Calpine's CEO Discusses Q3 2011 Results - Earnings Call Transcript

| About: Calpine Corporation (CPN)

Calpine Corporation (NYSE:CPN)

Q3 2011 Earnings Call

October 28, 2011 10:00 am ET


Bryan Kimzey - VP, IR

Jack Fusco - President and CEO

Thad Hill - COO

Zamir Rauf - CFO

Thad Miller - CLO


Brian Chin - Citigroup

John Cowen - ISI Group

Angie Storozynski – Macquarie

Ameet Thakkar - Bank of America

Julien Dumoulin-Smith - UBS

Michael Worms - BMO Capital


Welcome to the Calpine Corporation Third Quarter Earnings Release Conference Call. My name is Mitchell and I will be your operator for today’s call. (Operator Instructions) Please not that this conference is being recorded. I will now turn the call over to Vice President of Investor Relations Bryan Kimzey. 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 third quarter 2011 results. Today’s call is being broadcast live over the phone and via webcast, which can be found on our website at 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 or Chief Legal Officer is also with us to address any questions you may have on regulatory issues.

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 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 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.

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 material.

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

Jack Fusco

Thank you, Bryan, and good morning to everyone. I first want to start by welcoming Bryan to the Calpine team. As most of you know, Bryan comes to Calpine with a wealth of experience in investment banking, finance, and investor relations, and I am pleased that he has joined us.

On a regrettable more somber note on October 20th, we had a tragic accident at our Geysers power plant. A longtime Geysers employee, Mr. Corky Bracisco suffered a fatal automobile accident. I would like to reassure his family, friends, and our Geysers employees that my thoughts and prayers are with them.

Turning back to our results. We delivered another solid quarter. I challenged our operations team to prove that they can deliver and they kept for lost ground. And I am pleased to report that Calpine’s operating performance during the third quarter was record breaking.

Our overall fleet delivered an impressive 1.9% forced outage factor. Even more impressive was the performance of our Texas fleet 0.9% forced outage factor during one of the hottest and driest summers on record. Our Geysers power plant had 0.3% forced outage factor.

Women in operations and maintenance, thank you. Your efforts resulted in the production of 29 billion kilowatt hours of reliable affordable power for customers. Thad will further discuss our commercial and plant operations result later on this call.

From a financial perspective, we are on target to deliver our 2011 guidance. Adjusted EBITDA increased by 2% through the first nine months of year. The quarter saw slight decrease compared to the third quarter 2010 primarily driven by the sell of our Colorado plant, and sell of minority interest of our Freestone power plant, both of which occurred during December 2010. Zamir will discuss the detailed drivers of our financial results later in the call.

Meanwhile, we continue to make significant progress towards enhancing shareholder value through financially disciplined effective capital allocation, between our growth projects and share repurchase program.

I will cover the status of our growth projects momentarily. As of yesterday though, we have repurchased over 2 million shares. We will continue to execute this program on an opportunistic and financially disciplined basis, considering all available alternatives in our capital allocation decision-making.

Now turning our attention to 2012. We are initiating full year guidance for adjusted EBITDA and adjusted recurring free cash flow at $1.55 billion to $1.75 billion and $375 million to $575 million respectively. This is a wider range than we have typically provided due to the fact that we do not believe the four electricity markets are correctly pricing in the unprecedented regulatory and market outcomes. Therefore, at this moment, we are carrying a substantially larger open or unhedged position for 2012 than we did going into 2011 and prior years.

Zamir will cover the details of the 2012 guidance. But suffice to say, we have a high degree of visibility into incremental upside from 2012 to 2013, with a completion of both the Russell City and Los Esteros projects, as well as increased PJM capacity revenues and the implementation of carbon regulation in California. In longer-term, we believe that we will be able to deliver steadily growing returns to our shareholders, as the economy recovers, environmental regulations take effect, power markets tighten and electricity demand grows.

Turning to the next slide. As I just described, this is an unprecedented time in our industry on both the environmental and competitive market front. There are several pending environmental regulations that are scheduled to take effect in the next few years, as well as changes occurring at the state level in each of our core competitive wholesale markets that provide meaningful upside to Calpine.

This has introduced a level of uncertainty to our commercial development and customer origination business. Calpine continues to actively advocate for environmentally responsible generation in competitive wholesale markets to regulatory and market engagements.

On the environmental front, the EPA’s cross-state air pollution rule is being challenged by group of coal generators in States seeking the stated rule from becoming effective on January 1, 2012. Calpine has intervened to fully support the EPA and its efforts to enforce this long anticipated rule, for which the environmental control technologies have been available for decades.

As for the Utility MACT, as you all know, this week, the court that had ordered the EPA to issue this rule by November 16, granted the EPA’s request for a 30-day extension to issue the final rules by December 16. In both cases, we believe that the EPA remains committed to their timelines and to a meaningful reduction of emissions, which has been a long time coming. We would not be surprised to see continued congressional efforts to blockade EPA action, but remain hopeful that the EPA will stay the course on both CSAPR and the Utility MACT.

With respect to the carbon regulation in California, the formal rules for the state's cap and trade program were adopted last week. We remain supportive of this program and believe we are favorably positioned relative to these regulations.

On the competitive wholesale power market front, New Jersey and now Maryland are attempting to interfere with the PJM capacity and energy markets. Strangely enough, the unintended consequences of the states meddling has further depressed the four price signals and discourage new power plant built, as developers and financers await the outcome. This is exactly opposite of the state’s stated goal of building new plants in the respective areas and hopefully will be lesson other regulators to work within the structure of the competitive markets.

Calpine continues to advocate for unmitigated price discovery, where price signals incentivize and reward new development. Calpine’s regulatory and legislative initiatives include structural market reform in Texas, a commitment to maintaining the integrity of competitive power markets and PJM in non-discriminatory compensation for existing and flexible generation to further integrate renewables in California.

I would like to take a moment to revisit Calpine’s long-term investment thesis on the next slide. Calpine’s value proposition for its shareholders offers a compelling risk adjusted total return. Calpine is an investment in the cleanest, most modern, fuel efficient, large-scale independent power producer in North America, currently trading at a deep discount to replacement costs. Furthermore, we aspire to be the premier power plant company in our sector and have not let our focus stray from developing, building, owning, and operating power plants. There are two primary ways that we’re going to drive value for our shareholders. One, unlocking the intrinsic value of our existing power generation fleet, and two, enhancing value through effective capital allocation.

First, we are well-positioned to unlock the intrinsic value of our fleet from a cost, flexibility and environmental perspective. Natural gas fired generation is the most economic environmentally friendly, reliable, dispatchable technology that can be delivered at scale. Shale gas is providing a stable fuel source at affordable prices, and is forecast to stay that way for the foreseeable future.

In addition, flexible natural gas fire generation like Calpine’s fleet is critical to reliability integrating intermittent renewable generation like wind and solar into their electric grid.

Meanwhile, Calpine has no material environmental liabilities under either the current or proposed environmental regulations, and our combined cycle fleet is operating on average at approximately 50% of its capabilities. Therefore, Calpine is poised to benefit from higher output and higher prices, as our electric wholesale markets recover.

Secondly, as I mentioned earlier, we will enhance value through effective capital allocation. Our priority is to strengthen our balance sheet and show sufficient liquidity to maintain the desired leverage ratio. Over the past year, we have significantly derisked our debt maturities by accessing the capital markets and simplifying the capital structure with an investment grade like covenant package, which we believe, offers us the flexibility necessary to act in our shareholders best interest.

We continue to build a portfolio of options to capture value through financially disciplined growth and customer oriented origination, when the right external conditions materialize. Ultimately though, we waive all capital decisions, against the return of that capital to our shareholders.

I am confident that this management team possess the vision and skill to execute this strategy and unlocking enhanced value for its shareholders.

We discussed our pursuit of financially disciplined growth in more detail on the following slide. At the top, we show the committed projects that are already underway, including the Russell City and Los Esteros construction projects in California, which were on schedule and budget. Additionally, we continue our ongoing turbine upgrade program with 11 turbines upgraded to-date, out of the 19 committed. This list, by itself, is a great example of our philosophy on how we will grow this business in a disciplined manner going forward. We will grow either by, one, building new generation for our customers, where it is supported by a contract that allows to earn adequate returns on our investments or, two, adding new capacity in attractive markets where we can do so at a deep discount to replacement cost.

Beyond these committed projects, we continue to pursue opportunities to grow the business that are consistent with this philosophy, a few of which, I have listed at the bottom of the slide. As you can see, we’ve got opportunities in key markets like ERCOT and PJM where fundamental outlook is extremely bullish to invest at attractive prices.

For the projects in ERCOT, we’ve already begun the permitting process for adding new capacity at two of our existing sites. And in PJM we’re continuing to build a portfolio of options that will position us well for growth in that market, particularly as some of the market uncertainties are resolved.

Meanwhile, we’ve got two additional projects listed here that represent development opportunities for which off-take contracts are required. First, there has been a lot of media coverage lately on our proposed expansion at the geysers. We continue to work closely with the California Regulatory Agencies to get our permit across the finish line. The Mankato expansion is slightly different. We have an existing plant that we propose to expand, and believe, we are the most economic alternative for the Minnesota ratepayers. But we are in competition with the utility self-built.

Between all of these projects, if everything worked in Calpine’s favor, there is an estimated $450 million to $550 million of additional growth capital net of financing that we could deploy over the next few years. Those potential capital needs are forefront in our mind, as we make capital allocation decisions. It is important for us to be positioned to quickly capture opportunities like these as they present themselves.

Now, let me turn the call over to Thad for a closer look at our markets and operations.

Thad Hill

Thank you, Jack, and good morning to those of you on the call. Q3 was a good quarter with some real achievements both operationally and commercially. Operationally, as Jack described, we had a phenomenal quarter, both availability and safety wise; my hat is off to the men and women of the fleet. Commercially (inaudible) protected us from a collapsing gas price, extraordinarily weak weather in the West, and a mild August through September in the east. But they also prevented us from taking advantage of the full upside that remarkable August conditions in Texas represented.

On origination and growth, we had some success in California posting Pastoria under a three-year toll agreement and locking in a capacity there through 2015, with our customers South California Edison. And as Jack referenced, we are pleased with the progress in our construction projects.

In the Southeast the origination deal flows continue to pickup. In a few minutes I will spend a little more time on that to try and give a little more color on how we think about that part of our business. But before turning to normal operational and market updates, I want to pause for a minute and return to the hedging discussion at a philosophical level.

Over the last three years, we have had a philosophy of using the information that our broad geographical footprint affords us to make hedging calls around our expected output. Certainly we haven’t been perfect. But by using the information in equally available to us, given our fleet, some strong analytics and experience, we have done pretty well.

As our numbers depict, and as Zamir will report in a few minutes, we had a solid third quarter. That said it’s important to evaluate as we look at our hedging philosophy for 2012 and 2013.

For this, three factors weigh in favor of a revised more open approach, the potential for regulatory outcome Jack alluded to, market fundamentals tie in in ERCOT and PJM, which I will address in a later slide, and our takeaway from the last two summers that certain markets in certain times of the year provide opportunities for asymmetric outcomes for there is more upside than downside, with Texas this past August being a prime example.

The next slide helps make more sense of the headlines from the third quarter in the markets. In the west a very cold summer last year was followed by a very wet one this year where almost unprecedented hydro conditions dropped prices and volatility. Fortunately, through both hedgings and some new transactions we held the line on commodity margin. Since we have already discussed a bit, but the official load forecast is missed by almost 6000 megawatts because on both weather and a relatively strong economy. The results were very high prices particularly in August. This contrasts with softer market pricing we saw in Q2 when despite the weather and economic conditions market intervention by ERCOT kept prices low.

Our portfolio this year in Texas was 260 some odd megawatts lighter than last year given the sale of 25% of our Freestone plant which closed last December, and as previously discussed, we were highly hedged, but still delivered commodity margin results similar to last year thanks to the impact of the high prices on our open position.

At PJM, 2011 pricing did not achieve the year rates we achieved in 2010. Specifically although July was warm, August and September were not. That said, on days when the heat did show up all units were required to run and set the price which provides a very nice price umbrella for us since we burn relatively cheap gas in efficient combined cycle natural gas plants. There were just far fewer these days in Q3 this year versus Q3 last year. Despite this because we are hedging approach of locking in August and September when pricing was high and because our York plant went operational earlier this year we delivered a similar commodity margin result year-over-year.

The next slide covers our plant operating results which was already described as outstanding. Safety, while no loss time accidents in the third quarter something we're all proud of, unfortunately and tragically as Jack mentioned, however, we had an employee perish in an automobile while working in our geysers operation in northern California.

Our forced outage performance for the third quarter was strong. We achieved 1.9% versus our goal of 2.5%. Even more remarkable is our performance in Texas when we needed the units the most they were there for us. Given the extraordinary conditions we moved to almost a full base load operation for the month of August. Our plant staff showed commitment and expertise to keep our units up and running. I am thankful for and congratulate their efforts. But their performance was also strong in our other regions, most notably, the north. Our honor roll of plants with less than 2% forced outage factor and no recordable injuries is in the lower right, a good list.

The next slide addresses our outlook in commercial strategy for the different markets. In California, with a potential for a return to more normal weather, key rates in 2012 are up over 2011 liquidation levels, but only modestly. 2013 is looking likely for implementation of California’s carbon cap and trade program. And as you can see it is clearly reflected in the forward year rates. All of that said, the real medium-term question for California remains how owners are flexible fossil generation will be compensated for the benefits they provide to assist them that is increasingly dependent on intermittent generation. The PUC and [ISOR] are both actively working this issue and we are fully engaged.

In ERCOT, forward year rates have risen as a result of this summer's pricing activity in August and perhaps more modestly because of CSAPR. Although still and explicably the forward year rates in 2013 are lower than 2012 and generally forward year rates have been in levels far too low to encourage new investment. Clearly, load is growing in Texas and new investment is required soon. The forward pricing signals are just now working, why? There is both a short-term and a long-term issue. The shorter-term issue really has two primarily components. First there is some actions at ERCOT this summer to maintain reliability, the deployment in non-spending reserves as well as resurrection of some off body units interstate contract had a negative impact on pricing.

Secondly, the definition of market power in Texas and the associated bidding rules are very unclear. It is our view that many competitor restrain otherwise rational bidding behavior because of fear of action has occurred in the past.

The longer-term issue is the fact they get into the retail structure in Texas and their typical one-year contract with customers, there are virtually no wholesale buyers of power beyond a one-year term, which puts negative technical pressure on heat rates. Although there is no serious dialogue right now, on the longer-term issue, the shorter-term issues are very much employed and a resolution of any of them will be tremendously helpful.

We are actively engaged, as are others, and believe that Texas will allow the market to work as a must. Texas represents a great opportunity for Calpine over the next several years, both for our existing fleet, as well as for new investments in the low dollar per KW projects that Jack mentioned.

Finally, on PJM, the forward markets have also moved out again probably because of CSAPR, they’re more driven by the lower gas price and the impact that has on less efficient coal plants. Like Texas, the backwardation is also generally hard to understand. There is lots of intrigue at the moment, but the PJM effort on new entry pricing, New Jersey’s efforts, the recently announced Maryland RFP and it’s various iterations et cetera. But there are really two simple point you with. First, between now and 2015 these gyrations over capacity markets will have very little effect. There is very little under construction, retirements will start mounting, and we will remain on the marginal key days in the summer. There is nothing at all bearish about the near-term situation.

Secondly, in the middle term, we think the story is also bullish. Despite the regular capacity market dynamics that Jack described the fundamentals are strong. The combination of many old uncontrolled coal plants, oil gas prices, and tough environmental rules will lead to significant retirements. In short, there is room and need for new capacity, some of which we hope will be ours.

We take a lot of questions from the Southeast and thought it would be worth a slide to explain our thinking in a little more detail. First, two base assumptions for the discussion. First the Southeast at least the part including VACAR, Southern, and the TVA will be approaching equal very much faster than most people realize. Utility procurement plants are falling a bit behind the curve, because of the expanding list of retirements given the regions old units, higher coal prices, lower gas prices, and the air toxics rule, or in some cases, because of large nuclear projects then they will be falling behind schedule. We have seen a noticeable uptick in discussions with hard utilities and with public power around interest in asset contracting starting mid decade.

Secondly, there have been some M&A transactions that have set a price for Southeast combined cycles in the low to mid $400 million per KW range. As a note, for most combined cycles without contracts in the Southeast today, this value would deliver an impressive EBITDA multiple. Given these points, we ask ourselves what our best path forward is in the Southeast. We believe that there will be ample opportunity to contract or to otherwise monetize our plants over the next several years that will imply value materially above the current asset trading range in the region. Given Calpine history, a large extent a combined cycle recovery story to begin with, we believe that are right type of owner of these assets for now. And given our investment and our origination efforts, we feel we have the people and increasingly the relationships to manage through this. And anyway we will keep you updated on our efforts.

I will wrap up my prepared remarks on the usual hedge disclosure slide. This is a complicated slide and we bought some information, then we combine with our modeling tip slide in the appendix, can be helpful to those trying to model Calpine’s economics. Our Investor Relations team stands by to answer any questions you may have.

All that said, I will restrict my comments to the major enrollment business points in this page and there are two. First, to address 2012 and changes from the last call, our hedge position has increased to 63% from 52% since the second quarter call. However, parking back to some of opening comments, we are hedging 2012 a bit differently than 2011, in both Texas and PJM we are seeing some historically high spark spreads, despite lower gas price in the winter and chiller months. We have been selling there in California, but we’ve been keeping the summers in Texas and PJM much more open. That’s not to say, we won’t ultimately hedge them, but the asymmetry of opportunity here is leading us to a different approach. This also is a key contributor, in addition to the regulatory uncertainties that Jack discussed to the widening of our guidance range.

Second, in 2013, as in past years, in an option strategy with gas to try and monetize some of the value of time and volatility embedded in our portfolio. As you can see, we swept around $70 million of premiums. Our past gas options strategies were very low for us and were added again but with a twist.

In past years, we focused more on certain calls, this time around we are also at times selling puts. As gas price falls below certain level our portfolio begins producing some more megawatt hours in the East due to coal to gas switching. Therefore, selling some puts allow us to capture these option premiums, while hedging the downside against the potentially expended production of our fleet.

Thanks for your time and attention. With that I’ll turn it over to Zamir.

Zamir Rauf

Thank you, Thad, and good morning everyone. Now that you’ve heard about some of the more significant drivers for our business this quarter, I will discuss how those materialize in our financial results.

Third quarter adjusted EBITDA was essentially flat year-over-year, after taking into account the Colorado and Freestone sales that occurred last year. On a year-to-date basis, adjusted EBITDA increased modestly from $1,326 million to $1,347 million due largely to our Mid-Atlantic acquisition, which was completed on July 1st of last year.

Before getting into the details of the financial performance, I would like to highlight a few of the achievements we have announced over the course of the third quarter. First, as you heard me say in the past, one of my goals has been first to achieve BB credit metric. I am very pleased to say that with a recent S&P upgrade of our corporate rating, we’ve earned a BB- rating for a secured corporate debt from both major rating agencies. In addition, we’ve closed on and funded the financing for our Los Esteros growth project and simultaneously announced $300 million share repurchase program. And finally, we completed the distribution of all the remaining bankruptcy reserve shares as of mid August, officially eliminating that legacy overhang. In some, we’ve made a lot of progress during the quarter on several financial fronts.

Turning to the following slide. Let’s take a look at the third quarter performance versus last year. In Texas, adjusted EBITDA increased by $6 million year-over-year. Commodity margin was roughly flat driven by last years Freestone sale, which was partially offset by higher market heat rates that resulted from the extreme summer heat, albeit on a relatively small open position.

Planned operating expenses decreased in the third quarter of 2011 compared to the prior year period, which is reflected by our outstanding operational performance during the quarter. Meanwhile in the West, adjusted EBITDA declined by $17 million year-over-year due mainly to $20 million reduction in adjusted EBITDA from last year sale of our Colorado plants.

We experienced slightly lower commodity margin in the West resulting from the sustained high levels of hydro generation that drove lower market heat rates on our open position, offset in part by the higher average hedge prices and originated transactions including the contract at our Delta plant that began earlier this year. As in Texas plant operating expenses in the West was down year-over-year.

Moving to the North, adjusted EBITDA was relatively flat year-over-year. Because of our acquisition of the Mid-Atlantic plants completed on July 1st of last year, the results form the North are now comparable on a quarterly basis. We did add York Energy Centre in March when it began commercial operations, so the impact from this new plant during the third quarter of 2011 was modestly offset by lower spark spreads on our open positions in PJM as compared to last year.

Finally in the Southeast, we experienced $15 million decline in adjusted EBITDA driven by the expiration of certain hedge contract that were in place in 2010, as well as by unplanned outages in the region during the third quarter of 2011.

On the next slide looking at 2011 versus 2010 on a year-to-date basis, adjusted EBITDA increased 2% primarily due to the strong performance of our very successful Mid-Atlantic acquisition last year, which is clearly reflected by the numbers in the North Region. This more than offset the Texas winter weather event in February, the persistently lower market heat rates in the West, and the expiration of certain hedge contracts in the Southeast. As such, we remain well on track to achieve our 2011 guidance, which we detail on the following slide.

As Jack mentioned, we are reaffirming our 2011 guidance, initiating 2012 guidance, and giving you a glimpse into a few aspects of 2013’s performance as outlined on the slide.

You will note that items that reconcile adjusted EBITDA to adjusted recurring free cash flow are relatively consistent year-over-year except for major maintenance expense in CapEx, which declines due to a less intensive maintenance cycle next year. We expect to settle the vast majority of the legacy interest rate swaps for $150 million over the course of 2012, primarily within the first nine months of the year. After that time, most of these swaps will have rolled off with only approximately $5 million remaining to pay in the first quarter of 2013.

We expect to invest only $10 million of equity next year in growth projects essentially entirely within our turbine upgrade program. This of course does not include any of the potential development projects Jack mentioned earlier. The ongoing expenditures for construction across Russell City and Los Esteros will now be entirely funded by the financings we secured for these projects earlier this year.

Lastly, let me also talk a bit about the sale of our Riverside plant in Wisconsin. As many of you know that plant is currently under contract with a subsidiary of Alliant Energy, and as a part of the PPA, Alliant has a call option to purchase the asset in 2013. Alliant has publicly expressed that they intent to exercise this call option, which further contract requires payment of the proceeds in the fourth quarter of 2012. As such, while the cash maybe in Escrow until the transaction is closed. We expect to receive proceeds of approximately $375 million in late 2012. Please note that Riverside does not have any project debt associated with it.

Looking past 2012 and giving you a peak into 2013, we have directional visibility into some favorable items that are incremental to our expectations for 2012. Our California construction projects, which are contracted with PG&E are scheduled to come online in mid 2013. PJMs RPM capacity payments increased in mid 2013 and we expect California carbon regulation to begin in Ernst. These favorable increments to adjusted EBITDA will be partially offset by the sale of Riverside, along with the expiration of a couple of contracts.

Overall we feel very good about 2013’s favorable trajectory, relative to 2012, and we are hopeful that we will be able to capture even more upside as the bullish fundamentals in our key markets continue to materialize.

The next slide takes a closer look at 2012 guidance. On the left, we show a bridge from 2011 to 2012 guidance with a solid bars representing the midpoint of the range for each year. The first driver from this year to 2012 is a stepped on next year in our contracted regulatory capacity.

Next as you can see from the second and third bars while 2012’s market prices are currently much slower than the prices we realized in 2011, our prudent hedging strategy has preserved the majority of 2012’s commodity margin relative to current market prices. On a side note, while today’s 2012 forward prices are lower than 2011 actual realized prices, due mainly to weather events we experienced this year, 2012’s forwards are actually higher today than 2011 forwards were a year go. And this is a fundamentally bullish signal for the power markets.

Finally 2011 performance was adversely affected by February freeze in Texas, which completes the bridge to the midpoint of 2012’s guidance range. The right side of the slide shows a projection of our 2012 sources and uses of cash. Starting with $1.2 billion of expected unrestricted cash on hand at year-end 2011 and adding to that our 2012 adjusted recurring free cash flow guidance range we expect total cash sources for 2012 of $1.575 billion to $1.775 billion. $400 million of that cash will be set aside to maintain our minimum liquidity balance of $1 billion when combined with our expected available revolver capacity and another $120 million will go to our contractual retirement of debt. And as I mentioned on the previous slide, $150 million goes towards virtually eliminating our legacy interest rate swaps and $10 million covers the committed growth projects.

We have reserved $270 million towards the opportunistic completion of our share repurchase program and expect to receive approximately $375 million in late 2012 from the sale of Riverside. At the end of the day we expect to have more than ample cash to provide us with the flexibility we need for future growth opportunities and for potential additional returns of capital to our shareholders over time.

On the following slide I would like to conclude with a few messages that I believe capture Calpine’s unique financial attributes. First, we continue to deliver solid financial results and generate positive cash flow preserving a strong liquidity balance. Second, because we have no environmental liability to fund, no significant environmental CapEx investments to make, and no material near term debt maturity, our capital allocation decisions are not already dictated for us. Our capital is available for investment or for return to shareholders, and we take that responsibility very seriously. Third, we have full strategic and financial flexibility afforded to us by our investment grade like debt governance. In all these factors among others leave us very well positioned to respond to future opportunities.

With that I would like to thank you all again for your time and for your support of Calpine and we will now open the lines for Q&A.

Question-and-Answer Session


(Operator Instructions). Brian Chin from Citigroup is on line with a question. Please go ahead.

Brian Chin - Citigroup

Can you give a little bit of color on where ERCOT is at on the non spinning reserve dispatch orders given the recent meaning they had earlier this week?

Jack Fusco

Yeah, Brian, I will start and as Bryan Kimzey mentioned in his introductory remarks, also Thad Miller here who can comment probably more robustly than I can on the regulatory proceedings. Yesterday the PUC gave to the stakeholders -- and let me back up for a minute the non spin the section issue let me before I go deeper on this before I go deeper on this for us, because in this past summer multiple times when things that tied ERCOT actually deployed assets its called non-spin and when that happened it had a very negative impact on market price and so there has been a proceeding which is rather than just when this deployed you know, could have been a price stake or whether or not there should be some four that you serve it to ensure that market pricing signals on ERCOT are not just completely are taken down.

Yesterday, the PUC gave to the stakeholders an indication that they prefer what they think the appropriate price levels floor pricing should be $120 and $180 depending on whether the non-spin unit is actually operating or not. We think that is a positive sign. This summer often times you saw prices drop all the way down to $40 with the non-spin has been out there. We would have preferred a higher floor price, to be frank. There is an ongoing dialog around several other items in Texas <> non spin they are very, very critical. So, it’s a small step, clear step in the right direction but there is more work to go to make sure that the market impacts is lower. So we are pleased, wish it had been higher but I think it's at least the rightful step on some of these issues. Thad?

Thad Hill

I think just a couple of additional things, Brian. One is that the process from here on now the PUC did not actually broke on it in the sense that mandating this; it was advice to the stakeholders to go back to the table and workout the parameters of how this would be implemented. That said, in the past PUC has used that approach the stakeholders have usually accommodated the PUC and gone forward with those proposed changes.

The other thing worth mentioning is that in the dialog yesterday, as Jack said, this step is we view it more as a baby step towards better price discovery in scarcity situations but they indicated that they would be open to a couple of additional steps that the stakeholders may want to look at. They didn’t click as much specificity around those but that is moving some of the non-spin reserve into responsive resources which will take away some of the capacity that ERCOT has to deploy as non-spin and put it in a different category.

And then the second thing was that they wanted to the stakeholders to look at moving the ceiling for the balance penalty curb to $4,000 directionally which we think directionally would be helpful in terms of prices for ERCOT. So, the stakeholders will be back to the table and discuss those as well.

Brian Chin - Citigroup

So just to make sure this is clear, if the rule is passed as is advised then when non spin reserves come into the dispatch the lowest prices can drop to somewhere in this triple digit range that they are discussing as opposed to potentially pulling the price all the way down to $40 per megawatt?

Thad Hill

Brian that’s right essentially whatever is deployed on an non-spin will be the deployed into the as did I think they are a $120 or $180 depending on whether it's off-line or online. So, it will be helpful.


John Cowen from ISI Group is on line with a question. Please go ahead.

John Cowen - ISI Group

Hi thanks good morning. I had actually two questions. The first is this issue of out of market entry potentially suppressing prices in organized capacity markets seems to be sort of popping up in almost all of the RTOs, and I know while you guys benefit from higher capacity prices you are also eying some new development projects in PJM which I guess for some degree will depend on getting longer term contracts there. So, I guess my question is, what do you think the best market fix is to this issue broadly? And also if it includes longer term contracts what do you think the right contract term is to both encourage new development and ensure reliability and also sort of balance the risks between the developer and the repairs?

Jack Fusco

Hi John this is Jack Fusco I will start with that and then on either or Thad to chime in. I think, philosophically we are opposed to the state's meddling. We made that both in New Jersey and Maryland and any of the other ones, we have made that well known. We have worked very diligently with the stakeholder process in PJM to help formulate what the new entry market rules or changes should be. It is our position, as you may know, Zamir testified in New Jersey two weeks ago to this position, that we believe that the right solution is a price signal somewhere between five and seven years. Any shorter than that makes it very difficult to finance and puts a lot of risk all the risk quite frankly on the owner of the asset, and any longer than that we think its undue risk for the rate payers overall. I look at either of the Thads to see if they have

Thad Miller

No, I think that’s right. I kind of embedded in that question I believe was our view on our ability to develop the mid-Atlantic and construct new assets, and we have a portfolio of options out there. Clearly, five-year price signals, Jack mentioned, will be incredibly helpful as we try and develop some of these. The dialog with PJM around the new entry pricing model is on the right track and we will see how that plays out this year.

I would say in a way that is non-discriminatory because this (inaudible) so and we think we can kind of make that work. To the degree, it doesn’t get fixed, we also have the ability to deploy some cheap -- very cheap existing equipment in some places and perhaps at a much more modest level could add some capacity around the edges under the current construct and we really think we need to get the market fixed on which will help a lot with the state interventions.

John Cowen - ISI Group

Okay, thanks. And my second question was just around the buyback. I noticed you bought back 10% of what was authorized, which was lower than some people are expecting. How do you approach the buyback? I mean are you looking at certain price range? Or does that mean that you now think you have other more attractive opportunities in buying back your shares? Or maybe just whatever color you want to offer on that?

Thad Miller

Yeah, and I appreciate your comment. I’m not sure what the overall expectations were. We announced the buyback on August 23 and then within a few weeks after that, our trading number closed for the quarter. So we were in a blackout period.

As you all know, when you are in the blackout period and that (inaudible) you either buy programmatically you are on a 10b51 not opportunistically. So – in that case and in all our locations, there is significant buying restriction under the SEC rules. I guess the up-tick rule is one of them. There’s also limit on daily volumes. So there is a lot of different things that we have to consider. But I think overall, we are making good progress.

John Cowen - ISI Group

Okay. So most of that will get or a lot more we get on in this quarter in Q4. Is that fair to say?

Thad Miller

I’m not saying that at all. We will see what – we will see what happens and how the stock price reacts.


Angie Storozynski from Macquarie is on line with the question. Please go ahead.

Angie Storozynski – Macquarie

Thank you. I have two questions. First of all, you’re simply adjusting a hedging strategy, I bet, to take a market view and understand that over the next especially 30 days we’re going to hear a lot from EPA and while on the other hand, if EPA regulations are delayed, you’re facing some downside to power prices maybe to a less extent for '12, but definitely '13, do you really think that the risk/reward is attractive at this point?

Jack Fusco

Angie, I think it depends by markets and by time of the year. When you, for example, and I mentioned this in my prepared remarks, we are seeing all time historic highs spark spreads and PJM in Texas right now for one of time periods, and some of the shortest. And as I mentioned, we sold some of that, and I am not going to get into exactly how much and how much we have lost in the like, but we sold some of that because it’s all time highs. We do think there is still some upside just to take if it have to come from the PJM and beyond peak. Its all-time highs.

The summer issues we view as much less having to do with anything with EPA and much more having to do with general scarcity. And so there are our point is there is really a symmetric metric outcome and given the fact there are certainly downsides from where its currently trading there could be more upsides should we have a repeat of 2010 in PJM or 2011 August from Texas. We are going to be biased current to capture more that upside.

And associated with that there is a downside risk should things get their own way. But generally speaking we have been very conservative on our hedging over the last three years and we think it served us well. As the market has begun to turn or we feel turn, some of it due to the EPA, some of it due just to the fundamentals out there, we are evaluating at some level conservatism so you could expect some changes from up there.

Angie Storozynski – Macquarie

Okay and my second question is given the yesterday’s meeting at the Public Utilities Commission of Texas and the proposed changes to the dispatch of non-spin and also the proposed or potential change of increase of the cap from $3,000 to $4,000 per megawatt/hour. What type of upside do you see to forward peak prices in ERCOT if both of these are implemented?

Jack Fusco

I think both are very, very bullish. I think 2012 itself is ultimately can be driven a lot more by you know kind of how the economy continues to do and in the weather patterns at some level. So in over the next couple or three years the willingness of the PUC in Texas to have the market to work, and where to give forward pricings to build new assets, it’s a very positive thing. The devil is in the details and Thad Miller and his team are working very, very hard, but we remained convinced that the state of Texas believes philosophically that free market should work and they are going to do the thing they need to do to make sure the price signals are clear. I think that’s you know a good thing, again in baby steps but hopefully in the right direction.

Angie Storozynski – Macquarie

But you don’t did not see the impacts already embedded in forward heat rates?

Jack Fusco

Next summer it’s trading about $65 or $70 a megawatt hour for July and August right now. While the heat rate is in press of the 17 or whatever is, $70 is not exactly scarcity pricing. And so, we certainly see heat rate come up but I would say that there is a lot more upside to that if crude scarcity exists and if the market is going to work.


Ameet Thakkar from Bank of America is on line with the question. Please go ahead.

Ameet Thakkar - Bank of America

Just a real quick question on slide 14, on some of the hedge disclosure. It looks like I guess you have added a modest level of hedges in '13, but the hedge gross margin declined by couple of dollars a megawatt-hour, can you kind of like walk us through why small change in hedge percentage would have a big change in the hedge margin?

Thad Miller

Yeah Brian there are few thing. It came down from 29 to -- sorry, Ameet, it came down from $29 to $27. And with there is rounding the new numbers too so, I think you have to I am not sure it was full $2 versus some fraction of $2 above $50. But first t past too many contracts was then at a very attractive price. We feel for California that $27 a megawatt-hour on peak for the entire year is obviously a very high thanks to that certainly hedging down the pressure. So, I think we've got -- well, we just changed our model on commissions so for smaller amounts on one of our transmission holdings. So the primary thing impacting would be the new original activity.

Ameet Thakkar - Bank of America

Okay and just from a kind of broader perspective on you guys have talked about changing the hedging philosophy to be able to bit more open in part because you feel like the forward markets don’t really reflect some of the fundamental drivers out there, but then you have got, kind of couple of dissolvent products you are also looking at, and I can fully appreciate you are not going to build those on a merchant basis or anywhere near that. But can you kind of just walk how can we reconcile where we are looking to add when you still feel like there is a forward market there even, if you can build it at a discount to replacement cost. Is it really just a matter of trying to beat some of the off city opportunity?

Thad Miller

I think embedded in the question is actually the view which we feel that forward markets do not represent fundamentals for several issues we have already talked about here, and we just take Texas for a minute. We think the fundamental are much above the forward market. So the same reason why you wouldn’t hedge, is also the reason, if you could build something on a deep discount dollar per KW because we’ve got the same reason you will make that investment, not justified on the forward curve you are ready to sell out but based on the fundamental view which is above the forward curve.


Julien Dumoulin-Smith from UBS is on line with a question. Please go ahead.

Julien Dumoulin-Smith - UBS

Not too bad thank you. Couple of quick clarifications actually the first with respect to non-spin. Looking historically over the past year or year-to-date rather how much upside would you’ve gotten there what would have been lets call it a pro forma the commodity margin uplift if it had not been or if the proposals had been in place?

Thad Hill

Yeah, Julien, we don't have a view of that, yeah, I mean we just found out what the numbers are going to be. But if we take $180 as an example what I will tell you is last year when non-spin was deployed or earlier this year, the average price was deployed at, was about $250 a megawatt hour. So and the prices fell down and typically way down deep into the double-digits. So this certainly provides a lot of upside from what’s occurred over the last year and they will full make up potentially but it spins on the hour.

Julien Dumoulin-Smith - UBS

Great. And then also a clarification no CSAPR, in light of the latest modifications can you be a little bit more specific about if you think or how much upside you see into Texas forwards going into ‘12 and ‘13?

Thad Hill

Yeah, I will say this. Generally speaking given the changes in CSAPR in ’12. Now it is not required the cold to gas switching occur and will satisfy the obligation, and openly it will depend on what the price is. In Texas independent of anybody retiring plans or anything else like that that may happen, probably the biggest upside for us in Texas is in the off-peak. Because when coal is on the margins as it is the number of times they will raise price. And when price goes up, as you all know we have a number of cogents with run through obligations. So far run through is that obligation in Texas at a minimum will get upside on those. And I think the broader impact will ultimately depend on what upside you trade for per megawatt hour et cetera.

Jack Fusco

Julien you’re going to appreciate it this is a very contagious issue right now with the court.


Our last question comes form Michael Worms from BMO Capital. Please go ahead.

Michael Worms - BMO Capital

Just a quick question Jack can you give us an update on the Calpine trade in California what is needed between now and 2013 to get this over the finish line?

Jack Fusco

Yeah, well let me ask Thad Miller to get deep in it.

Michael Worms - BMO Capital


Thad Miller

Michael, the final rules are in place. So we’ve already seen the market reacting to that. There is the potential that there would be additional lawsuit seeking to delay it, but we think that the likelihood of the stay its is very low. So, we expect it to continue to march forward. The rules are in place.


I will now turn the call over to Mr. Bryan Kimzey for any closing remarks.

Bryan Kimzey

Thank you, everyone for your interest in Calpine. That concludes our third quarter 2011 earnings conference call.


Thank you, ladies and gentleman this concludes today’s conference. Thank you for participating. You may now disconnect.

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