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 speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. 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 line 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 two, 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. 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. After that, Donald will take you through the financials, and I'll just come back at the end and give you a few brief comments on our progress against our 2018 goals. As you can see in our highlights, we reduced our net debt by close to CAD 300 million, 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 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 A PPAs 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. 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, that's not really a surprise. That team has done some excellent work. They're highly competitive, they've been working hard to get a strong coal transportation agreement in place that adds value.
That, along with the work they've done on their cost structure, 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. Excellent work by that team. 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. 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. 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, they've made a number of changes to a number of processes, and the way they do things. They're not finished all that work yet, we are optimistic that their work is laying the foundation for a new level of performance expectation for that fleet. The Canadian 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 cost.
We were disappointed that a dispute has emerged between the MSA and the ISO over the mothballing rules and what we're calling the stub period of the energy-only market, which is really just a small period now before the capacity market comes into play in 2021. 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. 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. 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. We are expecting strengthening in prices due to that growth. 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. We also have strong water resources in our hydro assets. 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. 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 first quarter, we are in the last phase of our investment part of the program. That cost us approximately CAD 11 million in the quarter. Those costs are finished as we go forward. As we go into the rest of the year, the investment costs are behind us. 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 CAD 50 million to CAD 70 million in cash savings from the program as we go forward. In my view, the quarter has us out of the gate well. 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.
With that, Donald is going to take the time now to give you more detail on the financial results.
Thank you, Dawn. Welcome to everyone on the call. As Dawn noted at the beginning of our discussion, our EBITDA, funds from operation, and free cash flow for the quarter were similar to last year after adjusting for the early termination payment of the Sundance D and C PPA in 2018 and the settlement for the indexation dispute with U of C in 2017. As you can see from slide five, the EBITDA of CAD 259 million was CAD 19 million higher than last year, an increase of 8%. Free cash flow increased CAD 2 million to CAD 81 million. Funds from operation totaled CAD 161 million, a slight reduction to last year.
As you can see from the chart on the bottom left of slide six, segmented cash flow from our power generating assets, which exclude energy marketing and corporate segments, totaled CAD 241 million during the first quarter, an increase of CAD 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 Edmonton, and lower capital expenditures. The impact of stronger prices 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 CAD 22 million in sustaining CapEx relative 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 CAD 195 million-CAD 205 million in sustaining capital during the year. Energy marketing gross margin and EBITDA during the first quarter were much higher than last year and totaled CAD 17 million and CAD 9 million respectively, compared to CAD 1 million and a loss of CAD 4 million last year. Some of these gains in the first quarter will be realized in future quarters 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 seven, we have CAD 1.1 billion of available credit on our credit facility, a reduction of approximately CAD 300 million since year-end, as we drew on our credit facility to repay a portion of the $500 million U.S. loan. In addition to our available credit, we had CAD 329 million of cash on hand at the end of the quarter, which includes CAD 157 million received from the Balancing Pool on March 29th, for the total liquidity of CAD 1.4 billion. Turning to slide eight, our adjusted FFO to net debt has shown consistent improvement over the past two years and is within our 20%-25% target range at 20.9%. Our net debt at the end of the quarter totaled CAD 3.1 billion, a reduction of approximately CAD 300 million during the quarter.
Using the proceeds from the early termination of the PPA in Alberta, 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%-30% range in 2021. We expect to maintain our current debt level over the course of the year, even with more than CAD 200 million of capital allocated to coal to gas conversion and the construction of our Tuwin project in the U.S. Our capital allocation plan for the next three years 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 CAD 1.2 billion of free cash flow over the next three years, including the CAD 157 million received this quarter and a further CAD 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 CAD 80 million 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. We have increased the lower end of our free cash flow also for 2018 from CAD 275 million to CAD 300 million.
Further, as discussed on our year-end earning 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 outstanding when we believe our share are undervalued. During the quarter, we acquire and cancel almost 374,000 share at the price below CAD 7 per share under our NCIB for a total amount of CAD 3 million. Our capital allocation plan for TransAlta over the next few year is prudent, we are still evaluating whether to invest in the gas pipeline being developed by Tidewater to supply our coal facility with natural gas. 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 31st, we have more exposure to merchant power price.
This differ from our previous highly contracted position in the province, it impacts the way we manage these units. In December, we announced our decision to mothball two of the four units at Sundance, as it was uneconomic to run multiple units at lower capacity factor. The other two 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 on page nine, the expectation for pricing for the next three year is in the range of CAD 50 to CAD 65 per megawatt hour, which is the strongest pricing we've seen in Alberta since 2014. As price has moved up during the quarter, we enter into some fixed-price contracts to reduce our exposure and lock in margin.
As we progress through the year and see where power price land, 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. 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 you see on slide 10. 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. 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. When we look at the specific changes proposed in draft two, 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. There's always a number of areas that need agreement before we'll be really confident that the market will attract capital.
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. I want to talk about what we see are the two 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. If I was to rank the top two 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. CONE stands for Cost of New Entry. 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.
In Alberta, we know that the new entrant will be a simple cycle gas-fired peaker. 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 return if investors are going to show up to the market.
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, that if we get the CONE calculation correct, it will create a more vibrant capacity market. 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. For example, if the existing 1,300 MW of REP contracts reduce capacity and energy pricing, it will absolutely create an unlevel playing field. 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.
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. 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 on some days has given us a lot of confidence that converting our plants to gas is really the way to go. We're seeing some impressive optimization value coming out of that. The Tidewater team 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 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. If they can just get the gas there, we can absolutely start to use it.
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 first quarter, 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 relentless work and will take a lot of attention from our teams. I did speak about Greenlight earlier, I am just going to take a minute to update you on the two 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, that's one of our primary goals this year. The larger of the two projects is a 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 pads. The second project is the smaller of the two, 29 megawatts, it's in New Hampshire. It has two 20-year PPAs, which are both strong. We are waiting for the results of the environmental permitting approval appeal, once that comes in, if it's positive, 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.
Of course, value for our shareholders as we own 64% of that vehicle, we have a large dividend coming from TransAlta Renewables that supports our financing plan. When I put all of the actions together in the first quarter performance with progress on the goals, 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 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 CAD 328 million of free cash flow right in the middle of our range.
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 a diverse fleet, our success in reducing cash costs and increasing performance as we execute new practices throughout our operations, finally, our ability to optimize around the volatility in the Alberta market with our uncontracted merchant coal and our hydro assets. Our assessment so far is that our free cash flow goal is becoming achievable. 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 have been pivotal to our financial strength. His leadership has been key in repositioning and reducing our debt. We're all going to miss his energy, optimism, and sense of humor. 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 a new CFO. Luckily, the CFO that we had in place before Donald joined us, Bret Gellner , is still here, he's agreed to act as CFO in the interim. 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.
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 the call up for questions from the analysts and media?
Certainly. As a reminder, if you would like to ask a question, press star followed by the number one on your telephone keypad. Again, that's star followed by the number one on your telephone keypad. Your first question comes from David Galison from Canaccord Genuity. Please go ahead.
Good morning, everyone. My first question is on the hedging. You've talked about layering in hedging throughout the year, depending on how the market evolves. I'm just wondering what portion of exposure are you comfortable with or are you targeting throughout the year? Maybe as you see the market evolve, how would you look at hedging post 2018?
Go ahead.
We need to be very flexible and depending. We have generation, that generation has a certain variable cost, and depending on what is the price forward, that's what we're basically looking to hedge. Currently, I would say, a significant portion of our base load is hedged for this year. What we're trying to optimize now is basically, it's the excess over the base load, 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. During the summer, we probably price will be higher, we probably have a bit more length. That's the way we look at it. It's very similar to what we're doing in Centralia, in term of dynamic hedging and basically managing what we call a delta position.
Yeah. We do have the authority to hedge into 2019. If we see prices in 2019 that we think are good to take off the table, we can do that. When we get there in real time, we may or may not have to run the plant. We really are treating it more as a dynamic hedging strategy rather than what you would have seen in the past.
Okay. My second question is just on the Tidewater pipeline. You had mentioned that you're looking at making that investment or potentially an investment. Just wondering how you're viewing that and what it would actually take for you to exercise the option and make the investment in the pipeline.
The way Tidewater is set up today is, 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. 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. It's kind of two.
First of all, the pipeline is on its way to going ahead, and as long as everything goes well with them and they get their regulatory approvals, it will be built. The second decision is whether or not we want to own a piece of it. 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 they have to go through the regulatory process. 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.
My question was actually on the second option, which was you taking a piece in it. What your thoughts were around making the decision to take the investment?
Yeah. Well, 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 do that.
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?
I would say it's pretty neutral in a sense that basically higher compliance cost, but higher revenue and one offsets the other in Q1. We believe Q2 will probably a little bit better or at least Q3, during the summer. I would say during Q1, it's basically neutral from our perspective, because most of our carbon tax during Q1 was under PPA, and it's a pass-through. If you ask the question to the PPA owner, they're going to have a different answer. From our perspective, if you're a pass-through and the merchant, we have been able to basically price that increase to offset the carbon tax. I would say neutral.
Just remember, you have to look at it. You almost have to think about the carbon tax as being in two 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. 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 units. We're in control of how much we pay there depending on what prices look like.
Thank you very much.
Your next question comes from the line of Robert 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? 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 at the end of this week, I suspect. On capital allocation, priority still like debt repayment. That's number one, and that's basically the priority of our capital allocation . The coal to gas conversion is important. We're investing for the future of that business, so that goes second, and the excess cash is basically share buyback. That's what we said in January, when we announced that program, and that's the direction we're taking.
Yeah. Just remember the U.S. Northeast wind farms are going to be funded and financed out of TransAlta Renewables, not out of TransAlta. 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 on what the returns would be. As you know, we've been very clear that we think the returns on buying back TransAlta shares are very high. 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 Donald said, the highest returning project for sure in the portfolio is extending the life of the coal plants on gas.
Probably everybody's forgotten, but those coal plants were slated to start shutting off by 2025, in any event. 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 timeframe. It's a small amount of capital for a long set of cash flows. 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 CAD 27 million that are sitting on your book right now, when those could be realized? Then secondly, how much realized losses was in comparable EBITDA in Q1?
What I would say, when I'm looking at the CAD 25 million, CAD 27 million that we have in free cash flow for energy marketing, I basically have three buckets. 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. Acquisition of financial instruments for the future that we enter into in Q1. 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 two-thirds 2018 and a third 2019 for the realization.
Yeah. I'm not sure where they are.
Yeah
between those positions, it's 2018 and 2019.
It's 2018 and 2019. More weighted to 2018.
Thank you. I'll jump back in the queue.
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 Sundance 1 and 2 coming offline as a CAD 12 million decline in EBITDA, I think it's CAD 26 million year-over-year. In your comment just a minute ago, saying that you're kind of neutral on the carbon taxes. Where is it in the cost profile that you're seeing that drop on EBITDA? 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. We're not holding the same fixed costs as we had with six units and then trying to pay for them with two units. We've had a massive amount of readjustment of that business to get it down to two units that can kind of stand on their own. That's number 1. Number 2, the same with the mine. The mine is being resized as we speak to a much lower volume of coal. Of course, as we get a pipeline in there, that's even a lower amount of coal. It's making sure that we have that sort of dual-fuel flexibility until we actually do the conversion.
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 flows last year or slightly better, which is our goal.
Maybe you can comment in terms of the timing on the resizing of the mine versus fixed operating costs and how those compare in size and when those will be realized in terms of the cost savings initiatives.
Yeah. It's not an easy thing to do to just turn a mine from 12 million tons to six or seven million tons. It's not an overnight thing. We think it'll take about 12 months to get to the exact size that we need it to be with the right cost. They're scaling it down as we go through the year. 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. We think by the middle of next year, we'll have that appropriately sized.
If the guys can go faster, you'll see that in our results sooner as we go toward the end of this year.
Okay, good.
Our free cash flow estimates that we've given you account for that scaling issue. We've built in the cost As we go forward here.
Right. Okay. 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 or free cash flow for on a full year basis?
We don't normally give that guidance.
We don't give guidance, the way I'm looking at U.S. Coal is basically like CAD 30 million-CAD 50 million. If you look at historically what it performed, it should continue to perform and improving over time because of the significant improvement they're doing on their fuel supply. Those are very creative.
Yeah.
The way that they basically set up contracts with BNSF and the coal supplier to make some of their costs linked to natural gas and make the unit more flexible and running a bit more often. Creating a bit of more margin.
Okay. Then my last question in the comments, in the MD&A talks about TransAlta carrying about CAD 300 million-CAD 400 million of debt. Is that related to coal or Offtake monetization, or is that some project-level debt at some of the assets at RNW?
Could you repeat the question? Sorry, I missed the question.
I think in the MD&A talks about to cover the maturities in 2019, you're looking at raising about CAD 300 million-CAD 400 million of debt. I'm just wondering if that's from Offtake monetization or is that project-level debt on some of the RNW assets?
It's the Offtake monetization.
Okay, thanks. All the best as you transition there, Donald.
Thank you.
Your next question comes from Benjamin Pham of BMO. Your line is open.
Okay, thanks. Good morning. 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 of a positive tone. I may have missed this in your earlier remarks, but was there some layering of hedges that you were putting on for the rest of the year that probably reduce a lot of the variability in the remaining portions of your business on the Alberta coal side?
Yeah.
Yeah.
I would say, Ben, that just in terms of how we've looked at the year and how it's going to play out. 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. As well, as we look at, remember, we're kind of gaining experience with optimizing our assets as we go through April here. Turning plants on and off and getting them into the market and looking at our ancillary services and hydro and all that sort of stuff. 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.
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 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. On Rob's question about the buying back stock with the blackout commentary. 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.
Yeah.
That's not the first priority with our capital. The first thing is we are focusing on our debt. We're focusing on our growth. We need to allocate capital to our conversions. Residual capital goes to basically share buyback. We're not changing course on this. Clearly, as price are below our threshold, we'll acquire probably some share in Q2.
Yeah, 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 guide, at the higher end, then we can allocate a little more capital to that.
Okay.
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? 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 for everything.
Thanks, Ben.
Your next question comes from Robert Kwan of RBC Capital. Your line is open.
Morning. Just wanted to come back to the proposed capacity market framework design. Don, I think you touched on penalties. I don't think you touched on this. I apologize if you did. 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 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. As you know, I'm a hack economist, and even as a hack economist, I can barely understand what they're talking about. 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. I would expect that as we go from CMD2 to CMD3, there'll be a lot of discussions about what that looks like. I think if you mitigate everybody, what are we doing here?
Right.
It's not really a market, right? 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'll end up in a spot where you won't be mitigated?
No. I think TransAlta will definitely be mitigated because of 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?
Right.
It won't be us that'll set the price, it'll be the other 70% or 75% of the market that will set the price. 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. I think definitely we'll 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.
Right.
Let's say we were mitigated at, I would be surprised if it stayed at the 0.5 and this current RSI thing that they talk about that doesn't make any sense to me. John Kousinioris, in the north, maybe understands it. He's sitting here. I think when they get those calculations correct, at the end of the day, they really need 70%-80% of the market to be setting price. Of course, we get that price, whatever that turns out to be as it crosses the supply and demand.
For sure. 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?
Yeah. We haven't really been focusing much on that, to be honest, Robert. It hasn't been a major focus for us. Our focus has been primarily on the supply side, Dawn's been articulating that. Our focus has definitely been on the 0.5 of net CONE that people that would be offering supply would be mitigated to be honest.
Are you thinking about buyers bidding capacity into the market as solid capacity, that kind of thing?
No, just where you've got a net buyer power who might have some incentive-
Yeah
to do something else with the capacity price. We've seen in other markets an introduction of buyer-side mitigation to prevent that activity.
Yeah.
Okay.
Our sense of it 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.
It's pretty small.
Yeah, it is relatively small.
Got it. 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 low fall and in fact putting up a bunch of zeros like this morning?
Yeah. Honestly, in the shoulder period, you're going to get low prices and volatility in the negative direction, right? I would expect as we go into the summer, there's no question with that the Alberta market should have more volatility in its period going forward. It's just the way that the market works. 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. 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. I haven't been surprised at all.
Okay.
April and May are never solid months in terms of pricing. July, August, September will be the true test.
Yeah.
Perfect. Thank you. Then, Donald-
The market's behaving as we would expect. Yeah.
Okay. Donald, best wishes with the move back home.
Thank you.
Your next question comes from Charles Fishman of Morningstar Research. Your line is open.
Thank you. 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? Do you need to have those resolved before you go in heavier amounts of buyback?
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 Ward Abbott. Your line is open.
Just a couple 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? 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. No one will pay you. The ISO's not going to phone us tomorrow afternoon and say, "Here's a capacity contract to bring that plant back for a couple of years because we need the capacity. It really has to make it on the energy sales. 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. Right now, we actually make our money by dispatching up the units to a higher capacity utilization versus starting another unit.
You have 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. Our whole strategy is fill those units up first, 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." It's a combination of price and volume. Right now, we aren't seeing the need for these two units, and they're not running at 85% capacity utilization.
Okay. I guess with a capacity market set up, does that thinking change in terms of-
Yeah.
Totally.
Yeah, absolutely. Remember, these are mothballed under the energy-only market rules, which that's what we set them up under. They're absolutely being set up to be competitive capacity supply into the capacity market. Those bids, I think, will go in sometime in 2020. All of these units will be bid in to the capacity market. That makes a huge difference.
Okay. Just following up on the last set of questions. When you talk about volatility, how are you guys thinking about volatility in the Alberta market, I guess currently versus post-capacity? Because looking in other power markets in the U.S., having a capacity market can, at times, reduce energy price volatility just because there's sort of a floor of excess available standby capacity.
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? 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. On average, you make a variable cost or a slight margin to that depending on which unit you've got in the energy market. For our units, for example, you talked about Sundance unit 2, that's a great capacity resource.
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 MW of wind into the province, because all that wind has to be backed up. 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. The way we make our money is how we get it out of the capacity market. We don't mind that there isn't that volatility.
Okay. Just a housekeeping item. The capital allocation slide, I didn't see it from Q4 that sort of shows CAD 1.4 billion of bond repayment uses and dividend of CAD 100 million and so on, and sources and uses. I didn't see that in this presentation. I'm not sure if it was discussed because for some reason my call got disconnected. Are you guys still seeing the capital allocation plans in terms of CAD 1.2 billion of free cash flow, using CAD 400 million of liquidity and so forth, kind of matching that allocation plan that you put out a couple months ago?
Yeah. The slide is exactly the same as a couple of months ago, Donald did make comments about that and said exactly that. It's exactly where we were.
There's no change to our capital allocation.
Okay. Yeah.
No change at all. In fact, we're advancing because out of the CAD 1.4 of bond repayment, we've repaid USD 500 million, CAD 600 million in March of this year.
Okay. Okay, great. So you already used some of that. I guess it kind of looks like you've used some of the liquidity, so to speak. Is that more of a seasonal volatility because given that your liquidity's 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 two? Or is this sort of you've kind of taken that CAD 400 million of liquidity that's been used and then the remaining sources, call it CAD 1.7 billion, those are still going to be realized, I guess, over the next year and a half?
What you will see us doing over the course of the year, we will do some financing activity that will replenish our liquidity.
Okay.
Basically, our next scheduled repayment is CAD 400 million in November of 2019. Now we have roughly 18 months to rebuild our liquidity should we pay that maturity. We'll do this through financing of some contracted cash flow and free cash flow from the business over the next 18 months.
Okay, great. Thanks so much. Good luck to you.
Thank you.
Your next question comes from Patrick Kenny of National Bank Financial. Your line is open.
Yeah, 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?
Yeah, 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. The team is working on a second pipeline. There's two potential opportunities there. Well, actually three, because you could do another one with Tidewater. Then there's the adding compression to Tidewater. All of that is in discussion and underway right now.
Okay, then just on the fuel mix as well, without full CTG conversion. I know you've talked about in the past one-third gas, two-thirds coal ratio as kind of a good ballpark for Sundance and Keephills, but recently we've seen some higher ratios at some other coal plants. 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.
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. For sure, if there's ways to increase the capability. Remember, these plants are all designed individually one by one and built one by one, so they do have different set points for that. The engineers will, if there's 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. Lastly, all the best in health 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.
I think we're sticking with our plan. We really want to be in 2021 at 25%-30% and at the upper end of that range. Capacity market is great, there will still be some volatility, and some years will be better than others. The good thing is you know that three years in advance. From a rating perspective, that's a positive because it gives you time to, or to basically set your balancing in accordance. We are sticking with our plan at 25%-30% effort to that. The good thing, however, is most of the corporate obligation of TransAlta will have been repaid, and the balance sheet will be very strong in 2020 after we repay the CAD 400 million due in 2019 and the CAD 400 due in 2020.
I would just add, 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 CAD 1.1 billion, CAD 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 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.
I think the balance sheet for those assets will be very strong and will carry the company through the 2020s very well.
All right. That's perfect. Thank you very much.
Again, if you would like to ask a question, press star, then the number one on your telephone keypad. Your next question comes from Jeremy Rosenfield of Industrial Alliance. Your line is open.
Yeah, 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. 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? That really works well with our wind assets. 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, flow batteries, all that stuff. Still quite a ways off. If you want to subsidize storage in a massive way to bring it into the system, you can do that. If you want economic storage, it's still projects like Brazeau. That is the best, lowest cost way to bring storage into the province, and it would be our first. It's our main focus.
We've tried a million different ways to think about how to put a solid-state battery in. If you look at the economics of those, even if you get two hours a day at a differential of CAD 10 or even CAD 20, you're talking about CAD 40 a day for millions of CAD worth of investments. You're talking about 20-year payback. We're not interested in that. Our current hydro is great storage, and then seeing if we can get Brazeau is more important.
Okay. 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 your development, and it looks like maybe some of the sizing or the cost numbers have moved around. What is the latest update, maybe?
Yeah. We're working here with the province and the ISO and 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 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. 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. We'll have to wait and see.
Okay.
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 four or five years to get it's not very economic. We're just really sizing our spending to the regulatory environment.
Okay. No, I always want to stay on the middle of my skis. Just turning to the new wind investments. There's one that's under construction. Does that carry construction debt already? I assume the other one, which is not under construction, doesn't have any debt?
No, right now 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 asset that's under construction, if it had debt already that you were acquiring as part of the transaction.
No.
No.
Okay, perfect.
They were in development.
Okay, perfect. In terms of financing options, do you assume a tax equity component for the permanent financing?
That's our plan.
Okay. Would RNW be the owner of 100% of the cash equity?
The RNW will own an economic interest in the two projects.
Right
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.
This concludes today's conference call. You may now disconnect.