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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. [Operator Instructions] Sally Taylor, Manager, Investor Relations, you may begin your conference.
Thank you, Chris. Good morning, everyone, and welcome to TransAlta's First Quarter 2018 Conference Call. With me today are Dawn Farrell, President and Chief Executive Officer; Donald Tremblay, Chief Financial Officer; John Kousinioris, 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 to 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 operation and free cash flow are reconciled in the MD&A for your reference. On today's call, Dawn and Donald 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, Donald will take you through the financials, and I'll just come back at the end and give you some -- a few brief comments in our progress against our 2018 goal.Now as you can see in our highlights, we reduced our net debt by close to $300 million, and we delivered results for the quarter in line or slightly better than last year. After adjusting for onetime positive cash flows in 2017 and 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 APPA 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 team. 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 first quarter 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 expectations for that fleet.Now the Canadian team -- coal team has also been very busy laying out the Sundance units 2, 3 and 5 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 4 and 6 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 ISO over the mothballing rules and what we're calling the subperiod of the energy-only market, which is really just a small period now before the capacity market comes into play in 2021. However, we're cautiously optimistic that those 2 regulators will come to some sort of agreement on those rules to assure -- 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 test of those rules, including reliability at the time.Now while we are observing relatively modest spot power prices here in the second quarter in Alberta, this is not unusual or uncommon, given the seasonal demand that we always see in April and 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 coal 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've received in the past from the Sundance PPA. 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 first quarter, we are in the last phase of our investment part of the program. So that cost is approximately $11 million 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 million to $70 million 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 uncontracted cash flows from our diverse assets, which are located in a diverse number of markets.So with that, Donald is going to take the time now to give you more detail on the financial results.
Thank you, Dawn, and welcome to everyone on the call. As Dawn noted at the beginning of our discussion, our EBITDA, fund from operations and free cash flow for the quarter were similar to last year after adjusting for the early termination payment of the Sundance B and C PPA in 2018 and the settlement on the -- for the indexation dispute with the OEFC in 2017. As you can see from Slide 5, EBITDA of $259 million was $19 million higher than last year, an increase of 8%. Free cash flow increased $2 million to $81 million, and funds from operations totaled $161 million, 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 million during the first quarter, an increase of $26 million 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 Solomon contract in Australia with strong results from U.S. Coal, the contribution from South Hedland and lower capital expenditures.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 first quarter of 2018, resulting in a decrease of $22 million in sustained CapEx related to the first quarter of 2017. However, the lower spending during the first quarter does not change our outlook for 2018, and we still expect to spend between $195 million to $205 million sustaining capital during the year. Energy Marketing gross margin and EBITDA during the first quarter were much higher than last year and totaled $17 million and $9 million, respectively, compared to $1 million and a loss of $4 million last year. Some of these gains in the first quarter 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 first quarter of 2018. Finally, cash flow from the Energy Marketing business is also impacted by the acquisition of financial instruments to cover future positions.Let's move to our balance sheet and credit metrics. As you can see from Slide 7, we have $1.1 billion of available credit on our credit facility, a reduction of approximately $300 million since year-end as we drew on our credit facility to repay a portion of the $500 million U.S. bond. In addition to our available credit, we have $329 million of cash on hand at the end of the quarter, which includes $157 million received from the Balancing Pool on March 28 -- 29 for the total liquidity of $1.4 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 $3.1 billion, a reduction of approximately $300 million during the quarter. Using the proceeds from the early termination of the [indiscernible] free cash flow and the 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 million of capital allocated to coal to gas conversion and the construction of our 2 wind projects in the U.S.Our capital allocation plan for the next3 year will continue to strengthen our balance sheet, improve our credit rating and position the company for growth. With our results during the first quarter and the outlook for the year, we remain confident in our ability to deliver at least $1.2 billion of free cash flow over the next 3 years, including the $157 million received this quarter and a further $56 million we are seeking from the Balancing Pool for the early termination of the Sundance PPA. Given the performance of the business during the first quarter, we delivered more than $80 million of free cash flow. Our historical performance, the high level of revenue and the contribution from uncontracted capacity in Alberta, assuming current power price, we believe we'll 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 outlook for 2018 from $275 million to $300 million. 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 shares outstanding when we believe our shares are undervalued. During the quarter, we acquired and canceled almost 374,000 shares at the price below $7 per share under our NCIB for a total amount of $3 million. Our capital allocation plan for TransAlta over the next few 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 PPA effective March 31, we have more exposure to merchant power price. This differs from the previous highly contracted position in the province, and it impacts the way we manage these units. In December, we announce our decision to mothball 2 of the 4 units at Sundance as it was uneconomic to run multiple units at lower capacity cycles. 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 update on 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 entered into some fixed-price contracts to reduce our exposure and lock in margin. As we progress through the year and see power price -- sorry, as we progress through the year and see where power price lands, we expect to strategically layer in additional hedge 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, Donald. So I'm going to take a couple of minutes here to comment on our progress against our 2018 goals. They're all outlined on the slide that 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 second 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 market, and then we'll leave most of the details if you want to talk about it in the Q&A. So if I was to rank the top 2 issues that I think are important, the first one that we have to get right to have a good functioning capacity market here in Alberta is the concept of CONE. And CONE stands for cost of new entry. And it's the #1 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 emerging markets 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 is -- has been recognized by many of the market participants here. And I think a number would agree with us that it's critical to getting -- if we get the CONE calculation correct, 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 1,300 megawatts of [ rep ] contracts reduced 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 cost 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 was all about advancing coal to gas. Donald did talk about that in his comments. I think the only thing I would like to add there is, first 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 has -- is a very impressive group, and their work on the regulatory setting 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 coal-firing opportunity is substantial for us as we could use up to 30% of the fuel in the existing plants before we convert it. So if 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 the very top one, a 20% improvement over last year, which we've already got a pretty strong safety record. We did make it through the first quarter. And as of the end of April, we are on track towards that goal. As many of you know, those will just take 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 first quarter. Both projects are expected to reach commercial operation sometime during the second half of 2019. 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. It's 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 -- 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 financial plans.Now when I put all of the actions together in the first quarter performance with progress on the goals, 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 cash -- free cash flow goal, which is to improve over last year. Last year, we achieved $328 million 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 operation; 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 our 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 has 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 Montréal. We do have an executive search underway to find a new CFO. Luckily, our -- the CFO that we had in place before Donald 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 Donald 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, Dawn. Chris, could you please open up the call up for questions from the analysts and media?
[Operator Instructions] Your first question comes from David Galison from Canaccord Genuity.
So my first question is on the hedging. And so you talked about layering in hedging throughout the year depending on how the market evolves. Just wondering what portion of exposure are you comfortable with, are you targeting throughout the year? And maybe as you see the market evolve, how would you look at hedging post 2018?
So we need to be very flexible. And depending as -- 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 baseload is hedged for this year. What we're [indiscernible] is basically is the excess over the baseload, and we are managing the unit accordingly. For example, like in May, you will see lower generation from our plant, and we're basically almost fully hedged for the month 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 Centralia 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've 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 I'm just wondering what you're -- how you're viewing that and what it would actually take for you to make the -- to actualize 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 are 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, 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 plant, and we can actually displace some of the coal, which really reduces cost, 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.
So my question was actually on the second option, which was you taking a piece in it, so what your thoughts were around making the decision to take the investment.
Yes, I mean, well, once we get clearer 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 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?
Like I would say, like it's pretty neutral in the sense that basically like higher compliance cost but higher revenue, and one offset the other in Q1. We believe Q2 will probably be a little bit better or like in Q3 like during the summer. But I would say during Q1 is basically neutral from our perspective because like most of our carbon tax during Q1 was under like -- units that are under PPA, and it's a pass-through. If you asked the question to the PPA owner, they'd, again, have a different answer. But from our perspective, it's either pass-through and the merchant, we have been able to basically price that increase to offset the carbon tax. That would be neutral.
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 plan, 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 cost 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.
Your next question comes from the line Rob Hope from Scotiabank.
All the best in your future endeavors, Donald. 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 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 will be able to restart using it again at the end of this week, I suspect. On capital allocation, like priority is still like debt repayment, so like that's #1. And that's basically the priority of our capital allocation. The coal-to-gas conversion is important. It's like we're investing for the future of that business, so that goes back in. 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 a TransAlta Renewables resource. The pipeline, we'd have to think about that. It depends in what the returns would 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. And as Donald said, the highest returning project for sure in the portfolio is the extending the life of the coal plant on gas. As many of you -- probably everybody has 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 2035 time frame, and it's a small amount of capital for a long set of cash flow. So that's, by far, our best investment in the fleet. And definitely, it's a better investment than buying back our own shares.
Very true. All right. A -- one question. Just taking a look at the Energy Marketing, your comparable EBITDA versus Energy Marketing cash flow, which was an outflow during the quarter. Can you give us some color on the unrealized gains of $27 million 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 $25 million, $27 million that we have like in free cash flow for the Energy Marketing, I basically have like 3 buckets, and it's probably 1/3-1/3-1/3 between mark-to-market gains that will be realized in the future between losses that we incur at the end of last year that realized during the quarter and acquisition of financial [indiscernible] for the future that we enter into in Q1. So that's the way I characterize the outflow there.
Do going to that -- to answer the question of which period, I'd say it's probably 2/3 2018 and 1/3 2019 for the realization.
Like I'm not sure like when they are exactly in those position, but like it's '18 and '19.
'18 and '19, more weighted to '18.
Your next question comes from Mark Jarvi of CIBC Capital Markets.
I just wanted to go to the Canadian Coal segment. There was some commentary that by Sun 1 and 2 coming offline, that was a $12 million decline in EBITDA. But I guess $26 million year-over-year. So in your comments just a minute ago 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 as you take more units offline, where's the cost profile heading as you spread costs across lower generation?
Well, remember there's a lot of work being done at the company to reduce fixed cost so that we -- like we're not holding the same fixed cost that 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 one. And then the number two, 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 the 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 conversion. 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?
Yes. So they've -- it's not an easy thing to do to just turn a mine from 12 million tons to 6 or 7 million tons. It's like not an overnight thing. So it's going to -- it's taking -- we think it will take about 12 months to get it 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 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 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 toward the end of this year. But the free cash flow estimates that we've given you account for that scaling issue. So we 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 in this quarter. You talked about it in your prepared remarks. Where do you think that business could deliver in terms of EBITDA or free cash flow on a full year basis?
We don't normally give that guidance.
We don't give guidance, but the way I'm looking at like at U.S. Coal is basically like $30 million to $50 million. 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 on their like fuel supply. So those guys are very creative. The way that they basically set up contract was being a [ set ] and a coal supplier to make most of their -- some of their costs linked to natural gas and make the units 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 comments in the MD&A talks about potentially securing about $300 million to $400 million of debt. Is that related to coal or off-coal monetization? Or is that some project-level debt at some of the assets at RNW?
Can you repeat the question? Sorry, I missed the question.
I think the MD&A, it talks about, to cover the maturities in 2019, you're looking at raising about $300 million to $400 million of debt. I'm just wondering if that's from off-coal monetization, or is that's project-level debt on some of the RNW assets.
It's the off-coal monetization.
Your next question comes from Ben Pham of BMO.
I also wanted to wish you the best as well, Donald. 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 with 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 the rest of the year that probably reduced a lot of the variability in the remaining portions of your business on the Alberta coal side?
Yes. 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 -- first quarter 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. 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, would have been effectively guaranteed by capacity payments. So as we've looked at that and looked 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?
The expectation is that we will buy stock over the course of the year when we believe that there's value in the 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 will go to basically share buyback. So we're not changing like course on this. But clearly, like as price are like below our threshold, we'll like buy probably some share in Q2.
Yes. And I think we were pretty clearly 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 first quarter, 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.
Your next question comes from Robert Kwan of RBC Capital.
Just wanted to come back to the capacity market framework design. And Dawn, you were -- I think you touched on penalties. I don't think you touched on this, and 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. 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 am a hack economist. And even as a hack economist, I can barely understand what they'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 I think's going to be an effective market for creating a capacity price. So I would expect that as we go from CMD 2 to CMD 3, 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? 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, though, 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 would 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, we'll be mitigated. But it doesn't mean -- remember, everybody misinterprets that. And I think because we're mitigated, that's the price we get. Not true. So let's say we were mitigated at -- I would be surprised if it stayed at the 0.5 and the current RSI thing that they talk about that doesn't make any sense to me. John Kousinioris maybe understands it. 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, do you want to talk...
Yes, we haven't -- I mean, we haven't really been focusing much on that, to be honest, Robert. It isn't -- it hasn't been a major focus for us. It's been -- our focus has been primarily on the supply side, and Dawn has been articulating that. And our focus has definitely been on what the 0.5 of net CONE that people that would be offering of supply would be mitigated to, 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 pricing we've seen in other markets and 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 is definitely on the supply side.
And it's pretty small.
Yes, it is relatively small.
Got it. And maybe and just finish, you've given some thoughts on power pricing. Just wondering if I can get a little more color here. Obviously, we're in a shoulder period, so that certainly is a piece. Do you think 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 low vol and in fact putting up a bunch of zeros like this morning?
Yes. Yes. 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 it, 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 and May are like never like solid months kind of pricing. Like July, August, September will be the true test.
Yes. So the market's behaving as we would have expected.
Your next question comes from Charles Fishman of Morningstar Research.
Dawn, I only have one question. Does the disputes with Fortescue have any impact on your thinking with respect to the amount and timing of the share buyback? And 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.
Your next question comes from Mitchell Moss of Lord, Abbett.
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 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 us tomorrow afternoon and say, "Here's the capacity contract to bring that plant back for a couple of years because we need the capacity." So it really has to make it in 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 unit to a higher capacity utilization versus starting another unit. You've 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 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 setup, does that thinking change in terms of...
Yes.
Totally.
Yes, absolutely. So remember, these are mothballed under the energy-only market rule, 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 in other power markets in the United States, having a capacity market can at times reduce energy price volatility just because there's sort of a floor of excess available or available standby capacity.
That's right. 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, unit -- if you talk 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 a 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 a housekeeping item, the capital allocation slide, I didn't see it from Q4 that sort of shows $1.4 billion of bond repayment uses and a dividend of $100 million and so on in sources and uses. I didn't see that in this presentation. I'm not sure if it was discussed, because I, for some reason, my call got disconnected. But are you guys still seeing the capital allocation plans in terms of $1.2 billion of free cash flow, using $400 million 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 Donald 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 we're like advancing because like out of the $1.4 billion of bond repayment, we repaid like USD 500 million, CAD 600 million in March of this year.
Okay. Great. And so if you already used some of that, I guess, it kind of looks like you used some of the liquidity, so to speak. So is that more of a seasonal volatility because given that your liquidity has come down in terms of that capital allocation? In other words, should I expect the liquidity to come back up over the next year or 2? Or is this sort of you're kind of taking that $400 million of liquidity that's been used, and then the remaining sources, call it, $1.7 billion, those are going to be -- those are still going to be realized, I guess, over the next 1.5 years.
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 we basically -- like our next scheduled repayment is CAD 400 million in November of 2019, so now we have like roughly 18 months to rebuild our liquidity to repay that maturity. And we'll do this through like financing of some contracted cash flow and free cash flow from the business over the next like 18 months.
Our next question comes from Patrick Kenny of National Bank Financial.
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 just on the fuel mix as well without full CTG conversion. I know you talked about in the past 1/3 gas, 2/3 coal ratio is kind of a good ballpark for Sundance and Keephills. 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 one by one and built one by one. 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, Donald, back 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, 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. Capacity market is great, but there will still be some volatility, and some years will better than others. The good thing is you know that's [indiscernible] from a rating perspective, that's a positive because it gave 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% [indiscernible] 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've repaid the $400 million due in 2019 and the $400 million due in 20120.
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 resource debt that will be left that sits in that kind of $1.1 billion, $1.2 billion 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 overlever merchant assets. They'll lever than up to 60%, 70%. We are underlevering 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 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.
[Operator Instructions] Your next question comes from Jeremy Rosenfield of Industrial Alliance.
Just two questions. First, on the transition into capacity market and some of the changes in CMD 2 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 where 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 is 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 Brazeau 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 Brazeau. So that is the best, lowest-cost way to bring storage into the province. And it would be our first -- it's our -- it's our main focus. And we've 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 -- even if you get 2 hours a day at a differential of $10 or even $20, you're talking about $40 a day, for millions of dollars’ worth of investment, you're talking about like 20-year paybacks. We're not interested in that. Our current hydro is great storage and then seeing if we can get Brazeau is more important.
Okay. So just looking at Brazeau, since you brought it up. Where is the project in terms of development? I think in the MD&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 isn't exact. We're working here with the province and the ISO and really waiting to see of 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 1,300 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 your skis 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. Just turning to the new wind investments, do the assets right now -- 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 RNW, and we're just funding it through there until we decide how to more permanently finance it.
I meant the construction, the assets that's under construction, if it had debt already that you're acquiring as part of the transaction.
No, no, no.
[indiscernible] in development.
Okay. 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 RNW be the owner of 100% of the cash equity?
The -- RNW will hold like an economic interest in the two projects, similar to what we did in the past, yes.
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.
This concludes today's conference call. You may now disconnect.