half of the year and as we mentioned, the sale of Riverside is expected to close in the fourth quarter.

In summary, our disciplined approach to capital allocation has allowed us to put a significant amount of capital to work at higher returns for our shareholders. Looking forward, we expect to continue to build liquidity and generate strong adjusted recurring free cash flow and as I have said in the past, we will put our excess capital to work.

The following slide captures how our capital allocation approach supports the Calpine investment thesis, which is about delivering our operating excellence; generating strong financial results supported by favorable industry fundamentals and financially disciplined capital allocation. Over the past year, we have reduced the number of shares outstanding, while continuing to deliver solid financial results, thereby enhancing the value of the remaining shares. Over time, we expect that the rigor we apply to our capital allocation decisions will continue to drive value for the business. Whether to accretive growth, attractively priced divestitures or additional returns of capital to shareholders.

Combining this discipline with favorable industry fundamentals we believe will enhance the per share value of our equity. Our capital allocation decisions have always been driven by returns to equity and free capital per share accretion is the primary metric we have always used. As such, we thought it appropriate to share the same view with you and are today reporting for the first time adjusted recurring free cash flow per share. As you can see on the slide, for the first six months of 2012, we delivered $0.13 of adjusted recurring free cash flow per share compared to $0.04 in the prior year period. More importantly, for the full year, we are expecting a range based on our updated guidance of $1.07 to $1.29 per share compared to a $1.01 per share in 2011.

As we continue to deliver strong free cash flow and opportunistically repurchase our shares, we believe that we will continue to enhance these power share metrics over time and continue to deliver impressive total shareholder returns.

As you’ve heard from us today, we remain focused on operational excellence and disciplined capital allocation. We remain committed to our core business and we remain well positioned for the secular trends that are shaping our industry today.

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

Question-and-Answer Session

Operator

Thank you. (Operator instructions). From Goldman Sachs we have Neil Mehta online. Please go ahead.

Neil Mehta – Goldman Sachs

Jack, Thad, Zamir, how are you? Hello?

Operator

Please standby.

Jack Fusco

Hell. Can you hear us?

Neil Mehta – Goldman Sachs

Yeah. Can you hear me?

Jack Fusco

Great.

Neil Mehta – Goldman Sachs

Great. So just want to talk about coal-to-gas switching trends here. You said in the past $3 an MMBtu in Texas and $4 an MMBtu in the north would be the logical point where you would start to see reversal of coal-to-gas switching. Are those still the right metrics to think about that dynamic?

Thad Hill

Neil, it’s Thad. Yes, I think that’s right. We would begin to see as gas prices moved upwards through the mid twos towards the upper twos, we’ll begin to see our units in Texas not running full out through the night. Now I need to say this also happened at the same time that a lot of coal plants that had been temporarily laid up came back on for summer weather. So there’s a little bit here between the actual everything is on the line and you’re switching on and off based on the economics versus having some coal plants that were laid up. They’re coming back. Yes, generally those numbers are still accurate.

Neil Mehta – Goldman Sachs

Got it. And second question is around capital allocation. Can you just refresh us a little bit about your buyback philosophy here? It sounds like you’re going to continue to be active potentially with buybacks but not just indicate your plans as you go forward with it and how do you think about buybacks versus dividend?

Zamir Rauf

Yes, we are definitely looking at share buybacks as a very accretive way to return capital to our shareholders. One of the things about announcing share buybacks of course is when you do so the market knows that there’s a certain amount of capital coming to work. We believe we’ve developed a history here of returning capital to shareholders and we plan to continue doing that. When we look at capital allocation, we look at free cash flow per share accretion. That’s our primary metric and we evaluate any capital allocation decision we make against buying back our stock. So the extent that an investment is more accretive as you’ve seen with both projects that we’ve announced, then we invest capital in that and to the extent that buying back shares is the most accretive use of our capital that’s what we will do. But we believe that given where the equity is these days it’s definitely attractive and as you can see we’ve been buying a significant amount.

Neil Mehta – Goldman Sachs

Thank you very much.

Operator

From Morgan Stanley we have Stephen Byrd online. Please go ahead.

Stephen Byrd – Morgan Stanley

Good morning. I’m wondering if you could just give a brief update on in the Texas market, whether you see increasing appetites for the institution of either a capacity market or some other form of additional payments to ensure that there are sufficient incentives for new build construction.

Jack Fusco

Stephen, we have the benefit of having Thad Miller with us this morning who is our Chief Legal Officer and he oversees that regulatory group. So I’m going to have Thad Miller answer that question for you.

Thad Miller

Stephen, we certainly have the appetite for it and we think that the stakeholders as well as the PUC realize that something needs to be done in this market and we think the Brattle report has really focused their attention on capacity markets as viable alternative. We’ve already submitted comments in the workshops that the commission is conducting as a follow up to the Brattle report supporting capacity markets and I think over the next couple of months, well over the next month there’s a couple of workshops scheduled and I think we’ll all have a better idea of where the various constituencies may be advocating change. But we feel that the capacity markets will be seriously entertained by the stakeholders, by the commission.

Operator

From Jefferies we have Paul Fremont online. Please go ahead.

Paul Fremont Jefferies & Company

Thank you very much. My first question relates to the, I guess it’s the modeling page where you made changes. You have three sort of buckets of premiums of discounts that are attached to different megawatt hour output levels. So my first question is, which of these megawatt hour output levels should we be expecting in 2012?

Thad Hill

Well, hey Paul, it’s Thad. We’ve announced that year to date we've produce 56 million megawatt hours before the third quarter starts. So while we certainly don’t know where the balance of the year is going to hold, I think it would be hard to imagine us producing less than 95 million megawatt hours this year and beyond that we’ll just have to see how the year goes.

Paul Fremont Jefferies & Company

Okay. But that might imply actually the third category of 105 to 115 as not being unreasonable?

Thad Hill

If you double that you end up in that range. But we just don’t know how the fall is going to play out or if it is tied to gas price.

Paul Fremont Jefferies & Company

And then the second question is, in your modeling tips, you used to talk about assuming two thirds on peak, one third off peak. That’s sort of no longer a part of your how to model the company. How should we think about those percentages based on the higher volume levels that you’re currently at?

Thad Hill

Well, Paul, the reason we have the new disclosure on page 21 in the appendix for those of you looking at it is because that mix is highly dependent on the whole coal to gas switching thing. So rather than give guidance on two thirds, one third, what we’ve done is try and direct you to depending on how many megawatt hours we make which is driven a lot by coal to gas switching to guide to you to a way to think about how to model the margins. So I would just say if you can use the chart on page 21 and I know our IR team will be helpful to walk you through it, very happy to walk you through it. It takes the place of that old two third to one third guidance.

Paul Fremont Jefferies & Company

Okay. But these look more like extrinsic adders than they look like the percentage of time, right? So I guess I’m not following on a percentage basis how this chart really addresses that?

Thad Hill

Let me take one more run at it and then I think we should probably go offline and Christine and Bryan are ready to talk. But as we end up running more off peak we actually begin to – -- the mix goes from the old two third to one third towards more balanced. As that happens, the premium that we would expect to receive over the on-peak price begins to come down because we’re putting more megawatt hours in the mix that are usually lower spark spreads in the overnight hours. And so as that mix shifts this chart should kind of walk you to the right place. But I think the team will be more than happy to walk you through this in detail after the call.

Paul Fremont Jefferies & Company

Thank you.

Operator

From Bank of America we have Steve Fleishman online. Please go ahead.

Steve Fleishman – Bank of America Merrill Lynch

Good morning. Just one follow up on the buyback question. Just to clarify what you said. I believe your authorization right now is $600 million. Is it possible you could go beyond the authorization without kind of announcing that?

Zamir Rauf

Yes, it is possible. Absolutely Steve.

Steve Fleishman – Bank of America Merrill Lynch

You don’t need to announce you’ve expanded the authorization?

Zamir Rauf

Well, it all depends. It’s definitely a legal analysis and you’ve got to build a track record and a trend of a certain behavior. So as we discuss this with our lawyers depending on the amount we may or may not have to announce, but our preference is to not announce and to just increase the program as we go forward.

Steve Fleishman – Bank of America Merrill Lynch

Okay. Thanks for that clarification. And then just on the – maybe just get a little more take of your views on the legal challenges that remain for the subsidized plants in PJM. I think we saw something that there might be a New Jersey decision next week and I think the Maryland contract is still pending. Could you just maybe give a little more color on the likelihood those plants actually get built or not?

Zamir Rauf

Yeah. Steve, let me ask Thad Miller again to take it.

Thad Miller

Well, Steve you’re right. In New Jersey there is an argument on the motion for summary judgment and I think it’s the 30th is the date. We still feel good about that position but the briefings are in the hands of the court and it’s all public information and we’re happy to give you those filings. But we still feel we have a very good position to get a favorable judgment on that. In Maryland we have challenged the Maryland PUC proceeding in the state court. However that proceeding actually in our view probably isn’t even final yet because CPV and the EDCs our understanding is haven’t filed the final agreement and therefore the proceeding can’t be finished until the final agreement is filed. So I think the uncertainty around the finality of that will continue to drag out.

Steve Fleishman – Bank of America Merrill Lynch

Thank you.

Operator

From Barclays we have Gregg Orrill online. Please go ahead.

Gregg Orrill – Barclays

Thanks a lot. I was wondering if you could talk about what you’re seeing in the forward curves in Texas and whether you think the price cap raise recently is priced in and what additional policy actions you think are likely there. I guess we’ve got a workshop today.

Thad Hill

That’s right Greg. On the forward curve we remain very committed in our belief that the forward heat rate curve and spark spreads do not appropriately indicate the fundamentals in the market and that as things continue to tighten the real prices as they liquidate and we’ll continue to rise and we think there’s a lot of upside toward curves. As far as today, Thad Miller already spoke to it, but there’s a workshop today that will take on at least initially address the question around how you think about the reserve margin in Texas and how it should be managed and there will be a follow up workshop in August that talks more specifically around some of the options that the Brattle Group laid out. So we think over the next month or so and really towards the end of September we’ll get a lot better read. But obviously we believe the changes need to be taken. We believe that Texas also believes changes need to be taken and the question is what the changes will ultimately be.

Gregg Orrill – Barclays

Thanks Thad.

Operator

From Macquarie we have Angie Storozynski online. Please go ahead.

Angie Storozynski – Macquarie Research Equities

Thank you. I sort of wanted to start with your sensitivity in natural gas prices. In general I understand what you’re trying to say, but when you’re showing us your sensitivities on the hedge page, how do I reconcile that with your agnostic positions on natural gas when you’re showing me that your dollar change in natural gas price impacts your gross margin by about $350 million?

Thad Hill

Thanks Angie. It’s a good question. So if you just look at 2013 as an example on that page, a dollar move up in gas, holding everything else constant in our portfolio would increase by $350 million gross margin. However, we know that when gas prices increase heat rates are actually negatively correlated and the negative – the sensitivity we have at the bottom of the pages shows that as heat rates, as gas moves up at that – at a 0.5 heat rate will actually move down in heat rates and we actually think as we kind of allude to in the little box on the right that the heat rate correlations at lower gas prices negative correlations are much stronger. So you have to take the two together, Angie. And again these are moves in the entire calendar strip that we’re talking about here, but the important thing is the negative correlations are actually much stronger at lower gas prices. So again we think we are natural in ’13 and long in ’14 based on the embedded negative correlations.

Angie Storozynski – Macquarie Research Equities

Okay. And secondly, it seems like the on-peak spark spread needed to justify new investments is going up every time you guys report and yet we are seeing new projects attempting to enter the market especially in Texas. So how can you reconcile those two? I thought that historically you were saying we need about a $30 on-peak spark spread. Now you’re implying $35 to $40 and yet we have just had plan financed – expensively financed but still financed in Texas.

Thad Hill

That’s right. So the $35 to $40 is across the country. Texas we would argue would be at the lower end of that range, Angie. Other markets though will be at the top end of the range. In regards to your question, $30 to $35, the chart on this page we’ve simplified we do it all on peak. If you were to assume kind of a 5000 hour a year run rate for combined cycle, that number does work its way down closer to $30 a megawatt hour a spark required. But because the on-peak hours in the year don’t equal 5000 hours, they’re actually closer to 4000 hours, if you try and recover everything in the on-peak it moves it up to $35. So it’s a function of how you do the math and in this page we’re just trying to apply on-peak to on-peak.

Angie Storozynski – Macquarie Research Equities

Great. And the last question I promise. Could you tell a little bit, what are we talking here about exceptional dispatch in California?

Thad Hill

What happens is the California ISO over time has used their ability to what we call exceptional dispatch which is dispatch plants and they’ve had issues in the market. And the exceptional dispatch when it is used essentially puts the plant into the stack as a price taker. So it slides the whole rest of the stack out to the right which necessarily lowers pricing. And so we are spending a lot of time working with the Cal ISO and in time with them to ensure that as they take actions they deem that are necessary for market reliability, that it doesn’t negatively impact the overall prices. Very similar to the issue we had last summer with the non-spend issued in Texas. And so the California ISO has committed to try and do the minimum exceptional dispatch they need and we’re watching very closely the conditions in Southern California because obviously we want market prices to reflect scarcity when there is some.

Angie Storozynski – Macquarie Research Equities

Okay. Thank you.

Operator

From Citigroup we have Brian Chin online. Please go ahead.

Brian Chin – Citigroup

Hi. Just going back to the buyback question. If we look at the buyback run rate since you guys started buying back equity, do you think that going forward that that run rate is higher or lower than what you intend to do going forward as a rough gauge?

Zamir Rauf

Hi Brian, this is Zamir. We’ve always said we’re going to be opportunistic with our buyback program and we have been. I think from what you see today it’s definitely opportunistic. We are generating a lot of free cash flow. We are building back our liquidity up to $2 billion by the end of the year. We are going to be generating a lot of free cash flow going forward and to the extent that we have growth projects that are more accretive, we’ll be investing in those. But as I said we’re not going to let grass grow beneath our cash. We will put it to work. And so what rate we buy at is really dependent on what other opportunities we have. But we will be putting our capital to work and Brian that’s one of the reasons we introduced free cash flow per share is that as we move forward over here each share is going to be more valuable, whether it’s from the buyback, whether it’s from the increased free cash flow generation, whether it’s from optimizing the capital structure and reducing interest expense over time, it all accretes to our shareholders.

Brian Chin – Citigroup

Understood. And then one follow up question. On slide 10 you talk about your effective gas position last quarter versus this quarter. When we look at the forward curves they’ve generally bounced up a little bit over the last quarter and yet your position has become what seems to be incrementally a little bit more bullish or less bearish. Can you just talk about in general what are you seeing out there that causes your position on the forward curves to have to change.

Thad Hill

Yes. No, so we made a decision in the second quarter and I don’t want to get too specific about this, that our position certainly was geared short based on the natural operation of our fleet. As gas price falls, clearly we make more money when we’re dispatching against the margin in the markets where that makes sense. And we had captured some real gains in our portfolio and we decided as we saw these big gas burns coming in across the country to go ahead and tilt ourselves back to a little more neutral and so far anyway that was the right call.

Brian Chin – Citigroup

Great. Thank you.

Operator

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

Julien Dumoulin-Smith – UBS

Good morning. So first another question on Texas real quick. We’ve heard some discussion regarding resource adequacy as potentially a third way between a capacity market and scarcity pricing through energy only approach. Would be curious to get your take on what that would look like if that really is a viable pass forward and I’ll leave it open ended.

Thad Hill

Well, Julien, I think some of the debate you’re hearing is around whether or not Texas should set a reserve margin target. For those of you who don’t know and just for a second just step into policy, right now let’s assume that the reserve margin can be wherever it’s going to be, although there’s a soft target out there and the market will drive appropriate reserve margin. That works pretty well when you actually have a load which weighs off if prices get too high. But the load here in Texas is pretty price inelastic. And so when that happens you actually probably or better off setting a reserve margin target and then solving for that economically and that is what ought to be the discussion I think today and we’ll see how it plays out at PUC today and will be around. So if you do set a reserve margin target there are very many different mechanisms so there are the capacity markets or others to kind of what I would argue the first point of discussion.

Julien Dumoulin-Smith – UBS

Great. And maybe with regards to California, you’ve alluded to it a little bit, but just curious, what’s the timeline more than anything about the reforms out there? We talked about it throughout the year but as you look at the back half here, you checked the box here, congrats on Sutter, but where to from here?

Thad Miller

This is Thad Miller again. I think that there are two proceedings out there as we talked about before, long term procurement proceeding and then RA proceeding and they’re still throwing the ball back and forth between those two proceedings in terms of long term structural changes to the market. But we expect both of those proceedings to progress over the course of the late summer and autumn. So we are expecting that we’ll have much better visibility on where California is headed in the last half of this year.

Julien Dumoulin-Smith – UBS

Great. Thank you very much.

Operator

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

Brandon Blossman – Tudor, Pickering, Holt

Morning guys. Thad, just to circle back on the new build in Texas. Obviously you can’t understand exactly what’s in the competitors head there. But $1000 KW Greenfield obviously positive implications for your fleet on a valuation basis. What’s your perspective on that? You guys obviously think it’s a bit too early, but is that a sound bet or are we just way too early on that?

Thad Hill

Brandon, I’m not going to comment on somebody else’s investment. We’ve said several times that we have a hard time doing anything merchant replacement cost given we think there are opportunities over time to acquire or build at deep discounts. Like the acquisition we’ve done or like the two projects that we have under construction or will begin construction this year in Texas. They’re 55% of the placement costs. But that being said we actually are thankful for that project. Texas is growing. The load is growing. PUC predicts between 2,000 and 3,000 megawatts a year and we believe that could be a fair forecast and the most important thing to us is that we don’t end up with reliability issues in the state that threaten the competitive market. So we’re thankful that’s going to happen and we hope that there is some incremental investment which occurs over the next couple of years.

Brandon Blossman – Tudor, Pickering, Holt

Fair enough. And then Jack, accelerating share buybacks indicate that M&A landscape doesn’t look too appealing to you right now. Do you have any general comments on that over the next two, three years?

Jack Fusco

I don’t know about the next two or three years but I could tell you today and what you’ve seen from us is that we believe that that’s probably the single most effective way to return capital back to our shareholders and I wish Brandon there were some more growth opportunities. But you’re going to find from us that we’re fairly conservative and very disciplined on the way we approach our discretionary capital.

Brandon Blossman – Tudor, Pickering, Holt

Fair enough and probably at this point probably good news on the margin. All right, thanks.

Operator

From ISI Group we have John Cohen online. Please go ahead.

Jon Cohen – ISI Group

Hey, good morning. Just have a couple of questions on Texas. I was trying to get my head around what your exposure is for the rest of your year to heat rates in Texas specifically. So if I look at this page 10 is it fair to assume that most of the balance of 2012 is ERCOT given your open position?

Thad Hill

Well, that’s probably not a fair assumption and we don’t give out the regional specifics. Obviously there’s 19% of our megawatt hours for the balance of the year are open. Certainly some of those are in Texas. Some of those are in another market. So we tell you that we think given the potential volatility around outcomes in Texas, that in particular our August position in Texas probably has the biggest swing one way or the other in the balance of the year from an economic outcome. But I wouldn’t try and do the math off this page.

Jon Cohen – ISI Group

Okay. Does it mean 500 Btu is actually not that big a swing for what heat rates can do in August in Texas? So 27 looks small or could actually be quite big depending on how the weather shakes up.

Thad Hill

Yes, we agree with that.

Jon Cohen – ISI Group

Okay. And I guess my other question is, what do you attribute the disappointing prices in July to? How much of that do you think is just weather and load and how much is higher availability of some of these units? We’ve had a couple of days where load has been sort of above the 60 gigawatt range and we still had some disappointing prices.

Thad Hill

Right. Well, it’s been primarily the weather. In our experience if you look back to last year load really has to get materially above 60,000 megawatts to actually get a pop. That’s one by the way the issues that we think the PUC will be taking on is the outcomes in Texas have gotten increasingly digital which is you break a number and I don’t know – we’ve got our views of where it is and you end up with extremely high pricing, but just below that number you end up with the pricing like we got in July. So I would say we think July has been primarily weather driven. We don’t think the line in the sand is 60,000 megawatts and then from a regulatory perspective though this on off number is very hard to construct and build around. And so we’re hopeful that the PUC will continue to address it.

Jon Cohen – ISI Group

Okay thanks. And one last question if I can is on – you might not want to touch this one, but in PJM, if you knew before you bid what the clearing price would be, would you still have the debt unit? Or said another way, how disappointing do you think the outcome in MAC was?

Thad Hill

No, we don’t think the outcome in MAC was that disappointing. We knew – obviously we didn’t know everything about the capacity market before it cleared, but this is a 30 year life investment and one year of capacity price and the pricing cleared the fine and in line with our expectations. We’re making a 30 year investment and we believe the fundamentals as you get deeper into the back half of the decade will continue to improve. So we’re very happy with our decision.

Jon Cohen – ISI Group

Thank you.

Operator

And our final question, from SunTrust we have Ali Agha online. Please go ahead.

Ali Agha – SunTrust Robinson Humphrey

Good morning. Two quick questions. First, Thad, just wanted to clarify the points right at the beginning you talked about the coal to gas switching sensitivity, the $3 rough threshold. So if you look at the forward curve for 2013 on the 360, 370 range on gas, fair to say we should assume less production next year from your fleet than we’re seeing this year? Is that roughly the way to be thinking about this?

Thad Hill

It depends on if you believe the forward curve or not.

Ali Agha – SunTrust Robinson Humphrey

Right. Assuming that forward curve is back of course.

Thad Hill

Clearly, if you believe next year that gas is going to be at 370 versus I think the first year of this year it’s been around 240 or 250 then absolutely our production would be lower year over year holding everything else constant.

Ali Agha – SunTrust Robinson Humphrey

And second question. Jack, from your perspective, the pure play merchant IPP model in the public arena is shrinking rapidly. You’ve got another merger happening. There’s one company in bankruptcy and then there’s you guys. From a philosophical perspective, do you see the merchant IPP model really working in the public equity markets? Who’s your benchmark? How do you see Calpine as a standalone merchant pure play IPP out there?

Jack Fusco

Yes. Ali, I’ve been in this business for well over 30 years so I’ve seen the cycle and first off, I think it’s better that we have financially strong and stable brethren or IPPs or colleagues in this space versus those that aren’t. But when I formed Ryan Power Holdings back in 1998 there were two publicly traded merchants. It was Calpine and AEF and they seemed to get along just fine as far as their abilities to raise capital and then when I took Ryan public there were three or four more that joined shortly thereafter. So it’s a cyclical business. I’m not troubled. There hasn’t been anything announced that wasn’t expected and I’m perfectly comfortable with being the standalone IPP in the space.

Ali Agha – SunTrust Robinson Humphrey

Okay. And using the same history, I was there with you from that point. So would you anticipate more public IPPs possibly to the cyclical the other way?

Jack Fusco

I think it could. As you look as these high bred utilities and you see that the high breds are trading at a discount to the pure play utility, it’s pretty similar Ali to where we were back in the late ‘90s. so I wouldn’t hold it past anybody.

Ali Agha – SunTrust Robinson Humphrey

Understood. Thank you.

Operator

Thank you. I will now turn the call back over to Mr. Bryan Kimzey for any closing 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 Investor Relations. Thanks again for your interest in Calpine Corporation.

Operator

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

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