Earnings Call
Transalta Corp (TAC)
Earnings Call Transcript - TAC Q1 2021
Operator, Operator
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. Thank you. Ms. Valentini, you may begin your conference.
Chiara Valentini, Conference Moderator
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 are 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.
John Kousinioris, CEO
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 a strong power market in Alberta during the 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 the 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.
Todd Stack, CFO
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 $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 on 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 three 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 can 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. For the 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.
John Kousinioris, CEO
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.
Chiara Valentini, Conference Moderator
Thanks, John. Rebecca, would you kindly please open up the call for questions from analysts?
Operator, Operator
And your first question comes from Julien Dumoulin-Smith with Bank of America.
Dariusz Lozny, Analyst
Good morning. This is Dariusz Lozny filling in for Julien. Thank you for taking my question. I wanted to discuss the new wind project, Garden Plain, briefly. It seems you've had success in contracting the initial phase. Could you share your plans for contracting the remaining 30 megawatts? Additionally, how does this fit into potential plans to integrate it into TransAlta Renewables? Also, could you clarify the $17 million EBITDA estimate? Is it based solely on the current contract, or does it include assumptions about the remaining 30 megawatts?
John Kousinioris, CEO
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.
Dariusz Lozny, Analyst
Thank you for that detailed information. I have one more question regarding the note in the MD&A about the conditional settlement with Fortescue. When do you anticipate we will receive more specific information about the settlement and its potential financial impact?
John Kousinioris, CEO
Yes. Kerry, would you like to respond to that? I can maybe let Kerry add some insights. We are working through that. The conditions involved in that settlement are what I would consider normal commercial conditions that need to be resolved. I am optimistic that we will see a resolution regarding all conditions being satisfied within the quarter, certainly by early summer, and we hope to see FMG return as a customer. Kerry, is there anything else?
Kerry O’Reilly Wilks, EVP, Legal, Commercial and External Affairs
No. I’ll just reiterate the last point that we’re all very excited to move forward with the settlement and to welcome back FMG as a core customer in Australia.
Operator, Operator
Your next question comes from the line of Maurice Choy with RBC Capital Markets.
Maurice Choy, Analyst
Thank you, and good morning. My first question is about the Alberta power market. You mentioned that one of the primary reasons for the improved guidance is better Alberta power prices. I understand we are only five months into this new power market environment, but do you believe that the power price levels we've seen so far this year will continue through 2022 and beyond?
John Kousinioris, CEO
Yes, Maurice, I appreciate the question. Our current viewpoint is that the pricing we anticipate for the remainder of the year, which is around $69, aligns broadly with what we consider to be normal prices for power in the province. When I think about it, I see pricing in the $65 to $70 range. This is something we have communicated, and we’re observing that trading on 2022 pricing falls within that range. It's important to keep in mind that in the current market, people need to account for not just the energy value in the price, but also the capacity price for their generation and facilities. We believe that the pricing we see for the rest of the year is appropriate and justified.
Maurice Choy, Analyst
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.
John Kousinioris, CEO
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, 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 the 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.
Maurice Choy, Analyst
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. Do you feel like you need to do more with regards to those simpler conversions?
John Kousinioris, CEO
Not sure…
Maurice Choy, Analyst
Sun 4 and K1.
John Kousinioris, CEO
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?
Maurice Choy, Analyst
Yes, that’s correct.
John Kousinioris, CEO
Right now, we are still assessing those facilities, particularly K1 in light of potential repowering later in the decade, but we currently have no plans to alter the operating parameters of those two units as we move into 2022. You can expect to see K1 operating at approximately 70 megawatts and Sun 4 at around 110 to 113 megawatts, running solely on gas as we gradually wind down operations at the mine. There will be no changes to that strategy or plan.
Operator, Operator
Your next question comes from the line of Rob Hope with Scotiabank.
Rob Hope, Analyst
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?
John Kousinioris, CEO
Yes, I think we never really know how a quarter will turn out until we get started. This particular quarter was significant for us. As we moved through it, the results aligned closely with our expectations. There were times when the ancillary services market became highly competitive, with many players trying to participate. However, overall, the volume we sold was somewhat lower than what we achieved last year, but it was roughly in line with our expectations. This time, we sold over twice the amount of energy in the market. Therefore, I wouldn’t say there were any surprises based on the discussions we had with our optimization team throughout the quarter.
Rob Hope, Analyst
As we look ahead for the remainder of the year, is there anything noteworthy to mention, or are you on track with your historical guidance of 225 to 275, despite the absence of environmental credits this year?
John Kousinioris, CEO
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.
Operator, Operator
Your next question comes from the line of Ben Pham with BMO.
Ben Pham, Analyst
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?
John Kousinioris, CEO
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.
Todd Stack, CFO
And John, I would just add that the average $95 price is really a February story.
John Kousinioris, CEO
Absolutely...
Ben Pham, Analyst
It appears that the outlook remains strong, and last month showed significant performance as well. Are you receiving any feedback from consumers, retailers, or government regarding concerns about the high power prices, similar to what we hear in the Ontario region?
John Kousinioris, CEO
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.
Ben Pham, Analyst
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?
John Kousinioris, CEO
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.
Operator, Operator
Your next question comes from the line of John Mould with TD Securities.
John Mould, Analyst
Maybe just circling back to Sundance 5. Can you provide some context on how the expected returns on that investment have 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?
John Kousinioris, CEO
Yes, John. When we examine the modeling for the plants, even with the higher capital costs associated with developing the project, the returns still appear to be quite strong. We are actively monitoring the market, with our forecasting team assessing pricing trends. So far, the returns look robust, and the plant's flexibility and efficiency are solid in the current market context. There are additional ways to create value as well. For instance, your gas supply strategy will be essential, and over time, addressing carbon emissions will also play a crucial role in the plant's value proposition. Overall, things are looking positive.
John Mould, Analyst
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?
Todd Stack, CFO
Go ahead, John.
John Kousinioris, CEO
Sure. That’s a great question. We evaluate our approach week by week and quarter by quarter. Given the current market liquidity, hedging long-term can be difficult. Therefore, we focus on the next quarter or two in terms of expected volumes. Our team analyzes our predicted generation, particularly what we expect to be baseload. We consider where we think the market will settle and the signals related to hedging. If we believe the market is overestimating our expectations, we add more hedges. Conversely, if we think the opposite is true, we may take a more open stance. We also want to maintain the peaking aspect from certain plants, which might not operate as frequently, but can capture some of the higher usage hours. Our hydro generation will generally have a more open approach as well. Todd, do you have anything to add? You'll notice more variability in our hedge levels compared to the past, where we might have aimed for a 70% hedge. Now, it will fluctuate based on our market assessment at any given time. Todd?
Todd Stack, CFO
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.
John Mould, Analyst
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?
John Kousinioris, CEO
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.
Operator, Operator
Your next question comes from the line of Mark Jarvi with CIBC Capital Markets.
Mark Jarvi, Analyst
It seems there have been several announcements regarding CCS and hydrogen. I'm curious if there is a limited amount of government support for this technology. What are your thoughts on incorporating this into Sun 5 and the repowering process? Do you need to act on this right away, or can you afford to be patient about its integration, especially since others are also making progress?
John Kousinioris, CEO
Yes, it's a great question. In the context of Sun 5, we are actively considering what our strategy for CCS or CCUS might be in the future. It's expensive; the unit could generate around 2 to 2.5 megatons of CO2 a year. The cost of implementing CCS at such a facility to capture about 90% of emissions would likely be in the $800 million range, possibly more. This cost is comparable to the repowering expenses of the current unit. We are in active discussions with the government, and there have been some constructive proposals from the federal budget, but more work is needed to develop this. There's a shared understanding between the industry and government that achieving our goals will likely require assistance to make these investments economically viable. Regarding the urgency, Sun 5 will be a fairly efficient facility, and while carbon pricing is expected to increase, the annual cost rise will be modest, around $2 to $3 per year. The real impact will be felt in about five to six years when carbon pricing approaches the $100 mark, which could make some technologies more economically feasible. As for hydrogen, we are assessing its potential, but it's currently quite expensive—much more so than natural gas. There are also challenges related to infrastructure; significant build-out will be necessary to ensure supply and delivery to our facilities. Additionally, the existing infrastructure isn't ideally suited for blending or using hydrogen. Even if we mix it in the fuel, the emissions reduction isn't linear; for example, burning 30% hydrogen might not yield a 30% reduction in emissions; it could be as little as half that. Significant reductions would only occur at higher levels of hydrogen combustion, around 80% to 90%. While this is a lengthy response, I wanted to illustrate how we are analyzing these technologies and potential partnerships needed to move forward, emphasizing that collaboration will be essential.
Mark Jarvi, Analyst
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?
John Kousinioris, CEO
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.
Mark Jarvi, Analyst
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?
John Kousinioris, CEO
Yes, I think that's generally how we view it. There is a base level of hydro generation that we have, which I consider to be around 125 or 150 megawatts. However, our primary focus is more on the thermal fleet from a hedging perspective than on our hydro fleet, which we perceive as being more dynamic.
Mark Jarvi, Analyst
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?
John Kousinioris, CEO
Certainly. The energy generated from the 30-megawatt merchant component we plan to contract will belong to TransAlta. In contrast, Pembina is securing not only the energy but also all the associated environmental attributes from that generation. I'm curious if there’s a mechanism in place to account for potential changes in carbon prices or if that has already been settled. No. Their price for the blended energy and environmental attributes is fixed. Therefore, any changes in the value of credits, whether they increase or decrease, would be for Pembina’s responsibility.
Naji Baydoun, Analyst
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?
Todd Stack, CFO
Thanks, Naji, it’s Todd here. I'll address that. The sustainability loan aligns with the targets outlined in our year-end sustainability report. Essentially, we are aligning our financial commitments with our goals. This is characteristic of a Sustainability Linked Loan; if we meet or surpass our targets, we benefit from lower financing costs. However, if we fail to meet our targets, the costs will be higher. The two metrics we disclosed are our GHG target and our diversity target. Regarding green financing, we haven’t issued a green bond, nor have we issued a corporate bond in quite some time—it's been over a decade, I believe. Instead, we have financed our wind farms and other renewable assets directly. Although they may not be labeled as green bonds, they are definitely financing tied to renewable projects, and investors view them as green financings.
Naji Baydoun, Analyst
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?
Todd Stack, CFO
We did not repurchase any shares this quarter, and while I can't recall the exact number of buybacks from last year, we have an NCIB program that we plan to extend into next year. Our capital allocation strategies will remain largely unchanged. However, it is true that our funds from operations available for activities outside of sustaining capital and dividends are increasing. We are continuously exploring mergers and acquisitions opportunities, and our development team has several projects in progress. As John mentioned, we are hopeful to secure at least one additional wind farm by the end of the year.
John Kousinioris, CEO
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. It's a great question, Patrick, and we discuss it frequently within the team. I believe the province's decarbonization will definitely require increased electrification moving forward, which excites us and presents significant opportunities. Our emphasis is on being client-centered, working closely with customers to understand and address their needs. This involves more than just providing a standard facility; we aim to help them strategize their future requirements and the solutions we can offer. We're pursuing this approach in all three countries where we operate. Regarding Alberta, I anticipate an increase in partnerships, particularly in project development where our focus is on contracted growth. This shouldn't present significant disclosure issues; to us, it's primarily about contracts and customers. In fact, we're seeking to minimize the merchant aspect of our operations moving ahead. However, in the realm of carbon capture, we might see more collaborations, which could add some complexity due to the substantial investment involved. Partnering with third parties for aspects like pipelines, injection, and the capture process will likely be necessary given the risks and capital required. Honestly, this will become a disclosure concern for us and a consideration for any organization involved in carbon-related generation.
Patrick Kenny, Analyst
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?
John Kousinioris, CEO
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.
Operator, Operator
And your final question comes from Chris Varcoe with Calgary Herald.
Chris Varcoe, Analyst
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?
John Kousinioris, CEO
Yes, let me address those points separately. I anticipate that we will see more partnerships moving forward. It makes sense, as some players in the province need power, environmental attributes, and decarbonization solutions. Companies like ours can provide those solutions, encouraging collaboration that benefits both parties. I believe this trend will persist, and our company is dedicating significant time and effort to adopt a customer and partner-oriented approach. This focus on service orientation is one of our internal priorities. Regarding renewables, we are definitely witnessing an increase in construction. Over time, this may lead to more variability in generation, as renewable sources can be unreliable; for instance, solar energy depends on sunlight, and wind energy relies on wind conditions, both of which are influenced by seasons and temperature. Our province has high baseload requirements, primarily driven by the industrial sector rather than residential demand. The challenge will be to ensure reliable generation through gas or future technologies like batteries and pumped storage, which can help manage the volatility associated with renewables. I believe we will see more renewables introduced, along with increased fluctuations in their daily supply. The ISO is already considering these issues from a policy standpoint, and we will participate in those discussions. It presents an exciting opportunity for us as we consider the future. I hope this provides some clarity. Yes, that's a great question. Ultimately, it will come down to economics. The credits are very helpful, and having those accelerated tax deductions will definitely enhance the viability of projects moving forward. As a company, we consider what other countries do, especially in the U.S., where the federal government invests significantly in R&D to develop cost-effective solutions that can be shared or partnered with the industry. These are the two main factors that matter. It’s essential to ensure that, from a financial standpoint, the private sector can contribute to meeting our greenhouse gas emission targets while maintaining reliable and low-cost power. It’s a complex equation, and if any aspect of it is mishandled, it could pose a challenge for the country.
Chiara Valentini, Conference Moderator
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.
Operator, Operator
Thank you for participating. This concludes today’s conference call. You may now disconnect.