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Executives

Christine Parker – Investor Relations

Jack Fusco – President and Chief Executive Officer

Zamir Rauf – Chief Financial Officer

Thad Hill – Chief Operating Officer

Analysts

Ameet Thakkar – Bank of America-Merrill Lynch

Julien Dumoulin-Smith – UBS

Angie Storozynski – Macquarie

Brian Chin – Citi

Ted Durbin – Goldman Sachs

Paul Fremont – Jefferies

Gregg Orrill – Barclays Capital

Brandon Blossman – Tudor, Pickering, Holt & Company

Calpine Corporation (CPN) Q2 2011 Earnings Conference Call July 29, 2011 10:00 AM ET

Operator

Good day, ladies and gentlemen and welcome to the Calpine’s Second Quarter 2011 Earnings Conference Call. As a reminder, today’s presentation is being recorded. At this time, it is my pleasure to turn the call over to Ms. Christine Parker. Please go ahead.

Christine Parker – Investor Relations

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

Joining me for this morning’s call are Jack Fusco, our President and Chief Executive Officer; Thad Hill, our Chief Operating Officer; and Zamir Rauf, our Chief Financial Officer.

Before we begin the presentation, I encourage all listeners to review the Safe Harbor statement included on slide two of the presentation. As a reminder, certain statements made during the call and within the accompanying presentation materials may be deemed forward-looking statements within the meaning of the applicable securities laws. These statements involve certain risks and uncertainties detailed in our most recent filings with the SEC. Should one or more of these risks or uncertainties materialize or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. Additionally, we would like to advice you that statements made during the 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.

Lastly, today’s call and the accompanying presentation materials may reference certain non-GAAP financial measures. Reconciliations of these non-GAAP measures to the most directly comparable GAAP measures are available within the appendix of our presentation materials.

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

Jack Fusco – President and Chief Executive Officer

Thank you, Christine and good morning to everyone and thank you for your interest in Calpine. Since we last spoke back in April, Calpine has continued to make solid progress in our strategic initiatives while maintaining our focus on delivering another quarter of strong results.

Beginning on slide four, let’s cover a few of the more significant accomplishments. Operationally we have adjusted well to the dynamic market conditions we faced across our fleet. With the increase in volatility in our energy markets knowing that we can deliver when called upon as a paramount for achieving our financial objectives.

For Calpine, that translates to a metric we call starting reliability, a measure to ensure our unit startup when they are needed. This quarter we achieved a fleet-wide starting reliability of over 98%, our highest second quarter and year-to-date results on record. While an impressive statistic on its own what makes me even prouder is that the 98% starting reliability was achieved across nearly 4,500 starts during the quarter, up 46% compared to the same quarter last year.

I’d like to give a special thanks to our plant management for a job well done. Their efforts resulted in a production of more than 20 billion kilowatt hours of reliable, affordable power for our customers. At the same time, since the market conditions were mediocre at best, we elected to complete over 80% of our total 2011 plant maintenance projects by the end of June well ahead of schedule.

Our customer origination team performed well. We signed a 10-year gas tolling contract for Carville Energy Center with Entergy. The contract is indicative of the recent uptick in interest we have seen in our Southeast fleet and is consistent with our strategy of monetizing through sale or through contract the value of our assets in the region. As for our committed growth projects, we remain on schedule and on budget with our two construction projects in California, both of which will operate under a 10-year gas tolling contract with PG&E when complete in 2013.

From a financial perspective, we grew adjusted EBITDA by 7% over last year’s second quarter and we improved our operating cash flow by 41%. As you will hear from Zamir later in the call, we are on track to delivering strong adjusted recurring free cash flow this year and are raising our guidance accordingly.

Lastly, on the regulatory front, we have continued our active advocacy for both competitive wholesale markets and environmental regulations at both the state and federal levels. I’ll get into some of the recent environmental developments on the next slide.

Turning to the following slide, the federal regulatory front has clearly dominated the headlines in 2011. First, with the issuance of the draft Toxics rule in March and more recently with the issuance of the final Cross-State Air Pollution rule or what we at Calpine call CSAPR in July. Though CSAPR covers 27 states in the central and eastern portions of the country, much of its press has been related to its inclusion of Texas, which was added to the program prior to the rule’s finalization. Whereas the Toxics rule effectively gave lignite coal-fired plants a free pass, CSAPR does not and becomes the binding rule for power plant generators in Texas.

While it is still early and appeals in lawsuits are highly likely, should the rule remain intact, CSAPR could noticeably alter the supply stack in Texas. Given that in order to comply in 2012 there are really only three compliance pass from many of the state’s large coal-fired plants. Number one, switch to PRB Coal, a cleaner fuel than lignite, if it is accessible, if it is economic, and if they can get it under contract. Two, limit the operations of the unit for some portion of the day or the year or three, where scrubbers are already installed, which is not everywhere, run them more than they are currently running at additional cost.

Analysts have estimated that over 2300 megawatts of capacity in Texas is at risk as a result of CSAPR. In response to this outlook some of the argue that good reliability will be compromised as a byproduct of CSAPR though we disagree. Those units could be available to operate during peak times. But more of this shoulder in off-peak would need to be generated from cleaner burning natural gas plants like those in Calpine’s fleet.

Outside of Texas, the Toxics rule is a binding rule in the eastern half of the country, effectively everywhere that burns primarily Appalachian coals. As a result of the Toxic rules, we continue to foresee the retirement of over 20,000 megawatts of capacity in this area in the coming years. Though the EPA extended the comment period on the Toxics Rule by 30 days, we feel that they remain committed to issuing the final rule on the November 16th deadline, with implementation slated for November 16, 2014.

Finally in California, local regulations are expected to be far more impactful than the federal. As you have already heard, the official implementation of AB32 has been delayed until 2013. We believe that the state as a whole is committed to Carbon Control Regulation that AB32 remains on track for the 2013 implementation.

Furthermore, efficient gas-fired plants and renewable geothermal plants should benefit from this regulation from 2013 and beyond. As the rest of the country considers responsible generation and ways of reducing hazardous emissions including carbon, mercury and nitrous oxides among others, increased reliance on gas-fired generation is an obvious and affordable solution.

Turning to the following slide, we compare the levelized lifetime cost of various technologies against the combined cycle gas turbine burning natural gas. I did not want to get into a debate on the intermittent renewables, so we utilized in most cases EIA numbers and we added published transmission and backup costs.

In a world of scarce financial resources and energy inflation concerns at the forefront, why on earth would be spend two to five times more on our electricity bills, instead of utilizing a relatively clean, reliable, affordable and abundance source of natural gas.

Wouldn't low-cost electricity spur an industrial revolution in America? Making an investment in offshore wind for example in order to reduce carbon emissions implies that carbon reduction is worth over $650 a metric ton, a staggering comparison to the recent Reggie quotes of around $2 a metric ton.

In addition to make a 1000 megawatts of offshore wind competitive to a 1000 megawatt natural gas-fired combined cycle power plant would require nearly $600 million per year in taxpayer or ratepayer subsidies. In a day and age where fiscal rectitude is of utmost importance asking tax payers of its treasury to bear this cost, is a burdensome and unnecessary request.

Before I turn the call over to Thad, I would like to wrap up with some thoughts on capital allocation on the following slide. This has been a point of emphasis for us in 2011 having enhanced our capital structure and improved our flexibility to the successful refinancings we completed back in January. We talked about several inputs that way on our near-term decisions about capital allocation and I think it’s important to put them all into context once again.

First, as you heard me say in the past, have a proven track record of doing what is right for shareholders. The long-term health and prosperity of Calpine is utmost and foremost to my decision making process. My upbringing and work experience has made me a fiscally conservative executive. I am going to make sure that we have enough liquidity to manage the business effectively under any reasonable stress test.

Additionally, we are also going to make sure that we got our leverage targets in sight. So, we can quickly and cheaply access the capital market. Next, we got ensured that we can fully fund our committed growth projects. Just last month, we announced we successfully closed on the project financing of our Russell City project that is already under construction.

With that behind us, we are now focused on securing Los Esteros and though it was not yet complete, we are making very good progress. Additionally, as you will note, we have a significant number of development projects in the pipeline for which we have high expectations of delivering future earnings.

Our focus is to continue to position Calpine to take advantage of future opportunities in markets, where we see fundamentals continuing to shift in our favor. So, long as those opportunities generate returns that are higher than the return of capital to our shareholders.

Moving further down the list, last quarter we announced that we had launched an auction process for Broad River and Mankato Power Plants. As you may recall both assets are relatively new, high quality power plants that operate under long-term contracts with investment-grade utilities.

The responses we got during the auction process were lukewarm and were neutral to negative, when compared to our ongoing ownership of the plants. The plant optionality wasn’t fully valued in the offers including the expansion capabilities in Mankato, where an oversized steam turbine is already in place and capable of servicing another combustion turbine.

For that reason, we have officially included the auction process and we are pleased to retain the plants as part of the Calpine fleet, but clearly we will not be receiving any incremental proceeds as might otherwise have been the case.

And finally, we obviously keep an eye on the economic recovery which we’re hopeful is on the horizon, but realistic that it may take some more patience. In sum, these are the factors that we are weighing when we make up to allocation decisions. As we do so, we consider all alternatives for investment and all tools available at our disposal. We are not committed to any given one of those tools, but instead are committed to the principle of doing what will deliver the most value over the long term for our shareholders.

With that let me turn the call over to Thad Hill for his review of our operational and commercial performance.

Thad Hill – Chief Operating Officer

Thank you Jack, and good morning to those of you on the call. The second quarter of 2011 for the commercial and operations organizations was one of solid performance and progress on a continuum March towards building the premier operating organizations. To list but a few of our accomplishments, the fleet operated well although perhaps short of our very high aspirations. We executed a new 10-year deal with Intergeal for a cargo plant. We began construction of Los Esteros combined cycle conversion helped Zumir’s organization complete the project financing of Russell City and our hedging strategy has remained effective. In natural gas position an almost completely hedged California position and leaving some length in Texas and the East turned out to be the right positions to carry us into the summer that we so far.

The longer term outlook also continues to brighten. Since the new executive management team came to Calpine, we have made tremendous progress reducing cost, improving operating performance and shifting our culture, and we continue to evolve ourselves. We are clear in where we want to take the organization, our expectations for performance are understood and I have every confidence that our team will continue to rise to the challenge.

Our 2012 hedge positions while it is still seemed to be appropriate and in particular our early sign in California heat rate CO2 is still reflected in the price proved to be the right call. And as Jack mentioned many of the long-term trends, some of which I will discuss in more detail continue to work our way. On the following slide we’ll show our usual operating statistics, our safety performance although strong by relative measures still our recent performance and the second quarter we have two loss time accidents. This continues to be a focus point for Jack and me and the broader team and the most important responsibility that we have.

Our first outage performance is in the graph in the lower left. Again by any absolute standard, we experienced good performance for our fleet so far this year on par with where we were at this point in 2010. And more importantly I’ll point out while still an estimate our performance has been exceptional in the month of July. The units have been there as we needed them the most. That said the performance particularly in the west during the second quarter is not an ideal, although as we will discuss further given the extraordinarily weak market conditions. This did not cost us significantly. At a high level we have come across two issues. First we were required to rebuild a generator at our new Otay Mesa plant, disappointing for sure for a new power plant, and second we have experienced a couple of failures to transformers in our fleet. To ensure tha the second issue does not become a more systemic one, we have begun a very aggressive inspection and preventative maintenance program which we believe will be successful.

As has been become our tradition, in the lower right of the slide, we showed the honor plants that have achieved exceptional operational and safety results. My congratulations to the teams that are listed. In the upper right, our production results, our production is roughly flat year-over-year in Texas, Southeast and at the Geysers and also in the North adjusting for the Mid-Atlantic acquisition. However, in the West, even after adjusting for the sale of our Colorado plants, our production is down by half. In fact, our capacity factor for the second quarter was around only 25% in the West region driven down by exceptional hydro conditions continued to persist.

On the next slide, we show our typical hydro disclosure data. Our positions overall have not moved materially from last quarter’s call, but there are several things worth pointing out. First, we are materially hedged in 2011, but as I mentioned, we are almost completely hedged in the west and are more open in our other regions, a position we like given the regional weather and load patterns. Second, in 2012, were open heat rate, but generally flat gas due to the natural offset of our heat rate and gas positions. Maybe more interesting in 2012 like in 2011, our hedges are more tilted towards the West. When heat rates ran up with the probability of the California carbon market or AB 32 being implemented, we begin selling in the West. And in fact for those of you who follow this disclosure closely, you will see that we have moved our 12 hedges up. This is due primarily to selling West heat rates. As a probability of AB 32 implementation in 2012 diminished, heat rates retreated, but we had sold enough that we had actually locked in the CO2 spread for fair portion of our portfolio. In 2013, we are along both gas and heat rate usually expect that we will begin to start trying to capture some of the value of our long synthetic gas portfolio through these two options like we have done in the past.

The following slide tries to explain some dynamics around the summer as well as quick snapshot of thoughts. Starting on 2011, we show our heat rates in our core markets are now versus at the time of the last earnings call. In California, they stayed flat, but at very low levels. I have already mentioned our load capacity factor in the West. As you can see, the primary culprit has been ethic levels of hydro production driven by rain and snowfall levels 60% above last year.

In Texas, although heat rates have ticked modestly up and has been blazing hot, the market has not been as robust as he had hoped given the higher load. Two major factors have impacted us here. First, during June, because of prevailing weather patterns wind levels were unusually strong although that’s not returned to more normal levels. Secondly, as things have gotten tight on specific days and prices responded, ERCOT has deployed non-spin resources, essentially, exceptionally dispatching units to ensure short-term reliability. These deployments negatively impact real-time pricing.

Obviously, ERCOT needs to do what they need to do to ensure that enough units are running. The concerns that surfaced at ERCOT and the PUC that this price dampening impact could affect longer term liability by medium price signals required for investment. A proposal made by ERCOT to fix this is working its way through the stakeholder process and we are very encouraged that it will make a difference if not by late this summer and certainly by next.

Finally, in PJM, the story continues to be that as load increases, oil comes on the margin which provides a very nice price on (indiscernible) gas fleet, which would bring less expensive fuel at a higher efficiency than the price-setting oil-fired unit. Although the weather was not what it was last summer through June, we have certainly enjoyed number of days of this phenomenon and believe it will continue to persist for the next several years.

Moving to the discussion of 2012, you can see the relationship of current heat rates in 2012 versus 2011 forwards. In California, assuming a more normal weather here, the heat rates should be up and they are. However, almost inexplicably to us, the Texas and PJM heat rates continued to be stubbornly backward-dated. Although they have run up in the last several days, this backwardation is not driving us to feel we should aggressively hedge our portfolio.

Absent a double-dip recession, these markets should only continue to get tighter in our economics better. On our last call, we discussed our outlook for the 2014/2015 PJM capacity auction. And since then we have received several questions from investors about the actual results. On the next slide, we show you on the left what our perspective was at the time of our last call. We were (indiscernible) and it turned out rightly so, although we certainly did not call the expansion of the RTO pricing.

Underneath the results are the two factors that made the difference. First, the tip of the iceberg on the coming wave of coal retirements, almost 7,000 megawatts to not get picked up in this auction that were picked up last time. Second, the continued rapid rise in demand response should merit some more discussion. We are deeply concerned about the amount of demand response that has been lifted in these auctions.

Not as Calpine, we are doing fine, but as industry participants concerned about reliability, air quality, and fair markets. As demand response continues to increase, it is moving beyond a pure backup to a resource that will be dispatched with increasing frequency. As can be seen in the chart on the right, with a 7.5% penetration of demand response and a 17.5% reserve margin, DR is expected to be called around five times a year. However, as demand response penetration increases and reserve margins tightened both of which are happening dramatic increases occur. In math, demand response penetration for the 14 to 15 auctions stands at almost 12% given this and a 15% reserve margin in an average summer, we would expect DR to be called nearly 20 times a year, it will be much more in a non-average summer.

Often people confuse demand response with energy efficiency. So I want to make sure that I draw the distinction. Energy efficiency, better insulation, conservation, more efficient lighting has been a part of the equation for a long time. Demand response, however, is something entirely different and there are at least a couple of issues worth mentioning. First, some of the demand response obligation is met by backup diesel generation. On a day when demand is high and the heat and humidity are unrelenting, starting up uncontrolled diesel generators can make air quality worse when it is already at its worst. Doing so creates an environmental issue that states are just beginning to get their hands around. Second, there is a real reliability issue.

As the chart on the lower right shows as DR is increasingly called upon compliance drops, although the example in this page was recent, this harkens back to the interruptible customers of utilities in the late 1990s that took the discount and signed up for the interruptible tariff until they were interrupted much like what happened in Baltimore last Friday. We cannot take this type of risk in our major markets. We are all for demand response as a resource that should compete we are not comparable that it will be there when we needed and as we’ve seen some recent stories in Maryland were providers could not signup enough customers to meet their contracts. We are betting our liability and even our economy on this and their enormous risks and then answer questions. And expect us to be heavily engaged in this debate over the next several months.

Finally, I’d like to turn back to Texas on the next slide. You’ve seen from us the chart on the left that shows by official ERCOT numbers how thin the reserve margin is getting how fast. We say this represents great opportunity for our fleet. We tried to spell the math up a little on the right. The current full year rate as depicted by the blue line is roughly flattish although as I’ve already mentioned some real changes around the deployment of non-spin should certainly help near-term pricing but at a $5.50 gas price in order to encourage new combined cycle investment at full replacement cost the forward heat rate must be up to at least 13,000. This represents almost a doubling of the current spark spread margin. Besides our existing fleet taking advantage of this dynamic, we are dusting off some plans for some low dollar per kW expansion opportunities at two of our plants where we have an oversized steam turbine and can deploy a CT we already own. We were deeply bullish of Texas. The market will work and it’s just a matter of when. But when it does it will be a very good thing for our fleet.

With that I’ll turn things over to Zamir.

Zamir Rauf – Chief Financial Officer

Thank you Thad and good morning everyone. Building upon our successes from last year we have continued to make significant progress on several fronts. Beginning with our capital structure and continuing with our quest of simplifying the balance sheet and adding more flexibility last quarter we announced a refinancing of the $1.3 billion term loan at our NDA subsidiary which we replaced with a very attractively priced term loan at a corporate level. Similarly, during the second quarter we refinanced the Deer Park and Metcalf project debt to a corporate level of term loan which in addition to simplifying things also released restricted cash and eliminated the complexity of preparing separate audited financial statements for the project lenders. We also completed the purchase of 23 million of subsidiary level debt. In addition to completing these transactions we have made great progress to out securing project financing to fund our committed growth projects.

Last month we announced a closing of an $845 million credit facility for Russell City Energy Center at very attractive terms including pricing of LIBOR plus 2.25%. the facility includes a $700 million construction loans and a $145 million letter of credit facility. With that behind us we are focusing on securing funding for the Los Esteros expansion. We are currently in advanced discussions with our banks and expect to close financings during the third quarter.

Finally, I’d like to highlight the significant ground we’ve covered with respect to resolving the lingering impact of a couple of remaining bankruptcy issues. The first and most prominent issue was removing the restricted corporate debt covenants associated with our exit credit facility. As all of you know during the first quarter, we successfully refinanced the last tranche of that legacy facility and migrated all of our corporate debt to an investment grade like covenant package. Beyond the credit facility, we also had some disputed bankruptcy claims that had not yet been resolved. I am very pleased to say that as of the end of the second quarter we have settled all remaining disputed claims are on schedule to complete the final settlement commitment within a week from today.

As many of you may know, we had remaining unreserved approximately 44 million Calpine shares that were authorized but not yet distributed spending the resolution of these disputed claims. Given the fact that all claims are now resolved we have begun distributing the excess shares from the reserve to former unsecured creditors. To-date more than half of the reserved shares have been distributed including those used to settle the claims and we expect to release the remaining shares over the course of the next several months. Please remember that the release of these shares is a non-dilutive event. Reserved shares have always been included in our reported weighted average shares outstanding in all periods and no new equity is being issued as a result of these releases.

The only bankruptcy related items still remaining, but the interest rates swaps associated with our legacy credit facility, which we previously discussed. While the credit facility has been refinanced we are elected to retain the swaps giving the limited downside exposure. These swaps substantially expire in 2012 and we continue to evaluate our options to retain or resolve them in the meantime.

Moving to the next slide, we remain on track to deliver solid performance again this year, despite turbulent markets and extreme weather conditions. As such we are updating and typing our guidance for 2011 adjusted EBITDA to a range of $1.7 billion to $1.75 billion and also raising our 2011 adjusted free cash flow guidance to a range of $475 million to $525 million.

This increase is primarily reflective of the significant cash interest reductions we have generated this year as a result of our refinancing transactions. Meanwhile we are also reaffirming our net growth CapEx estimate of $155 million for 2011, which includes York, Russell City and Los Esteros energy centers along with our ongoing turbine upgrade program.

Turning now to a brief overview of the quarter, we have continue to deliver solid results with adjusted EBITDA increasing by 7% over the second quarter of 2010. As we saw during the first quarter of this year, the year-over-year comparative was meaningful impacted by the changes in our portfolio mainly the acquisition of our Mid-Atlantic fleet in July of 2010 and the sale of our Colorado plants in December of 2010.

In addition the second quarter of 2010 included a $10 million benefit from a rec revenue at the Geysers. As you may recall, though the contracts will effective at the beginning of 2010 we had deferred the associated revenue increases during the first quarter pending the receipt of regulatory approval.

We receive regulatory approval of the contracts in the second quarter of 2010 and therefore recognized the cumulative benefit of the new contracts at hat time. Meanwhile this year during the second quarter, we once again demonstrated our focus on efficiencies with plant operating expenses at our legacy fleet down modestly and SG&A expenses flat compared to last year’s second quarter. Despite a net increase of nearly 3,400 megawatts of capacity across the fleet.

Before we get in to more details on the quarter performance, I would like to call your attention to the graph on the lower right which shows the tremendous progress we have made improving the quality and flexibility of our liquidity. As a result of the financings, and ongoing capital structure simplification efforts over the past couple of years, we have released and migrated a material amount of restricted project cash to the corporate level and this cash is now available to be used for general corporate purposes.

Let’s turn to the next slide to review some of the details of the current quarter performance. In Texas, adjusted EBITDA was relatively flat year-over-year. From a commodity margin perspective higher average hedge prices and higher market heat rates on open positions will offset by the sale of a 25% undivided equity interest in our Freestone power plant in December of 2010.

Texas was also impacted on a comparative basis by the recognition of a $15 million benefit in the second quarter of 2010 related to an adjustment associated with the maintenance contract.

Meanwhile in the west, aside from a $20 million decline associated with the 2010 sale of our Colorado plants, adjusted EBITDA was also negatively impacted in the current year quarter by extreme hydro conditions in California. The benefit in the second quarter of last year associated with the recognition of our Geysers contracts. As I mentioned in the previous slide and to a lesser extend the unscheduled outage at Otay Mesa.

Our Southeast region was also negatively impacted by unscheduled outages along with the expiration of certain hedge contracts that benefited the second quarter of 2010. Offsetting these declines, adjusted EBITDA in our north region was up significant due mainly to the acquisition of our Mid-Atlantic fleet in July of last year.

Wrapping up on the following the slide, the year-to-date results were impacted by many of the same factors I just discussed. In the north, we benefited from the acquisition of our Mid-Atlantic as well as higher spark spreads on open positions for our legacy fleet. These benefits were offset in part by declines in Texas driven by the extreme cold weather event in February along with lower unit availability associated with our plant maintenance schedule in the first quarter of this year.

In addition adjusted EBITDA in our west region was negatively impacted by the sale of the Colorado plant in December of 2010 and the unplanned outages at Otay Mesa during the second quarter of this year. Adjusted EBITDA in the Southeast also declined as a result of unplanned outages during the second quarter as well as the expiration of certain hedges that benefited 2010.

In summary, on a year-to-date basis we are continuing to deliver solid performance on a well track to achieve out updated guidance. Financially we are stronger than we have ever been before and we continue to build equity and generate strong adjusted recurring free cash flow.

The added flexibility of our investment-grade covenant package has given us complete flexibility regarding our ability to continue to make capital allocation decision that are in the best interest of our shareholders. The overhang on the reserve shares is almost behind us at this point and the uncertainty surrounding the bankruptcy claims is over.

With that, I would like to thank you all for your time and I will now turn the call back over to Jack for his concluding remarks.

Jack Fusco – President and Chief Executive Officer

Thank you, Zamir. Wrapping up on our final slide, this year, we spent a lot of time laying out our regional strategic priorities and had been clear about the promising path we see for the future of Calpine. We are ideally position to capitalize on the fundamentals that are shaping the marketplace today and we foresee opportunities, we can expand in our core regions. We remain committed to being the premier operator in the space and believe that those efforts will continue to allow us to deliver value for our shareholders.

I thank you all again for your time today and we will now open the line up for any questions.

Question-and-Answer Session

Operator

We will go first to Ameet Thakkar with Bank of America-Merrill Lynch.

Ameet Thakkar – Bank of America-Merrill Lynch

Good morning.

Jack Fusco

Good morning.

Ameet Thakkar – Bank of America-Merrill Lynch

I just had a couple of quick questions on the Mankato plant. Jack, I think, in your remarks, you mentioned one of the issues you encountered during the sales process was I guess not sufficient value being contributed to the option I guess to expand the plant. Could you tell us how much can the capacity be upsized at that plant and what if any filings have you guys made on your own to pursue that expansion?

Jack Fusco

Ameet, yes, on Mankato directly first on the wholesale process, I would like to say one, that you also get a lot of comfort that we are financially discipline, buyers as well as sellers of power plant assets. The sell process we were trying to be opportunistic and there are a variety of reasons both economic as well as market that it just didn’t happen.

But with Mankato specifically, the steam turbine is oversized and it would be very easy to install another combustion turbine in (indiscernible) that feed the existing equipment and get well over 200 megawatt of additional capacity out of that plant. In fact that’s what our filing has said to the commission up there in response to Xcel wanting to build a new unit in that market. So, its public information and its very detail, it’s in our filings for those of you who are interested. Was there a second half of that question? Ameet

Ameet Thakkar – Bank of America-Merrill Lynch

No, that was it from me.

Jack Fusco

Thank you.

Operator

And we will go next to Julien Dumoulin-Smith with UBS.

Julien Dumoulin-Smith – UBS

Hi, good morning.

Jack Fusco

Good morning

Julien Dumoulin-Smith – UBS

I wanted to ask with respect to some of the new sites you have listed on the PJM development front. I would be curious to hear that your latest thoughts on percent you perceiving those mostly in light of the NEPA changes in PJM and how that could change your long-term contract opportunities in PJM.

Thad Hill

We will certainly on encouraged by some of the suggest that are potential rules that are in PJM as we set all along, although the existing RPM process works great or works well. That has led to a lot of frustration with people concerned about new generation getting added in the corporate amounts and we think that’s quite a very good balance when you refer to existing generation as well as allowing some forward pricing some forward pricing, which can help with new investment. As far as the sites themselves go, we are actively building a set of options in ERCOT of the country and we do believe that the requirement will be material in the middle part of the decade and we think that represents some great opportunity for us steadily through on the ground and we’re making sure that we have permits and interconnection and good sites and the ability to get capacity added cheaply and very effectively and so we'll wait and see how things play out over this year.

Jack Fusco

Our preference is either twofold. Julien, it is either one to get a contract for the put of the facility, or two to be able to sell the facility very quickly and cheaply well below replacement costs.

Julien Dumoulin-Smith – UBS

Great, thank you. And then just perhaps following up on your latest thoughts on the capital allocation specifically share repurchase to the extent you can comment, I’d be curious to hear if you anticipate pursuing any in the back half of this year or is that still probably a 2012 and beyond ambition?

Jack Fusco

For share repurchasing. We think we’ve told everybody in the street that if we pursue it we’re not going to tell you until after we’re complete and that we view the share repurchasing program to be just part of our normal capital allocation decision making process. I know there has been a lot of speculations themselves. But at this point it’s just speculation.

Julien Dumoulin-Smith – UBS

Great. And then finally just a last quick third question here, on the I know you did adjust cash flow rules however you say it, but could you perhaps comment in your anticipation or in your thought do the current 2012 and 2013 forwards reflect the impact of the regulations or do you see further upside here?

Jack Fusco

No Julien. We have not seen forward prices reflect, but we think the rules are as they should, well we say we’re asking for an increase. I will just take Texas as an example. We certainly have seen on peak in the summer and particular forward increase, which we think is driven by forward increases and some of the other factors we talked about. Primarily our view on this will drive offpeak prices and we’ve seen very well or no increase there. So, we don’t think that the thing is necessarily yet been reflected in forward pricing.

Julien Dumoulin-Smith – UBS

Great, well, thank you very much.

Jack Fusco

Thank you.

Operator

And we’ll go next to Angie Storozynski with Macquarie.

Angie Storozynski – Macquarie

Thank you. I have two questions. One, clearly you are cycling your gas blends more, and we also had a bit of a step-up in outages - unplanned outages and maintenance. Is that just a coincidence or is this something that we should incorporate going forward in our estimates of higher maintenance spending?

Jack Fusco

Well, Angie, I only take the first point first, which is cycling units more. In the second quarter, you’re right. We continued to cycle our units more, but those primarily were Western units, which were impacted by the hydro conditions. In the first quarter call we talked about Texas cycling and particularly with regarding to May and June, our up and down in those units are much more in line with our historical norms. So that is kind of work its way through. As far as the outages, the specific outages tended to be as I mentioned transformer issues which are not directly related to the wear on the machine. Cycling definitely increases wear more and that’s built into our expansions around maintenance and the like. But I would not take the quarter outages particularly those in the West they did not have anything to do with cycling.

Thad Hill

Everything we know Angie this year is since the markets were mediocre especially out West. We completed 80% of our schedules major maintenance that we had annualized for the year. We completed all in the first half of the year just to take advantage and for those units would be available for the summer months as well as for the fall.

Angie Storozynski – Macquarie

Okay. Second question is could you explain a little bit more the usage of the non-spin resources in ERCOT in the second quarter and what it looked like in July?

Jack Fusco

Sure, Angie. In June we’ll stack up for a minute. So, ERCOT has been cool. Whenever you start to get near the end of the stack, they can actually burn down a bunch of units. Today the way that pricing mechanism works is the real-time pricing mechanism works as the real time price is what it is, but as soon as those megawatts, and they can be more than 2,000 megawatts in a relatively short amount of time, get deployed, it drives the real-time price down dramatically. So, we saw several circumstances in June where things were tight and prices were in the hundreds of dollars a megawatt hour even, they deployed the non-spin when prices dropped to 40 bucks or 50 bucks. And as you would expect to happen when there's a big injection of generation almost immediately into the stack, that happened in six days is June. It is our view that prices versus where they actually liquidated would have been a lot higher if not on six days had that been put in – had those megawatts not been injected.

The view in fact is that ERCOTs doing what they need to do, short-term reliability is something they absolutely need to focus on, but do that in a way that would kill the forward price signal given how tight the markets can be in this coming year, is a problem. And I think the PUC exit and ERCOT has put a proposal forward to make sure that when that happens it doesn’t impact price going forward and we are very comfortable with that and hopefully it will get its way through the stakeholder process, but it is an ERCOT proposal that shows the state’s concerned around this. As far as your question about July that’s only occurred three days in the month of July so far.

Angie Storozynski – Macquarie

Great. And my last question is you made comments about forward heat rates in ERCOT and clearly, I mean, the market has – maybe the heat rates haven’t gone up as much as in other markets and there is probably limited liquidity going forward, but could you make any comments about potentially, I mean, if you have added any hedges beyond 2013 in any other markets than ERCOT?

Jack Fusco

The only significant long-dated hedges that would have been in our disclosures different this time than prior, Angie, would have been the impact of cargo showing up in our hedge numbers.

Angie Storozynski – Macquarie

Okay. Thank you

Jack Fusco

Which is a long-term contract with Entergy.

Angie Storozynski – Macquarie

Yeah, thanks.

Operator

Our next question comes from Brian Chin with Citi.

Brian Chin – Citi

Hi, good morning.

Jack Fusco

Good morning Brian.

Brian Chin – Citi

We heard earlier this week from Southern Company that their Southeast fleet had experienced pretty substantial increase in utilization factors, but it looks like the Southeast here, with your fleet, didn’t really experience significant increase. Can you talk about some of the reasons why comparisons between the two fleets might not be valid and are those structural reasons going forward? And any sort of extra color on that would be helpful?

Thad Hill

Sure Brian. I think what you have to do is, I mean, we have become Southeast somewhat loosely to talk about an area of geography from South Carolina all the way to Oklahoma. This summer, heat rates grew up substantially in the eastern half of our definition of the Southeast, so where Southern would be located. In fact, TVA heat rates, for example, were up dramatically in almost couple of hundred points second quarter this year over last year. On the other side, FPP which is in the proxy for some of our assets in the western part of the Southeast two greats were actually down substantially for every year. So I think we would agree that we saw lot of more in the kind of near the Southern territory, but a lot less action in the western parts in Southeast.

Jack Fusco

In other words driven by weather.

Thad Hill

Yeah, weather and gas supply pricing and the like, yes.

Brian Chin – Citi

Got it. And then secondarily, given the hydro pack performance out west went down a little bit on 2Q, what’s your thought in terms of how that will spill out into 3Q? Is that something that we should expect to see impact 3Q as well?

Thad Hill

Yeah, I mean, the water is still running. We are starting to see necessarily running overnight as much which means that it’s being impounded a little more for on-peak. So, we are beginning to see the beginning of the end maybe that it would be still be the beginning of the end. It will impact us through call it, the first half volumes.

Brian Chin – Citi

Great. And then last question, on the Broad River and Mankato cancelled transactions, could you give any color on the types of MDs that you saw as having interest? Were they primarily strategic players, private equity? Just give a little bit of flavor on the types of folks that through their hat in the ring?

Jack Fuso

Yeah, it’s something that we want to comment on Brian specifically, but it was all over the math as far as different types of investors that we are initially anticipating in the divestiture.

Brian Chin – Citi

Okay, I understand. Thank you.

Jack Fusco

Thank you.

Operator

And from Goldman Sachs, we will go next to Ted Durbin.

Ted Durbin – Goldman Sachs

Thanks. It sounds like you are getting closer to getting a permit for your Geysers expansion; I think you said fourth quarter. I’m just wondering if you could remind us how much capacity you get there, what kind of CapEx you would be thinking about and if you did get a permit then, would you be thinking about a 2014 COD?

Jack Fusco

We are getting closer to getting the permit. It’s under 50 megawatt rights up 250 megawatts. We had not publicly disclosed the CapEx number and we are continuing to do work on that. We will not build the new Geysers without a contract. The simple forward price curves do not support it. The potential for the TPA it does support as we go on to the renewals projects in California. It’s a very low prospect and we are in dialogue potential customers hold on that right now. But we will not go forward without a contract.

Ted Durbin – Goldman Sachs

Okay, thanks. And then just again say on the expansions, I mean in Texas, you are talking about low dollars per kW. What would you need to see there to move forward? I mean you've talked a lot about how you're bullish there, but what is kind of the next things you will be looking for to actually do an expansion?

Thad Hill

The Texas market is going to work and it is heading for a very tight market and then so we see an appropriate market. I think the clear question is can we get capacity added at low enough dollar per KW we are comfortable owning additional merchant capacities. As Jack said earlier and as we have said before there only two ways to grow either as a long-term contract or you can actually get capacity in the ground really cheap relative to anything it looks like replacement costs. So, we are comfortable with trajectory of the Texas market and so the question for us is, can we deploy this new equipment at existing sites with existing operating steam turbines in conjunction with them and get it done at a price that we will be happy owning the asset in the merchant market and we are working through that.

Ted Durbin – Goldman Sachs

Okay, thanks. That is it for me.

Thad Hill

Thank you.

Operator

Our next question comes from Paul Fremont with Jefferies.

Paul Fremont – Jefferies

Thanks. My first question I guess has to do with lowering the top end of the range of the EBITDA guidance for the year. I assume that the hydro conditions and the pricing in California, is playing a role. What are some of the other drivers there?

Jack Fusco

Paul you are right. I mean the last we hope for normal weather patterns to some day, some year show up in the west. So, that’s the big driver there. The other driver quite frankly is February 2nd. We talked about on the last call. We were not pleased with our performance for those six hours on February 2nd and that had a fairly meaningful impact on us.

Paul Fremont – Jefferies

Okay. If I look at your slide 11, you basically have indicated in the past and continue to indicate that a heat rate relationship per dollar change in gas of 300 BTU per kilowatt hour. In the past year, I think we have seen gas actually decline, but for the most part in most regions, power prices have remained the same. And I’m wondering if this relationship has held up over the past six months or over the past year or whether you see that potentially breaking down?

Thad Hill

No. Paul in fact flat power price that can decline in gas price means in fact heat rates have risen, right. So, the negative correlation that we have talk about is actually there.

Paul Fremont – Jefferies

But at a much faster rate, right?

Thad Hill

But at a much faster rate and in our view we gave a little bit of this in our Analyst Day, but the lower the gas prices, the higher the negative correlation. So, I think we see the number like 170 heat rate point and gas rate is at a much higher price. If it is falling we see that rate increase. So, that is trading for 2430 I would argue that 200 points probably is a little low. However, there is a foreign strip out there kind of we got a review it what in relationship is it different parts along the curve. That obviously won’t come with. So, we will update this number once in a year. But it tend to be is loose property, but you are right. For gas prices means higher negative correlation.

Paul Fremont – Jefferies

And I guess my last question is, given nominal GAAP net income losses, you’ve got huge amounts of NOLs that you could potentially book in the future. Can you give us a sense as to your ability to use those NOLs and when could they begin to sort of materially add to your cash?

Zamir Rauf

Paul, I think with the NOLs, as far as not paying taxes over time, I think that’s a given, but I think strategically there is – there are ways to take advantage of NOLs aside from just positive net income being offset and not paying taxes. So that is something that we continue to look at and over time we hope we will be able to actually create significant value out of those NOLs, because they are worth a lot. I mean, we’ve got $7 billion of NOLs, almost $5.8 million of those are unrestricted and that we can use them immediately. So we have – we definitely have plans in the future for the NOLs.

Paul Fremont – Jefferies

Okay, thank you very much.

Jack Fusco

Thanks Paul.

Operator

Our next question comes from Gregg Orrill with Barclays Capital.

Gregg Orrill – Barclays Capital

Thanks. I wanted to follow-up on CSAPR discussion just to see if you were maybe willing to quantify an impact there, either to power prices in Texas or PJM East or even the impact benefit that Calpine could realize?

Thad Hill

Yeah, hey Greg. I won’t quantify the impact, but let me maybe talk about the dynamics quickly into the markets. In Texas as Jack mentioned, we need to run some scrubbers more. There have been some analyst reports around how much of SO2 could get reduced by running scrubbers and more. When you look at the data out there, people that operate scrubbers in Texas are definitely operating the scrubbers at lower amounts in the summer than they are in the balance of the year. And it looks like you could probably increase summer (indiscernible) about 25% by running scrubbers as they are run year-round. That gets you to the part of the way there. Just switching, if you are an operator of lignite to coal, but not all the lignite facilities actually have rail access to bring in Western coal so that is somewhat more limited

And in our view you end up short, which would mean you’re going to end up over the next couple of years having to operate especially when you get 24 teams for sure, having to operate coal plants less on the shoulders. This provides an uptick in the off-peak heat rates to us although we see it as far less likely that it will impact on PT rates. And but that’s a good thing with the (indiscernible) and how to take that back on the margin in the shoulders. In PJM, and we view that as a very strong impact that will increase and help us over the next couple of years in Texas.

In the east, where the other place it impacts us, primarily given some of the reductions up in PJM the coal burn is already off over the last several years, because of some coal to gas switching. So although there are reduced SO2 that’s allowed, already less SO2 being emitted. Also on the shoulders where you end up with gas much more closely on the margin, so we do think that it will be a marginal help with gas burning more than coal, but we think a lot of that’s already been taken just based on the natural relationship of the gas versus coal pricing already. So a little help there, a lot more help primarily on the shorter months in Texas, especially taking in ‘14, but a little bit cleaner there.

Gregg Orrill – Barclays Capital

Okay, thank you.

Operator

Our next question comes from Brandon Blossman with Tudor, Pickering, Holt & Company.

Brandon Blossman – Tudor, Pickering, Holt & Company

Good morning, guys.

Jack Fusco

Good morning Brandon.

Brandon Blossman – Tudor, Pickering, Holt & Company

Let’s see, I guess a follow-up on page 11, the hedge page, Thad, could you walk through 2013 and the changes quarter-over-quarter on both hedge volume and the hedged margin and kind of comment on how Carville fits into that picture?

Thad Hill

Sure. Carville is the primary change Brandon that occurred in 2013, that’s one of the changes was Carville. The other thing that changed because the 2013 heat rates have expanded, when the 2013 heat rates expand we also get more delta, so the denominator gets bigger if that makes sense. So hedge increase was primarily Cargill. There is a dollar impact there. We also had some expansions of delta. The other thing I should comment about 2013 just so everybody understands, is that Russell City and Los Esteros are included in the 2013 hedge number, although those projects were already expected last quarter.

Brandon Blossman – Tudor, Pickering, Holt & Company

So you added in this quarter that weren’t there last quarter?

Jack Fusco

They were already be in. I just wanted to make it clear that people understood that they were in there. The two changes quarter-over-quarter were the Carville contract and then an expansion in the expected production.

Thad Hill

And further look at the collection, so these denominators getting bigger. Carville would increase the numerator.

Jack Fusco

Carville would increase, yeah, two things happens out there. The number of megawatt hours got moved out to unhedged to hedged would have increased the numerator would have also increased. And on balance that would have probably taken the number down just a little. And then the other thing that happened is an expansion of the breaks that actually increased the number of megawatt hours in the hedged bucket which would otherwise I think the numerator remaining the same shall say that we will have hedged price. does that make sense. And we can get through some of those mechanical term as well.

Brandon Blossman – Tudor, Pickering, Holt & Company

Yes, probably necessary. And then so the implication there is that Carville is lower than your current hedge book as far as value?

Jack Fusco

Yeah, there is no doubt that we are not expecting $70 a megawatt hour as margin offer Carville from that contract, hedged contract or losses. That’s replacement cost.

Brandon Blossman – Tudor, Pickering, Holt & Company

Fair enough. And then probably -- well, for Jack or for Thad here, just big picture, asset A&D market, so a little bit disappointed on your sales process. Sounds like you are looking towards more and more brownfield development. Does that imply that the purchase markets -- the assets that are on the market right now are not attractive to you guys?

Jack Fusco

You know like I expect you all should assume that we’re constantly looking at value creating opportunities in the sector that for us especially after a large fleet in a lot of organic possibilities we don’t need to be fullish with our capital and just do M&A for M&A sakes. So, if you’re asking me branded do I think some of my brand brownfield of opportunities and my expansion opportunities are more value creating, then acquisitions the answer is at this point of time would be yes which is why you see that we’re really expanding our efforts there to make sure our pipeline is full to capture future opportunities.

Brandon Blossman – Tudor, Pickering, Holt & Company

That’s great. Helpful color as always, guys. Thanks.

Jack Fusco

Thanks.

Thad Hill

Anymore?

Operator

And ladies and gentlemen, that does conclude our question and answer session for today. At this time I’d like to turn the call back to Ms. Parker for any closing remark.

Christine Parker – Investor Relations

Thank you everyone for joining us today and if you have any questions please feel free to reach out to the investor relations group. Thank you.

Operator

And ladies and gentlemen that does conclude today's conference. We thank you for your participation.

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