Good morning. My name is Amy, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation's Second Quarter 2024 Results Conference Call. Ms. Valentini, you may begin your conference.

Thank you, Amy. Good morning everyone and welcome to TransAlta second quarter 2024 conference call. With me today are John Kousinioris, President and Chief Executive Officer; Joel Hunter, EVP, Finance and Chief Financial Officer; and Blain van Melle, EVP, Commercial and Customer Relations. Today's call is being webcast, and I invite those listening on the phone lines to view the supporting slides that are posted on our website. A replay of the call will also be available later today, and the transcript will be posted to our website shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualifications set out here on Slide 2, detailed further in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced during today's call are in Canadian dollars, unless otherwise noted. The non-IFRS terms we used, including adjusted EBITDA and free cash flow, are also reconciled in the MD&A for your reference. On today's call, John and Joel will provide an overview of TransAlta's quarterly results. And after these remarks, we will open the call for questions. And with that, let me turn the call over to John.

Thank you, Chiara. Good morning, everyone, and thank you for joining our second quarter 2024 conference call. 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 peoples of Treaty 7, which includes the Blackfoot Confederacy comprising the Siksika, the Piikani, and the Kainai First Nations; the Tsuut'ina First Nation; and the Stoney-Nakoda, including the Chiniki, Bearspaw, and Good Stoney First Nations. The City of Calgary is also home to the Metis Nation of Alberta Districts 5 and 6. I'm pleased to report that we saw another quarter of exceptional operating and financial results. We had strong performance from our contracted and merchant generating fleets, which benefited from our optimization and hedging strategies and improved average fleet availability of 90.8%. Our highly capable operating and world-class trading teams ultimately delivered adjusted EBITDA of $312 million, free cash flow of $172 million or $0.57 per share, and net earnings attributable to common shareholders of $56 million or $0.18 per share. And we continue to maintain a strong balance sheet with over $1.7 billion in available liquidity, including $350 million in cash, which positions us well to deliver on our 2024 priorities. I have a number of updates on our strategic initiatives to share with you this quarter. First, and as you all know, we completed the transition of our Chief Financial Officer role at the beginning of July, and I'm very pleased to welcome Joel Hunter to his first quarterly conference call at TransAlta. Joel brings over 26 years of experience, spanning various areas in the energy sector to our company, and we're excited for him to join our team and drive our financial strategies forward. Next, I'm pleased to announce that we have achieved commercial operations at our 200 megawatt White Rock East and 200-megawatt Horizon Hill wind facilities in Oklahoma. Our Oklahoma wind facilities, along with the recently contracted sale owner production tax credits, will contribute over $100 million to our company in adjusted EBITDA annually. Third, we continue to work on securing regulatory approval for the Heartland Generation transaction. The regulatory review process with the Competition Bureau has proven to be more challenging and protracted than we originally anticipated. We have been working to address the Bureau's perspectives regarding the transaction and the Alberta electricity market, and expect to have a better sense of the timing and likelihood of the success of the transaction in the coming weeks. Fourth, we're seeing an acceleration of significant opportunities at our legacy thermal sites in Alberta and Washington State, which I will speak to later in the call. And finally, during the quarter, there were a number of regulatory announcements made by the government of Alberta on the restructured energy market. Last month, the Ministry of Affordability and Utilities published an open letter providing direction to the Alberta electric system operator on the design and implementation of a restructured energy market in the province. The restructured energy market is expected to include the introduction of the day ahead market, strategic energy bidding mechanisms, the allowance of a higher price count and potentially negative pricing and shorter settlement windows shifting from hourly to sub-hourly intervals. We have previously advocated for and support a number of these market reforms. The restructuring is intended to result in stronger incentives for dispatchable generation and provide long-term signals for investment to promote grid reliability within the province. The design is to be broadly finalized by the end of 2024, with implementation expected to occur during the 2026 calendar year. We are confident that through the consultation process, in which we are actively involved, the right framework will be put in place to ensure strong future development opportunities for all forms of generation to responsibly achieve a net zero grid in a manner that ensures reliability and affordability for Alberta. We have seen multiple grid alerts since the beginning of this year, and the province hit new records for peak load twice in July. These were periods where our Alberta Thermal fleet was very much required to ensure grid reliability, illustrating its continued value and the need for additional capacity to backstop the intermittency of renewables in the province. The interim market power mitigation and supply cushion regulations that I spoke about during our last quarterly call took effect on July 1. Due to high temperatures, higher-than-expected load requirements and subsequent high pricing in July, the offer price limit in the market power mitigation bill was triggered on July 22. This meant that for the remainder of the month, our gas fleet as well as the gas fleets of the other market participants with more than 5% of generating capacity in the province were constrained to a maximum bid price of $125 per megawatt hour. We did not, however, see a significant change in bidding behaviors since July 22. There continues to be scarcity pricing with high temperature-led tightness in supply as well as more benign pricing when we experienced higher production from renewables. While there was a large block of bids at $125 per megawatt hour during certain hours, the spot price settled higher on a number of occasions as a result of the bidding behavior of unconstrained market participants during periods of tighter supply. We continue to believe, given current market conditions, that the interim regulations will have a limited impact on our portfolio. As a reminder, the interim regulations are set to expire on November 30, 2027, at which time the restructured energy market is expected to be fully implemented. We are increasingly excited about the opportunities to support the energy transition in our core markets from our legacy generating sites. Our legacy thermal sites in Alberta, Centralia, and Sarnia have great value and unique advantages through enhancement, redevelopment, and repurposing. We have the ability to extend their operating lives and potentially repower them with a combination of new and existing technologies and build out the infrastructure required to meet the growing needs of the future. They are well-suited to backstop the intermittency of renewables and serve the growing demand for electricity from data centers in a resource-constrained environment where permitting and interconnection can be challenging for new supply. Our legacy sites in Alberta have close to 1.3 gigawatts of operating capacity at Sundance Unit 6 and Keephills Units 2 and 3. And we have a further 2.1 gigawatts of vital infrastructure at Sundance and Keephills and over 40,000 acres of land available to meet customer needs. Similarly, in Washington State, our Centralia site has 1.3 gigawatts of generating facilities and over 12,000 acres of land that can be repurposed to meet customer needs. Both sites have highly skilled labor, existing transmission infrastructure, water rights, proximate access to fiber optics networks, cooling ponds, rail access, and connectivity to natural gas pipelines. We are currently in exploratory discussions with several potential counterparties to determine how to best meet their potential energy needs from both our Centralia and Alberta Energy campuses. The existing infrastructure at our brownfield sites can significantly reduce timelines for permitting and their access to transmission gives them a real advantage and speed to available power supply. We are uniquely positioned to respond to the growing need for timely, affordable, reliable, and clean power for both existing and new customers. Joel will now provide more details on the quarter.

Thank you, John, and good morning, everyone. Let me start my comments this morning with a discussion on our segmented results led by our Alberta portfolio. We are very pleased with our second quarter operational performance and financial results despite a challenging pricing environment. Strong performance from the Gas segment driven by high availability, strong production, and higher realized prices from hedging activities delivered adjusted EBITDA of $146 million during the quarter. The Hydro segment produced adjusted EBITDA up $83 million, broadly in line with our expectations due to lower Alberta spot prices, which were partially offset by the sale of environmental attributes in favorable hedges. The Wind and Solar segment delivered adjusted EBITDA of $88 million, a 76% increase compared to the same period last year due to the addition of the Northern Goldfields Solar, White Rock East and West, Horizon Hill, and the return to service of Kent Hills. The Energy Transition segment delivered $3 million of adjusted EBITDA, which decreased year-over-year due to an extended planned outage at Centralia and increased economic dispatch as a result of lower market prices at Mid-C. The Centralia facility returned to full operating capacity in the third quarter. And finally, our Energy Marketing segment delivered solid performance with adjusted EBITDA of $30 million due to hedging activities. Overall, the second quarter was strong, delivering free cash flow of $172 million or $0.57 per share. Year-to-date, we have achieved $381 million or $1.25 per share of free cash flow, approximately 73% at the midpoint of our annual guidance of $525 million. Turning to the Alberta segment. The second quarter spot price averaged $45 per megawatt hour, which was significantly lower than the average price of $160 per megawatt hour for the same period in 2023. The decline year-over-year was primarily due to incremental generation from the addition of new gas, wind, and solar supply and lower natural gas prices. Weather conditions for the second quarter were also milder compared to the second quarter of 2023, which had more periods of extremely hot weather and constrained supply. In response to these foreseen declines in power prices, we proactively deployed hedging strategies to enhance our portfolio margins and significantly mitigated the impact of these lower-margin power prices. In the second quarter, we maintained hedge volumes of approximately 2,100 gigawatt hours at an average price of $84 per megawatt hour. We also enhanced our margins through our optimization activities. We were able to capture higher margins by fulfilling many of our higher-priced hedges with purchase power during lower priced hours. This strategy led to a $97 per megawatt hour realized merchant power price for the Alberta electricity portfolio, which includes all of our hedging and optimization activities and merchant revenues from the operation of our facilities. By employing this strategy, we were able to effectively optimize cost for production capacity and deliver ancillary services across our Alberta fleet, which resulted in a realized merchant power price that was significantly above the hedged and spot power prices. Looking at the balance of the year, we have approximately 4,500 gigawatt hours of our Alberta portfolio generation hedged at an average price of $85 per megawatt hour, which is well above the current forward curve. For 2025 and 2026, our team has hedged production at an average price of approximately $80 per megawatt hour, also well above the current forward curve levels for both years. Going forward, we will continue to lock in opportunistic hedges to secure earnings and cash flows and limit the downside impact of lower spot prices and excess supply conditions anticipated over the next two years. Turning back to Hydro, the fleet continues to see strong realized pricing and production during peak hours, demonstrated by the continued outperformance of the average spot price quarter after quarter. The premium to spot electricity prices has averaged approximately 28% over the last three years, and ancillary services earn on average 51% of spot prices. Looking forward, we expect this segment will continue to receive a premium to spot pricing to perform within our 2024 guidance expectations. Energy production was lower in the second quarter, which was offset by higher ancillary services volumes. During lower demand in pricing periods in the solar season, we focused on refilling our reservoirs in order to be optimized for peak demand and when the market needs the water flow the most, which we have seen with extreme heat and numerous high-priced hours over the past month. Our hydro fleet has performed exceptionally well throughout July and continues to demonstrate its value during peak demand periods. I'll now pass it back to John to discuss the 2024 guidance and balance of year priorities.

Thanks, Joel. As Joel highlighted in his remarks, we are confident in our ability to meet our 2024 guidance as we're tracking to the upper end of our adjusted EBITDA and free cash flow ranges. Our results in the first half of the year show the value of our diversified fleet and our optimization and hedging strategies. We continue to have relatively high hedge positions, which are reflected in our strong results year-to-date. Hedges have been executed both financially and through our commercial and industrial business to mitigate the impact of new renewable and gas-fired supply additions in Alberta. We have hedged positions that are significantly above current forward prices in 2024 and have secured attractive hedge positions for 2025 and 2026. Second, we do not expect to experience adverse impacts from the regulatory evolution of the electricity market in Alberta, given the positioning of our merchant portfolio. In fact, we see numerous opportunities to meet the essential needs of the market and new and existing customers from our legacy fleet. And third, we're confident in the ability of our fleet to deliver strong operational results, as has been the case so far this year. We remain committed to returning value to our shareholders. We were very active in the market through the first six months of the year, and as of June 30, have returned $89 million to our shareholders through share repurchases, which is approximately 59% of our 2024 target, resulting in a reduction of almost 9.5 million common shares. And since the end of the quarter, we have purchased approximately 2 million additional common shares for a total of $21 million at an average cost of $9.82 per common share. We will continue to repurchase shares given our current share price, which we believe to be undervalued. We believe our $150 million share repurchase plan is an appropriate and balanced use of our capital as our liquidity and financial performance permits us to pursue opportunistic growth with returns that meet our strict thresholds while maintaining our balance sheet strength and resilience. As I look at our strategic priorities for 2024, we're focused on the following key goals: first, improving our leading and lagging safety performance indicators while achieving strong fleet availability of 93.1%, achieving EBITDA and free cash flow within our 2024 guidance ranges, executing our enhanced common share repurchase program for 2024 and advancing our ESG program. We also look forward to closing and integrating the Heartland generation transaction, provided we are able to satisfactorily complete the current review of the transaction by the Competition Bureau. We remind everyone that our growth targets are aspirational, as we continue to be prudent and disciplined in our growth plan. Our growth team is focused on our development pipeline and advancing high-quality and attractive return projects. As I mentioned earlier, we're seeing considerable opportunities to support the energy transition in our core jurisdictions, in particular, at our legacy thermal sites, where we are actively pursuing redevelopment or re-contracting opportunities to serve a growing customer base. We will be patient in deploying capital and will balance what is best for our shareholders in both the near and long term. 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 strong and underpinned by a growing high-quality, increasingly contracted, and diversified portfolio. Our business is driven by our unique, reliable, and perpetual hydro portfolio, our contracted wind and solar 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. We remain on track to achieve our ambitious CO2 emissions reduction targets and remain committed to net zero by 2045. Third, we have a tremendous resource in our legacy thermal sites, which we are now actively looking to enhance, redevelop and repurpose to meet the evolving needs of our customers. Fourth, we have a diversified development pipeline and a talented development team focused on securing appropriate returns as it works to advance our clean electricity growth plan ambitions. And fifth, our company has a sound financial foundation. Our balance sheet is strong, and we have ample liquidity to return cash flow to our shareholders through share repurchases and pursue and deliver growth when returns meet our thresholds. Finally, we have our people. Our people are our greatest asset, and I want to thank all our employees and contractors for the outstanding work they have done to deliver strong results during the quarter and set the company up for success for the balance of the year. Thank you. I'll turn the call back over to Chiara.

Thank you, John. Amy, would you please open the call for questions?

And our first question comes from Patrick Kenny with National Bank Financial.

Maybe just starting with the Heartland transaction. Obviously, a lot of moving parts here, John, as you mentioned, related to the Alberta market reforms and of course, now new load growth emerging in the U.S. So just wondering how you see the merits of the deal stack up to some of these other new opportunities that might be now available for that $600 plus million of capital and what assets you might look at from a strategic standpoint should the competition approval fall through?

Yes, Patrick. We are continuing our efforts to finalize the Heartland transaction and are actively engaging with the regulators to achieve this. We are committed to maintaining a disciplined approach as a company. Our investment strategy connected to this transaction is based on the appealing mix of assets they possess and the price we agreed upon. We believe that leveraging our organization's skills will provide advantages for these assets. We still see potential benefits from this transaction; however, we are currently addressing the Competition Bureau's views on it along with the broader Alberta energy market. We recognize numerous opportunities on both sides of the border, which I categorize into two main areas. Firstly, regarding our legacy assets, we are enthusiastic about the discussions at Alberta Thermal regarding data centers and the value these assets bring in ensuring reliability in Alberta. Similarly, similar conversations are taking place at our Centralia facility. As you may know from our growth pipeline, we focused heavily on Alberta in the near term, but we have paused those plans amid the current uncertainty in the REM. Nonetheless, we are advancing other projects across the three regions where we operate and remain actively engaged in the M&A market. When assessing M&A opportunities, we are identifying potential in the renewable sector as well as the gas sector, particularly in U.S. regions we find appealing, such as the Pacific Northwest and the Desert Southwest.

Got it. And then maybe drilling down a little bit more into the Alberta REM design now that you have a bit more clarity on how your assets might line up from a competitive standpoint. Can you maybe expand on your comments around pursuing repowering and re-contracting opportunities? Are we talking about potential tolling agreements with the ASO or more so trying to secure longer-term contracts with co-location customers?

I would say that, look, it's early days in terms of the kinds of discussions that we're having. But maybe I'll answer the question this way. We are actively engaged in discussions with respect to the potential of citing where the migration of data centers up into Alberta and Antrim facility specifically. So that would be number one. And kind of the form that those kind of arrangements would take place would vary depending on the customer that we would have, but they would be longer-term in nature. And look, they're super focused on reliability and access to power, and there's a lot of advantages that Alberta provides, including a relatively welcoming, I would say, political environment in terms of the support that we've gotten from the leadership in the province to have these kinds of facilities come into the jurisdiction. And then secondly, our analysis would show that as the market evolves in the province of Alberta, the need for the coal to gas converted units and not just one or two of them, but like a significant number, like four or five, six units, if you want any redundancy, is going to be critically important to slow growth in the province going forward.

Appreciate that, John. And then Joel, I know it's only been a month, but as you get a closer look at the portfolio of assets, and I know this is very much a conversation with John and the Board, but curious to get your initial thoughts around potential capital recycling opportunities or other initiatives to maximize the value of certain assets?

Yes, Pat, it's my first month here. And first of all, I'm very pleased with the results that we saw during the quarter here and what we're seeing through the month of July just given where power prices have been. I'd say to you, when we look at the portfolio, yes, capital recycling will become an important part of our strategy going forward, where we can add value to the shareholder. And what I mean by that if we see an opportunity where we can sell an asset that's at say a 10x multiple and redeploy that cash in something that's at a 6x multiple. For example, that's going to add value to the shareholder at the end of the day. So again, we're, again, very opportunistic here with respect to our portfolio management going forward and how we redeploy that capital.

And our next question comes from the line of Mark Jarvi with CIBC Capital Markets.

Maybe just starting on the buyback. Maybe picking up on the last comments, Joel's made about capital recycling ability to take profits from an attractive sale and put them into undervalued assets. Is that something you consider capital recycling around supporting the buyback? And just given the activity you've seen today, is there a likelihood that the $150 million sort of target gets increased, given the fact you've got strong free cash flow, maybe not a lot of near-term equity investments on your growth platform right now?

Yes, Mark. Why don't I start and then maybe Joel can supplement it. Look, when we think about the recycling, and it's interesting, we've just wrapped up a series of Board meetings and it was a topic that we had chatted with our Board about. I mean I think we would tend to think of it in the context of if there was something that we were looking to do to either shore up our balance sheet or I would say, more to the point, an acquisition that made sense for us or something that we were trying to pursue that would have a significant impact on the cash flows of the company going forward. Those are the kinds of opportunities that we would be primarily looking to recycle our capital for. With respect to the share buybacks, we're very comfortable with that $150 million target that we have, and we're well over 60% of the way there to meeting that this year. It's something that we evaluate all of the time. And Joel can speak to this in a second. But we continue to look at what the value is to our shareholders of doing that versus some of the other opportunities that we have, and it's an ongoing discussion that we have. Joel, I don't know if you have anything to add?

I would like to add that at the beginning of the year, we stated our goal of up to $150 million in share buybacks year-to-date. As of July, we are approximately 74% of the way there. The average price per share this year is about $9.44. Moving forward, we will continue to repurchase our shares. If we reach the $150 million limit, we will reevaluate and consider whether to extend that, particularly since we believe our shares are currently undervalued. This is an effective way to return capital to our shareholders, and we will keep reassessing this matter as we move ahead.

Understood. And then, John, your comments about the Heartland deal and remaining disciplined, depending on what the Competition Bureau says, if they felt it made sense for you to buy on select assets or shed some of those assets. Are you open to some concessions? Is it sort of an all or nothing for you or maybe you're not even in a position to comment on that right now?

Yes. No, Mark. It's a great question. So look, the conversations we've had with the Bureau continue to be dynamic, I would say. And with respect to concessions, it is something that we would consider in the event of the overall thesis that we have for the transaction. But as I mentioned before, we have internal return expectations and a thesis around the transaction that we're going to stick to from a very disciplined sort of perspective. And it needs to fall within, I would say, the parameters of what the original sort of investment thesis were. And if that becomes challenged, then we're going to clearly have to be in a position where we would reevaluate it.

Okay. And then John, you made a comment about the value of the coal to gas converted assets and the need there for reliability during tight periods in the market. If you look at where the forward curve is, obviously, it's at a level where they're not that profitable. I guess average price is not always the same as realized prices of those units. But is there still a potential where you think out of the market capacity or payment makes sense? And if not, then is there a rationalization not to happen here? Or do you solve it more on the demand side, trying to bring in load to the market? Just wondering how you see those assets staying relevant and profitable in the years ahead?

Yes. You were a little bit muffled and maybe it's just my age Mark, but I think I got the gist of what you were saying. So look, we continually assess the fleet and the viability of the coal to gas assets in the market. I think the role in the market is going to change. So I would say when you look at the hedging program that we have for the balance of this year, going into 2025 and also into 2026, that is all oriented towards and orchestrated towards kind of providing a base level of an envelope of operability effectively of those particular units. So we do have confidence in the ability of the units that provide value for us in the energy market. But more importantly, I think we're looking at the units from an optionality perspective. So when we look at them in the context of the energy market, that's one thing we can do, but we also look at them in terms of what role can they provide from a reliability perspective. What role can they provide from a data center perspective? It's all of those kinds of things. And it wouldn't surprise me that as time goes by, we will assess those units. Does it make sense to keep them in the market? Does it make sense to mothball them, for example, or get to a place where we hold them in reserve? And I think my view would be that, over time, you'd likely see them become more contracted than kind of the way they are today. I think the role will evolve over time.

That's right, John. I think you highlighted two important points. First, we definitely see a need for reliability, which we've discussed before. Second, with the potential data center load that has come into the province, there is an opportunity to secure some long-term contracts.

If you had to choose at this moment, Blain, would you say it's more about a bilateral contract with data centers and new load, or is it more likely that there will be some government support for liability and a contract capacity payment to maintain the relevance of those assets in the market?

Yes, Mark, I would say that it's early days with the discussions we're having. However, I believe we are broadly pursuing both options.

Maybe just keeping with the capital recycling theme here. Obviously, having an active program is something quite new for the company and really quite rare across all sector as well. Can you just elaborate on what caused the management and the Board to think about this program? Is it an environment thing? Is it just a different approach in management? Is this something you're seeing just helping me understand what's changed?

Yes. Maurice, we have always taken a continuous approach to evaluating our broad portfolio of assets. We assess their value within TransAlta and how they might be valued by others outside the company. This is an ongoing process that we carry out annually with Joel's team. Looking ahead, I feel optimistic about the opportunities available to us, both in terms of new initiatives and the value of our legacy assets. It has become increasingly important for us to adopt an asset management perspective to maximize value for shareholders. We currently operate 79 facilities across three countries, with most of our cash flows stemming from a subset of these facilities. Some of our facilities are considered core, while others might be viewed as less central. This understanding shapes our mix of assets and our perspective on creating value, which I believe has gained greater prominence recently.

I guess a quick follow-up to that is obviously, I'm not going to ask you what's non-core, but I guess what is core rather than obviously your legacy sites?

Yes. I mean when I think of our core assets right now just in terms of the opportunity set, our legacy coal to gas assets in Alberta, our facility down in Centralia, just given the opportunity set that we're seeing right now. Certainly, our hydro fleet is a core asset. We think Sarnia is important. And right now, for us, Australia is a very important business. We have a mixture of everything from small hydro to individual wind farms, which are at different stages of their contractiveness and life cycles that may or may not, depending on the circumstances, makes sense for us to consider recycling. But hopefully, that gives you a little bit of a flavor. Joel, I don't know if you want to add anything here?

I'd just say one thing, too, here is that there has to be a good use of proceeds. We're going to be opportunistic here going forward to John's point, that if we see a real opportunity here where we can really add value longer term, then we'll look to recycle capital. So again, it's always been part of our DNA here. But as John mentioned, as we see opportunities here going forward with our legacy assets and just new opportunities within our existing markets that we just have to consider capital recycling as part of the financing going forward.

Let's wrap up the discussion on capital allocation. How do you assess the overall performance of the program? Is it focused on per share growth? Is it funded through equity sales? What other financial strategies are you employing?

When we consider how to allocate our capital, there are several factors we need to evaluate. We focus on achieving appropriate risk-adjusted returns, ensuring that our decisions positively impact our EBITDA, earnings per share, and free cash flow, while also aligning with our credit metrics. This is one of the key criteria we assess. Additionally, when redeploying capital, we prefer to extend the duration of our portfolio, which may be supported by long-term contracts. Overall, we have multiple criteria to look at to ensure we are delivering suitable risk-adjusted returns for our shareholders.

If I could just finish up with one question from, I guess, the Q1 call. I think you mentioned in the past that you expect 2025 to be in line between 24%. And I think that's from an EBITDA and free cash flow perspective in dollars in per share. Is that still a view that you hold?

Yes, Maurice, when we consider 2025 and examine our hedge position along with the opportunities related to the fleet, we remain quite confident about how 2025 is shaping up. I believe we're in a solid position.

Maybe just going back to redevelopment and re-contracting and looking at your Alberta fleet. How does the age and emissions level of your subcritical coal to gas units figure into the discussions you're having? And when you think about re-contracting those units, like what is the maximum capacity factor that you think those older units, I'm basically excluding Keephills 3 here, could reasonably support on an annual basis, just given their age?

Look, let me give you a sense of sort of a flavor of some of at least preliminary sort of thoughts that we have around that and maybe some of the early perspectives that we're getting from the market. I think the units can run fairly reliably. I think now that they've switched over to gas from coal, having high 80s and into even low 90% kind of availability, I would say, Blain and Joel, would be something that we would expect to see. I think they're relatively good from an emissions output perspective. I mean we've passed basically the CO2 emissions that come out of those units compared to what they were like from a coal perspective. They are very, very cost-effective. I think at least some of the discussions we've had, don't require a fully behind the fend solution. So the ability to actually be linked to the grid to be able to provide some of that backstop is something that's helpful. And then we do have a reasonably sized renewable fleet in the province of Alberta. So when we think of our hydro and we think of the wind, the hydro from a rec perspective to be able to sort of shelter some of that. Carbon emissions has come from the units and then from the wind perspective, not just REX, but actually generation from a merchant perspective, to the extent it doesn't need to be perfectly shaped. I think there's a mix of levers that we have that we can pull to create a pretty attractive offering, I think, to people that would be interested in it. And I think the units overall, when I think of Sundance 6 and I think of K2 and K3, I mean, they're well-maintained units. We've been very, very rigorous in terms of our asset management programs. We spend the appropriate amount of sustaining capital. We have a really talented operating and maintenance team to oversee those units. So overall, I'd say we feel pretty good about the offering.

On the redevelopment side, could you share your perspective on the technology discussions? Are these discussions leaning more towards gas, or are they a mix of gas storage and solar? Specifically in Canada, does the clean electricity regulation impact this process at all? Is it a constraint in moving forward, or do you see it evolving over time?

I would say it depends on the jurisdiction. For example, in the U.S., the discussions are certainly around gas, but also involve what I would call clean electricity at the facility, especially given our land holdings to help with decarbonization. We're envisioning these as campuses. This could include some gas-fired generation and storage. From a transmission perspective in that area, there's Centralia right now. You might see some solar, some wind, and some storage connected to repurposed facilities toward gas. In Australia, there’s also a mix. We have implemented hybrid solutions for customers, combining gas and solar, along with storage and potentially some wind. In Alberta, the discussions have primarily focused on gas rather than adding other technologies to the mix. We believe that as the need for reliability grows to address intermittency in the province, storage will be increasingly significant, at least from our perspective as we move forward. So, it really varies by jurisdiction and encompasses a bit of everything. We have a long history of working with various technologies from wind to solar, hydro, and gas, including storage, which we have both here and in Australia. We're very comfortable with all of these technology options.

Maybe one last one. I realize you're not going to want to put timelines on all this, but I guess, aspirationally, when you think about the demand for firm supply and what the opportunities you've got in your legacy sites. What are you kind of hopeful that you could have a little more clarity on what your opportunity set is going to look like here?

Look, we're actively working in each of the three jurisdictions here. I feel like I can't give you a specific date in order to say that my team sometimes gets frustrated with me when I give them sort of my impatience on it. But look, we need to take the time that we need to do things in an appropriate way. And some of the things that we're looking to do are going to require a bit of regulatory input, some of it's going to require a little bit of creativity on our part to make sure that we meet the needs in an appropriate way with our customers. But certainly, Joel or Blain, what I think of the next year, I suspect we'll be able to do some really interesting things, I think, in some of these facilities.

I wanted to follow up on your comments regarding what is fundamental to your portfolio. You covered a lot, but I noticed your non-hydro renewables were not included in your answer. I find it surprising because I know you aspire to reach 70% renewables. Can you clarify that for us? Also, has there been any change in your 2020 target?

We continue to see a consistent path towards decarbonization for the company, even as the types of assets we discuss evolve. In the last quarter, approximately 55% of our EBITDA came from renewables in Q2 this year, and we anticipate that this trend will persist. We have a significant number of wind farms and a gas facility in Michigan, among various other assets in our fleet. Our development pipeline is primarily focused on wind, solar, and storage projects, and we also engage in pump storage initiatives. We are committed to making our operations cleaner over time and take our decarbonization goals very seriously. These goals are integral to our company's performance evaluations. While we view our legacy facilities as having an extended lifespan, they now have emissions profiles that are likely lower than their previous levels. Overall, we are maintaining our course towards cleaner operations.

Could you clarify whether the comment about repowering the Alberta coal and gas facilities relates to a potential AI load contract? That would be necessary for repowering a site and for spending money that was previously allocated for Sundance's capabilities.

Yes. Currently, we have sufficient capacity to meet existing needs. However, during our discussions with potential clients, their load requirements are significantly high, around 500 to 1,000 megawatts, rather than just 100 megawatts. Given our established presence, we don’t foresee immediate enhancements, but in the longer term, there may be opportunities to upgrade the site. We have the necessary infrastructure in place, including cooling ponds, transmission systems, and a capable labor force, along with ample gas supply. Therefore, we can consider optimizing our existing assets to meet demand as it evolves over time.

Can you elaborate on my question? For instance, if you have a converted coal and gas plant, its lifespan might not exceed ten years depending on future regulations. Is it sufficient or acceptable for an AI load, or would they prefer something that is more efficient with lower emissions and a longer operational life?

We're not seeing any significant concerns in our discussions right now. The focus is primarily on reliability and speed to market. Gas prices are currently at $0.80, and whether the heat rate is 7x or 10x won't greatly affect decision-making from a fuel cost perspective. Over time, there will be a push for cleaner options. We're aware of the regulatory environment, and I believe it will evolve based on the needs for reliability and affordability in the markets we operate in. We're actively engaged in these discussions and haven't encountered any barriers in our conversations so far.

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

And this concludes today's conference call. You may now disconnect.