TransAlta Corporation (TAC) Q2 2019 Earnings Report, Transcript and Summary

Good morning. My name is Christine, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Second Quarter 2019 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Chiara Valentini, Acting Manager, Investor Relations. You may begin your conference.

Thank you, Christine. Good morning, everyone. And welcome to TransAlta's second quarter 2019 conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Todd Stack, Chief Financial Officer; John Kousinioris, Chief Operating Officer; and Brett Gellner, Chief Development Officer. Today's call is webcast, and I invite those listening on the phone lines to view the supporting slides, which are available on our website. A replay of the call will be available later today, and a transcript will be posted on our website shortly thereafter. As usual, all information provided during this conference call is subject to the forward-looking statement qualifications set out on Slide 2, detailed in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency unless otherwise stated. The non-IFRS terminology used including gross margin, comparable EBITDA, funds from operations and free cash flow, are also reconciled in the MD&A for your reference. On today's call, Dawn and Todd will review the quarterly and year-to-date results and expectations for the remainder of the year. After these prepared remarks, we will open the call for questions. With that, let me turn the call over to Dawn.

Thanks, Chiara, and welcome everyone. Today, will be a short call to give you some color on the quarter and year-to-date and update you on the growth projects we're executing. We are preparing for our Investor Day in September where we'll discuss our strategy more specifically so we won't add much on that front today. Overall, I'm pleased with the results as a business during the quarter and our year-to-date. Our highly contracted facilities operated as expected to deliver our base cash flow. The year-to-date results in coal and hydro here in Alberta have been helped by stronger than expected pricing. The fundamental market here in Alberta is behaving competitively, which is a strong foundation for our assets here in this market. Now as I look at the first six months of the year, this is what I saw. First Canadian coal is stronger than expected due to more dispatching at the Sundance facilities in response to some stronger prices in the market and the ability of our plants to co-fire more aggressively now that the Pioneer Pipeline is operational. Prices in the first half of 2019 average $63 per megawatt hour compared to $46 per megawatt hour in the first half of 2018. This additional pricing provided for some capacity pricing for merchants Sundance and justified keeping them online. We do expect some of this to continue as we move through to the end of 2019. The stronger pricing and the ancillary services market gave us about the same amount of EBITDA from our hydro facilities as in the first half of 2018. Todd will show you that we didn't make as much on ancillary services in Q2 of 2019 as we did in the second quarter of last year. Last year, there was an exceptional demand for these services in the second quarter. However, when you assess the strength of that business in this market over the past six months under what I believe is normal and competitive pricing, the hydro portion of our business continues to perform well and as expected. Energy marketing is having a strong year primarily due to the gain they experienced in the Pacific Northwest in quarter one. Otherwise, everything is performing the way we normally expect them to perform and it's great to see what they're doing this year. Centralia has returned to normal expectation in quarter two but still lags in cash for 2019 due to the issue they experienced in quarter one. And our corporate costs were slightly higher in quarter two due to some additional expenses. We're finding ways to offset those costs and expect them to be mostly normalized by the end of 2019. Overall 2019 was expected to be below 2018 for EBITDA and cash flow as the Mississauga and Poplar Creek contracts rolled off and stepped down. We also expected to have significantly less free cash flow in the second quarter as we had planned outages in coal this year that we did not have last year. However, the first six months are showing additional strength and we are not down by as much as we expected. So this is great news. As a result, we now expect to be at the upper end of our free cash flow guidance for 2019. Now during the second quarter we announced the completion of the Pioneer Pipeline. It was completed four months ahead of schedule and has begun slowing natural gas to generating units at Sundance and Keephills. The pipeline is currently flowing about 50 MMcf/day during the startup phase. Firm throughput other approximately 130 MMcf/day of natural gas can commence in November. The completion of that pipeline is a cornerstone towards our strategy of transitioning to gas and we've achieved a major milestone in that plan. We are accelerating our conversion and repairing plans for our Sundance and Keephills to gas-fired generation in the 2020 to 2023 timeframe, as you all know. On July 4, 2019, we issued final notice to proceed on our Sundance Unit 6 and are targeting to complete the conversion of that Unit 2 gas in the second half of 2020. During the second quarter of 2019, we closed the first tranche of the strategic investment by Brookfield. The proceeds of $350 million provides TransAlta the financial flexibility to advance our coal-to-gas conversion strategy and creates a strategic partnership with one of the world’s leaders in renewable energy. We also announced last week the swap of our half of G3, for Capital Power’s half of K3. The economic change from this swap is insignificant in the short-term. However, we now have complete flexibility on how we operate the mine and transition our fleet to gas. Turning to Slide 5, we will provide a quick update on our new assets in a construction pipeline. The top two projects on this slide, Big Level and Antrim are great projects for TransAlta Renewables and both projects are currently funded directly by TransAlta Renewables. Construction is advancing and we have revised our cost estimate at TransAlta Renewables by US$10 million, primarily due to the impact of extreme weather conditions. We continue to target both wind projects to reach commercial operation later this year in 2019. Skookumchuck and Windrise are currently being funded by TransAlta, both projects are underpinned by 20-year PPAs with strong counterparties and therefore, our excellent candidates for acquisition by TransAlta Renewables both Windrise and Skookumchuck projects are progressing. Windrise will reach COD by mid-2021. Skookumchuck construction has commenced and COD has targeted by late Q4 2019 or early Q1 of next year. And we will acquire our 49% equity industry in the project at COD. Turning to Slide 6 on a consolidated basis, you can see how these growth projects will lift our future EBITDA. We expect to see benefits of Big Level and Antrim and Project Pioneer later this year. Next year, we’ll start to see the benefit from Skookumchuck and by 2022 we expect to have approximately $60 million of EBITDA added to our run rate. This year, we are investing over $400 million and growing the business through new development projects. Over the next three years, we will commission these five projects which have a total capital investment of approximately $850 million, before proceeds of project financing and tax equity. Finally, today we announced the promotion of John Kousinioris to our Chief Operating Officer. Congratulations to John, who’s here with us today, as he takes on a role that I, myself held from 2009 to the end of 2011. This change allows me to lift out of the day to day operation and to work more aggressively on our growth strategy and the execution of additional policy work to ensure that our transition to gas and renewables by 2025 is successful. There’s a lot to do to consolidate the business as it moves to a simpler operation. And John has a strong team working for him that can focus on simplifying the business. So with that, I’ll turn the call over to Todd.

Thank you, Dawn. And welcome to everyone on the call. Before I jump into the operational results, I’d like to start by reviewing the Alberta price trends on Slide 7. The Alberta market continued to demonstrate strong fundamentals in the second quarter. Prices remained relatively consistent with prior periods with an average price of $57 per megawatt hour this year compared to $56 per megawatt hour in 2018. During the period, power prices generally average between $30 and $40 on most days with prices increasing during short periods of supply demand tightness. Our merchant coal and hydro assets performed well under these market conditions. We are currently seeing the balance of Q3 at $52 per megawatt hour and Q4 is currently estimated to be $60 per megawatt hour. As we look at 2020, the forward curve increased from $50 per megawatt hour in early May to $58 per megawatt hour based on improving market fundamentals. On Slide 8, I will highlight the improving performance of our Canadian Coal segment. In Q2, EBITDA increased 40% from $47 million in 2018 to $66 million in 2019. On a per megawatt hour basis, EBITDA margins increased by $8 from $16 per megawatt hour to $24 per megawatt hour, this represents a 30% improvement to EBITDA margins driven by higher realized price and lower operating costs. Quarter-over-quarter realized revenue per megawatt hour increased by 6% or $4 per megawatt hour. And operating costs also improved by 6% or $3 per megawatt hour. The ongoing transition of our mining operations and the increase in the amount of coal-firing is resulting in lower fuel and carbon costs and lower OM&A. On a year-to-date basis, the trend is similar with EBITDA Canadian Coal increasing from $111 million in 2018 to $129 million in 2019, a 16% increase. EBITDA margins also improved from $16 per megawatt hour to $20 per megawatt hour, a 27% improvement in margins. As Dawn noted at the beginning of our discussion, our results in the second quarter and year-to-date were down relative to last year, driven by a number of factors including the contract expired at Mississauga and stepped down in contract payments at Poplar Creek. On Slide 9, we’ve bridged our year-to-date EBITDA and segment cash flows for 2019 versus 2018, and we’ve shown the impact of the Mississauga and Poplar Creek contract changes to these results. Excluding the impact of these known contract changes, we delivered EBITDA and segment cash flows in line with last year and in line with our expectations for the three and six months ended June, June 30. Our Energy Marketing team had another solid quarter, generating $20 million of cash flow compared to $9 million in Q2 of 2018. As shown in the bridge, on a year-to-date basis, cash flow from Energy Marketing is delivering $53 million better than in 2018. Over the last six months, the team has been able to take advantage of market opportunities primarily in the U.S. Western markets. The Canadian Gas segment, excluding the impact of contract changes, EBITDA improved by $2 million in the quarter and $8 million year-to-date when compared to 2018. The improvement was primarily due to favorable market conditions at the Sarnia facility. Our hydro business delivered good results, generating EBITDA of $37 million in the quarter and $64 million year-to-date. In Q2 2018, ancillary service revenues were very strong to the high demand driven by high imports since the province. And as a result, Q2 2019 EBITDA was comparatively lower by $12 million. On a year-to-date basis, EBITDA results for 2019 were in line with 2018. As described in the last slide, Canadian Coal delivered significantly higher EBITDA in the second quarter and year-to-date versus 2018. However, this improvement was offset by lower results at U.S. Coal due to the unplanned outage in Q1. Coal segment cash flows were also negatively impacted by the additional plan maintenance at Sundance Unit 4 and on Keephills Unit 1. There were no planned outages in 2018 in our Canadian Coal business. On Slide 10, we’re showing the buildup of our hydro PPA EBITDA to help illustrate the upside of the hydro assets once the PPA expires at the end of 2020. For the six months ended June 30, 2019, our hydro assets generated $64 million in EBITDA. However, they would’ve generated $142 million if the current PPA obligation payments did not exist. Just to wrap up on the quarter, our overall performance was in line with expectation and we continue to attract towards the upper end of our free cash flow guidance of $330 million. Liquidity was very strong at Q2 with $1.3 billion available on credit facilities and we also had $200 million of cash on hand. During the quarter, we returned $21 million of capital to shareholders through our share buyback program and we expect to purchase up to $250 million over the next three years. At our Investor Day in September, I will provide more detail on capital allocation. With that, I will now pass the call back to Chiara, who will open up the call for questions on the quarter and first half of the year.

Thank you, Todd. Christine, would you please open the call for questions from analysts and media?

Thank you. [Operator Instructions] Your first question comes from the line of Mark Jarvi from CIBC Capital Markets. Your line is open.

Hi. Good morning, everyone.

Hi, Mark.

Yes. First question was just maybe on the decision for notice to proceed on Sundance Unit 6. Obviously, we’ve all seen the decision around the capacity market. Just wondering what gave you guys the confidence to go ahead with that versus some of the other hybrids and other conversion options you guys have been thinking about?

Yes, let me start, and then Brett, who’s been doing all the analysis, can chip in on. I think kind of overall, if you look at just the carbon pricing in the market, Mark, it funds the conversion, a simple conversion and you can get a simple conversion done quickly, it takes – it will take us until – when we’re looking at our hybrid options, hybrids can’t actually be put into the market until 2023-2024 timeframe because of the regulatory work you got to do to get the permits. And so effectively the shareholders will be better off the quicker we get off coal and it’s effectively get funded by carbon tax reduction. And then that allows us the flexibility of deciding just how much – how many hybrids and we’ve got to manage it within a really good balance sheet as well. So that’s kind of the math that we’re doing as we get ready for Investor Day. I don’t know, Brett, do you want to add anything to that?

No, no, I think, that’s exactly – in September.

Yes. Okay, we’re looking forward to September. And then maybe any update in view from the transition from CCR to the tier in terms of how the facilities that opted in hydro and becomes to the wind that are getting carbon credits? How do you think those would be treated in any additional clarity on that yet?

Yes, there is no additional clarity on that. Of course we’re continuing to advocate for the rollover to be simple and as per the CCR. But until they make a decision, we won’t know.

Okay. And then…

Just a particular insight on that.

Okay. And then when you think about being able to hit the upper end of range for free cash flow for the year, just – what do you guys assuming that on power prices? Is it largely in line with where the forward curve is? Are taking in the conservatism or just roughly where do you see power price need to be free to hit that upward into the range?

No, I think it’s based on where we see the forward curve today and we don’t think that the market – we think the market will fundamentally trade around there. So all of our analysis shows that if you look at supply and demand and how the market’s reacting, but those are pretty reasonable prices in the current environment with current carbon price.

Okay, great. Thanks. I’ll jump back in the queue.

Thanks Mark.

Your next question comes from the line of Andrew Christie from Credit Suisse. Your line is open.

Thank you. Good morning. Maybe if we just get in a little bit of the mechanics on the cash flow in the hydro JV with Brookfield. Are you intending to sweep all the cash out to the partners and then you’d redeploy elsewhere?

Yes, it’s Todd here. I think that’s largely correct, but we’re still many years away from Brookfield’s conversion rates executing. So those details really haven’t been ironed out at this point. But I think largely that’s a good assumption to go with.

Remember, they can’t actually execute on the hydro until 2025. So for now, we just pay the interest on the money that they’ve been invested into the business.

And then just maybe a similar question, how do you think about the cash flow you received from RNW at this stage? Obviously you were active in buying back stock in the quarter. How do you think about the dividends you receive to effectively accrete TransAlta shareholders by buying back more of your own stock at the current value?

Well, I think that’s a good point. I think the way we think about it is a little bit different. So, we have sort of the money offensively set aside out for the share buyback, $250 million that we can buyback over three years here. And at the same time, when we look at the cash flow from the dividend for TransAlta, we pay a dividend – so we get about $150 million from RNW, we pay a dividend of about $40 million. So you can basically say, okay, the TransAlta shareholder gets $40 million of that $150 million. And so then the remaining $110 million is some the cash that we’re using along with other free cash flow that we’re generating under the Alberta business to reinvest in the Alberta business and keep our balance sheet strong.

Okay. Thank you. And then maybe just why you’ve mentioned the reinvestment in the Alberta business, there’s a comment in the MD&A on the repowering of the coal units, and it’s 40% less cost than a new combined cycle with a similar heat rate. Could you maybe provide a bit of color on just other performance attributes like the ability to ramp and cycle around those units in the future versus a combined cycle?

Yes, it’s Brett, Andrew. We don’t see much different, we went and saw a site that’s been running for 10 years and has been running very successfully and has very good ramping capabilities. So again, given the lower heat rate, we’d also expect them to run more frequently is base load. So the actual ramping will be kind of around the margin versus traditional peaker type unit as you would expect. We don’t see any significant performance differences and clearly, we’re utilizing existing capital that’s already in the ground, which enhances the economics quite significantly.

Okay. That’s great. Thank you.

[Operator Instructions] Your next question comes from the line of John Mould from TD Securities. Your line is open.

Good morning, everybody. Maybe just starting with the hybrid and I recognize, you don’t want to steal your Investor Day thunder, but there’s a comment in the MD&A that you expect to make the decision around those investments in 2020. And I think that was previously late 2019 in the Q1 MD&A. So I’m just wondering what’s changed since May, that’s informed that update.

Yes, nothing – when we’re proceeding with evaluating those as we’ve discussed in the past, and again, we’ll update you to more here in September on our plans. But we’re advancing a lot of the studies, the analysis and it just based on that our final investment decision would be later in the 2020 period, so just the amount of work we have to do there. But no real change on timing of when we would think about those being built if we proceed with them. And like I said, we’ll be able to provide you with more information in September once we get there.

Yes. So let me try to give you just a sense of the decision making, which is quite different if you’re looking at just a simple conversion versus a hybrid. So as you know, a simple conversion is kind of an extra $30 million to $50 million inside an outage that instead of being four weeks becomes eight weeks. And fundamentally the cash is being – it’s a productivity investment because the cash is being funded by reduced carbon taxes that immediately occur when you run the units after the fact, right? You go from pain while like at $20 – you go from pain about $12 to $1 in carbon tax. So it doesn’t take very long for that investment to pay off. So those are relatively simple inductance and we’ve already got everything lined up for that. We’ve got all the regulatory decisions are made both federally and provincially for that and we’ve got all the permits, so everything fits. It’s just now lining up the equipment and lining up the outages. And on Investor Day we’re going to – we’ll reveal which plants are going to get sort of there the simple conversion. When it comes to the hybrid, that’s really the similar development path as we undertook when we were thinking about Sun 7, first of all, they’re more capital, significantly more capital. They’re much less than a combined cycle plant. But they’re more capital. There’s more permitting considerations. There’s more stakeholder work that has to be done in the region around things like noise and all the regular stuff that you do. And then there’s still some regulations that we need to make sure are the way we want them relative to the greenhouse gas, future greenhouse gases and all that sort of stuff. So effectively, they’re on the same kind of development path as you would expect that size of investment to be. And they take 2.5 years to build. So you’ve got to line up your EPC contractors and make sure you got your construction all ready to go. So it’s just a longer decision timeframe. So I think they make a ton of sense in the Alberta market as it is today, especially Sun 7 is the only market. It makes a ton of sense for the trends out of that portfolio to have some mix of both. But net-net, the decision making will be akin to what you saw on Sun 7 and we’ll walk you through on Investor Day, sort of what those key milestones are. But really it’s a lot about just making sure we’ve got all the development done correctly. So does that help, John?

Yes, that’s I really appreciate that detail. And then maybe just moving to the Ontario market, it would be curious to your thoughts on the market changes happening in Ontario right now and how this is informing your recontracting that will look for your existing thermal assets in the province.

Yes. I mean I think the Ontario market is a very – it’s a very complicated market structure. And personally, I was surprised that they would be able to actually get to a capacity market that worked because they – I mean, they still have a great big government own generator in that market. And there’s a lot of aspects of that market that doesn’t make it a market. So I think that market structure is much more served by the way that they do the contracting. So I think net-net, it’s really positive for us, because we know Sarnia can run till 2040. Sarnia has got three customers that rely on it for steam and rely on it for competitiveness and all the rest of it. So I think if actually net-net positive for us.

Okay, great. And then maybe just one last housekeeping question quickly regarding the FMG disputes, can you maybe just remind us where those are at this point?

Yes, I mean, currently like all legal disputes. We’re in the middle of what it looks like in Australia. So in Australia, there’s a requirement to do mediation before you actually can get into the courts. If all goes well, that mediation takes place towards the end of this year. Usually, these things, I never relied too much on the timing because there’s always a lot of back and forth and dates move. So I’m hoping we get the mediation stage of this done through the end of this year, but I’m certainly not going to guarantee it to you. So wait and see. We’ll have an update on that for you probably in our October call. In November, when we do our – I think our call is in October, so it when we’re finished our third quarter, we’ll know if that mediation is underway.

Okay, great. Those are my questions. Thank you very much.

Yes. John, the other thing I would say is the trial list is currently scheduled for the second kind of the – the back half of the second quarter of 2020.

Yes. Okay. So there’s a trial date in August 2020.

Okay, great. Thanks.

Your next question comes from the line of Maurice Choy from RBC. Your line is open.

Thank you and good morning. My first question is on, I guess, conversions and the potential hybrids, how does it governments reviews of a price cap and floor or even the power mitigation matters effect your decision on technology or in timing?

So I think what we’ll – I mean, what we’ll try to do is, we’ll have a sense and we do actually have a sense because we know enough about energy markets generally to know kind of how that will impact the way that units of discussion to the market and how it impacts the kind of pricing overall. So we don’t actually – at this point, we don’t see that review having a big impact on price other than it has to effectively create some sort of capacity price in the energy market for new generation to be brought into the marketplace. Because our hybrid, they’re actually replacement of existing capacity. It’s not that bigger deal for us. But we’ll give you some color on that as we’re bringing forward our investment decisions. Currently, I can say pretty clearly though I doesn’t have a huge impact on how we make our decisions for making those investments because there’s so economics.

I guess even on timing that also doesn’t have…

Yes. Because remember they need to have all this in place. PPAs roll off at the end of 2020. By January 1 2021 everybody’s got to know the market rules because the PPAs are gone. And right now the PPAs are where the reliability and capacity guarantees are in the marketplace. So you’ve got to replace that by having the energy only market signals give you a lot of confidence about reliability. We don’t intend to issue a final notice to proceed on those plants until somewhere in 2020 anyway, by that time we’ll know what those rules are. I suspect it won’t change our timing at all, but, you never know. But my view is it doesn’t have a big impact on our timing because our timing is to have those units come online in early 2024.

Right. And then my second question, I guess is on hedging. I guess something similar to the first question, does the government’s review or even the conversions that you’re planning to do right now. Would you wait for Sundance, six conversions to finish run smoothly before you get more confidence on other conversions, others that entire process affect your hedging strategy moving forward.

Yes. I would say it doesn’t affect our hedging strategy at all. We have a pretty significant portfolio where we’re always looking to place hedges in the market to get rid of that price uncertainty.

Yes. This conversion is not risky, and we’re not looking at it is, okay. We’ve now got a unit that’s going to take some time to ramp up and run smoothly. I mean, this unit will run way more smoothly on gas. So that doesn’t impact our hedging at all. I think – as we think about hedging, we’ve always thought about hedging relative to – the decision on how hedging it’s as relative to stability of cash flow. And so we’ve really got to turn, our mind to that as we enter into a more of a merchant market with less PPAs. And there are some other market fundamentals that have to occur in the Alberta market. Like, to the extent that the RRO disappears, to the extent that there’s more customers looking for more hedges as they don’t have that option. I think there’s a number of changes that will come to make the market even more competitive. And then that is the kind of information that feeds how we think about hedging.

And I suppose, since you do not believe that the reviews would have much impact on price, governments review also shouldn’t alter your hedging strategy.

No. What alters your hedging strategy is your view of the fundamentals. And that’s the basic – that is the basic work that you’ve got to do is you got to think about where the market fundamentals are and that tells you how much you hedge and how much you leave open.

Great. Thank you very much.

Thanks. Maurice.

[Operator Instructions] Your next question comes from the line of Chris Varcoe from Calgary Herald. Your line is open.

Hi, Dawn. I just wanted to go back to the Alberta government’s decision. Do you stick with the energy-only-market, I guess I’m wondering what impact will it have upon the company and more specifically on your thoughts on investing in future generation in the province?

Yes. So Chris, really the difference between a capacity market and an energy-only-market, as you either invest in assets that provide capacity, so that the reliability comes because you’ve got machines waiting to run in case they’re needed. Or are you on an energy-only-market, you tend to favor investments in machines that run at really high capacity factors and create energy with what are called low heat rate. And so in our strategy, our simple conversions are capacity products and our hybrids, our energy products. So really what it’s done is it has that reevaluating just our mix. We still think that – for our company, a competitive portfolio, which has hydro wind and some of these capacity conversions. And then some hybrids, is the right mix for our company, a competitive portfolio, which has hydro wind and some of these capacity conversions. And then some hybrids is the right mix for our company and it allows us to ensure that we can provide low prices for customers, because fundamentally, that’s what we’re here to do. We’re here to make electricity boring, simple and cheap for everybody. So, net-net, what it’s doing is it’s causing us to think about – what our investment strategy looks like for hybrids. And that’s what when we have our Investor Day on September 16 in Toronto, that’s what we’ll be announcing.

Okay. Does that make you any more likely or less likely to make future investments in generation in the province?

No. It’s about the same. I mean, I think we’re a big player here in Alberta. We pride ourselves in providing low-cost electricity to the marketplace here. It’s just really more how we think about the mix for the Alberta market.

And I just wanted to ask you what impact, if any at all, will it have upon the transitioning the guests? You alluded to it gets a little bit there, but I’m just wondering, you might be able to provide a little more color on what impact that might have on the timing or anything else that you do as you transition the core fleet to get.

Yes. So, just simply currently, there’s a carbon tax of $20 in the market. We expect that to rise as you have to be in compliance sort of with all the carbon legislation that’s in the country. Our view is fundamentally that carbon will be priced over the next 20 years no matter what. No matter what that political framework is? So we cannot – we cannot get our coal fast enough in this company. It’s – and gas right now in Alberta is extremely inexpensive. There’s lots of it. It’s cheaper than anybody ever imagined it would be. So it’s – and it’s half – it doesn’t command a very high carbon price. So, our coal-to-gas strategy is completely predicated on our belief that it’s not smart to be in carbon intensive fuels for the future for our shareholders.

Just lastly, obviously, we’re sticking with the energy-only market, but there’s, as you pointed out, there’s going to be review here. Are there changes that you think fundamentally have to happen to the energy-only market to make it more attractive to invest? And I guess specifically what changes would you be asking the governmental accounts?

Yes. I mean for sure the number one change has the government has to have to think about is, is in pricing. Because if you don’t have enough of a price signal in an energy-only market to attract new capital, you won’t get into capital and you’ll run up against the law like you’ll just – you’ll have the investments from the incumbents like ourselves, but you won’t get new entry into the marketplace. And so think about it this way, Chris, it costs you over $1 billion to build a brand-new gas plant, let’s say. And you got to say to yourself, I’m going to get paid over, let’s say 20 years. I got to get paid back that capital and a return on that capital. And I have to rely on a spot market to get me that return. So, I better have a lot of confidence that, that market functions well. It functions like a market and I can see that pricing in the marketplace. So, they’ve got to turn their attention to that. I’d say first and foremost. Secondarily, the work that I’m doing on the policy side is, I think Alberta has to get behind some sort of a proactive legislation, about the use of gas for making electricity for 20 years to 25 years, because I don’t think people can invest in gas generators with the notion that in the future, some other – somebody might come along and say, well, we don’t like gas anymore. So, we’re going to shut your gas plants down. So, we have to have our ability to make those investments over a long period of time protected. And I think that’s a piece of work that I’d like to see happen here in Alberta and I’ll be advocating for.

Thank you.

Your next question comes from line of Mitchell Moss from Lord Abbett. Your line is open.

Hi. Thanks for having the call and all the questions. I’m just wondering on the Pioneer Pipeline EBITDA that you guys show on where you discuss there’s some variability based on volume. I guess first is that 2021, 2022 level based on just the – I guess steam turbine boiler conversion, and not the combined cycle conversion or is there also potential of combined site – like extra throughput because of increased gas?

Yes. So it’s Brett here. Yes. So, the picture you saw there, as Dawn mentioned, the hybrid or combined cycle would – it takes longer to permit. So, this does not pick up that. But remember as Dawn also mentioned, we’re really converting units in exchange for other units that are running. So, they’re very efficient units and so that picture probably doesn’t change dramatically once we go to the hybrids and it’s driven by throughput. So, the way pipelines work, not just pioneer, but generally, here in Alberta is tools are paid to get on the pipe and tools are paid to get off the pipe. And so the more volume you move through that pipe, clearly, the more revenue and EBITDA it generates. Because the capital doesn’t change, now that you got the pipe, you might have to put some compression in, a modest compression in to get it above a certain volume over time, but that’s relatively modest. So, any increase in throughput really goes directly to the bottom line, because the operating costs and the capital are kind of fixed already.

Okay. But this is essentially just showing the basic conversion, not the combined cycle.

Okay. And included in coal-firing, so as Dawn mentioned, we – in coal-fire, currently without converting up to 30% that you took those units today and we’ve been maximizing that. And so this is a mix of conversion on and – coal-firing and conversions as we convert some of the units overtime.

Yes. just think about it this way. First of all, the current Pioneer Pipeline when it gets to its 130 in November, can be used right away to – we can use that right away to coal-fire and we can maximize the use of the pipeline for that. Then in 2020, when Sun 6 is converted, we’ll use – we’ll need to use the gas for Sun 6 Plattco firing as we get all the way through our strategy and we get to our hybrids, whatever our decision is on how many of those we do, we actually have to add some more pipeline capacity. And Brad and his team are working on that. So, we’ll show you how that works in terms of our gas supply and demand and our pipeline as we – at our Investor Day, which we know everybody’s going to come to now, because we’ve advertised, somebody thinks that we’re going to do there that everybody I’ll have to show up.

And could you – outside of a capacity auction, which seems to be off the table for now, what are some other market characteristics that would – you would need to decide to go ahead with a full combined cycle conversion?

Well, the number one market characteristic is exactly what I just talked about. You have to know that the market is very competitive and that it’s not – there’s not interventions that can happen in the market. So, Alberta has had a pretty solid energy-only market over the last 20 years. So, you’ve got to sort of say to yourself as we go forward, the rules that are put in place are put in place, they’re protected. They can’t be intervened in and I can reliably use the fundamentals of supply and demand, predict what prices will be. So, I can determine whether or not my investment will be recovered. And so it’s just whether or not that market is set up as a competitive market, which we have every reason to believe, it will be, because it has been in the past. But it’s really transitioned – as the PPA is transition out, new rules have to transition and to make sure that the pricing very robust and if that pricing is robust, that’s what protects your investment.

Thank you very much.

Thank you. Thanks, Mitchell.

There are no further questions at this time. Ms. Chiara Valentini, I’d turn the call back over to you.

Thank you everyone. That concludes our call for today. If you have any further questions, please don’t hesitate to reach out to the Investor Relations team. Thank you.

This concludes today’s conference call. You may now disconnect.