TransAlta Corporation (TAC) Q4 2021 Earnings Report, Transcript and Summary

[Call Started Abruptly] Miranda, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation’s Fourth Quarter 2021 Results Conference Call. All lines have been placed on mute to prevent any background noise [Operator Instructions]. Thank you. Ms. Valentini, you may now begin your conference.

Great. Thank you, Miranda. Good morning, everyone, and welcome to TransAlta's fourth quarter and 2021 year end conference call. With me 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 being webcast, and I invite those listening on the phone lines to view the supporting slides that are posted on our website. A replay of the call will be available later today, and the transcript will be posted to our Web site shortly thereafter. All of the information provided during this conference call is subject to the forward-looking statement qualification set out here on our Slide 2, detailed further 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 noted. The non-IFRS terminology used, including adjusted 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 our expectations of 2022. After these remarks, we will open the call for questions. And with that, let me turn the call over to John.

Thank you, Chiara. Good morning, everyone. And thank you for joining our 2021 annual results call. As part of our commitment to towards reconciliation, I want to begin by acknowledging that TransAlta's head office where we are today is located in the traditional territories of the Niitsitapi, 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 Metis Nation, Region 3. It's a pleasure today to share with you our ultimate achievements for 2021. TransAlta had a record year, and I'm extremely proud of the performance of our company and our employees and the outstanding progress we have made in advancing our priorities. In 2021, we delivered $1.26 billion of adjusted. EBITDA, a 36% increase over 2020 results. We also delivered free cash flow of $562 million or $2.07 per share, a 59% increase over 2020 on a per share basis, exceeding the top end of our restated guidance range. And in September, given our view of 2021 performance on our expectations for 2022, we increased our common share dividend by 11% to an annualized $0.20 per share. Our performance was driven by our ability to optimize our fleet and deliver operational performance, which enabled us to capture the higher prices experienced in Alberta, demonstrating the underlying value of our diversified fleet. In addition to the strong results in our generation fleet, energy marketing also had an excellent trading results across our US power and natural gas desks, where we capitalized on our deep knowledge of North American power markets and captured market opportunities. In 2021, we were able deliver on all of our key priorities, particularly in the areas of growth and carbon transition. In terms of carbon transition, the three year transition plan that we started in 2019 to phase out coal fire generation in Canada has been realized. We completed our final coal to gas conversion and are now fully off coal in Canada and running on lower carbon emitting natural gas. This marks the achievement of an important milestone nine years ahead of the government target of 2030. Our coal transition is among the most meaningful carbon emission reduction achievements in Canada. Overall, we've reduced our annual CO2 emissions 29 million tons since 2005, including 3.9 million tons in 2021, a 24% reduction year-over-year. And we've adopted a more ambitious target for emissions reductions, targeting a 75% CO2 emissions reduction by 2026 from 2015 levels, and we're proud to be the first publicly traded electricity company in Canada, committed to setting a science based emissions reduction target. Shifting to growth. Our development team secured 600 megawatts of renewables growth during the year representing 30% of our five year growth target with growth in each of our three core markets in 2021. We achieved commercial operation and completed a project financing our wind rise, our largest wind facility in Alberta, and we continue to monitor new and emerging technologies for deployment in the back half of the decade and beyond. We recently made an investment in Ekona to advance the commercialization of their hydrogen technology platform. If successful, this technology would produce cleaner and lower cost hydrogen and has the ability to be cited wherever natural gas infrastructure exists today. I remain confident in our ability to deliver on the remainder of our 2 gigawatts clean electricity growth plan, and we are targeting to reach investment decisions on another 400 megawatts of renewables growth in 2022. We ended the year with record liquidity and we are well positioned to fully fund our renewable growth pipeline. Strong performance from our hydro fleet, coupled with the addition of wind rise and the North Carolina Solar portfolio led to EBITDA contribution from renewables and storage assets increasing from 35% in 2020 to 43% in 2021. As I mentioned, in 2021, we secured 600 megawatts of growth projects across Canada, the US and Australia. A solid start to our 2 gigawatts target by 2025. This represents a capital investment of approximately 1 billion and delivers 30% of our five year target on a megawatt basis. Combined, these projects will contribute just under 100 million and EBITDA once fully operational, achieving 40% of our five year EBITDA targets. We closed the North Carolina Solar acquisition in November, which is already in service. And we currently have 178 megawatts of projects actively under construction in Alberta, and in Western Australia. And later this year, we will start construction on our White Rock project in Oklahoma. All of our construction projects are expected to be funded with existing liquidity. In December, we entered into two long term PPAs with a new investment grade customer for the full output from the 300 megawatt White Rock wind projects in Oklahoma. The delivery of low cost reliable and clean energy from White Rock supports our customers’ sustainability goals, and will nearly double our wind fleet in the United States from 375 megawatts to 675 megawatts. Commercial operation is expected to be achieved in the second half of 2023. And these wind facilities will be our sixth and seventh in the US, and combined will be our large US wind project. As I turned down to our US development pipeline, you can see that the White Rock project has moved from the advanced developing category into the under construction category. We still have over 800 megawatts of potential development sites in the US across a number of projects in several key markets. Our most advanced right is now the 200 megawatts Horizon Hill project in Oklahoma. And we're pleased with the progress that our team is making as they advance that project towards the final investment decision. The demand for renewables remain strong in the US and we see plenty of opportunity for growth in that market. We're looking at a number of opportunities to grow our development pipeline in the US, and expect to add some excellent sites to our pipeline over the course of 2022. We remain disciplined on growth in Canada, including here in Alberta. We've shifted away from merchant baseload gas generation, and are now exploring opportunities to maximize the value of our Hydro and Wind fleets, with a new focus on battery storage as well as Wind and Solar. This includes our water charger project, where we've recently filed her application with the Alberta Utilities Commission. The project will build a 180 megawatt battery storage facility near the ghost reservoir on the whole River. The batteries would be charged from our existing hydroelectric facility there and dispatched to the provincial power grid when demand for power is high. We continue to develop a number of wind development sites in Alberta as we see continued demand for renewable PPAs in the market from corporate customers. Our team is actively seeking opportunities to contract our sites and advance those projects into the construction phase. In Australia, we've moved the 14 megawatt Mount Keith capacity and transmission expansion projects to the advanced development stage. We're seeing growing opportunities in Western Australia in support of our remote mining customers. Our team is developing customized clean power solutions to meet the ESG objectives of our customers in the most cost effective manner. We're advancing several opportunities there and we expect to reach final investment decision on additional projects with BHP and others in the coming months. I'll now turn it over to Todd to take us through our financial results for the year.

Thank you, John and good morning, everyone. As John discussed, we had a record year [Technical Difficulty] and our diversified fleet delivered excellent results with $1.26 billion of adjusted EBITDA and record free cash flow of $562 million. This stellar performance was led by our Alberta fleet, which I'll discuss first. The hydro gas energy transition and wind facilities are dispatched as a portfolio in order to benefit from baseload and peaking energy sales. And for the full year, the fleet generated just under 13,000 gigawatt hours of electricity. The strong pricing throughout the quarter resulted in the average pool price for Q4 settling at $107 per megawatt hour and at $102 per megawatt hour for the full year. This is significantly stronger than the average price of $47. The ability of hydro to capture peak pricing was demonstrated throughout the year with average realized prices of $122 per megawatt hour, which represents a 19% premium over the average spot price. Ancillary services from our hydro fleet continued to be an important contributor to the hydro business and volumes were broadly in line with expectations. Overall hydro gross revenues benefited from strong realized pricing for both energy and ancillary services and exceeded our expectations for the year with the Alberta hydro fleet delivering over $300 million of EBITDA. The gas and coal units also realized strong pricing of a $102 per megawatt hour, which is a combination of both the hedge positions as well as from peaking merchant sales. Our wind fleet, which is not dispatchable realized an average price of $63 per megawatt hour, which was one of our strongest years ever. And looking forward to 2022, we have approximately 75% of the expected Alberta gas generation hedged at $75 per megawatt hour and roughly 55% of our natural gas fuel requirements is hedged at $2.75 per GJ. In addition to our contracted production, we continue to retain a significant open position in order to realize higher pricing during times of peak market demand. During the fourth quarter of 2021, we change our segmented reporting disclosures to align with our clean electricity growth plan and the recent completion of our off call transition. Through this resegmentation, we now have a single gas segment, which includes the previous North American and Australian gas segment and it also includes the Alberta thermal units that were converted to natural gas. We combine the Alberta Thermal and Centralia segments into the new energy transition segment, which is reflective of the transitory nature of these assets. This segment includes the Centralia facility, the remaining legacy Alberta Thermal assets that did not undergo boiler conversions, as well as all of the mine reclamation operations. No changes were made to the hydro, wind and solar or the energy marketing segments. The 2021 results and corresponding history have been restated to reflect our new segmentation. As I mentioned, our performance was led by the Alberta hydro fleet, which delivered a threefold increase in adjusted EBITDA from $105 million in 2020 to $322 million in 2021, a fantastic result. Similarly, adjusted EBITDA from the new gas segment also increased 35% year-over-year from $367 million in 2020 to $494 million this year. Adjusted EBITDA from the energy transition segment decreased 24% year-over-year due to the retirement of the Centralia unit one at the end of 2020. And we expect contribution from this segment to decline further in 2022 with the retirement of Keypills unit one at the end of 2021 and Sundance unit four in April of this year. Our energy marketing team also delivered another consecutive year of outstanding results. We delivered $137 million in adjusted EBITDA, a 21% increase to 2020, which was also a great year for the team. Overall TransAlta delivered an exceptional year and are we are very pleased with both the results across our diversified fleet and the realization of the potential of our Alberta generating portfolio. I want to thank all of our employees for their dedication and contribution in achieving these fantastic results. I'm going to turn now to [highlight] our longer-term trends for free cash flow and EBITDA performance and the continuing financial strength of the company. For 2021, EBITDA exceeded our 2020 annual results by 36% and delivered towards the top end of our 2021 guidance range. In January, we announced our 2022 EBITDA guidance range of $1.065 billion to $1.185 billion. Our 2022 guidance is based on our estimate for Alberta pricing of between $80 to $90 per megawatt hour. Free cash flow for 2021 also exceeded our 2020 annual results by 57%, and exceeded our guidance range. Our free cash for 2022 is estimated in the range of $455 million to $555 million, which equates to free cash per share of $1.86 at the midpoint. Our balance sheet and liquidity remained very strong. We closed the year with $2.2 billion of liquidity, including $947 million of total cash. This positions us extremely well to fund our future growth pipeline, including our 480 megawatt of projects under or soon to be under construction. Before I turn things back to John, I like to turn to TransAlta Renewables and our year end results there. As you were aware, our operating wind and solar assets as well as the majority of our contracted gas assets are held within TransAlta Renewables and are fully consolidated in TransAlta’s results. Overall, TransAlta Renewables had a solid year for growth by adding four new assets to the fleet. The company’s adjusted EBITDA increased with the additions of the Skookumchuck wind and Ada cogen facilities in Q1, as well as the commissioning of wind rise and the acquisition of the North Carolina solar facilities both in the fourth quarter. Our year end also marked the conclusion of our contract dispute with FMG at South Headland. FMG has returned as a customer at South Headland and is now taking power under renegotiated PPA. For 2022, we expect adjusted EBITDA at R&W to be between $480 and $525 million, representing approximately a 9% growth year-over-year. Higher EBITDA from our new assets will be partially offset by the loss in revenues at Kent Hills for the balance of the year. We expect CAFD at the midpoint of our guidance range will decline relative to 2021 due to the impact of Kent Hills, scheduled principle repayments on the South Headland debt, and the provision settlement at Sarnia relating to our outage in 2021. Given these cash flow impacts in 2022, we expect the company's dividend payout ratio to be between 88% and 102%, exceeding our stated target range of 80% to 85%. The Kent Hills rehabilitation plan is on track and proceeding as expected. We are targeting to begin construction in the second quarter of the year, and discussions are ongoing with both New Brunswick power and our lenders. We will look to share additional information on progress as it becomes available. We have strong liquidity at R&W for the upcoming funding needs. In addition to our $700 million committed credit facility, we had $244 million of cash at the end of 2021. And based on R&W’s current financial position, we have sufficient capacity to continue to fund the annualized common dividend at $0.94 per share. With that, I'll turn the call back over to John.

Thanks Todd. In 2022, we'll continue to focus on progressing our key goals, which include reaching a final investment decision on 400 megawatts of additional clean energy projects across Canada, the United States and Australia, achieving COD on the garden plain, wind and the garden clean wind and northern goldfields solar projects, progressing construction on our White Rock wind projects. Expanding our development pipeline with the focus on renewables and storage, recontracting with the remaining industrial customers and the ISO at Sarnia, progressing the rehabilitation of Kent Hills’ wind, delivering EBITDA and free cash flow within our guidance ranges and advancing our ESG objectives, which includes reclamation work at Highvale and Centralia, providing indigenous cultural awareness training to all of our employees, and achieving at least 40% female employees by 2030. I'd like to close by highlighting as I always do, what I think makes TransAlta highly attractive investment integrate value opportunity. First, our cash flows are resilient, that are supported by a high quality and highly diversified portfolio, as underscored by our record year in 2021. Our business is driven by our contracted wind portfolio, our unique reliable and perpetual hydro portfolio and our efficient gas portfolio, all of which are complemented by a world class asset optimization and energy marketing capabilities. Second, we're a clean electricity leader with a focus on tangible greenhouse gas emission reductions. Our decarbonisation journey has resulted in greenhouse gas reductions that represent 9% to 10% of Canada's 2030 target. In 2021, we reduced our annual CO2 emissions by a further 3.9 million tons adopted a more ambitious emissions target of 75% by 2026 from 2015 levels that are committed to setting a science based emissions reduction target. In addition, our focus on removing systemic barriers through our commitment to equity, diversity and inclusion and good governance places as well ahead as a leader in ESG. Third, we have an extensive and diversified set of growth opportunities, which includes a pipeline of advanced stage projects, and a talented development team focused on realizing its value. Our execution is on track and we delivered on that growth pipeline in 2021. Already securing 600 megawatts of renewables and storage growth. Fourth, our company has a strong financial foundation, our balance sheet is in great shape and we have ample liquidity to pursue growth. Finally, our people. Our people are our greatest asset. And I want to thank all our employees and contractors for the work that they have done to deliver our exceptional results in 2021. We're committed to a company culture where everyone belongs and can bring their best authentic selves to deliver great results for our company. TransAlta has had an exciting time in its evolution and we're well positioned for the future as a leader in low cost reliable and clean electricity generation focused on serving and meeting the needs of our customers. Thank you. I'll turn the call back over to Chiara.

Thank you, John. Miranda, would you please open our questions from the analysts and media?

[Operator Instructions] Your first question would come from Dariusz Lozny from Bank of America.

I just wanted to maybe discuss the US development pipeline a little bit. I noticed comparing against your Investor Day materials there's been a little bit of movement there, looks like a couple of solar projects are no longer on that slide perhaps a couple of them moved back to 26 from a slightly earlier timeframe. Could you maybe talk about the drivers of those changes? Is it supply chain related potentially? Are there inflationary pressures driving any of that? Just maybe talk about some of the puts and takes as that pipeline developed, if you could.

It's really driven by sort of the continuous evaluation that our development team does in terms of seeing which projects are the best ones that we have to actually advance. And it's a continual sort of iterative process that our development team has in assessing which ones we're going to prioritize and which ones are further away or less likely to proceed. It isn't really at this point based on any of the challenges that we see from a supply chain or an inflationary perspective, it's really driven more by the potential of projects and where we think that we'll be able to slot them in from a development perspective.

And maybe just staying on that topic. Bearing in mind, it seems like you guys are advancing some of the US Oklahoma projects pretty well. I just want to confirm, is the goal still remain to add 2 gigawatts by 2025 or is there perhaps some flexibility by when those 2 gigawatts might be online?

Our target remains as it was from our Investor Day to get to 2 gigawatts from 2025 as we progress and we develop our development pipeline, and we continue to sort of execute as well as we can from growth we'll reevaluate the target. But our target right now remains as it was in our investor day in September of last year.

Your next question will come from Maurice Choy from RBC Capital Markets.

My first question is just to follow up on the earlier question about your clean energy growth plan. You mentioned that small changes to the pipelines were not driven by the supply chain inflation pressure. So maybe just bigger picture. Could you just point to maybe the top two things that you watch out for, and once we can follow as well that would alter be that delay or even -- has the growth of this plan to deliver that 2 gigawatt?

So Maurice, right now, I think we -- look we're in the middle of basically a billion dollar build out from growth largely in 2023. Our developing teams and our growth teams are busy. We tend to be focused on matching our development projects with PPAs. We don't build projects on spec. They're always driven from having a PPA that really underpins the economics of the project as we go forward. We continue to see robust demand both in Canada and the United States and Australia for those product. And really we don't see -- I mean, I think we have a natural progression in terms of meeting the target that we've set. If we're more successful in terms of increasing our pipeline than our current approach, you might see us accelerate some of the development that we do in terms of something that that could impact, in this there are inflationary pressures or something happens to the demand that we're seeing in the market, that kind of reduces that sort of drive that we're seeing from the corporate sector in the sense of a shift to renewable that might affect kind of the progression. But right now we're not seeing that we're seeing sort of steady demand going forward. We're seeing PPA prices that have adjusted and actually gone up to reflect some of the inflationary pressures that we're seeing. So for at least from a TransAlta perspective, it's about finding customers to match with our projects as we go through and develop them in a way that meets our threshold hurdle rates.

And maybe the second question is more of a bigger picture question. On Slide 16 for your 2022 priorities, you mentioned that you're looking to secure long-term contracts for Alberta merchant fleet. Maybe firstly, what projects are you referring to on these? And the bigger picture question is how do you view your profile in terms of contracted cash flow versus merchant today and where would you like to be?

So one of the things that we do, so that reference in the slide to securing long-term contracts, where Alberta merchant fleet is directed to our merchant fleet. What a lot of people sometimes lose sight to the fact is when we talk about our hedging position, roughly Todd, I would guess 20 to 25 of hedge position is based on contracts that we have with our C&I business, our commercial and industrial business. And that's often multi-year contracts that provide kind of contractedness to our merchant fleet and kind of underpin our hedging efforts that are there. When we think of the kinds of other contracts that we're looking for, I think, the recent transaction that was announced with Lafarge, for example, -- where we're powering with renewable energy their operations there, as an example, I think we're moving, I think quite well for instance to contract the remaining merchant position at Garden Plain. And we continue to develop our C&I business as a critical component going forward. So we set targets for the team, they had a really great year last year increasing that position. And our view is to ensure that we have a good contracted position balanced with ensuring that we have enough length in the market to take advantage of higher pricing when it occurs. So that's really what we're referring to there. Todd, I don’t know if you want to add any color…

I was just going to remind Maurice, that as part of the Sun 5 project, we did take on a long-term contract there with a reputable counter party. Now that contract doesn't start until 2023, but those are fantastic contracts that will again, boost our overall contractedness across the company and especially here in Alberta.

Your next question will come from Rob Hope from Scotia Bank.

A bit of a larger kind of question conceptual in nature. How are you viewing the relationship between R&W and TransAlta these days? We've seen the evaluation premium of R&W compress, and you're looking to keep White Rock as a TA project there as well. How are you viewing R&W as a funding vehicle and is some of the strategic comparative still there to keep it a standalone vehicle?

TransAlta renewables for us remains the vehicle where we have a lot of our contracted natural gas and renewables assets. Today, we continue to view it as a vehicle that could help fund, our growth we’re mindful of continuing to consider dropdowns to it. I mean, Garden Plain is a good example of the kind of project that we would consider dropping down to it. The strategies of the two companies are converging for sure that is something that we're very mindful of and we continue to evaluate and reevaluate kind of the positioning of the two. But right now, it's a core pillar for TransAlta and it remains as is in terms of our current strategy.

Maybe something a little bit more granular there as well, the FMG settlements? Can you maybe just talk to what the impact would be going forward EBITDA basis? Will this replace EBITDA that FMG was originally going to put into South Hedland or will it be something less than that?

The settlement is confidential actually. So we can't disclose any of the terms that we have with FMG going forward. So I wish I could give you more information. I can say that we're happy to have the dispute over with FMG and bring them back into the fold as a good customer for the facility there. And in fact, it was one of the reasons we had a bit higher sustaining capital spend, we ended up buying a spare engine for South Hedland to make sure that it would meet the needs of FMG as we go forward. But in terms of the specific deals, as specific terms rather of settlements, I can't actually give them to you.

Next question would be coming from John Mould at TD Securities.

Maybe I’d just like to start with your business in the Pacific Northwest and your longer term outlook there. Beyond the retirement of the second unit, essentially at the end of 2025, what are you doing to look to maintain a position in that market beyond that, that closure? Recognizing there are gas supply constraints in the area. Is there a gas conversion opportunity? Are there other renewable opportunities in that area that maybe you're looking at what's on your potential with some things you do there?

So doing a coal to gas conversion of Unit 2 is challenging. I think for a number of reasons. I think you alluded to them, I think gas supply remains a challenge in the region. And candidly, even permitting is probably a challenge. We continue to evaluate what we could potentially do with the site and really are thinking of it in a couple of ways. One, there is opportunity to add some renewables for example, we've looked at solar at that part of the world. So we're on the physical location of the site in the past and continue to work to see what we could do there. We're looking to see whether there's alternative technologies that we could bring to the generating facilities there that wouldn't be dependent on gas in terms of going forward and working -- in the early stages of working with some companies that could potentially provide sort of a new technology approach that could see some of the residual infrastructure that we have there be utilized in the future. And we continue to focus on potentially increasing our pipeline in terms of providing other renewables particularly wins in the region to be able to meet some of the growing renewables needs of customers in the region. I'd also be remiss if I didn't mention that we have looked at and continue to evaluate the importance of and the potential of maybe storage at that facility given some of the baseload generation that has traditionally been there with coal is fading away pretty rapidly and as that market transitions, having some of that storage to be able to help out is another opportunity.

And then maybe just moving on to the water charger project, just wondering little bit if you can talk through a little bit the interplay there with the Brookfield hydro investment. Would that initiative get held as under the umbrella of the TA Alberta hydro unit in which Brookfield will be able to secure an interest? And how does capital costs work there and then the EBITDA formula that determines. Brookfield just take in those assets does that -- how does that all get factored into the project?

As we develop the project, we'll clearly engage in discussions with Brookfield to kind of make sure that we're clear about the impact on it. My sense of it right now would be that those revenues and this is at a first blush John would be part of the cash flows it go into the hydro purchased at this point in time. And the capital would be for TransAlta’s account as we develop it, and would just then be factored into the purchase equation of the interest when they back into it at this point in time. So hopefully that gives you a bit of a sense.

Your next question would cover from Andrew Kuske from Credit Suisse.

I guess as you start to grow the portfolio of assets in two different geographies, how do you think about hurdle rates across the geographies and asked the question in part cause of your portfolio positioning and Alberta is somewhat unique, and you have a lot of optionality that comes out of that portfolio. And so how do you think about investing capital within the core Alberta market versus what you've done in the US and even Australia?

Andrew, I would say, our hurdle rates are evaluated based on the risk of each project. And clearly when we think about -- when I think about the projects in the US versus the projects here in Alberta, we're effectively developing similar risk profile assets, renewables profile, long term contracts with good counterparties. And so I don't particularly see a big difference between the two hurdle rates in the two -- in the geographies. And similarly for Australia, we've seen very similar rates of return on projects that we execute down there.

Yes, we haven't Andrew, I'm not sure. I'm just thinking of sort of our own process given that we had over the course of the last year, we didn't see much variation based on the geography of the investment. It was driven more off of kind of I would say, Todd, a base level of returns that we expect with adjustments for the quality of the counter party, risk associated with the development, regulatory certainty, tenure, those kinds of things, more than issues relating to geography, if you see what I mean.

And then maybe for my second question, I guess maybe a bit more geeky and some of the technical stuff, and as we think about just battery usage to supplement certain assets. What are you seeing or what are you getting from OEMs as far as battery performance in colder weather, maybe Alberta versus hotter weather climates like what you experience in Australia?

The only I can say, I mean, that's a question that I think we could probably get back to you on with some of our folks from the development side. I think all I can say is when we look at our wind charger projects, sort of in Southern Alberta, we haven't seen any impacts from a weather perspective. The units are sort of enclosed in appropriate sort of structures. The temperature seems to be within an appropriate operational zone. So we haven't seen any impacts. And I know when we were developing our Northern Goldfields project, which has a storage component to it the issues associated with kind of the performance of the unit in would be hot weather for sure seem to be pretty com just going from memory from what we're experiencing in Southern Alberta, Andrew. We can get back to you with specifics though.

Your next question will come from Naji Baydoun from iA Capital.

Your target for 400 megawatts this year of new projects, you have a lot of projects or some of the most advanced ones in Alberta. I'm just wondering if you talk about how those would fit into your existing portfolio in the province, if there's -- really the focus just is on contracting all of them, or if there's a bit of -- some merchant exposure?

When I think of Alberta and I think of kind of the projects that we're developing, there's really four that are kind of significant ones from my perspective. The biggest one is Ripplinger, which is a 300 megawatt wind farm in Southern Alberta, that would be something that we would be looking to contract. Tempest, which is just going to from memory a 100 megawatt wind farm is something that we're also focused on developing more rapidly and are actively working that wind farm, that too would be contracted. And I think of kind of something that might be a little bit more merchant, I think of water charger, which is 180 megawatt battery project we were talking about in a little bit earlier, that would typically be at least our own thinking around that is it would be much more of a merchant project. It would be -- we could potentially contract it, but I think it's more merchant. It would be operated in tandem with our hydro facilities. And we also see it as ancillary service provider in the market. And then SunHill 4 solar, which is a little bit of a later stage development up there. We would also be looking to have that contracted. So right now, when I look at kind of the leaders, at least from my own perspective, in terms of what we're pursuing in Alberta of significance, it sort of three quarters would be contracted with the merchant being more oriented towards being tied with hydro and being something that we can optimize through the optimization team that we have with ancillary services and the like.

And a question on, I guess, what kind cost pressures you on some projects? So your overall goal is deploy 3 billion to develop 2 gigs. You've already got 30% of that at a cost of roughly a billion. So maybe you can just remind us, even if you go a bit over budget here, what are some of the levers that you have to maintain your returns, both on the project and the portfolio level?

So we have seen some inflationary pressure, but we don't -- we always do our projects tied to -- and I'll set water charger aside, tied to having a power purchase arrangement, which is tied to the project. And what we tend to do is, one, make sure our economics make sense, because it's tied to sort of the revenue stream that we would be getting from the contract at that time. And we have seen that PPA prices particularly in the US have adjusted to sort of reflect some of the increased costs that we see from a construction perspective. So we're holding the returns if you see what I'm saying, number one. Two, we are very much focused on at the time that we sign a PPA, we contemporaneously really fix the cost of as much of the project as we can. And when we mean as much as we can, we mean 90% of the projects with both in terms of securing the turbines, for example, at a fixed price entering as EPC contracts with a fixed price arrangement, so we're locking in as much as we can. The other stuff that we're doing is the supply chain to your points becoming more of an issue, at least right now. So we're looking at being more specific about what jurisdictions the equipment is coming from, whether it's coming from Asia, or whether we're sourcing products from North America or from Europe is something that we've actually specified in connection with our White Rock project. And finally, we're considering early delivery of some components, to mitigate against inflationary pressures and make sure that we are able to maintain the timing that we need to get things done. So hopefully, that gives you a bit of a picture of the levers that we have, that we've been pulling as we develop our process. But so far, I think the top line takeaway is we're able to maintain our returns.

[Operator Instructions] Your next question will be coming from Mark Jarvi from CIBC.

Talking about one of your targets for this year is it starting next contract. Do you have a sense of when our point and you'll have some clarity on that. And the point now is having some indication or bookends in terms of potential EBITDA haircut or whether they'll be sort of pro forma pull through contracting?

I'll maybe start and then turn it over to Kerry, who can talk about the ISO process that that we're going through. So we have contracted one of the four, we actually have a Bitcoin mining company, which has come on to the park that we have there, which is also contributing to some of the cash flows that we're seeing. So we're happy to see that. In terms of the other three major industrial customers that were there, we are expecting to have those. They're in various stages of negotiation, but fairly advanced, I would say. And we would expect to have all of them contracted, certainly in the first half of this year, by enlarge, which then leaves -- and we would expect kind of EBITDA expectations for those to be kind of a same or maybe even slightly better than what we currently have from that segment there. It's an important facility for a lot of the customers that we have in that Sarnia region. And then on the ISO side, maybe Kerry, you can give Mark, a bit of color, in terms of the process there.

So the Ontario government is actually fairly advanced in how they're structuring RFP process, we were required to register at the end of February, which we did, and they're still finalizing what the rules and the contract will look like. But -- to be in by the end of April, and the current estimate is that contracts will be awarded by the end of August. So we should have much more certainty on what that will look like for us in the coming weeks really.

And I think Kerry those would be for 2026 and five year periods post 2026. In terms of what that means from a cash flow perspective, I mean, I think it will probably see a bit of a reduction in the EBITDA that would come from the ISO contract and [Multiple Speakers]…

Primarily from the ISO contract and Kerry, they've set caps on what they expect for bids through that new capacity auction program that they're going…

And can you -- again to the split between the industrial update and the ISO…

It's probably about 30% to 40% from the industrial customers and then probably 60% from the ISO contract.

I think of it as 60, 40, Mark.

And then Todd, any updated thoughts in terms of [Technical Difficulty] this year in terms of whether or not you just repay it and given the strong cash position or would you look to refinance or what’s your strategy there?

I think right now we have I think over a billion dollars of capital committed for construction on new facilities. So our expectation is to refinance that maturity. We likely won't wait until November. And I know our treasury team is actually hedged a lot of the underlying over the course of the last year. So we're in good shape on the underlying reissue, but I think we will be refinancing it [Multiple Speakers] maturity.

And then last one, John, you talked about being able to preserve margins, even though some cost pressures and just looking at White Rock, the CapEx numbers are up a bit there. Can you just remind us again in terms of higher EBITDA projections versus a couple months ago? Is that fully recovered through the PPA or is there some sort of merchant component of that and just your certainty on sort of the ability to offset CapEx with higher EBITDA at White Rock?

No, I mean, I think that is based on the PPA contract that we see there a bit of variation, depending on the PPC treatment I think, that we get depending on where that lands in the US. But the -- there is an merchant position for example, mark that would supplement kind of where the EBITDA cash flows are.

There are no further questions at this time. Please go ahead.

Great. Thank you everyone. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the TransAlta Investor Relations team. Thank you, and have a great day.

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