Good morning. My name is Sherry, and I will be your conference operator today. I would like to welcome everyone to TransAlta Corporation’s Third Quarter 2024 Results Conference Call. Ms. Valentini, you may begin your conference.

Thank you, Sherry. Good morning, everyone and welcome to our third quarter 2024 conference call. With me today are John Kousinioris, President and Chief Executive Officer; Joel Hunter, 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 also 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 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 our call today are in Canadian dollars, unless otherwise noted. The non-IFRS terminology 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. 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 third 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. TransAlta delivered another quarter of excellent financial and operating results. We had strong performance across our generating fleet as well as from our Energy Marketing segment. Our third quarter results illustrate the value of our proactive hedging strategy and the active management of our Alberta merchant portfolio. During the quarter, we delivered adjusted EBITDA of CAD325 million, free cash flow of CAD140 million or CAD0.47 per share and average fleet availability of 94.5%, demonstrating our strong operational capabilities. Our strong balance sheet continues to provide us with flexibility with over CAD1.8 billion in available liquidity, including approximately CAD400 million in cash. We are well positioned to execute on our capital allocation priorities, which include completing our enhanced share repurchase program for 2024 and funding the closing of the Heartland Generation acquisition. I would now like to update you on a number of our strategic initiatives this quarter. First, with respect to the Heartland Generation acquisition, we remain actively and constructively engaged with the Competition Bureau in our effort to obtain Competition Act approval. We have made good progress on this front and now have greater optimism regarding a pathway to completing the transaction. We have also constructively engaged with the seller to ensure that the transaction continues to meet our value expectations. I'm hopeful that we will be able to update everyone on the status of the transaction shortly. Next, we continue to advance the significant contracting and development opportunities we see at our legacy thermal sites in both Washington State and Alberta. Finally, given the weakness in expected market conditions we see for the next year or so, we've decided to temporarily mothball Sundance Unit 6 effective April 1, 2025, which enables us to preserve the unit and site for future opportunities. Moving to our legacy energy campuses. As we noted during our last call, the Centralia site has multiple opportunities that we're currently assessing, and we are in active discussions with several potential counterparties to determine how to best meet their energy needs from the site. This could include both the repurposing of existing assets and the potential for new facilities, which would serve to enhance the reliability of the grid in Washington State and support the energy transition in meaningful ways. If successful, we will have the ability to extend the operating life of the Centralia site as well as build out other opportunities, including potentially wind, solar, batteries, pump storage and next-generation technologies. Critically important infrastructure, including transmission is available at the site with significantly reduced redevelopment costs and timelines for permitting and would provide us with an advantage in speed for delivering power supply. We expect to be able to share our more detailed development plans for Centralia during the first half of 2025. We're also progressing multiple opportunities at our legacy thermal sites in Alberta. We're actively marketing these sites and believe that they hold significant value and provide unique advantages to customers. Our legacy sites around Wabamun Lake in Alberta have close to 1.3 gigawatts of operating capacity at Sundance Unit 6 and Keephills Units 2 and 3. The Sundance and Keephills sites are within 20 kilometers of each other and only 80 kilometers from Edmonton. We have a further 1.6 gigawatts of vital infrastructure at Sundance and Keephills, and over 40,000 acres of land available to meet customer needs. The sites have water rights, fiber optic cable access close by and grid interconnection on locations. Retired units and spare site capacity at both sites provide us with the potential for significant expansion, including repowering in the future. Our merchant renewables portfolio in the province also enables us to bundle renewable energy credits to lower customer carbon intensity, and our marketing optimization and regulatory experience differentiate us from other options. We often hear that Alberta's geographic location makes it less desirable for data centers from a latency perspective. We don't believe this to be the case. Our analysis shows that Alberta is well located for both AI trading and AI inferencing applications when you consider that most would require latency of 75 milliseconds or better. Latency would not, therefore, be an issue for many customers if they were to be located on one of our sites, and we're in discussions with multiple hyperscalers who are potentially interested in our Alberta energy campuses. We're also progressing several initiatives to ensure our sites are turnkey ready for data centers. We believe we're uniquely positioned to respond to the growing need of data center customers for timely, affordable, reliable, and clean power. However, while we see great potential in our Alberta thermal sites, given the more immediate fundamentals of the market in 2025, we've taken the prudent financial decision to temporarily mothball Sundance 6, while reserving it for future economic opportunities. With current oversupply conditions, the decision defers significant sustaining capital expenditures and enables us to consolidate our cost structure and operations. We will maintain the flexibility to return Sundance to service when market fundamentals improve and support the addition of the unit's generation. We will continue to operate the unit through to the end of the first quarter of 2025, and the mothball period will commence April 1, 2025. Our Alberta portfolio is fully capable of managing our hedging strategy, while Sundance 6 is mothballed and in the meantime, we'll continue to evaluate the Sundance site for data centers and reliability contracts, actively assessing opportunities while the site is not in operation. Switching to our 2024 outlook, our financial performance year-to-date makes us confident that we will deliver the year towards the upper end of our adjusted EBITDA and free cash flow ranges notwithstanding the larger planned outages that we have in the fourth quarter that will impact our free cash flow.

Thank you, John, and good morning, everyone. We are very pleased with our third quarter operational performance and financial results, which are led by our Alberta portfolio in the Energy Marketing segment. The Alberta portfolio was able to outperform expectations, while we continue to face a challenging merchant pricing environment. The Hydro segment produced adjusted EBITDA of CAD89 million, broadly in line with our expectations given the lower realized and ancillary spot prices. The decline quarter-over-quarter was partially mitigated from a greater volume of ancillary services due to increased demand by the ISO as well as the ability to capture better than average premiums that were in line with average spot energy prices. We are also able to sell additional environmental attributes to offset the power price declines at the merchant fleet. The wind and solar segment delivered adjusted EBITDA of CAD44 million, a 19% increase compared to the same period last year, primarily due to the addition of the Oklahoma wind assets, together with the new PTC transfer deals in return to the service of Keephills. The Gas segment, which had improved availability of 96.3% delivered adjusted EBITDA of CAD139 million during the quarter. The reduced contribution year-over-year was driven by overall lower production resulting from higher economic dispatch and excess supply conditions in Alberta, while the decline in realized prices in the Alberta portfolio was partly mitigated from our favorable hedge premiums and position. The Energy Transition segment delivered CAD34 million of adjusted EBITDA, which increased year-over-year due to lower purchase power costs driven by lower mid-sea pricing on repurchases of power and lower production from higher economic dispatch. Our Energy Marketing segment delivered exceptional performance with adjusted EBITDA of CAD54 million, an increase of CAD41 million year-over-year due to the positive market volatility across North American power and natural gas markets and higher realized settled trades in the third quarter. Corporate costs have increased year-over-year, primarily due to increased spending for planning and designing of our ERP upgrade program and initiatives to support our strategic growth. Overall, the third quarter was excellent, delivering free cash flow of CAD140 million or CAD0.47 per share. Year-to-date, we've achieved CAD521 million or CAD1.72 per share of free cash flow, setting up the company well to reach the top end of our guidance, as John noted earlier. Turning to the Alberta portfolio, the third quarter spot price averaged CAD55 per megawatt hour, which was significantly lower than the average price of CAD152 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 source supply as well as lower natural gas prices. Weather conditions for the third quarter were also milder compared to the third quarter of 2023, which had more periods of extremely hot weather and constrained supply. We continue to proactively deploy hedging strategies to enhance our portfolio margins and mitigate the impact of lower merchant power prices. In the third quarter, we had hedge volumes of 2,365 gigawatt hours at an average price of CAD85 per megawatt hour, which compared favorably to an average spot power price of CAD55 per megawatt hour. We also continue to enhance our margins through our optimization activities as we captured further margins by fulfilling many of our higher-priced hedges with purchase power during lower-priced hours when power prices were below our variable cost of production. This strategy led to an overall CAD90 per megawatt hour realized merchant power price for the Alberta portfolio. By continuing to employ this strategy, we were able to effectively optimize variable cost of our production capacity. By optimizing our fleet and fulfilling our hedges with purchase power, we were able to respond to higher demand from the ISO and deliver additional ancillary service volumes across the Alberta fleet. This quarter, our realized price for our ancillary services settled at prices equal to the average quarterly spot energy price of CAD55 per megawatt hour. Historically, this has averaged around 50% of the average spot power price. The Alberta grid continues to need additional ancillary services for reliability, and our Hydro fleet is optimized to support this market. During lower demand and pricing periods, we focused on maximizing our reservoirs to be optimized for peak demand for the winter season. Our Hydro fleet has performed exceptionally well through the first nine months of the year and continues to demonstrate its value in different market environments. Looking at the fourth quarter, we have approximately 2,400 gigawatt hours of our Alberta portfolio generation hedged at an average price of CAD82 per megawatt hour, which continues to be above the current forward curve. For 2025 and 2026, our team has hedged production at an average price of approximately CAD76 per megawatt hour, also above current forward pricing levels for both years. I'll now pass it back to John to discuss the balance of our year priorities.

Thanks, Joel. We remain committed to returning value to our shareholders and have been active in advancing our share buyback program through the first three quarters of the year. As of September 30, we have returned CAD114 million to our shareholders through share repurchases or approximately 75% of our 2024 target, resulting in a reduction of almost 12 million in common shares, and we remain committed to completing the CAD150 million share repurchase program by year-end. As I look at our strategic priorities for 2024, we are focused on the following key goals: first, improving our leading and lagging safety performance indicators while achieving strong fleet availability; second, achieving EBITDA and free cash flow consistent with the top end of our 2024 guidance ranges; third, executing our enhanced common share purchase program for 2024; fourth, closing the Heartland Generation transaction and integrating the assets into our fleet; and finally, advancing our ESG program. We continue to be prudent and disciplined in our growth plan, and our team will be focused on meeting the needs and expectations of both our customers and our shareholders. We're seeing considerable opportunities to support the energy transition in our core jurisdictions, particularly at our legacy thermal sites, where we are actively pursuing redevelopment and recontracting opportunities to serve a growing customer base. I'd like to close by highlighting what I think makes TransAlta highly attractive for investment and a great value opportunity. First, our cash flows are strong and resilient and underpinned by a growing high-quality and 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 a world-class asset optimization and energy marketing capabilities. Second, we're a clean electricity leader with a focus on tangible greenhouse gas emissions reductions and we remain on track to achieve our ambitious CO2 emissions reduction targets. Third, we have a tremendous resource in our legacy thermal sites, which our teams are actively working to redevelop and repurpose to meet the evolving needs of our customers and markets. 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. Finally, 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, close the Heartland acquisition, and pursue and deliver growth when returns meet our thresholds. Lastly, I want to thank all of our employees and contractors for the outstanding work they have done to deliver our excellent results during the quarter and set the company up for a strong finish to 2024. Thank you. I'll turn the call back over to Chiara.

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

And our first question will come from the line of Mark Jarvi with CIBC. Your line is open.

Good morning, everyone. Maybe John, talking about repurposing our thermal site. Is your view that you'd be able to host data centers on your site or mostly be serving data centers at a different location? So just through the grid or behind meter colocation is the perspective you're looking at right now?

Yes. Good morning, Mark. Our primary focus right now is actually more oriented, I would say, towards colocation. The kind of discussions that we've been having would be given the facilities we have, given the location that we're in, and given the land that we have, the ability to provide water at site. Everything from temperature to the availability of workforce has us thinking about the ability of kind of building out a campus that is proximate there. And as we look at developing the work around that, one of the things that our team is doing, and Blain is actually on the call here and could add some color, is to think of it sort of in a phased approach where we could deal with customers with sort of what we currently have and work to the interim to derisk what we're thinking of permitting. We're thinking about the physical facilities and the way that we could develop the immediate area to make it an even more attractive site for people and then more on a longer-term basis, think about how we would potentially add or create even more efficient generation at site to be able to meet their needs from a longer-term perspective. Blain, any color on that?

I think that's correct, John.

And maybe just a follow up on that. We've seen other firms file with the ASO for interconnection of data centers. We haven't seen that on any of your sites. Is that just given the size of the potential load is more manageable when you back up power you guys can serve with your existing sites or units? And then, I guess, additionally, what's the sort of conversation around emissions profile, given where your coal to gas conversion units are today on emissions profile? And is solving for that, if there is a requirement for an emissions profile, just an option with some of your renewables that you own?

Yes. Let me see if I can answer all of the questions. Filing to kind of get an interconnection setup is not a difficult thing to do. We see what's been set up to sort of prospectively serve data centers in the province, and it's fine that folks have done that. Frankly, that's not a critical path item from our own perspective. What we are really focused on is advancing the conversations and making sure that we're developing the site, so it was just easier for people to make that decision. So are the utilities there? How are we doing from a fiber optic perspective? Can we get the building set up? What are the development permits that we need to be able to move things forward? So it's more about that than kind of putting in an interconnection request. We've got a lot, as you know, from given the legacy sites that we have there, transmission access, so that's not really, I would say, a gating item, I would say, Blain, in terms of the way that we're looking at it. In terms of emissions profile, I would say right now, it's a very interesting topic. I would say the number one priority is probably speed to access to power. Costs are important and then latency is obviously important. Emissions profiles would be a medium to lower order of priority, at least at present. I think over time, you'll see that become a priority once I think access and supply ends up being built out. But right now, number one is sort of how quickly can we get something done, can you get us the reliability that we need? And is latency setup well? So that's pretty much a reflection of where I think John mentioned in your remarks that our portfolio and bundled with renewable energy credits offers an attractive alternative to solving that emission profile challenge for certain customer classes. And then just a follow-up on what Blain just said, that's kind of unique for us, given our wind fleet in Alberta, a chunk of which is merchant and also our hydro fleet. So we do have the ability to provide.

Maybe last question for me. What do you think will come first clarity on what happens at Centralia or what happens on one of your sites in Alberta?

Mark, I’m smiling because it feels like we have a bit of an internal competition going on, similar to what we sometimes see in the office. Both projects are progressing well. I would say our discussions regarding Centralia are probably slightly more advanced than those related to Alberta Thermal when it comes to timing. The demand is more urgent for what we can offer in terms of reliability in the Pacific Northwest, so I would give that a slight advantage in terms of timing. However, we are actively working on both projects simultaneously.

Thank you. One moment for our next question. And that will come from the line of Benjamin Pham with BMO. Your line is open. Mr. Pham, are you on mute? Your line is open.

Hi. Good morning. Maybe on Sundance 6, can you walk through the various puts and takes of the mothball? And I know you mentioned some consolidation of costs, and maybe that power prices will respond directionally positively relative to a mothballed unit, but you are losing the EBITDA contribution from it. So I'm just wondering if you're up ahead on that? Are you neutral or a different scenario?

Yes. Good morning, Ben. Regarding Sundance 6, we continuously assess our fleet and its optimization, especially in light of our confidence in the Heartland transaction and its potential impact on our portfolio. Specifically, as we anticipate power prices for 2025 and 2026, we expect a decline. We've analyzed the capacity factors we expect from our generation sources, including K2, K3, and Sun 6, and determined that mothballing Sun 6 is the best decision. This allows both K3 and K2 to operate at higher capacity factors than if all three units were running. We're also confident in our hedge position for 2025 and 2026, which consists of about 5,500 gigawatt hours of hedges, roughly equivalent to 800 megawatts per hour at mid-$70 levels. We believe that our strategy for 2025 and 2026 will reflect the tactical approach we took in 2024, supplemented by our Hydro fleet and the potential from Heartland to manage effectively through this transition. Additionally, Sundance 6 is approaching a significant turnaround, requiring substantial capital expenditures to extend its operation for the next two years. From our perspective, it didn't make economic sense to maintain all three units at this time. Thus, we decided to defer that investment. Much of the preparatory work is already complete, and while we've placed the unit in mothball mode, we plan to retain a significant portion of the workforce on payroll to maintain key operational capabilities. While there will be some redundancies, we want to ensure we can bring the unit back when the time is right. I hope this provides some clarity.

No, that's great. And maybe just my other one, I'm just thinking about some of your comments on the 2025 guidance early this year. Maybe I think the reference was flat versus 2024, but just given the good results in 2024 now and maybe some updated assumptions internally. Just a ratio, where are you thinking about with respect to 2025?

Yes, I can start, and then Joel can add his thoughts. Our perspective on 2025 remains unchanged. With our growing confidence in Heartland and our hedge levels, our hedge volumes for 2025 in the $75 range are similar to what the gas fleet secured last quarter. We are well hedged and will see a full year of production from our new wind generation. Overall, we feel optimistic about 2025. We are finalizing our budgeting process, which will be presented to the Board, and we will provide market guidance at that time. We've performed well towards the upper end of our guidance in 2024, which is encouraging, and we remain confident about 2025.

The only thing I would add there, John, is to comment earlier that we don't have an Investor Day this year. So we would look to provide guidance here in connection with our Q4 results in mid-February. But to John's point, we're in the middle of our budgeting process right now, but the guidance that we provided earlier in the year remains intact.

Okay. Great. Can you clarify what was driving the cash taxes? I might have missed it in your initial remarks, but is there an explanation for the cash taxes?

Yes, Ben. In Canada, until this year, we were able to utilize loss carryforwards. Over the past few years, even with higher net income, this allowed us to keep our tax bill relatively low. However, those carryforwards have now been exhausted. As we look to 2024 and beyond, we anticipate a higher effective tax rate, likely closer to our statutory tax rate for your modeling purposes. In our disclosures regarding assumptions, we are guiding cash taxes from CAD140 million to CAD160 million, which is now CAD30 million higher, setting the estimate at CAD160 million for the year. This change is simply due to the exhaustion of our large carryforwards last year.

Thank you. One moment for our next question. And that will come from the line of Maurice Choy with RBC Capital Markets. Your line is open.

Thank you and good morning, everyone. I just want to stick with Sundance 6 for a moment. If there was no data center opportunity, would your decision today have been different, maybe involving a parent shutdown? And maybe separately, what does this mean in terms of potential for capacity payments? And if you could just elaborate on an earlier comment about what this may mean for getting approval on the Heartland Generation deal? I appreciate that.

Yes, I'll begin with the last point. There have been no discussions with the Competition Bureau regarding TransAlta's existing fleet. It's important for everyone to understand that the Sundance 6 decision is unrelated to any future Competition Act approval. Our focus is on maximizing the potential of our entire fleet while enhancing the EBITDA through operational efficiency. We anticipate a significant increase in supply coming into the market in 2025, which we believe will affect the market structure. Therefore, it's logical for us to align our generation capabilities with our hedging position to maintain balance. Regarding reliability contracts, the discussion extends beyond just those contracts. The RAM and market redesign in Alberta have resulted in a stronger emphasis on overall reliability and a system that sustains the energy-only market while promoting capacity in the future. This is also crucial for Sundance 6 in terms of revenue, although it will require time to navigate. We have decided to keep the unit operational because we believe it has significant value, whether for reliability or market recovery, especially as we are observing load growth in the province. It was the right decision for us at this time. We can return the unit to operation if the situation changes, which would only require a three-month notice. In the meantime, we will maintain our operational readiness to act if the market conditions shift. If a major data center is announced in the province, for instance, it could dramatically alter supply and demand dynamics, potentially leading to a significant tightening of supply. We see substantial value in the units, but we do not anticipate needing them in 2025.

That's a good segue into your comment about repowering for legacy sites. And from my understanding, you now at least have some optionality. Can you describe what motivates you to go about repowering, including market conditions, contracts, electricity policy or even balance sheet position?

Yes. When we think of the legacy fleet in Alberta, at least in my mind, there are four units: K1, Sun 5, Sun 4, and potentially Sun 3. I mean we don't consider Sun 1 and 2 as part of the mix at this particular point. I don't think you would see us bring the units back on a merchant basis, to be honest. I think that's more for Sun 6. I say that in the context of the way we're thinking about Heartland potentially as well. But if we had data centers or reliability kind of contracting that justified bringing those units back in a way that would warrant kind of the capital expenditures required to bring them back to the place where we would be comfortable operationally or even upgrade them to make them more efficient, that's what it would require. When we look at our cash flow forecast going forward and our borrowing capacity, I don't think we see ourselves as being particularly financially constrained in terms of being able do what we need to do from a data center perspective at this point in time. I'm pretty optimistic; there's a lot of work to be done, but I feel good about all of the optionality we have. Frankly, I think we have more optionality than anyone does in Alberta.

That's good to hear. Thank you very much.

Thank you. One moment for our next question, and that will come from the line of Patrick Kenny with NBF. Your line is open.

Thank you. Good morning, everyone. John, just back on the Heartland transaction, and I'm just curious how this new macro outlook across North America has changed your view on the Heartland assets on a relative basis. So, i.e., is it still more accretive to shareholder value to close the transaction, even if it means adjusting some of the deal terms just to enhance your Alberta presence or taking that CAD600-plus million and potentially looking at opportunities outside of Alberta with this new macro outlook, perhaps in certain other U.S. markets.

Good morning, Patrick. I would say we're probably more bullish around what we can do with Heartland today, given how we see the market potentially evolving in Alberta over the medium to longer term. I think the transaction is accretive; we would be hard-pressed to buy assets at this price level anywhere in North America, and the returns are really strong. We have a hyper-vigilant focus on returns from a shareholder perspective, and that's what drives our decision-making. When we think of the evolution of the province, the Sheerness Units, for instance, which didn't factor prominently from a valuation perspective initially, I think those units have more value today in terms of legacy steel in the ground. Considering our ability to deploy capital in other parts of North America, given marketplace evolution, we don't feel constrained from a financial perspective to do that. So it's not an either-or situation, it's additive as we look at the two. We're excited about opportunities in the Pacific Northwest and the Desert Southwest. We also see significant opportunities in Western Australia, which is our core market. Net-net, we feel good overall in terms of where we are.

From a capital allocation standpoint, your cost of capital has significantly improved over the past four or five months. However, asset prices have also increased. I'm curious about your perspective on the buyback program, specifically regarding this year's CAD150 million target in relation to previous discussions about capital recycling opportunities and possibly becoming more aggressive with some strategic mergers and acquisitions.

I think, look, why don't I start, and then I'll turn it over to Joel. The share buyback program, at least from my perspective, is something we discuss with our board as part of our 2025 budgeting process. I think it's a constant lever we're focused on. I know our cost of capital has improved, but I still see CAD1.70, ballpark year-to-date in terms of free cash flow per share. When I look at that in context of where we're trading, it is still a deal to buy back shares and create value for our shareholders this way. Balancing is important; we can't let our fleet and business atrophy. We'll have to invest to keep moving forward, but when opportunities to buy back shares present themselves, creating that value will definitely be among our focuses on capital allocation.

I agree, John. The other thing, Patrick, is that as mentioned earlier, we will come out with our 2025 guidance in February, I think we'll have more color around that, including respect to the dividend and if there's going to be any extension of the share buyback in 2025 at that point in time. We're committed to fulfilling the full CAD150 million this year; we are around 76% complete as of the end of the quarter. We look to wind that up here by the end of the year at CAD150 million.

Maybe just, Joel, as a sneak peek, how would you rank deleveraging in the priority list versus accelerating growth opportunities for next year?

We maintain a very strong balance sheet. Our leverage rate now on adjusted EBITDA is around 3.2 turns of debt to EBITDA at this point. It has crept up a bit but is still in line with our BBB or BB+ credit ratings. As we balance that going forward, share buybacks with further capital allocation alongside maintaining a strong balance sheet. To the extent we see opportunities to strengthen the balance sheet through reducing our debt, we'll look to that, but we see other opportunities right now, given that we're comfortable with our leverage levels.

We don't have any expiries in the near term. We have CAD400 million about this time next year. So we are in pretty good shape with no expiries that we need to manage through.

Thank you. One moment for our next question. And that will come from the line of John Mould with TD Securities. Your line is open.

Hi. Good morning, everybody. Continuing on the data center theme, I wonder if you could touch on the question of bring your own power and the policy direction here. How well understood is both the current supply surplus and the arguable spare capacity that a company like yourselves has just given that Alberta's chief advantage in this theme seems to be potential speed to market? When are you expecting to see clarity on the rules of the road here, both from the data center perspective and the power provider perspective?

Good morning, John. Look, that's a bit of a hard one to answer. Our province has been very clearly supportive of data centers coming into the jurisdiction. The government has been involved in missions, for example, to Silicon Valley, where they've been trying to socialize the opportunity set that Alberta provides. What’s required here is balance. Having a lot of load come into the jurisdiction in a way that significantly impacts power pricing by tightening the market is something the government and the ISO might be leery of. They want to ensure grid reliability. When you hear things like bring your own power, I think that translates to doing this in a balanced way and ensuring the system remains affordable, reliable, and continues to decarbonize over time. We believe we have an advantage because we have a lot of capacity that, with relatively modest capital investments, we can bring back. From a speed to market perspective, it would be additive generation to ensure that that reliability, affordability, and sustainability remains over the longer term. We can navigate this without needing significant regulatory intervention; it just requires discipline to match supply and demand effectively.

That’s very helpful. Thanks very much for that. The focus of our call has been on optionality at Wabamun and Centralia and not so much on the broader renewables portfolio and your potential development pipeline. So just wondering how your development teams are currently spending their time on Canada versus the US, but also on the thermal opportunity set or maybe I'll rephrase that as the reliability opportunity set because that would include storage as well versus some of the more traditional renewable power projects that you've had in your earlier-stage pipeline historically?

We continue to advance our clean electricity growth plan, that remains a priority for us. Our near-term projects have an Alberta flavor, as you know, and we paused those while wanting to see the Renewable Energy Market develop in Alberta and gain confidence around pricing. The activities of the team right now, I would say probably half of their efforts would be spent on creating value from the legacy assets. I think it presents a significant opportunity set with returns besides conventional power development. I believe it's critical we allocate resources to capture that opportunity. That said, we continue to look at opportunities from a renewables perspective. The focus is definitely on the pipeline, managing it smartly, and ensuring profitable opportunities in our priority markets. The team is working on advancing projects and expanding the pipeline creatively. We are working on a few large projects that we hope will be impactful for the company. It's quite a mix of conventional, unconventional in terms of fuels, and the reliable legacy assets moving forward. Our challenge is finding and hiring capable people to keep things moving.

Okay. That's great. Thanks. And then maybe just one last one on ancillary services. Both the quarterly result and market performance is strong, both on volumes and price realizations there despite reasonable spark spreads given the energy price dynamics. I'm wondering if you could provide a little color on how you're seeing the market. Did the Intertie outage play a part in the ancillary demand this quarter? Looking forward, how are you feeling about ancillary services as the Renewable Energy Market unfolds, recognizing it's still early days?

I'll try to deal with the last part first. I can't give you much color on how the Renewable Energy Market is developing from an ancillary service perspective; I think it's early days. Discussions have focused more on conventional energy markets rather than supplementary energy markets, and on Hydro's role in meeting those needs. But I think we feel pretty confident that our hydro fleet will continue to perform well. Average pricing this year is around CAD65, and we expect to generate over CAD300 million with our hydro fleet. The ISO has been procuring more ancillary services, which is a reflection of the volatility we see as the grid evolves. The scale of inter-hour variation in supply has increased significantly, leading to the need for services that ensure grid reliability. Our Hydro is particularly well-placed for regulating reserves. This quarter, we procured around 900 in ancillary services, which is exceptionally high. I believe it's a good performance overall.

Okay. That’s great. I'll leave it there. Thanks very much.

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 IR team here at TransAlta. Thank you very much, and have a great day.

This concludes today's conference call. You may now disconnect.