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spk03: Good morning. My name is Joelle, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation's second 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 two. Thank you. Ms. Valentini, you may begin your conference.
spk04: Great. Thank you, Michelle. Good morning, everyone, and welcome to TransAlta's second quarter 2023 conference call. With me today are John Cusignoris, President and Chief Executive Officer, and Todd Stack, EVP Finance and Chief Financial Officer. Today's call is being webcast, and I invite those listening online to view the recording 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 the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide two. It's 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 reconciled in the MD&A for your reference. On today's call, John and Todd will provide an overview of the quarter's results. After these remarks, we will open the call for questions. With that, let me turn the call over to John.
spk07: Thank you, Kiara. Good morning, everyone, and thank you for joining our second 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 Dakota First Nations, as well as the home of Métis Nation Region 3. TransAlta had another exceptional quarter. We're proud of the overall performance of our company and our employees. We delivered $387 million of adjusted EBITDA, 39% increase over our Q2 2022 results, and free cash flow of $278 million, or $1.05 per share, a 94% increase over Q2 2022 results on a per share basis. Both metrics beat our expectations for the quarter. Our results benefited from continuing strong power prices in Alberta and Mid-Sea, lower natural gas commodity prices, and the success of our asset optimization and hedging strategies. Overall, the Alberta market was impacted by tighter supply conditions resulting from transmission constraints, which limited imports from adjacent markets, supportive power prices in adjacent markets, which also lowered net imports into Alberta and encouraged exports of power from Alberta to the Pacific Northwest, periods of overlapping outages, and lower than normal wind resources, which impacted renewable generation. We also saw significantly lower fuel costs compared to last year, given lower overall commodity prices and the impact of our hedging program. The higher realized prices coupled with lower realized gas prices delivered higher gross margins for our portfolio compared to Q2 2022. Our overall availability was 85%. Apart from our ongoing outage at Kent Hills, our performance had weaker availability due to higher planned outages in the hydro and gas segments, which was partially offset by better performance at Centralia compared to last year. During the quarter, we delivered on a number of key priorities, beginning with the announcement of the proposed acquisition of TransAlta Renewables by TransAlta Corporation. This transaction will not only simplify our corporate structure, it will enhance our strategic position, and provide alignment within our clean electricity growth plan in a manner that we believe will create value for all our shareholders. The combination will also deliver capital efficiencies and enhance cash flow predictability and diversification for both sets of shareholders while preserving the combined company's ability to realize future growth. On the growth side, our development team continues to expand our pipeline, adding another 344 megawatts of growth project. 300 megawatts of which are renewables projects based in the US and Australia. And 44 megawatts relate to a new peaker initiative that we have here in Alberta and that I'll be speaking about shortly. The rehabilitation of Kent Hills is progressing well with 27 of 50 turbines fully reassembled. Turbines are being returned to service as commissioning activities are completed. And to date, 10 turbines have been fully placed back into operation and are earning revenues from New Brunswick Power. We are now anticipating that the repair costs will increase to about $140 million as we have opportunistically expanded the scope of work to include certain blade repairs, which will permit us to defer or avoid future maintenance at the site. We completed $35 million in share buybacks during the second quarter, bringing our total capital return to shareholders during the first half of the year to $71 million through the repurchase of 6.1 million common shares at an average purchase price of $11.62. Our current NCIB program was renewed in May, and we see it as a capital allocation alternative that will help us continue to enhance long-term shareholder value. 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 recently announced transaction with TransAlta Renewables, as well as our growth projects. As you all know, a key priority for the company for 2023 is completing the construction of our contracted renewables projects. We currently have 678 megawatts of projects in the construction phase, representing an investment of $1.4 billion, with approximately $1.1 billion spent to date and $300 million left to go. Our 130-megawatt garden plane wind farm here in Alberta is nearing completion. All 26 turbines have been assembled, and we're pleased to announce that 23 units are in operation today and available to generate electricity to the grid. We expect to finalize commissioning and declare commercial operations in a week or so following resolution of an outstanding issue with the three remaining turbines. We expect the wind farm to contribute $15 million of contracted EBITDA annually, and so far, we're pleased with the performance of the turbines at the site. Our Northern Goldfield solar project in Australia is also reaching its final stages of completion. All major equipment has been installed and construction work is largely complete. Energization and testing processes have commenced. The solar facility is beginning to generate electricity and is expected to achieve full commercial operations in the second half of 2023. This project will deliver approximately $9 million of adjusted EBITDA annually. Construction at the Horizon Hill Wind Project in Oklahoma is also advancing well, and all major equipment has now been delivered to site. Turbine erection activities are underway, and we're pleased to report that 27 of the 34 wind turbines are fully assembled. Construction of the transmission interconnection is also underway. Although our turbine erection activities are progressing, the critical path to our schedule is the completion of the transmission line, which unfortunately is seeing some delay. As a result, we're now expecting to reach commercial operations during the first half of 2024. At our White Rock East and West projects, equipment deliveries are well advanced, and the final blade sets are due to arrive in August. In the meantime, tower assembly has commenced, along with the construction of the transmission interconnection. Horizon Hill and White Rock will contribute adjusted EBITDA of over $100 million annually to our company. Finally, our Mt. Keith 132 KB expansion project is also making progress, with the gas-insulated switchgear being installed in August. The project will achieve commercial operations in the second half of 2023 and contribute approximately $7 million of adjusted EBITDA annually. These projects, along with the Ken Hills rehabilitation, constitute the largest construction program that TransAlta has taken on in recent memory. Given the economic and construction environment we're facing, we're overall pleased with how our projects are tracking. We're only slightly above budget on our two U.S. projects, and we're broadly on track with our timing for all of the projects. Within our development pipeline, we currently have 418 megawatts of advanced stage generation and transmission projects that we're advancing towards final investment decisions. additional growth capital of approximately $730 million. They range from wind generation at Tempest to battery storage at Water Charger. I'm pleased to share that we've added our Pinnacle 1 and 2 projects to our advanced stage development pipeline. Pinnacle 1 and 2 will be a highly flexible and quick-ramping peaking facility in Alberta, designed to respond to volatile price environments. As renewables penetration advances over time in the province, Our expectation is that demand for fast ramping, highly responsive, flexible supply will be needed as a complement. Our Pinnacle 1 and 2 projects will leverage our existing infrastructure and interconnection at Keep Hills to deliver exactly this type of capacity. The project comprises four 11-megawatt Wärtsilä generating units. The engines will be connected in pairs, with each pair linked to the grid independently. We expect approvals and permits to be issued in Q4 with a potential in-service date in the second half of 2025. We also continue to advance our growth pipeline. As you recall, in 2022, we added almost two gigawatts to our renewable development pipeline across all our regions, providing significant progress towards our longer term goal of having five 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. In the quarter, we added an additional 344 megawatts of future development opportunities, and so far this year, we've added 630 megawatts, or about 42% of our goal. Notably, in the second quarter, we acquired a 50% interest in the 320 megawatt tent mountain pumped hydro energy storage project here in Alberta, and a combined 300 megawatts of wind prospects in the U.S. and Australia. We see continuing strength in power prices in Alberta and the Pacific Northwest. In Alberta, forward power prices for the balance of the year are trading higher as a result of continuing conditions of tighter supply, resulting from generation outages, delays in new asset entry, and persisting transmission constraints that are limiting imports. We also continue to see supportive prices in adjacent markets, which are experiencing lower than normal hydrology. With our strong results this quarter and improved market expectations for the rest of the year, we are once again pleased to increase our financial guidance for 2023. We're now expecting Alberta power prices to settle the year between $150 to $170 per megawatt hour, about $25 per megawatt hour higher than our guidance in Q1. We're raising our expectations for adjusted EBITDA to a range of $1.7 billion to $1.8 billion, representing an increase of 17% over the midpoint of our prior guidance. And free cash flow is now expected to be in the range of $850 million to $950 million, an increase of 29% at the midpoint compared to our guidance at Q1. 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 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. Spot prices in the second quarter of 2023 continued to exceed our expectations, settling at $160 per megawatt hour versus $122 in 2022. Year to date, Pricing through the first half of the year has been stronger than expected at $151 per megawatt hour, and we expect this strength to continue through the end of the year. As John noted, we now expect spot prices to average between $150 to $170 for the full year. Overall, we continue to realize higher merchant power pricing for energy and ancillary services across the merchant fleet in the first six months of the year, and we're able to optimize our available capacity across all fuel types. The ability of our hydro fleet to capture peak pricing was demonstrated throughout the second quarter with a realized energy price of $199 per megawatt hour, which represented a 25% premium over the average spot price and delivered a 53% stronger realized price versus 2022. Similarly, our gas fleet exceeded our expectations, capturing peak pricing throughout the quarter with a realized merchant price of $202 per megawatt hour, which represented a 27% premium to the average spot price. Our merchant wind fleet realized an average price of $75 per megawatt hour, which is below the average price of $96 we saw last year. But on a year-to-date basis, the merchant wind fleet has realized an average price of $83 per megawatt hour, which is tracking 11% higher than what the wind fleet realized in the first half of 2022. Looking at the balance of the year for 2023, we have approximately 3,600 gigawatt hours of Alberta gas generation hedged at an average price of $102 per megawatt hour, and roughly 88% of our required natural gas volumes are hedged at an attractive price of $2.27 per gigajoule. Our hedging activities aim to mitigate the impact of unfavorable market pricing on 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, which was demonstrated in our strong Q2 and year-to-date results. Our financial results for the second quarter were strong. As John noted, we generated $387 million of adjusted EBITDA and an exceptional $278 million of free cash flow. Our performance in the second quarter was led by the gas fleet with adjusted EBITDA of $166 million, a 155% improvement over last year. The gas segment benefited from expanding gross margins in the Alberta fleet through higher realized prices, and lower input costs as hedged and market prices for natural gas declined significantly from last year. The hydro segment also outperformed with an adjusted EBITDA of $147 million, a 67% increase to the same quarter in 2022. Hydro benefited from strong realized pricing, as well as from a 20% increase in production over 2022 levels due to higher water resources in the quarter. Higher water resources were driven by timing of the seasonal runoff and higher precipitation. The wind and solar segment underperformed quarter over quarter. Although we brought in new production from the garden flame facility, we experienced lower overall production due to pervasive weaker wind and solar resources in all regions compared to the same quarter last year. We also experienced lower realized merchant pricing in Alberta and lower environmental attribute revenue. Quarterly variability in wind resource is expected, and we remain confident in our fleet's ability to realize its long-term average production levels. Energy marketing had similar performance to last year, and in the quarter delivered $49 million of gross margin and $43 million of adjusted EBITDA, which is another great result for the segment. Corporate costs increased by $9 million, primarily due to higher incentive accruals reflecting our strong performance, and were also impacted by higher spending on strategic and growth initiatives and from the impact of inflationary pressures. Overall, TransAlta's results again exceeded our expectations and delivered a great first half of 2023. The strong performance of our hydro fleet continues to benefit our shareholders. In the second quarter, the hydro assets generated $147 million of EBITDA and are well on track to deliver over $500 million this year. This compares to over $500 million of EBITDA in 2022 and over $300 million in 2021. Although energy production and ancillary service volumes vary quarterly, they remain largely consistent on an annual basis. This provides long-term predictability and a floor to cash flows that is unique to this asset class. In Q2, while the strong water flows increased our energy sales, it did at times limit our ability to provide ancillary services into the market from these units. This resulted in lower ancillary sales from the hydro segment year over year. When this occurs, we are able to backstop the ancillary service sales with our gas fleet, which we did in Q2. During the quarter, we sold approximately 200 gigawatt hours of ancillary services from the gas fleet. Realized pricing continues to be strong, with a premium on spot electricity prices of roughly 25% and with ancillary services earning approximately 50% of spot prices. Together, the higher realized prices on both energy and ancillary services and higher energy flows more than offset the impact of lower ancillary service volumes in the hydro segment. Before I turn things back to John, I'll turn to TransAlta Renewables to highlight key details of our acquisition announcement. As John mentioned, we are pleased to announce a path forward on our simplification efforts. We've entered into a definitive agreement where TransAlta will acquire all the issued and outstanding publicly held common shares of TransAlta Renewables. The $13 offer from TransAlta represents an 18.3% premium to TransAlta Renewables closing share price at July 10th, 2023, and a 13.6% premium based on the prior 20-day volume weighted average price of the TransAlta Renewables common shares. Each TransAlta Renewable shareholder will have the ability to elect to receive $13 in cash for TransAlta Renewable share or 1.0337 TransAlta shares per TransAlta Renewable share or a combination of cash and shares. In each case, consideration is subject to proration, with the maximum cash consideration being fixed at $800 million and the maximum share consideration being equal to 46.4 million TransAlta shares. Upon closing of the transaction, the pro forma ownership of the combined company will be approximately 85% held by current TransAlta shareholders and 15% held by current TransAlta Renewables shareholders. The board of directors of each company has independently determined that the transaction is in the best interest of their company and fair to their shareholders. The transaction was also unanimously approved by the independent members of the TransAlta Renewables board and they have unanimously recommended that RNW shareholders vote in favor of the transaction. In terms of next steps, we expect to obtain an interim order from the Alberta Court of King's Bench establishing the process for TransAlta Renewable Shareholder approval, and we'll mail out the management information circular to TransAlta Renewable Shareholders on or about August 25th. A special meeting of TransAlta Renewable Shareholders to consider the arrangement is expected to take place on or about September 26th. The arrangement must be approved by at least two-thirds of the votes cast by TransAlta Renewable shareholders represented at the meeting and by a simple majority of the minority of public shareholders of TransAlta Renewables represented at the meeting. The transaction is subject to regulatory approvals and other customary closing conditions and is expected to close in early October. And with that, I will turn the call back over to John.
spk07: 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, and Mount Keith Transmission projects, while progressing the White Rock Wind and Horizon Hill Wind projects to completion early in 2024, expanding our development pipeline by 1,500 megawatts with a focus on renewables and storage, completing the rehabilitation of Kent Hills Wind, advancing the long-term contractiveness of our Alberta electricity portfolio, delivering permanent financing for our Oklahoma growth projects, and achieving EBITDA and free cash flow within our increased guidance ranges. I'd like to close by highlighting 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. The acquisition of TransAlta Renewables will further diversify and increase the contractiveness of our cash flows. 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 of 75% by 2026 from 2015 levels. And our board has recently approved our commitment to net zero by 2045. Third, as noted earlier, we have a diversified and growing development pipeline and a talented development team focused on realizing its value. And 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 our employees and contractors for the excellent work they have done to deliver our exceptional quarter. Thank you. I'll turn the call back over to Kiera.
spk04: Thank you, John. Michelle, would you please open the call for questions from the analysts and media?
spk03: Thank you, ladies and gentlemen. We will now begin the question and answer session. Should you have a question, please press star followed by the one on your touchtone phone. You will hear a three-tone prompt acknowledging your request and your questions will be pulled in the order they are received. Should you wish to decline from the polling process, please press star followed by the two. If you are using a speakerphone, please lift a handset before pressing any keys. Your first question comes from Darius Lawsney with Bank of America. Please go ahead.
spk10: Hey guys, good morning. Thank you for taking my question.
spk08: Maybe just at the outset, I was wondering if I could get your thoughts on the announcement yesterday from the Alberta Commission that put a pause on new applications for wind and solar. I don't believe there should be much of a material impact to your pending projects in the pipeline, but maybe if you can comment on that and maybe more broadly How do you see this sort of impacting your longer-term plans as far as where to concentrate your development pipeline? Thank you.
spk07: Yeah, good morning, Darius, and thanks for that question. I mean, look, the impact of the announcement yesterday will be limiting, at least for a period of time, the advancement of renewable project in the province for that six-month period while there's consideration being given to the pathways going forward. I have to say that from our own perspective, we have raised in the past the importance of making sure that we have a balanced approach to the growth that we're seeing in renewables in the province. I think people have heard me say this before, it's like a three-legged stool and it's critical that the grid is clean, but also reliable and affordable. And I think spending a bit of time to review how the system maintains affordability and reliability as we begin to transition towards the lower emitting grid is critical. So we're looking forward to that consultation process that we'll be having that will involve the Alberta Utilities Commission. We take a long-term view on our development pipeline in Alberta, and I can tell you it's business as usual for us in terms of trying to advance the our projects here. In specific response to a couple of your questions, you know, we don't really see it having a significant impact on our advanced stage projects. Water Charger and Tempest have Alberta Utilities Commission approval and we continue to advance those forward and are working hard to get them completed and announced this year. Pinnacle one and two, which we've just announced, would be gas investments in the province. So again, they wouldn't be impacted by the halt, as we understand it, that is being put in place as a result of the Alberta Utilities Commission decision. In terms of where we're thinking overall in Alberta, I would say that we continue to be committed to all of our decarbonization net zero targets. We continue to see demand for renewables in the province. We expect kind of renewables growth to continue once this review is completed in the province. We are, though, for sure, I would say, turning our minds to what other attributes the system will require in Alberta as it evolves in the coming decade and having, you know, fast response battery and some peaking capacity that can create that reliability and stability that the market will need periodically is also something we're looking at. And that's really what Pinnacle 1 and 2 are all about, along with Water Charger.
spk10: Great. Thank you for that detail.
spk08: Really appreciate it. If I could ask one more on the updated guidance for the full year, obviously very robust results, $200 million more on free cash flow. to the extent that the balance of the year continues to come in above expectations. Is there any possibility of perhaps raising the cash contribution in the R&W buy-in, or is it more or less set as you guys announced earlier in July, and that's how you plan on proceeding?
spk07: Yeah, no. So the transaction with TransAlta Renewables is fixed. There is, from our perspective, no prospect of any change in the composition of the consideration for that transaction.
spk00: I'd just say that we are conscious that when the transaction closes, there might be some movement in shareholder interests from TransAlta Renewables' side. And so you'll notice that we did reinstate our NCIB program back in May, and so we're very much able to go out and support the stock if there is some churn.
spk10: Okay. Thank you both very much. I'll turn it over here.
spk03: Thanks. Next question comes from Mark Jarvie with CIBC. Please go ahead.
spk11: Yeah. Thanks, Gordon. So just coming back to the moratorium, a couple other questions. One, do you think this will have any impact on, I guess, the outlook for pricing or ancillary services here if there is a little bit of a slowdown in the I guess the penetration ramp-up of renewables and then just maybe clarify, you said nothing, no impact on Tempest, Watercharger. What about some of the, I guess, the next phase of projects like at Ripplinger, Sun Hills? And I guess the last little question would be if they do constrain where you can site new projects, can you talk a little bit about the ability to build on existing sites, whether it's your thermal sites or legacy wind sites?
spk07: Yeah. You know, Mark, maybe I'll start with the back half of your question. Look, as we were progressing our development pipeline, the projects that were sort of next up in terms of moving through the process for us would have been Ripplinger and Sun Hill Solar. And I think generally we would have been looking to begin advancing approvals for those projects kind of in the back half of this year and the early part of next year. So I would say that those projects, which we continue to work on, would be a little bit delayed in terms of being sort of in the permitting queue to get them completed. We'll see how the consultation progresses. I think there's a strong desire on the part of the province to ensure reliability in the grid, which makes sense for us. That's something that we've been speaking to. And also the notion of making sure that various stakeholders in rural parts of the province that are being impacted by the dramatic renewables growth that we've seen have been addressed. You also have to remember that our development pipeline also has an extensive exposure to projects in the United States and Australia, and we're able to accelerate and kind of move the focus of the growth that we have into different jurisdictions. But from a long-term perspective, I don't think we're expecting much in the way of change. It's sort of business as usual. On your question on pricing, when we look at sort of 2024, the balance of 2023, and and into probably even 2025, I would say, Todd, I'm not sure that we think that the announcements would have much in the way of a significant impact. There's plenty of projects that are under construction. There's some large gas plants that are looking at coming in, most notably Kineticorps and also the Suncorps plant at the tail end of of next year. So, you know, the slowdown would be, you know, projects that are still a number of years away from being able to see the light of day. So I think in terms of our near-term view, you know, I'd say very little impact.
spk11: Okay. That's very helpful. It makes sense, John. And then just, you know, when you think about some of your growth objectives or the main growth objective, sort of the 2 gigawatt, $3.6 billion project, and you're seeing, you know, things like this maybe delay in Alberta, you know, still some constraints on supply chain and cost. How would you frame that now in terms of your path forward on that? You know, if it takes a bit more time, I assume you guys are comfortable with that. How would you sort of frame your, I guess, willingness to stick to that timeline versus just continue to be disciplined and, you know, you've got excess cash to use for the buyback, just sort of, you know, your updated views in terms of, how aggressive you push for those goals right now?
spk07: Yeah. You know, look, I'll begin by saying that the TransAlta TransAlta Renewables acquisition is, at least from our own perspective, a pretty significant acquisition of generation. I mean, we're acquiring kind of the economic interest in that balance, you know, 1.2 gigs essentially of generation that we didn't effectively own as a result of the structure that was there. But in terms of the incremental projects going forward. Look, we're remaining super disciplined. We won't do projects until we've de-risked them as much as we possibly can and are comfortable with the contractual terms or, you know, when you're looking at projects like Water Charger, that our optimization team is ready to go in terms of what they will be doing to create value for our shareholder in those projects. So we think our targets are appropriate ones. We continue to advance them. We like our 418 megawatts of advanced stage project that we're seeing get through. I think for us, we're just going to remain super disciplined on our capital expenditures. We're not going to pull the trigger on projects unless we're getting the kind of returns that we need for them. And, you know, with the appropriate contingency that we have, we think prices have stabilized, I would say. I think over the last little bit, you know, what used to be about a million and a half dollars a megawatt for development has inched up, I'd say, Todd, closer to two. But it's kind of staying around, too. On the wind side, we're a little bit concerned about the supply chain and kind of 25-ish, 26-ish There's a lot of wind development that is going place and there's work to do for the OEMs to be able to supply all of that. But it's pretty much steady as she goes from a TransAlta perspective and, you know, always with a view of making sure we're creating value for our shareholders. We will be at our investor day in November looking to update our targets, broadly speaking, to the end of the decade. It's amazing how quickly time goes by. So stay tuned for that. But I don't think there'll be any surprises in terms of what our approach is going forward.
spk11: And just to follow up that, you talked about maintaining good returns. How would you frame the returns on the advanced stage projects now that you have in front as you come to a final investment decision and I'm particularly interested to see how the returns on something like Pinnacle 1 and 2 would square against some of the other projects that are in the advanced stage.
spk07: Yeah, I mean, look, we look at it as we assess each project in light of the sort of risk elements associated with the project. So we've got like an overall sort of hurdle rate that we tend to target for the company and then it either goes down or it goes up depending on the characteristics specifically that the project has, including whether or not You can put debt financing on it, you know, how easy it is to actually construct it, how confident we are in the data, what the contracting strategy is. So it is a, how do you put it, it's sort of a sliding scale in terms of the way we look at it. Certainly, you know, projects like our water charger, pinnacle type projects would be higher returning projects than, kind of contracted renewables. They need to be, candidly, given that there's a merchant component to what they have. So our focus in those projects would be to get our capital out of them as quickly as we possibly can. So we expect much higher returns, whereas if you have a project that you've contracted for 15 or 20 years and gives you that stability of cash flow and the ability to put project financing or other debt against it, it's a different assessment. So I don't know if that gives you the kind of color that that you need, but we do look at it from a broad portfolio perspective, I'd say. Todd, I don't know if you have anything else to add to that.
spk00: Well, I was just going to add, look, clearly inflation is higher underlying rates. We've taken that in consideration even on what I would call the standard fully contracted wind facility on our return expectations. So I would say that return expectations are inching up, and John really go into the detail about merchant is really a whole different spectrum of return expectations.
spk11: I know that makes sense, and good to hear the returns are inching up. What would you say would be the premium required? Can you quantify in terms of basis points or percentage-wise for that merchant exposure?
spk10: Oh, let's put it this way.
spk07: It's several hundred basis points higher than it would be for contracted renewables from a TransAlta perspective. So well north of 10%. Let's put it that way. Well north. Yeah, well north. Yep.
spk11: Okay. All right. Thanks, Sean. Thanks, Todd.
spk03: Your next question comes from Ben Pham with BMO Capital Markets. Please go ahead.
spk12: Hi, thanks. Maybe to start off on the clean electricity growth plan, can you talk about some of the moving parts on White Rock Horizon? Can you talk about the timing being revised? In the main context on the CapEx movement and a little bit of movement on the EBITDA for Horizon Health?
spk07: Yeah, Ben, you came across as pretty muted, but I think I caught the gist of what you were asking. I mean, in terms of the timing on the plan, you know, look, our advanced stage projects are probably about another 25 to 30% of the targeted EBITDA that we want. We do expect to be bringing some of those forward. We like the fact that they're in multiple jurisdictions, those in Alberta, feel to them, but also a feel in Australia where we continue to progress things going forward. We remain confident in hitting our target in terms of getting financial investment decisions on the two gigs by the end of 2025. We are seeing appropriate returns, I think, for the projects generally, but given the inflationary environment that we see, we're even being more cautious than usual in terms of buttoning down the cost of developing the projects and de-risking them as much as possible. So that's generally the approach.
spk00: Todd? And John, sorry to say, Ben was commenting on specific issues around Horizon Hill and white rock delays and capital cost creep in there, I think, Ben. And so as John updated in the call, the construction of the turbine facility is going extremely well. Lots of progress there, and it really is the transmission interconnections I think on both sites that are really critical paths and driving delays, and there's just some equipment supply in there, and then the final interconnections that need to be done.
spk10: Yeah, sorry, Ben. I didn't quite catch that.
spk12: Oh, no, that's okay. It's good to get the broader view first, too, on that. Can you also comment on why is the – I know there's snowpack in Alberta. It's helping out that side, but we're – We're seeing mostly drought conditions elsewhere. Is this more of a regional difference? And then maybe just any comments on how do you think about the resource projections you have and engineers with Q2 being quite stopped and how that feeds into even how you underwrite projects as well?
spk00: Well, I think we did see an early melt this year and a lot of water came through in Q2 versus some that often spills into July in our Q3 results. We saw a lot of the melt come in Q2, but we did see high precipitation in the period as well. Long term, I mean, clearly if the melt comes in Q2, we'll have less production in Q3. But as we kind of, you know, talk through their even though we got the extra energy in the water in Q2, it did impact our ancillary services sales. So if we get a little bit less water in Q3, then we have the opportunity to offer more into the ancillary market from the facilities. Longer term, you know, we're still confident in the long run hydrology there and really no concerns on the long run average production that we get from those facilities.
spk07: Yeah, I mean, the kind of variability we're seeing is kind of within the zone of what our expectations would be in what's seen over know the more than a decade of data that that that we have in fact it goes a lot longer than that i mean this year we had a lot of water in june um i think ben as you know we don't we don't have as much storage as we'd like on on our systems uh here in alberta so you can't actually store the water we've gotta we've gotta spill it and manage the river flows as we go uh forward so uh in light of the overall management that we do there and and the constraints that we have in the facilities To Todd's point, we ran them, and there was disproportionately more energy was generated from the fleet rather than ancillary services, but our gas fleet picked up the slack on the AS side.
spk12: Maybe just one last one, if I may. You mentioned in response to the question around the 2025 targets, R&W being quite a significant transaction. Are you maybe suggesting that... you really like when you're doing R&W on a proportionate basis, you've effectively met your 2025 targets in a sense, because it always was some sort of M&A in it. And then can you confirm you mentioned around investor day, there's going to be probably no change in methodology. Is it still going to be on a gross basis, that guidance, or you may want to relook at that?
spk07: Yeah. Look, when we talk internally about what we're doing and when you look at the TransAlta Renewables acquisition. I mean, you know, we're spending quite a bit of money for that. It is growth from our perspective. We're preserving cash flows from those assets. You know, we're not sort of explicitly saying that, you know, check, we've made the two gigawatt target. We continue to advance and trying to add incremental megawatts going forward. And we're confident of moving that forward. The key criteria for us is just making sure that the projects that we do create value for our shareholders. I mean, if If all we needed to do was hit two gigs, we could do it, but you may not get the kind of projects from the company that you'd want us to have. So we're going to stay disciplined. In terms of investor day, yeah, you will be seeing sort of growth. We're not proposing to change the methodology or anything like that. It'll be very much, as we work through it, similar to what you're seeing now in terms of a long range, you know, megawatt target, you know, broad speaking, an annual pathway, you EBIT targets for the company and kind of our expectations on what the capital spend would be based on the best information we have at the time.
spk10: That's great. Thank you. Thank you, Ben.
spk03: Your next question comes from Rob Hope with Scotiabank. Please go ahead.
spk01: Morning, everyone. Just one for me. I want to ask about conceptually how you're thinking about the peaker plant at Key Pills. As we see Connecticut and Cascade and the Suncor Project Center service, is the expectation that kind of your coal-to-gas conversions could be seeing less utilization and won't have that ramping capacity that will be required in a renewable heavy environment so that this peaker investment is allowing you to use existing infrastructures and interconnection to better meet the more volatile pricing environment?
spk07: Yeah. Good morning, Rob, first of all. Look, I think the way you've characterized it is sort of an appropriate one as we see the evolution of the fleet. When you look at our coal to gas units now, we tend to describe them, and I think you've heard us describe them as kind of Alberta peaking units. They'll be There'll be periods of time where they'll be running at relatively high capacity factors and there'll be other periods of time that we won't need them as much. But I think you've hit the nail on the head when you're looking at not just Pinnacle 1 and 2, but even, you know, Water Charger, for example. Those are products that will be oriented towards meeting what we anticipate will be increasing intermittency in the grid and more significant volatility in terms of price movement. So having fast response products will be critical, I think, going forward, both to meet the reliability that the grid is going to need, but also from our own perspective to create value for our shareholders. Different products under each of the different assets, some of them are more what I would call energy arbitrage assets. Some will be able to provide more ancillary services support, but we're very much looking, as it relates to Alberta, kind of two pathways. One would be an overall renewables build-out in time as the province continues to make its transition to decarbonization. And secondly, what are those kind of reliability, fast-responding capacity products that the province is going to need to ensure the stability of the grid. So those are the two pathways that we're looking at from an investment perspective.
spk01: I appreciate that. And actually, maybe one follow-up. You did add some hedges in 2024 and 2025 that looks like to be a good pricing, but Overall, how are you thinking about the kind of trade-off of adding hedges in 24 and 25 versus where the forward curve is, as well as just maintaining optionality?
spk07: Yeah, look, our hedging team is in there and feel, I think, that the kind of pricing that we're getting in – and I'll talk mostly about 24 because 25 is a ways away – And, you know, the market isn't all that liquid, but we're getting, I would say, some reasonable early liquidity in terms of 2024. I think we're seeing prices that are in the high 90s right now that are there. The team is happy with what they're seeing. They're layering on edges. You have to remember, we also have our CNI business, which is a multi-year business, which provides hedging that goes out. Typically, I think on average around three years, I would say, Todd, going forward. So we continue to do what we've always done. And that is, you know, look at our internal modeling, where we think the fundamental price is going to be. How do we de-risk elements of the fleet at the same time leaving enough open links in the market? in the fleet to be able to capture kind of the volatility that we expect will increase. I think as time goes by, it'll become less about, you know, what you made in the 60% of the hours in the marketplace, but much more about how you did in that 25, 30% of stronger hours in the market. And we're really focused on that part of the market and shifting the capabilities of our fleet to be responsive there.
spk05: Thank you.
spk03: Your next question comes from Andrew Cusk with Credit Suisse. Please go ahead.
spk09: Thanks. Good morning. I guess the first question is for John, and it ties into some of your last comments there. When we look at the Alberta power market, we're having higher highs and lower lows. It's a very bifurcated market with maybe longer-term prices starting to average down a bit. Some of that's reflected in your hedging program where 24 for 25, kind of flat on price, but you've got your gas hedges at a greater dollar value, carbon prices obviously go up each year. All of that implies kind of lower margins. So I guess when you think about all that, is that kind of baseload hedging program to give business stability and certainty on a high degree of the cash flows, and then you're trying to capture around it for that sort of 25% of the market where there's maybe a greater volatility?
spk07: I think, Andrew, good morning, by the way. You've captured it sort of exactly right. That is the mindset. And, you know, what's interesting is, you know, in the past when we've talked about average hours, they were really meaningful, at least from my own perspective, because there was, you know, the standard deviation around that was a little bit tighter, if you see what I'm saying, whereas now the path to the average is what's really going to matter, I think, should go to 24, 25. We've had these kind of discussions, I know, with you in the past and others. So I think you've got it exactly right. It's how do you kind of de-risk the base and create that sense of predictability? And that is both a revenue statement. at a cost item with the gas that we're procuring to kind of lock in margin as we go forward, and then making sure that you've got fast-responding length to be able to take advantage of the volatility when it comes, and candidly, to create reliability for the grid here in the province of Alberta.
spk09: Okay, that's great. I appreciate that. And then maybe just on Pinnacle 1 and 2, and if I could maybe geek out a little bit on some of the ops conditions on those units. It's been a while since I've looked at them, but my recollection is sort of like two to three minutes to full load on a ramp rate, 10 minutes for efficiency and about an 8,000 heat rate. Is that all about broadly right?
spk07: Yeah, I think in terms of the ramp rates that you have, you've got it pretty much bang on the mark. I think their heat rate is probably a little bit higher than But at least from our own perspective, they'll be running at times when the heat rate isn't going to matter all that much from a pricing perspective, if you see what I mean, Andrew. What really matters is the speed with which they're able to respond, and that's our focus. The other thing I would say is they were an opportunistic purchase that we made probably two years ago now. They became available on the market, and in anticipation of the evolution of the market, we – We picked them up for pennies on the dollar. Let's put it that way. So we're shipping them up here now from the PAC Northwest and look forward to advancing them.
spk09: So the pennies on the dollar, that sounds like very high ROIs.
spk10: That's the goal. That's a good goal to have. Thank you. Thanks so much, Ed.
spk03: Your next question comes from Najee Beidou with IA Capital Markets. Please go ahead.
spk13: Hi, good morning. I just wanted to go back a bit to the topic of growth and CapEx pressures. Seeing a bit of sort of higher sort of dollar investments on the wind side. I guess with things like Water Charger and Pinnacle and maybe just a function of those specific assets in that specific market, but are you seeing sort of better risk-adjusted returns on the solar storage side maybe versus wind? And if that's the case, what are some of the ways that maybe you can accelerate development on that side of the house, seeing as how most of the pipeline today is made up of wind projects?
spk07: Yeah. Good morning, Najee. I would say, you know, if you were to kind of draw a spectrum of kind of returns, I would say that we would see probably the lower level of returns more in contracted solar, I would say, higher returns in contracted wind. And look, we have particular expertise in wind. And for us, that's a core part of our business. And then it gets higher in the spectrum as you begin moving towards some of the peaking gas capacity that we're looking at, and then some of the battery storage that we would be looking at. And I would say that even when we look at like Kent Mountain and some of the pump storage that we have, the kind of returns we would expect for those projects would be significantly higher. We do look at it from a portfolio perspective. You know, there is a finite amount of, you know, storage and kind of peaking gas that we would put in because what's critical, I think, for those kind of assets is to have those really strong optimization capabilities that you need to be able to extract value from them. We definitely have that in Alberta. So that is a focus for us. It's not something that is pervasive in terms of all parts of North America. So we continue to focus on, I would say our investments still are oriented towards green. You'll see the company continuing to execute on renewables as we go forward. We'll be opportunistic, I think, on natural gas investments that we think we can add value to. as a company, and we think that we can get acceptable risk-adjusted returns for all of those types of projects as part of the portfolio that we're building out.
spk10: Okay, understood.
spk13: I also wanted to get your thoughts on the sort of emissions credit, be it inventory or... annual generation, does that change at all with the R&W buyout, either in terms of the amount or strategy? Just how are you thinking about the sort of emissions credits post-R&W?
spk00: Yeah, we can talk about that. Yeah, not a real big change, Najee. Renewables was typically selling the credits that it produced on an annual basis, and so TransAlta Renewables wasn't actually even carrying an inventory balance that balance was all developed and held and strategized at the TransAlta Corp level from both the hydro and the wind assets, as well as purchased credits. So, I mean, you'll notice we are carrying a fairly large balance in there, and we have a lot of internal discussions about how and when to utilize those credits. You'll see in Q2 we chose not to retire any credits and simply pay the $50 obligation from last year's production, and we'll continue to look to how to optimize that inventory level.
spk10: Okay, so no changes to the treasury then.
spk13: Maybe just one last question. So the hydro is, again, on track for a very strong year. I think in the past in a more – to normalize power price environment. I think you were talking, uh, sort of a 200 million ish run rate, even the number for the hydro fleet. Is that still the right number given what we're seeing in the market and how, how the dynamics are playing out? Or do you think that that number could be materially higher?
spk07: Well, we, we've, um, so I think you're, you're right. Your memory's right, Najee. I think when we were first thinking about, um, the post-PPA period and we were thinking of our hydro performance, I think it was actually around 240 million that we were thinking the hydro run rate was going to be, and that was a little bit of a guess. We've seen it, I think in 21, it was around 300 million. In 22, it was just a little bit over five. And look, we're tracking to another let's call it 500-ish year on the hydro fleet. Look, we've had really elevated pricing, I would say, in the province of Alberta over the course of at least the last two years. If you were to sort of ask me what I think kind of the normal run rate is, I mean, we'll see how the markets develop in 24 and 25. You know, we would expect sort of average pricing to come down a little bit, but we would also expect volatility to be pretty meaningful. So, The ability, I think, of the hydro fleet to capture those economic rents, I think, will remain high. Will they be 500 million? You know, that's a big number. But, you know, the low 200s feels lowish, I think from my perspective as we go forward.
spk00: Yeah, I think when we put those numbers out there in the 200s, it was really predicated on sort of the last 10 years or 20 years of average. It is backward-looking. Probably in that $60 to $70 price range. I think we see a step change up from there. Carbon impact on power prices in Alberta will have a real impact. somewhat through the balance of the decade, but then even into the 2030s will be very dramatic on the long-term power price. So it will go up and down, but I think the trend is definitely for much stronger prices over the next 10 years than we saw in, say, the 2010s.
spk07: And Najee, I think as the grid changes and evolves with more renewables coming in, I think the value of hydro and the kind of, you know, reliability and ancillary services support that it provides in the marketplace will actually, yeah, you know, my view is it should increase over time.
spk10: So I think we're really well positioned with the fleet. That's great detail. Thank you.
spk03: Your next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
spk02: Yeah, good morning. John, I know you've had a whole day to think about it, but assuming there is a slowdown in renewables in Alberta beyond the six-month period here, how would you think about the commercial tension surrounding the next phase of corporate PPAs in Alberta? Do you think there might be an opportunity over this six-month period to strike while the iron's hot related to some of your uncontracted renewable capacity in the province?
spk07: Yeah, good morning, Patrick. Look, you're right. It's been 24 hours, I think almost to the hour, since the announcement has come up. And, you know, look, it's a decision that we know the province of Alberta, you know, wouldn't have taken lightly. I think they see some of the pressure points in the province, and they're hearing some of the feedback they're getting From folks in in parts of the province and they want to make sure that we do this in a thoughtful way So we completely understand that I do think to your point that those projects that are through the queue Let's put them, you know put it that way like our tempest project I think are in a particularly good position now to be able to get PPAs and move on from a contracting perspective given there. I would say comparative scarcity and I also am hopeful that it means that we can do more like we did with Lafarge on some of the other renewables that we have where we can get longer contracted contracts for some of our merchant renewable fleet. Not so much from hydro, but certainly from the wind that we have in Alberta to be able to meet sort of the ESG and environmental goals that third parties have. As you know, Alberta is really the only truly deregulated market in the country. So the good thing about it is that there's people that are trying to meet their needs or coming to Alberta to kind of get the supply that they need to meet them. The challenge is, and I think this is what is reflecting the province's position, is that that incremental build-out isn't necessarily built on fundamental supply and demand, you know, balances within the province. And so it's a balancing act in terms of going forward.
spk02: Okay, that's great. Thank you. And then I guess it's been less than a month since you announced the roll-up transaction, but just given the focus performed well, I guess validating your strategy of simplifying the story. I know the near-term priority is closing R&W here, but are there any other corporate structure optimization opportunities that you might be able to point to that... might serve to keep this valuation momentum going beyond cleaning up R&W?
spk07: Yeah, I mean, look, we're focused on getting the R&W transaction done in that late September, actually early October timeframe. it's a critical thing that we need to do. We're pleased that it's been well received in the marketplace. You know, we're focused on our upcoming investor day where we're going to talk about kind of our pathways going out for the balance of the decade. You know, our M&A team, we have a small team, but they're a very capable team. They're continually, you know, looking at the funnel. It's a very wide funnel of opportunities that arise and they see stuff that ranges from, you know, renewables in each of our three jurisdictions to alternative fuels, which is kind of new, to even occasionally some natural gas opportunities that might exist. So we're still active from that perspective. Very mindful, Patrick, on just the cost of things. We still find assets in the M&A market to be a bit expensive, I would say. That doesn't mean that there aren't opportunities there. I think there are. But we're going to be super disciplined and make sure that if we proceed with something, whatever we pay makes sense for our shareholders.
spk02: Okay, that's great. Thank you very much and have a great weekend.
spk03: Thanks, Patrick. Our next question comes from Chris Varco with Calgary Herald. Please go ahead.
spk06: Hi, John. With all of the renewable projects in Alberta that have been proposed over the last couple of years, What impact do you think it's having on the Alberta market? And you talked about reliability concerns and some of the other issues. And I guess just taking a big picture, what are some of the broader impacts you're seeing?
spk07: Good morning, Chris. In terms of the renewable build-up coming into the province, I mean, I think, so first of all, I would say we have a lot to be proud of here in the province in terms how much we've decarbonized the grid. And I think that journey continues. I think if you go back, oh gosh, like probably even five years ago, certainly 10 years ago, our emissions per megawatt generated in the province were probably more than double what they are today. So a tremendous amount has been accomplished, and a lot of that was on the back of kind of the shift from coal to natural gas. We have seen significant renewables build out in the province. That isn't surprising to us, given kind of the state of the marketplace here in Alberta and, you know, as a deregulated market, particularly given corporate ESG requirements, I think there was a rush and I think continues to be demand for renewables in the marketplace. In terms of impacts, look, we've been talking for quite a while to, you know, here in Alberta, frankly, everywhere, because it's similar challenges we're seeing everywhere that we operate about the importance of kind of aligning the importance of having clean generation with affordability and reliability. And what we're seeing with the renewables is more, I would say, a few things. So when it's a windy day or a super sunny day, you've got a lot of renewables generation that is actually in the marketplace. And then if all of a sudden the wind dies down or all of a sudden we're getting to dust, and we're getting into the evening, the solar just goes away. And it's not like it's 50 megawatts. It's large amounts of generation that are online, offline, if you see what I'm saying. So that increases the kind of volatility that you're seeing in the marketplace. And really, from an Alberta perspective, that's up to our gas. And I'm saying gas because a little bit of coal we have left is going to be converted to gas to backstop that and make sure that that is there. And in a way that is reliable and affordable for Albertans. I think the other element with the renewables build out is I think it does create pressure on transmission. We have more dispersed generation coming across the province and kind of building out that transmission that you need to be able to take the power where it's being generated and move it to the populated areas or the industrial areas of the province is an incremental cost burden that we need to be mindful of. And, you know, finally, just from a regulatory permitting, you know, supply chain, you know, making sure that stakeholders in parts of the province that have seen quite a bit of development are being heard is another third factor that that I think needs to be addressed. So there's a lot of change. It's come relatively quickly. And, you know, we're seeing some of the impacts of that. And I think the province is trying to just make sure that we have thoughtful pathways going forward and that the pace, I think, is an appropriate pace to maintain that three-legged stool of clean, reliable, and affordable for our province.
spk06: Just to follow up, sort of a two-part question here. Maybe I'll start with the first one, and that is you mentioned the stakeholders in rural Alberta being impacted. What are you hearing from rural landowners when you're proposing renewable projects, and how are you addressing their concerns?
spk07: Yeah, I think from a stakeholder's perspective, I think it's very, very diverse. I don't think there is, at least our experience would be that there isn't a single voice or a singular view on what we're seeing when we're out there getting things developed. I think there is a significant group of individuals that are welcoming of the development that's taking place in the sense of creating revenue streams for them and, you know, creating economic opportunities for people in those, you know, jurisdictions. I think of our operations in southern Alberta and now even east central Alberta. For sure, there's jobs that are being created and opportunity for some of the landowners to create revenue. I think folks that have concerns, they're legitimate concerns and we listen to them and it has everything to do with impacts to you know, birds and bird migration, you know, bats to sidelines, candidly, in terms of being able to see that we live in a beautiful part of the world. So being able to have that view that you've always had in an appropriate way, I think is a appropriate view and people express it. And, you know, it's our responsibility to hear that out. It does impact how we cite things. It impacts where we cite them. And I can tell you, we take the reclamation obligations that we have when it's all done very, very seriously. And, you know, we've actually reclaimed the first wind farm that was built in Alberta. So we have a sense of what that's about and returning the land to the state that it was in. We also have, as you know, years and years, candidly, decades of experience with mine reclamation. So it is critically important that that work is done and it's done from people who you know, that are determined to do it in an appropriate way. So hopefully that gives you a bit of a flavor. There isn't a singular voice. It's everything from a spectrum of opportunity to concern about what happens at the end of the life of a wind farm and everything in between.
spk06: And just to ask you, what signal do you think the pause is sending to the industry? Will it impact your investment decisions or do you think the industry's investment decisions, such as perhaps looking to other jurisdictions because of the pause?
spk07: Look, I, I, I think a lot of the, um, a lot of the companies that I think are in kind of the vanguard of building out new generation in Alberta also have projects in other jurisdictions. So, so they, they, they look at, you know, deploying capital in, in, in multiple places than they are. And I look at our company, you know, we're in Canada, the U S and, and Australia. And, um, the development environment and opportunity sets are relatively similar in all those jurisdictions. So, to a certain extent, you're agnostic about where you go. I think with respect to this pause that we're seeing to have the consultation done, it's six months. We take a long-term view in terms of our projects. There's still a lot of projects that that are effectively grandfathered and are being built out, including ours, and we're committed to seeing those through. I think we'll end up with a thoughtful response from the Alberta Utilities Commission and the government when the consultation process is done, and I think we'll end up being better developers and builders of these assets as they go forward. I mean, I can only speak for our company and on other companies, but we're staying the course. And the projects that we would have been putting in the development or in the permitting queue sort of imminently, we're continuing to work on and develop with a view to seeing them being realized eventually in the longer term.
spk10: Thank you.
spk03: Ladies and gentlemen, as a reminder, should you have a question, please press star followed by the one.
spk10: If there are no further questions at this time, please proceed.
spk04: 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 later today or on to next week. Thank you so much.
spk03: Ladies and gentlemen, this concludes the conference call for today. We thank you for participating and ask that you please disconnect your lines.
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