TransAlta Corporation (TAC) Q1 2021 Earnings Report, Transcript and Summary

Good morning. My name is Rebecca and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation’s First Quarter 2021 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] Thank you. Ms. Valentini, you may begin your conference.

Great. Thank you, Rebecca. Good morning, everyone, and welcome to TransAlta’s first quarter 2021 conference call. With us today are John Kousinioris, President and Chief Executive Officer; Todd Stack, EVP, Finance and Chief Financial Officer; and Kerry O’Reilly Wilks, EVP Legal, Commercial and External Affairs. Today’s call is webcast, and I invite those listening on the phone line to view the supporting slides that we have posted on our website. A replay of the call will be available later today and the transcript will be posted to our website shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualifications set out here on slide 2. Further details 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 comparable EBITDA, funds from operations and free cash flow are also reconciled in the MD&A for your reference. On today’s call, John and Todd will provide an overview of the quarter’s results, along with expectations for the balance sheet 2021. After these remarks, we will open the call for questions. And with that let me turn it over to John.

Good morning, everyone, and thank you for joining us on our first quarter call in 2021. As part of our commitment towards reconciliation, I want to begin by acknowledging that TransAlta’s head office, where I am today, is located in the traditional territories of the Niitsitapi and the people of the Treaty 7 region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut’ina and the Stoney-Nakoda First Nations, as well as the home of the Métis Nation Region 3. We had an exceptional first quarter. I’m very pleased with the performance of our team and the headway that we’re making in advancing our priorities. Our portfolio delivered a 41% increase in comparable EBITDA, which resulted in a 23% increase in free cash flow per share, compared to the first quarter of 2020. Our performance was led by the exceptional results of our Alberta Hydro fleet with strong contributions from our Energy Marketing segment, which had an excellent start to the year with favorable trading results across North America and our wind fleet. We experienced the strong power market in Alberta during quarter as all generation was fully dispatched on a commercial basis, given the transition to a fully merchant market, which happened on January 1st of this year. This benefited our hydro fleet, in particular from an energy and ancillary services perspective. And later on in our presentation, Todd will highlight the value of our diversified fleet in the Alberta market. We continue to make progress on our growth targets for 2021. Last week, we were pleased to announce the launch of our Garden Plain wind project, and we’re very excited to have Pembina Pipeline as a cornerstone customer to support its commercialization. During the quarter, we also made progress on a number of our key priorities. We advanced construction of our 207 megawatt Windrise facility in Alberta, despite the ongoing challenges posed by COVID-19. We’re about 84% complete as of March 31st and expect to achieve COD in the fall. We are now midway to successfully completing our coal-to-gas conversion initiative. The Sundance 6 and Sheerness conversions were completed earlier this year, and our Keephills 2 conversion is currently underway. The Keephills 3 conversion is set to be completed in the fall. And with the closure of the Highvale Mine, effective December 31, all of our Alberta Thermal facilities will be off-coal and generating solely on lower carbon natural gas. We have largely completed the planning and detailed engineering design for the Sundance 5 repowering project. The plant’s detailed design has increased steam production, resulting in slightly higher overall output, which we now expect to approach 750 megawatts. In addition, a decision was made to upgrade the high pressure steam turbine as part of the repairing scope to allow for maximum operating flexibility in the unit going forward. Project costs have increased to account for changes in final design, which has resulted in a new estimated capital cost range for the project of between $900 million and $950 million. We’re also actively evaluating carbon capture and storage solutions for eventual adoption by the unit. We continue to maintain liquidity in excess of $2 billion in support of our coal-to-gas conversion initiative, Sundance 5 repowering and our 2.5 gigawatt growth pipeline, and we are well positioned to fund our current plans with existing balance sheet capacity. We renewed and extended our credit facilities at both TransAlta and TransAlta Renewables during the quarter, and are pleased to announce that we have extended and converted our syndicated credit facility into a Sustainability Linked Loan. This loan aligns our cost of borrowing to our greenhouse gas emissions reductions and gender diversity targets. This further underscores our Company’s commitment to our ESG goals. Finally, we announced that we won’t be proceeding with the Kaybob cogeneration facility with Energy Transfer Canada and that we’ve commenced an arbitration proceeding against them for wrongful termination of the agreement. As I look at our strategic priorities for 2021, our goal is to be the supplier of choice for customers that are focused on sustainable growth and decarbonization. We remain focused on advancing our three core operating pillars, TransAlta Renewables, Alberta Hydro and our Thermal Generation group, and the last two of those groups underpin our Alberta business. These operating pillars are supported by our world-class Energy Marketing team as well as our experienced Corporate teams. As I noted earlier, we’re commencing the Garden Plain project and are extremely excited to have a great Alberta-based company, like Pembina as a new customer to make it a reality. Working with customers like Pembina to create low-cost, reliable energy solutions in support of their sustainability goals is a cornerstone of our strategy. The project will have 130 megawatts of capacity and is backed by an 18-year agreement for 100 megawatts of the capacity, along with the associated environmental attributes. We expect the project to deliver approximately $17 million in comparable EBITDA in 2023. We’re scheduled to commence construction this year and expect the wind facility to be in commercial operation during the latter part of 2022. This project will be TransAlta’s 11th wind farm in Alberta and will increase our North American wind fleet to over 2 gigawatts of capacity. We remain customer-centered on growth with our unique offerings and breadth of our portfolio to deliver clean power solutions to our customers. A key element of this goal is expanding our renewables business with the objective of advancing two new wind projects this year, one in Alberta and the other one out of our U.S. wind development portfolio. And we’re well on our way to delivering on this goal with our Garden Plain wind project. We currently have an additional 500 megawatts of advanced stage wind project in our growth pipeline, which have the potential to be commercial in the 2023 to 2024 timeframe and are actively marketing these opportunities to various customers within Canada and the United States. We also have over two gigawatts of earlier stage opportunities in various geographies and with various technologies. Our development team is being kept busy in Canada, Australia and the United States. We’re working to create customized power solutions to meet our customers’ ESG objectives in a cost-effective manner. I’ll now turn it over to Todd to take us through our financial results for the quarter.

Thanks, John. Looking at our financial performance on slide 8, we had an excellent quarter and our diversified fleet delivered outstanding results at $310 million of comparable EBITDA, a 41% increase over 2020. Higher comparable EBITDA was driven by strong results in our Alberta business as well as from our Energy Marketing business. Strong EBITDA results from the business were partially offset by higher distributions to our partners, higher sustaining capital and the cash payments to settle prior period provisions. Free cash flow of $129 million or $0.48 per share was about 20% higher compared to 2020. With the expiry of the PPAs, both our Hydro and Alberta Thermal segments benefited from the strong pricing in the Alberta market. Cash flow from our hydro fleet significantly outperformed last year, delivering a threefold increase from $23 million last year to $72 million this quarter. The Alberta Hydro business was able to fully benefit from the strong pricing levels in the market due to the elimination of the PPA obligation payments that were previously paid to the Alberta Balancing Pool. Results from the Wind and Solar segment were in line with expectations. Overall, cash flow was down modestly compared to the same period in 2020 as a result of the payment of line loss provisions in the quarter. The provision payments were partially offset by higher realized pricing in Alberta and the addition of the Skookumchuck facility. Results from the North American and Australian Gas segments increased by about -- by $8 million or about 14%, primarily due to the addition of the Ada facility and higher realized pricing in Alberta at the Fort Saskatchewan facility. Centralia experienced an isolated eight-day unplanned outage during periods of high-merchant pricing in the quarter, resulting in lower cash flow compared to last year. Our Energy Marketing segment once again delivered exceptional performance, with $45 million of cash flow in the first quarter by capitalizing unfavorable short-term trading of both physical and financial energy products. Corporate costs decreased primarily as a result of the receipt of the Canadian Emergency Wage Subsidy and realized gains from the total return swap relating to the performance of our shares in the first quarter. CEWS funding will be used to create incremental employment in the organization throughout this year and into 2022. Overall, TransAlta delivered an outstanding first quarter, and I’m going to spend a few minutes on the next two slides to discuss two of our core businesses, firstly, TransAlta Renewables; and secondly, our Alberta business. As many of you are aware, our operating wind and solar assets as well as the majority of our contracted gas assets are held within TransAlta Renewables. This highly contracted component of our business is targeted to generate approximately $500 million of EBITDA for the full year 2021. I want to remind everyone that the quarterly results discussed on this slide are fully consolidated at the TransAlta Corporation level. Quarter-over-quarter, R&W’s comparable EBITDA was up 4%, primarily due to the timing and recognition of environmental credits, lower overhead costs and the strengthening of the Australian dollar. These benefits were partially offset by lower wind resources, which resulted in lower production. Overall, AFFO and CAFD per share were in line with last year. During the quarter, we completed the drop-down of the Windrise facility. And on April 1st, we completed the transfer of the economic interest in the Skookumchuck wind and the Ada cogen facilities. R&W will fund the remaining capital cost for Windrise, and all 3 investments will contribute to EBITDA at the R&W level in 2021. The recently announced Garden Plain project is underpinned by a long-term PPA with a strong counterparty, which makes it an excellent drop-down candidate for TransAlta renewables in the near future. Overall, we continue to maintain our CAFD forecast for TransAlta Renewables to be within the currently stated guidance range of $285 million to $315 million or approximately $1.13 per share. Turning now to the Alberta business. At the end of 2020, the power purchase arrangements for most of our Alberta Hydro facilities as well as Keephills Units 1 and 2 expired. And effective January 1st, these facilities began operating on a fully merchant basis. These facilities, in addition to our other thermal assets are dispatched as a portfolio to benefit from baseload and peaking energy sales in the Alberta energy-only electricity market. In addition to energy sales, both the Thermal fleet and the Hydro fleet are able to provide ancillary services to the grid operator. During the quarter, our total Alberta portfolio generated roughly 2,700 gigawatt hours of production and $284 million in revenue. Power prices in Alberta and in other western regions were significantly impacted by cold weather in Q1. In particular, the month of February experienced extreme cold, with power prices in the month averaging $152. Strong pricing in February contributed to the average pool price for Q1 settling at $95 per megawatt hour. In the quarter, the Alberta Thermal fleet generated 2,100 gigawatt hours, with an average realized price of $87. Our realized price was slightly lower than the average settled pool price due to the impact of our hedging program. In the quarter, we had hedged approximately 1,600 gigawatt hours of baseload capacity at an average price of $64 per megawatt hour. The combination of our hedge revenues and our peaking sales resulted in revenues at Alberta Thermal being roughly in line with 2020, but with lower volumes of production. Turning to Hydro. Due to the dynamic and peaking nature of our hydro facilities, we did not directly hedge volumes from these facilities in the quarter. The ability of Hydro to capture peak pricing was demonstrated with average realized prices of $122 per megawatt hour, which represents a 28% premium over the average spot price. This premium is similar to the premiums realized in the winter months of 2019 and 2020. Energy and ancillary volumes were broadly in line with expectations, but gross revenues benefited from strong realized pricing and exceeded our expectations for the quarter. For the balance of the year, we expect Alberta spot prices to settle at the higher end of our guidance range at around the $65 to $70 per megawatt hour. Balance of the year, we’re hedged on average about 400 megawatts, but we expect to add to these hedges through the course of the year. I’ll close off my discussion by highlighting the current financial strength of the Company. Due to our strong cash flow performance in the first quarter, combined with the anticipated strength in Alberta power prices for the balance of the year, we expect our annual results for EBITDA and free cash flow to be towards the upper end of our guidance range. Our balance sheet and liquidity remain very strong. We closed the quarter with $2.1 billion in liquidity, including $650 million of cash. This positions us extremely well to fund our gas conversions and deliver on our renewable growth plan. Our senior corporate debt level has been reduced to $1.1 billion, which is below our targeted level and leaves us in a very strong financial position as we continue through 2021. With that, I’ll turn it back over to John.

Thanks, Todd. As I look toward our priorities for the balance of 2021, we set a number of goals, including achieving our best ever safety results in what will be a heavy turnaround year for our Company; strong availability throughout the fleet; exceptional ESG progress and results; the completion of Windrise and the start of construction for Garden Plain; additional growth in the form of a new wind facility from our U.S. growth portfolio, along with a growth project in Australia; completion of our coal-to-gas conversions; advancing our Sundance 5 repowering project; recontracting our Sarnia cogeneration facility, which we’re off to a good start on with the recontracting we secured with one of our large industrial customers there; and delivering 2021 EBITDA and free cash flow at the upper end of our guidance. To close off our presentation, I want to highlight what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are resilient and are supported by a high-quality and highly diversified portfolio. Our business is driven by our contracted wind portfolio, our unique, reliable and perpetual hydro portfolio, and our efficient thermal portfolio, all of which are complemented by our world-class energy marketing capabilities. Second, we are a clean power leader with a focus on tangible greenhouse gas emission reductions. Our decarbonization journey has resulted in greenhouse gas reductions that represent close to 10% of Canada’s 2030 reduction target. In addition, our focus on removing systemic barriers through our commitments to equity, diversity and inclusion and good governance place us well ahead as a leader in ESG. Third, we have a strong and diversified set of growth opportunities, which includes a pipeline of advanced stage projects and a talented development team focused on realizing its value. And finally, our company has a strong financial foundation. Our balance sheet is in great shape and has ample liquidity to pursue growth. We believe the Company is at an exciting time in its development, and we are well-positioned for the future as a leader in low cost, reliable and clean electricity production. Finally, I’d like to also take a moment to say thank you to all of our employees and contractors for their resilience in the face of COVID-19. They continue to work hard every day, adding value to our Company by doing what our communities need most, delivering low cost, reliable clean power. They have been and continue to be terrific. In light of the impact of the COVID-19 pandemic and restrictions on gatherings here in Alberta, we’ve made the decision to postpone our 2021 Investor Day until the early fall of this year. At that time, we will explore with you our strategic plans for 2021 and beyond. And with that, I’ll turn the call back over to Chiara.

Thanks, John. Rebecca, would you kindly please open up the call for questions from analysts…?

[Operator Instructions] And your first question comes from Julien Dumoulin-Smith with Bank of America.

Hey. Good morning. This is Dariusz Lozny on for Julien. Thank you for taking my question. I just wanted to quickly discuss the new wind project, Garden Plain, briefly. It seems like you’ve had pretty good success contracting the first bit of it. I was wondering if you can discuss plans for contracting the remaining 30 megawatts. How that fits into potential plans to drop it into TransAlta Renewables? And also, if you can comment on the $17 million EBITDA estimate, does that -- is that based on just the current contract that’s in place, or does that assume something with the remaining 30 megawatts?

Great. Dariusz, thanks for your questions. On the project, we are actively in the process of marketing the balance of the 30 merchant megawatts as we move forward into the year. We see actually a number of opportunities, both with existing RFPs in the jurisdiction and frankly, through our outreach with existing customers that we have. So, we’re pretty optimistic that we would be able to do a pretty good job of contracting up that residual component. In terms of it being a drop-down for TransAlta Renewables, we think it’s an excellent project, as is candidly. So, having a little bit of that merchant component remaining with the wind facility would not, at least from my perspective, be an impediment to having it be dropped down to TransAlta Renewables. But as I said, we do expect to be able to progress the contracting for the balance of the plant. And candidly, it was just more efficient to rightsize the plant from a cost perspective and fill in that tail end of the contracting. In terms of the EBITDA, that $17 million number is sort of our best estimate of what we would expect to see, based on the base contract that we have there and a number of scenarios, some of which would include contracting and some of which would include a merchant component and the environmental attributes associated with the wind farm.

Okay, excellent. Thanks very much for that detail. And if I could just ask one more, and this is regarding -- there’s a note in the MD&A about conditional settlement with Fortescue. When do you think we might hear more about that in specific terms of the settlement and potential financial impact?

Yes. I mean, Kerry, do you want to maybe respond to that? I mean, I can -- maybe Kerry can add some color. I -- look, we’re in the process of working through that. I think the kind of conditions that are involved in that settlement would be what I would characterize as sort of normal course commercial kind of conditions that need to be resolved. I’m hopeful that we would see a resolution of that in the sense of having all conditions satisfied. Within the quarter, certainly, by the early part of the summer, and our hope would be to see FMG return to the plant as a customer. Kerry, I don’t know, is there anything else… Kerry O’Reilly Wilks: No. I’ll just reiterate the last point that we’re all very excited to move forward cast settlement and to welcome back FMG as a core customer in Australia.

Your next question comes from the line of Maurice Choy with RBC Capital Markets.

Thank you, and good morning. My first question is about Alberta power market. You mentioned that one of the primary reasons for the improved guidance commentary relates to better Alberta power prices. I recognize that we are only five months into this new power market environment, but is this your view that these levels -- these power price levels seen so far for this year as well as the rest of this year will carry through for 2022 and beyond?

Yes. Maurice, I really appreciate the question. Look, our current view is that the kind of pricing that we’re expecting to see, particularly in the balance of the year. And I think the balance of year price is sort of in that $69 range are broadly in line with what we would expect to be sort of normal prices for power in the province. When I think of it, I tend to think of pricing in that $65 to $70 range. It’s something that certainly we’ve communicated, and we’re seeing -- to the extent there is some trading on 2022, pricing that’s broadly in that zone. And remember, with the current market that we have, it’s important that people get not just the energy value in the price, but also the capacity price for their generation and for their facilities and the price. And our view would be that pricing in sort of the range that we’re seeing for the balance of the year is appropriate and justified.

Great. And that probably flows quite nicely into my second question, which is about Sundance Unit 5. And I’m trying to understand better the changes that you’ve announced, including the cost estimate change. Can you elaborate a little bit more about what has motivated this? You mentioned increased operating flexibility, the 20 megawatts of additional capacity. Is it all due to the change in the power market dynamics or common regulation? Any additional color would be appreciated.

Yes. It’s a great question. So, we’ve continued to advance the design work on the facility. And as we went through that and looked at the various constituent elements of the plant, we were able to get more precise estimates on what the cost would be to actually develop it. And some of the work, just to give you a bit of a flavor, would have included things like incremental costs associated with some of the piping we need. A better understanding of some of the geotechnical requirements that we need for the plant, all of which have contributed to both, a clarity in terms of what the actual design parameters are and a bit of an increase in cost relating to those things. With respect to the high-pressure turbine work, we did a bunch of analytics. And although our view is that the plant will largely be running in a baseload form, we thought that making some of the changes there to increase the flexibility of the plant, particularly as we see the advent of an increasing number of renewables in the marketplace, just makes a lot of sense. I think having a plant, given the investment that we’re proposing to make, that is as flexible as a brand-new plant, is exactly what we wanted to do. And really, it’s those two groups of things, greater clarity and a better sort of specifications around plant, and making sure that we have that maximum flexibility that have contributed to I think a better project but also a project that has crept up in price.

And just as a quick follow-up, because you mentioned those two items. As you carry on your second or kind of third conversion, once you include Sundance. [Ph] Do you feel like you need to do more with regards to those simpler conversions?

Not sure…

Sun 4 and K1.

Sorry. Maybe I just want to make sure that I understand the question that you’ve asked. So, are you asking, are we planning to do more on Sun 4 and K1? Is that your question, Maurice?

Correct. So, obviously -- sorry, yes is the answer.

Yes, okay. Right now, we don’t have -- I mean, we continue to evaluate those facilities, particularly K1 in the context of potential repowering later in the decade, but we have no plans at this point in time to change kind of the operating parameters of those two units as we move into 2022. So, you would expect to see those two units, I think, K1, operating at roughly a 70-megawatt kind of capacity and Sun 4 in kind of that 110, 113 megawatts, firing solely on gas as we wind down operations on the mine. So, no changes to that strategy or plan.

Your next question comes from the line of Rob Hope with Scotiabank.

First question is on the Hydro quarter, 77 was a good number there. Can you give us some gives and takes as what you saw in the ancillary market? It does look like your ancillary revenue as a percentage of spot was a little bit higher than normal. So overall, was this kind of a quarter as expected, or did your outage at big or and even drag you down a little bit there?

Yes. I mean, I think we -- Rob, you never know until you start the quarter, right? And this was a bit of a paradigm-shifting quarter, as you know, for us. I think, as we went through the quarter, I think it came out broadly as we expected. I think, there were periods of time during the quarter where, candidly, the ancillary services market was hypercompetitive, in terms of all of the people that we’re trying to supply into it. But on balance, I think, the number that we got, a little bit below the number that we would have realized last year in terms of the volume of that we would have sold in the market was broadly where we would have expected it. In this case, it’s a bit over 2 times the amount of energy that we sold in the marketplace. So, I don’t think there was any surprises when I think of all the discussions that we had with our optimization team through the quarter.

Okay. And then, as we look forward through the rest of the year, is there anything to note there, or are you tracking pretty well to your -- we’ll call it historical guidance of 225 to 275, even with the lack of environmental credits this year?

Yes, we are. We expect that the kind of guidance that we’ve been talking about is broadly where we’re expecting so far, our Hydro to land and haven’t really seen anything into April and the early part of May that would suggest that that wouldn’t be the case. So, so far, so good.

Your next question comes from the line of Ben Pham with BMO.

I want to go back to question on Alberta power prices. And I’m wondering, when you see power prices what you saw in Q1 $95 dollars or so in the past, it’s typically because demand outstrips supply. I mean, in this case, maybe exclude the weather impact, would you characterize the market as more economical foot holding that’s really driven that power price versus the market being in a tight supply-demand situation?

Yes. So, I would characterize it in a couple of ways, Ben. I mean, the first thing was, look, February was a really cold month. And the kind of pricing that we saw in February where it cleared in the mid-$100 range was an exceptional outcome. And the weather absolutely contributed to that. And I think, as you know, I think it was actually on February 9th. We actually hit a new peak load in the province. So for sure, notwithstanding the pandemic, we saw periods of time in the quarter, just given the winter where there was high load. I think the second thing that I would say is for sure, and people are dispatching their units commercially in the marketplace, and that kind of goes back to, at least from our own perspective, with the view to long run marginal costs. We need to be able to get our capacity payments out of the market. We need to be able to cover the variable cost for the energy component. Some of those variable costs have actually increased with carbon pricing going out. So, we weren’t particularly surprised from what we saw in the quarter. The last thing I would say is before just making one other comment is that when we look at how tight the supply was from the viewpoint of the dispatchability of the units, we tend to not look at just installed capacity in the market, but actually the capacity that would have been available to run, it’s much tighter than people think. I think that something like 40% of the time, certainly, in that first quarter, we had a supply cushion that would have been 15% or less. So, it’s actually, from a practical perspective tighter throughout the period than people would have expected. And then, just my final sort of point of color would be that I think you have to look at the pricing from a longer term perspective. I’m not sure that looking at it in a week or a quarter or a day or an hour is sort of indicative of where it is. So, at least from our perspective, we tend to think of kind of an annual average and even from a longer term perspective. And when you go back and you look at the province over the course of the last 10 years or so, seeing average pricing kind of approaching that $60, at a time where, frankly, some of the variable costs were lower, is not unusual in the context of where we are.

And John, I would just add that the average $95 price is really a February story.

Absolutely...

January and March were both right around where we would have expected to settle in the winter months of the year.

And it was just a few days in February that made all the difference as well. Yes.

Okay. And it does look the forward looks still robust and even given last month was also quite strong. Are you getting feedback from consumers or retailers or even government about concern around this high-power price, like what you -- what we kind of hear more in Ontario region?

Yes. We haven’t experienced that, Ben. And I kind of go back to the point that I was making. I do think you have to take a longer term view of what the pricing is in the marketplace. And candidly, pricing that is in that sort of mid-$60 to $70 range over the course of the year is pretty competitive pricing, certainly, from a Canadian perspective, I think, certainly, from a global perspective, when we look at what power prices are in many other jurisdictions, including jurisdictions that we would compete with. It’s a reasonable price, and I think reflective of what the true cost of generation is in the marketplace.

Okay. And if I may, one more question on your growth pipeline, slide 6, and you have some cogen opportunities in Australia. I’m curious, what about renewables in Australia, like pump hydro storage or wind? Is there an opportunity there for you?

Yes. I would say two things. We continue to assess the opportunity set. Primarily that is in Eastern Australia, which is very renewable-heavy from an opportunity set. And you’re right, there is pump storage that is being done there. Our focus has been to be -- a bit more on looking at solar opportunities and maybe some wind development opportunities in Eastern Australia. But, when you look at Western Australia where we are, and we tend to think of it as the opportunity set being kind of hybrid generation that we’re working with some of our customers. So, it would be our expectation, certainly, our goal this year to be delivering some projects in that jurisdiction that would have some renewables attached to storage for some of the work that we’re doing with the customers there.

Your next question comes from the line of John Mould with TD Securities.

Maybe just circling back to Sundance 5. Can you provide some context on how the expected returns on that investment has evolved, given on one hand that the cost increased, so one to two quarter COD the way? And then, on the other hand, what looks like improved asset flexibility and a bit of a capacity increase?

Yes. I mean, John, the -- what I can say is that we -- when we look at the modeling for the plants, even in the context of some of the higher costs -- capital costs that we see in developing the project, still pretty robust returns. I mean, we continue to evaluate the market. Our forecasting team is actively involved in kind of assessing what pricing looks like, and we continue to assess it. But so far, it does look like the returns are robust. The flexibility that the plant has are positive and just the efficiency of the plant is very solid in the context of the market. And there’s other ways to provide value, too. So, for example, your gas supply strategy will be critical. And obviously, as time goes by, the way that you’ll deal with carbon, will be another key component in the value proposition associated with the plant. But so far, so good.

Okay. And then, maybe moving on to just your hedging approach regarding some of your peakier units. I know you don’t want to get into talking about what your current hedges look like. But can you provide just some high-level thinking on how you approach hedging the output from some of your older coal or coal-to-gas units that otherwise might not run much outside of high-price periods?

Go ahead, John.

Yes, sure. No, it’s a great question. So, it is something that, John, we evaluate, week by week, quarter-by-quarter. As you know, the liquidity in the market is such that your ability to sort of hedge long, long term is challenging. So, we tend to think of it more in the approximate quarter or two in terms of the volumes that are there. And our team spends time kind of looking at what our expected generation is going to be. We have a sense of what will be baseload effectively in the generation. And then, we evaluate that in the context of where we think the market will land and what the signal is from a hedging perspective. And if we think that the market is effectively overvaluing our expectations, we’ll layer in more hedges. And if we think it’s the reverse, we’ll probably be more open as we move in. And we always want to keep, kind of to your point, that peaking component from some of the plants that may not run as much and tend to go after some of the higher hours. That will be more open. And in general, we tend to think of our hydro as being more open as well. Todd, I don’t know if you want to add any color there. But, I mean, it -- I think, you’ll see more variability, I think, in our hedge levels as compared to maybe what you would have seen in the past where maybe, John, we would have said we want to be 70% hedged. I think you’ll see it vary depending on what we think our assessment of the market will be at any given time. Todd?

I was just going to add that, yes, it is a very dynamic. It is a month-by-month decision. John mentioned it’s market-driven as to where we see the value proposition in the future months. But, it’s also driven off of where we have particular outages on our fleet or other outages going on in the province. And as you can imagine, with our K2 unit currently undergoing the coal-to-gas, we have less megawatts hedged just because that unit is not available, whereas all of our units will be back on over the course of the summer. So, we’ll have more length there and potentially enter into more hedges at that.

Okay. That’s great. Thanks for that. And then, maybe just lastly on the Brazeau pumped storage project, you’ve had some time to digest the federal carbon price proposal and what that could look like in the years ahead. I’m just wondering what kind of work you’re doing on that project, discussions you might be having with potential counterparties? And what might be required beyond long-term certainty on the carbon price to help move that project forward?

Yes, a great question. So, we do continue to periodically have discussions around that project, both with customers, John, and also with government, candidly. In general, with the trend towards, and we’re convicted around the trend towards decarbonization and the increase of intermittency in the generation. We do think it’s a great project and can effectively act as a battery for the jurisdiction. Building a facility like that in a merchant context is challenging. So, we would need to have, I think, a sense of revenue certainty or certainly predictability, before I think we would proceed with that. So, our discussions tend to be around that for us. But we continue to think that there will be a time for that project as we move forward. And the team continues to look at it. We continue to speak to customers about it, and I think it has tremendous attributes that there will be a day when it will be needed.

Your next question comes from the line of Mark Jarvi with CIBC Capital Markets.

It seems like there’s been some announcement -- or there’ve been some announcements from some others around CCS and hydrogen. I’m just wondering if there is sort of a finite level of government support for some of that technology. What’s your view in terms of integrating that into Sun 5, the repowering? And do you have to kind of move on that now? Like, can you be patient in terms of whether or not you want to integrate that, or do you feel like kind of how things start moving, given that others are moving as well?

Yes. No, it’s a great question, Mark. So, look, we, in the context of Sun 5, are actively considering what the CCS or CCUS kind of strategy on that might be in the future. And it’s expensive. It is -- that would be a unit that would generate, call it, 2, 2.5 megatons a year of CO2. And in today’s dollars, kind of the cost of putting CCS on a facility like that that would capture, call it, 90% of the emissions coming out of that, would be easily in the $800 million range, possibly even more. So, it’s not much different, Mark, than the actual cost of the repowering, of the unit that’s there. So, we are actively looking at it. We’re in discussions with the government. I think, there’s been some constructive proposals that came out of the budget, certainly from a federal government perspective, and there’s more work to do to develop it. But, I think there’s a recognition, both by the industry and by government that achieving our goals is going to require probably some assistance to get some of these kinds of investments done in a way that just makes sense economically going forward. You had a couple of other points there. I mean, from a -- in terms of the urgency for that, Sun 5 will be a pretty efficient facility. So, even though we’re seeing an increase in carbon pricing going forward, the sort of incremental annual increase in cost is relatively modest, kind of in that $2 to $3 a year incremental cost from a carbon perspective. So, it really bites, I think, 5, 6 years out where you start seeing carbon pricing approaching that $100 range, which might then begin to make some of these kind of technologies more economic. The final thing that I’d say, you mentioned hydrogen. We are looking at hydrogen and assessing it. It’s pretty expensive. Candidly, Mark, I mean, many times more expensive than natural gas is right now. And there’s a couple of other challenges associated with it. I mean, one, there’s a lot of infrastructure build-out that would have to take place to make sure, A, that we’ve got the supply and it can be delivered to the facilities to run them. But probably more importantly, at least in the foreseeable term, the existing infrastructure that’s in place isn’t really all that well suited to blending it or burning it. And the challenge you have is even if you mix it, which we think we can probably do and it wouldn’t cost a ton more from a capital perspective, there isn’t a linear relationship between your emissions reductions and the hydrogen that you burn. So, for example, if you burn 30% hydrogen in the fuel mix, you won’t get a 30% reduction in emissions. The emissions reductions might be half that. It’s only when you get to kind of 80%, 90% levels of hydrogen kind of burn that you sort of capture equivalent levels of CO2 emissions. So, it’s a bit of a long answer, but I just want to give you a flavor of the way our company is looking at it, and we’re looking at the technology. And certainly, we’re looking at companies we could partner with to move it forward. I think it’s going to require a collaborative effort.

And just in terms of readying yourselves or having that flexibility down the road, are there things that you’ll have to change in your planning for Sun 5, or have you already sort of integrated that that down the road if CCS becomes more economic, it’s easy to integrate that unit?

Yes. It’s more of the latter. We don’t think right now that there’s a lot that we need to do in our current planning to kind of contemplate possible technologies that we would need going forward. So, that isn’t driving kind of plant design now.

Okay. And then, just on the hedging, I think it’s said in the disclosures that you really weren’t hedged at all in the hydro or to your benefit this quarter. Is that sort of the plan going forward to keep those assets largely open?

Yes. I think, in general, that’s the way we tend to think of it. I mean, there is a -- you could argue that there’s a base level of hydro generation that we have. And I tend to think of that as being kind of 125 or 150 megawatts. But, in general, our focus is more on the thermal fleet, Mark, from a hedging perspective than our hydro fleet, which we see as being more dynamic.

Got it. And then, just coming back to Garden Plain in that contract, maybe you can’t share too much given the agreement. But just any comment in terms of how the carbon credits are dealt with in that term in terms of how they’re shared or upside as carbon prices go higher?

For sure. What I can tell you is on the 30-megawatt merchant component, which we’re looking to contract, I mean, the energy generated from that and the environmental attributes from that would belong to TransAlta today. With respect to the piece that Pembina has contracted, they’re contracting for not just the energy, but they are getting the benefit of all of the environmental attributes associated with that generation as well. And there’s some sort of mechanism that accounts for whether or not carbon prices change, or is there sort of -- have you kind of locked that in today?

No. They -- so their price for the -- the blended price effectively for the energy and the environmental attributes is fixed. So, whatever ends up happening with the value of credits, whether they go up or whether they go down, that would be something that is really for Pembina’s account.

Naji, your line is open.

So, just maybe to start off with the conversion of the credit facility to Sustainability Linked Loan, I’m just curious if you can provide us any more color on that specific conversion. And maybe more broadly, how you’re thinking about green or sustainability financing as part of your funding options going forward?

Great. Yes. Thanks. Naji, it’s Todd here. I’ll take that. So, the sustainability, I think loan really maps to the targets that we had set out in our sustainability report at year-end. So, there’s really -- we’re basically putting our money where our goals are. And that’s a typical Sustainability Linked Loan, where so long as we meet or exceed our targets, we’ll enjoy and get lower cost financing. But, if we don’t achieve our targets, we’ll be above those. The two metrics that we put into that that we disclosed is both our GHG target as well as our diversity target. As far as green financing, look, we have not issued a green bond, but we haven’t issued a corporate bond in quite a while now. I think it’s -- I think it might even be over a decade now that we haven’t issued a corporate bond. What we have done is we’ve issued financings directly related to our wind farms and other renewable assets. And so, while they may not be tagged is a green bond, clearly, they are financing directly linked to renewables projects. And I can tell you, the investors consider them to be green financings.

And I guess, you seem to be relatively well capitalized now with the expectations for a strong year in Alberta, I guess, for the rest of ‘21 and maybe ‘22. Does that change your capital allocation priorities at all? Do you see the possibility of maybe doing buybacks or M&A over the next 12 to 24 months?

Well, I mean, on the buybacks, I mean, we bought back -- I can’t remember the exact number last year. We didn’t buy any back in the quarter. We do have an NCIB program in place, and we do plan to extend it for the balance of the year and through to next year. I don’t see a major change in our capital allocation plans. But you are correct that our FFO available for what I’ll call other activities, sort of outside of the sustaining capital, dividends, et cetera, is growing and is larger. And we absolutely are always looking at M&A opportunities. And certainly, the development team has a lot in the pipeline. And as John said, hoping to convert at least one other wind farm here through the balance of the year.

Yes. And I think, Naji just in terms of 2021, I mean, we still have a pretty big sustaining capital spending year with our coal-to-gas conversions. I know, like we are anticipating a strong year this year. But I think, Todd, it would be fair to say that once we’re through this, probably a bit lighter on the sustaining capital side and probably more capital in terms of our capital allocation approach to things like dealing with growth and dealing with potential returns to our shareholders, directionally.

And just one last question on the Brookfield strategic investment and partnership. I guess, you’ve had that partner for about two years now. Just wondering if you can talk about any major lessons or takeaways, either from the joint operating committee or having two Board members on your Board. Has that impacted or sort of informed your view of how to manage either hydro operations or how to think about growing both, TransAlta or TransAlta Renewables?

Yes. I would say -- look, I would characterize our relationship with Brookfield as an excellent one. What I would say is when the Brookfield nominees are participating on the TransAlta Board, they really have their TransAlta caps on, would be -- I think, the observation that you would universally get from the TransAlta team. So, it’s not like they’re bringing a unique Brookfield approach. I think, they just look at TransAlta, they look at our unique strategy, they look at what our opportunity set is, and they contribute very, very actively in that discussion. They’ve been great. I think all of the Brookfield representatives on our Board have been tremendous. In terms of the work that we’ve been doing around our hydro, I think the discussion has been constructive. We have a -- they have an approach to the way that they run their hydro fleet and their business. We have our own approach in the way that we run our fleet. We are actually partners in a facility as well. So, it’s not like we don’t know each other very well. So, I think, the discussions are helpful, they’re constructive, and in many respects, kind of reinforce just the existing operating dynamic that we currently have. So, it’s not like we’re changing the way that we’re operating our hydro as a result. But, very much appreciate the input that we get on that committee.

Your next question comes from Luca Nadal [ph] with National Bank Financial.

Good morning. I cut out a little, earlier. So, I might have missed the question. But, I’ll just ask quickly. I’d like to know if there’s a specific strategy for your environmental credits that you plan to sell in the future. And how many of them do you think you can sell per year?

Yes. Luca, you dropped on that very last part of your question. But, I think what you’re asking is do we have a strategy around our environmental attributes. We do. And frankly, it’s something that we continually look at and assess. So, it’s everything from looking at what we anticipate prices to be like in the future to really looking at what our own emissions profile is as a company. We -- even though our emissions have been reduced dramatically from where they were even just a few short years ago, we still have an emissions profile as we go forward. So, we tend to look at a blend of what do we need to manage TransAlta’s carbon costs going forward versus what can we actually secure by monetizing some of those credits in the marketplace as compared to what we could potentially maybe acquire credits for at a lower price to deal with our own costs. So, there’s a big optimization exercise that goes on with that. And we have a team that is exclusively oriented towards dealing with that every year.

Good. And the second part of my question was just how my credit, do you think, like as an average, you could sell per year?

Oh, gosh. I don’t have that number with me. What I would say is that the market works, as I understand, in fits and starts. So, it’s very much a bilateral market, particularly in Alberta. So, there is liquidity in the market. But, I don’t think people should assume that it’s kind of intimately liquid sort of marketplace. Todd, I don’t know…

Yes. I was just going to add as well that we don’t -- we certainly produce RECs off of our wind fleet and have for many years, and we are now producing RECs off of a hydro fleet, so creating an inventory level. But recall also that we actually do consume them ourselves through our thermal fleet. And so, we are of our own as biggest users of those RECs. Now, we do opportunistically sell them into market when we have excess or we see additional value, but we are using a fair number of the RECs internally.

Your next question comes from the line of Rob Hope with Scotiabank.

Just a follow-up on the FMG. Just going back to my 2017 notes, it looked like FMG was, we’ll call it, 40 megs of capacity there, and that was around $20 million of EBITDA. So, is the expectation that at some point in 2021 this could come back, or could we see altered kind of agreements there?

Yes. I mean, Rob, we’re still in the process of trying to get the matter settled. So, we’re pretty constrained in terms of kind of answering that question. So, I ask that you just kind of bear with us as we work through all of this. But -- and hopefully, you’ll get a bit of a better sense of that as we go forward.

You next question comes from the line of Patrick Kenny with National Bank Financial.

Yes. Good morning. John, just a high level question on partnerships here, and you have Pembina signed up, but you lost Energy Transfer. Decarbonizing the oil sands will no doubt be a team effort by many Alberta companies. I guess, how do you see the need for more partnerships going forward, A, accelerating your growth and overall transition story, but also B, presenting challenges in trying to simplify your corporate structure so that investors can really see the value of future cash flows?

Yes. Look, it’s a great question and it’s something we talk about a lot internally, Patrick. So, to your point, I think the decarbonization of the province is for sure going to require a greater amount of electrification to occur going forward. So, that’s something that we’re excited about and creates a pretty big opportunity set. And our focus is to actually be very client centered and really focused on trying to work with customers to meet their needs. And that isn’t just by saying, oh, here’s an off-the-shelf facility that we can build for you, but really trying to work with them to the extent that we can to help them map out their own future needs going forward and the solutions we can bring. And we’re trying to do that in all three countries in which we operate. Coming back to Alberta, I do think we’ll see more partnerships. I think -- and I think we’ll see them in two areas. I think, in terms of project development, our focus is very much on contracted growth going forward. I’m not sure that creates a big issue from a disclosure perspective. From our perspective, it’s just contracts and customers. If anything, we’re trying to reduce the merchant component of the Company going forward. I think the area where you might see more partnerships that might add some complexity would be actually on the carbon capture side. Those are big dollars. I think, being in a place where you can cooperate with third parties in a way that each of the constituent components going into capturing carbon, everything from pipelines to the injection to dealing with the actual capture, you might see more partnerships associated with that given the risks and the capital required to see it through. And candidly, I think that’s just something that’s going to be a disclosure issue for us and just a factor for everybody that has that kind of element of carbon in their generation.

Right. And as maybe a follow-up question to that, just given the higher cash outlay here for Sun 5, does it make sense to pursue a partner just to help share some of that capital cost risk, perhaps similar in structure to the Alberta Hydro strategic investment, given the run rate EBITDA off of Sun 5 is somewhat unknown at this point?

Yes. What I would say in response to that is, right now, we’re not in any discussions relating to a partnership for that facility. I can’t predict to you 100% what the future would hold. But today, there’s nothing that we’re working on in that regard with that facility.

And your final question comes from Chris Varcoe with Calgary Herald.

Hi, John. Just a follow-up on the question about the corporate partnerships. We’ve obviously seen a number of them announced in the last 6 months to 12 months. I’m wondering whether you are going to see or whether you expect to see that sort of slowdown at some point here in the near future. And maybe more broadly, what impact are all of these sort of additional renewables going to have upon the marketplace and upon your plans going forward on other projects?

Yes. So, let me try to answer each of those separately. So, my expectation is that we will see more partnerships, Chris, going forward. I think it just makes sense. Some of the players in the province have a need for power, have a need for environmental attributes, have a need to decarbonize. Companies like ours have the ability to meet some of those solutions. And I think that naturally lends itself to companies getting together to create solutions that result in a win-win for both sides. So, I do think that that trend is here to stay for us. And in fact, as a company, we’re spending quite a bit of time and investing quite a bit of effort in making sure that we have a real customer and partner-oriented mindset in the Company. That’s actually one of the core things that we’re focused on internally, just having more of a service orientation. So, I think, for sure, Chris, that’s a trend that we’ll continue to see, just given the transformation that’s required in the costs, candidly, to see projects of the nature that we have coming through, and really just risk allocation between the parties going forward. On your second point, on the renewables, we do continue to see, for sure, more renewables being built out in the province. I think, over time, that will result, certainly during periods of the year, where we’ll see more intermittency, in the generation because the renewables can be unreliable at times. They only -- they’ll only work when the sun is out in terms of solar and when the wind is blowing, and there is a seasonal element to that, and temperature plays a key role. And our province has very high baseload requirements, given the nature of the industry in the province and isn’t so much our residential base, the industrial base that drives demand in the province. So, I think the trick in the future is going to be to having that firming generation, gas or whatever the technologies are in the future, batteries, pumped storage, all of which will be able to respond to kind of step in and backfill any of that variability that results in some of the renewables going away. So, I think, we’ll see more renewables coming in, and I think there’ll be more volatility in how it’s supplied in any given day. And I think that will be something that I know the ISO is already thinking about from a policy perspective, and we’re -- we will be involved in discussions relating to that. And it’s kind of exciting, because it’s an opportunity for a company like ours and just a reality in terms of where we see the future going. So hopefully, Chris, that gives you a bit of a sense.

It does. And just finally, to follow up on the question about the carbon capture and sequestration. What are you hoping to see, or what do you think the industry is going to need to see from the federal tax credit that is being contemplated right now in order to make CCUS projects attractive for you on things like Sundance 5 repower?

Yes. It’s a great question. At the end of the day, it’s going to come down to economics, to be candid, Chris. So, the credits are very, very helpful. Having those accelerated deductions from a tax perspective will certainly help improve the viability of the projects on a go-forward basis. Some of the things that at least we think about as a company is -- and I look at what other countries do, I look at, for example, what’s done in the U.S. where the federal government there and in other jurisdiction spends a bunch of money to do a bunch of that R&D that is necessary to create kind of cost effective solutions, which could then be distributed out or partnered with the industry to kind of bring forward. So, for me, those are the two broad constructs that are important. It’s all about making sure that from a financial perspective it makes sense that the private sector can do what they need to do to help the country meet the kind of targets that we have set for greenhouse gas emissions, and yet do it in a way that power remains reliable and low cost. I mean, it’s an interesting algorithm, interesting calculus that you have to meet. Because if you flub up one of those elements, I think it’s a problem for the country.

And at this time, there are no further questions. Do you have any closing comments?

Great. Thank you, Rebecca. Thank you, everyone. This concludes our call for today. If you have any further questions, please don’t hesitate to reach out to the Investor Relations team here at TransAlta and TransAlta Renewables.

Thank you for participating. This concludes today’s conference call. You may now disconnect.