Earnings Call: Q1 2018

May 8, 2018

Good morning. My name is Chris, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation First Quarter 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. Thank you. Sally Taylor, Manager, Investor Relations, you may begin your conference. Thank you, Chris. Good morning, everyone, and welcome to TransAlta's Q1 2018 conference call. With me today are Don Farrell, President and Chief Executive Officer Donald Tremblay, Chief Financial Officer John Koutsanares, Chief Legal and Compliance Officer and Brent Ward, Managing Director and Treasurer. 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 qualification, which is set out on Slide 2, detailed in our MD and 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 operation and free cash flow are reconciled in the MD and A for your reference. On today's call, Dawn and Denal will review the quarterly results and the outlook for the remainder of the year. After these prepared remarks, we will open the call for questions. So with that, let me turn the call over to Dawn. Thanks, Sally, and welcome, everyone. Today, I'm going to start with some color on how I saw the quarter and how it's affecting our view of the year, which is positive. And after that, Janelle will take you through the financials and I'll just come back at the end and give you some a few brief comments on our progress against our 2018 goals. Now as you can see in our highlights, we reduced our net debt by close to 300,000,000 dollars and we delivered results for the quarter in line or slightly better than last year. After adjusting for one time positive cash flows in 2017 2018, our year over year comparable run rate EBITDA for the business increased by 8% and our free cash flow increased by 3%. These financial results are primarily due to strong performance from our U. S. Coal and our Canadian gas segments, which more than offset the impact from the expiration of the Sundance APPAs at the end of 2017. The first quarter performance and our progress on debt reduction are exactly in line with the plans we laid out for you when we met with you early in December at our Investor Day. Now some of you may be a bit surprised by the great Q1 performance from our U. S. Coal teams. As you know, we've always optimized the value of those assets in the market, so that's not really a surprise. But that team has done some excellent work. They're highly competitive. And they've been working hard to get a strong coal transportation agreement in place that adds value. So that along with the work they've done on their cost structure allows them to is allowing them to make money on those assets even when there's lots of water in the Pacific Northwest and even when gas prices are fairly low. So, excellent work by that team. Now as well, if you look across the fleet, you'll see that availability during the quarter was 93.9% compared to 88.5% during the first quarter of 2017. And I'm really pleased to report that the Canadian coal segment led the improvement on availability. Their availability during the quarter was 90.5% compared to 83.7% in the Q1 of last year. Now their increase in availability was primarily driven by improvements in maintenance and operating performance across their fleet. That team has really embraced many of the practices that we've all learned through our Greenlight program, and they've made a number of changes to a number of processes and the way they do things. Now they're not finished all that work yet, and but we are optimistic that their work is laying the foundation for a new level of performance expectation for that fleet. Now the Canadian team, core team has also been very busy laying up the Sundance Units 2, 35, so they can be ready to bid as new capacity as that capacity market emerges. It was absolutely the right decision to consolidate energy into Sundance Units 46 and to make sure that we can deliver those megawatt hours at lower costs. We were disappointed that a dispute has emerged between the MSA and the ISO over the mothballing rules and what we're calling the sub period of the energy only market, which is really just a small period now before the energy before the capacity market comes into play in 2021. However, we're cautiously optimistic that those two regulators will come to some sort of agreement on those rules to ensure a strong functioning of the existing market. And we're also confident that our current mothballed units will be grandfathered under the old rules as they did meet the trust of those rules, including reliability at the time. Now, while we are observing relatively modest spot power prices here in the Q2 in Alberta, this is not unusual or uncommon given the seasonal demand that we always see in April May. Demand will increase as we move into the summer and we are expecting strengthening in prices due to that growth. And things are as you're reading, things are getting a little more optimistic here in Alberta with some of the oil price recovery. We are also, however, seeing incredibly low natural gas prices in the market here. We have some co firing capability, which is allowing us to utilize that gas and reduce fuel costs and our carbon bill. And we also have strong water resources in our hydro assets. So by optimizing natural gas and coal as fuel, with hydro and merchant generation, we are able to positively offset some of the capacity payments that we would have received in the past from the Sundance PPAs. And it's this capability that is helping us deliver cash flows in line or potentially better than 2017. Our progress on our Greenlight program has been significant. You saw that in our availability outcome. During the quarter, the Q1, we are in the last phase of our investment part of the program. So that cost us approximately $11,000,000 in the quarter, and those costs are finished as we go forward. So as we go into the rest of the year, these costs the investment costs are behind us and the value that we've created by making these changes will start to be realized in a number of our run rates. We do continue to forecast $50,000,000 to $70,000,000 in cash savings from the program as we go forward. So in my view, the quarter has us out of the gate well and we're positioned across the fleet to deliver both contracted and un contract contracted cash flows from our diverse assets, which are located in a diverse number of markets. So with that, Ganel is going to take the time now to give you more detail on the financial results. Thank you, Don, and welcome to everyone on the call. As Don noted at the beginning of our discussion, our EBITDA, plan from operations and free cash flow for the quarter were similar to last year after adjusting for the early termination payment of the Sundance D and CPPA in 2018 and the settlement from the taxation for the indexation dispute with UFC in 2017. As you can see from Slide 5, EBITDA of €259,000,000 was €19,000,000 higher than last year, an increase of 8%. Free cash flow increased £2,000,000 to £81,000,000 and funds from operations totaled £161,000,000 a slight reduction to last year. As you can see from the chart on the bottom left of Slide 6, segmented cash flow from our power generating assets, which exclude energy marketing and corporate segments, totaled €241,000,000 during the Q1, an increase of €26,000,000 or 12% year over year. We successfully offset the impact of the scheduled expiration of the Sundance A PPA at the end of last year, the higher fuel costs at Canadian Coal and the termination of the Solven contract in Australia with strong results from U. S. Coal, the contribution from South Edmond and lower capital expenditure. The impact of stronger price in Alberta was mostly offset by increased environmental compliance costs in the province during the quarter. There was no planned major maintenance during the Q1 of 2018, resulting in a decrease of $22,000,000 in sustaining CapEx relative to the Q1 of 2017. However, the lower spending during the Q1 does not change our outlook for 2018 and we still expect to spend between €195,000,000 to €205,000,000 in sustaining capitals early year. Energy marketing gross margin and EBITD during the Q1 were much higher than last year and totaled €17,000,000 and €9,000,000 respectively compared to €1,000,000 and a loss of €4,000,000 last year. Some of these gains in the Q1 will be realized in future quarter and are not included in free cash flow. Free cash flow was also impacted by certain mark to market losses that occurred at the end of last year, but were realized in the Q1 of 2018. Finally, cash flow from the energy marketing business is also impacted by the acquisition of Financial Instruments to cover future position. Let's move to our balance sheet and credit metrics. As you can see from Slide 7, we have €1,100,000,000 of available credit on our credit facility, a reduction of approximately 300,000,000 since year end. As we drew on our credit facility to repay a portion of the 500,000,000 In addition to our available credit, we had USD 329,000,000 of cash on hand at the end of the quarter, which includes R157 $1,000,000 received from the balancing pool on March 28 29, sorry, for the total liquidity of RMB1.4 billion. Turning to Slide 8, our adjusted FFO to net debt has shown consistent improvement over the past 2 years and is within our 20% to 25% target range at 20.9%. Our net debt at the end of the quarter totaled €3,100,000,000 a reduction of approximately €300,000,000 during the quarter. Using the proceeds from detailed determination of the PPN about our free cash flow and a reduction in our working capital. We are making great progress to strengthen our capital structure and are ahead of our plan to deliver FFO to debt at the end of our 25% to 30% range in 2021. We expect to maintain our current debt level over the course of the year, even with more than €200,000,000 of capital allocated to coal to gas conversion and the construction of our 2 wind project in the U. S. Our capital allocation plan for the next 3 years will continue to strengthen our balance sheet, improve our credit rating and position the company for growth. With our results during the Q1 and the outlook for the year, we remain confident in our ability to deliver at least €1,200,000,000 of free cash flow over the next 3 years, including the €157,000,000 received this quarter and a further €56,000,000 we are seeking from the balancing pool for the early termination of the Sundance PPA. Given the performance of the business during the Q1, we delivered more than €80,000,000 of free cash flow, Our historical performance, the high level of contracted revenue and the contribution from uncontracted capacity in Alberta, assuming current forward price, we believe we will achieve results at the upper end of our free cash flow guidance for the year. And we have increased the lower end of our free cash flow also for 2018 from €275,000,000 to €300,000,000 Further, as discussed on our year end earnings call, we initiate a normal course issuer bid with the intention of using incremental cash flow generated by the business to reduce the number of share are undervalued. During the quarter, we acquired and canceled almost 374,000 shares at a price below $7 per share under our NCIB for a total amount of 3,000,000. Our capital allocation plan for TransAlta over the next 3 years is prudent and we are still evaluating whether to invest in the gas pipeline being developed by Tidewater to supply our coal facility with natural gas. And we are advancing the preliminary engineering work on the conversion of our coal facility to gas. With the early termination of Sundance PTA effective March 31, we have more exposure to merchant power price. This differ from our previous highly contracted position in the province and it impacts the way we manage these units. In December, we announced our decision to mobile 2 of the full units at Sundance as it was uneconomic to run multiple units at lower capacity factor. The other 2 units at Sundance as well as our share of the output of K3 and G3 will be economically dispatched in the market. As you can see on the graph of page 9, the expectation for pricing for the next 3 years is in the range of $50 to $65 per megawatt hour, which is the strongest pricing we've seen in Alberta since 2014. As prices have moved up during the quarter, we enter into some fixed price contracts reduce our exposure and lock in margin. As we progress through the year and see power price I'm sorry, as we progress through the year and see where power price lands, we expect to strategically layer in additional edge to further reduce our open exposure and lock in value for our shareholders. With that, I will now pass the call back to Dawn. Thanks, Janelle. So I'm going to take a couple of minutes here to comment on our progress against our 2018 goals. They're all aligned on the slide that you see on Slide 10. And when you look at Slide 10, you see that our first goal for 2018 was really about supporting the development of a fair and equitable capacity market, and everybody here is working hard on that. The 2nd draft, as many of you know, of the comprehensive market design was recently issued by the ISO. And while the design is still a work in progress, we are pleased that progress remains on track and that feedback is being incorporated by the ISO as players work with them. One of the key issues for us is the government of Alberta's commitment to treat new and existing assets equitably and we remain very confident that they will honor that commitment. So when we look at the specific changes proposed in draft 2, there were changes to the demand curve, which we view very positively. And we do believe that that reduces price volatility, which is important for customers. Additionally, we were very, very supportive of the changes that were made to the penalty regime because companies like us that have larger fleets will be very much able to manage our fleet well within that. Now there's always a number of areas that need agreement before we'll be really confident that the market will attract capital. And that's both capital we see the capital that you need to maintain existing generation and the capital that you need to build new generation as the same kind of capital. So I want to talk about what we see are the 2 most important aspects of the new capacity markets and then we'll leave most of the details if you want to talk about it in the Q and A. So if I was to rank the top two issues that I think are important, the first one would that we have to get right to have a good functioning capacity market here in Alberta is the concept of COME. And COME stands for cost of new entry. And it's the number one building block of a strong capacity market and it is a calculated metric that goes into how you think about how you bid in that market. Now in Alberta, we know that the new entrant will be a simple cycle gas fired peaker. And the development of the cost of that new entrant needs to reflect the actual financing conditions of building a new peaker in a merchant market such as what will be here in Alberta. In our view, that's a generator that will have a much thicker equity component to it and it must have the right returns to reflect the risk that comes along with having to win a new contract every single year for 25 years to make a return on that equity and to service the debt that will need to be raised to support that capital investment. Power Generation continues to be a highly capital intensive industry and capacity will need to earn returns if investors are going to show up to the market. So we are gaining confidence that the discussion of this has been recognized by many of the market participants here. And I think a number would agree with this, but it's it will create a more vibrant capacity market. It will create a more vibrant capacity market. Now the second feature of a very strong capacity market is preventing subsidized generation from impacting prices in both the energy and the capacity portions of the market. So for example, if the existing 1300 megawatts of REP contracts reduce capacity and energy pricing, it will absolutely create an unlevel playing field. So for Alberta to function properly and for investors to make decisions that will last over 15, 20, 25 years, we absolutely must know how these subsidized resources will be treated in the Alberta capacity market. We are hopeful that the next iteration of the comprehensive market design will address this important issue. Now there are many other issues that are being discussed, including how costs will be allocated between both the capacity and the energy market, whether or not shadow bidding or economic withholding will be allowed in the energy market, the shape of the demand curve, the amount of procurement and the allowable capacity that will be able to be bid by each unit here in Alberta. All important aspects of the market, all making progress and in my view, all very manageable. So our view would be that getting the cost of new entry right as we come out of the gate and ensuring that investors are absolutely confident that prices will not be impacted by changes in government policy over time for subsidized resources are absolutely key to the success of a future capacity market. Our second goal is all about advancing coal to gas. Janel did talk about that in his comments. I think the only thing I would like to add there is, 1st of all, the recent reduction in gas prices to almost free in some days has given us a lot of confidence that converting our plants to gas is really the way to go. And we're seeing some impressive optimization value coming out of that. Now the Tidewater team is a very impressive group and their work on the regulatory study and stakeholder aspect of the project is very strong. We are hoping that they'll have a way to get gas to the plants faster than their current plan. The co firing opportunity is substantial for us as we could use up to 30% of the fuel in the existing plants before we've converted. So they can just get the gas there, we can absolutely start to use it. So hopefully, they'll find ways to speed up that pipeline. On safety, our goal is a very tough one, a 20% improvement over last year, which we've already got a pretty strong safety record. We did make it through the Q1. And as of the end of April, we are on track towards that goal. As many of you know though, this will just take daily and daily relentless work and will take a lot of attention from our team. I did speak about Greenlight earlier, so I am just going to take a minute to update you on the 2 U. S. Wind projects that TransAlta Renewables agreed to acquire during the Q1. Those projects are expected to reach commercial operation sometime during the second half of twenty nineteen. They do demonstrate our commitment to grow and diversify TransAlta Renewables portfolio with long term contracted assets, and that's one of our primary goals this year. The larger of the 2 projects is 90 Megawatt Wind Development in Pennsylvania with a strong 15 year PPA. Construction has started on this site. Still in the early stages, we're clearing trees and starting roads to prepare for the turbine pad. The second project is the smaller of the 2 29 megawatts and it's in New Hampshire. It has 2 20 year PPAs, which are both strong. We are waiting for the results of the environmental permitting approval appeal. And once that comes in, if it's positive, then we would start construction on that project sometime in August. TransAlta Renewables will be funding these growth projects, creating long term value for their shareholders. And of course, value for our shareholders as we own 64% of that vehicle and we have a large dividend coming from TransAlta Renewables that supports our financing plans. Now when I put all of the actions together in the Q1 performance with progress on the goal And I look at sort of the great week that I'm seeing week by week here on the operational performance, as well as the great week on as people are doing all of the work on Greenlight. I do think that that is giving us more optimism in terms of our ability to hit our free cash flow goal, which is to improve over last year. Last year, we achieved $328,000,000 of free cash flow, right in the middle of our range. And as we think about beating that goal, we're looking at a number of factors, including the percentage of free cash flow that is generated from contracted assets across the diverse fleet, our success in reducing cash costs and increasing performance as we execute new practices throughout our operations and finally, our ability to optimize around the volatility in the Alberta market with our uncontracted merchant coal and our hydro assets. So, our assessment so far is that our free cash flow goal is becoming achievable. Now that ends my formal comments. Before I conclude, I would personally like to thank Mr. Donald Tremblay, who's sitting across from me smiling, who announced just before AGM that he needs to return to Eastern Canada to get closer to his family. I really do want investors to know that the 4 years that Donald has invested in TransAlta have been pivotal to our financial strength. His leadership has been key in repositioning and reducing our debt. And we're all going to miss his energy, optimism and sense of humor. And we're sure that he'll occasionally come back to Calgary to visit him or we'll just come and see him in Montreal. We do have an executive search underway to find any new CFO. Luckily, our the CFO that we had in place before Janelle joined us, Brett Gellner, is still here and he's agreed to act as CFO in the interim. So many thanks to Brett, who will continue to execute the financial plan that Danelle has put in place and that we put forward to you on Investor Day. So with that, I'm going to turn the call back over to Sally for questions. Thank you. Thank you, Don. Chris, could you please open the call up for questions from the analysts and media? Certainly. Your first question comes from David Galifin from Canaccord Genuity. Please go ahead. Good morning, everyone. So my first question is on the hedging. And so you've talked about layering in hedging throughout the year depending on how the market evolves. Just wondering what portion of exposure are you comfortable with or are you targeting throughout the year? And maybe what as you see the market evolve, how would you look at hedging post 2018? So we need to be very flexible. And depending on like we have generation, that generation has a certain like variable cost. And depending on what is the price forward, like that's what we're basically looking to hedge. So currently, I would say like a significant portion of our like base load is hedged for this year. What we're price optimized now is basically the excess over the baseload and we are managing the unit accordingly. So for example, like in May, you will see lower generation from our plan and we're basically almost fully hedged for the amount of May. But during the summer, we probably price will be higher, so we probably have a bit more length. So that's the way we look at it. So it's very similar to what we're doing in Australia in terms of like dynamic hedging and basically managing what we call like a delta position. Yes. And we do have the authority to hedge into 2019. So if we see prices in 2019 that we think are good to take off the table, we can do that. And then when we get there in real time, we may or may not have to run the plant. So we really are treating it more as a dynamic hedging strategy rather than what you would have seen in the past. Okay. And my second question is just on the Tidewater pipeline. You had mentioned that you're looking at making that investment or potentially an investment. So just wondering what you're how you're viewing that and what it would actually take for you to make the exercise the option and make the investment in the pipeline? So the way Tidewater is set up today is we right now we're working with that team and they're making the investment in the pipeline and they're doing all of the work to get all the regulatory deciding the stakeholder work, get it built. We would have an option if we wanted to actually come in for a portion of that investment up to 50%. We haven't made that decision yet. Key for us is just to get the damn pipeline built because once it's built, we can then start to utilize that gas in our plants and we can actually displace some of the coal, which really reduces costs, especially in today's gas price environment and also reduces the carbon bill. So it's kind of 2 first of all, the pipeline is it's on its way to going ahead. And as long as everything goes well with them and they get the regulatory approvals, it will be built. The second decision is whether or not we want to own a piece of it. And then we're kind of pushing hard now to say, okay, is there any way you can go faster, which is always hard to do because there are pretty they have to go through the regulatory process. But clearly, I think gas producers here in Alberta should be cheering and helping us along here because they need to get some of their gas utilized here in the province. And so my question was actually on the investment? Yes. Well, I mean, once we get clear that we've got all the regulatory approvals and the pipeline is in place, we'll make that decision then whether or not we'll do that. And then just my last question was around the carbon tax in Alberta. Can you give a little bit of color about what the impact was for the quarter? Well, like I would say, like it's pretty difficult in a sense that basically like higher compliance costs, but higher revenue and one off than the other. In Q1, we believe Q2 will probably a bit better or actually Q3, like during the summer. But I would say during Q1, it's basically neutral from our perspective because like most of our carbon tax during Q1 was under like needed that are under PPA and it's a pass through. If you ask the question to the PPA PPA owner, they didn't have a different answer. But from our perspective, like the theater pass through and the merchant, we have been able to basically price that increase to offset the carbon tax. That was seasonal. Yes. Just remember, you have to look at it. You almost have to think about the carbon tax as being in 2 buckets. Under the existing PPAs, the PPA buyers pay the carbon tax. They dispatch the units. And depending on how much they dispatch the units is what their bill is. For our merchant plants, only if we see prices that recover the carbon tax and give us some profit will we dispatch those units. So, we've got to be able to pay for the carbon tax, pay for the fuel, pay for all the variable costs and make a bit of a return for us to dispatch the unit. So we're in control of how much we pay there depending on what prices look like. Thanks very much. Your next question comes from the line of Rob Hope from Scotiabank. Please go ahead. Good morning, everyone, and all the best in your future endeavors, Donald. Thank you. Maybe a broader question. Just in terms of capital allocation, how do you view your potential opportunity set, whether that be the Tidewater Pipeline, solar at Centralia or U. S. Northeast wind versus the returns you'd be afforded through your NCIB? And then secondly on that, have you been using your NCIB in Q2 so far? We haven't used it in Q2 because we're currently in blackout. So we'll be able to restart using it again this week, I suspect. On capital location, like priority still like debt repayment, so like that's number 1, and that's basically the priority of our capital location. The coal to gas conversion is important. It's like we're investing for the future of that business, so that goes second. And the excess cash is basically share buyback. So that's what we said like in January when we announced that program and that's the direction we're taking. Yes. So just remember the U. S. Northeast wind farms are going to be funded and financed out of TransAlta Renewables, not out of TransAlta. So that's not taking away from the financial capability of TransAlta. The solar would be the same. It would require a long term contract and it would be at TransAlta Renewables Resource. The pipeline, we'd have to think about that. It depends on what the returns will be. And we do as you know, we've been very clear that we think the returns on buying back TransAlta shares are very high. So that might be a project that could end up in TransAlta Renewables and we have to decide if we're even going to do that because we really have to think about our capital allocation. As Danelle said, the highest returning project for sure in the portfolio is extending the life of the coal plants on gas. As many of you probably everybody's forgotten, but those coal plants were slated to start shutting off by 2025 in any event. So the fact that we've now been able to get the legislation federally and provincially to convert them to gas takes them well into the 2,035 timeframe. And it's a small amount of capital for a long set of cash flows. So that's by far our best investment in the fleet and definitely is a better investment than buying back our own shares. Very true. All right. A Q1 question. Just taking a look at the energy marketing, your comparable EBITDA versus the energy marketing cash flow, which was an outflow during the quarter. Can you give some color on the unrealized gains of $27,000,000 that are sitting on your book right now, when those could be realized? And then secondly, how much realized losses was in comparable EBITDA in Q1? So what I would say, like when I'm looking at the like that like $25,000,000 $27,000,000 that we have like in free cash flow for the energy marketing, I basically have like 3 buckets and it's probably a third, a third, a third between mark to market gain that will be realized in the future, between losses that we incurred at the end of last year that realized during the quarter and acquisition of Financial Instruments to for the future that we enter into in Q1. So like that's the way I characterize the outflow there. All right. Thank you for the color. Going to that to answer the question of which period, I'd say it's probably 2 thirds 2018 and a third 2019 for the realization. I'm not sure like where they are exactly in those positions, but like it's 2018 2019. It's 18 2019, more weighted to 2018. Your next question comes from Mark Jarvi of CIBC Capital Markets. Your line is open. Good morning. I just wanted to go to the Canadian Coal segment. There was some commentary that by SUN 1 and 2 coming offline of the $12,000,000 decline in EBITDA, but I guess $26,000,000 year over year. So in your comment just a minute ago, you're saying that you're kind of neutral on the carbon taxes. So where is it in the cost profile that you've seen that drop on EBITDA? And then as you take more units offline, where's the cost profile heading as you spread fixed costs across lower generation? Well, remember, there's a lot of work being done at the company to reduce fixed costs so that we affect it like we're not holding the same fixed costs as we had with 6 units and then trying to pay for them with 2 units. So we've had a massive amount of readjustment of that business to get it down to 2 units that can kind of stand on their own. So that's number 1. And then number 2, the same with the mine. So the mine is being resized as we speak to a much lower volume of coal. And then of course, as we get a pipeline in there, that's even a lower amount of coal. So it's making sure that we have that sort of dual fuel flexibility until we actually do the conversions. So that's it's really how we've resized the cost structure to the number of plants out there that's allowing us to then make sure that we can be at the same level of free cash flow as last year or slightly better, which is our goal. And maybe you can comment in terms of the timing on the resizing of the mine versus fixed operating costs and when sort of how those compare in size and when those sort of will be realized in terms of the cost savings initiatives through Yes. So they've it's not an easy thing to do to just turn a mine from 12,000,000 tons to 67,000,000 tons. It's like not an overnight thing. So it's going to take it's taking we think it will take about 12 months to get to the exact size that we need it to be with the right cost. So they're scaling it down as we go through the year. And of course, we've got to manage that. And at the same time, it's an uncertain time for our people. So we've got to do it in a way that we keep people working and keep training people and all the rest of it because all else being equal, people would rather go up north and work on one of the mines at Fort Hills or something like that. But so we think by the middle of next year, we'll have that appropriately sized. And if the guys can go faster, you'll see that in our results sooner as we go towards the end of this year. Okay. Good. And then The cash flow estimates that we've given you account for that scaling issue. So we've built in the cost as we go forward here. Right. Okay. And then just looking at the results of the U. S. Coal, which again were quite strong this quarter, you talked about in your prepared remarks, where do you think that business could deliver in terms of EBITDA free cash flow on a full year basis? We don't normally give that guidance. We don't give guidance, but the way of looking at what you can do at U. S. Coal is basically like €30,000,000 to €50,000,000 Like if you look at historically what it performed, it should continue to perform and improving over time because of the like significant improvement they're doing under like fuel supply. So those are very creative. The way that they basically set up contract with BNSF and the coal supplier to make most of their some of their costs linked to natural gas and make the unit more flexible and running like a bit more often, so creating a bit of like more margin. Okay. And then my last question in the comment in the MD and A talks about potentially securing about $300,000,000 to $400,000,000 of debt. Is that related to coal or off coal monetization? Or is that some project level debt at some of the assets at R&W? Could you repeat the question? Sorry, I missed the question. I think at the MD and A talks about to cover the maturities in 2019, you're looking at raising about $300,000,000 to $400,000,000 of debt. I'm just wondering if that's from off coal monetization or is that project level debt on some of the R and W assets? It's the off coal monetization. Okay. Thanks. And all the best as you transition there, Donnell. Thank you. Your next question comes from Ben Thanh of BMO. Your line is open. Okay. Thanks. Good morning. I also wanted to wish you the best of all done all. First question on guidance, revision there and wondering on it's quite early in the year. It looks like the commentary was Q1 was in line with expectations of a positive tone. And I may have missed this in your earlier remarks, but was there some layering of hedges that you're putting on for rest of the year that probably reduce a lot of the variability in the remaining portions of your business on the Alberta Cola side? I would say, Ben, that just in terms of how we've looked at the year and how it's going to play out. Our Q1 was a little bit better than we expected from a free cash flow perspective, and we're seeing that strength continue as we go forward here. And as well, as we look at, remember, we're kind of gaining experience with optimizing our assets as we go through April here and turning plants on and off and bidding them into the market and looking at our ancillary services and hydro and all that sort of stuff. So as and we're trying basically getting the cost structure right and being able to optimize is what allows us to continue to have a run rate of free cash flow that in prior years, which would have been effectively guaranteed by capacity payments. So as we've looked at that and look at the forward market, that's where we think that our bottom end could have come up and which kind of puts you in now puts you in line with where we were last year. And then our goal is to see if we can get a little bit above that. Okay. And then on Rob's question about buying back stock with the blackout commentary. Is I wasn't clear, is the expectation that you would be buying more stock then? Like the expectation is that we will buy stock over the course of the year when we believe that there's value in this stock. And that's not the first priority with our capital. Like the first thing is like we are focusing on our debt. We're focusing on our growth. We need to allocate capital to our conversion and residual capital goes to basically share buyback. So we're not changing like course on this, but clearly like at price are like below like our threshold will acquire probably some share in Q2. Yes. And I think we were pretty clear when we announced that program that as we see the cash flows being at the more positive end of our guidance at the higher end, then we can allocate a little more capital to that. And we haven't changed our view on that. You saw us do a little bit of purchasing in the Q1, but it was moderate, right? But as we go through the year, as we gain confidence in where the cash flows are at, then I think we've got a little more flexibility. Okay. Sounds good. Thanks. Thanks for everything. Thanks, Dan. Your next question comes from Robert Kwan of RBC Capital. Your line is open. Good morning. Just wanted to come back to the proposed capacity market framework design. And Don, I think you touched on penalties. I don't think you touched on this. I apologize if you did. But just with respect to market power mitigation on the supply side, just your thoughts on what's there? And I guess more specifically, do you expect to be mitigated? Well, I think the way that the design currently works, almost everybody is mitigated. So I think there's a bit of a in the discussions that are going on in the current CMD, if you do all the calculations and it's the most complex thing I've ever seen. I mean, as you know, I'm a hack economist and even as a hack economist, I can barely understand what you're talking about. But I think at the end of the day, it mitigates 70% of the market, the way that it's being calculated, which isn't going to be an effective market for creating a capacity price. So I would expect that as we go from CMD2 to CMD3, there'll be a lot of discussions about what that looks like. Because I think if you mitigate everybody, I mean, what are we doing here? What it's not really a market, right? So I do think there'll have to be some movement on that. Okay. Would you just given the amount of capacity you've got that even if there is a change and it's a lower percentage, do you think that it's reasonable that it will end up in a spot where you won't be mitigated? No. I think TransAlta will definitely be mitigated because of our just our total sheer volume of capacity that we have in the market. I think it's just whether or not the rest of the market if we're the only ones that are mitigated, then effectively the price will probably be set at the right level, right? Because it won't be us that will set the price, it will be the other 70% or 75% of the market that will set the price. But if they come up with a formula where they actually mitigate 70% of the players and the 30% that are left, are trying to set price and there's only a couple of them that won't work either. So I think definitely will be mitigated, but it doesn't mean remember, everybody misinterprets that and they think because we're mitigated, that's the price we get. Not true. So let's say we were mitigated at I don't I would be surprised if it stayed at the 0.5 and the current this current RSI thing that they talk about that doesn't make any sense to me. John Kuzinorz maybe understands that he's sitting here. But I think when they get those calculations correct, at the end of the day, they really need 70% to 80% of the market to be setting price. And then, of course, we get that price, whatever that turns out to be as it crosses the supply and demand. For sure. And I guess as it relates to mitigation, do you have issues with the asymmetry and the lack of buyer side mitigation? The lack of buyer side? John, you want to talk? Yes. We haven't I mean, we haven't really been focusing much on that, to be honest, Robert. It hasn't been a major focus for us. It's been our focus has been primarily on the supply side, and Don's been articulating that and our focus has definitely been on what the 0.5 of net column that people that would be the supply would be mitigated to be honest. Are you thinking about buyers bidding capacity into the market as solid capacity, that kind of No, just where you've got a net buyer power who might have some incentive to do something else with the capacity price. And we've seen in other markets the introduction of buyer side mitigation to prevent that activity? Yes. Our sense right now as it relates at least on the work that we've done here in Alberta, not to discount that issue, but it hasn't been sort of the principal focus that we've had. It's definitely been on the supply side. And it's pretty small. Yes, it is relatively small. Got it. And maybe I'll just finish. You've given some thoughts on power pricing. Just wondering if I can get a little bit more color here. Obviously, we're in a shoulder period, so that certainly is a piece. Do you think that really as you look at your power price outlook that we might be seeing or you expect to see more volatility than you might have thought as we get through the year just given we come into April, we've seen a little bit of actually quite high amount of volatility for a short period of time. But then since then, it's been pretty, pretty low vol and in fact putting up a bunch of zeros like this morning? Yes, yes. So I mean, honestly, in the shoulder period, you're going to get low prices and volatility in the negative direction, right? And I would expect as we go into the summer, you'll I mean, there's no question with that the Alberta market should have more volatility in that period going forward. It's just the way that the market works. So that's how as we're doing our dynamic hedging here, that's mostly what we're looking at is how to position around that volatility. But we do expect more as we go into the summer. I guess just have you been surprised with the amount of capacity that you've got back, the demand growth and then the mothballed units that the price has been as low as it's been? No. No, I haven't been surprised at all. Like April May are like never like solid months in terms of pricing. Like July, August, September will be the true test. Yes. Perfect. Thank you. So the marketing is behaving as we would have expected. Yes. Okay. Donald, best wishes with that move back home. Thank you. Your next question comes from Charles Fishman of Morningstar Research. Your line is open. Thank you, Don. I only have one question. Does the dispute the disputes with Fortescue have any impact on your thinking with respect to the amount and timing of the share buyback? Do you need to have those resolved before you go in heavier amounts of buyback? No, no. That doesn't impact our thinking on the share buyback at all. Okay. Thank you. That's all I had. Your next question comes from Mitchell Moss of Warde Lebitt. Your line is open. Hi. Just a couple of questions. Looking at the Sundance Unit 2, what type of prices would you want to see either in the forward markets or I suppose in the capacity market that would cause you to bring the plant back online? Well, it's a combination of price and volume, right? So you've got to see the big challenge in the Alberta market is it's fundamentally got a lot of capacity supply in the market and there's no capacity value for these units like no one will pay you The ISO is not going to phone it tomorrow afternoon and say, here's a capacity contract to bring that plant back for a couple of years because we need the capacity. So it really has to make it on the energy sales. So it's really if we were running 4 and 6 at 80%, 85% capacity utilization and we could see another 50% capacity utilization to start that unit back up, we would think about it then. But right now, we actually make our money by dispatching up the units to a higher capacity utilization versus starting another unit. You got to remember with these units, the heat rate is the best. So the efficiency of burning fuel is the best and the carbon tax is the lowest when the heat rate is in its best position, which is at a higher capacity utilization. So our whole strategy is fill those units up first and then only if you can see a pretty good amount of gigawatt hours needed in the next unit at a good heat rate, would you start to say, okay, it's time to bring that unit back. So it's a combination of price and volume. And right now, we aren't seeing the need for these 2 units and they're not running at 85% capacity utilization. Okay. But I guess under a capacity with a capacity market set up, does that thinking change in terms of? Yes. Totally. Yes, absolutely. So remember, these are not called under the energy only market rules, which that's what we set them up under. And they're absolutely being set up to be competitive capacity supply into the capacity market. So those bids, I think, will go in sometime in 2020 and all of these units will be bid in to the capacity market. That makes a huge difference. Okay. And just following up on the last set of questions, when you talk about volatility, how are you guys thinking about volatility in the market, in the Alberta market, I guess, currently versus post capacity because looking at other power markets in the United States, having a capacity market can at times reduce energy price volatility just because there is sort of a floor of excess available standby capacity? That's right. Yes. So for sure in an energy only market, if you don't have volatility and you don't have extremely high priced hours, you can't make a capacity payment for the units, right? So there is a lot more volatility in an energy only market that's designed properly. When you go to a capacity market, if you get the market set up correctly, and you bid your capacity contracts, you make your returns effectively on the capacity side of the market. And on average, you make a variable cost or a slight margin to that depending on which unit you've got in the energy market. So for our units, for example, units you talked about Sundance Unit 2, that's a great capacity resource. It doesn't it's not really going to be all that necessary to run, but it's a great standby capacity resource, especially as you bring 5,000 megawatts of wind into the province, because all that wind has to be backed up. So you do absolutely expect less volatility in an energy capacity market, which is the promise to the consumers, because all else being equal, consumers like less volatility. But the way we make our money is how we get it out of the capacity market. So we don't mind that there isn't that volatility. Okay. And just kind of housekeeping item. The capital allocation slide, I didn't see it from Q4 that sort of shows $1,400,000,000 of bond repayment uses and dividend of $100,000,000 and so on and sources and uses. I didn't see that in this presentation. I'm not sure if it was discussed because I had for some reason my call got disconnected. But are you guys still seeing the capital allocation plans in terms of $1,200,000,000 of free cash flow, using $400,000,000 of liquidity and so forth, kind of matching that allocation plan that you put out a couple of months ago? Yes. The slide is exactly the same as a couple of months ago and Janelle did make comments about that and said exactly that. So it's exactly where we were. There's no change to our capital allocation, no change at all. And in fact, like we're like advancing because like out of the 1.4 of like bond repayment, we paid like US500 million dollars US600 million dollars in March of this year. Okay. Okay, great. And so you already used some of that. I guess, it kind of looks like you've used some of the liquidity, so to speak. So I mean, is that more of a seasonal volatility because given that your liquidity has come down in terms of that capital allocation? In other words, I expect the liquidity to come back up over the next year or 2? Or is this sort of you've kind of taken that $400,000,000 of liquidity that's been used and then the remaining sources, call it, dollars 1,700,000,000 those are going to be those are still going to be realized, I guess, over the next year and a half. So what you will see us doing over the course of the year, we will do like some financing activity that will replenish our liquidity. And like our next scheduled repayment is CNY400 1,000,000 in November of 2019. So now we have like roughly 18 months to rebuild our liquidity should we pay that maturity. And we'll do this through like financing of some contracted cash flows and free cash flow from the business over the next like 18 months. Okay, great. Great. Thanks so much. Good luck to Nal. Thank you. Your next question comes from Patrick Kenny of National Bank Financial. Your line is open. Yes, good morning. Just with Battle River 5 coming off PPA in the fall, does that accelerate your plans at all to bring in a second pipe into Sundance or perhaps go ahead and support Tidewater building its pipeline to the full capacity? Yes. I mean both of those the teams are working on both of those outcomes. For sure, as you know, just watching the gas prices here, there's a lot more upside potential. So, the team is working on a second pipeline. There's 2 potential opportunities there. Well, actually 3 because you could do another one with Tidewater. And then there's the adding compression to Tidewater. So all of that is in discussion and underway right now. Okay. And then just on the fuel mix as well without full CTG conversion. I know you've talked about in the past onethree gas, twothree coal ratio is kind of a good ballpark for Sundance and Keyfills. But recently we've seen some higher ratios at some other coal plants. So just wondering, given how low gas prices are, if you're finding new ways to increase the amount of gas that you can put into the boilers? Well, the engineering teams are always looking at that. We use the 30% as just a broad ratio that we think about as we look ahead and do planning. But for sure, if there's ways to increase the capability and remember, these plants are all designed individually 1 by 1 and built 1 by 1. So they do have different set points for that. But the engineers will if there is a way we can use more gas in a boiler, if we've got it, they'll be doing that as well. Okay. That's great. And lastly, all the best in Altobac East. Just maybe one last question before you go, and that's with the transition to a capacity market likely being viewed as a net positive from the credit rating agencies. Just wondering what your view is on the optimal credit ratios heading into next decade? Yes. So I think we're sticking with our plan. Like we really want to be in 2021 at 25% to 30% and at the upper end of that range. CapEx market is great, but there will still be some volatility and some year will be better than others. The good thing is that 2 year in Agen. So from a rating perspective, that's a positive because it gives you time to or to basically set your balance sheet in accordance. But like we are sticking with our plan at like 25% to 30% FFO to debt. The good thing, however, is most of the like corporate obligation of TransAlta will have been repaid and the balance sheet will be very strong in 2020 after we repay the €400,000,000 during 2019 and the €400,000,000 during 2020. Yes. And I would just add, I mean, the view of the management team here is that as we go into 2020 with the capacity market and of course we'll have the hydro as well here in Alberta and some wind and all the rest of it, That if you think about the recourse debt that will be left that sits in that kind of $1,100,000,000 $1,200,000,000 range. We think that's about the right amount of debt for those assets going forward. It is a very counter strategy to the industry. The industry tends to over lever merchant assets. They'll lever them up to 60%, 70%. We are under levering merchant assets because we think that's what you're supposed to do if they're merchant. Even though they are, like you say, they're a little more stable because of the capacity market. So I think the balance sheet for those assets will be very strong and will carry the company through the 2020 very well. All right. That's perfect. Thank you very much. Your next question comes from Jeremy Rosenfield of Industrial Alliance. Your line is open. Yes, thanks. Just two questions. First on the transition into the capacity market and some of the changes in CMD2 allowing for smaller sized units. I'm just wondering if you've looked at or if you expect to start to look at the opportunity to put some storage solutions in with some of the existing wind assets or on some other sites that you have in the province? We're always kind of looking at that. But what we're finding is our storage is actually the cheapest storage you can have. It's the storage that we have in our hydro, right? So that really works well with our wind assets. And we continue to work hard on seeing if we can get going on a big storage project with Brazil because we've done a ton of work on storage, solid state storage, full batteries, all that stuff. Still quite a ways off. I mean, there you can if you want to subsidize storage in a massive way to bring it into the system, you can do that. But if you want economic storage, it's still projects like Brazil. So that is the best lowest cost way to bring storage into the province. And it would be our first it's our main focus. And we tried a million different ways to think about how to put a solid state battery in. But if you look at the economics of those, you're getting a couple of even if you get 2 hours a day at a differential of $10 or even $20 you're talking about $40 a day for 1,000,000 of dollars worth of investments, you're talking about like 20 year payback. We're not interested in that. So our current hydro is great storage and then seeing if we can get Brazo is more important. Okay. So just looking at Brazo since you brought it up, where is the project in terms of development? I think in the MD and A, it mentions that you're spending a little bit of cash to advance the development. And it looks like maybe some of the sizing or the cost numbers have moved around. So what is the latest update maybe? Yes, the latest I mean, it still is in the exact we're working here with the province and the ISO and well, really waiting to see if the province wants to support the development of a large hydro project as part of their renewables goal. They've stated 5,000 megawatts. They've done calls now for about 1300 megawatts of wind. I think it's really more of a policy decision if they want some of that dispatchable renewables to come from projects like hydro and we're waiting to see them make that decision and then determine some sort of competitive process for us to bring that project forward in. We're very much working hard with them to see if we can get that done before the end of this year, but we'll have to wait and see. And we're just limiting our spending because as you know, in the Canadian market, if you get too far over, you see spending money and you don't get regulatory approval or it takes 4 or 5 years to get it, it's not very economic. So we're just really sizing our spending to the regulatory environment. Okay. No, I always want to stay on the middle of that, Keith. Just turning to the new wind investments. Does the assets right now or sorry, so there's one that's under construction, does that carry construction debt already? And I assume the other one, which is not under construction, doesn't have any debt? No. Right now, that's just on we have a credit line for R and W, and we're just funding it through there until we decide how to more permanently finance it. I meant the construction, the asset that's under construction, if it had debt already that you were acquiring as part of the transaction? No, no, no, no. Okay. Perfect. Okay. Perfect. And then in terms of financing options, do you assume a tax equity component for the permanent financing? That's our plan. Okay. And would R and W be the owner of 100 percent of the cash equity? The RNW will hold like an economic interest in the 2 projects similar to what we did in the past, yes. Great. Okay. Great. That's it for me. Thank you. Thank you. There are no further questions at this time. I'll now return the call to our presenters. Thank you, everyone. That concludes our call for today. If you have any other questions, please don't hesitate to reach out to myself or Alex at Investor Relations. Thank you.