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Edited Transcript of CPN earnings conference call or presentation 10-Feb-17 3:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Calpine Corp Earnings Call

HOUSTON Feb 10, 2017 (Thomson StreetEvents) -- Edited Transcript of Calpine Corp earnings conference call or presentation Friday, February 10, 2017 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Bryan Kimzey

Calpine Corporation - VP of IR and Financial Planning

* Thad Hill

Calpine Corporation - President & CEO

* Trey Griggs

Calpine Corporation - President of Calpine Retail

* Zamir Rauf

Calpine Corporation - CFO

* Andrew Novotny

Calpine Corporation - SVP of Commercial Operations

* Caleb Stephenson

Calpine Corporation - SVP of Wholesale Origination and Commercial Analytics

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Conference Call Participants

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* Julien Dumoulin-Smith

UBS - Analyst

* Neel Mitra

Tudor, Pickering, Holt & Co. Securities - Analyst

* Shar Pourreza

Guggenheim Partners - Analyst

* Angie Storozynski

Macquarie Research Equities - Analyst

* Greg Gordon

Evercore ISI - Analyst

* Michael Lapides

Goldman Sachs - Analyst

* Praful Mehta

Citigroup - Analyst

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Presentation

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Operator [1]

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Good morning, and welcome to the fourth-quarter 2016 earnings conference call. My name is Brandon, and I will be your operator for today.

(Operator Instructions)

Please note this conference is being recorded. I will now turn it over to Bryan Kimzey, Vice President of Investor Relations and Financial Planning. Mr. Kimzey, You may begin.

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Bryan Kimzey, Calpine Corporation - VP of IR and Financial Planning [2]

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Thank you operator, and good morning everyone. I'd like to welcome you to Calpine's investor update conference call covering our fourth-quarter and full-year 2016 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 can access the webcast and a copy of the accompanying presentation materials in the investor relations of our website.

Joining me for this morning's call are Thad Hill, our President and Chief Executive Officer; Trey Griggs, President of Calpine Retail; and Zamir Rauf, our Chief Financial Officer. In addition, Thad Miller, our Chief Legal Officer; Andrew Novotny, SVP Commercial Operations; and Caleb Stephenson, SVP of Wholesale Origination and Commercial Analytics are also with us to address any questions you may have on legal, regulatory or detailed commercial issues.

Before we begin the presentation, I encourage all listeners to review the Safe Harbor statement included on slide 2 of the presentation which explains the risks of forward-looking statements and the use of non-GAAP financial measures. For additional information, please refer to our most recent SEC filings which are on file with the SEC and on Calpine's website. Additionally, we would like to advise you that statements made during this call are made as of this date and listeners to any replay should understand that the passage of time by itself will diminish the quality of these statements.

(Caller Instructions)

I'll now turn the call over to Thad to lead our presentation.

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Thad Hill, Calpine Corporation - President & CEO [3]

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Thank you Bryan, and thank you to all of you listening on the call today. We very much appreciate your interest in Calpine. For the eighth year in a row we delivered strong adjusted EBITDA and adjusted free cash flow within or above our original guidance range, which speaks to our stable and repeatable business and our ability to execute. In 2016 we earned $1.815 billion of adjusted EBITDA and $736 million of adjusted free cash flow, despite a year with low wholesale price volatility and, in particular, the lack of any exciting summer pricing.

We also had many commercial and financial achievements of which we are very proud. We operate our fleet extremely well and had our best safety year ever; there is no more important achievement than that. We maintained our focus on costs, which helped in a more difficult commodity margin here. We integrated our Champion purchase, added the smaller bolt-on North American Power, and completed the acquisition of Noble Americas Energy Solutions, which we now call Calpine Energy Solutions, one of the nation's largest direct commercial and industrial retailers.

We continued our unique among competitors active portfolio management with the sale of Osprey and Mankato, and we have accelerated the process toward a stable and long-term capital structure. Since our last call we have termed out our nearest corporate majority, increased both our revolver capacity and our secured debt capacity, and began execution of a plan to pay down $2.7 billion of debt by the end of 2019. Zamir and his team have made tremendous progress in short order.

More broadly, I am proud of the entire Calpine team for their 2016 accomplishments. Difficult markets can come and go, but our folks stayed focused and made progress operationally, commercially, strategically and financially. My sincere personal thanks to the Calpine employees.

As you can see on the slide, our 2016 adjusted EBITDA of $1.815 billion continues the trend of stable financial results that our investors have come to expect. Since 2009 we have been in this approximate range, with the exception of the effects of the Polar Vortex in 2014.

Our guidance for 2017 of $1.8 billion to $1.95 billion of adjusted EBITDA falls right in line with this trend. We believe we can maintain this level of financial performance or better while shrinking the balance sheet with a strong tilt toward debt paydown, given the current capital market environment.

I mentioned that our outlook for the next several years is positive, despite some sector headwinds. To acknowledge a few, we recognize the forward spark spreads have fallen to this week's capacity auction in New England was down versus last year, and that nuclear plants are seeking bailouts in several competitive markets. These headlines have been well covered, yet we find that no one is arguing the other side of the coin and we believe some factors are worth noting.

The next slide attempts to lay out the key reasons behind our optimism in four basic parts. First, we have the best and youngest scale generation fleet and we operate it exceptionally well. Our flexible, modern and clean plants have decades of life remaining in them, with no environmental CapEx, no lingering environmental liabilities, no pension expense, no distressive city areas. We are straightforward power company with a set of plants that can turn and off twice a day if needed, something that is very valuable in a world of increased intermitting generation.

As I mentioned already, we don't just make power, we sell it. And we sell it in a variety of ways including wholesale, direct to residential, through brokers, and direct to large industrial and commercial customers. Not only to this help us manage our fleet commercially and increases our collateral efficiency, but it also gives us greater earnings potential and a bit of a natural hedge.

In fact, the way I think about it we are essentially adding several dollars of revenue per megawatt hour to our wholesale generation fleet. In addition to retail over the last 1.5 years has added a new dimension to our business that has improved commercial operations, been accretive to our cash flow, and has improved the stability and lowered the risk of the overall enterprise.

Although the markets in 2016 and 2017 so far have shown limited volatility, we are optimistic over the next several years in several key areas. Trey will cover this in more detail, so I don't want to steal much of his thunder, but as the captions say, in Texas as widely reported, a rebound is coming. In the East, although perhaps more challenged, our assets are much better located then most, particularly with regards to the premium location of our assets in the constrained East MAAC and DPL South zones of PJM. And in California, our electricity capacity is needed to keep the lights on; we just need market signals that reflect as much.

Wrapping up on the gov/reg front, despite some state nuclear bailouts of plants that have already been paid for twice over by ratepayers and the extension of tax credits for renewables, we are optimistic here too. Last year there were a couple of key Supreme Court wins that made it clear that the federal government retains jurisdiction over wholesale power markets, and we are optimistic that a reconstituted FERC will work hard to protect the sanctity of restructured electro-markets.

We think FERC, along with the large RTOs, will work to shift tariffs that help ensure that out-of-market compensation and subsidies, should they survive court challenges, do not crush pricing to power plants like ours that are required for liability in a changing grid. So all in all, a balanced but optimistic point of view.

The next page describes our 2017 objectives. At its simplest there are three. First, we must continue to deliver the EBITDA and cash we say we will.

Second, we set out to build a new retail presence to complement our wholesale business. We have been successful. Now we must integrate what we've acquired.

Third, we must make progress shrinking our balance sheet to both improve the risk profile of the Company and create greater flexibility. There is not a lot to say about hitting the numbers, other than we pride ourselves and our operation's excellence, both in the fleet commercially and in our support functions, both in terms of efficacy and efficiency.

On retail, as I've mentioned, we've invested heavily to create a platform. That platform is now complete. We have systems and multiple residential, small business and larger commercial and industrial channels. Now we integrate, a process that is well underway.

Recognizing the importance of this task to Calpine, I've asked Trey Griggs to focus full time on this, and he will transition to a new role of President of Calpine Retail. He job will be to ensure we achieve our high expectations from this new part of our business.

I am grateful to Trey for accepting this very important charge. Andrew Novotny and Caleb Stephenson, who many of you know, will both report to me directly, with Andrew focusing on the commercial optimization of the fleet and Caleb leading our wholesale origination and commercial analytics effort.

On the balance sheet we're planning to pay off close to $1 billion of debt this year, and as previously mentioned, $2.7 billion of debt by 2019. Despite our solid confidence in our business, the lack of sponsorship in the public equity space today is pushing us towards delevering first and foremost. I believe right now that not only does $1 of debt paydown create $1 of equity value, but the perceived derisking of the Company could actually lower the discount rate and thus create additional value.

The next slide lays out our debt reduction plan with some more information. Zamir will provide more detail on the ins and outs in a few minutes. In addition to the debt reduction we had previously disclosed, we have decided to go ahead and take out our last tranche of high cost, almost 8% debt, versus terming it out as had been our plan.

We are accomplishing this primarily through a short-term bridge loan that will save some interest expense until we paid it off next year. We also continue to keep an eye on our 2022 notes that become callable at par in 2019 which, as of today, look like another opportune way to reduce debt. Combining these paydowns with our scheduled repayments and the payoff of the term loan we used to fund the Solutions acquisition, we see a path for $2.7 billion of debt reduction by 2019.

There are several key points on this. First, after executing this delevering plan, we would still have several hundred million dollars of dry powder available for deployment.

Second, this assumes no further asset sales. As you know, we have been an active asset seller whenever a counterparty values an asset more than we do. You should always expect that we are engaged in multiple M&A discussions at any time; it is no different now.

I am not going to predict if or when our next asset deal will occur, but believe the track record speaks for itself. I am hopeful the proceeds to deploy will actually be higher if we can make a good deal elsewhere, but we also do not have to rush to do a deal that does not make sense. We will stay disciplined.

Third, as mentioned, we expect to be balanced in our capital allocation decisions and will also actively contemplate in returning money to shareholders. Obviously there's more dry powder with an asset sale or two, but returning cash will remain in our toolbox.

This extraordinary delevering program reduces leverage by almost 1.5 times of adjusted EBITDA to current levels, or a remarkable $7.50 per share of debt in a short amount of time. In other words, if we did nothing else, in a constant multiple world this represents very real value accretion to our shareholders; approximately two-thirds over three years, even before considering the potential for multiple expansion.

This really brings me to my final point, which is our valuation. I understand that there is a lack of sponsorship today for IPP equities, and this has led to a much lower valuation of our stock than the fundamentals merit.

The intersection of our strong assets, growing retail business and market fundamentals provides us with an extraordinary cash flow that endures. Our adjusted EBITDA multiple is approximately 1.5 times lower on sentiment alone than where we have traded the last several years. Our adjusted free cash flow yield has doubled.

We have heard clearly the signal that derisking the Company further through debt reduction is the right long-term decision for our shareholders. As I tell our team, if we stay focused on creating the cash, managing the portfolio actively for value, successfully building the retail business and continuing to shrink the balance sheet, the value will come. I look forward to reaping the rewards together. With that, I'll turn it over to Trey.

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Trey Griggs, Calpine Corporation - President of Calpine Retail [4]

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Thank you Thad, and good morning to everyone on the call. As Thad mentioned, as of today I will be transitioning into the role of President of Calpine Retail, a role that I am incredibly excited about. I will speak about the retail platform in more detail shortly, but let's first begin with our traditional review of fleet operations which shows the exemplary performance in 2016 from Charlie Gates and his entire team of professionals.

Last year our employees raised the bar for safety achievements once again, delivering our lowest ever total reportable incident rate. In addition, our forced outage factor of 2.1% was consistent with 2015 and continues to represent best-in-class performance.

The honor roll of plants that most significantly contributed to these results is presented in the lower right. As always, congratulations and thank you to these teams who lead by example.

Moving to the generation volumes chart on the upper right, you'll see that, as expected and as previously communicated, our volumes in the West declined meaningfully last year primarily as a result of a return to more normal hydro conditions in 2016 as compared to 2015, a trend we expect to continue into 2017 given the recent weather in the West. Meanwhile generation volumes at the Geysers were roughly flat year over year as we recovered from the wildfire of late 2015. And we are proud to say the Geysers are back at full operation for 2017, and are expected to achieve their more typical annual generation volumes of around 600 million megawatt hours this year.

In Texas 2016 volumes were down slightly as a result of higher natural gas prices driving a reversal of coal to gas switching, while volumes were up in the east primarily as a result of portfolio changes.

Let's take a closer look at each of these markets on the following slide, beginning with California in the West. As you all know, increasing renewables penetration and more recently and temporarily increased levels of hydro generation have severely weakened the energy markets. However, we're starting to see signs of improvement in the outlook for resource adequacy markets, reflecting the increasing value of well located, reliable, dispatchable asset like ours.

A number of factors have begun to drive meaningful changes in the supply mix just since our last earnings call. We've seen La Paloma, the power plant we referenced last quarter as having filed with FERC for relief from the California market, now file for bankruptcy.

We've also seen the retirement of two units at Moss Landing and the shutdown of operations at Pittsburgh. In other words, more than 2,800 megawatts of capacity has stopped operating in just the past six weeks, which puts total retirements or retirement announcements over the past five years at approximately 15 gigawatts.

Looking ahead, the question remains for California, how many more retirement or shutdowns are out there, and how many the state can weather under the current market compensation structure? At the same time load growth, according to third-party weather normalized analysis, has outperformed market expectations, showing positive trends despite an increase in behind the meter solar and energy efficiency. With dispatchable supply shrinking and loads still growing, the state is facing a significant challenge. Suggestions that massive energy storage systems could be capable of filling the void left by the exiting capacity are unrealistic.

Ignoring economics altogether, there are services that a grid needs that batteries simply cannot provide. Chief among these is the fact that batteries are only typically able to discharge for three or four consecutive hours before they have to be recharged. Find yourself with a cloudy day or two, or worse yet an extended drought like we saw in 2013/2014, and batteries will not be able to get the job done. California will continue to need dispatchable, flexible generation resources, which need to be compensated appropriately, and we are confident that our assets are the right ones to do so, particularly given their proximity to the Bay Area.

Moving onto Texas. Those of you who follow us regularly know that for several years we have taken issue with the assumptions embedded in the state's reserve margin forecast, or CDR, primarily with respect to load growth estimates that we felt were too low and new supply that we felt was highly unlikely to arrive. In its CDR issued just this past December, ERCOT has now increased its load growth estimates to a level that we feel more closely approximates what we've observed in the market over the past few years and what we expect for the future, as shown in the chart in the top middle of the slide.

Unfortunately the December CDR still includes approximately 4,000 megawatts in its supply outlook that are questionable at best based on current economics. Our view of the market, in which we remove new resources that are unlikely to be built and in which we set aside capacity whose deployment would trigger scarcity pricing, is reflected in the green bars of the chart below. As you can see, this economic reserve margin drops meaningfully as we approach the end of the decade.

Meanwhile, the amount of intermittent renewable resources that are contributing to the economic reserve margin is growing to the point where it equals 100% of the economic reserve margin in 2020, and even increases thereafter. Combined with potential for coal and steam gas retirements which are not assumed in our economic reserve margin, we continue to expect improvement in this market from today's lows.

Lastly as we look to the East, all eyes these days are focused on capacity auctions. In PJM most of our assets are located in East MAAC, where we see the potential for resources that bid in last year's auction as base only to be at risk as the market transitions to a 100% CP requirement.

We predict that roughly 2,500 megawatts, or 8% of the capacity in East MAAC that cleared the auction last year could be at risk. Obviously depending upon how the final parameters are set, the impact of these at-risk megawatts could be mitigated by load, imports or other factors.

In New England the auction results were lower than last year, but not unexpected. More broadly with respect to capacity markets in the East, we continue to see attempts for market interference that could weigh on clearing prices. But the commitment from PJM and ISO New England in particular to preserving the competitive market-based principles of the auctions is reassuring.

Let's now turn to the following slide where we convert our views on the markets into a portfolio position. Right off the bat let me call your attention to the fact that as of this quarter we have changed and simplified our modeling tips and related hedge disclosures to incorporate our expanded retail platform.

Rather than embedding our retail economics into our legacy wholesale hedge disclosures, we have stripped them out and are now providing retail margin as a separate adder after completing the traditional wholesale market modeling exercise. The equation in the upper left illustrates this new math and highlights a projected retail margin range for 2017 of $375 million to $425 million.

As a result of these changes you'll note that our wholesale energy margin as a percent of wholesale margin has declined modestly in 2017, as did our hedged wholesale margin per megawatt hour for 2017 and 2018, both of which are driven by the movement of retail contribution out of these disclosures and into its own separate adder. You'll note that we have also updated the premium range table in our modeling tips in the appendix, in part as a result of this same movement and in part due to the cumulative changes in our portfolio since we last updated the table in 2014.

Moving past the changes to the methodology, it is worth noting that our 2017 volume is slightly below 2018 and 2019, due largely to lower spark spreads, including those driven by dry conditions in the West and from marginal hours during the off-peak and shoulder periods that are much less valuable to begin with. The 2018 and 2019 volumes you will see have held in there, as out-year sparks are relatively flat or in contango from 2017 to 2019, with the exception of ERCOT which we do not believe is sustainable. Before leaving this slide, in sum we have, I believe, simplified our modeling methodology by going back to our historical approach for modeling the wholesale business and then adding retail on top.

Let's wrap up with a look at our retail platform on the following slide. Thad noted that integrating our retail acquisitions and creating a retail energy powerhouse is a top priority for Calpine in 2017. As a result, I will be making retail success my full-time job.

This is made possible by virtue of our bench strength at Calpine. On prior earnings calls and investor meetings you have heard frequently from Andrew Novotny and Caleb Stephenson, two very capable leaders who will rise to the challenge of directing our wholesale organization. My focus on retail will initially be successful integration, following by growth to add to the retail margin described on the prior slides.

Now a few words about our retail organization. We have three distinct retail sales channels: Direct large commercial and industrial, indirect or broker-driven business with small C& I, and residential mass market. The platform is now strategically complete, meaning we do not plan to buy other platforms unless we find deep value opportunities.

Ours is a strong platform that strategically complements our wholesale footprint, as you can see from the map on the right. As we move forward with integration, we will do our best to balance common backend systems with unique customer acquisition approaches across the entities.

So what does retail get us? Well for starters, it gets us expanded sales channels and enhanced liquidity for our wholesale generation volumes. But beyond that, the retail platform adds opportunity for improved margin by virtue of its stable, reliable long track record of consistent performance backed by a solid reputation.

Champion Energy is a perennial leader in Texas. Solutions is a standout in comparison to the competition because it provides a higher level of service and advice. North American Power has quickly grown its retail footprint in the Northeast, offering a natural extension of the Champion platform in that area. I am thrilled to be leading the integration and growth of this business line, benefiting Calpine and its shareholders as we position the Company for the future.

Thank you again. I will now turn it over to Zamir.

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Zamir Rauf, Calpine Corporation - CFO [5]

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Thank you Trey, and good morning everyone. I would like to start today with a review of our full-year 2016 financial results. For the year we generated $1.815 billion of adjusted EBITDA and $736 million of adjusted free cash flow, maintaining our track record of solid stable performance.

A full year of operations at our Granite Ridge and Garrison Energy centers positively contributed to our earnings, as did strong cost performance and the strategic expansion of our retail platforms that added to our margins and complemented our wholesale fleet. These positive drivers were offset by milder weather, lower generation volumes as Trey previously described, and lower spark spreads along with limited volatility across our core market, resulting in weaker liquidations.

As our team now turns to 2017 we'll focus on three key objectives as laid out by Thad. First, we are strategically executing on our plan to reduce debt, which I will describe in detail in a few slides. Second, we will deliver on our financial commitments to our shareholders, continuing our record of consistent stable cash flows. Third, we will integrate our recent retail acquisitions into our business and optimize their financial performance, as you just heard from Trey.

Turning now to the fourth-quarter results in the following slide compares our quarterly adjusted EBITDA distribution year over year. As shown in the chart on the upper left, the fourth quarter of 2016 reflects a favorable variance related to the impacts of the wildfire we experienced at the Geysers in 2015 since operations were fully restored by the fourth quarter of 2016.

This variance was offset by lower regulatory capacity payments in PJM and lower contributions from contracts, primarily Pastoria in the West. In addition, as previously described, weaker market liquidations and lower contributions from wholesale hedges across our regions partially offset by the impacts of our retail hedges and our focus on cost management accounted for the balance of the year-over-year variance in the fourth quarter. In all, our fourth-quarter results were in line with expectations and allowed us to achieve full-year results consistent with our guidance.

Turning now to the next slide, I would like to go into greater detail on our $2.7 billion debt paydown plan which will ultimately result in no corporate debt maturities until 2023, reduce leverage by nearly 1.5 turns at current EBITDA levels, and significantly lower our interest expense, which I will come back to in a moment. As such, we have already made great strides to our strengthening and derisking our balance sheets since our third-quarter call. Since that time we have been very active and have extended maturities, increased our revolver capacity, decreased interest expense, and ultimately increased our financial flexibility.

We've begun aggressively executing on our delevering plan, and you can see the results of our completed and planned actions between the two maturity charts on the right. The top chart shows our maturity profile as of the third quarter call and the bottom charts shows our projected maturity profile after the completion of our $2.7 billion delevering plan by the end of 2019.

To highlight the activities we've already completed since the third-quarter call, we've repriced the $475 million project debt for Russell City, saving 50 basis points this year escalating to 75 basis points of savings by 2023. We've refinanced our $455 million Steamboat project debt and extended the maturity by six years from 2019 to 2025.

We have repriced $1.1 billion of 2023 term loans, saving 25 basis points. We've extended our LIBOR plus 275 basis points 2022 term loan maturity by two years to 2024. And we've upsized our revolver by $112 million to slightly under $1.8 billion through June 2020.

During that same time, following the acquisition of our Solutions retail business, we closed a low-cost short-term $550 million bridge loan at LIBOR plus 175 basis points that will be repaid in full by the end of this year. And finally, as we said on our third-quarter call, we paid off $120 million of our high-priced 2023 senior secured notes using cash.

This redemption left $453 million of principal outstanding on these notes at a very high interest rate of almost 8%, and we are pleased to announce that we have recently called this remaining amount. The call will be funded with cash and a $400 million short-term term loan due in 2019, also at LIBOR plus 175 basis points which we plan to pay off in full by the end of 2018, or slightly under two years from now. The benefit of this transaction is twofold: it allows us to accelerate debt paydown and reduces the interest rate by 5% in the interim.

The maturity chart in the lower right also reflects our previously mentioned plan to repay $750 million of our 2022 senior secured notes when they become callable at par in late 2019. In total, this impressive $2.7 billion paydown of debt will decrease our leverage ratio by almost 1.5 turns at current EBITDA levels.

The following slide shows the details of this debt paydown by year in the chart on the left. Through the paydown of this debt along with our recent refinancing activities, we will benefit from significant interest savings.

The $2.7 billion debt paydown alone results in approximately $150 million of annual cash interest savings by 2020. I'm very proud of our treasury team for all these accomplishments and for the progress we've made to date. These deliberate and proactive actions will not only increase our flexibility, but will also accrue to our shareholder equity value.

I would like to thank you once again for your time this morning. Operator, please open the lines for Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

Julien Dumoulin-Smith, UBS.

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Julien Dumoulin-Smith, UBS - Analyst [2]

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Good morning. Congrats.

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Thad Hill, Calpine Corporation - President & CEO [3]

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Good morning, Julien.

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Julien Dumoulin-Smith, UBS - Analyst [4]

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Perhaps just a quick first question. If you can elaborate a little bit in terms of the updated disclosure to the wholesale margin with the retail, the $375 million to $425 million.

Is there an O&M number we should be thinking about that, or relative to the initial transactions you guys did? I suppose if you take Noble and Champion together you have a little bit over a couple of hundred million in EBITDA. Is that roughly comparable, or is that actually a higher net/net EBITDA number that comes out of that $400 million retail margin?

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Trey Griggs, Calpine Corporation - President of Calpine Retail [5]

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Julien, it's Trey, thanks. If you look at slide 21 where our modeling picture's at in earnings presentation, you'll note that note 9 discloses that you should add $130 million to total costs in 2017. That primarily, there are some puts and takes and some portfolio changes, but that primarily represents the addition of the two retail platform that we acquired and closed on, on or about the beginning of this year. So taking that in consideration and knowing that we owned Champion throughout 2016 should get you pretty close to the math using that $375 million to $425 million margin number.

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Julien Dumoulin-Smith, UBS - Analyst [6]

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Got it. All right, excellent. Then a little bit of a bigger picture question. Just be curious, obviously there's been a lot of questions out there about your contract portfolio, especially out West. Can you elaborate a little bit on the state of where they are relative to market, especially outside of the big three but Los Esteros, Otay, and Russell City (technical difficulties) California (technical difficulties) the contract portfolio?

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Thad Hill, Calpine Corporation - President & CEO [7]

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Julian, thanks. The short answer is, outside of the big three the earnings that we have there are at market. We see very little incremental downside risk, if any at all.

Maybe the longer answer to that question, and it probably deserves a longer answer. There was a sell-side report that came out this week that has garnered a lot of attention.

About that, a couple of things. One, their fundamental premise about how the California market evolves. And I think reasonable people can have different perspectives on this, and our perspective, I think Trey did a pretty good job of laying in his prepared remarks, but we are certainly willing to come back and talk more about that.

However, the second part of that is actually the underlying economics. I would encourage anybody, we are more than happy to spend time with folks on the phone around what those economics are because we have a little bit of a different take maybe that has been bandied about this week. So let me lay that out, and I will try do this clearly and quickly.

The three parts of our business, first for the Geysers. The Geysers have strong cash flow. They are fully contracted through 2021, they are about half contracted through 2028. And we feel pretty good about the pace of recontracting that asset; it is very important to the State of California in achieving their renewable goals.

The second category, which I think is a category you mentioned, which are largely uncontracted merchant assets in California, and including Sutter, they're 3,500 megawatts. Those plants together are producing right at zero cash flow. So were not happy with that situation, but there is no downside at all; and in fact I think we see a fair amount of upside, again giving Trey's remarks. We've shown, by the way, though, that we will not operate assets at a loss, whether it was our [actions] at Sutter or whether it was our actions with Clear Lake that we demonstrated.

So there's no downside to that. We see a lot of upside, but I'll part with using the market and what's going to come back to those.

The third category that got a lot of attention had to do with our contracted portfolio, and there's some smaller plants but generally there are three, as you pointed out. One of those Otay Mesa, has a put call on it which will transition probably in 2019 to San Diego Gas and Electric. There is a put call number approaching $300 million in there.

The other two are Los Esteros and Russell City. Those contracts expire at the end of 2023. So I just want to remind people we are talking about 2024. Those three plants together produce about $170 million of cash, as we've disclosed before.

Russell City and Los Esteros we believe our critical, not just for overall supply demand but where they are specifically on the grid, and those assets are required and they will continue to earn cash. Just to do a little play with the numbers. That $170 million, let's say it reduces by $120 million, and I don't know what the number is, maybe it's more, hopefully less because those assets are required.

That $120 million off some cash flow at today's cash flow multiple is about $600 million of value, because we are about 20% free cash flow yield. But over the same time period those three assets, there's a $1 billion of cash -- excuse me, of debt paydown that occurs. So we don't see the value problem.

We are paying off $1 billion over a number of years, and maybe give up some cash flow, but giving up $100 million of cash flow to pay off $1 billion of debt is not necessarily a bad tradeoff. We don't think that this situation which occurs in 2024 should remotely receive a lot of the attention it did today. Again, I would like to end with the fact that we grew -- there's a lot more upside in California then there is downside for us to this point.

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Julien Dumoulin-Smith, UBS - Analyst [8]

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Got it. I will let the next questioner go.

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Operator [9]

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Neel Mitra, Tudor, Pickering, Holt & Co. Securities.

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Neel Mitra, Tudor, Pickering, Holt & Co. Securities - Analyst [10]

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Hi, good morning. With the accelerated deleveraging that you have through 2019, is there a goal debt-to-EBITDA that you are targeting, or could you maybe lay out how that will evolve over time? Obviously 2017 is kind of your trough EBITDA. So looking out over time it would be useful to see how that evolves.

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Zamir Rauf, Calpine Corporation - CFO [11]

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Sure, Neel. This is Zamir. Look, we put out a stated goal of getting to 4.5 times and obviously I cannot give you multi-year guidance here. But if you just look at the $2.7 billion alone that we are paying off, as Thad mentioned that represents two-thirds of our current market cap and it's a greater than 20% reduction over our year-end gross debt balance.

That alone reduces leverage by 1.5 times which is a material reduction, not to mention the several hundred million dollars of cash that we will have on the balance sheet after this debt gets paid off. So if you plug that into your model I think you can quickly see how leverage reduces over time.

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Neel Mitra, Tudor, Pickering, Holt & Co. Securities - Analyst [12]

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Got it. The stated goal is to be at 4.5 times or less over time, is that right?

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Zamir Rauf, Calpine Corporation - CFO [13]

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It is the 4.5 times range, that is correct.

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Neel Mitra, Tudor, Pickering, Holt & Co. Securities - Analyst [14]

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Okay, great. Then a second question. Could you maybe explain in PJM why you have the bullish view regarding EMAAC and capacity prices? And why you're assets are advantage over MAAC or RTO assets?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [15]

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Sure, Neel, thanks. This is Andrew. First of all, as Trey said in his scripted remarks, we believe that there is approximately 3,000 megawatts in EMAAC that bid in the last auction as base only and refused to accept the CP risk. So the primary reason why we are bullish for EMAAC is that the 100% CP requirement this auction puts up to 3,000 megawatts of those plants at risk for not offering into this auction.

Of course the market monitor did a report and a scenario on the latest auction and what that would have meant to the EMAAC price, which his scenario was an enormous number, something greater than $300 a megawatt day. At this point there are plenty of mitigating factors that would keep us from suggesting that the price could be anywhere near that good, and certainly parameters like transmission capability and what the load numbers are when they -- for the final parameters when they are released come out to be. But despite those offsets, we still believe that EMAAC is going to separate from RTO and be a better region.

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Neel Mitra, Tudor, Pickering, Holt & Co. Securities - Analyst [16]

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Is there also factors like demand response and imports and situations like that that impact EMAAC a lot less than RTO beyond just the base CP spread?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [17]

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They are interconnected in that demand response is one of the sources of supply that will struggle to provide 100% CP. And so as Trey laid out in his chart and his scripted remarks, a good portion of the 3,000 megawatts that we think are at risk are demand response.

Now, there are some rules where demand response is able to seasonally couple with of the resources, but we don't believe that that's going to be possible for much more than 500 megs out of the 3,000. So all of that comes together in a view that should be relatively constructive year on year.

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Neel Mitra, Tudor, Pickering, Holt & Co. Securities - Analyst [18]

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Okay, got it. Thank you very much.

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Operator [19]

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Shar Pourreza, Guggenheim Partners.

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Shar Pourreza, Guggenheim Partners - Analyst [20]

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Good morning, guys.

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Thad Hill, Calpine Corporation - President & CEO [21]

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Good morning.

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Shar Pourreza, Guggenheim Partners - Analyst [22]

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Congrats on the $2.7 billion delevering initiative. Are you comfortable at this point, Zamir? Are there any opportunities to potentially accelerate the 1.5 times debt reduction? Thad, I think in your prepared remarks, and it may be a subtle change in language, that it appears you've taken a little bit more of a much more definitive stance that delivering is sort of that near-term priority versus buybacks.

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Zamir Rauf, Calpine Corporation - CFO [23]

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Look, Shar. Zamir here. Yes, our focus to delever as quickly as possible. We may have some opportunities along the way, but really we're being very aggressive over here. I mean, you just look at what we did with the $453 million and paying that off in two years.

We are paying off a lot of debt here. In 2018 it's possible that we have further opportunities to delever, and especially in 2019 once we are done with this $2.7 billion. As I said, we still have a lot of cash on the balance sheet available for capital allocation which can be used for any capital allocation that happens to be most attractive at the time, including more debt paydowns. We will continue to evaluate that as we move forward.

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Shar Pourreza, Guggenheim Partners - Analyst [24]

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Got it, thanks. Then Thad, thanks for addressing some of the nuclear incentives. It's obviously one of the near-term risks around the sector. But can you maybe just comment on some potential moves we may see in Pennsylvania and Ohio? Obviously these states have become a lot savvier in how to structure these deals than we have seen in the past.

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Thad Hill, Calpine Corporation - President & CEO [25]

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Let's take the whole category of nuclear bailouts on for a minute, and we can get to specific areas. First and foremost, there's obviously a constructive effort, or a very concentrated effort on this across a number of states. Obviously it's occurred in Illinois, it's occurred in New York. There are efforts underway in other states.

The amazing thing if you kind of sit back and think about it on a couple of different levels. First off, these plants, as we mentioned, have already paid for twice. During restructuring there were stranded costs for recovery and they were completely paid for by the repairs. When gas prices went up the owners of these plants were completely compensated again by the high gas price regimes. So this is actually asking for the same power plant to be paid for by the third time by consumers, and I'm not sure how well that's understood but certainly that needs to be understood by people who make the decision.

Some of the places where these are being asked for, there have been statements by the companies that the plants are actually making money, and in other places there has been asked to open books that I am not so sure that there is a willingness to do that on these plants. So there is a kind of a state-by-state effort that is going on here. Additionally of course they're legal challenges, as you are seeing in both Illinois and New York that will ultimately play out, and we will have to see how those actually play out.

Third and finally, there are a couple points that I do want to make, which is first off, while this is a threat to competitive markets it's not actually a threat to our earnings stream because these assets are not bringing on new plants, they are just keeping existing plants around. So the downside is more limited than, for example, if a state was tried to build such (inaudible) combined cycles like we saw in New Jersey and Maryland for (inaudible) and we saw the Supreme Court overturn that effort.

But we do believe that the RTOs are very concerned about if you actually put assets at risk by the subsidization, if they're going to ensure reliability they're going to have to protect the competitive market in some ways. There is a series of conversations in some of the large RTOs around how you actually prevent subsidized generation from negatively impacting price. And we think at least the existing FERC Commissioners are supportive of that discussion.

I think you should expect to see both the RTO's and FERC and stakeholders very actively over the balance of the year around how you actually restructure tariffs to prevent negative impact in competitive markets. So we're pretty positive this isn't going to have a very, or at all, a negative impact on our business, but at the same time are also going to be constructively engaged to do our best to prevent it.

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Shar Pourreza, Guggenheim Partners - Analyst [26]

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Great, terrific. Thanks. Trey, congrats on the new move.

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Trey Griggs, Calpine Corporation - President of Calpine Retail [27]

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Thanks very much.

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Operator [28]

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Angie Storozynski, Macquarie Research Equities.

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Angie Storozynski, Macquarie Research Equities - Analyst [29]

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Thank you. Wanted to talk about Texas. You are retiring your Clear Lake co-gen I think later this month. Houston will have a new transmission line only in June of next year. How do you see not overall ERCOT, but that zone performing for the next, say, 1.5 years?

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Thad Hill, Calpine Corporation - President & CEO [30]

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Angie, it is good to hear your voice. I'll start and then Andrew or Caleb or Trey or somebody else can maybe weight in on. Look, Texas builds transmissions lines pretty effectively. So Houston is at a premium right now over the long term, and we think it deserves to be there over the long term.

I don't think that you can make the long-term view that any one part of Texas will remain at a premium, as much as we would like that. That's just kind of the way things work here. Generally we're constructive if the market beyond the basis because we acted, we're losing money at Clear Lake, and took it out.

We believe up to 30% of the assets in Texas are losing money, and it's a tough environment with the link coming in. And we expect even more retirements. So I'll see if anybody wants to add anything, but we're very constructive that eventually economics will work and we did our part with Clear Lake, and we will see how others eventually respond or not; that is not in our hands.

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Angie Storozynski, Macquarie Research Equities - Analyst [31]

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Okay. On PJM, we share your opinion about EMAAC. However, what is your take on forward spark spreads? I mean, you have a number of assets that are being developed, and granted not necessarily in EMAAC, but we're no longer see them hedging like a typical plant, gas plant in forward gas and power markets.

So those revenue puts that they have to actually procure financing are making us concerned about the level of forward spark spreads because we think that there's not enough of expected draw of gas and not enough of a power supply being depicted in forward curves. What do you think about spark spreads, forward spark spreads in PJM?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [32]

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Great, Angie. This is Andrew. Look, as Trey said in his opening remarks, we laid out where the PJM spark spread is at West Hub. You can see that it is fairly stable as we go out through 2019. And to be honest with you, as we look at it we think it is relatively fair.

It is already well below where we were for the last couple of years, and we think the market has priced the new capacity incorrectly. There is still going to be abundance of total supply of Marcellus gas, and we think that over time, although the spark spread's not going to be as exciting as it was for the last couple of years, that the forward market right now is providing a pretty good indication of where it's going to be.

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Thad Hill, Calpine Corporation - President & CEO [33]

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Angie, on the bigger picture I do think it is interesting. We saw some new builds come into Texas financed in similar ways, and that activity has stopped. In New England saw the capacity market, although as we mentioned, it was lower. There was no new, and in fact actually a little bit of a decrement of capacity in New England.

So the real question I think in a lot of people's minds is one is when the supply gain in PJM going to slow down. The RTO pricing, I think people have a fair view on the outlook, it's not going to be very huge, probably. You've got these spark spreads which are down $10 a megawatt hour versus where they've liquidated this year and last year in the forwards, which is appropriate. While there will probably be some new combined cycles that can bid into this auction, I hope that we are at the beginning of the end of that.

But this is the reason why we have a geographically diverse portfolio, because while we think PJM is fairly represented here, there's not a lot of growth there. In New England we think we've clearly found the bottom and there's reasons to be optimistic from here. In Texas and even California, at the beginning of the decade we think there are reasons to be optimistic. It's one reason you have a diversified portfolio.

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Angie Storozynski, Macquarie Research Equities - Analyst [34]

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Thank you.

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Thad Hill, Calpine Corporation - President & CEO [35]

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Thank you.

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Operator [36]

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Greg Gordon, Evercore ISI.

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Greg Gordon, Evercore ISI - Analyst [37]

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A lot of my questions have been answered already. I have one more for you. On page 11 when you give your natural gas price sensitivity, and this is actually a good follow-on to Angie's question. Are you extrapolating in PJM that if we were to see a significant increase in natural gas price at M3, that you would see a higher overall EBITDA because of an improved spark spread in that market, or do you think that -- what are the factors that drive the higher revenues when you look at your natural gas price sensitivity in PJM as, let's say, as it pertains to Texas?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [38]

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Good question. This is Andrew. As we said before about these two sensitivity tables, it is tough to look at one in isolation of the other. Each table holds the other factor constant.

The top table does show our sensitivity if you are to assume heat rates stayed unchanged, but I think it is very reasonable if we were to see, say, as you suggested M3 prices increase that we would see heat rates compress. So looking at what that effect is from the bottom table as an offset, I think is reasonable. We have provided in the previous quarterly disclosures our view of what that looks like on an unhedged basis with the Calpine Smile. So I'd probably points you back to that as a good way to look at the two combined in an unhedged year. In general, looking at these sensitivities, I do think that the top table should be offset by some portion of the bottom.

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Greg Gordon, Evercore ISI - Analyst [39]

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Right. And that would be increased depending on how much of a quantum of gas price change you wanted to assume, right?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [40]

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I think that is right.

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Greg Gordon, Evercore ISI - Analyst [41]

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(Multiple speakers) the gas price does not have as much of an offset on the heat rate as $1 gas change, for instance?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [42]

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That is right, which is why it's probably helpful to go back to that Smile table. I think that what the Smile table would show you, or chart, excuse me, is that once we start seeing Marcellus prices increase, say, above [$2.50] we start actually seeing probably a benefit of our portfolio, much as we have with Texas and California.

Certainly the left-hand side of the Smile, if we were to -- as we saw prices go from $1.30 up to $2, we do expect to see PJM sparks spreads compress, which has basically already happened in the forward market and is priced in. To some extent from here where the forward markets are trading for something like 2018, we actually don't see at those price levels much downside to an increase in the Marcellus price because is it's already somewhat high and reflected in the sparks spread.

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Greg Gordon, Evercore ISI - Analyst [43]

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Right. One of the things that I find interesting is when I look at a histogram of historic forward power prices against forward gas prices at PJM is that it would appear to me that at sort of a $3 level at M3 you are at a tipping point where power prices would actually start to go higher if we saw a further move-up in Marcellus gas price, whereas as we saw last year from February through June we had a big move in gas price and all that happened was spark spreads went down but power did not start to go up. If we had a similar quantum of move from, let's say, low $2s to mid-$3s on M3 gas, not that anybody believes it'll ever will happen, there should be at least a modest increase in spark spread and power prices should in fact actually go up for the first time in a few years in PJM, right?

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [44]

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Yes, I think that's right and probably a better summary of what I was trying to say. (Laughter).

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Greg Gordon, Evercore ISI - Analyst [45]

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Fair enough

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [46]

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If there's one I do think, I do think that probably the bottom point is more like $2.50 rather than $3.

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Greg Gordon, Evercore ISI - Analyst [47]

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My last question is, these charts don't and can't fundamentally capture the opportunity to generate revenue from volatility. And again, after last summer nobody believes there will ever be a volatility event again ever either in any market. But can you refresh our memory on what sort of an hour at the offer caps and inter-cot might mean for you in terms of potential revenue capture?

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Thad Hill, Calpine Corporation - President & CEO [48]

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Greg, I will take that. You are right. Obviously our portfolio lacks volatility more than it lacks lack of volatility. We're hopeful we will have a return to volatility. I think that's overall good for our business, although our retail business is a partial hedge of that which is one of the reasons why we like that.

Look, at $9,000, a couple of hours at the offer cap makes a material difference to us. And Andrew, I don't know if you know what two hours at the offer cap mean on a year-long spark, but it's a significant move up should we get there.

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Andrew Novotny, Calpine Corporation - SVP of Commercial Operations [49]

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Yes, when we think about the summer package for July/August, every hour at the price cap is worth about $13. So you can divide that by six, I guess, for the first calendar year on the spark spread.

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Thad Hill, Calpine Corporation - President & CEO [50]

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So material.

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Greg Gordon, Evercore ISI - Analyst [51]

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Thank you, guys. Take care.

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Thad Hill, Calpine Corporation - President & CEO [52]

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Thanks, Greg.

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Operator [53]

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Michael Lapides, Goldman Sachs.

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Michael Lapides, Goldman Sachs - Analyst [54]

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Congratulations on a good quarter. Real quick. On the New England capacity auction, one of the surprises, at least for us, that came through was the significant on a percentage basis increase in demand response and energy efficiency. Just curious how you think the move to pay for performance, or CP, and what is happening in the DR markets is actually kind of playing out versus kind of original expectations when pay-for-performance was put in place?

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Caleb Stephenson, Calpine Corporation - SVP of Wholesale Origination and Commercial Analytics [55]

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H, Michael. This is Caleb. Yes, we also were surprised to see a significant pickup, somewhere in the neighborhood of 640 megawatts of new energy efficiency and demand response which puts the total energy efficiency and demand response participation auction close to 3 gigawatts, which is roughly 10% of supply. It is a significant portion of what cleared in the auction. We will have to see how this plays out. Performance standards continued to grow more stringent, and we do question the ability of demand response in particular to succeed in a high-performance environment.

From an energy market formation perspective, it is actually probably helpful to have an increasing portion of the supply be represented by demand response as opposed to, for example, [near] combined cycles. While the auction result was down significant year on year, it's still a great price and we see upside in the energy markets by virtue of the participation from demand response

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Thad Hill, Calpine Corporation - President & CEO [56]

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Michael, if I could, I'd go beyond. I think Caleb did a great job of addressing the energy market upside from lower power plants and more high-priced DR in there. But I do think it is important to note that the performance standard that you mentioned actually increases next year.

It goes from $2,000 to $3,500 -- or next auction from $2,000 to $3,500 a megawatt hour. And we did not see a lot of [delouse] bids this year, but next year there is not only more incentive to be delisted, but the results in more penalties if you can't operate. So I actually do think that some of the changes in the market actually make the forward capacity auctions in New England likely more constructive than what we've seen so far, just to hit the capacity point. I think Caleb nailed the energy point.

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Michael Lapides, Goldman Sachs - Analyst [57]

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Got it. On another topic, you've done a good job over the years of rationalizing the portfolio to focus on the primary competitive markets, New England, PJM, Texas, and to some degree California. How are you thinking about the portfolio outside of that, meaning you still own some assets in some of the regulated states, you still own some assets in Ontario, you don't have a whole lot of scale in New York, even though you kind of own that plant right outside the airport. Just curious about how you think about further rationalization of the portfolio from here?

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Thad Hill, Calpine Corporation - President & CEO [58]

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Michael, thanks. We will do what is it in our shareholders' best interest with asset sales or rationalization if and when it make sense. The assets that we sold as we've kind of rotated our portfolio into the markets that we're comparable in that are fair to IPPs, we've sold the two types of ours, primarily. One is either a load-serving entity that could put it into rate base, or two is where we actually were successful in originating a contract from the asset and yield-seeking investors were willing to pay a lot more than our shareholders valued them.

I think that's still a useful framework to think about these individual assets. Every asset has a story. You mentioned some of them, and I won't go asset by asset. But we do think that there is potential out there.

That being said, a lot of times there is one natural owner for these assets, there are a couple of natural owners. And we have found that by being -- not having to do anything by a particular time and by being very deliberate and by being patient, we've done some pretty good deals.

You should expect that somebody values their assets more than we will, when it is right and the value is there we will continue to transact. And it is hard to predict because all of these are one-off and kind of bespoke, but we think we will be able to continue our track record.

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Michael Lapides, Goldman Sachs - Analyst [59]

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Got it. Last item, and congrats, Trey, on the new gig. Can you talk a little bit about the volumes on the retail side? I know you've talked about the customer account on that slide, but just curious on the volumes roughly what percent of your total retail volumes is large industrial versus what percentage is res or small commercial?

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Trey Griggs, Calpine Corporation - President of Calpine Retail [60]

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Yes, Michael. Thanks, I appreciate it. Good to hear your voice. The total volumes aggregated by region are on slide 12 in the top right where we show our retail load in California at approximately 8 million megawatt hours. The central region, ERCOT, 20 million megawatt hours. In the East, which includes the mid-Atlantic states, New England and some of the Midwest, we are roughly matched with our generation footprint with a 37 million megawatt hour retail load.

In terms of splitting that between residential, even though -- residential and C&I, even though we have a far larger number of residential meters, our volume is far and away weighted towards C&I. The C&I platform, as you can imagine, is a great liquidity tool for us given that it is large volume and highly transactional. So even though residential is smaller in terms of load, the C&I actually is a terrific liquidity channel.

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Michael Lapides, Goldman Sachs - Analyst [61]

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Okay. The only reason why I asked that is if I take the total megawatt hours in the mid-60 millions and I take the $400 million midpoint of the margin, it is kind of talking about a $6 a megawatt hour average margin on retail. That just seems relative to what some of the other, including some of the bigger retailers in the country, have said about C&I retail margins.

Just seems a little bit above. I wonder if there is significant margin risk, or margin erosion risk if the bulk of your supply is C&I.

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Trey Griggs, Calpine Corporation - President of Calpine Retail [62]

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The margins, first of all I am impressed you did that math in your head like that, that quickly. Second, the margins in retail, and the math, by the way, is roughly accurate. The margins in retail vary widely between residential and C&I, as you're well aware. They tend to be smaller margins on a (inaudible) basis in the C&I space then in residential where the numbers are larger, but on a blended basis roughly around where you're talking about.

In terms of stickiness and worried about attrition and all that sort of thing, you'll note that we included our retention rates in our slide 12 at the bottom. These platforms are not new.

The Calpine Energy Solutions business, what we acquired from Noble, has a customer base that is loyal and in many cases has been with that platform for 10-plus years. Similarly, our Champion business, as you're well aware, has for the last six of the seven years won the JD Power award for best in customer service and has a very loyal and proud brand.

And the North American Power business that we acquired in the Northeast is primarily residential, and certainly a somewhat newer platform, certainly newer to us. But similarly has a strong and proud brand. We feel good about the fact that we've now built a retail platform with better than industry average retention rates in our view.

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Michael Lapides, Goldman Sachs - Analyst [63]

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Got it, guys. Thank you. I will turn it over to someone else. Much appreciated

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Thad Hill, Calpine Corporation - President & CEO [64]

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Thanks, Michael.

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Operator [65]

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Praful Mehta, Citigroup.

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Praful Mehta, Citigroup - Analyst [66]

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Hi, guys. Thanks. A lot of the topics have been covered, so I will get to nuances on the topics. One was on the asset sales point, Thad, that you brought up. The [ken] seems to be a disconnect between private and public market valuation. I want to get your view on how you thought private markets is looking at assets, or if there's any particular region that you think private market will be more aggressive on valuation versus how your current portfolio has been valued by the public markets?

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Thad Hill, Calpine Corporation - President & CEO [67]

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Yes. Thanks, Praful. I'm trying to read through the question. There are -- the private valuations tend to look a lot higher than the public valuations. We have found that the valuations are even higher when there's yield associated with the contract versus merchant, or when somebody is trying to put it in rate base, as I've said.

It is very clear that private investors are underwriting what looks like a different forward expectation of the business than public investors are, and we hope private investors are right. Over time that arbitrage will collapse, and hopefully we will see value appreciate.

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Praful Mehta, Citigroup - Analyst [68]

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Fair enough. Getting back to slide 11, when you do show these sensitivities to gas prices, I guess that as GAAP goes above $2.50 or $3 gas is more on the margin so the correlation between gas and power prices and heat rates starts to increase. I wanted to get a little bit more on how does retail fit into that. Now that you have a bigger retail footprint, we would expect retail margins to compress as power prices go up, and is this sensitivity -- how should we think about the sensitivity to overall EBITDA, I guess, with movements in power or gas prices?

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Caleb Stephenson, Calpine Corporation - SVP of Wholesale Origination and Commercial Analytics [69]

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This is Caleb, Praful. The sensitivities really aren't impacted that significantly by the inclusion of the retail platform in the business. And the reason for that is that we run a flat book within retail organization.

So it certainly gives us a hedging tool, and that shows up in our hedge percentages and has an effect that way. But in terms of whether we have additional volumes on explicitly the retail business, there is not much of an impact.

In terms of price relationship, we really haven't seen that much of a relationship between margins and price. Certainly as gas prices have fallen over the years it's given an opportunity to increase volumes, but margins have held and they're pretty steady from what we've seen so far.

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Praful Mehta, Citigroup - Analyst [70]

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And you don't -- it's not like a near-term thing where retail margins hold on for a year or two but then will compress or move with power prices? Do expect the book to stay flat irrespective of where power goes?

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Thad Hill, Calpine Corporation - President & CEO [71]

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Praful, I will start and then I will let anybody answer. Once they are a customer and they are in our portfolio, they are hedged. I think your question, and I think we are answering, once you get out beyond customers that you are signing up, you don't know because there's quite a lot of these customers are in one-year or two-year or three-year contracts.

There actually could be compression in the upside of an energy market. But I think we would welcome that world, a little more volatile energy market, in a retail margins on 2019 after our contracts have rolled off [as] a benefit to our overall portfolio. So maybe we can all hope that happens.

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Praful Mehta, Citigroup - Analyst [72]

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Fair enough. All right. Thank you, guys.

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Operator [73]

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

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Bryan Kimzey, Calpine Corporation - VP of IR and Financial Planning [74]

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Thank you, and thanks to everyone for participating in our call today. For this of you that joined late, an archived recording of the call will be made available for a limited time on our website.

If you have any further questions, please don't hesitate to call us in Investor Relations. Thanks again for your interest in Calpine Corporation

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Operator [75]

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Thank you, ladies and gentlemen. This concludes today's conference. Thank you for joining. You may now disconnect.