Calpine Corp. (NYSE:CPN)
Q2 2016 Earnings Conference Call
July 29, 2016 10:00 AM ET
Bryan Kimzey - VP, IR & Financial Planning
Thad Hill - President, CEO & Director
Trey Griggs - CCO & Executive VP
Zamir Rauf - CFO & Executive VP
Andrew Novotny - Senior VP, Commercial Operations
Thaddeus Miller - CLO, Executive VP & Secretary
Jerimiah Booream - UBS
Keith Stanley - Wolfe Research
Ali Agha - SunTrust
Abe Azar - Deutsche Bank
Brian Chen - Bank of America Merrill Lynch
Praful Mehta - Citigroup
Welcome to the Calpine Second Quarter 2016 Earnings Conference Call. My name is Vanessa, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.
I will now turn the call over to Bryan Kimzey, Vice President of Investor Relations and Financial Planning.
Thank you, operator, and good morning, everyone. I'd like to welcome you to Calpine's investor update conference call, covering our second quarter 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 section of our website.
Joining me for this morning's call are Thad Hill, our President and Chief Executive Officer; Trey Griggs, our Chief Commercial Officer; and Zamir Rauf, our Chief Financial Officer. In addition, Thad Miller, our Chief Legal Officer; and Andrew Novotny, SVP, Commercial Operations, 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 two of the presentation, which explains the risks of forward-looking statements and the use of non-GAAP financial measures. For additional information, please refer to our most recent SEC filings, which are on file with the SEC and on Calpine's website.
Additionally, we would like to advise you that statements made during this call are made as of this date, and listeners to any replay should understand that the passage of time by itself will diminish the quality of these statements. After our prepared remarks, we'll open the lines for questions. In the interest of time, each caller will be allowed one question and one follow-up only.
I'll now turn the call over to Thad to lead our presentation.
Thank you, Bryan, and good morning to everyone on the call. And thank you for your interest in Calpine. Today, I'm pleased to report second quarter adjusted EBITDA of $452 million and adjusted free cash flow of a $158 million. Our business continues to operate well in all fronts. Operationally, we continue to perform. Our plans are meeting more and more, whether in the Eastern Texas where we now often displace call in operators base work plans or in California where despite lower rent times this year given the strong hydro conditions, we're increasingly supporting the states intermittent resources with our flexibility.
Time and again, our assets arise in to the challenges presented by the evolving markets. Commercially, our champion retail business continues to deliver. On the wholesale front, we continue to work on our customer focus and toward that end are pleased to report the California Public Utilities Commission has approved our latest 50 megawatt contract at a fixed price off of the Geysers. The Geysers continues to be a stalwart asset and the team there remains on track which recovered from last year's major wild fires.
We expect to be back to full production levels before the next earnings call. Trey will have more on our plan in commercial performance in a few minutes. I just want to say that I'm confident we will continue to drive results through operational excellence and as we strive for a customer led business like no other. We've had a very strong first half of the year, which combined with a good hedging program, has enabled us to remain within our regional guidance range despite or due to the weak summer power price liquidations today.
Today, we're narrowing our guidance range for this year to $1.8 billion to $1.9 billion of adjusted EBITDA and $710 million to $810 million of adjusted free cash flow.
On the next slide, I want to take a minute and reflect more broadly on the changing landscape with the electricity business. For some time, we've been describing the secular forces that are shaped in electric markets. These include first, low natural gas prices, and second, increasingly stringent environmental roles. Both of these are good for our business, that resulted in more run hours per fleet and in general shift away from older based load units.
The third major secular force, the rapid growth the renewable generation underscores the importance of our fleet's operational flexibility. To-date, renewables growth has matured primarily by subsidies such as tax craves. In the future, we expect other policy initiatives including the clean power plan to continue to concur this maneuverable growth. These three ongoing changes in the power sector, I mean, the flexible economic natural gas for generation has becoming more and more important. Just this past week the US set new all-time records in terms of natural gas burn for power generation, as shown on the chart in the bottom left.
The charts on the right further highlight not only the historical but also the potential future revelation of the generation mix in the United States. The clean power plan case reflects the EIA's analysis of how the resource mix might evolve to both maintain reliability and achieve the target emissions reductions by 2030. As you can see, natural gas generation is projected to increase by nearly 30% versus today. Most trends in yet is the recent clean energy pledge that President Obama made with the leaders of Canada and Mexico.
This calls for 50% carbon free generation by 2025. Unlike the clean power plan, there is no clear policy vehicle to achieve this vision, so it is in a very different place not tangible, yes, store challenged clean power plan. That said, is that we're achieved as you can see in that outcome on the bottom of the slide as coal declines, gas out there is likely to increase. As the world shifts away from coal and towards renewables, natural gas would be a growing part of the resource mix and we will benefit greatly from that dynamic. The good news for Calpine is that we are well positioned for this this evolving road, growth in intermittent resources, the current low gas price environment and the operational flexibility of our power plans provide us a distinct opportunity.
Of course, despite our advantage fleet, we are not sitting still as we discuss on the next slide. We continue to position ourselves for this new environment to active portfolio management, a strong customer focus active advocacy and continued operational innovation. Portfolio management is core to what we do and it has enabled us to strategically reposition our portfolio over time. Our efforts this quarter have been focused in Texas where our business is in solid shape. Our modern and flexible gas fleet is performing quite well, enable the gas high win environment and as we have described industry we'll discuss, we continue to believe that the fundamentals will ultimately be reflected in higher and potentially sharply higher, prices during peak lit hours.
That said, within the next couple of weeks, we intend to file with ERCOT to retire 400 megawatt Clear Lake facility. We expect to seize operations by the summer of 2018 at the latest and possibly might sooner. Clear Lake is an older technology than our other plants and its maintenance costs have risen. Without a better price signal, we're no longer going to sustain its operation. In the absence of much needed market reform from the Texas Public Utility Commission, we expect more retirements from others. Despite the stay or the regional haze federal implementation plan for Texas, many power plants are struggling to breakeven.
We'll still eventually get in market recovery and it's just likely to be much more dramatic and unnecessarily volatile. Either way, supply and demand fundamentals will play out. Clear Lake is just one of several portfolio changes we made this year including the sale of South Point, the layup of Sutter and the purchase of Granite Ridge. We'll continue to actively manage our portfolio to position the fleet for success in a shifting world. Clear Lake is the last of our assets with any kind of near term economic challenges. Although I will say we're now sort of challenge, we will not maintain and just hope for a better day.
We also have actively sought to migrate our portfolio to more attractive assets and more competitive regions and then a first time move complemented a core point generation business with Champion's retail sales channel. You should expect that we're almost continuously in discussions on both the buy and the sales side of opportunities. We think this active management crew differentiates us from others in the business. We'll continue to be agile with how we position ourselves. In other source of our long term success and one we're continuing to double down on, is our customer effort.
Over the last several years, we have been uniquely successful on the wholesale origination efforts with our California contracts, our Texas public power franchise and the South East efforts have facilitated the sale of that fleet of good value. This success has come from a focus on relationships being flexible and creative with the products and services we sell and making sure that our operations capability can back up with the customer demands. Even while continuing the wholesale efforts as just discussed win a retail as fall with the acquisition of Champion. We plan to continue to grow our retail efforts with the same principles that have led to our unique wholesale success.
As you can see on the chart in the lower left, we're pushing every larger amounts of our power production directly to customers versus indirectly through financial hedging. This provides more stability at cash flows in higher margins. And a time of change and difficult commodity environments, having the direct link toward and customer relationships as part of our business, provides many benefits. I cannot say enough about our advocacy efforts led by Thadd Miller and Steve Schleimer. Along with our peers and trade organizations, our efforts have been hugely successful on landmark legal and regulatory arenas.
Without trying to name all the supplicates, it's now clear in the Eastern markets that wholesale power rests under Federal, not state jurisdiction, that all resources including demand response much participate on a level plain sure and capacity markets that out of market contracts for non-renewable generation are not permitted in most cases and finally the capacity markets can't provide more compensation in many originally envisioned both the real requirement to perform.
This is really a remarkable track record and shows the commitment of the courts and for to competitive markets. In the upper right you can see we and many of our peers are currently focused on a number of key issues. We are confident in our positions and ability to reach favorable outcomes. Without taking you through the entire list, I will pause for a minute on the one doing with appropriate compensation for services provided. We're currently into rather contradictory moment in time, the wholesale power markets were designed to provide the cheapest sources of power. However, some current national and state environmental and tax policies fly directly in the face of this.
The result is a general conflict between state renewable or clean power procurement efforts and federal over side of wholesale power markets. For example, as we disclosed before, our California business is overall very healthy with strong contracts with the Geysers and some of our gas plants that extend want in next decade. However, our merchant gas plants which are absolutely critical to liability particularly in Northern California and will be for many many years under any scenario received very little conversation.
From an investor standpoint, the good news is we believe there's really no downside from here, given that these plants contribute very little cash today. But we are providing critical services without even a reasonable shot in for a compensation. Therefore, in response to another generators filing effort, we recently filed intertwined testimony that requests a forked technical conference to ensure the long term viability to competitor for market in California. We're also continuing to be actively engaged with state regulators from this issue. All that said, although we're in necessary resource in that market, we don’t believe compensation is reasonable and we've grown increasingly impatient to current state of affairs. In the coming month, you should expect to hear more about this from us.
Finally, a comment on our operations. As many of you know, we greatly pride ourselves on our fleet and our technical capability. In contrast to nuclear and coal base load, we provide the flexibility to meet load swings and the opportunity to capture the most attractive pricing. We have continued to invest appropriately in our fleet and our well maintained assets whereas competitive today as they were last decade when they were coming online. As intermittent resources increase, a much of the older coal and some nuclear baseload units retire, we believe our gas assets will run a much the same way for the most part.
In some markets, by many of the Eastern markets, where the renewable resource penetration maybe less, we are likely to be more base loaded. In other markets like California around solar, in Texas around wind, our cycling capability will be ever more important. We must however continue to innovate. At times, our gas assets may need to start twice a day or to ramp faster. As you can see in the world right, our California gas peaker fleet is new more today than ever in the past. We'll continue to maintain them and then keep investing a modest modifications that will enable them to meet this challenge.
Maybe more interesting is how we're shifting the operational flexibility of our Geysers geothermal fleet. In response to the heavy soar component of the California resource mix, prices can sometimes go negative and we believe this will be a continuing trend giving the ever procurement of solar by the state. Of course, once FERC price go negative in the afternoon, it is not a problem for our gas fleet, we simply turn off. But this problem which is reeking how the coal and nuclear fleets across the country, also has implications for a base load geothermal plant like the Geysers. Despite having a zero marginal cost asset, we must be flexible.
As you can see in the lower right, we are continuing to innovate how we operate but changes in operating per axis as well as physical modifications. Historically, the Geysers has been a base load generator. With the modifications we're making now through 2018, we will increase our ability to curtail output during negatively priced afternoons. The team on the hill as we call it, is doing a great job and the value that renewable, dependable and increasingly dispatch able resource continues to grow.
In summary, the electricity orders evolving from one of traditional horizontal base load intermediated and peaken resources to one of intermid in generation and fast react and flexible natural gas units. We have the right fully to take advantage of these changes and we believe we're taking the right steps to continue to evolve our portfolio, leverage our customer relationships, actively advocate and innovate operations to deliver value over the long term. I'm very excited about the next several years.
With that, I'll turn it over to Trey.
Thank you, Thad. And good morning to everyone joining us. As Thad just described, our commitment to operational excellence is a key component of our efforts to ensure Calpine's critical role in the nation's evolving power markets. The charts on this slide, highlight our performance on this front. As always, I'm fortunate to present them on behalf of Charlie Gates and his team to whom all the credit belongs.
Starting with the top left, we continue our track record of delivering top core tail safety statistics. Our number one priority at Calpine is to make sure our employees get home safely each and every evening and we will continue to focus on making our workplace safe. Below that, our forced outage factor for the second quarter overall was 2.7%. While this performance is notable, by industry standards that percentage is slightly above our target of 2.5%. Importantly however, a closer look at the quarterly results revealed that the outages occurred primarily in April and May.
By the time the heat came in June, our fleet was ready, achieving a 2.2% forced outage factor fleet wide. The table in the bottom right shows the power plants with stellar performance in both safety and forced outages during the second quarter. Congratulations to the teams whose efforts resulted in this recognition. Wrapping up in the top right, you'll see our second quarter generation volumes by region. Consistent with our expectations, the return of more robust hydro conditions in the West has significantly reduced run times for our gas fleet.
Meanwhile, in Texas, our volumes reached a second quarter all-time high, driven largely by higher spark spreads and lower natural gas prices both of which worked to our benefit. In the East, absent the impacts of additions to our portfolio, our generation was roughly consistent with last year's second quarter despite milder weather early on. These volumetric trends are reflected in our hedge disclosures as shown on the following slide. As I mentioned no our first quarter call, in comparison to the approximately 115 megawatt hours we generated in 2015, we are projecting total generation volumes for 2016 to trend towards approximately 105 million megawatt hours with 2017 slightly below that based on the forward gas curve.
With that in mind, let's take a look at our updated disclosures. We've increased our hedge percentages across the board since our last call, most notably for 2017. As a result of incremental hedges, our hedged margin for megawatt hour declined in both 2017 and '18 as is typically the case as we get near to these outer years. As a reminder, our Champion retail volumes and margins are included in the hedge disclosures presented. Our standard sensitivity disclosures are presented in the middle of the slide in which we isolate the impacts of a $1 move in natural gas prices and separately of a half heat rate point holding all else constant.
The following slide illustrates the impacts on our fleet when we combine these two events, which more closely reflect how our markets typically behave. Here we provide an updated view of the Calpine Smile, which illustrates the sensitivity of our commodity margin, ignoring hedges to changes in natural gas prices assuming offsetting moves and market heat rates. Whereas in the past, our smile was more symmetrical, you can see that we are now positioned with more upside as gas prices rise and yet we remain relatively insulated from downside risk. The shift in the shape of our smile has largely been driven by first changes in our portfolio, including the sale of the South East assets and an increase in our New England footprint.
And second, a decline in coal costs particularly in Texas. At a high level, the updated smile reinforces the point that Calpine's benefits from rising gas prices. This view can be further dissected into the nuances of the regions in which we operate. In the West and New England, we are basically long gas, given the lack of coal competition in these markets. In particular, the portion of our Geysers fleet who's prices remain indexed to around the clock prices, benefits from rise in gas prices that drive power prices higher in that market. In Texas, were long at gas prices generally above $2 per MMBtu. As gas prices rise above this level, the efficiency advantage of our fleet relative to the market begins to benefit us more.
Below $2 per MMBtu, we become short, which accounts for the less side of the smile. Meanwhile, in the mid-Atlantic, given the significant amount of coal generation remaining in the market and the comparatively higher prices of that coal, we still tend to be short at low natural gas prices. With ongoing shale production in the Utica and Marcellus, we believe this position will continue to benefit us for the foreseeable future. Taking together our regional gas sensitivities create the Calpine Smile as depicted on the slide. Generally, our fleet is long gas above $2 and short gas below $2.
Let me conclude on the following side with a broader overview of the same markets. As everyone is aware, there are particular challenges unique to each market in which we operate. However, the value and necessity of Calpine's clean and reliable fleet of power plants has never been more certain. For example, the California power market will continue to rely on our fleet long into the future. Increased intermittent generation and once through cooling regulations will drive further retirements of less efficient gas generation as well as Diablo Canyon. As a result, California is non-intermittened generation supply will become uncomfortably tight.
Units like ours that can provide reliable clean power when the sun is not shining and the wind is not blowing will be needed more and more to support the states renewable power objectives. Near term, given the location of our merchant fleet in Northern California, along the PG&E backbone gas pipeline system, the recent rate case decision means that our assets will begin experiencing a roughly $7 per megawatt hour advantage relative to nearly 75,00 megawatts of other Northern California generation that will now bear the burden of paying higher gas delivery charges.
We believe our fleet in California is very well positioned for the future. And as Thad mentioned in his remarks, we are actively working to ensure that the market against economically recognize the critical services our assets provide, today and for years to come. Switching to Texas, we continue to see weather normalized load growth in the second quarter. However, despite the growth, we have recently seen an emergence of mothballing decisions, driven by maintenance expenditures that the market is not providing sufficient compensation to cover. And this is happening today, prior to and independent of any requirement or lack thereof for compliance with regional haze regulations.
The recent stay of the EPA's regional haze SIP for Texas maybe viewed by some as a lifeline for coal generators in the state. However, Texas still has obligations to make with respect to regional haze and interstate transport that will drive SOx and NOx emissions down. As a matter of fact, the EPA still needs to finalize its SO2 non-attainment area designations in Texas, which may impact some large coal plants. Regardless, the fact of the matter is that nearly 25% of the state's existing capacity including PRB coal and less efficient gas steamers are struggling to breakeven. This is driving economically discipline generators to retire or seasonally mothball these assets rather than maintain them.
So, for a state looking to successfully manage continued load growth, intermittent wind and an energy only philosophy, the current market construct is proven challenging. Wrapping up with the East, the big news from the second quarter was the result of the 2019, 2020 capacity auction in PJM. Although we were disappointed by the clearing prices for this auction, the results shed an important light on what may come next year as the market transitions to a 100% capacity performance requirement.
In the chart on the upper right, we show the composition of the reserve margin and PJM. The blue bar represents the contribution of capacity performance products toward meeting the markets reserved margin. The green bar shows the portion of the reserve margin being met by products that cleared as base, which goes away in the upcoming 2020, 2021 auction. Within the green bar, about 40% represents capacity that bid into the auction only as base. Presumably unwilling to participate as a capacity performance resource, in the upcoming auction, does that capacity go away? The remaining 60% represents capacity that bid into the auction as capacity performance, but only cleared as base.
If the same capacity is to clear in the upcoming auction which it must in order for the target reserve margin to be met, then prices presumably have to rise. Additional factors, such as the inability to bid in seasonal capacity, the higher cost of new entry and the lapse of bonus depreciation are also supportive of higher auction prices next year.
So, with that, let me now turn it over to Zamir for his remarks.
Thank you, Trey. And good morning everyone. I will now share with you our second quarter results and drivers for the remainder of the year. Our second quarter adjusted EBITDA of 452 million was roughly in line with last year. The chart on the left shows the key year-over-year variances. We benefitted from portfolio additions of Granite Ridge in February and a full quarter of commercial operations at Garrison. Please note that these amounts are presented on an unhedged basis with a contribution from hedges associated with these plans embedded in the markets and hedge column.
We also benefitted from an increase in regulatory capacity revenue due to higher capacity payments in PJM and New England in April and May. Offset by the expiration of Pastoria's tolling contract and release operating lease. Lastly, we received a gas transportation credit from PG&E which mostly offset lower market pricing and hedge contributions year-over-year. Turning to the balance of the year, capacity payments in PJM and New England, decreased in July as we rolled into the 2016, 2017 auction year, along with a lower contract value from the roll off of the previously mentioned Pastoria contract.
The largest year-over-year variance however, is the decline in market and hedge energy margin, primarily in the third quarter. Midway through this summer, we have yet to see spark spreads with the strong price levels we hedged that last summer and as such, we are narrowing our adjusted EBITDA guidance range for the year to 1.8 billion to 1.9 billion.
On the following slide, let's take a closer look at our second quarter performance on a regional basis. In the West, adjusted EBITDA was up 21 million year-over-year. In addition to items described on the previous page, our generation and spark spreads were lower due to the expected increase in hydro generation. We also had lower hedge power prices for the Geysers due to lower natural gas prices year-over-year. In Texas, adjusted EBITDA was down 6 million due to lower contributions of wholesale hedges, partially offset by the contribution of our retail hedges and higher generation in Texas as we achieved a record second quarter capacity factor of 62% in Texas this year.
In the East, adjusted EBITDA decreased 20 million due to lower spark spreads driven by a milder weather early on, partially offset by our portfolio additions of Granite Ridge and Garrison, higher contributions from retail hedges and a PPA at Morgan that started in February.
Turning to the last slide, Calpine continues to represent a compelling value proposition, now more than ever. Over the years, our business has and will continue to whether through many different market conditions. We experience extreme, mild and moderate temperatures in all of our markets both in the summer and winter months. We've operated in abnormally wet and dry hydro conditions. We've withstood and supported significant penetration of renewable generation in California and Texas. And last but not least, we've gone through volatile swings in natural gas prices. Through it all, our business has consistently produced strong and stable adjusted EBITDA and free cash flow and will continue to do so for the foreseeable future.
Our geographic diversity, strategic portfolio management and versatile gas-fired fleet produces resiliency from the secular trends in electric markets. In addition, we recently refinanced our 2019 and 2020 senior term loans and we do not have any corporate debt maturing until 2022. Our balance sheet is in great shape and we are focused on de-levering towards our target of 4.5 times. There are also some tailwinds which I'll address in a minute, but even before considering those, we are deeply undervalued. Our levered free cash flow yield is approximately 15% which is about 6 percentage points higher than our five year average, yet our outlook has not materially changed.
Don’t forget that not all EBITDA's created equal. We convert 75% of our EBITDA to unlevered free cash flow, which is the highest rate in our industry and significantly higher than coal and nuclear fleets. In addition, our modern flexible fleet deserve a higher terminal value. Our high quality EBITDA and long lived assets had not reflected in our current free cash flow yield. Regarding the tail winds I mentioned, I see several opportunities for upside. Texas and California are at cyclical lows. There is potential upside in PJM as we move to a 100% CT. There is an increasing need for flexible gas fire generation and natural gas prices are rising. There are also great opportunities to grow our retail business and allocate capital in a disciplined way to enhance value for our shareholders.
And finally, in addition to these tailwinds and as we've mentioned in the past, 2018 PJM and New England regulatory capacity payments represent a $250 million locked in increase over 2016. As such, our current free cash flow yield represents a great opportunity to invest in Calpine now.
With that, thank you for your time today, and we look forward to taking your questions. Operator, please open the lines for Q&A.
Thank you. [Operator Instructions] And we have our first question from Jonathan Arnold with Deutsche Bank. Jonathan, your line is now open.
Pardon me, Mr. Arnold, perhaps you've muted and your answer line is now open. You can state your question. I am sorry. Since like we are not receiving a response from Mr. Jonathan Arnold, would you like me to proceed with the next question?
Thank you. Our next question comes from Jerimiah Booream with UBS.
Hi, good morning. Thanks for taking the question. I just wanted to dig into the hedge margin a little bit here. Say went from 24 to 21. Can you just speak to the maybe the markets where you added hedges in any other dynamic in place there?
Hey, Jerimiah, good morning. Andrew, you got in you pick the question.
Yes, sure. Thank you very much. Look, we typically don’t disclose specific markets that are adding hedges to. But in general, we do see this effect as we hedge future out years and we get closer to liquidation. It's important to note that our out year is 2017 and 2018, have a greater percentage of our long term originated contracts that have higher value. They're, you know, typically predicated one, new build cost and so those dollars per megawatt hour much higher. And as we get closer to the year and start hedging more around the clock and flat, and off peak spark spread, those dollars from what our start to decline. As we approach it’s a typical effect we see every quarter.
Okay, thank you. And also, just in terms of the Texas market, obviously you're shutting down Clear Lake, do you see any other assets on the gas front like old gas assets that might be shutting down in the near future?
Well, I think you'll have to ask the other generators to be specifically about that. We do the math, we think, you know, it's a third of the market or 30% of the market is losing money or breakeven a best and that includes a lot of co-plants that also include some of the older gas steamers that are in the market. So, what others will do will be up to them. But the economics appeared to be fairly clear from the outside looking in, till we'll see our people, you know, working for their overtime.
Fair enough, thanks guys.
Okay, and thank you. Our next question comes from Keith Stanley with Wolfe Research.
Hey, good morning.
So, just a follow-up on the hedge question. I appreciate that you do more ATC and off-peak hedging over time. Can you say if there is any bit, it doesn't sound like there's a big swing in expected generation for 2017 and '18, since last quarter. Is that right?
Yes, since last quarter. I don’t think, you know, there is not necessarily a swing in expected generation. The train is opening remarks, you know, discussed are generation expectation for 2016 kind of and beyond relative to say the prior year.
Okay. And then would you be want to say how much of your retail business is, just thinking through the retail business how much of your expected retail margins for 2017 and '18 are already kind of baked into that hedge margin. So, we're thinking a lot of the retail books already in that hedge margin number or a lot of that retail book is sort of still to be sold and upsides of those hedge margin numbers.
Well, this is Trey. So, I don’t know that I would necessarily describe it as upside. But certainly the retail book is constantly growing and is very organic in the way that it evolves. It generally is a 12 to 24 month type tenor, and you as I described in my prepared remarks know that those numbers roll up into those hedge disclosure. So, beyond 2018, you shouldn’t expect that there is a great deal of effect.
People have, we talked about the former protocols. You know, and obviously not going to respond to marked rumors or press releases. What I will say is that we've only got presume with the business if we think returns make a lot of sense, and I don’t think buying contractive projects is a way to go for us. You know, I think you triggered to make the map work, you got to get there in development. But we recognize that VOP pulling update on this, and we'll provide a much more wholesome update on our plans, what they will correlate etcetera, before the end of the year.
Okay, and --.
Okay, sorry. There is a second question on M&A and you repeat that if you would, I'm sorry.
Just any interest in sort of buying more power conventional sort of gas plants at this point?
Yes. And look, we would certainly buy more power plants, particularly gas plants as you know is what we operate and are comfortable with. But it's all a matter of brace. And so, we'll just, you know, we continue to watch everything. In the past we've been pretty successful, we've not been successful in kind of we had called transparent two step auction processes where things were heavily competing. We have been successful and we entered in to bio lateral discussions and I think, you know, as I said in my prepared remarks, you know, it kind of all times continuously, we're talking to people about they guard your assets more than we do and we're also trying to find things that make sense or we're going to continue be very disappointed on that.
I don’t think we have to have more on gas assets. I like our current portfolio but if it makes financial sense, we'll absolutely continue to acquire.
Thanks a lot.
And thank you. Our next question comes from Ali Agha with SunTrust.
Thank you. First question, when you look at your key markets, let's say taxes or PJM, maybe the New England. Can you give us a sense of and you look at those forward spreads, you gave us some updates for '16 in this side deck as well. How would you look at the forward spreads today or '17 versus your fundamental view? How, you know, is the market right right now or how much off is the market do you think from a fundamental basis and tell us what the forward curves are telling us.
Well, our Andrew maybe talk more specifically, although I don’t know, you know, how much accrual you want to get between the current market versus what we think. But generically in most of the markets, I think we see upside from where the current forwards are creating, whether it's because of the gas curve or the fundamentals. I don’t know, Andrew will. Without endangering your commercial business, you want to give him more answer in that?
Sure, let me just kind of go around the horn on some of these markets really quickly. First I think its worth, you know, talking about loads in July. So, starting with Texas, we've had great loads including well growth, at the same time for July I was had to at normally windy conditions just simply driven by the weather. That being said, those windy conditions aren’t expected to continue through August, which is typically very low wind month in Texas. So, at this point seemed a low growth we've seen there, we think it's pretty reasonable to saying that August is going to have a day or two over 70,000 of loads setting new records, and a typical August wind conditions occur, we would think that we would have a much different price response than what we're seeing from the market so far.
And as we look out the curve protectors, you know, as we've noted, Texas has the most low growth and it has the tightest reserve margin and it's not compensating generators to stay around. So, it's hard not to see some form of recovery here, whether it occurs to a changing process from that you see or volatile energy market. We're fairly optimistic on it. Then heading to the East, in terms of PJM and New England. You know, PJM has had an exciting week this week for load. We've seen loads in the mid-Atlantic get back to 57,000 megawatts, whereas well in the RTO got as high as a 152,000. We didn’t see any real scarcity pricing but we did see oil runs. The oil units run this way. Of course they are at a much lower cost and the world back when what was a $100 a megawatt hours, so that kept energy margins down to some extent.
But more importantly, when we look back at this week, we see that we are probably just a few 1000 megs away from demand response need to run, which would set the price above a $1000 a megawatt hour. So, really right on the brain. That gives us optimism as more when we look at the forward curve in PJM, which of course is down next year. But it's really down for kind of two reasons. 1) Which is real is our new plants which are going to come, but 2) a big portion of why the market is down for next year, has to do with a much much higher Marcelles price before curve is shown. At this point, given the number of pipeline delays, we're not sure that the $0.80 or $0.90 premiums from Marcelles gas next year versus this year warranted and so are pretty optimistic on PJM out the curve.
And then finally, let me just shift to the West Coast really quickly. You know, we've seen pretty reasonable loads this summer and in fact we even saw up higher show whether normalized growth for June, despite the 15,00 megs of new solar that's coming to the market. When we look at those curves, and especially given the right case as Trey mentioned in his opening remarks. We're not really sure why the forward market is priced in really very little for the increasing gas cost.
Although you got more out of Andrew than I thought you would.
Very helpful, thank you. My second question just kind of dog tailing on all of this, you know, reducing your high end of your guidance today, August hasn’t played out yet, you're talking about less windy conditions in August etcetera. Is that because of your hedge, and you're so hedged in '16 that perhaps if there is a sudden turn in the weather, you may not be in a position to capture that. Just curious why you load the high end today while the summer is still playing out?
Yes. Ali, it's a very fair question. You know, historically on the second quarter call, we typically take our range down to about a $100 million. Because you know, you're 7/12th of the way through the year and you're 2/3rds of the way through the summer. So, you know, and there been some things and sure they've gone very well and something that haven’t worked out as we might have hoped. You know, for example we I think that a very good job of being ahead of the mild winter, and benefited actually from the mild winter, but the hydro, the very why you're in California wasn’t you know heard us.
We had this summer our prices and pulled the slots few days have been fairly mild when we are sooner would have hoped on for better. And so you kind of put all these in and kind of come out, we want to give a reasonable range on and make sure that we're helping you understand the business. So, a tail venture certainly possible and we hope for them but we also want to give you all the best information we can.
Understood, thank you.
Yes, thank you.
Thank you. Our next question comes from Abe Azar with Deutsche Bank.
Hi. Is it possible to stay of the regional age roll, can actually accelerate retirement decisions. In your opinion, would people not waiting till 2021 to see co-employment time ins as we saw you do at Clear Lake today?
Well, yes, well I don’t know what other people are going to do on. And I withheld knowing the perspective in a second about you know the rather environment was out there. But I'm not sure that the difference between having capital to spend in 2019 or a year or two after matters that much, to debating whether or not you want to retire unit in 2017 or 2018. We don’t think that these assets are ultimately going to persist under any scenario deep into next decade. But Thadd you want to give a quick environmental update maybe there are some other rules that I think.
Yes. And I think our view is that the regional haze rule or at least the aspect of it that was the subject of the fifth circuit stay was one limited aspect of it. You still have later this decade or later this year rather, the [indiscernible] the best available of both retrofit technology plant that has to be put in place by Texas failing which the EPA will put it in place in December. And you also have the SOx nonattainment rules that the EPA is supposed to release. So, we think those rules continue to pressure the coal plants and coupled with the economic pressures that Thad and Trey alluded to, you know, I think we'd agree with your conclusion that it really doesn't change much.
Great. And then shifting to California. How much upside to generation do you see from the impacts of the rate case and is that mostly for your contracted units or is it for some of the merchant units?
Yes. You know, the big beneficiary here will be our merchant units. So, what the rate case is gone is its raised the price for natural gas, you know, that pull off of the local distribution system for the lack of the better word in Northern California by a $1 occurred MMBtu. And there are about 75,00 megawatts of that that exist in our operations today. So, you know, there are so many heated rate units and men of our merchant units pull off of that, we pull off the backbone. So, our merchant unit's get a $7 megawatt hour benefitted somebody else's combined cycle has to dispatch and we get a $10 or an $11 benefitted somebody else's or the steaming it has to dispatch. So, it's really hard to say what's going to happen to dispatch or what's going to happen to margin.
We're having 75,00 megawatts in generation have a dollar higher gas price to us overnight, this starts Monday, was actually a very helpful thing.
It's great. Thank you.
And thank you. Our next question comes from Brian Chen with Bank of America Merrill Lynch.
Hi, good morning.
Good morning, Brian.
NextEra announced that they were going to be repowering a significant portion of their wind fleet. About 3 gigawatt to 4 gigawatts of potential repowering. I was wondering could you comment if other wind owners in the industry follow suit. Can you just comment on what impact that has on power markets particularly in California and Texas and how the company's profile and outlook might be altered?
Yes sure, Brian, it's Trey. So, presumably they're repowering now because of the availability and access to the tax credits and also presumably the updated technology that increase potentially their capacity factors. We got 16+ gigs of installed wind in West Texas and about 18 gigs of transmission capacity. So, I'm not sure that there is a whole lot of realm for incremental megawatt hours or megawatts to be delivered into the broader Texas grid. I think what they're doing makes sense but I wouldn’t expect that there is. You know, they own the older the vast majority of those older wind farms and so I wouldn’t expect there is a wave of similar opportunities coming.
Can you talk about what impact that might have on market heat rates and spark spreads if at all?
Yes, sure. This is Andrew. I mean, look, you know, Texas when we think about in two parts, what the impact on kind of shoulder and off-peak prices versus what the impacts on say August scarcity. And look I think it's fair to say that there could be some impact as we continue to develop 2000 or 3000 more megs of land or increase the capacity factors on some of the older existing plant in the off-peaks and shoulders. That being said that's kind of influx or amount of distress if not a far greater amount of distress on coal and base load generation which we were debating the retirements of right now as we speak. One thing that's absolutely sure is that Texas prices when they exhibit scarcity do so under very low wind conditions which happens to occur when heat is very high in months like August. So for a month like August it's going to be very difficult for tweaking all the pre-existing wind generation or building new wind generation to add much more than 300-400 megawatts to this absolute peak of the summer. So it's more or less impact on scarcity.
Understood. That's very helpful and then just one follow-up on [indiscernible] I recognize that the plant is a very old vintage natural gas plant from the mid 1980s, but can you comment on to what extent it's operating profile is different than other Texas assets you have and also when we say that it's going to be retired how easy is it to potentially bring it out of retirement? Is it a permanent retirement or is it more of a contingent retirement? Can you just give a little color on there?
Yes, so real quickly, that plant was built in the mid 80s. It was acquired by Calpine it was not originally Calpine built plant. It is the older much older technology with the much higher heat rate. The plant is actually on a schema site so when it is retired we expect that it will be deconstructed, demolished and the land will be turned back over to schema start for use for another activities. So this plant does operate on – it's got maintenance but the contracts coming to an end and we don't think it's worth a while to spending the amount of money that's necessary to keep this plant competitive because we go forward given the current market conditions so we are doing economic rational thing but once it's gone it will be gone.
Do you have any other plants in your fleet that are of similar vintage?
We have some other plants that are similar vintage not many. Most of our fleet as you know is from last decade or is early for waiver, but we do have some others but they all are either we believe comfortably contracted or will be. So as I said in my prepared remarks we don't give any other of our assets in this kind of economic situation at all.
Yes thank you.
And thank you. Our next question comes from Praful Mehta with Citigroup.
Hi guys and sorry I am jogging the couple of call so I apologize if people already answered this question but just wanted to understand on TCEH as they exit bankruptcy it looks like they’re getting to close how do you think their exit impacts the Texas market and potential retirements?
I think you are going to have to ask them, they’ve got a management team in place up in Dallas but we are going to have another competitor, another public competitor on this space we can certainly work on, but as what their plans are when they are out there. You are going to have to ask them and we soon have a lot better access. So good luck.
Fair enough. And then, I am assuming you addressed regional heads, but do you expect any near term impacts from the regional head stay or is it just the 19-20 kind of implications on retirement or potential retirements?
Yes Praful, we did while you were on other call, we did address that and I think the quick summary is that there are some other environmental rules which are coming into place but the economic stress in the business is now and so in our view we are far from certain that has any kind of practical implications but we can spend more time with you on that after call.
And thank you. Our next question comes from [indiscernible].
Yes, I have two questions. First one is just with regards to the strategy in process that we should look for in California?
Yes, Thad Miller, you want to talk a little bit about that?
Sure. Hi Mora. Look Mora, there is no doubt that our plants are needed for reliability and integration of renewables in California for the foreseeable future and so the question is how do we get reasonably or adequately compensated as we look forward. We have spent the great deal of time and effort meeting with policymakers as well as stakeholders in that market as well as folks at the federal level. And the result of that is you have seen a number of initiatives at the PEC level and [KISO] directed at on the margins ostensibly to improve pricing. But we don't think any of these one offs are going to be the solution rather we think that it calls for a larger solution and we have taken another step recently towards that which is in the [indiscernible] case that was filed at FERC for a plant not owned by us, we filed comments pointing out what we think are some of the infirmities in the California market and asking FERC to have a technical conference on this to discuss it and notably we had some other parties reply in that proceeding, stakeholders in California supporting our request and in particular the KISO noting that they are not opposed to our request and read into that what you would like, but we read it as being supportive.
And so, we are not at this point yet asking FERC to take action. We continue a dialogue with the policymakers and the stakeholders in California to put the fixes in the market there that we think would result in adequate compensation and we see this as a process over the coming months where we will be continuing to talk to these stakeholders hopefully FERC will initiate the technical conference and will move forward from there but we think that people are now getting the message the sense of urgency that we here at Calpine have about making these changes and finally I will say that anything is on the table, I mean there is a spectrum of solutions here ranging from capacity payments to FERC tariffs to PPA and we are open to discussing and evaluating any of those with the various constituencies.
Alright. And I will add just more real quickly to remind people that while we have the guides for business which is doing well in our contracted gas plants are doing well we have 3500 megawatts of combined cycles this year turned out $20 million of cash. Now with the gas rate changes we talk about we like some upside from there in the next year or two, but nonetheless that's not a big cushion and these things are absolutely needed for liability and I think people are starting to understand that.
Okay. Second question is a little bit more tricky. You have on page 15 the kind of EBITDA consistency of the company, but if you even showed on a free cash flow consistency under many different environments going back even further since the shack and the team took over post of bankruptcy the consistency of the cash flow speaks for itself and yes people are questioning the viability of -- in call but it's hard to question the viability of relatively young gas lead in my opinion. And having said that whether your free cash flow yield is 10% or 15% or 20%, the market is not giving any credit to the asset value and the cash flow that the assets generate, so that I appreciate the leverage that the company has but at the end of the day the question that I have is, is this business something that should be in the public markets or should this be a private company overtime? I am trying to understand because it's not – yes, I love to hear the thoughts on that?
Yes. What I will say is obviously the evaluations cycle on these businesses and this free cash flow yield it does seem consistent with the fact that it's hard for us to understand how overtime we are going to have a business that yield this amount of cash, you do the math and take the many hundred and million dollars and kind of figure it out. We don't think it's sustainable certainly which is why we think the evaluation will have to checked up, it's just as far as whether or not it's better -- public or any other thing we will always do whatever the most economic thing is for our shareholders. But right now we are fully intent on running the business continuing to use the cash _ with the belief that the cash keeps coming the devaluation will fall in.
Okay. Yes, I mean again the consistency of the cash flow under any sort of environment it is what it is. So I don't know interesting that the evaluation doesn't seem to matter. I guess the third question is just any comments on the nuke plants in New York, the attempts in Ohio, it is any these policy issues which aren't necessarily kind to the merchant space?
Well, there certainly has been a lot of runs on [ACTIS] whether it was the New Jersey, Maryland, RSP from new combined cycle new build. Whether it was what Ohio has done and the other efforts you mentioned. So far and we believe in a very strong manner but FERC and the courts have been very supportive of the eastern, these few markets on clearly the rule recently about federal it's clear. It's federal not state to oversee these markets, all that has been very positive. That being said there is a clash rate right now between states and federal jurisdiction on this that will continue. I feel very comfortable that the current rules will continue to hold. We have no full protection. And PJM we have full protection in New England, New York is a slightly different situation with the one stage ISO and we also overtime will continue to work with folks to make sure that tariffs continue to protect us.
So I think while these are happening I think there is no risk to the energy markets based on renewables and there are to the capacity markets which I think the differences shown are pretty strong. So we will continue on working with them to write it all. The other thing I would notice is that what is very clear is that this is trying to keep all the assets around versus trying to get new assets in for the most part which obviously what we want assets that are economic retire that would be very helpful. It's less threatening than trying to build a bunch of new plants under some kind of out market contracts. So we feel pretty good about correct record we have had and about how things will play out. We are working pretty hard at this and expect to keep working very hard at it.
And thank you. This concludes the question-and-answer session. I will now turn the call back over to Bryan Kimzey for closing remarks.
Thank you. And thanks to everyone for participating in our call today. For those of you that joined late, an archive 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.
Thank you. Ladies and gentlemen, this concludes today's conference. We thank you for participating. And you may now disconnect.
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