Good morning. My name is Mike, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Fourth Quarter and Full Year 2018 Results Conference Call. [Operator Instructions]. I will now turn the call over to Sally Taylor, Manager, Investor Relations. You may begin your conference.

Thank you, Mike. Good morning, everyone, and welcome to TransAlta's Fourth Quarter 2018 conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Brett Gellner, Chief Strategy and Investment Officer; Christophe Dehout, Chief Financial Officer; and John Kousinioris, Chief Growth 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 the 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, which is 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 reconciled in the MD&A for your reference. On today's call, Dawn, Brett and Christophe will provide an overview of the past year and update on our coal-to-gas conversion and hydro assets, followed by the financial results. After these prepared remarks, we will open the call to questions. With that, let me turn the call over to Dawn.

Thanks, Sally, and thanks, everyone, for joining us on the call today. In just 22 months, the remaining legislated PPAs that were set up here in 2000 to bridge to the full deregulation of the electricity markets will expire. And really, that's not that far away. By the end of 2020, Alberta's transition to a fully competitive market for power generation will be in place. This event creates significant opportunity for investors and companies that hold low-cost and competitive assets here in the province. Only producers with strong portfolios of competitive assets can be profitable and TransAlta has that portfolio. Today, we intend to assure you that our plan to position for the new capacity market in Alberta is not only well underway, but it's tracking. You will also get the information you need to see that moving to a clean power company is profitable, it's right for the environment, and most importantly, it keeps prices affordable for consumers. Our presentation has been extended so that we have time to outline the significant progress we've made on our strategy, and of course, we want to take the time to share the highlights of our 2018 performance. On performance, you'll hear that 2018 was one of our best years in terms of safety, operational, and financial performance. Lots to be proud of. On safety, total injuries declined 44% relative to 2017, a great accomplishment for all our teams out in the field. On operations, we had the best availability at Sundance and Keephills since 1990 and 2011, respectively, again, a greater confirmation -- a great accomplishment from the teams at Wabamun. On financial performance, the cash we collected in 2018 from our operations, along with the onetime payment for the expiry of the Sundance PPAs, has made a real dent in…

Okay. Good morning, everyone, and thanks, Dawn. So as Dawn indicated, I'm going to review our coal-to-gas strategy and the future upside in EBITDA from both our converted coal units and hydro assets. In terms of our coal-to-gas strategy, the first key message I want you to take away is that the economics and benefits of converting to gas is driven by a number of factors, not just carbon policy. Secondly, our strategy to convert is on track, and we're targeting the first conversion for the second half of 2020. Finally, we're also evaluating a repowering option for some of the units, which has the potential to deliver significant long-term value. In terms of our hydro assets, I'll walk you through the significant upside in EBITDA once we're off the PPA. Our hydro business delivered $109 million of EBITDA in 2018, but I'll show you it would have delivered $244 million without the PPA. Finally, I'll show you that there's significant potential upside in the combined converted coal fleet and hydro business in the future. So now just turning to the slide. As we've discussed in the past, there are significant benefits to converting the coal fleet to gas. First, if the units are not converted, they have to shut down under provincial and federal government regulations between the end of 2026 and the end of 2029. This impacts all coal units in the province, not just TransAlta's. The outside data, which all coal units in the province have shut down at the end of 2029. However, if converted to gas through a boiler conversion, the units can run significantly longer under the federal regulation that was put in place last year. How long a unit can run depends on its carbon emission intensity. For TransAlta units, we expect that…

Thank you, Brett, and good morning, everyone. I am pleased to be speaking in my first TransAlta conference call and look forward to many more with you in the future. I will start with a quick overview of our performance for the fourth quarter of 2018 and our financial results for the full year. Following that, I will take you through the evolution of our debt and capital allocation for both TransAlta and TransAlta Renewables, and the impact of our last renewable projects on our future results. First, looking at the quarter. Power prices in Alberta were strong, averaging $55 by megawatt hour compared to $22 for the same period in 2017. This increase is primarily due to higher carbon compliance costs and improved market fundamentals. As Dawn mentioned, our fleet availability was stronger during this quarter than it was in 2017 due to lower outages and derates in Canadian coal. This was partially offset by higher outages at our coal unit Centralia in the U.S. These factors supported financial results equivalent to the fourth quarter of last year, during which, we still benefited from the Sundance PPA. Our fourth quarter EBITDA of $233 million was $42 million lower than in 2017, partially due to outages and a negative change of $28 million in the mark-to-market of our committed hedges for U.S. coal operations. This mark-to-market movement does not impact our funds from operation or free cash flow, and we expect it to reverse in 2019. We also saw a reduction of $10 million in our Canadian Coal EBITDA due to higher carbon compliance and coal costs, as well as lower fixed revenue due to the terminated PPA at Sundance. Hydro, Australian and Canadian Gas operations had stronger quarter results and outperformed the fourth quarter of 2017. As you can…

Thanks, Christophe, and welcome to Canada. And thanks, Brett, for all of that great information. So just a couple of closing comments, because I'm hoping you're all anxious to get to the Q&A period because I think we've provided you with a lot of information today that you haven't heard before. And as you can see, we've really advanced. So you've heard today that in 2018, we delivered what we set out to do. You've heard that we've advanced our strategy and our execution plan significantly on our coal-to-gas and are really positioning to advance those conversions into the 2020 to 2023 time frame. You've heard that we have strengthened our balance sheet and are really set up to go into what will be a competitive market. As you all know, in a competitive market, it's only about cost, cost, cost so that you can deliver value to customers because that's what they expect. We've shown you today that going green is profitable and that it benefits consumers, and that's a significant change in my 33 years in the industry. I think this is really the first time that I can say that, clearly, consumers can get what they want, which is green and low cost power. We've shown you that TransAlta Renewables can fund the long-term contracted projects, and we've got John Kousinioris here ready to answer questions on that front, and we've been able to find excellent projects. We've shown you we can take some of the returns of that into TransAlta, as we do all the development, the prospecting, and really, the setting up for those projects. I guess the other thing we've shown you is that our strategic plan is extremely simple and it's measurable, and you can measure our performance in it. It focuses on converting those plants to gas and creating sustainable cash flows for the next 15 years. Brett's shown you that there's even better opportunities now that we've looked very deeply at the idea of potentially using one or two of the locations for hybrids, which are significantly more cost-effective than anything anybody can put in the ground here in Alberta. We've shown you that the hydro PPA expires, just like all the rest of them. And I think our disclosures are excellent now. You can see in our MD&A, in black and white, exactly how that works, and Brett's done a great job of showing that to you. So with that, I think you know what our investment thesis is. I think it's changed significantly over the past year, and I really look forward to your questions as we go forward because I think we've given you a lot to chew on here today. So with that, I'll turn it back over to Sally.

Thank you, Dawn. Mike, if you could please open up the call for questions.

[Operator Instructions]. Your first question comes from Rob Hope from Scotiabank.

Appreciate the new hydro disclosure. Not surprisingly, the first question is on the hydro upside. So if we look at Slide 18 and the $244 million of EBITDA that you outlined, that assumes some sort of capacity market. If we rewind this back to 2018, where there's no capacity market, would it be fair to assume that then kind of the EBITDA you would have generated in 2018 would have been $244 million less than $56 million, so closer to $190 million?

Yes, I think I'm going to start with that, and then John and Brett can come in. Because I think one of the things you got to look at, and you can see it further on EDC slides, remember, in an energy-only market, the capacity price is in the energy price. So I think in a -- people in a fully functioning -- remember, the market today in Alberta is an energy-only market with PPAs. So in a fully functioning energy-only market, if you went back to that, you have to put in place some safeguards and some guardrails to ensure you've got enough capacity, which means that you really have to have capacity prices show up in the energy-only price in order to market to create enough capacity for reliability. So given that the hydro dispatches at prices -- can dispatch by hour into the highest-priced hours, you'd have to expect that under a true energy-only market with the right rules in it and with the right capacity response in the energy-only price, that I don't think it would be that much different. But I'll let Brett and John comment on that.

Yes. The only -- so to that point, think about those average prices that I walk you through historically. So if you say $60, remember 2018 averaged $50 on a flat energy. So as I mentioned, ancillary gets about half that. We get a bit higher because we sell more in the peak hours on the energy. But even just taking that extra $10, and applying it to the energy and ancillary services that we sell, if you assume $60, you would recover maybe not all that capacity price, but some of it. So it really depends on -- there are some years where prices have been quite a bit higher than $60. So to Dawn's point, 2 different markets, but I mean, technically, you are correct, it comes out. But our view is prices could be higher to overcome some of that.

And Brett, you articulated it well. I think that's exactly what would probably happen. And the other thing is unlike other jurisdictions, we are capped from a pricing perspective, when you have those high-priced hours at $999, and [indiscernible] since you'd get more, and that kind of goes to Dawn's point of...

Yes, if you look at true energy-only markets where they don't have PPAs and they don't have capacity calls, you cannot run the Alberta market with $1,000 a megawatt hour cap, or you'll run out of capacity. You have to be willing to take that cap up to 10,000, 14,000, 15,000, 20,000. It has to cap theoretically in order to achieve the capacity that you need in the market, is the opportunity cost of the last -- of the first unit that you take off the system. So there's lots of theory that goes behind that. So I think if you want to be conservative, you could do that, Rob, but I think you have to really consider what our capacity -- what an energy market would have to look like if it's going to achieve the capacity you need for reliability.

All right. Appreciate that. And then as a follow-up, just looking at 2019 year-to-date, you're Sundance units have been running ahead of your guidance level. February pricing was $100 a megawatt hour roughly. Just want to get a sense of how you think you're performing relative to your 2019 guidance.

Well, we'd love to tell you that we're going to hit it out of the park. But we also live in Alberta, and of course, January was a really low-priced month. And so when we kind of look at January and February together, we're pleased and -- but it's early in the year, Rob, and certainly, as we go through the year, we'll be sure to update you if we see that it's running more positive than we thought.

Your next question comes from Ben Pham from BMO.

I wanted to follow-up on some of Rob's questions on the hydro bridge. And no doubt, I mean, there's certainly some EBITDA upside that's heading hidden in terms of the future expectations. I just want to get to some of the assumptions underpinning this, because it seems like this disclosure is not too different than 2017 Investor Day. But just doing some quick math, if you take energy plus capacity, doesn't that assume about a $19 all in power price? Or am I tackling that wrong?

Yes, I think so remember -- you've got to remember, the hydro sells the roughly 1,500 gigawatt hours and 3,000 gigawatt hours of ancillary, so two products plus capacity. So when you take the revenue, I don't know, which revenues you captured there, Ben, but you need to look at it from that perspective. And I would say, from a disclosure, I think it is more fulsome. We have broken out more on the buckets on the revenue between ancillary and energy and capacity, which we think is helpful because you can take those revenues divided by your volumes and look at how they compare to flat energy prices. And so hopefully that gives you more information for you to use in your modeling efforts. But no, it wouldn't be generating, without seeing your math, those kind of dollars per megawatt hour.

I think the numbers actually, Ben, are closer to $60 when you actually do the math. I think as Brett said, there was about 1,500 gigawatts of energy and a bit over 3,000 gigawatts of ancillary services, which we sold, which are roughly at 50% of what we kind of realized energy price would have been over the period. I think the average -- the flat price for the year would have been around $50.

Okay. So I just want to quickly clarify that. So on the revenue side we could just take what you've provided here, but the denominator, I shouldn't be looking at 1,600, I should be adding another 3,000.

That's right.

Yes, that's right. Think of it like -- remember, ancillary services, you can't sell energy unless you're called to sell that energy, so think of it as you're really offering two products in the market on an hourly daily basis, one of which flows through the turbines, one is kind of kept on reserve and only used when called upon. And then, it gets -- it captures energy prices at that time as well, but it's really for the system operator to manage this system for unplanned events, but also voltage support and regulation and that has been going on since deregulation.

And it's -- and they're really necessary products here in Alberta. I think the other thing that we've done, Ben, to help people see what this is, is you're getting a disclosure of the volumes of the ancillary services and where you can go find them, so you can verify them independently.

Okay, that makes a lot of sense. Looks like it's more mid-60s, which seems reasonable versus, I think, it was kind of 180 or so, which seem really high. Okay. And there is some disclosure around some mothballing changes and maybe I might have messed up some previous disclosures, but maybe just some thoughts on Sun 4, Sun 5, just some changes in the mothball timing.

I don't think -- so Sun 3 and 5 are mothballed currently, and they currently go out to the end of March of 2020, so I think we made that change a bit -- a few -- several months ago, so no, no major change there.

Your next question comes from Patrick Kenny from National Bank Financial.

Dawn, just on Windrise, you made it clear on the last conference call that in your view, the returns from these projects were less than stellar. Just wondering what other attributes are there economically or strategically helped convince you to allocate the CAD 270 million towards the project.

Well, be clear, Patrick, on -- in all of our bids, we don't bid to the returns of the market, so we just put in our price, we put in the returns that we require for the risk and return of that project, so we evaluate -- we have the site, we evaluate the cost that we can get turbines out. We evaluate our competitiveness on construction. We evaluate sort of the risk of the counterparty, which, in this case, was a strong counterparty and then we put in the actual return that we need to make the project go, and we bid that price. And if we get the project, then it meets our return threshold. And if we don't, then we let her go. And so when we bid projects like this into the first call, we didn't make the cut, but we did make it in the second call, so we were actually surprised by that because we had to ensure that we got the returns that we needed to achieve our target returns for now, we're achieving target returns for long-term contracted assets with strong counterparties with low construction risk. Remember, all of our guys that work in Southern Alberta built our wind farms. And they can build this one, they're aesthetic. John is their new buddy. So we did have advantages there that we've had some for a long time, but we were never able to get our projects through the process because the returns -- people were willing -- they either had lower return threshold or they had better competitive advantage than us. So net-net, that Windrise meets the criteria for sure of our target returns for TransAlta Renewables. And as I've said it, it's sitting right now in TransAlta, but it's a candidate for TransAlta Renewables.

And the only other add was we did develop a site that we didn't have ready for that first round, which is a better site and that's the one on one and it had better attributes to it, so the economics were also part of that. So things had changed between the initial rounds and the second round even...

Well, and also we need to get just better turbine prices, right?

Correct.

Yes, all of us [indiscernible]

Yes, did that help, Patrick?

That does. And I might have missed it in the release, but maybe you can just confirm if you intend to extend the NCIB beyond March 13? Maybe just a comment.

Oh yes, yes -- you might have missed it. Did we put it in the release?

I put it.

Okay. It's in. Yes.

And maybe just a comment on how the NCIB competes for dollars relative to some of these contracted renewable projects out there.

Well, let me just -- I really, really want to land this point. So the NCIB is a TransAlta Corporation NCIB. The -- any sort of contracted assets, they're headed for TransAlta Renewables, so then you have to say, okay, how does TransAlta Renewables think about if it had its own NCIB and, of course, it doesn't. But how would it compare its capital allocation at TransAlta Renewables? And what I see over there, Patrick, is renewables is a big dividend company, so it gives its capital back to dividends, which we want at TransAlta. We're making sure that we finance everything that we're doing on those long-term contracted assets over there. So now when you think about capital allocation at TransAlta, you need to think about, we've got our cash coming from renewables and it's fully financed when it comes over. So it's -- debt has already been paid by the project debt over in renewables. And then we have our cash from our -- rest of our business. And so then the question around capital allocation is when we think about that NCIB, is it a better use of capital than doing the coal-to-gas conversions? Right now, I can tell you the coal-to-gas conversions are a much better return, and you want us to do those and what Brett's presentation showed you today is that even if we can accelerate those sooner, they even give us better returns. But once they're done, the NCIB is really important because then there is quite a significant amount of capital available for return to shareholders through the NCIB or through dividend uplift. Does that make sense?

It does, yes, I appreciate those comments, Dawn. And then, maybe, just for Christophe, and yes, welcome to these lovely winters here in Calgary.

Thank you.

As you look to position the balance sheet for the post PPA era in a couple of years, just wanted to get your thoughts on the importance of maintaining an investment-grade credit rating. What you feel are the most important credit metrics to focus on? And then also maybe you can comment on Slide 25. You're now showing dividend increases as potentially part of your long-term capital allocation strategy, so maybe just a sense as to what your longer-term optimal payout ratio target might be as a percentage of FFO earnings.

Well, the importance of being in investment grade, I mean, has been shown, I mean, certainly, on the trading floor or the fact that we have access to several capital markets. And as you know, the Canadian, I would say, capital market is slightly different than in U.S., but first, it's really important to be investment grade. I tend to focus on FFO to debt, I mean, as rating agencies also do. As far as talking about shareholders' remuneration and beyond, I mean, the end of the PPA, I think it's too soon to tell. I think the message here is really the fact that we've been consistent in our capital allocation until now, and so we still target to -- we aim at the CAD 1.2 billion of corporate debt by the end of 2020. Once -- as I said, once the uncertainty is lift also in the Alberta market, I mean, as we look to convert, I mean, our coal units to gas, once we've invested and once we've realized also the upside on hydro, we'll then allocate capital in the best way we think.

Yes, Patrick. Let me comment here because I think Christophe is just really starting to pull things together here and, certainly, I agree with him entirely that in Canada, investment grade is an important criteria. But the way I've been thinking about it is, Brett showed you that sort of the EBITDA under various scenarios. What's really important when you think about that chart is that the capital required to maintain the hydro and the conversions is significantly different than the capital that's required to maintain coal plants. So the net cash coming out of that chart is stronger. So when you take that net cash and add it together with the other cash that we have, the way I've been thinking about it is, if you start with your FFO, you need an allocation for the sustaining capital so that the assets continue to produce cash over time and then you need an allocation to debt repayment. By that time, that's gone away, as you know, because we'll -- I think the balance sheet that we're aiming for as we start into the decade is a good, strong balance sheet and really no IPP has ever have that balance sheet. They tend to overlever. We're endeavoring to underlever at the TransAlta Corporation level. So if you think about capital allocation then, to me, it's if you got to have money for the sustaining, you got to have money for the highest-value growth projects, and you really got to be clear about what high value is and what your targets are. And then, you've got to distribute cash to shareholders. I think when we get there depends on what the share price is. If the share price is low, for sure, the majority of that capital return to shareholders would be through share buyback. There may be an opportunity to start increasing the dividend, but I think it'll be a combination of those 2, and we'll have to think about what is the amount that shareholders can depend on coming from us as a return of capital for their investment.

Your next question comes from Mark Jarvi from CIBC Capital Markets.

I wanted to quickly go back to the ancillary revenue services. I'm just wondering what do you guys think, how that trends under capacity market if that's different at all versus the energy one?

Yes, we've done a bit of modeling, Mark, on that going forward. And candidly, we don't see that changing significantly when we do the work that we do, both internally and when we look at people from an external perspective that sometimes we see it broadly continuing. And when Brett went through his slide and he talked about kind of the notional capacity value that would be there for the fleet, it's kind of $6-ish sort of per kilowatt month kind of value. We think that, that is an unreasonable sort of proxy for what we expect in the capacity market as well. So in general, we think it is more of the same. And one of the reasons we used that 2018 kind of bridge, it's just when you look at kind of a pricing in that bridge, it's not an unreasonable kind of snapshot on what you can expect on a go-forward basis. It's a reasonable proxy, I think.

Okay. And then, in terms of market share where the hydro is having nearly 50% as you see a bit of a shift in the generation mix, the more wind and some of the coal coming off-line, what do you guys -- should that stay flat or is there anything, you think, would trend differently in terms of percentage that the hydro captures?

Yes. I mean, right now, I think what we've seen has been stable for a period of time. And you're right, the generation mix is changing. In fact, it's increased slightly as we've gone on. One thing you need to remember is, we also have obligations in our hydro fleet to manage water flows along the river. And we have a number of permits, so there is an environmental -- everything from recreational users to making sure the lights flows are appropriate along the river. So our macro capacity to actually provide more ancillary services in terms of volume is a little bit constrained in terms of what we're going to be able to do so. Again what you're seeing is a reasonable kind of proxy for the kinds of volumes I think that we're expecting.

Well, I think the thing you want to think about is in a market that has growing renewables, the demand for ancillary service is a bit higher.

Should go up.

Because you, on -- especially in some of the cold days here in February, the wind doesn't blow at all. So it's really important to have capacity in ancillary services and operating reserves and all of that. So I would expect, just given the pricing that you see on renewables and how far down it's come down, I would expect to see more in the systems all across the world, which I think puts a higher value on ancillary services.

Remember, it's a service that kind of matches supply and demand variability during the day, so...

Right. I just wanted to turn to TransAlta Renewables. You've talked about some of the growth that's happening there and potentially, Windrise standing up in TransAlta Renewables. Could you guys just maybe update us in terms of what you guys think? What is the return hurdle right now whether it's sort of an IRR or cash-on-cash yield for RNW investment?

Yes. Mark, we generally -- I'll be honest with you, we generally keep kind of -- that kind of discussion through what our hurdles are and what we're looking at from IRR is, I think, pretty closely guarded to us. I can tell you that when we're looking at drop-downs from TransAlta to TransAlta Renewables, we have our independent committee going through it. They do get a financial adviser, and they go through a pretty rigorous process to make sure that the value of the asset that comes in and effectively, the development team that they're paying for to TransAlta for that asset is appropriate in light of the cost of capital in the company.

Your next question comes from Andrew Kuske from Crédit Suisse.

Not to harp on the hydro, but I do appreciate the incremental disclosures in the quarter. And just one maybe easy question to start off with that do you anticipate any changes to how hydro will be dispatched in the capacity market to -- versus how they are now?

Yes, it's a good question. We've been engaged with the ISO in terms of the technical rules that they're developing for ancillary services and which are particularly oriented around the hydro that we have. The short answer to that process is, in general, we think that the rules those are being proposed are flexible enough to permit us to actually operate hydro as we have been. And they've been developed with that in mind, given, as I mentioned earlier, the obligations that we have from an environmental and permit perspective to manage the water flows on the river. So I think we're expecting, right now, a very similar, not much of a change in the way that we're operating the fleet.

And Andrew, we really want you to harp about the hydro a lot, so feel free to ask us a gazillion questions. We'll stay on the phone all day with you, and we'd like everybody to harp about it. So thank you.

Okay, well, I'll continue harping on hydro later, but I'll...

Okay, thank you now. Thank you.

When you think about just the outlook for pricing in the market structure in Alberta, clearly, you're doing the coal-to-gas conversions. Initially, there are going to be high heat rate units to start off with. You're going to have less baseload coal in the overall market. Just how do you think about the generation stack in the capacity market in the next few years versus what we've seen in the last say, 10 or 15?

Andrew, it's Brett. I mean, clearly, it's somewhat a function of the carbon policies and prices, so based on the current carbon policy that's in place today, coal-to-gas on a pure carbon is quite a bit less than coal. There is quite a bit of savings there on a per megawatt hour and then now you're down to really your next variable as your fuel charge and that's your natural gas versus coal. But ultimately, too, as I said earlier, coal goes away for everybody at the end of 2029, so you got a bit of what happens over the next decade and then longer term. But certainly, from our perspective, even though they have higher heat rates than, obviously, a combined cycle or something like that, they -- because of those attributes, we'll continue to dispatch. We expect similar to the way they've been dispatching of late. And then -- but if the carbon policy changes and shifts that, that could shift it going forward. You also have to remember, some of the units like the older peakers that were put in place, the heat rates on those are still pretty high and don't -- aren't as good as a new peaker that's in place. So again, they tend to only operate certain hours and try to pick off those higher prices. So right now, we don't see a lot of change well when we look forward, but again, it's subject to price this -- gas prices and other factors, carbon, in particular.

Your next question comes from Robert Kwan from RBC Capital Markets.

Maybe, I'll just continue here on coal-to-gas. I'm just wondering some of the disclosures here around lengthening the conversion up to '20, '23, and then there is also a statement talking about some or all of our units. I'm just wondering what's in behind that as well.

Yes, so the '20 to '23 is really just, as you can appreciate, you can't do all of these in one shot.

I think we'd be forward. We're '22, '23. Is that where we -- I don't know if we like this.

[Indiscernible].

He's actually moved it to 2020.

Yes. We've moved in a bit, but it's really somewhat a function of timing and outages, and you're not going to -- you're going to do one at a time, as you can appreciate, Robert. And then the summer all is really back to the comment I made about us evaluating this repowering option. So if we see that as an opportunity, then clearly, we may not spend money on the boiler conversion and just move into those instead. So that's the purpose of this summer all.

Okay, got it. I guess, then, just moving to Windrise or just using Windrise, as an example, and really more taking a step back and looking about -- looking at how you think about growth risk versus return, growth versus other uses. Based on your EBITDA disclosure for both the pipeline and then the total projects, it looks like you're constructing at plus or minus in the 11x range. Just wondering how you think about that versus M&A that seems to be going in 11 or the 9 to 11x range, so kind of just constructing at where private transactions are going.

I mean, I'll jump in and then, John can jump in. I mean, I would say that we are seeing for some assets EBITDA multiples even higher. I also think it's very important to look at each market is going to be different, depending on whether you have tax attributes, what the tax profile looks like, what the term of the contract looks like, so again, we look at it less than from EBITDA multiple perspective, we look at the long-term IRRs of the project. And then, they have to stand and meet our hurdles, but then what we do is we also then roll that into RNW because it may have some other attributes. For example, we may be able to accelerate some of the tax pools from that asset and apply it against Russell fleet. There might be some synergies that we can add to it. So it's less about multiple and more about our return. And I can tell you, the stuff we're seeing, Robert, especially on the solar side or even -- you've seen some of the big hydro stuff is very, very low equity returns.

Not a lot to add to what Brett said, frankly, the only thing is that again every project, whether it's an M&A project or whether it's a development project that we're doing internally, I mean, we think of the value of it, it's all based on the characteristics of the project. Everything from the regulatory certainty of the jurisdiction to the quality of the counterparty to the tenor of the contract to the technology that's being used and how comfortable and familiar we are with the technology, so it's a much more nuanced kind of discussion, and we continue to see in many places a very hot from a pricing perspective, M&A market perspective.

And Robert, I just want to comment on the pipe because I think you rolled that in your comment. The pipe, again, as I -- we tried to show there, once the pipes are in the ground, clearly, there is not much more incremental capital. We might have to do a bit of compression to get it beyond uncertain levels, but very, very modest. So any incremental volume that gets pushed for that pipe, it's just all straight to the bottom line. And that's why once we start moving volumes that we expect to move through there, you can see it is a very good investment for us, plus it just gives us -- it's my kind of view at no differently than owning the mine or direct lines. It's part of our field supply strategy and good returns coming with it.

Right. And then, just to the risk versus return part of this question, this $39 to $41-megawatt hour that you guys have put forward, are there any other revenues that you'd receive as part of that? And if not, how do you weigh that against just building merchant energy carbon credits, capacity price especially when you square that up against your Slide 19?

The price that we're getting into the PPA is the full price. And the economics that we did in making the decisions received was based on that price that it met our whole rates and everything there. There is -- there are people that are speculating, to your point, about whether or not you build some thing like in the emerging kind of market and take those kind of assets. That is not in the kind of risk profile that we have had, certainly, for TransAlta Renewables. I mean, for TransAlta, we're pretty clear about wanting to have contracted assets as best as we can and having the certainty and predictability associated with those assets, and that's in our focus today.

Yes, so Robert, let me make a couple of comments. So I think for TransAlta, the mix is important right now. The contracted assets that we'll add from 2018 from Antrim, Big Level and Windrise. And also having the discipline to project finance those with low-risk counterparties and to derisk those cash flows effectively. The combination of that portfolio with what we're going into Alberta with which will be coal-to-gas and hydro that will be subject to a market, that mix together gives us a lower cost of capital at the corporate level and allows us to continue to have a strong balance sheet on the investment-grade side. As we go forward into the 2020 time frame, and we look at if we were -- if I was to line up the returns of what Brett showed today on a hybrid against a merchant wind project, I would take the hybrid because I think it's got -- it's going to not only provide capacity to the market and ancillary services, but it's going to provide a ton of energy and it's going to be lower cost energy in the market because of the heat rates. So we look at it -- we would look at in the Alberta market that investment would be superior to a merchant wind project. Now when you go over to the Australian market, where our teams kind of -- they look over there under John's guidance, if you're going to build merchant renewables, you go to Australia where that gas prices are $12. And they're still bringing brown coal, and they're charging people $100 per megawatt hour, that will be the better place to take that kind of risk. And I would take that risk if I could see us getting our cash back in 2 to 3 years. I would not take the risk on a wind farm where you need 7 to 8 years to get your money back in a merchant market because I think as you'll see over time, and this isn't next week, and I shouldn't even say because people will think it's next week, but over a long period of time, as ISOs have to think about what it looks like to have more of these interment renewables, they'll have to change rules so that they get enough capacity. So the net-net for our portfolio, I think our mix of assets is right, and we like that contracted -- we'll have a certain amount of contracted projects in TransAlta Renewables because that gives us a better cost to capital at TransAlta.

I think the one thing we also didn't mention, just in terms of your ability to project finance the asset when it's built, which is something that we focus on, I mean with the merchant project that's something, which you're going to be able to do, including with the contracted asset is sticked into that is much, much better.

And remember, a wind farm in the capacity market doesn't get paid a lot of capacity. It's a very low amount and also wind, as you know, tends to get a price at a discount to the average price because of wind it blows, so when you factor all that, the risk, the inability to put project debt against it, it is a much higher risk scenario, and you have to think about that when you're looking at those prices that the ISO were awarded.

Understand. And if I can just finish with -- oh, sorry, Dawn, do you have...

Sorry, does that help, Robert, just give you, I think, in any way?

Yes.

Yes, okay.

If I can just finish with Slide 19 and the energy and capacity, what's the underlying capacity price assumption in '22 plus, it looks really high?

Yes, again this is from EDC. I think their capacity price is -- what you need to do is this is all on a megawatt heats. They're probably in that $15 to even $20 per KW or -- when you -- and you can just basically, if you took that amount on a per megawatt hour, what I usually do is just there's about 85 million gigs to get to our revenue and divide by clearing capacity in the 10,000. Once you adjust for UCAP, that will give you a rough KW month divided by 12, obviously, to get it on a monthly. And I think you'll get kind of in that zone. I have the numbers, I just don't have them right in front of me.

Okay. And do you have any thoughts kind of from a TransAlta perspective where you think capacity might end up landing?

Look, my only comment there is -- so again, we think the all-in price is a important way to look at it because especially for plants that are going to run frequently like hydro and fishing coal and our repowering and conversions, but it really comes down to that historical rate of $60 to $65, we think all-in is kind of a number to compensate people that are already in the market but also when required, attract new capital.

Yes, I think if you look at where things are going to go through the 20s, you're going to have to add new capacity in Alberta, and I think the -- I, as an economist, no matter what forecasts show, high prices never persist forever and low prices never persist forever because if -- I think people -- there is people that I have talked about a $30 price, and I'm like, wow, if operators doesn't want any power, I guess, they'll produce a $30 price, and I don't think that's sustainable. I think the ISO in terms of its capacity market has been trying to achieve something that ensures that you can get cost of new entry, you can get new entry, and they don't, in my view, think of new entry is only coming from the incumbents using their balance sheets, they have to actually get new entry to be financed by others and to get it -- when I look at the cost of new entry, it's been in the $50 to $55 range depending on where gas prices are for a long time. So we tend to see that as our kind of how we think what the opportunity might be. For planning purposes, we take the lowest possible price we can dream of and then we drive our cost to that low price.

Got it. Do you know -- is EDC done, assuming that cost of new entry is driving the price or the unconstrained bidders versus all of you who are going to be constrained at 85% of net count?

Yes, I think you'll have to pay for their service. We can't give you more than that, unfortunately though.

All I can say is those numbers that are -- if you really want to get a new generator and all, you have to have the capacity prices that are that high. For some period of time, all of these guys are coming in and managing it this way. Sorry to tell, we have to go. We're going to -- we'll put Brett on the phone with you off-line, Robert, after, with more detail, if you want.

Your next question comes from Charles Fishman from Morningstar Research.

I just have one question left for Brett on Slide 12. You showed the decision of repowering as a 2019 deliverable, so should we -- will that decision occur this year then? Or will you wait -- let the capacity market start up and, obviously, which would have an impact on the energy market, which I would assume would be the driver for that decision? How -- can you add a little more color there, Brett?

Sure, sure. Yes, and those definitely were full steam ahead here. And as I said, we're just close, still issuing limited notice to proceed, which really just finalizes the engineering work that we've been done just in more detail and then we go to limit notice to proceed and we start ordering equipment, which is really the long lead time. The actual outage, as I mentioned, is only approximately 60 days, but we do have to order the equipment and so on. So yes, we're -- I mean, from our perspective, as I said, there is so many benefits to converting that -- this is not a -- we're still wondering. This is where we're going as a company. And the timing, as I said, on when and how many and what years is really just us managing our work levels and stuff like that. And as I said, we're not going to do them all in 1 year or all in 1 month and all at the same time, but no we're full steam ahead.

But the repowering decision, which I heard is probably what $500, $600, $700 per KW, that is -- would that be a 2019 deliverable that decision?

Yes, yes, sorry, if that's what you're referring to. So yes, look, we want to do a bit more work. As I said, we've done sufficient work that we're pretty excited about it. We need to do a bit more work around things like just -- on the steam side, on the steam turbine and some modeling efforts. But that would be a more longer-permitted project, no question. It's like a -- we've had our Sun 7 combined cycle project from a few years ago, combined cycle that we didn't -- we got fully permitted, but by the time you permit and build, you're talking closer to four years all in. But we hope by this year that we would have advanced that enough to make that call and lay that out for people.

Your next question comes from [indiscernible].

I have two questions, and I appreciate you taking my time. So the first question is how you think about like bracketing in the possible political risks to both carbon and capacity markets, given the changes in Alberta politically? Like how do you sort of frame that range of outcomes and financially any color you have there would be helpful.

Okay, so that -- it's Dawn Farrell here. So two things that we think about. On the political risk factor, the capacity market, I think we're -- what we know is that the capacity market recommendation has come directly from the ISO who is the regulator here in Alberta and who is one of the top and most respected ISOs in the world. We know that ISO made that recommendation independently and it was accepted under the current government. And we know that the government -- the party that would like to be the new government also has a very high respect for the institutions in Alberta, the regulatory institutions in Alberta. So I gain my confidence in knowing 2 things: one, that the leadership at the ISO is exceptional and that their commitment to replace the existing PPAs with a market structure that will ensure that we have enough capacity and reliability in Alberta because, as you know, high reliability at low prices is the lifeblood of the competitive economy. I take my confidence and the respect that people have for them and that it's their decision and it was their decision under the current government and it's the current party that would like to get to be the new government, it's their philosophy as well to respect regulators. So that's on the capacity market. On the carbon levy, there was -- under the old conservative government who is now the UCP, they had put in place a high emitters tax, it was called the [indiscernible]. It had a somewhat similar form to what we have today. It wasn't as high as the one that we have today, but it certainly was there. We do know from discussions that there is a high probability that there will be a -- some sort of a price for carbon emissions in Alberta. And we also, in our federal government, under the federal backstop, there is a carbon price. So if any provincial government currently in Canada decides that they want to not have some sort of carbon price, they fall into the federal backstops and the federal government actually sends the carbon builds to consumers. So -- and you see that going on in Ontario right now, so everything is pointing towards having a price for carbon on coal. I think, finally, the way we look at it is, clearly, investors will support the cash flows coming out of our gas fleet, and they'll, I think, pay more for those cash flows than they would cash flows from the coal fleet because they see those as being transient in nature and short term because there is no dropping, moving, icing some higher carbon intensity ways that make electricity too low or 0 carbon intensity ways of making electricity. So we handicap it as the high probability of a capacity market and a high probability of some sort of price on carbon.

Okay, that's really helpful. So then one other quick question, plus something on hydro since -- so I guess, the other question, on the repowering opportunity, a couple of hundred million of additional CapEx potentially there, like, how do you think about financing that? And I just want to make sure you're not -- that there wouldn't be like some sort of equity component there obviously given where the stock is.

No. We do not think about financing it with equity. I can say that clearly. And clearly, we're just balancing our capital decisions as we go forward. We've got good capacity in the company.

Yes, and just the only other point remember, it's spread out over time because it is a longer-term project. And secondly, as we indicated, we may not do some other projects instead, so we're saving some capital on those projects that would go towards this. But as Dawn mentioned, the returns from our perspective are very good and these would be more starting later or even post 2020.

Yes. I think people will need to think about it this way. We finance a significant amount of coal turnaround capital every single year in this company to keep these coal plants running. And when you're financing the coal plants turnarounds, you're not just fixing the boilers after the floors have made holes in them, but you're having to put significant capital into the mine. You have to -- having to put capital into all the coal-handling equipment, all the grinding equipment, all that sort of thing. So the sooner that you can stop doing coal outages, and you can actually do an outage where you do sort of a final piece of work on the boiler, and you put in the new gas burners, you lower your capital significantly. So there is some incremental capital for sure for the new burners and getting the pipe into the plant, but it is offset by capital that's significant, as you say, on coal. So we're actually able to finance it indirectly through not spending money on the coal plant, not entirely. It's a marginal amount -- not marginal. I mean, it's a couple of hundred million, but it's not significant relative to our current capital -- sustaining capital that we spend today. I hope I was clear there, sorry if I wasn't.

Yes. No, that totally makes sense. That helps a lot. And then just another quick question on the hydro, like, I just want to be clear, the home for that is TransAlta, there is no current discussions to drop that into renewables or something right given the long contract venture?

That's correct. That's correct.

Your next question comes from Mitchell Moss from Lord, Abbett.

Thanks for the very detailed slides and the long Q&A. Just talking about coal-to-gas, you guys have discussed the $5 to $6 -- or I think a $6 capacity price or $60 to $65 all-in price. Would you say that those are reasonable price levels or sufficient price levels for you guys to invest in the repowering to a combined cycle?

Yes. Yes, for sure. I mean, as I -- given that the capital is significantly lower than a new combined cycle, that's a repowering if you take the actual conversion, boiler conversion, it's extremely low capital. And as I said, we save a lot of money not having to do NOx and SOx and a whole bunch of others. And so at those prices, yes, no, things are very good and a new one, obviously, you double the capital so you would be more -- you wouldn't get as good of a return at the same price.

Okay, so it would be sufficient though to tell me and talk about -- I just want to make sure there was also some confusion from an earlier question on boiler conversion versus a full combined cycle repowering. What -- you're talking about the combined cycle repowering, correct?

Yes. Yes. So remember, the boiler conversion effectively is just replacing the coal burners with gas burners. It's a relatively straightforward, small dollars, relative dollars, short outage. But you don't get the benefit of the lower heat rate. The repowering is putting new combustion turbines, gas turbines effectively in [indiscernible] to generate not only power but steam. We then take that steam and run it through the existing steam turbine that's being fed by that boiler today, so we dismantled the boiler, but we utilized the steam turbine and transformer and a lot of other capital and infrastructure that's already there. And as a result, that's quite a bit lower than having to build a brand-new where you have to build a steam turbine as well. It includes a steam turbine as part of the package. So two different capital profiles but one has better heat rate and longer life, the other one is very low capital, but you don't change the heat rate dramatically. And both are good economic projects and remember, even if we do a boiler conversion and run it to the end of the legislated life, you got steam turbines still in good shape, one can do the repowering on it, and now you've extended the life of that unit as well. But that's further down the road, so...

Yes, think about it this way, it's -- a capacity market demands two products. It demands low-cost capacity and low-cost energy. So the simple conversions are directed towards low-cost capacity and the hybrid is really smoking hot, low-cost energy, and so that's what we're -- that's -- so we believe that our portfolio with those two products in it is really competitive, and that's what we're -- that's why we've decided to spend some resources this year to see if we can get one of these hybrids off the ground because of the way lower cost that they have relative to a brand-new combined cycle.

And when you talk about the two units, do you mean -- is this going to be the potential Sundance -- both Sundance and Keephills could be converted to one by ones?

I think if we are focused on the one by one or it could be a 2 on 1 is more on Sundance because remember, there are higher heat rate units, K1 through 3 are newer plants, lower heat-rate plants. So if we do the repowering, it's highly likely one of the Sundance units, and that's what we're focused on.

We have four units at Sundance and three at Keephills, so we have seven units to make decisions on.

Okay, okay, so it's not -- when you talk about 2 units, it's not the whole plant. It's potentially just certain units within it.

Yes, right, that's right. Okay, so well, we should -- we've got twos more people, and we're getting the -- there's a lot coming in our office, so well, we can get on the phone with anybody after as well. Okay.

The next question is from John Mould from TD Securities.

I'll keep it quick. Just going back to Slide 19, can you just clarify the carbon pricing assumption in those estimates rises to $50?

Yes, oh sorry, on the forecast?

Yes.

Yes, again, you'll have to purchase there.

Fair enough.

All I can tell you is on the EBITDA sensitivity, one that we showed as well for both hydro and coal, that you'll see in the footnote what we assume there. We assume the existing provincial program and $30 per ton prices.

Okay. And then just lastly, on the federal backstop, you mentioned a little earlier, you're not subject to it today, but conceivably, it could be one day. Can you just maybe provide some color on your comfort with how that framework has evolved relative to the CCIR, particularly as it relates to your hydro facilities?

Yes, for sure. And so we're, obviously, very involved whenever there is regulations and very thoughtful in terms of how we think about these things and approach them and work with other participants and it's not just industry, other people that have an interest. We -- I mean, from our perspective, the backstop program is good. I mean, we -- it's a declining proposal, so it starts higher than what the provincial one does today, but it declines essentially towards the provincial one is, I think, right in 2030 and which is essentially a combined cycle type of unit. And so from our perspective, our strategy fits nicely into both programs, but we would have less and may be even no carbon obligation on a converted facility for the first few years under the federal program just because we would be coming in below the level until it declined every year. So both are fine, but certainly the federal is a good one.

Better, yes.

Is better for converted facilities for sure. It doesn't change a combined cycle or a gas plant. They're both at around 0.37, so they're unaffected. It really impacts coal and coal-to-gas and coal firing.

Your next question comes from Naji Baydoun from Industrial Alliance Securities.

Just a couple of good questions. Could you go back to the Sundance 4 unit. I think the previous question on mothballing was the change in the outlook. Can you just talk about the -- how we should think about the maintenance work and the output for the unit for the year? And does it impact your guidance at all?

So remember, currently mothballed is unit 3 and unit 5, and they are mothballed currently till the end of March of 2020. So 4 and 6 are the only 2 units from Sundance that are currently operating. And in our disclosure, I believe we outlined our maintenance -- plant maintenance, for which units we have. And Sun 4 does have a bit of an outage that will go into that unit this year. And I think the other one -- we have one other Keephills units, but that's in our disclosure, so is that what you're referring to?

Yes, just any units that are mothballed with very minimal expenditure and they're captured inside our guidance and our guidance has not changed at all for this year on anything.

Okay, got it. And just a wrap-up kind of question on the additional tariff from the hydro assets and progress on the coal-to-gas conversion. Appreciate the additional color that you provided today on both of these. Just wondering what you do see as the significant risks to the outlook on both of these initiatives.

Look, I don't -- I mean, any projects involve a lot of effort and -- but right now, as Dawn says, we try to model multiple scenarios and this -- the conversion, you got to remember, we always compare it first against being on coal and based on all those things I walked you through. I mean, it makes a lot of economic sense. So we test a lot of different price scenarios, both on gas, carbon, energy capacity and these all make sense. And we look at how much capacity is needed in the market going forward. But that's why we also look at things like repowering and so on and do a mix of that going forward. So there is always risk. I would say, the main risk is just we don't know what the energy and capacity prices are going to be. I mean, we can only do our modeling, and it will be what they will be. But as Dawn says, we're trying to -- we're setting these plants up to be very low cost both from a capacity and energy perspective in a market that needs this kind of capacity. You've got to remember, this is -- a lot of people live here in Alberta, so it's a heavy industrial 24/7. You need power all the time, and you can't do that unfortunately with all wind.

Yes, I think that's it.

All right. Thanks.

There are no further questions at this time. I'll turn the call back over to our presenters for closing remarks.

Thank you, Mike. Thank you, everyone, for joining us today and, particularly, thank you to all those people who patiently waited to ask questions. I know it was a bit longer today, and I would just like to reiterate, as usual, anyone who has further questions, please do not hesitate to reach out to either myself or Alex at Investor Relations. We can set up the call if you have further questions that we can't answer. Thank you.

Thank you, everybody.

Goodbye.

Bye.

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