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spk04: Good morning. At this time, I would like to welcome everyone to TransAlta Corporation's first quarter 2023 results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, please press star followed by the number two. Thank you. Ms. Bautini, you may begin your conference.
spk08: Great. Thank you, Sergio. Good morning, everyone, and welcome to TransAlta's first quarter 2023 conference call. With me today are John Cusignoris, President and Chief Executive Officer, Todd Stack, EVP Finance and Chief Financial Officer, and Kerry O'Reilly-Welks, EVP Legal, Commercial, and External Affairs. Today's call is being webcast, and I invite those listening in 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 qualifications set out here on slide 2, and 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 Tal will provide an overview of the quarter's results, and after these remarks, we will open the call for questions. And with that, let me turn the call over to John.
spk09: Thank you, Kiara. Good morning, everyone, and thank you for joining our first quarter results call for 2023. As part of our commitment 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 Nitsitapi, the people of the Treaty 7 region in southern Alberta, which includes the Siksika, the Pikani, the Kainai, the Tsutsina, and the Stony Nakoda First Nations, as well as the home of Métis Nation Region 3. TransAlta had an exceptional first quarter. We're proud of the overall performance of our company and our employees. We delivered $503 million of adjusted EBITDA, a 94% increase over our Q1 2022 results, and free cash flow of $263 million, or $0.98 per share, a 145% increase over Q1 2022 results on a per share basis. Both metrics beat our expectations for the quarter. Overall, our results benefited from continuing strong power prices in Alberta and Mid-Sea, complemented by strong operational performance from our fleet and the success of our asset optimization and hedging strategies. The Alberta market was impacted by stronger power prices in adjacent markets, which lowered net imports into Alberta, encouraged exports of power from Alberta to the Pacific Northwest, and together with increased outages in the province, allowed us to increase overall production from our Alberta gas fleet by 40% as compared to the same quarter last year. Our higher capacity factors in the gas fleet, coupled with lower realized gas prices, delivered higher gross margins for our portfolio compared to Q1 2022. Our Alberta hydro and gas merchant portfolio also benefited from our large and calculated power hedge positions in the quarter. Our overall availability was strong at 92%, despite our ongoing outage at Kent Hills, and was driven by the great performance of our Alberta gas fleet, which achieved 96% availability. Highly important for delivering on our peaking capacity strategy within the Alberta market. Apart from Kent Hills, our performance was partially offset by weaker availability in our wind fleet due to a lengthy outage at wind rise from a transformer failure due to a manufacturing defect, while snow storms and Hydro-1 transmission outages impacted our Ontario wind fleet. During the quarter, we delivered on a number of key priorities. On the growth side, our development team continues to expand our pipeline, adding another 286 megawatts of renewables growth project. The rehabilitation of Kent Hills is progressing well with 13 towers fully reassembled and two-thirds of the foundations poured and completed. And I'm pleased to be able to say that commissioning activities have now commenced with the first turbine energized and currently in its final stages of commissioning. During the quarter, we returned $36 million of capital back to shareholders through the buyback of 3.2 million shares. We continue to buy back shares in April, returning an additional $29 million of capital back to our shareholders. In late March, we entered into an automatic share purchase plan to facilitate additional purchases under our normal course issuer bid. This channel now allows us to take advantage of market opportunities, especially in period when the company is in blackout. Our current NCIB program is set to expire in May, and we intend to renew the program with the TSX before it matures. And finally, with another quarter of strong cash flow, our balance sheet position is strong with excellent liquidity and cash on hand to fund our growth projects. Turning to our clean electricity growth plan, to date we've secured 800 megawatts of growth projects across Canada, the US and Australia, representing 40% of our two gigawatt target by 2025. We currently have 678 megawatts of projects in the construction phase, all of which are expected to be online by the end of 2023. These projects will contribute approximately $149 million in contracted EBITDA, once fully operational, or approximately 47% of our five-year incremental annual EBITDA target of $315 million. Here in Alberta, our 130-megawatt garden plane wind farm is nearing completion. All 26 of the turbines have been assembled, and over half the units are in operation today. We expect to finalize commissioning of the last turbines and achieve COD later this month. We expect the wind farm to contribute 15 million of contracted EBITDA annually, and so far, we're pleased with the turbine performance. In collaboration with Siemens, we've applied many learnings from the startup of Windrise to the project to ensure that turbine availability meets our expectations right out of the gate. Our Northern Goldfields project is also reaching final completion. solar panel installation is complete, and interconnection of the facility into our remote network is underway. The team is now installing the battery system and setting up the control system and expects to move into the energization and commissioning phase over the next few weeks. We're aiming to reach commercial operation by the end of the second quarter. This project will deliver approximately 9 million of adjusted EBITDA. And our two Oklahoma wind projects also continue to progress well, and we expect them to reach final completion by the end of this year. All of the turbine components have been delivered for both projects, and at Horizon Hill, we have completed the collector system and foundation work and have started to assemble turbines. At White Rock, over half the foundations have been completed, and the collector system installation is well advanced. We've just started to erect turbines at this site as well. These projects will contribute adjusted EBITDA of over $100 million annually. Our Mount Keith 132 KV expansion project is also well underway. Construction activities have commenced and are on track to be completed in the latter half of 2023. This project will contribute approximately $6 million of adjusted EBITDA annually. As you know, we're targeting to reach investment decisions on 500 megawatts of growth this year through a combination of greenfield and potential M&A activities. Within our development pipeline, we currently have 374 megawatts of advanced stage generation and transmission projects that we're advancing towards final investment decisions as we progress through the year. They represent additional growth capital of approximately $600 million. Our 94-megawatt Southern Cross capacity and transmission expansion projects in Western Australia are advancing well, and we expect to make final decisions together with our customer, BHP Nickel West, later this year. Our 180 megawatt water charger battery storage project in Alberta also continues to advance. And with the recently announced federal budget, we see opportunities under various programs together with our indigenous partners to pursue new funding channels to support the project as we work towards making a final investment decision. And finally, our 100 megawatt Tempest wind project in Alberta is also making progress. We're actively marketing this opportunity with multiple corporate customers. We continue to advance our growth pipeline in 2023. As you recall, in 2022, we added almost 2 gigawatts to our renewable development pipeline across our regions, providing significant progress towards our longer-term goal of having 5 gigawatts of projects in the pipeline. For 2023, we have an in-year stated goal of adding another 1,500 megawatts of new sites to our pipeline to replenish our growth in the longer term. And so far, we've added 286 megawatts toward this goal. Notably, in the first quarter, we acquired a 50% interest in the 320-megawatt 10-mountain pumped hydro energy storage project. This project provides us with a unique opportunity to supply 15 hours of long duration and zero-emission energy storage capabilities for the Alberta market, which will help to address the increasing intermittency that we believe will be experienced with the growth of renewable generation in the province. Since our last update, we see continuing strength in power prices in Alberta and the Pacific Northwest. In Alberta, Ford power prices for the balance of the year are trading higher as a result of, among other things, the relatively strong price results in the year to date, transmission import restrictions into the province, and delays in new supply additions. With our strong results this quarter and improved market expectations for the rest of the year, we're pleased to increase our financial guidance for 2023's adjusted EBITDA by approximately $250 million. We're now expecting Alberta power prices to settle the year $15 per megawatt hour higher than our initial guidance, between $125 to $145 per megawatt hour. Higher pricing and production are expected to increase adjusted EBITDA to the range of $1.45 billion to $1.55 billion, representing an increase of 19% at the midpoint of our prior guidance. Free cash flow is expected to be in the range of $650 million to $750 million, an increase of 15% at the midpoint compared to our prior guidance. And energy marketing gross margin is expected to be in the range of $130 million to $150 million, an increase of 40% at the midpoint of prior guidance. I'll now turn it over to Todd for further discussion on the quarter's financial results.
spk00: Thank you, John, and good morning, everyone. I'll kick off my comments, as I always do, with a more detailed overview of our Alberta portfolio performance. When we announced our guidance in December, our outlook was based on Alberta power prices ranging between $105 to $135 per megawatt hour. Looking at the first quarter of 2023, the spot price in the quarter settled significantly stronger at $142 per megawatt hour compared to last year's settle of $90. Overall, we realized higher merchant power pricing for energy across the Alberta fleet due to higher market prices and optimization of our available capacity across all fuel types. The ability of our hydro fleet to capture peak pricing was demonstrated throughout the first quarter, with a realized energy price of $168 per MWh, which represents an 18% premium over the average spot price. In addition, we enhanced revenue further through opportunistic hedging, which generated an incremental $24 million of gross margin, which resulted in a blended realized price of $258 per megawatt hour. Similarly, our gas fleet also captured peak pricing throughout the quarter, with a realized merchant price of $156 per megawatt hour, which represents a 10% premium to the average spot price, including hedges, the gas fleet realized an average power price of $136 per MWh, which represents a 62% increase over Q1 2022. Our merchant wind fleet also had great results and realized an average price of $89 per MWh, an increase of 53% to the same period last year. Looking at the balance of the year for 2023, we have approximately 4,800 GWh of Alberta gas generation hedged, at an average price of $86 per MWh, and roughly 94% of our required natural gas volumes have been hedged at attractive prices. Our hedging activities aim to provide downside protection and support for the Alberta gas fleet, and we continue to retain a significant open position in order to realize higher pricing during times of peak market demand. Our financial results for the first quarter were outstanding. As John noted, we generated $503 million of adjusted EBITDA and $263 million of free cash flow. Our performance in the first quarter was led by the gas fleet, with adjusted EBITDA of $240 million, a 129% improvement over last year. As we noted, the gas segment benefited from stronger production and realized prices in Alberta, lower input natural gas prices, and lower OM&A from further cost reductions from our previously retired coal operations. Adjusted EBITDA from the hydro segment was $106 million, a 74% increase to the same quarter in 2022. Although the segment experienced lower production caused by unplanned outages and icing, this was more than offset by higher realized spot and hedge prices for energy sales and higher net realized prices for ancillary services compared to last year. The segment has also started to monetize its inventory of environmental credits, and we received $8 million of environmental credit revenues in the quarter, and we expect this activity to continue over the course of the year. The wind and solar segment performed similar to last year, quarter over quarter. Although we brought on new assets in the period, we experienced lower production due in part to weaker wind resources compared to the same quarter last year and lower availability at our sites. Reduced production was offset by higher realized prices and the environmental attribute revenue in Alberta. Energy marketing continued its trend of above average performance and in the quarter delivered $53 million of gross margin and $39 million of adjusted EBITDA, a 129% increase over the same quarter in 2022, exceeding our target expectations. The Centralia facility within our energy transition segment also had a terrific quarter. Adjusted EBITDA for the quarter increased by $49 million compared to the same period in 2022. We realized higher merchant prices in mid-sea, along with higher production, resulting from tighter supply conditions in the region and better availability compared to the extended outage we incurred last year. Corporate costs increased by $6 million, primarily due to the insurance recoveries that were realized last year, and were also impacted by higher spending on strategic and growth initiatives and from the impact of inflationary pressures on labor costs. Overall, TransAlta's results again exceeded our expectations and delivered a great start to 2023. Shareholders continue to benefit from the strong performance of our hydro fleet. In the first quarter alone, the hydro assets generated over $100 million of adjusted EBITDA, and we are well on track to deliver roughly $400 million this year. This compares to over $500 million in 2022 and over $300 million in 2021. Production for both energy and ancillary services were lower this year, driven by a low water resource, lower availability at some sites, and operating restrictions due to icing conditions. Although production varies quarterly, it remains consistent on an annual basis, providing long-term predictability and a floor to cash flows that is unique to this asset class. Realized pricing continues to be strong, with a premium on spot energy sales of roughly 20%. Before I turn things back to John, I'll turn to TransAlta Renewables. In the quarter, TransAlta Renewables delivered adjusted EBITDA of $128 million. This represents a decrease of $11 million compared to the same period in 2022. The decrease was a result of a number of factors, including a lower wind resource, the timing of environmental credit sales, lower availability at several sites, and higher OM&A expenses due to higher insurance costs and escalation on long-term service agreements. As John mentioned earlier, our construction program at Kent Hills and in Australia are progressing well, and we expect contributions from these assets to start in the second half of 2023. As we move forward, we continue to focus on identifying opportunities to extend our cash tax horizon that we currently expect to impact results in 2024. With that, I'll turn the call back over to John.
spk09: Thanks, Todd. As I look at our strategic priorities for 2023, our primary goal is to continue delivering clean power solutions to, and be the supplier of choice for, customers that are focused on sustainable growth and decarbonization. In 2023, we're focused on progressing the following key goals. Reaching final investment decisions on the equivalent of 500 megawatts of additional clean energy projects across Canada, the United States, and Australia, and delivering 75 to 100 million in incremental EBITDA. Achieving COD on the Garden Plain wind, Northern Goldfield solar, White Rock wind, Horizon Hill wind, and Mount Keith transmission projects. Expanding our development pipeline by adding 1,500 megawatts of development sites with a focus on renewables and storage. Completing the rehabilitation of Kent Hills wind. Advancing a new technology roadmap that aligns with our clean electricity growth plan. Advancing the long-term contractedness of our Alberta energy portfolio. delivering permanent financing for our growth projects, achieving EBITDA and free cash flow within our increased guidance ranges, and advancing our ESG objectives, which include furthering reclamation work at Highvale and Centralia, providing Indigenous cultural awareness training to all of our US and Australian employees, and achieving at least 40% female employees by 2023. I'd like to close by what I think makes TransAlta a highly attractive investment and a great value opportunity. First, Our cash flows are robust and underpinned by a high-quality and highly diversified portfolio. Our business is driven by our contracted wind and solar portfolio, our unique, reliable, and perpetual hydro portfolio, and our efficient gas portfolio, all of which are complemented by our world-class asset optimization and energy marketing capabilities. Second, we're a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. This year, we adopted a more ambitious CO2 emissions reductions target up 75% by 2026 from 2015 levels. And our board has recently approved our commitment to net zero by 2045. Third, we have a diversified and growing development pipeline and a talented development team focused on realizing its value. Fourth, our company has a sound financial foundation. Our balance sheet is strong and we have ample liquidity to pursue and deliver growth. Finally, our people. Our people are our greatest asset And I want to thank all of our employees and contractors for the excellent work they've done to deliver our outstanding quarter. Thank you. I'll turn the call back over to Kiera.
spk08: Thank you, John. Sergio, would you please open the call for questions from the analysts and media?
spk04: Thank you. Ladies and gentlemen, we'll now begin the question and answer session. Should you have a question, please press star 1. If you want to withdraw your question, please press star 2. Your questions will be pulled in the order they are received. If you are using a speakerphone, please leave the handset before pressing any keys.
spk06: One moment, please, for your first question. Your first question comes from Rob Hope from Scotiabank. Please go ahead.
spk14: Good morning, everyone. uh just first question is on the updated guidance so you know you're expected alberta spot price goes up we'll call it twenty dollars ebitda goes up you know 200 250 250 million dollars you know that's significantly above kind of the you know the sensitivity ranges that you have provided previously and understand like uh energy marketing did did well but when we take a look at the gas portfolio and your and your hydro portfolio Should we think that there's some asymmetric upside in terms of your ability to capture margin when pricing is strong, which you typically don't bake into your guidance or your sensitivities?
spk09: Good morning, Rob. I think the answer to that question is yes, we do think that there is asymmetry to the upside. That's actually the language that we use internally when we speak with our optimization team and we do our internal reviews. And, you know, look, when we began the year and we were looking at what we expected pricing to be sort of in the back three quarters of the year and we see where it is today, it's a significant difference. from what our expectations were to where it is now. So that lift in the floor, so to speak, coupled with the ability of the fleet to flex when the pathways in the marketplace permitted to really, really permits us to have that asymmetry to the upside. And I think that's really what you saw in the first quarter, too.
spk14: I appreciate that. And then just in terms of kind of use of capital, your cash balance is now significantly higher than what we would characterize as run rate. You are buying back a little bit of shares here. But when you take a look at capital allocation priorities, how do you balance strengthening the balance sheet, investing in new projects versus returning cash to shareholders?
spk09: Yeah, look, we, as you know, we have a framework that we use on capital allocation and, you know, 40 to 50% of our deconsolidated FFO is focused on growth capital, debt reductions and share buybacks. You're right, the balance sheet is strong. We're still doing a significant amount of growth. It's in the hundreds of millions of dollars of spend. We do have just under 400 megawatts of advanced projects that we're looking on pushing forward. And again, that's a significant dollar amount to be able to invest and see that forward. And as you've seen, we've been very much focused on share buybacks over the quarter and actually into April, I think, Todd. We've collectively done over the last few months something like $65 million of share buybacks. I mean, so right now the two major levers that we're pulling on would be share buybacks, you know, given where the share price is trading and also making sure that we're positioned well for growth as it comes in.
spk06: I appreciate the color. Thank you. Sure. Thanks.
spk04: Thank you. Your next question comes from John Mould from TD. Please go ahead.
spk13: Thanks. Good morning, everybody. Maybe just digging into the hydro hedging a little more. You don't typically hedge your hydro, but clearly did your benefit this past quarter. Can you provide a little more context to your broader approach to hedging these assets and locking it upside? Is this something you'd look to do whenever your view of price diverges with near-term forwards and the liquidities there to transact?
spk09: Yeah, good morning, John. I think you've actually got it. I think that's exactly right. When we were in Q4 of last year and we saw kind of what the forward curve, which had okay liquidity, was kind of showing in terms of pricing for the first quarter of 2023. And we were looking at what our fundamental view was and where pricing would be. We just thought it was appropriate to layer in hedges, including in that sort of exceptional circumstance when we see that level of a divergence for our hydro fleet. As you know, we would typically leave hydro more open than our gas fleet. We tend to think of our gas fleet as being more I'd say, Todd, what we're focused on from a hedging perspective. But as we went into the quarter, just opportunistically, it just made sense. And really, that's what we expect our asset optimization team to do. Todd, I don't know if you want to add any more comments.
spk00: Yeah, I would just say, look, the forward curve was trading north of $250 for Q1 as we came out of December, just based on concerns of a really, really cold winter and some volatile prices. And the team looked at it and said, we think there's a portion there that's fully valued and decided to lock off some of that risk.
spk09: And I think it was prudent to do that. I mean, given where the prices were and, you know, it turned out the quarter was relatively benign from a weather perspective, I would say, and it ended up being the right decision.
spk13: Okay, great. Thanks for that. Maybe just turning to the growth side, you know, we have seen some additional renewable PPAs get finalized in Alberta. I'm just wondering if you can comment more broadly on The challenges, I suppose, not just in Alberta, but in your core markets are progressing towards that 500 megawatt target for this year in the current development environment, whether it's equipment costs, securing off-take agreements at appropriate pricing or other factors that make it a bit of a challenge.
spk09: Yeah, I'd say when we look at our sort of our advanced stage projects and we go forward, we're going to be super disciplined. So we continue to work hard to de-risk those projects as much as we possibly can, make sure that we're very, very comfortable with what our pricing is. and our costs more importantly from a supply chain perspective because given how competitive the world is, we want to make sure that when we go to our board and we say here's the project, here's the revenue stream, we end up locking in the returns that we promised that we were going to be able to lock in. Just to address, John, the more broader question that you had, look, there's challenges out there for sure and I don't think we're unique in identifying them. I think permitting is taking a little bit longer and to get done than it traditionally did. I think the cost of, you know, on the supply chain, I think some of those inflationary pressures have eased a little bit, but we've seen a considerable increase in just the cost of the steel on the ground, whether it's solar or wind, in terms of getting it, you know, getting it forward. Even, you know, labor availability for construction has been a bit of a challenge at times, depending on the jurisdiction. that you're in. And I think on the PPA side, there has been and there continues to be robust demand for product. But there still is a little bit, I would say, of a delta between kind of where costs have gone versus where the market is pricing things in. And people forget that it is risky to build these things. And, you know, you need to be very disciplined that the returns are appropriate from a risk-adjusted perspective. So when you put the whole thing together, look, we're very optimistic about the future. But I think it requires care and a lot of discipline as we go forward, and we're going to stick to that.
spk13: Okay, great. Thanks. Maybe just one last one on the R&W release. You again referenced the headwinds that R&W is facing on cash taxes. Any growth? What are the considerations for RMW in exercising its ROFO on the advanced stage projects in Australia? Or are you more focused on finding more near-term growth that could sooner mitigate those cash tax headwinds?
spk00: Yeah, I would say, look, just as far as the cash tax headwinds, I mean, obviously the solar project that's advancing right now will be beneficial for that. That's already looked into our plans. As far as the ROFO projects in Australia, They're all great projects. They're good economics. I would expect R&W to exercise those options going forward. But we are looking for more options, particularly in Canada, to help to defer the tax horizon.
spk06: Okay, great. I'll leave it there. Thank you very much. Thanks, John. Thank you.
spk04: Your next question comes from Darius Lossme from Bank of America. Please go ahead.
spk06: Hey guys, good morning. Thank you for taking my question.
spk12: First one, just on Alberta gas performance in the quarter. Can you clarify whether, was it most of the elevated output that you attribute to exports south into the mid-sea area or just a portion of it? And then the part B to that question would be in your updated plan, are you embedding any assumptions about future for quarters two through four? elevated levels of exports relative to the earlier plan or relative to prior years? Thank you.
spk00: Yeah, look, I'll start there and then John can jump in. Good morning. The general answer is yes. What we've seen is a bit of shift in dynamic. One is mid-sea prices are higher than we were thinking originally coming into the year. And so that's creating more demand to move power out of the province down in the Pacific Northwest when they need it. The other aspect is the ISO here in the province has reduced some of the capacity on imports. And so they've restricted down how much power can come into the market during periods of high demand. And so we're seeing a real shift in dynamics. And that is, you know, it does account for a lot of the differences. The imports and the strong mid-sea pricing, we expect to persist through the year and potentially even into 2024.
spk09: Yeah, and I would say, Darius, that we always have kind of viewed it as being kind of an integrated market, sort of Alberta into the Pac Northwest, and we really see it at the moment in terms of the dynamics between the two jurisdictions.
spk06: Great. Thank you for that. Appreciate it.
spk12: Maybe one more if I can, and this is just relative to the Tent Mountain project that you guys announced. Can you, first of all, Assuming that that is not included in your 23 500 megawatt FID target, presumably that decision is maybe a little bit further out, but correct me if I'm wrong. And is it a little bit at this point preliminary to discuss target returns slash capital for that project? And then finally, is there anything that you saw in the recent federal budget that gives you perhaps more confidence in being able to finance or otherwise get support for that project? Thank you.
spk09: Thank you for that. It is still pretty early days for that project. I think right now the team is actively working on it. We tend to think of that as being more of a 2026 kind of project and maybe even belong. beyond in terms of that coming to fruition. We think there will be a time when its unique attributes will be just a huge asset for the way that the marketplace will be evolving in Alberta given the intermittency that we see occurring as the renewable build-out occurs. And what I would say is in general I think the federal government sort of policy around tax credits and supports in terms of financial supports is relatively positive in terms of moving it forward. But it's still early days to get into specifics about how that is. We saw an opportunity and we kind of jumped on it and are pretty happy that we did.
spk06: Great. Thank you for the call. I appreciate it. I'll turn it over here. Thanks.
spk04: Thank you. Your next question comes from Ben Pham from BMO. Please go ahead.
spk06: Hi, thanks.
spk02: I wanted to follow up on your comments on, I think you mentioned there's a gap between CapEx and there's more on the renewable side CapEx and bridging that with securing a contract or maybe I didn't interpret the right way. Can you expand on that? Is that more of a U.S. situation? How does some of the budget support items that we've seen flow through impact that thought process? And I just want to make it clear, you're still quite confident around the 500 megawatts section this year.
spk09: Yeah, good morning, Ben. So, yep, we set the target and we do view our targets as stretch targets. We try to motivate our team to move forward and and achieve the best that they can do. We're comfortable with our advanced stage pipeline, their quality projects, and we are advancing them actively. The team is on all of them, and we have confidence that we'll be converting those as the year goes by. I'm not sure about the introductory question that you had. Maybe I'll try to add a little bit of color. I mean, what I was trying to say is that pricing from a renewables perspective and expected returns, at least from a TransAlta perspective, we need to make sure that the returns are appropriate on a risk-adjusted basis, which I think there's some time and the assumption is that there's no risk associated with construction. There's no risk associated with evolving dynamics within the marketplace in which the unit or the facility is being built. And I think it requires care when you're going forward and developing a project. And we owe it to our shareholders to be as disciplined as we can be when we're allocating capital. On the cost side, I mean, just to give you an example, I think, and I'll use the U.S. as an example, I think PPA prices there are up roughly around 10% or so over the course of the last year, and that's in the context of turbine costs, for example, increasing by 30%, 40%. So the market is reacting to the increased sort of cost of developing projects, but it isn't exactly the same. And for us, we're going to be very, very disciplined, both in making sure we lock in our economics and making sure that our costs are fully baked before we proceed on anything.
spk02: Okay, that's more clear. Thank you. Not that you weren't clear from the beginning. On the gas problem, procurement side of things. I'm wondering, just looking at what the quarter, how you benefit from low gas prices, do you anticipate any changes in how you're procuring gas going forward? And is there any sort of interest in even getting involved in buying a gas field at some point?
spk09: Yeah, no, thank you for that. We're pretty comfortable. I mean, I think over 90% of our entire dissipated gas burn is basically locked in for 2023 at very good pricing. I mean, sort of low $2 kind of pricing. And 2024 is candidly not much different than that. When we look going forward, you know, we're not contemplating actually buying an interest in any, you know, natural gas generation to supply where we are. We're comfortable with our ability to secure natural gas for our assets going forward. We have sort of a view on where we think natural gas prices are going to be in the kind of near to midterm and we're comfortable with where that is. I know it can be volatile. We've seen that over the last little bit. But when we look at sort of 23 and 24 and even into 25, I don't I honestly I don't see us actually making kind of integrating upstream effectively into the supply chain to be able to secure that fuel.
spk00: As you say, we do look at it every few years. And I think the conclusion continues to come back every time that the best thing to do with our business is to just hedge it forward in the financial markets or bilaterally with counterparties.
spk09: I mean, well, you know, our focus is to stick with things that we do well. And that's the power generation and growth side rather than, you know, oil and gas generation. It's not something that we're in.
spk06: Okay, got it. Thank you.
spk04: Thank you. Your next question comes from Mark Gavi from TIBC Capital Markets. Please go ahead.
spk10: Thanks. You guys mentioned that you'll be looking to renew the NCIB in the coming weeks here. I think it's for about 5% of shares outstanding. Would you take that up when you renew the NCIB in terms of maybe a bit more sort of grander ambition on the buyback?
spk09: Yeah. Good morning, Mark, first of all. Sorry. Look, we will renew the NCIB, I think, before the end of the month. I think it actually expires on the 30th, I think it is, Todd. So we will make sure that we do that this month. In terms of the size of it, I think we tend to ask for our entitlement to be up to the maximum amount that we're permitted under the rules to be able to buy back, just as a matter of course. And I think it's restricted by, I think, the proportion that you're allowed to get of your average kind of daily float that is traded on the exchange. So we will enable the maximum amount, I think, which I think translates, thought, to somewhere just a bit over 5% of the total float that we're permitted to repurchase under the NCIV. I'm just going from memory here.
spk10: Okay, and then, John, you also brought up M&A as a potential source of growth. I know you guys have been very cautious on that, just given where deal metrics have been, you know, with a stronger cash position. Anything change there? How would you characterize her in terms of your interest in looking at deal flow right now and what you're seeing in terms of opportunities and valuations out there?
spk09: Yeah, so the team is – I would say the team is busy. It was interesting. We – We just had a board meeting, you know, for the quarter, and, you know, we gave an update, and it was interesting to see kind of the funnel that we used in terms of what the team looks at and how it progresses through it. So we do remain active. You know, two areas for us would be are there – sort of good assets that we think we can add value to and bring into the fold. So that's one category. This would be operating existing assets that we could bring into the fold. The second area that we're actually spending quite a bit of time on is actually just development platforms and developers. Is there something that we could see there that makes sense to bring into the company to further I think, strengthen our growth capabilities within the organization. So those would be the two broad areas that we look at. We do kick the tires a lot, if I can use that sort of expression, and continue to see if we can opportunistically get something over the goal line. We're going to be disciplined on price, though. I would say, Mark, like things are still pretty expensive. And it's got a, you know, when we diligence these things, we need to make sure that we're comfortable with what we're getting, giving the pricing.
spk10: And then just in terms of the operating assets you mentioned, I mean, obviously there's a concerted effort to shift your portfolio to more contracted renewables. Where would gas or thermal assets fit in any terms of M&A on operating assets?
spk09: Yeah, you know, look, we do see gas opportunities occasionally. I think certainly from a sort of priority perspective, we are looking at more of the contracted renewables. But that's not to say that if a gas opportunity came up that was contracted, fit well with the kind of fleet, gave us the ability to optimize around it, given the skills that our team has, and permits us to have kind of within the emissions profile that we've set within the company, it is something that we would look at, and we do periodically look at those. So it's not like we won't look at gas at all.
spk10: Understood. Last question for me is just given the pricing dynamics and tightness in the Pacific Northwest, any sort of updated views in terms of opportunity sets and how you can extract value from the Centralia site?
spk09: Yeah, it's an ongoing, Todd just smiled, Mark, because it's an ongoing discussion that we end up having here. One of the challenges we have there is Our ability to, for example, convert the unit from coal to natural gas is super constrained, both in terms of volumes of natural gas and actual pipeline capacity. So when we look at the site, we're looking at it from, is there some solar we could do there? Is there battery installation that we could do there? Is there even wind that you could do there? The solar resource isn't the greatest. The wind resource is better east of the Cascades than certainly west of the Cascades. We are Looking, though, at everything from fusion, we're looking with FFI at the possibility of being involved in their hydrogen prospects there. So the infrastructure is great. It's in the perfect spot from a transmission perspective. So we continue to sort of chase all the potential opportunities that we can to see it through. So stay tuned. I think there is a lot of value in the site. It's just I doubt it'll be thermal in nature.
spk10: Would you characterize in terms of opportunities becoming more advanced or seeing something you think that could become more tangible in the near term?
spk09: I don't suspect that we'll see anything that will be tangible kind of over the next 12 to 18 months. I think most of the things that we're working on there, Mark, are things that would be sort of, you know, in my own mind, kind of 2025, 2026. I mean, we're into a place where the unit's going to run until, you know, the end of 2025 anyway. So it's really kind of the back half of the decade that's the focus. That makes sense. Okay, thanks for your time today. Thanks a lot.
spk04: Thank you. Your next question comes from Maurice Choi. from RVC Capital Markets. Please go ahead.
spk16: Thank you, and good morning, everyone. My first question relates to capital availability. Unless I missed it, I believe you continue to be equity self-funded for your 2025 growth targets. But given the growth opportunities that you have, which are clearly abundant, how do you view prospects for bringing in a long-term partner or partners be that for these school opportunities and or for a corporate simplification? And if you do, what would be the top thing that you'd like this partner to bring to the table besides capital?
spk09: Yeah, and so good morning, Maurice. Thank you for that. And I think you've actually just touched on it at the end there. Traditionally, look, we do have some great partnerships and when I think of the relationship we have, for example, with CKI and even the Heartland folks with Sheerness, I think those are very constructive partnerships and work very well. When we think of of bringing others to move things forward. It isn't because we see ourselves as being capital constrained right now. So for us to bring somebody in, I think one of the key drivers would be what would they bring to the table that makes it a bigger pie, so to speak, in terms of us being able to collectively participate in kind of accelerating our growth Or are there capabilities there that maybe we don't have or, you know, an area, a geographic area of focus that we aren't as strong in that we could, you know, bring our expertise in to move forward. So we do have these kinds of discussions every so often. I don't think there's anything... particularly active on that at this particular point in time, I would say. And when we think of partnership, we also think about our customers. So when I think of partnerships, I think of BHP, Nickel West, and we do view as kind of being in it with them as they continue to advance their business in Western Australia and we're there kind of shoulder to shoulder with them as they move forward. Todd, I don't know if you had any color.
spk00: The only thing I would add is the other thing we always consider about is risk mitigation. As we get large, large capital projects, we start to think about, you know, does it make sense given our market cap or our float, should we be thinking about diversifying some of that risk away with a partner just on any individual project? So that's another key consideration.
spk16: Thanks for that, Keller. And maybe I could just finish off with a regulation question. The CER, or the Clean Electricity Regulations, obviously seemingly coming this spring, what would you view to be a good outcome for your Alberta gas fleet, including a benchmark or even a number of years in terms of animal life.
spk09: Yeah, and I might turn it over to Carrie here who's in the room for us to give any color. I think, so look, we have to wait to see what the fine details are going to be when it's actually published at the end of the day. Our team is very actively involved in the process. I know Carrie and her team have been consulting on it. In fact, they just filed another submission on it. I think it was just yesterday. I think, Kerry, and it's around some of the things that you've alluded to, Maurice. It's everything from, you know, reliability running, for example, what should the end of life be? How do we think of, you know, smaller units? It's that nature of the flavor of things that that we do. So it's sort of how do you balance decarbonization while ensuring the integrity and the reliability and stability of the systems as we go forward. Turning to our units, you know, given the kind of timeframes that they're suggesting in terms, you know, the 2035 and the ability to maybe run longer than that. And I look at what the natural life is of our coal to gas converted units. They align pretty well, you know, I would say. So it's not like you know, our CTG units were ever going to run to 2050, for example. So, you know, I don't know that what is developing is going to have a major impact on how we're operating. Carrie, I don't know if you have any thoughts around that.
spk07: No, I think that I completely agree with everything you mentioned, John. The only thing that I would add is that we do understand that it will be delayed until later in the year. And one of the things that we speak with the government about is the importance for clarity which encourages investment certainty in the province and in the country as well. So I think the only point I would add to your comments is additional clarity on co-gen and how the co-gens will be treated under the CER. But otherwise, I think it's moving in the right direction. And, you know, hopefully we will see it at the latest in the third quarter.
spk16: Just to clarify, you mentioned that this aligns pretty well with the, I guess, physical characteristics of the fleet. Do you mean that by being a 2035, or do you mean that by a view of what those end of lives may be, whether that's 30 years or whatnot?
spk09: No, no. My reference was to the 2035 kind of timeframe. You know, we're not that far off. And that was actually a conversation piece when we were engaged with the government.
spk05: Thank you very much. Thanks, Maurice.
spk04: Thank you. Your next question comes from Andrew Cusk from Great Swiss. Please go ahead.
spk11: Thanks. Good morning. If you had a hypothetical project in Canada and the U.S. with exactly the same economics, where would you allocate capital if you start to think about the incentives of the IRA in the U.S. and then the new round of incentives in Canada? And then maybe just to give you a little bit of leeway on the answer, are there other factors beyond government incentives that would to dictate where the capital would go on such a project.
spk09: Good morning, Andrew. It's interesting, if they were exactly the same and we were in both jurisdictions, let me try to answer it this way. I think the financial incentives that the governments have on both sides of the border are pretty powerful and it's interesting. I was recently in Australia and the narrative there is also around how do you respond to the IRA in the United States, because they really do see it as an element of their industrial strategy that they need to be mindful of. So when you look at the two jurisdictions, there are differences. I mean, the refundability of the ITCs in Canada is pretty powerful. That was an important element of the response here from a Canadian perspective. You know, we are looking at... you know, very powerful in the US as well. I mean, transmission is an issue in the US in terms of where you are. And the reason I raise that is probably a differentiator between the two. I would say we're pretty agnostic within the jurisdictions, except for this. When we do our projects, we're very concerned about the post-PPA merchant period. And so for us, the assessment would be, you know, how does that look in the market in which we're making the investment in terms of differentiating, you know, are we more comfortable with the Canadian, Australian, or U.S. component? And, you know, what is the contract period IRR in the context of the two? So it's more that all things being the same. It's more what does that back end certainty look like to the extent you can get any and are we comfortable with that?
spk11: Okay, that's very helpful. Maybe building upon your comment there, that back end of a PPA, does that really speak to places where you have existing portfolio concentration on being more likely to draw capital? Because that gives you by default a greater level of comfort and optionality around the asset base.
spk09: Yeah, it can. So for us, I think it would be more, Andrew, around... you know, how large is our position in the jurisdiction? How intimately knowledgeable are we about it? Do we have the ability to influence regulatory outcomes within the jurisdiction or not? Do we have ability to recontract or have any particular sort of customer relationship that makes it a little bit differently? Does our trade floor have a particular expertise, not just in trading, but also from an intelligence perspective, you know, in that jurisdiction? So it's a hard... It's a great question, but it's a hard one to answer because it truly does depend and it actually evolves over time.
spk11: If I could just sneak in one more, how do you feel about your positioning in the interconnection queues, I guess mainly in the U.S.? You could answer Canada too, but I guess mainly in the U.S.? ?
spk09: I think in terms of the project timeframes that we have for bringing the assets in right now, if you were to look at kind of what is more ready in terms of our advanced stage projects, it's more a Canada, kind of Australia flavor. The US stuff is kind of a little bit further away in terms of getting forward. We're pretty comfortable in terms of where we are. It is one of the key considerations though, Andrew, to your point, and it's becoming an even bigger consideration in the U.S. in terms of, you know, what is the actual time frame? I mean, some of the time frames from beginning, you know, from initiation of envisioning of a project to the actual realization are, you know, exceeding half a decade now and getting longer. So that is for sure a factor. You know, one of the things about the IRA is it really incents demand increase and and meeting the demand, but it kind of forgot the wires part of the equation, which is kind of, at least from my own perspective, sort of the missing piece in terms of enablement.
spk11: Okay.
spk06: I appreciate that. Thank you. Thanks.
spk04: Thank you. Your next question comes from Najee Badun from AI Capital Markets. Please go ahead.
spk03: Hi, good morning, and congrats on the great quarter. I just wanted to ask a couple questions around organic growth and capital allocation. It seems like maybe project development is taking a bit longer than you'd like. Just any thoughts on what can be done differently to try to accelerate development? And maybe reading between the lines in your opening remarks a bit, do you anticipate to maybe backfill some of the sort of megawatts to achieve your target 3M&A?
spk09: Yeah, good morning, Najee. Thanks for your question this morning. I, you know, look, the projects have a life of their own. So we're not, you know, it's not like, oh, goodness, it's January and we haven't announced anything this month. That isn't the way we look at it. For us, it's more when are they ready to go? And if they're ready to go, then they might be clustered in terms of, you know, when they come in. within the organization. And candidly, we've been really focused on a lot of construction. I mean, in all three countries in which we're active over the last little bit, and it's I think in total about 1.4 billion over the last kind of 18 months or so. So that's been a big focus of the team going forward. So we do have things in our development pipeline that we can potentially accelerate to get to that 500 megawatt target that we have. It is a stretch target. We deliberately made it a stretch target when we set it for this year. We're comfortable with the advanced stage projects that we have. The team continues to work to move more projects to the advanced stage, and we will be opportunistic on M&A, but we're going to be disciplined. Like if we don't If we don't see returns that we like, we'll be patient and we'll bring the projects on when we think it makes sense for our company and our shareholders.
spk03: So in a scenario where, be it the 500 for this year or the 1,200 to reach the two gigawatt target, where maybe, like you said, the projects are lumpy, how much money would you be comfortable kind of pursuing? Or none at all if you don't find the right acquisitions?
spk09: Yeah, I would say it would be none at all if we don't find the right acquisition. I think, you know, we're not going to, you know, if the exercise was simply to get to the numerical target of two gigawatts, you could achieve it, but you might achieve it in a way that really ends up destroying value rather than actually maintaining value going forward. So for us, the overriding factor on our clean electricity growth plan is that we're going to make investments that we think provide value for our shareholders. And And that's sort of threshold one in terms of moving forward. We're still confident that we'll meet the targets and the team continues to work forward. And we're happy with where we are from a pipeline perspective. And I think we set a five gig pipeline target for 2025 and we're over four now. So I mean, that I'm very comfortable in terms of the scope of the inventory that we're building effectively to bring forward.
spk03: Okay, fantastic. That's very clear. And just tied to all of this is, It seems like you're doing a bit more buybacks than maybe what you would have talked about earlier. Again, just given if growth is a bit lumpy, do you think that you'd be allocating more capital to buybacks? Is that a fair assumption in the short term? And if the answer is yes, do you have sort of a maximum envelope for share repurchases that you have in mind for the year?
spk09: Yeah, we don't have a set number. of share buybacks that we would do over the course of the year. But, you know, look, it is a key factor from a capital allocation perspective. We're mindful that we've got a strong balance sheet right now. We're very mindful of making sure that we, you know, make sure that we're focused on our shareholders and giving them an appropriate return. And we look at that holistically in terms of the dividend and also the share buybacks that we're doing. And we also look at kind of where the share price is trading. And we saw, I think, Todd, it's fair to say, a little bit of weakness over the last little bit, certainly compared to where management thinks we should be trading at, and opportunistically we were in buying shares when we see that the value isn't there. Todd, I don't know if you want to add anything.
spk00: I was going to say that our tone is still to stay very opportunistic on share buybacks, and certainly when we saw it drop below $13, below $12, we signaled very strongly that's the time to be in the market. I was going to say that we are sitting on a decent amount of cash. We still have about $400 million or $500 million of construction to go here on the existing projects. But I would say that with rising interest rates, there's maybe a bit more pressure out there on some other people. And there may be some more attractive M&A opportunities show up in the next six months than we've seen over the last several years here with rates of return that are probably more acceptable to us. So I think we're in a great spot. So not only the cash balance, but the amount of liquidity, the strength of the balance sheet, it all points to a spot where the company's in a good spot to really jump on opportunities if they show up.
spk09: Yeah, what I would say, Najee, is kind of the optionality we have right now is kind of a nice place for us to be. So when we see an opportunity, we're in a position where we can actually proceed.
spk06: Okay, that's a good color. Thank you very much. Thank you.
spk04: Thank you. Your next question comes from Prachit Kenny from National Bank Financial. Please go ahead.
spk01: Thank you. Good morning. Just on the heels of the carbon tax here moving up to $65, if you could provide an update on your carbon offset strategy, where your credit inventory sits today, your procurement strategy going forward, and then how this all feeds into your outlook for utilization across your CTG units in Alberta.
spk09: Yeah, thanks, Patrick, and good morning. Todd, I don't know that we've, I don't have those numbers to hand, Patrick, so that's something we could certainly get back to you. I mean, I think we're long, we're fairly long credits, I would say. So in terms of being able to manage, I would say, the carbon exposure that the company has, not just this year, but actually the next few years, we're in very good shape. Our bigger discussions on The inventory we have of credits is how much do we monetize them and when, candidly. So it's more around that rather than the impact that they have on the fleet. Todd, I don't know if you have anything to hand.
spk00: Pat, we can clarify it afterwards. I think we have about 1.7 million. Something like that. It's about 1.7 million. In inventory, but we also generate about 750,000 RECs per year annually. And so we have been monetizing a portion of that we go, but obviously the inventory is built up. And we're just sort of looking, you know, there's a little bit of the carbon taxes going up year after year. Therefore, you know, they theoretically should be worth more value going forward. But at some point, we want to monetize them. We don't want to be sitting on too big of an inventory. And so we'll sort of be opportunistic about how we exercise and use those.
spk09: Yeah, I think, Patrick, and look, I think we're on record saying this. I think there does come a time, perhaps late in the decade, when there is a bit of decoupling between the carbon price and the value of the RECs. There could be a supply-demand imbalance, candidly, in terms of how that proceeds going forward. So we're managing our portfolio in the context of all of that.
spk01: Okay. And then, John, I guess stepping back here and as you assess opportunities to simplify the corporate structure over time, and I guess dovetailing in with Todd's comments on the strength of the balance sheet, I'm curious to get your thoughts on potentially consolidating some other CTG units in the province and perhaps spinning off some sort of high cash flow yielding entity for the portfolio of merchant thermal assets. has a play on crystallizing value for shareholders.
spk09: Yeah, it's an interesting suggestion that you have. And look, I would say our Alberta optimization team is one of the great strengths that the company has. And if there was an opportunity potentially to kind of expand the portfolio of assets that the team would be able to deal with. And Patrick, just to give you a sense of that, I mean, we're focused even on peakers that we're looking at bringing forward. There's a couple of projects that we have that we're actively involved in in pushing forward. Just to give you an example, kind of a merchant peaking, low capital cost peaking kind of fleet for the province. So it's not beyond the realm of possibility that we would look at that. Whether that would stay within the organization or would be spun out, I would just be speculating right now. But if the question is, are you looking at ways to maybe expand the breadth and depth and dynamic of kind of the portfolio we have in the province of Alberta, for example, the answer would be yes, I think.
spk01: Okay, great. I'll leave it there.
spk06: Thanks, John. Thanks so much.
spk04: Thank you. As a reminder, should you have a question, please press star one. Your next question comes from Chris Barco from Calgary Herald. Please go ahead.
spk15: Hi, John. Quick question here regarding the challenges that you see or what challenges, maybe more importantly, do you see to get to a net zero power grid in Alberta by 2035? And how expensive do you think it might be?
spk09: Yeah, Chris, and good morning and thanks for calling in. You know, candidly, I'm not sure anybody knows. how much it would cost to get us to that state by 2035. I think you've seen the ISOs come out with a bit of a suggestion in terms of, you know, what it would cost to get there on a number of different pathways. And I think even the ISOs analysis would show that at the very margin in terms of full decarbonization within the province, it It's hard to do. I don't think their paper actually contemplated they would get right down to zero. So would it be expensive? Yes, it would be expensive. And I think the main takeaway, at least from our perspective, is that the closer you get to achieving that zero, it's kind of like a geometric increase in what the costs are, like it sort of exponentially increases. And people need to understand the province has already done a tremendous job in decarbonizing. When I think of what the emissions profile was, you know, of the electricity sector in the province of Alberta in terms of megatons versus where it is today, the progress that's been made has been remarkable. And we're still on a journey of decarbonization. I know when Capital Power has done, you know, the work that they're proposing to do, it will see another step change in terms of the emissions reductions within the province. Getting us to that ultimate level is going to be technologically, I think, challenging and will also be just from a cost perspective challenging. The other thing I think that's important is at least our company, we tend to, you've heard me talk about this, the three-legged stool. And I think as we go on the journey to there, you know, the three legs of the stool are one, decarbonization and things being clean. The other two are making sure that things are affordable for both businesses and individual Albertans and also having a reliable system. Those two things are critical and it doesn't help anybody to just Secure the one leg of the stool without actually making sure that the other two legs come along in the journey and that you've actually got a proper stool that you can sit on by the time you get to 2025. There's been a lot of discussion about the clean part. Hasn't been as much discussion, at least in our company's view, on both reliability and on the cost. So what it means for us from a company perspective is, you know, we do have concerns in terms of the reliability of the system. I think the push towards renewables has been positive in this province, but it does have implications on both the market construct and the reliability of the system. And I think the ISO sees that. I think we see that. And it's critical that the lights are going to be on. We don't have brownouts or anything like that. And obviously, costs are important as well. We need to make sure that our economy remains competitive and and that consumers in the province of Alberta are taken care of. So it's a hard question to answer, but hopefully I've tried to just kind of give you some of the perspectives and the puts and takes that need to go into it. We've been pretty effective to get us a long way out of the way. The last part is going to require everything from technology to support, frankly, from government to get there.
spk15: Just to follow up, what are still the key uncertainties or wild cards that you see between now and 2035 in order to get to that net zero target?
spk09: There are many. For example, how many renewables can you bring into the province? What does it mean from a transmission and delivery perspective within the province. What does it mean in terms of the infrastructure we need in our towns and cities and rural areas to permit the electrification of transportation? Very challenging. I mean, Alberta's in its very early stages of doing all of that. What does it mean in terms of electrification for the oil sands, one of the great engines of our of our province and what are the costs associated with that. Will CCS be effective? Not generally, but to the actual levels that are being imposed on by the federal government to move forward. And secondly, we do think that there's going to need to be technological advancements to kind of get us there. So is hydrogen ready? It's not right now from our perspective. Is storage where we want it to be from a cost and effectiveness perspective? It's not quite ready in terms of where we need it to be. So it's everything from making sure that the Existing technologies that we have are as effective as they need to be. The renewables that come in, come in in a cost-effective way, given it's not just building them. It's all of the transmission and delivery infrastructure that's needed to do that. And then finally, some of the technologies that I think we're kind of banking on, candidly, to be able to get us there in the 2030s aren't quite ready for prime time. And look, we've made an investment in an entity called EIP that looks at new technologies, whether it is battery storage, fusion, you know, hydrogen, all of those kinds of things. There is a way to go. And you even heard discussion around SMRs. I mean, from our company's perspective, we've looked at them, not that it's a core technology for us, but we look at them and we look at the timeframes required to bring them in and the costs associated with that. You know, it's many times more than a natural gas fired plant. So who's going to pay for that and how is it going to proceed? So I know I know that's a lot there, Chris, but I just wanted to give you a bit of a flavor. It isn't any one thing. There's a there's a regulatory piece. There's a affordability piece. And then there's a technological kind of piece in terms of us getting there. And it's a bit opaque, right, when you get further out there. I think we see pathways to get us a good chunk of the way there, but to get us all the way there in a way that's affordable and reliable, you know, it's hard for us to predict right now. It's actually something that worries us.
spk06: Thank you. Of course.
spk04: Thank you. There are no further questions at this time. You may proceed.
spk08: Great. And 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 very much and have a great day.
spk04: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Thank you.
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