TransAlta Corp (TAC) 2025 Q3 法說會逐字稿

Good morning. My name is Livia, and I'll be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation 3rd quarter 2025 conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press 11 on your top one keypad. If you would like to withdraw your question, please press 11 again.

Thank you, Miss Ferris. You may begin your conference.

Thank you, Livia. Good morning, everyone. My name is Stephanie Perris, and I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta's 3rd quarter 2025 conference call. With me today are John Cousinnoris, President and Chief Executive Officer, Joel Hunter, EVP Finance and Chief Financial Officer, Blaine Van Mell, 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 qualifications set out here on slide 2, detailed further in our MD&A and incorporated in full for the purposes of today's call.

All amounts referenced are in CAD 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.

Thank you, Stephanie. Good morning, everyone, and thank you for joining our 3rd 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, Métis, 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 3rd 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 4th 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 continued 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 1st 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 one 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 2nd, 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's 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 AESO's 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's 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 AESO 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 $1500 per megawatt hour and eventually to $2000 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 rights.

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 Green Light's data center in-service date being pushed out to 2030.

Our understanding is that that is very much an outside date and that Kineticore 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.

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 30th, 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.

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 amid softer market conditions.

During the quarter, we generated $238 million of adjusted EBITDA, which was $77 million lower than the 3rd 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 $80 million 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 were 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 purchased 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.

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 were partially offset by lower current income tax expense and lower distributions paid to non-controlling 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 price 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, as the aforementioned adjusted EBITDA impacts are partially offset by lower expected current taxes and lower expected distributions to non-controlling 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.

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 are a safe and reliable operator with strong cash flows underpinned by our diversified hydro, wind, solar, and gas portfolio located across three 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. 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.

Thank you, John. Livia, would you please open the call for questions from the analysts?

(Operator Instructions) Robert Hope, Scotiabank.

Excellent. Okay, 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 color on what is driving this, as well as has your confidence in securing a project increased or decreased since the Q2 call?

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 two 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 confident—as 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.

I appreciate that. And then are you in discussions to serve other data center customers in Alberta on a shorter-term basis? You did mention Green Light. You do have confidence that it could be in service in 2027 or 2028. What gives you that confidence, and could you be supplying power to them in that time frame as well?

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, we'll be able to start seeing load come into our sites gradually, and probably a bit earlier than what Kineticore is currently anticipating. Hopefully that gives you a little bit of color.

Delionel Mark Harvey, CIBC.

Yeah, thanks. Good morning everyone, and congrats Joel and John. Not to get too far ahead of ourselves, but once you do have the MOU in place, what would be the sort of timeline when you think you can get to a binding agreement? And given the fact it's taken a bit longer to get to the MOU, does that shorten the window from MOU to final agreement?

Mark, good morning. Look, we would want to go pretty quickly, I would think, and we've already begun getting our team ready and internally prepared to move to definitive documentation. I can't give you a specific timeline on when that would occur, but certainly I'd be pushing our team to try to get it done as soon as possible. One of the key elements of the MOU is to have enough specificity and understanding of the arrangements between ourselves and our customers to make the definitive documentation easier to proceed. I think it will actually be quicker than it's taken to get the MOU done.

And then 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 through a joint venture on the data center? And the fact that it is multiple customers—how has that affected the timelines to reach the MOU?

Yeah, we are working with more than one customer who are working together to see the opportunity come through, and that's been the case throughout our engagement. 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.

Okay. On the last call, you indicated that you took the view that your underutilized coal-to-gas converted units are akin to incremental generation. When you think about phase two and you're trying to have those conversations with the AESO and the government, how have those progressed? Are you getting traction with that concept?

Yeah, I'm glad you asked about that. We have had discussions on phase two. Joel, Nancy, Blaine, and I have spent a fair bit of time on this as we move forward. Our company's position—which we sense is being well received by the government—is that we don't think co-location is necessary. We believe it would be better if there isn't a need to co-locate the data center with the generation going forward.

We absolutely believe that underutilized generation, like our coal-to-gas units, would be akin to incremental supply and 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, these units are the right ones to meet that need—especially given the challenges associated with the supply chain. Getting a turbine or transformers is many years out. So we think they have a critical role to get us from where we are today to where we envision the market going.

So just to follow up on that, John, when you talk about potentially a bridge, are you saying some of the underutilized megawatts could be viewed as available for a couple, three to five years until new megawatts come in, or potentially as "permanent supply" in the eyes of the phase two process?

Yeah, we're not necessarily thinking of it as permanent supply. For example, if we have a unit with a 20% capacity factor, there's a lot of horsepower left in that unit to run and supply incremental data center needs over a period of time. When we look at Keephills 2, Keephills 3, the Sheerness facilities, 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 two to get us there.

Benjamin Pham, BMO Capital Markets.

Hi, thanks. Good morning. I wanted to just touch 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 date—was your priority 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. Has that changed as time has progressed?

No, when we set the date, we expected that we would have had a bit more certainty or the ability to provide more clarity around both the data center strategy and some of the other initiatives we're working on, plus Centralia. It's taken us a bit more time to land those things. We could have had the investor day, but it wouldn't have been the investor day we wanted to have—one that would permit all of our investors and the investment community to understand the impact of these projects on the company and have all the building blocks necessary to fully understand the go-forward strategy. So it's really as simple as that. We picked a date we thought we could meet, we're still working through everything, and we retain our confidence level. We just want to make sure we have a good investor day—one that will be helpful to our investors.

Okay, got it. And your comments on the connection queue and updates—those in-service dates you mentioned always tend to be conservative and 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 the developments?

Yeah, no, I think we feel pretty comfortable about where we are, because what we're looking at—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. I think we're in good shape there. From our perspective, the timeline 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 we're pretty comfortable with from a supply chain and timeline perspective to get done. So I can tell you that TransAlta today isn't concerned about the timing perspective from our data center opportunity.

Okay, and just a step for me if I may—the 3,000 acres, I mean, I think that's a massive amount of megawatts you can theoretically add onto that acreage.

It is. I agree. We see it as a significant opportunity, and we're grateful for the engagement 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. All the work that we're doing, as I mentioned earlier in the call, isn't just for the 230 megawatts. It's as we envision the broader campus that we hope to develop over time.

Maurice Choy, RBC Capital Markets.

Thank you and good morning, everyone. You touched on planning with your customers for phases beyond 230 megawatts, and you also spoke about AESO phase two being critically important. If you think ahead between now and sometime in Q1 when you have your investor day, looking at it the other way—what would be the top reason that could derail your timeline to be even later?

Yeah, look, it's difficult to speculate. All I can say is—and all we can tell our investors—is we continue to work doggedly to set up our facility and the permitting around the opportunity that we have. So we don't see 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 they need to deal with to be able to land all of that and better understand what the future pathways are. We have confidence in phase two. We believe the government and the ISO are committed to the development of a data center industry here in the province of Alberta. It is a priority. Our team has met with very senior people in the government, and there's nothing I have heard that would suggest otherwise. So there isn't particularly a derailer that I would see in us moving through to the first half.

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

It would be helpful, from our perspective, to have a bit of a sense on where phase two is going to land so that we can plan around that. We think we will be able to meet within that, but it's important to get that done. The other area—and we've talked about this before—is the Clean Electricity Regulations (CER), which remain a bit of a challenge for us. We're working hard to ensure that we have maximum optionality to fit within those regulations as they currently exist, to ensure that we can meet the promise of the opportunity 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 something we need to manage around. Phase two is more of a clarity point that we think will be constructive. Hopefully that gives you a sense, Maurice.

It does, and maybe that's exactly where I'm going to finish off—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 the industrial carbon tax heading into 2030 or post-2030. I know that the Alberta government has frozen the carbon tax at $95 per ton, 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?

I'd be speculating. What I can tell you is that when we do our internal modeling, we run a number of scenarios as we assess our fleet. It's everything from the carbon price staying at $95 to the carbon price continuing on its anticipated trajectory toward 2030. 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.

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?

That's something we're working through with the customers. It's not something I can give specific details on. What we try to do in mapping out the opportunity is to ensure that it's robust and candidly insulated from regulatory uncertainty. That's actually what we're trying to do. In part, when you hear the company talking about being more contracted and how we're diversifying, it is driven by the goal to insulate the company from any kind of regulatory shifts or repercussions. That's the approach our team is taking with respect to the data center file. Candidly, it's a similar approach in Centralia. Blaine and his team are working on that. It's the same thing there. It's a real focus for us.

John Multwood.

Hi, good morning everybody. 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 IFCs as reported by AESO are 100 megawatts by January 2027 and then another 115 mid-year. How should investors view the timelines for your projects as provided by AESO 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? Help us understand that aspect.

Yeah, I mean those dates are oriented to when we think that we would begin to connect to the grid and when the load would start ramping up. So they’re not disconnected, John, if you see what I’m saying—they’re tied. We do see a gradual feathering in of load over time. The work that we’re looking at doing—I mentioned the substation earlier—would be a complete facility to accommodate the full ramping up of the generation over time.

And remember, the AESO requires the load to be in place by December 1st, 2028. So that’s what our current expectations are.

Okay, and then just to clarify your comments on phase two—do you or your customer need clarity on any aspects of phase two, even if it’s just early details on “bring your own power” or allocations, in order to finalize an agreement and have line of sight on some of that potential multi-stage development you referenced in your news release? What timeline are you hoping for more clarity on the key aspects of phase two?

On the last point, it’s pretty clear to us that the AESO and the government are aware that having certainty sooner rather than later would be positive. I can’t give you a specific date on when we would get that, but I know they’re trying to move at an appropriate pace to give us that level of clarity.

I’d say the number one thing, at least from my own perspective on phase two, is getting a better understanding of what “bringing incremental power” is all about and what role our legacy facilities—where we do have capacity—can play in that context. That’s probably the number one thing from a planning perspective for us going forward. We’re working to develop optionality so we can deal with that whichever way it goes. That’s something we continue to work on, and we’ll certainly be able to provide more clarity on it at our investor day.

Okay, thanks for that. And maybe just one last one on 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, given the potential for the power pricing environment to normalize considerably over the next few years. And from your side, how are you balancing the potential for that increased appetite with your aspirations on supplying large loads?

Yeah, I might start and then get Blaine to chime in, because it’s his team that oversees all of that work. I’d say—and Blaine, you can correct me—but I’d say it’s been pretty steady. 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 book that we have from a renewal perspective and incremental business continues as business as usual. We continue to see our customers roll over. I think the average tenor, Blaine, is roughly in that three-year range.

We have seen some of the recontracting prices come down a little bit, as some of them were done when we had higher power prices, and it takes time for that to roll off. We’re seeing that, but those prices are still constructive from our perspective. When you’re looking at 2028 or late 2027–2028, which is when we expect to see the forward curve in the merchant market tighten up, I don’t think that’s impacting a lot of the one-year, two-year, even three-year renewals right now in terms of moving the needle.

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

Thank you very much for all that color. I’ll leave it there. Congratulations to both Joel and John on the announcements.

Thanks so much, John. Thanks, John.

Julien Dumoulin-Smith, Jefferies.

Hey, good morning, team. 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. Speaking of which, I just want to understand a little bit more about the Green Light situation and what got posted by AESO. Inasmuch as you all articulate clear confidence that there’s still an ability to have that project in service by 2027 or 2028, what was the purpose of this AESO update that was posted? I just want to understand what exactly transpired, because there doesn’t seem to be necessarily a push in timeline from your perspective. Just to clarify that, because clearly the market’s pretty perturbed out there about this timeline issue.

Yeah, and look, we know this came out—when was it—yesterday, when the updated date was identified by people. I think that’s a question fundamentally for Kineticore more than TransAlta. But I can tell you, we’ve been in discussions with Kineticore and certainly have a view on what’s going on from a governmental perspective. Based on those discussions, they’re still driving for 2027–2028—not just them, but actually their customer too, is what our understanding is.

I know that in the area where they’re proposing to set everything up, they’re working to make sure there are no restrictions from a transmission perspective. One of the things they’re looking at from a worst-case scenario is if they needed to do a bit of bottlenecking, what does that look like? But I don’t think that’s what they’re driving at, and certainly not as the load would be ramping in. So everything we’ve heard based on our engagements is we’re still tracking—and they’re still tracking, more importantly—to that 2027–2028 timeline. Hopefully that gives you a little bit of color.

Got it. So there is some focus on the potential for a bit of a bottleneck, 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 the transmission, it seems like it's a fairly minor issue.

Based on my understanding, that 2030 date—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 one is that you would have had this thing done by the end of 2028. So it's pretty clear that they've had some discussions to make sure they have full optionality around their opportunity, and candidly, we would be doing exactly the same thing. So I can tell you from our company's perspective, we continue to operate and envision things being business as usual.

Excellent. All right, thank you for the clarification there. I appreciate it. And just a quick follow-up on Centralia. I know that's been a bit of an ongoing question. You talk about the end of the year—what should we expect specifically by then in terms of the scope of that opportunity? What are you tracking as far as it stands today for what that should look like—customer, scope of conversion, etc.?

We would expect, by the end of the year, based on the work 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 envisioning the opportunity we have to provide reliability services to them—we would see a definitive agreement. That definitive agreement would be an omnibus agreement that would deal with the work needed to convert the facility from coal to natural gas. It would set out the revenue streams and revenue tenor. It doesn’t contemplate that more agreements would be required—it would be the agreement.

We've done a reasonable amount of engineering and costing work that I expect we'd be able to share with the market on the scope of the work around Centralia. That includes not just the coal-to-gas conversion but also a bit of life extension, given that we've harvested the facility a little bit, and even some controls work that we need to do. So it would be—I don't know, Blaine and his team are working on this—a comprehensive arrangement. Blaine, I don’t know if you want to add anything.

No, I think that’s right. And like you said, we do expect in the next six weeks leading up to Christmas that we’ll have something to announce—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 online on natural gas.

Patrick Kenny, National Bank Financial.

Thank you. Good morning, everyone, and yeah, congrats John and Joel. Just maybe back on the rezoning at Sundance and Keephills—given the close proximity of the two sites, wondering if you could speak to how you might be thinking about integrating these two 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 other phase two proponents.

Thank you, Patrick, and good morning. What we did—3,000 acres is a significant amount of land—and our mine is quite comprehensive up there. It actually ranges on both sides of the highway. Keephills is on the south side of the highway, which runs east-west, and the Sundance facility is on the north side. So we took 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, going from memory, it's located immediately south of our Keephills facility, and that’s where we’d be looking to build out the data center and the substation. 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 we need, we’ve got existing infrastructure, the fiber is close at hand, so we’re not seeing any impediments. Getting the rezoning done was critically important, and as I mentioned earlier, it was a great process with a lot of engagement from our side and great receptivity from the folks in Parkland County, which we’re grateful for as they see the vision of what this can provide.

Okay, and then I guess with all these irons in the fire—Joel, I’m sure at investor day you’ll outline a funding plan—but assuming the Centralia economics on the conversion come in as expected, perhaps you could talk about how the returns might rank here in terms of Centralia versus supporting phase two load growth in Alberta, or even compared to M&A opportunities you might be looking at in the U.S.

Yeah, 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 capital spending that’s a fraction of what it would cost for a new build—it would offer attractive risk-adjusted returns for us. 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 a cost perspective and what kind of build multiple that would be.

But again, consistent with our strategy, this would be really attractive risk-adjusted returns for us, underpinned by a long-term contract. This is how we want to position ourselves going forward—to increase the contractedness of our portfolio. Similarly, with any opportunities we see in phase two, these would be underpinned again by long-term contracts with hopefully very attractive risk-adjusted rates of return.

And 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. Maybe talk a little bit about renewable and gas opportunities that we're looking at, because we haven't talked about it much on the call, but we are actively looking at a number of acquisition opportunities.

Yeah, good point, John. There are a lot of opportunities out there, Pat, that we're looking at—both on the renewable side and on the thermal side. I would say that we're seeing really a convergence in multiples, if you will, where on thermal, depending on the location, contract profile, etc., the multiples are converging up toward the lower end of where we are seeing for renewables. So again, consistent with our strategy, we remain technology agnostic and focused on our three geographies for M&A opportunities. It is very robust out there right now. For us, it's just about remaining really disciplined in how we allocate our capital.

Going forward. Yeah, very return-focused, I would say.

Okay, that's great. I appreciate the color, and yeah, I look forward to more details in the new year. Thanks.

Thanks, Pat. Thanks, Pat.

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

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

This concludes today's conference call. Thank you for participating, and you may now disconnect.