Earnings Call Transcript - TAC Q4 2021

Operator, Operator

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. 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 website 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.

John Kousinioris, CEO

Thank you, Chiara. Good morning, everyone. And thank you for joining our 2021 annual results call. As part of our commitment toward 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 result 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 to 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-fired 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 by 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 project financing for 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 in 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. 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. These wind facilities will be our sixth and seventh in the US and combined will be our large US wind project. As I turn 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. 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 remains 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 our 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 a final investment decision on additional projects with BHP and others in the coming months.

Todd Stack, CFO

Thank you, John, and good morning, everyone. As John discussed, we had a record year and our diverse fleet delivered excellent results with $1.26 billion of adjusted EBITDA and record free cash flow of $562 million. This outstanding performance was driven by our Alberta fleet, which I'll discuss first. We dispatched our hydro, gas energy transition, and wind facilities as a portfolio to maximize benefits from baseload and peaking energy sales. For the full year, the fleet generated just under 13,000 gigawatt hours of electricity. Strong pricing throughout the quarter resulted in an average pool price for Q4 of $107 per megawatt hour and $102 per megawatt hour for the full year, significantly stronger than the average price of $47. Hydro’s ability to capture peak pricing was evident throughout the year, with average realized prices of $122 per megawatt hour, reflecting a 19% premium over the average spot price. Ancillary services from our hydro fleet remained a key contributor, with volumes generally meeting expectations. Overall, hydro gross revenues benefited from strong realized pricing for both energy and ancillary services and surpassed our expectations for the year, with the Alberta hydro fleet delivering over $300 million of EBITDA. The gas and coal units also achieved strong pricing of $102 per megawatt hour, attributable to both hedge positions and peaking merchant sales. Our wind fleet, which is not dispatchable, attained an average price of $63 per megawatt hour, marking one of our best years. Looking ahead to 2022, we have approximately 75% of the expected Alberta gas generation hedged at $75 per megawatt hour, and about 55% of our natural gas fuel requirements is hedged at $2.75 per GJ. In addition to our contracted production, we maintain a significant open position to realize higher pricing during peak market demand. During the fourth quarter of 2021, we adjusted our segmented reporting disclosures to align with our clean electricity growth plan and the recent conclusion of our transition away from coal. This resegmentation resulted in a unified gas segment, which includes our previous North American and Australian gas segments, alongside the Alberta thermal units converted to natural gas. We merged the Alberta Thermal and Centralia segments into the new energy transition segment, reflecting the transitional nature of these assets. This segment encompasses the Centralia facility, the remaining legacy Alberta Thermal assets that did not undergo boiler conversions, as well as all mine reclamation operations. No alterations were made to the hydro, wind and solar, or the energy marketing segments. The 2021 results and corresponding history have been restated according to our new segmentation. As I mentioned, our performance was primarily driven by the Alberta hydro fleet, which saw a threefold increase in adjusted EBITDA from $105 million in 2020 to $322 million in 2021, a remarkable result. Similarly, adjusted EBITDA from the new gas segment grew by 35% year-over-year, increasing from $367 million in 2020 to $494 million this year. Adjusted EBITDA from the energy transition segment declined by 24% year-over-year due to the retirement of Centralia unit one at the end of 2020. We anticipate further declines in this segment’s contribution 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 year of excellent results, generating $137 million in adjusted EBITDA, representing a 21% increase from 2020, which was also a strong year for the team. Overall, TransAlta had an exceptional year, and we are very pleased with the results across our diverse fleet and the realization of our Alberta generating portfolio's potential. I want to express gratitude to all our employees for their dedication and contribution toward achieving these outstanding results. Now, I’ll discuss our long-term trends for free cash flow and EBITDA performance alongside the ongoing financial strength of the company. For 2021, EBITDA exceeded our 2020 annual results by 36% and approached the high end of our 2021 guidance range. In January, we announced our 2022 EBITDA guidance range of $1.065 billion to $1.185 billion based on our estimated Alberta pricing of between $80 to $90 per megawatt hour. Our 2021 free cash flow also surpassed our 2020 annual results by 57% and exceeded our guidance range. We estimate 2022 free cash flow to fall between $455 million to $555 million, equating to free cash per share of $1.86 at the midpoint. Our balance sheet and liquidity remain very strong, closing the year with $2.2 billion of liquidity, including $947 million of total cash, positioning us well to fund our future growth pipeline, including our 480 megawatts of projects currently under or about to be under construction. Before I turn things back to John, I want to highlight TransAlta Renewables and our year-end results there. As you know, our operating wind and solar assets, as well as most of our contracted gas assets, are held within TransAlta Renewables and are fully consolidated into TransAlta’s results. Overall, TransAlta Renewables enjoyed a solid year of growth, adding four new assets to the fleet. Adjusted EBITDA rose with the inclusion of the Skookumchuck wind and Ada cogeneration facilities in Q1, along with the commissioning of wind rise and the acquisition of North Carolina solar facilities in the fourth quarter. Our year-end also marked the resolution of our contract dispute with FMG at South Headland, with FMG returning as a customer under a renegotiated PPA. We anticipate adjusted EBITDA at R&W for 2022 to range between $480 million and $525 million, representing roughly a 9% year-over-year growth. Increased EBITDA from our new assets will be partially offset by revenue losses at Kent Hills for the remainder of the year. We expect CAFD at the midpoint of our guidance range to decline compared to 2021 due to the impacts of Kent Hills, scheduled principal repayments on South Headland debt, and the settlement provision at Sarnia related to our outage in 2021. Given these cash flow impacts, we expect the company's dividend payout ratio for 2022 to be between 88% and 102%, exceeding our stated target range of 80% to 85%. The Kent Hills rehabilitation plan is on track and progressing as expected. We aim to begin construction in the second quarter of the year, with ongoing discussions with both New Brunswick Power and our lenders. We will provide additional updates on the progress as information becomes available. We also have robust liquidity at R&W for upcoming funding needs. In addition to our $700 million committed credit facility, we had $244 million in cash at the end of 2021. Based on R&W's current financial standing, we have ample capacity to continue funding the annualized common dividend at $0.94 per share. With that, I'll turn the call back over to John.

John Kousinioris, CEO

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 a 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 a highly attractive investment-grade value opportunity. First, our cash flows are resilient, and 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 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 decarbonization 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, and 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 us 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. I want to thank all our employees and contractors for the work that they have done to deliver our exceptional results in 2021. TransAlta has 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.

Chiara Valentini, Senior Vice President

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

Operator, Operator

Your first question will be from Dariusz Lozny from Bank of America.

Dariusz Lozny, Analyst

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.

John Kousinioris, CEO

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. 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.

Dariusz Lozny, Analyst

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?

John Kousinioris, CEO

Our target remains as it was from our Investor Day to get to 2 gigawatts by 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.

Operator, Operator

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

Maurice Choy, Analyst

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 for, and once we can follow as well that would alter be that delay or even have an impact on the growth of this plan to deliver that 2 gigawatts?

John Kousinioris, CEO

So Maurice, we are currently engaged in a significant growth initiative that involves nearly a billion-dollar investment this year. Our development and growth teams are actively working to ensure that our projects align with Power Purchase Agreements (PPAs). We do not construct projects without securing these agreements, as they are essential for the project's economic viability. We continue to experience strong demand for these products in Canada, the United States, and Australia. We have a clear plan to meet our targets, and if we find greater success in expanding our pipeline, we may speed up some developments. However, if inflationary pressures or a decrease in market demand arise, particularly from corporate interests shifting toward renewables, it could impact our progress. At this moment, we see consistent demand and PPA prices that have increased in response to inflation. From TransAlta’s viewpoint, our focus is on aligning customers with our projects as we develop them to meet our financial criteria.

Maurice Choy, Analyst

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?

John Kousinioris, CEO

So one of the things that we do, so that reference in the slide to securing long-term contracts, where Alberta's merchant fleet is directed to our merchant fleet. What a lot of people sometimes lose sight of is when we talk about our hedging position, roughly, Todd, I would guess 20 to 25% of the hedge position is based on contracts that we have with our C&I business, our commercial and industrial business. That's often multi-year contracts that provide contractedness to our merchant fleet and 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 their operations there with renewable energy, is an example. I think we're moving quite well, for instance, to contract the remaining merchant position at Garden Plain. We continue to develop our C&I business as a critical component going forward. So we set targets for the team, and they had a really great year last year increasing that position. 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. That's really what we're referring to there. Todd, I don’t know if you want to add any color...

Todd Stack, CFO

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.

Operator, Operator

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

Rob Hope, Analyst

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?

John Kousinioris, CEO

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.

Rob Hope, Analyst

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 on an EBITDA basis? Will this replace EBITDA that FMG was originally going to put into South Hedland or will it be something less than that?

John Kousinioris, CEO

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. 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.

Operator, Operator

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

John Mould, Analyst

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 at the end of 2025, what are you doing to maintain a position in that market beyond 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?

John Kousinioris, CEO

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; gas supply remains a challenge in the region. 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 in 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 are alternative technologies that we could bring to the generating facilities there that wouldn't be dependent on gas in the future, and we're working—in the early stages of working with some companies that could potentially provide a new technology approach that could see some of the residual infrastructure that we have there be utilized in the future. We continue to focus on potentially increasing our pipeline in terms of providing other renewables, particularly wind in the region to be able to meet some of the growing renewables needs of customers in the area. 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 storage at that facility, given some of the baseload generation that has traditionally been there with coal is fading away rapidly, and as that market transitions, having some of that storage to be able to help out is another opportunity.

John Mould, Analyst

And then maybe just moving on to the water charger project, just wondering a 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? How does that all get factored into the project?

John Kousinioris, CEO

As we develop the project, we'll clearly engage in discussions with Brookfield to make sure that we're clear about the impact on it. My sense of it right now would be that those revenues—this is at a first blush—would be part of the cash flows that go into the hydro purchase at this point in time. 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.

Operator, Operator

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

Andrew Kuske, Analyst

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? I ask the question in part because of your portfolio positioning and Alberta is somewhat unique, and you have a lot of optionality that comes out of that portfolio. How do you think about investing capital within the core Alberta market versus what you've done in the US and even Australia?

Todd Stack, CFO

Andrew, I would say our hurdle rates are evaluated based on the risk of each project. Clearly when we 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. I don't particularly see a big difference between the two hurdle rates in the two geographies. Similarly for Australia, we've seen very similar rates of return on projects that we execute down there.

John Kousinioris, CEO

Yes, we haven't—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, I would say, Todd, a base level of returns that we expect with adjustments for the quality of the counterparty, risk associated with the development, regulatory certainty, tenure, those kinds of things, more than issues relating to geography, if you see what I mean.

Andrew Kuske, Analyst

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?

John Kousinioris, CEO

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 in Southern Alberta, we haven't seen any impacts from a weather perspective. The units are enclosed in appropriate structures. The temperature seems to be within an appropriate operational zone. So we haven't seen any impacts. I know when we were developing our Northern Goldfields project, which has a storage component to it, the issues associated with the performance of the unit in—would be hot weather for sure seem to be pretty common, just going from memory from what we're experiencing in Southern Alberta, Andrew. We can get back to you with specifics though.

Operator, Operator

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

Naji Baydoun, Analyst

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 could talk about how those would fit into your existing portfolio in the province, if there's really the focus just on contracting all of them or if there's a bit of some merchant exposure?

John Kousinioris, CEO

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 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 a 180-megawatt battery project we were talking about earlier. That would typically be at least our own thinking around that is it would be much more of a merchant project. It could potentially be contracted, but I think it's more merchant. It would be operated in tandem with our hydro facilities. We also see it as an ancillary service provider in the market. Then SunHill 4 solar, which is a little 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 perspective, in terms of what we're pursuing in Alberta of significance, it's 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.

Naji Baydoun, Analyst

And a question on, I guess, what kind cost pressures you on some projects? Your overall goal is to deploy $3 billion to develop 2 gigawatts. You've already got 30% of that at a cost of roughly $1 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?

John Kousinioris, CEO

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. What we tend to do is, one, make sure our economics make sense, because they’re tied to the revenue stream that we would be getting from the contract at that time. We have seen that PPA prices, particularly in the US, have adjusted to 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. 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 into 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. 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. So far, I think the top line takeaway is we're able to maintain our returns.

Operator, Operator

Your next question will be coming from Mark Jarvi from CIBC.

Mark Jarvi, Analyst

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

John Kousinioris, CEO

I'll maybe start and then turn it over to Kerry, who can talk about the ISO process that we're going through. So we have contracted one of the four, we actually have a Bitcoin mining company, which has come onto 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. We would expect to have all of them contracted, certainly in the first half of this year, by and large, which then leaves—we would expect kind of EBITDA expectations for those to be kind of the 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. The ISO side, maybe Kerry, you can give Mark a bit of color in terms of the process there.

Kerry Wilks, EVP, Legal Commercial and External Affairs

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. To be in by the end of April, and the current estimate is that contracts will be awarded by the end of August. We should have much more certainty on what that will look like for us in the coming weeks, really.

John Kousinioris, CEO

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 ...

Todd Stack, CFO

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 …

Mark Jarvi, Analyst

And can you clarify the split between the industrial update and the ISO?

Todd Stack, CFO

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

John Kousinioris, CEO

I think of it as 60, 40, Mark.

Mark Jarvi, Analyst

And then Todd, any updated thoughts in terms of ... 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?

Todd Stack, CFO

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. I know our treasury team has 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.

Mark Jarvi, Analyst

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 of 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?

John Kousinioris, CEO

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 there is a merchant position, for example, Mark, that would supplement kind of where the EBITDA cash flows are.

Operator, Operator

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

Chiara Valentini, Senior Vice President

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.

Operator, Operator

This concludes your call for today. We would like to thank everyone for joining, and you may now disconnect your lines.