TransAlta Corporation (NYSE:TAC) Q3 2025 Earnings Call Transcript

TransAlta Corporation (NYSE:TAC) Q3 2025 Earnings Call Transcript November 7, 2025

Operator: Good morning. My name is Olivia, and I’ll be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Third Quarter 2025 Conference Call. [Operator Instructions] Thank you. Ms. Paris, you may begin your conference.

Stephanie Paris: Thank you, Olivia. Good morning, everyone. My name is Stephanie Paris, and I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta’s Third Quarter 2025 Conference Call. With me today are John Kousinioris, President and Chief Executive Officer; Joel Hunter, EVP, Finance and Chief Financial Officer; Blain van Melle, EVP, Commercial and Customer Relations; and Nancy Brennan, EVP, Legal and External Affairs. 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 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 information statement qualification 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 are in Canadian dollars, unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA and free cash flow are 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. With that, I will turn the call over to John.

John Kousinioris: Thank you, Stephanie. Good morning, everyone, and thank you for joining our third quarter conference call for 2025. As part of our commitment towards reconciliation, I want to begin by acknowledging that our company operates on the traditional territories of indigenous peoples across Canada, Australia, and the United States. We recognize the rich and diverse histories, cultures, and contributions of the First Nations, Inuit, Metis, Aboriginal and Native American communities. And it is with gratitude and respect that we thank the peoples who have lived on these lands, for reminding us of the ongoing histories that precede us. TransAlta delivered solid performance during the third quarter, demonstrating our fleet’s resilience during challenging market conditions.

Our Alberta portfolio hedging strategy and active asset optimization continued to generate realized prices well above spot prices, while availability remained high across the fleet. During the quarter, we delivered adjusted EBITDA of $238 million, free cash flow of $105 million or $0.35 per share and average fleet availability of 92.7%. Based on our results to date and expectations for the fourth quarter, we remain confident in achieving our 2025 guidance range. We’re tracking to the lower end of the adjusted EBITDA range and the midpoint of free cash flow, which Joel will speak to later in the call. As you all know, a key priority for our company is to progress our legacy thermal opportunities, which we continue to do during the quarter. In Alberta, our data center project will contribute to powering a new industry in the province.

And in Washington, our Centralia project will support reliability for decades to come. Commercial negotiations for both projects continue to progress during the quarter. And while we remain confident in our advancement of these key priorities, we’ve decided to shift the timing of our Investor Day to the first quarter of 2026, following data center and Centralia announcements. We will provide you with detailed updates on both projects and their impact on our company, as well as the opportunities we see across all of our core markets at that time. Returning to the quarter, we executed agreements to extend our committed credit facilities totaling $2.1 billion with our syndicate of lenders. Our syndicated facility of $1.9 billion now has a maturity of June 30, 2029, and our bilateral credit facilities of $240 million were extended by 1 year to June 30, 2027.

During the quarter, we completed the sale of a 100% interest in the 48-megawatt Poplar Hill facility, as required under the terms of the Heartland Generation acquisition. And following the quarter, on October 2, we also closed the sale of a 50% interest in the 97-megawatt Rainbow Lake facility. The proceeds from the divestitures go to Energy Capital Partners, as agreed to under the terms of the transaction. This marks the successful conclusion of the remaining regulatory requirements for the Heartland acquisition. In August, the AESO announced its final design for the restructured energy market, or REM, which I will speak to momentarily. The government of Alberta also introduced proposed amendments to the TIER regulations. The proposed changes include recognition of on-site emissions reduction investments as a compliance pathway under the TIER system.

This may impact the emission credit market. However, as most of our credits are deployed internally towards our gas fleet emissions obligations, we do not anticipate this change, if implemented, to be material to our business. And finally, we continue to engage directly and collaboratively with the Government of Alberta and the AESO, on the Alberta data center strategy and their approach to large load integration. Turning more specifically to the work that we’re doing in realizing the value of our legacy generation sites. At our Centralia site, we’re actively engaged in commercial negotiations with our customer and expect to be in a position to execute a definitive agreement before year-end. At that time, we will be able to share our detailed development plans for the site.

We also continue to progress our Alberta data center strategy and the associated commercial negotiations. Recently, we entered into a demand transmission service contract with the AESO for 230 megawatts, representing the full allocation awarded to the company through Phase 1 of the AESOs data center Large Load Integration program. In September, Parkland County unanimously approved the rezoning of over 3,000 acres of TransAlta-owned land surrounding our Keephills and Sundance facilities to support future data center development. We’re grateful for this community support, which represents an important milestone to advance the opportunity for new investment, job creation, and economic growth in the region. We continue to work closely with our counterparties on their data center project and are steadily progressing towards the finalization of a memorandum of understanding.

We also continue to engage directly with the provincial government and the ISO on Phase 2 of the Large Load Integration program. We’re excited about the data center opportunity in Alberta and the meaningful investment it can bring to the province. In August, the AESO announced its final design for the Alberta restructured energy market or REM. The structure is consistent with our expectations, adds greater certainty to the market, and supports system reliability, something our diverse and dispatchable generating fleet in Alberta is well suited to provide. Notably, the REM will help ensure appropriate price signals are received by generators to enable reliable generation investment and ensure Alberta is competitive with other jurisdictions. The REM contemplates an increase in the provincial price cap to $1,500 per megawatt hour and eventually to $2,000 per megawatt hour, with additional administrative scarcity pricing during periods of tight system conditions.

The REM also creates a new ramping product to enhance system reliability, which our dispatchable fleet is well positioned to serve and mitigates against any adverse impact from the adoption of locational marginal pricing for incumbent generators through the allocation of financial transmission lines. The REM is expected to be implemented in 2027 or 2028, and we will continue our active engagement in the AESO consultation process, which is now focused on implementation. We believe that the changes to the market provided by the REM, coupled with the anticipated load growth from the fully allocated 1.2 gigawatts of data center system access granted by the ISO will see Alberta’s power supply and demand imbalance improve, and lead to a recovery in the merchant power price in the province, benefiting our diversified legacy fleet.

The forward price has begun to reflect the changing supply and demand dynamic in the province, driven by electrification, data center load, and population increases, along with the slowdown in incremental new supply coming online, which makes our existing generating fleet increasingly valuable. There appears to be a reaction today to a reference to Project Greenlight’s data center in-service date being pushed out to 2030. Our understanding is that that is very much an outside date and that Kineticor and their customer are still driving to have the project in service in 2027 or 2028. It remains our view, based on the information that we have, that forward prices do not yet fully factor in the impact of the REM or 1.2 gigawatts of data center load that will be coming online.

The gradual increase in load we now expect will rebalance the current oversupply of generation in the province and drive opportunities for growth in the long term. TransAlta’s dispatchable thermal and hydro fleet have existing capacity to provide reliability and serve the expected load growth. Before I turn the call over to Joel, I’d like to offer a few words on my upcoming retirement. As we announced today, I will be retiring from TransAlta and its Board, effective April 30, 2026. It has been an honor to lead TransAlta, and to work with such a committed and talented team. Together with our Board, we have evolved our business and built a strong foundation for the future by increasing shareholder returns, delivering strong financial results, navigating regulatory change, diversifying our business, and positioning our fleet to meet the customer needs of the future.

I fully support Joel, as the next President and CEO of TransAlta. He’s a proven leader and the right person to advance TransAlta’s strategy. I look forward to working with him, management, and the Board, over the coming months to ensure a successful transition. I’ll now pass the call over to Joel.

Joel Hunter: Thanks, John, and good morning, everyone. I’d like to start by offering my congratulations to John, on his upcoming retirement, and thank him for his leadership, guidance, and strategic vision for TransAlta, as well as his active support of my leadership. I look forward to working together to ensure a smooth transition and continued execution of our strategic priorities. We will announce the CFO successor in the coming months. Turning now to our third quarter results. I’ll start with an overview of the period, where our fleet demonstrated resilience in softer market conditions. During the quarter, we generated $238 million of adjusted EBITDA, which was $77 million lower than the third quarter of 2024, due to lower Alberta and Mid-C power prices, subdued market volatility impacting energy marketing and trading results, and lower contract revenue from our Centralia facility.

Turning to our segmented results relative to the same period of 2024. Hydro segment adjusted EBITDA decreased to $73 million compared to $89 million last year due to lower spot power prices in Alberta, as well as lower ancillary services revenue, which was impacted by lower availability from higher planned maintenance outages. Through optimization, we’re able to reallocate these services to our gas fleet, maintaining our market share of the associated ancillary revenues. Environmental and tax attribute revenue to third parties was also lower than last year. The wind and solar segment produced adjusted EBITDA of $45 million, in line with the third quarter of 2024. In the gas segment, adjusted EBITDA decreased to $110 million from $141 million in 2024, mostly due to lower realized power prices in Alberta, along with higher carbon pricing, partially offset by the addition of the Heartland assets, which increased contracted production, along with incremental ancillary services revenue due to production optimization between the gas and hydro segments.

The energy transition segment delivered adjusted EBITDA of $28 million, a $6 million decrease year-over-year due to lower market prices, partially offset by lower purchase power costs and a higher volume of favorable hedge positions settled. Energy marketing adjusted EBITDA decreased by $25 million to $17 million, primarily due to comparatively subdued market volatility across North American natural gas and power markets and lower realized settled trades in the quarter compared to last year. And corporate adjusted EBITDA was in line with last year at $35 million. As a reminder, our adjusted EBITDA excludes the impact of ERP costs as the integration is not reflective of ongoing operations or the performance of our operating assets. Overall, free cash flow was $105 million in the third quarter, which was $26 million lower than the same period last year.

Lower adjusted EBITDA and higher net interest expense was partially offset by lower current income tax expense and lower distributions paid to noncontrolling interests. Turning to the Alberta portfolio. The third quarter spot price averaged $51 per megawatt hour, which was lower than the average price of $55 per megawatt hour in 2024. The decline year-over-year was primarily due to incremental generation from the addition of new gas and renewable supply in the province, as well as benign weather. Throughout the quarter, we deployed hedging strategies to enhance our portfolio margins and mitigate the impact of lower merchant power prices. We realized the benefit from approximately 2,500 gigawatt hours of hedges at an average price of $66 per megawatt hour, representing a 29% premium to the average spot price.

In addition, our hydro fleet delivered an average realized merchant price of $76 per megawatt hour, a 49% premium to the average spot price, while the gas fleet realized an average merchant price of $79 per megawatt hour, a 55% premium to the average spot price. Our merchant wind fleet, which cannot be used as firm power for hedging activities, realized an average price of $28 per megawatt hour. We were also able to deliver additional ancillary volumes across the Alberta fleet. In the quarter, our average realized price for hydro ancillary service pricing settled at $47 per megawatt hour, an 8% discount to the average spot price. Due to the optimization of ancillary services to the gas segment from hydro during planned outages, the gas segment realized an average ancillary service price of $41 per megawatt hour.

Despite relatively benign weather in the quarter, which resulted in lower spot power prices, we captured additional margins by fulfilling a portion of our higher priced hedges with purchased power when prices were below our variable cost of production, leading to an overall realized price per megawatt hour produced of $103 compared to $90 per megawatt hour in the same period last year. For the balance of the year, we have approximately 1,900 gigawatt hours of our Alberta generation hedged at an average price of $72 per megawatt hour, well above the current forward curve of $57 per megawatt hour. Going forward, we expect to continue to optimize our fleet and reduce production in low-priced, high-supply hours by fulfilling our financial hedges and customer requirements with open market purchases.

Looking at next year, our team has increased our hedge position to approximately 7,800 gigawatt hours at an average price of $66 per megawatt hour, which remains well above current forward pricing levels. Based on our year-to-date results and balance of year expectations, we remain confident in our 2025 outlook. We are currently tracking towards the lower end of our adjusted EBITDA range, largely due to the Alberta spot power price tracking to the lower end of the outlook range of $40 to $60 per megawatt hour. Currently, we expect the full year spot price to average $46 per megawatt hour. In terms of sensitivity to the Alberta spot power price, $1 per megawatt hour is expected to have a $2 million impact to our adjusted EBITDA for the balance of the year.

Other factors influencing adjusted EBITDA include lower wind resource and subdued market volatility. Free cash flow is tracking to the midpoint of the outlook range and the aforementioned adjusted EBITDA impacts are partially offset by lower expected current taxes and lower expected distributions to noncontrolling interests. Consistent with the past year, we’ll provide a fulsome 2026 outlook update on our fourth quarter 2025 conference call in February. I will now turn the call back over to John.

John Kousinioris: Thank you, Joel. We remain focused on the following priorities for 2025. First, delivering adjusted EBITDA and free cash flow within our 2025 guidance ranges; second, improving our leading and lagging safety performance indicators while achieving strong fleet availability; third, maximizing the value of our legacy thermal energy campuses by capturing the opportunity presented by securing a data center customer at Alberta thermal as well as advancing our coal-to-gas conversion at Centralia; fourth, successfully pursuing any strategic M&A opportunities that may arise; fifth, maintaining our financial strength and flexibility; and finally, successfully implementing the upgrade to our ERP system. I believe TransAlta offers a compelling investment opportunity.

We’re a safe and reliable operator with strong cash flows, underpinned by our diversified hydro, wind, solar, and gas portfolio located across 3 countries and complemented by our leading asset optimization and energy marketing capabilities. There is significant and growing value in our legacy thermal sites, which our team is actively working to repurpose to meet the growing need for reliable generation in the jurisdictions in which we operate. We also remain a clean electricity leader with a focus on tangible greenhouse gas emission reductions as we remain on track to achieve our ambitious 2026 CO2 emissions reduction target. We remain disciplined in our approach to growth, focused on delivering value to our shareholders as we work to diversify our portfolio within our core jurisdictions and increase the stability and contractiveness of our cash flows, and our company has a sound financial foundation.

Our balance sheet is flexible, and we have ample liquidity to pursue and deliver multiple growth opportunities, along with the ability to also return capital to our shareholders. Finally, and most importantly, we have our people. Our people are our greatest asset, and I want to thank all our employees and contractors for their commitment in setting the company up for success in the remainder of 2025, and beyond. Thank you. I’ll now turn the call over to Stephanie.

Stephanie Paris: Thank you, John. Olivia, would you please open the call for questions from the analysts?

Q&A Session

Operator: [Operator Instructions] Our first question coming from the line of Robert Hope with Scotiabank.

Robert Hope: Congrats to John and Joel, on the announcements.

John Kousinioris: Thanks, Robert.

Joel Hunter: Thanks, Robert.

Robert Hope: Maybe on the data center front. So it appears that discussions are going slower than anticipated regarding customers for the data centers in Alberta. Can you maybe add a little bit of color of what is driving this, as well as has your confidence in securing a project increased or decreased since the Q2 call?

John Kousinioris: Robert, we remain confident in our ability to progress the data center opportunity that we have here in the province. Look, it’s a big initiative, both for our prospective customers and for our company. It takes time to make sure that all of the details that we need to work with. And frankly, there’s multiple parties involved in bringing it forward. It just takes time to do all of that. Phase 2 of the ISO process and the Government of Alberta process in terms of large load integration is also critically important. That’s taking a little bit of time to sort out because, at least from our own perspective, it isn’t just about the initial 230 megawatts that we’ve got. It’s about how we’re thinking about phasing a real data center opportunity for the province and for our company.

All of this takes time, but we’re tracking, and we remain in the confidence that we had last quarter and in other earlier times of the year to move it forward. It is very much a key priority for our company.

Robert Hope: Aare you in discussions to serve other data center customers in Alberta in — on a shorter-term basis? You did mention Greenlight. You do have confidence that it could be in service in ’27, ’28. What gives you that confidence? And could you be supplying power to them in that timeframe as well?

John Kousinioris: So all of the discussions that we’re having, all of the work that we’re doing are really around a single opportunity. And we’ve taken, at least from a TransAlta perspective, an exclusive approach with those prospective customers. So that’s the way we’re looking at it. It’s also our expectation that once we’re able to announce our MOU and begin moving forward that we’ll be able to start seeing load come into our sites gradually and probably a bit more earlier than probably what Kineticor is currently anticipating that they would have coming in. So hopefully, that gives you a little bit of color.

Operator: Our next question coming from the line of Mark Jarvi with CIBC.

Mark Jarvi: Congrats, Joel and John. Not to get too far ahead of ourselves, but once you do have the MOU in place, then what would be the sort of time line when you think you can get to a binding agreement? And given the fact it’s taking a bit longer to get to the MOU, does that shorten the window from MOU to final agreement?

John Kousinioris: Mark, good morning. Look, we would want to go pretty quickly, I would think, and we’ve already begun kind of getting our team ready and getting internally ready to kind of get to definitive documentations pretty quickly to move that forward. I can’t give you sort of a specific time line on that when that would occur. But certainly, I’d be pushing our team to try to get it done as soon as possible. I think one of the key elements of the MOU is to have enough sort of specificity in that and an understanding of the arrangements between ourselves and our customers in order to permit that to kind of make the definitive documentation of it easier to proceed. But I think it’s going to happen in — like, I think it will actually be quicker than certainly it’s taken to get the MOU done is what I would say.

Mark Jarvi: You used the word counterparties in the plural. Can you elaborate on what that means? Is that on the funding side for the customer? Is it a sort of joint venture in the data center? Anything you can shed on that. And the fact that it is multiple customers, how has that sort of affected the time line to reach MOU?

John Kousinioris: Yes. We do — we are working with more than one customer. We’re working together to see the opportunity come through. And that’s been the case throughout candidly, our engagement. And given where we are in the process and how we’re working through it, there isn’t a lot more that I can give you, Mark. I wish I could, but I can’t.

Mark Jarvi: On the last call, you indicated that — you took the view that your underutilized coal-to-gas converting units sort of are akin to incremental generation when you think about Phase 2 and you’re trying to have those conversations with the AESO and the government. How have those progressed? And are you getting traction with that concept?

John Kousinioris: Yes. I’m glad you asked about that. So we have had discussions on Phase 2. Joel and I, and Nancy have spent a fair bit of time, and Blain has been involved in that as well as we move forward. I mean, I’ll give you a bit of a sense on our company’s position, which our sense is it is being well received by the government, would be that we don’t — just to give you a bit of a sense is, one, we don’t think that colocation is necessary. We think that it would be better — there isn’t a need to co-locate the data center with the generation going forward. That would be number one. We absolutely believe that underutilized generation like our coal-to-gas units would be akin to incremental supply and be able to meet the need for data centers coming into the jurisdiction as a bridge to new generation that would be built into the 2030s to be able to meet that going forward because it isn’t just about reliability, sustainability and cost; speed matters.

And those units are the right units that we need. And it’s particularly so given the challenges associated with the supply chain. I mean, I think the practical reality is that getting a turbine, for example, or transformers is many years out. So I think they have a pretty critical role to get us from kind of where we are today to where we envision the market going. And so, that’s been what we’ve been advocating for. And I do think the government understands that position and candidly believes it has some merit.

Mark Jarvi: Just to follow up on that, John. When you talk about potentially a bridge, are you saying some of the underutilized megawatts would be something that could be viewed as — there for a couple of 3 to 5 years until new megawatts come in or potentially as “permanent supply” in the eyes of Phase 2 process?

John Kousinioris: Yes. I’m not sure that — at least we’re not thinking of it necessarily as permanent supply. So for example, if we have a unit and it has a 20% capacity factor, there is a lot of horsepower left in that particular unit to run and be able to supply incremental data center needs over a period of time. And so when we look at Keephills 2, Keephills 3, the Sheerness facilities that we have, Sun 6, and our ability to potentially bring something new to the market in the fullness of time into the 2030s, we absolutely see a bridging role during Phase 2 to get that there.

Operator: Our next question coming from the line of Benjamin Pham with BMO Capital Markets.

Benjamin Pham: I wanted to touch just base on the delay of your Investor Day. I can understand the reasons for it. I’m wondering, when you did set the Investor Day, you go back, was your priorities to get the MOUs on both of these projects? I vaguely recall it was more related to updating your long-term strategic capital allocation process. Or has that changed as time has progressed?

John Kousinioris: No. Ben, we set the date expecting that we would have had a bit more certainty or the ability to provide a little bit more clarity around both the data center strategy that we have going, some of the other initiatives that we’re working on, plus Centralia. It’s taken us a little bit more time to land those things. So we could have had the Investor Day, but the way we like to think of it, it wouldn’t have been the Investor Day that we would have wanted to have to permit all of our investors and the investment community generally to understand the impact of these projects on the company and be able to have all of the building blocks that are necessary to be able to understand kind of fully the go-forward strategy of the company.

So it’s really as simple as that. So we had picked a date we thought that prospectively — that, that would be something that we would be comfortable to be able to meet. We’re still working through everything and retain our confidence level. We just want to make sure we have a good Investor Day and one that will be helpful to our investors. So that’s what we’ve decided.

Benjamin Pham: Your comments on the connection queue and updates, I mean, those in-service dates you mentioned are always €“- tend to be conservative and that they move around. Does that warrant then perhaps for your projects to look at some outside dates just given that progress is a bit slower on some of your developments?

John Kousinioris: Yes. No, I think we feel pretty comfortable about where we are because what we’re looking — remember, it’s going to be a grid-connected opportunity, and then we will be effectively covering the generation needs that the entity has. So we feel very comfortable about our ability, from a power perspective, to meet the needs of the supply that we have for our customers, like I think we’re in good shape there. I think from our perspective, the time line is going to be driven more by the time it takes to actually build out the data centers and get that infrastructure in place. I think there’s a substation we need to put in place, but that’s something that we’re pretty comfortable from a supply chain and from a time line perspective to get it done. So we’re not — I can tell you that TransAlta today isn’t concerned about the kind of timing perspective from our data center opportunity.

Benjamin Pham: Just if I may, the 3,000 acres, I mean, I think that’s a massive amount of megawatts you can theoretically add on to that acreage.

John Kousinioris: It is — so I agree. It’s — like we see it as a significant opportunity. And we’re grateful for the engagement that we’ve received from Parkland County, who also see the opportunity for the county to have a real hub for data centers just West of the City of Edmonton there. So all the work that we’re doing, as I mentioned earlier in the call, isn’t just for the 230. It’s as we envision kind of the broader campus that we hope to develop over time.

Operator: Our next question coming from the line of Maurice Choy with RBC Capital Markets.

Maurice Choy: You touched on planning with your customers for phases beyond 230 megawatts. And you also spoke about [ AESO’s ] Phase 2 being critically important. If you think ahead between now and sometime in Q1 when you have your Investor Day, I guess, looking at the other way, what would be the top reason that could derail your time line to be even later?

John Kousinioris: Yes. Look, it’s difficult to be speculating. I mean, I think all I can say is — and look, all we can tell our investors is we continue to work, I would say, doggedly to set up our facility and the permitting around the opportunity that we have. So we don’t see, how can I put it, issues that could arise from a TransAlta perspective, from a timing perspective to get there. We’re working with our customers because they, in turn, have knock-on effects that they need to deal with to be able to land all of that and to be able to understand better kind of what the future pathways are. So we have confidence in Phase 2. We believe the government and the ISO is committed to the development of a data center industry here in the province of Alberta.

It is a priority. Our team is now with very senior people in the government, and we — there’s nothing I have heard that would suggest that that isn’t the case. So there isn’t particularly a derailer that I would see in us moving through, to be honest.

Maurice Choy: Maybe just a quick follow-up to that. Is there any regulation or policy, federal or provincial, that you need — you see as absolutely necessary for clarity for this MOU and definitive agreement to go forward?

John Kousinioris: It would be helpful from our perspective to kind of have a bit of a sense on where Phase 2 is going to be landing so that we can plan around that because I think we will be able to meet within that. It’s just it’s important to be able to get that done. The other area — and look, we’ve talked about this before, is the clean electricity regulations remain a bit of a challenge for us. We’re working hard to ensure that we have maximum optionality to be able to fit within those regulations as they currently exist to ensure that we can meet the promise of the opportunity that we see through the data center work. When our team is thinking about things, it’s more the CER, to be honest, that we think about long term as being something that we need to manage around. Phase 2 is more of a clarity point that we think will be constructive. Hopefully, that gives you a sense, Maurice.

Maurice Choy: It does. And maybe that’s exactly where I’m going to finish off with on the federal policy side. So obviously, the Canadian federal budget came out earlier this week. It doesn’t feel like we got much clarity on both the CER and/or the industrial carbon tax heading into 2030 or post-2030. I know that the Alberta government has frozen the carbon tax at $95 per tonne. But what can you share in terms of your expectations of both how the CER and the industrial carbon tax will be through 2030 and beyond?

John Kousinioris: Look, we — I’d be speculating. I can tell you that like when we do our internal modeling, we have a number of scenarios that we run as we assess our fleet, and it’s everything from the carbon price staying at $95 to the carbon price continuing on its anticipated trajectory towards 2030. What I can’t tell you is our engagement on the CER with the federal government continues. Our team was in conversations relating to that. I think it was last week in Ottawa, and I’m actually in discussions on it again later today. So it’s an ongoing process of discussion that we have.

Maurice Choy: Quick follow-up then. Who underwrites that risk of federal policy changes? Is that your data center customer, or would that be you? Or is that still under negotiation?

John Kousinioris: So that’s something that we’re working through with the customers. It’s not something that I can give sort of specific details on that. I think that what we try to do in mapping out the opportunity that we have is to ensure that it’s robust and candidly insulated from kind of regulatory uncertainty, to be honest, Maurice. Like, that’s actually what we’re trying to do. And in part, when you hear the company talking about being more contracted and how we’re diversifying, in part, it is driven to sort of insulate the company from any kind of regulatory shifts or repercussions that take place. And that’s actually the approach our team is taking with respect to the data center file. Candidly, it’s a similar approach in Centralia, I would say. Blain and his team are working on that. It’s the same thing there. It’s a real focus for us.

Maurice Choy: Perfect. My congrats to John, Joel, all of you, and hope to connect at the Investor Day.

John Kousinioris: Great. Thanks a lot, Maurice.

Operator: Our next question coming from the line of John Mould with TD Cowen.

John Mould: Maybe at the risk of going too in the weeds here, just trying to read the tea leaves a little more on these AESO in-service dates. So the Keephills load [indiscernible] as reported by AESO are 100 megawatts by January of 2027 and then another 115 midyear. Like how should investors view the time lines for your projects as provided by AESOs data? Are those timelines by which the load could actually be online or more of a timeline for those to be ready to connect to the grid from an AESO perspective? Just help us understand that aspect.

John Kousinioris: Yes. I mean, those dates are oriented to when we think that we would begin to be — like it’s tied to when the connection to the grid would occur and when the load would start ramping up. So they’re not linked, John, if you see what I’m saying. They’re tied. So we do see a gradual feathering in of load over time. And we would see — the work that we’re looking at doing, I mentioned the substation earlier, it would be a complete facility to be able to kind of accommodate the full ramping up of the generation over time. And remember, the ISO requires the load, I think, to be in place, I think it’s the 1st of December of ’28, right? So that’s what our current expectations are.

John Mould: I’d just like to clarify your comments on Phase 2. Do you or your customer need clarity on any aspects of Phase 2, even if it’s just like early details on bring your own power or allocations in order to finalize an agreement, in order to be able to have line of sight on some of that aspirational — maybe it’s not aspirational, just the potential multistage development that you referenced in your news release? And what time line are you hoping for more clarity to the market on the key aspects of Phase 2?

John Kousinioris: On the last point, it’s pretty clear to us that the AESO and the government are aware of the fact that having certainty sooner rather than later would be positive. So — I can’t give you a specific date on when we would get that, but I know that they’re trying to move at an appropriate pace to be able to give us that level of clarity. I’d say the #1 thing, at least from my own perspective, on Phase 2 is just getting a better understanding of what that bringing incremental power is all about and what role our legacy facilities where we do have capacity can bring in that context. That’s probably the #1 thing just from a planning perspective for us going forward. And we’re working to develop optionality so we can deal with that whichever way it goes. So that’s something that we continue to work on. And certainly, we’d be able to provide more clarity on at our Investor Day.

John Mould: Just one last one on just your hedging and midterm pricing. I’m wondering what kind of interest you’re seeing from C&I customers around signing mid- to long-term deals, just given the potential for the power pricing environment to normalize considerably over the next few years? And then from your side, how you’re balancing the potential for that increased appetite with your aspirations on supplying large loads?

John Kousinioris: Yes. Look, I might start and then get Blain to kind of chime in because it’s his team that kind of oversees all of that work. I’d say — and Blain, you can correct me, but I’d say it’s been pretty steady. Like, I’d say the C&I demand that we have — and I think we’re actually the largest C&I player now in the province of Alberta. The C&I book that we have from a renewal perspective, an incremental business, it kind of continues as business as usual. We continue to see our customers roll over. I think the average tenure, Blain, is roughly in that 3-year kind of range. We have seen some of the re-contracting prices come down a little bit, I would say, Blain, and Blain will be able to provide more color as they rolled off because some of them were done when we had higher power prices, and it kind of takes time for that to roll off, and so we’re seeing that.

But those prices are still constructive from our perspective. When you’re looking at kind of 2028 — late ’27, ’28, which is when we would expect to see kind of the forward curve in the merchant market to tighten up, we’re not — I don’t think that’s impacting a lot of the 1-year, 2-year, even 3-year renewals, Blain, right now, in terms of moving the needle. I mean, I don’t know what your perspectives are.

Blain Van Melle: John, that’s exactly right. The C&I business hasn’t really faltered even through the lower prices that we have right now. The re-contracting remains very robust. We continue to extract some good premiums over the financial market. And I would expect, as we move forward here and as some of this load does start to materialize already reflected in the forward price that that contracting levels will ramp up a little bit as the customers start to meet to plan for those power needs in later 2027, 2028, and 2029.

John Kousinioris: Yes.

John Mould: Congratulations to both Joel and John on the announcements.

Operator: Our next question coming from the line of Julien Dumoulin-Smith with Jefferies.

Julien Dumoulin-Smith: John, it’s been a real pleasure over the years. Joel, congrats. It’s been a pleasure to get to know you more recently, and big and exciting shoes to fill here given the data center opportunity. But back to the opportunity in here, speaking of which, I just want to understand a little bit more about the Greenlight situation and what got posted by AESO here. In as much as you all articulate clear confidence that there’s still an ability to have that project in service by ’27 or ’28, what was the purpose of this AESO update that was posted? I just want to understand what exactly transpired if there doesn’t seem to be necessarily a push in time line from your perspective? Just to clarify that because clearly, the market is pretty [ perturbed ] out there about this time line issue.

John Kousinioris: Yes. And look, we know that this came out, when was it, yesterday when the updated date was, I think, identified from people. I mean, I think that’s a question fundamentally for Kineticor, I think, more than TransAlta. But I can tell you, look, we’ve been in discussions with Kineticor and certainly have a view on what’s going on from a governmental perspective. Based on those discussions, they’re still driving for ’27, ’28. Not just them, but actually their customer too, is what our understanding is. I know that they have a bit of — in the area where — and this is not a secret particularly. In the area where they’re proposing to kind of set everything up, they’re working to make sure that there are no restrictions from a transmission perspective.

And I think one of the things that they’re looking at from a worst-case scenario is, if they need to do a bit of debottlenecking, what does that look like. But I don’t think that, that’s what they’re driving at and certainly not as the load would sort of be ramping in. So everything we have heard based on our engagements is we’re still tracking and they’re still tracking more importantly, forget about us, to that ’27, ’28. So hopefully, that gives you a little bit of color.

Julien Dumoulin-Smith: So there is some focus on a potential for a bit of debottlenecking to use your terms, but that doesn’t seem to be too substantive despite the statement technically on the website, from what you understand on the practicalities of transmission, seems like it’s a fairly minor issue.

John Kousinioris: Based on my understanding that, that 2030 date, and I don’t know how to describe it, it was almost like a worst-case kind of scenario in terms of where they are. It’s sort of an outside kind of date. And look, the idea through Phase 1 is that you would have had this thing done by the end of 2028. So like, it’s pretty clear that they’ve had some discussions to make sure that they’ve had full optionality around their opportunity. And candidly, we would be doing exactly the same thing. So like, I think, I can tell you, for our company’s perspective, we continue to operate and envision things being business as usual.

Julien Dumoulin-Smith: Excellent. Just a quick follow-up there. Just on Centralia. I know that’s been a bit of an ongoing question here, but you talked about end of the year here. What should we expect specifically by the end of the year in terms of the scope of that opportunity? And what are you tracking, as far as it stands here today, for what that should look like here, customer, scope of conversion, et cetera?

John Kousinioris: We would expect, by the end of the year, based on the work that we’ve done and how things are progressing with our teams — and I can tell you, our customer has been outstanding to work with. They’ve been a great partner to us in visioning the opportunity we have for us to provide the reliability services to them. So we would see a definitive agreement. That definitive agreement would be an omnibus agreement that would deal with the work that we would need to convert the facility from coal to natural gas. It would set out the revenue streams that we would — revenue tenure. It doesn’t contemplate that more agreements would be required. It would be the agreement. And we have done a reasonable amount of work, engineering, costing that I do expect we’d be able to share with the market on kind of what the scope of the work would be around Centralia in order to be able to get the work that we need done there, which is not just the coal-to-gas conversion, but also a little bit of life extension given that we’ve harvested the facility a little bit and even some controls work that we need to be able to do.

So it would be — I don’t know — I mean, Blain and his team are working on this one as well, a comprehensive arrangement, Blain, I would say. I don’t know if you want to add anything.

Blain Van Melle: No, I think that’s right, John. You said — in the next 6 week leading up to Christmas that we’ll have something to announce —

John Kousinioris: Yes.

Blain Van Melle: It would be like a true definitive agreement that spells out all the work that needs to happen over the next year as we approach bringing that facility back on line on natural gas.

John Kousinioris: That’s right.

Operator: Our next question coming from the line of Patrick Kenny with National Bank Financial.

Patrick Kenny: Congrats to John and Joel. Just maybe back on the rezoning at Sundance and Keephills just given the close proximity of the 2 sites. Wondering if you could just speak to how you might be thinking about integrating these 2 assets for a larger scale customer just in terms of sharing generation, transmission, even fiber and water licenses. And maybe how that might compare to your Sheerness site or perhaps give a competitive advantage over some other Phase 2 proponents.

John Kousinioris: Yes. I would say — thank you, Patrick, and good morning. What we did is — so 3,000 acres is a significant amount of land, and you know this, our mine is quite comprehensive up there, and it actually ranges on both sides of the highway, and Keephills is on the south side of the highway, which goes east-west there. The Sundance facility is on the north side of the highway. And so what we did is we took kind of a comprehensive approach from a rezoning perspective to be able to flex up from a scale perspective. Our initial view is that the site from a locational perspective would be proximate to our Keephills facility. In fact, just going through my memory, located south of our — immediately south of our Keephills facility, and that would be where we would be looking to build out the data center and the substation to deal with that.

I think, over time, as we look to optionality and opportunity around Sundance, there is opportunity for us to do that as well. But right now, it’s more around Keephills. We’ve got the water access that we need. We’ve got existing infrastructure that we need. The fiber is close at hand. So we’re not really seeing any impediments, but getting the rezoning done was critically important. And as I mentioned earlier, it was a really great process, a lot of engagement from our side and great receptivity from the folks in Parkland County, which we’re grateful to as they kind of see the vision of what this can provide.

Patrick Kenny: I guess with all these irons in the fire, and Joel, I’m sure, at Investor Day, you’ll be outlining a funding plan. But assuming the Centralia economics on the conversion come in as expected, perhaps you could talk to how the returns might rank here just in terms of Centralia versus supporting Phase 2 load growth in Alberta, or even compare it to M&A opportunities that you might be looking down in the U.S.?

Joel Hunter: Yes. I would say, Pat, when we look at Centralia, again, typical with any kind of legacy asset that you can extend the life of with, I would say, capital spending that’s a fraction of what it would cost for a new build that it would offer attractive risk-adjusted returns for us. But this is where we’ll provide more detail to you and the investor community at our upcoming Investor Day once we have definitive agreements in place, so we can talk about what that would look like from, as John mentioned, the cost perspective, what kind of the build multiple would be for that. But again, consistent with our strategy, this would be really attractive risk-adjusted returns for us, underpinned by long-term contract. This is kind of how we want to position ourselves going forward to increase the contractiveness of our portfolio.

And similarly, with any opportunities that we see in Phase 2, these would be underpinned, again, by long-term contracts with, hopefully, a very attractive risk-adjusted rates of return.

John Kousinioris: Maybe on the M&A side, Joel, I think we’ve seen a bit of a — not compression, I can’t think of the right word, but kind of a realignment — I mean, maybe talk a little bit about renewable and gas kind of opportunities we’re looking at.

Joel Hunter: Yes.

John Kousinioris: — because we haven’t talked about it much on the call, but we are actively looking at a number of acquisition opportunities.

Joel Hunter: Yes, there’s — yes, good point, John. There are a lot of opportunities out there, Pat, that we’re looking at, both on the renewables side and on the thermal side. I would say that we’re seeing really a convergence in multiples, if you will, where on thermal generation, depending on the location, depending on the contract profile, et cetera, that multiples are converging up toward probably the lower end of where we are seeing for renewables. So again, consistent with our strategy remain technology agnostic, remain focused on our 3 geographies for M&A opportunities, but it is very robust out there right now. For us, it’s just remaining really disciplined in how we allocate our capital here going forward.

John Kousinioris: Yes, very return focused, I would say.

Joel Hunter: Yes.

Operator: There are no further questions in the queue at this time. I would now like to turn the call back over to Stephanie for any closing remarks.

Stephanie Paris: Thank you, everyone. That concludes our call for today. If you have any further questions, please contact the TransAlta Investor Relations team.

Operator: This concludes today’s conference call. Thank you for participating. And you may now disconnect.