TransAlta Corporation (NYSE:TAC) Q3 2024 Earnings Call Transcript

TransAlta Corporation (NYSE:TAC) Q3 2024 Earnings Call Transcript November 5, 2024

TransAlta Corporation misses on earnings expectations. Reported EPS is $-0.09 EPS, expectations were $0.13.

Operator: Good morning. My name is Sherry, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Third Quarter 2024 Results Conference Call. [Operator Instructions] Ms. Valentini, you may begin your conference.

Chiara Valentini: 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 reference during our call today are in Canadian dollars, unless otherwise noted. And 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.

John Kousinioris: 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. And 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 includes 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. And 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. And 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 steel in the ground transmission is available at site with significantly reduced redevelopment costs and time lines for permitting and would provide us with an advantage in speed to delivering power supply.

We expect 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 REX to lower customer carbon intensity and our marketing optimization and regulatory experience differentiates 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. As you can see from the map on the slide, 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 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 in the 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. Joel will now provide more details on the quarter.

Joel Hunter: 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 $89 million, broadly in line with our expectations given the lower realized and ancillary spot prices. The decline quarter-over-quarter was partially mitigated from 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 $44 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 service of Keephills. The Gas segment, which had improved availability of 96.3% delivered adjusted EBITDA of $139 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 Alberta portfolio was partly mitigated from our favorable hedge premiums and position.

The Energy Transition segment delivered $34 million of adjusted EBITDA, which increased year-over-year due to lower purchase power costs, which were driven by lower mid-sea pricing on repurchases of power and lower production from higher economic dispatch. And finally, our Energy Marketing segment delivered exceptional performance with adjusted EBITDA of $54 million, an increase of $41 million year-over-year due to the positive market volatility across North American power and natural gas markets, and higher realized settle 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 $140 million or $0.47 per share.

Year-to-date, we’ve achieved $521 million or $1.72 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 $55 per megawatt hour, which was significantly lower than the average price of $152 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 $85 per megawatt hour, which compared favorably to an average spot power price of $55 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 $90 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 $55 per megawatt hour. Historically, this has averaged around 50% of the average spot power price. 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 in order to be optimized for peak demand and 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 $82 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 $76 per megawatt hour, also above current forward pricing levels for both years. I’ll now pass it back to John to discuss our balance of the year priorities.

John Kousinioris: 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 $114 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 remain committed to completing the $150 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 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. 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, close the Heartland acquisition 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 of our employees and contractors for the outstanding work they have done to deliver our excellent results during the quarter and set company up for a strong finish to 2024. Thank you. I’ll turn the call back over to Chiara.

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

Operator: [Operator Instructions] And our first question will come from the line of Mark Jarvi with CIBC. Your line is open.

Q&A Session

Mark Jarvi: Ho, 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?

John Kousinioris: 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, 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 work to in the interim, 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 be able 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. I would say, generation at site to be able to meet their needs from a longer-term perspective. Blain, any color on that? Or I mean, I think that’s…

Blain van Melle: I think that’s correct, John.

Mark Jarvi: And maybe just a follow up that. We’ve seen other firms filed 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 around emission profile just up on solution with some of your renewables that you own?

John Kousinioris: Yes. Let me see if I can answer all of the questions. Look, we – filing to kind of get an interconnection setup is actually not a difficult thing to do. And 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 more 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 they going to look like? It’s so 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 it in an interconnection request. We’ve got a lot, as you know, from — given the legacy sites that we have there, transmission access there. So that’s not — it’s not really, I would say, a gating item, I would say, Blain, in terms of the way that we’re looking at it. So would be the first thing. 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. I would say what our discussions are right now, emissions profiles would be lane, I would say, kind of a medium to lower order of priority, at least at present. I think over time, you’ll see that, 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 set up well. So that’s pretty much a reflection of where I think John mentioned in your remarks that our portfolio and bundled with REX come off of our existing portfolio also provides an attractive alternative to solving that emission profile challenge for certain customer classes. And then just a follow-up on what Blain just said, and 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.

Mark Jarvi: 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 site the presence in Alberta?

John Kousinioris: Mark, I’m kind of smiling because it’s a bit of an internal race. You sound like sort of we see sometimes in the office. Look, they’re both advancing. And I would say, Blain [ph] kind of comparable time lines, I think we would probably have I’d say our discussions are probably a little bit more advanced than Centralia than they would be at Alberta Thermal from a timing perspective. And the need is acute in terms of what we can provide from a reliability perspective down in the Pacific Northwest. So that would probably have a bit of a slight edge in timing, I would say. But we continue to work worth — we continue to work both at the same time, contemporaneously.

Mark Jarvi: Great. Okay. Thanks for the time today.

Operator: 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

Q – Benjamin Pham: 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 the 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?

John Kousinioris: Yes. Good morning, Ben. On Sundance 6, look, we’ve been — like we continuously look at the fleet, and we continue to look at the optimization of the fleet. And we look at that in the context of our confidence in the Heartland transaction and how that might adjust the portfolio of the company as we go forward. Specifically, on Sun 6 as we see kind of power prices in 2025 and 2026, which is something we predicted in terms of the dip going down. And we look at the capacity factors that we anticipate from our generation, both from K2, K3 and Sun 6, we were pretty comfortable that the right decision for us in the context of all of that. From an EBITDA and value maximization perspective was to mothball Sun 6 and have both K3 and K2 running at higher capacity factors that would have otherwise have been the case if we had all of three units that we’re running.

We’re also pretty comfortable from a hedge position that we have in 2025 and 2026. And I think it’s about 5,500 gigawatt hours of hedges, which translates to about 800 megawatts per hour of a hedge position at kind of those mid-$70 kind of levels. We’re comfortable with that. You’ll see that 2025 and frankly, even 2026, are a bit a repeat strategically of what we’ve tactically tried to do in 2024, plus we’ve got our Hydro fleet and like I said, the potential around Heartland to be able to have the length that we need to be able to manage through all of that process. The other thing I would say is that Sundance 6 was coming up to a pretty significant turnaround. So there would be significant capital, sustaining capital expenditures that we would need to put into the unit to make sure that we extended it so that it would be fully operational into — for the ensuing two years.

And at least from our own perspective, it just didn’t make economic sense to kind of triple up, if you can see with the three units at that particular point in time. So we’ve deferred that. A lot of the work has been done. We know what we need to do. And we put the unit into mothball, we’re going to keep it for Q1 where you expect pricing to be more constructive and then we would mothball it. But you should know we’re actually keeping a good chunk of that workforce on the payroll. So there will be some redundancy in the organization, and I — it’s always disappointing when that happens. But in terms of operators and some of the key people that that we need to be able to bring the unit back, I just we want to be clear we’re keeping that capability intact while the unit is effectively mothballed.

So hopefully, that gives you a bit of color.

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

John Kousinioris: Yes. I can — look, I can start and then Joel can chime in. I don’t think our view has changed in terms of where we are on 2025. I think given our increasing confidence on Heartland, given kind of the hedge levels that we have, and it’s interesting. Our hedge levels in 2025 at kind of that $75 range begin to approximate about what the gas fleet was able to actually secure over the course of the last quarter, we’re pretty highly hedged. We’ll have full year production from our new wind generation. So I would say, we feel pretty good about 2025. We’re in the final throes of that budgeting work, I would say, Joel, and that will obviously go to the Board, and we’ll provide the market with guidance at that point in time. But look, we’re — we’ve had — we’ve trended to the upper end of our guidance in 2024, which has been great, but we remain confident about 2025. Joel, I don’t know if you…

Joel Hunter: The only thing I would add there, John, is to comment earlier that we don’t have an Investor Day this year, Ben. 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 year remains intact.

Benjamin Pham: Okay. Great. Maybe just one quick cleanup. What was driving the cash taxes, maybe I missed — I didn’t — I may have missed in your initial remarks, but there’s explain in the cash taxes?

Joel Hunter: Yes, Ben. So if you think about in Canada, up until this year, we weren’t — we had loss carryforwards that we were able to utilize. So think about over the last few years despite higher net income, we were able to keep our tax bill relatively low as we had carryforwards. Those carryforwards have been exhausted. So as we think about 2024 and beyond what we all see here is a higher effective tax rate, probably closer to our statutory tax rate for your modeling. And so you look to our disclosure in the assumptions, you can see in our cash taxes, we initially kind of guided on our assumptions from $140 million to $160 million. That is now $30 million higher. It’s a $160 million kind of mark here for the year. So again, it’s just as a result of us exhausting our large carryforwards last year.

Benjamin Pham: Okay. Got it. Thank you.

Joel Hunter: Yes.

Operator: 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.

Maurice Choy: 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 just mean in terms of potential for capacity payments? And if you could just elaborate a little bit about an earlier comment about what this may mean for getting an approval on the Heartland generation deal? I appreciate that.

John Kousinioris: Yes. Hi. Maybe I’ll start with the last one. I don’t — so there’s been no discussions, I would say, with the Competition Bureau as it relates to TransAlta’s existing fleet. So I just want to make sure that folks understand that. So the Sundance 6 decision had nothing to do with any kind of a Competition Act kind of approval going forward. Look, we’re very much focused on maximizing the optionality of all of the fleet that we have. And we look to do that, at the same time we’re trying to maximize kind of the EBITDA that the fleet is going to be able to generate just by being as operationally efficient as we possibly can be. We see a lot of supply coming into the market in 2025. We see a lot of that impacting the market construct that we have there.

So from our perspective, it just made sense to match up our generational capabilities with kind of our hedging position make sure that that we were in balance. In terms of reliability contracts, I think it’s actually a bit of a bigger discussion than just reliability contracts. I mean what we have seen with the RAM and the market redesign in the province of Alberta, is an increasing focus on reliability generally. And on a construct, I would say, that preserves the energy-only market, but kind of does so in a way that sort of I would say, incentivizes capacity going forward. So, that’s also something that is prospectively, I think, important for Sundance 6 from a revenue perspective. That’s going to take some time to work through. And so what we’ve done we’ve kept the unit around.

We think it has a lot of value, whether it’s reliability, whether there’s a market recovery because we are seeing load growth increase in the province. And it just made sense for us to make that decision at that particular point in time. We have the ability to bring the unit back if circumstances change. And I think that’s a three-month notice period to be able to do that. And meanwhile, we’ll be making sure that we keep our operational capabilities to enable us to be able to do that should market change. And as you know, Maurice, if a data center is announced in the province, and let’s say it’s a gigawatt in size, that changes the entire supply and demand kind of fundamental within the province. We go from being in a place where we have kind of excess supply compared to the demand, a bit of a supply imbalance to one where it’s quite a bit tighter.

And we’re actually seeing that, I think, in in terms of reserve margins, too. If you roll out 2026, 2027, you end up seeing things tighten up considerably the province. So, we just think there’s a lot of value in the units. We just don’t think we’re going to need it in 2025.

Maurice Choy: That’s a pretty 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 we motivate you to go about powering, including market conditions, contracts, electricity policy or even balance sheet position?

John Kousinioris: Yes. And when we think of kind of the legacy fleet that we have in Alberta, at least in my own mind, and Blaine and I and our team, we talk about it all the time, along with Chris, who runs our operations. So, it’s K1, Sun 5, Sun 4, potentially Sun 3. So, there’s actually four units that we have. I mean we don’t consider Sun 1 and 2 as sort of being part of the mix at this particular point in time. I don’t think you would see us bring the units back on a merchant basis, to be honest. I think that’s more of Sun 6. And I say that in the context of the way that we’re thinking about Heartland potentially as well. But if we had data centers or reliability kind of contracting that that made sense to bring those units back in a way justified kind of the capital expenditures required to bring them back to the place where we would be comfortable with them operationally or even upgrade them and make them more efficient.

That’s what it would require. And then just when we look at our cash flow sort of forecasted going forward and our borrowing capacity, Joel, I don’t think we see our cells as being particularly financially constrained in terms of being able to do what we need to do from a data center perspective at this point in time. So, I have to say Maurice, pretty optimistic. Like there’s a lot of work to be done, but I feel good about all of the optionality that we have. I mean, candidly, I think we have more optionality than anybody does in the province of Alberta. So I can even like where we are.

Maurice Choy: That’s good to hear. Thank you very much.

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

Patrick Kenny: 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 more 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 beef up your Alberta presence or taking that $600-plus million and potentially looking at opportunities outside of Alberta with this new macro outlook, perhaps in certain other U.S. markets.

John Kousinioris: Yeah. I think — So good morning Patrick, look, 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 the province of Alberta over the medium to longer term. I think the transaction is accretive, we would be hard-pressed to be able to buy assets at this kind of price level anywhere in North America, and I think the returns are really strong. And we have a hyper sort of vigilant focus on returns from a shareholder perspective. That’s really what drives our decision-making. So when we think of the evolution of the province, when we think of the Sheerness Units, for example, which were units that didn’t factor sort of prominently, I would say, from a valuation perspective as we were thinking of it.

I think those units have more value today in terms of legacy steel in the ground. In terms of our ability to deploy capital in other parts of North America, given the evolution that we’re seeing in marketplace is there. We don’t feel that we’re particularly constrained from a financial perspective to be able to do that. So it’s not an either or kind of situation is sort of additive as we look at the two. So we’re excited about opportunities that we see in the Pacific Northwest. And we’re actually excited about opportunities that we see in the Desert Southwest. We continue to look at both of those areas. And we think that in the medium to long-term, there’s a lot opportunities in Western Australia as well, which are our core markets. So I think net-net, we feel good overall in terms of where we are.

Patrick Kenny: And to your point, I guess, from a capital allocation standpoint, your own cost of capital has improved quite a bit over the past four or five months. But obviously, at the same time, asset prices are up. So I’m just curious, how you’re thinking about — and maybe this is for Joel, but how are you thinking about the buyback program beyond this year’s $150 million target versus …

John Kousinioris: Yeah.

Patrick Kenny: …when you talked in the past about capital recycling opportunities and maybe getting a bit more aggressive on some strategic M&A?

John Kousinioris: Yeah. I think, look, why don’t I start and then I’ll turn it over to Joel. Look, I think the share buyback program, at least from my own perspective, and look, it’s something that we talk to our board, and we’ll be talking to our Board of our despite part of our 2025 budgeting process. But like I think it’s a constant lever that, I think we’re focused on as a management team. I know our cost of capital has improved, but I still see $1.70. I think, ballpark year-to-date in terms of free cash flow per share. And when I look at that in the context of where we’re trading, like I think it’s still a deal to buy back shares and create value for our shareholders that way. So it’s something that balance is important, like we can’t let our fleet and our business atrophy.

We’re going to have to continue to make investments and move that along. But certainly, when opportunities present themselves to do share buybacks to support our price and to create that value, I think it’s going to be definitely one of the things that we’ll be looking at from a capital allocation perspective, Joel?

Joel Hunter: Yeah, I agree, John. And the other thing, Pat, is that as mentioned earlier, is when we come out with our 2025 guidance in February, I think we’ll have more color around that, say, with respect to the dividend and obviously, if there’s going to be any extension of the share buyback in 2025 at that point in time. But to John’s point, we remain committed to fulfilling the full $150 million …

John Kousinioris: Yeah.

Joel Hunter: …this year, we’re around 76% complete as the end of the quarter. So we’ll look to wind that up here by the end of the year at $150 million.

Patrick Kenny: And just maybe, Joel, as a sneak peak, I mean, how would you rank deleveraging in the priority list versus accelerating growth opportunities for next year?

Joel Hunter: Pat, on that, we do maintain a very strong balance sheet. When you look at our leverage rate now on adjusted EBITDA of around 3.2 turns of debt to EBITDA at this point in time. And it’s crept up a bit, but still in line with our BBB or BB+ credit ratings. So as we balance that going forward, share buybacks, further capital allocation along with maintaining a strong balance sheet. So to the extent we see opportunities to further strengthen the balance sheet through reducing our debt, we’ll look to that, but we see other opportunities right now given that we are very comfortable with our leverage levels.

John Kousinioris: We don’t really have any expiries in the near term. I mean, we have $400 million about this time next year-ish. So we’re in pretty good shape in terms of — do you know what I mean, Patrick, in terms of kind — any kind of expiries that we’re needing to manage through.

Patrick Kenny: Okay. That’s great. I’ll leave it there guys. Thanks.

John Kousinioris: Thanks.

Operator: 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.

John Mould: 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 at [indiscernible] just given that Alberta’s chief advantage in this theme seems to be potential speed to market. And 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?

John Kousinioris: Yeah. Good morning, John. Look, that’s a bit of a hard one to answer. And maybe what I’ll say is this, look, our province has been very clearly supportive of data centers coming into the jurisdiction. I mean, the government has been involved in missions, for example, into the Silicon Valley where they’ve been trying to socialize the opportunity that sets — the opportunity set that Alberta provides. I think what’s going to be required here is balance. So having a lot of load come into the jurisdiction in a way that has a significant impact on power pricing by tightening up the market, I think, is something that I think the government and the ISO was probably leery of. They want to make sure that the grid remains reliable.

So when you hear things like bring your own power, I think what folks are saying, I think to me anyways, that’s code for, let’s do this in a balanced way and make sure that the system remains, affordable, reliable, and we continue to decarbonize it over a period of time. I think that’s where we have an advantage, because we have a lot of capacity candidly that with relatively modest capital investments, we can bring back from a speed to market perspective, and it would be additive generation, if you see what I’m saying, in terms of being able to flex up and be able to make sure that that three-legged stool I mentioned of reliability, affordability and sustainability kind of remains over the longer term. So I think this is something that we can navigate.

I don’t know that it requires — Blain, I would say I don’t know there requires a lot of regulatory intervention for us to get there. I think it just requires discipline and making sure that we can match reasonably supply and demand as it comes through.

John Mould: That’s very helpful. Thanks very much for that. And just clearly, 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 is your development team — how are your development teams currently spending their time on kind of 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?

John Kousinioris: Yeah. So look, we continue to advance kind of our clean electricity growth plan, that remains a priority for us. We had — our near-term projects had an Alberta flavor, as you know, and we paused those given that we were wanting to see the REM develop here in the province of Alberta and get a sense of confidence around the fidelity of the price. So when you look at sort of the activities of the team right now, I would say probably half of the team’s efforts would be spent on kind of create value from the legacy assets. I think it’s a pretty significant opportunity set and the returns are significant for our shareholders. They are candidly returns that would be significantly in excess of what I would say conventional power development would provide.

So I think it’s critical that we allocate the resources to kind of capture that opportunity set. But having said that, we continue to look at opportunities from a renewables perspective. The focus is definitely on the pipeline, managing it, making sure that we’ve got good opportunities in kind of what we’re considering to be our priority markets, which are more Western North America phased as opposed to more in the SPP, where we were initially a little bit more focused, but the team is working on advancing projects. They’re working on expanding the pipeline. They’re actually doing some pretty creative things on the pipeline, to be honest, that they’re still nascent, so we can’t kind of give you a color on that, but that’s something that we’re excited about.

And we continue to work on a couple of large projects that hopefully will be very impactful for the company. So it’s quite a quite a mix of, I would say, the conventional — the unconventional and by unconventional, I mean, in terms of fuels and kind of the bread-and-butter legacy assets in terms of going forward. The team is busy. Our challenge is actually, John, finding and hiring capable people that can move it along. So that’s what we’ve been doing to make sure that we’ve got the capacity to deal with it.

John Mould: Okay. That’s great. Thanks. And then maybe just one last one on ancillaries, both the quarterly result and just the market more broadly, pretty good performance, both on volumes and price realizations there despite pretty reasonable spark spreads given the energy price, which can have the effect of — it’s just an interesting dynamic there. I’m just wondering a little more color on how you’re seeing the market. Did the Intertie outage play a part in the ancillary demand this quarter? And then looking forward, how are you feeling about how the ancillary services piece of the REM is unfolding, recognizing it’s very early days still there?

John Kousinioris: Yeah. Look, I’ll maybe try to deal with the last part first. I can’t give you a lot of color on how the REM is developing from an AS perspective. I think that’s really early days. I think the discussions have been focused more on what I would call the conventional energy market rather than kind of the supplementary parts market and Hydro’s role in meeting those particular needs, John. But look, I think we feel pretty confident that our hydro fleet is going to be valuable and will continue to perform well. I mean, just look at where we are this year. We’ve got average pricing this year that is sort of in that — I think year-to-date, we’re about $65 or something like that in the province, and we’ll get over $300 million with our hydro fleet as we go forward.

We’re also seeing the ISO procuring more AS, which is interesting. And I think that’s just a reflection of the kind of volatility that we’re seeing as the grid evolves. I mean there was a time like 3 years ago, I would say, Blain, when the kind of scale of inter hour kind of variation in supply would have been more in the 400 or 500-megawatt range. We’re seeing like 2,000 megawatts in terms of variation that can occur if the wind drops off or it’s evening and our solar ends up going away. So the need to kind of respond to that and to make sure that the grid is reliable from a frequency perspective. So, when we look at our Hydro, there’s kind of nothing better. I mean, it’s better than batteries in our view, particularly for regulating reserves.

And I think what you’re seeing is just a reflection of the need for those services as the market kind of evolves over time. So, like I’m pretty confident that we’re going to have good hydro performance going forward. And look, I think we almost got to 900 in terms of the quantity of AS that was procured in the last quarter, which is like exceptionally high. I don’t recall us ever having that level. So I think it’s strong on product.

John Mould: Okay. That’s great. I’ll leave it there. Thanks very much.

Operator: That is all the time we have for Q&A today. I would now like to turn the call back over to Ms. Valentini for any closing remarks.

Chiara Valentini: 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.

Operator: This concludes today’s conference call. You may now disconnect.