TAC

Good morning. My name is Shannon, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation First Quarter 2026 Results 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 star one one on your telephone keypad. If you would like to withdraw your question, please press the star followed by one one again. Thank you. Ms. Paris, you may begin your conference.

Thank you, Shannon. Good morning, everyone. My name is Stephanie Paris. I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta's first quarter 2026 conference call. With me today are Joel Hunter, President and Chief Executive Officer, Mike Politeski, EVP Finance and Chief Financial Officer, Chris Fralick, EVP Generation, Nancy Brennan, EVP Legal and External Affairs. Today's call is being webcast. 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 made available later today. The transcript will be posted to our website shortly thereafter. All information provided during this conference call is subject to the forward-looking statement qualification set out here on slide two, 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 noted otherwise. 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, 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 Joel.

Thanks, Stephanie. Good morning, everyone, and thank you for joining our first quarter conference call. TransAlta delivered solid operational performance during the first quarter of 2026. During the quarter, we delivered adjusted EBITDA of CAD 204 million, Free cash flow of CAD 102 million, or CAD 0.34 per share, and average Fleet availability of 93.8%. While our Alberta merchant portfolio was impacted by softer than expected prices, our hedging strategy and active asset opti-optimization generated realized prices that were well above spot prices during the quarter. We remain confident in achieving our 2026 guidance range. In the quarter, we advanced our data center strategy in Alberta and coal to gas conversion at Centralia, hosted our Investor Day, providing an overview of our strategy and context on the current and future operating environment.

We closed the acquisition of Far North Power Corporation, adding contracted generation in our core market of Ontario. In connection with our fourth quarter and year-end 2025 results, we announced an MOU with CPP Investments in Brookfield for data center development in Alberta, with TransAlta as the exclusive power and site provider. We continue to be actively engaged with our counterparties. We are making progress towards definitive agreements. Last month, the AESO released an updated draft process for Phase 2A of their large load integration. It is important to note that this is draft, which does not represent final outcomes and will continue to evolve as discussions progress. TransAlta continues to participate in the AESO's Large Load Integration Working Group, and we look forward to hearing additional details as they finalize their process in the coming months.

In March, the U.S. Department of Energy issued another temporary order requiring Centralia Unit Two to remain available for operation if needed for a 90-day period ending on June 14th. TransAlta is adhering to the order and recently submitted its request for reimbursement to the FERC for costs related to the initial order. Progress continues with the conversion, and I'm pleased to report that our timeline for a final investment decision in the first quarter of 2027 remains on schedule. In the quarter, we achieved adjusted EBITDA of CAD 204 million, a decrease of CAD 66 million compared to the first quarter of 2025. This was primarily due to the reduction of generation at Centralia, lower Alberta power and hedge prices, as well as reduced market volatility, which affected energy marketing performance.

Hydro segment adjusted EBITDA was CAD 35 million, down CAD 12 million compared to the first quarter of 2025 due to lower Alberta spot hedge and hedge power prices, lower ancillary services, reduced merchant volumes, and fewer emissions credit sales to third parties. The wind and solar segment reported adjusted EBIT of CAD 95 million, a 7% decrease compared to the first quarter of 2025, mainly due to lower wind resource and availability in Eastern Canada. Within the gas segment, adjusted EBITDA was CAD 93 million, CAD 11 million lower than first quarter of 2025, primarily due to lower Alberta spot and hedged power prices and the retirement of the Ada cogeneration facility. These impacts were partially mitigated by higher realized prices on Ontario and the acquisition of Far North Power. The energy transition segment experienced a year-over-year decrease in adjusted EBITDA of CAD 36 million.

Adjusted EBITDA is anticipated to remain neutral or slightly negative within the segment, primarily due to ongoing expenses associated with retired units in both Alberta and Washington State. These costs are partially mitigated through revenues from byproduct sales. energy marketing adjusted EBITDA decreased by CAD 4 million-CAD 17 million, primarily due to higher incentive costs and realized and associated with higher unrealized mark-to-market gains. Corporate costs of CAD 37 million were 10% lower when compared to the first quarter of 2025. In the first quarter, free cash flow totaled CAD 102 million, driven by reduced net interest expense and increased realized foreign exchange gains from operating activities.

Overall, despite low Alberta spot power prices, we are pleased with our first quarter operational performance across all of our business segments and remain confident in our ability to meet our 2026 guidance range. Turning to the Alberta portfolio, spot prices averaged CAD 32 per MWh in the first quarter, which was notably lower than the average price of CAD 40 per MWh in the first quarter of 2025. The decline year-over-year was primarily due to a mild winter in addition of new gas generation in the market. The gas fleet exceeded merchant market pricing by realizing average price of CAD 48 per MWh, a 50% premium to the average spot price of CAD 32 per MWh.

The hydro fleet also continued to capture merchant upside, delivering an average realized price of CAD 46 per MWh, a 44% premium to the average spot price. The merchant wind fleet realized an average price of CAD 20 per MWh, which was impacted by increased intermittent wind and solar generation in the overall Alberta merchant power market. Although weather conditions during the quarter were generally mild, contributing to lower average power prices, we enhanced our margins by meeting portions of our higher price hedge commitments through power purchases when market prices were below our variable production costs. We benefited from approximately 2,400 gigawatt-hours of hedges, an average price of CAD 66 per MWh, CAD 34 per MWh higher than the average spot price.

During the quarter, we delivered approximately 1,000 GWh of ancillary service volumes at a modest 9% discount to the average spot price. Through effective fleet optimization and meeting hedge obligations with purchased power, we consistently address the AESO's demand for reliability products. Looking at the balance of the year, we have approximately 6,900 gigawatt-hours of Alberta generation hedged at an average price of CAD 64 per MWh, well above the current forward curve of CAD 41 per MWh. Going forward, we'll 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. For 2027, we currently have approximately 5,500 GWh hedged at an average price of CAD 65 per MWh, well above current forward pricing levels.

As discussed at Investor Day on March 23rd, we continue to expect anticipated increase in load will rebalance the current oversupply of generation Alberta later this decade and drive opportunities for growth in the long term. Last month, we announced the addition of two new executives to our leadership team. I'm pleased to welcome Mike Politeski to TransAlta as he takes on the role of Executive Vice President and Chief Financial Officer. Mike brings over 25 years of experience in the energy sector. Over the course of his career, he has played a significant role in large-scale transactions and business transformation and brings deep experience in investor relations, governance, and capital allocation. His established reputation as a strong, collaborative leader will be important as we pursue our strategic objectives. I'm also pleased to welcome Grant Arnold as our Executive Vice President, Growth and Chief Commercial Officer.

Grant brings over 30 years of leadership, commercial and technical experience in the power generation and energy sector. He has contributed and led prior companies through significant growth, expanding their operating and development portfolios across North America. I'm confident Mike and Grant will strengthen TransAlta's high-caliber leadership team, where together we will execute our strategy focused on disciplined growth and operational excellence. I'll now turn the call over to Mike to offer a few words as he steps into the role.

Thanks, Joel. I've been impressed by what TransAlta has built, an operationally strong business with a clear strategy and meaningful opportunity set ahead. I'm grateful for the warm welcome I've received externally as well as inside the organization, and I'm looking forward to working with all of you as we deliver on our strategy. My focus will be straightforward. I plan to continue to strengthen our financial position and support the execution of our strategic priorities. We will operate with excellence, grow with discipline, and maximize value for our shareholders, all while ensuring we maintain our financial strength and flexibility through disciplined cost and capital management. I'll now turn the call back over to Joel.

Thanks, Mike. For 2026, we remain focused on the following priorities: Improving our leading and lagging safety performance indicators while achieving strong fleet availability, delivering adjusted EBITDA and Free cash flow within our 2026 guidance ranges, maximizing the value of our legacy thermal sites by advancing our Alberta data center project, as well as advancing our coal-to-gas conversion at Centralia toward a final investment decision, pursuing strategic M&A opportunities, and enhancing our financial strength and flexibility through disciplined capital allocation and cost control. Stepping in as CEO, I believe TransAlta offers a compelling investment opportunity. We operate a safe and reliable fleet that generates strong and consistent cash flows. That strength is grounded in a diversified portfolio of hydro, wind, solar, and thermal assets across three countries, and it's enhanced by our industry-leading asset optimization and energy marketing capabilities. Our legacy thermal sites continue to represent considerable and increasing value.

We are proactively pursuing repurposing opportunities at these facilities to address the growing demand for dependable power in our operating markets. Concurrently, we maintain a leadership position across multiple technologies, consistently prioritizing responsible and reliable generation. We are disciplined in how we grow. Our priority is creating value for our shareholders as we diversify our portfolio within our core geographies and continue to increase the stability and contracted nature of our cash flows. This strategy is supported by a strong financial foundation. We have a flexible balance sheet and ample liquidity, giving us the ability to pursue and deliver multiple growth opportunities while continuing to return capital to shareholders. Finally, and most importantly, we have our people. Everything we achieve is powered by the dedication and expertise of our employees and contractors.

I want to thank them for their commitment and for positioning TransAlta for continued success in 2026 and beyond. Thank you. I'll now turn the call back over to Stephanie.

Thank you, Joel. Shannon, would you please open the call for questions from the analysts?

Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster.

Our first question comes from the line of Robert Hope with Scotiabank. Your line is now open.

Morning, everyone. Maybe to start off with. I know it's early days, can you give us any sense or color on how the Brookfield MOU for the data center in Alberta is progressing, whether that be for the initial or the subsequent phases?

Yeah, Robert. Joel here. You know, we made significant progress, as we announced back at the end of February, signing the MOU with Brookfield and CPPI. I would say to you that this wasn't your kind of boilerplate MOU. It's quite comprehensive, including reaching agreement on a lot of the commercial terms. We are now in the process of the definitive agreements, and that remains very active between ourselves, CPPI and Brookfield. Can't give you a definitive timeline on that other than it is progressing as planned, and it is a very collaborative effort between both ourselves and Brookfield and CPPI.

All right. Appreciate that. Then maybe moving over to the M&A market, it is highlighted as a, you know, a strategic opportunity for 2026. Can you comment on, you know, how the market is progressing, whether you're seeing a good amount of deal flows and kind of what opportunities look the best at this moment?

Rob, I would say that there is certainly a lot of deal flow. We are constantly looking at opportunities really within our core geographies. When we look at to Canada, for example, you know, most recently just announced the acquisition of Far North Power Corporation. We're seeing opportunities here and in the U.S., in particular in the WECC. It's across all technologies, whether it's thermal, wind, solar. It is quite competitive, we have to remain very disciplined in how we approach M&A. You know, we kind of look at it through the lens. It has to be accretive to our, you know, cash flow per share. It can't harm the balance sheet, we have to, you know, preserve our balance sheet strength going forward.

I would say it has to be in strategy, and it has to be highly contracted. You know, one of our objectives here as we look at M&A or any capital allocation that we're doing, Rob, that we want to increase our contractiveness over time. It is critically important that when we look at opportunities, that it comes with a, you know, a strong contract profile or at least a pathway to recontracting in the future. I would say to you overall, it's a very robust market. It is very competitive, and we just remain very disciplined in how we approach these M&A opportunities.

Sounds great. Appreciate the color. Thank you.

Thanks, Rob.

Thank you. Our next question comes from the line of Mark Jarvi with CIBC. Your line is now open.

Yeah, thanks. Good morning, everyone. Joel, just with the additions to the management team, is there anything else you'd like to add to the team? I guess below Mike and the additions there, is there sort of a filling of the bench that is required over the next couple of quarters?

Mark, I would say that we've really landed our management team here with the addition of Mike and Grant. We also have on our, on our Senior Management Team here, Chris Fralick and Nancy Brennan are here with me today, along with Jane N. Fedoretz, who's our Head of our Chief Administrative Officer, and Mark Flickinger, who's our Head of Major Construction Projects. We have the right team in place. What we see below the team at our Vice President level is very strong, a very deep bench here that really kind of excites me as we look to execute on our strategy here going forward. Very comfortable where we're at, Mark, here with our executive team, along with the rest of our employees.

Whether it's from VPs right down to, you know, people, you know, in the field, wherever, they're it's a very, very strong team of people that we have in our organization. It goes to my closing remarks that if it wasn't for our people, we wouldn't be able to execute day-to-day, you know, safely and efficiently with our operations or execute on our strategy.

Okay. You know, with them settling in their seats, does that, does that potentially push out any sort of M&A timelines, you know, out a few more quarters? Just curious on how Mike and Grant coming in the fold in the midst of the data center definitive, uh, agreements coming together, whether or not they see something or terms or anything like that that could potentially just push out the timeline before you get to definitive agreements, just given the fact they've just come on board with the company?

Yeah, Mark. To answer your first question with respect to M&A, no, it's actually very active. Again, we have a strong team that actually reports into Grant that with respect to M&A and kind of corporate development that they're very active right now. That's certainly not gonna slow down things at all as it relates to M&A. Similarly, with the data center file as well, the teams that are really responsible for delivering that report into Grant. Grant's, even though he starts today, is, you know, actively engaged with the team here. We certainly don't see any slowdown here with that given the progress that we have made to date, both with the MOU with CPPI and Brookfield.

It certainly helps having two, kind of executives like Mike and Grant to come in and really support where we need to go, with executing on these major initiatives, but it's certainly not slowing us down.

That's good to hear. The last question from me is just, you brought up the draft, the phase IIA. Curious in terms of your updated discussions around some bridging solutions. We heard one of your peers talk about the view that they think there's still excess supply from supply in the market with existing generation, and it can avoid costly grid upgrade charges. Where are you in the conversations around maybe being able to use your fleet a bit more in terms of going beyond the 1.2 GW in phase I?

Yeah, Mark, it's certainly there's active dialogue between ourselves, the AESO and the government. Nothing has changed from what we highlighted at Investor Day on March 23rd. As we look at our, you know, coal to gas units here in Alberta, which is roughly 2.7 GW of installed capacity that last year ran at around a 20% capacity factor. We point to those units to say there is surplus capacity there that could be used as, you know, call it like almost like a bridge, if you will, for phase II to new generation in the future. I think that's acknowledged that, you know, all levels, that there is the spare capacity.

I think, you know, what we're trying to get to here is a win-win situation where we can bring in a data center customer, meet their needs by using a portion of that surplus capacity that's there with our coal to gas units. At the same time, ensuring reliability and affordability for the grid here in Alberta. Very active dialogue. We know that the AESO wants to get it right. We understand that, you know, they are concerned about reliability in the province, but they also are, you know, they see the real opportunity here for data centers to come to the province. Active dialogue, as you can well imagine here, we remain optimistic, you know, using our coal to gas fleet here, going forward beyond phase I.

Would there be an expectation that you'd make some other commitments if you're gonna use the existing generation to facilitate incremental load, whether it's a commitment to bring on new generation down the road, dispatch conditions on the existing fleet? Would there be sort of something, I'm not saying concession per se, but some sort of measures you think they'd be required to facilitate the more usage of the existing assets?

I would just say to you, Mark, that, you know, those are things that we do, when we do have discussions that we do bring up here. We're trying to find, you know, a solution here, where we see that there's, again, this surplus capacity and how best to utilize it, to ensure that we, you know, improve the reliability, if you will, of the grid. I think it's safe to say, though, that, you know, especially with the MOU between Alberta and the federal government and the CER, going away, that when we think about data centers here in Alberta, this is a long-term investment opportunity, for both the data centers and for ourselves. When I look at our existing fleet, they're not gonna be around forever.

If we can get data centers here in Alberta, then, you know, in all likelihood, you know, we would look to deploy more capital in the province to support the needs of that, of that load longer term. Again, we remain encouraged by, you know, again, what we're seeing from a policy standpoint. We remain encouraged with our discussions with our customers here that, you know, we're taking a very long-term view and, you know, ultimately, if we could get to a point where we are building, you know, new facilities here, it would be underpinned obviously by a long-term contract with our customers if we got to that point.

Okay. Makes sense. Thanks for the time this morning.

Thanks.

Our next question comes from the line of Benjamin Pham with BMO. Your line is now open.

Hey, morning. First off, congratulations to Mike and Grant on their appointments. I wanted to go back to the timing of the Alberta MoU. I wanted to clarify, is TransAlta still sticking with that expectation for definitive agreements by end of year?

Yes, Ben. That's we're working toward. Again, things are well advanced. As I mentioned earlier, Ben, the MoU was a large part of that. There was a lot of work behind that that really started last year and ended with us signing the MoU at the end of February. We are now again working toward various definitive agreements. You know, our expectation is it's gonna be in year. Just can't give you a definitive time around that, but it's certainly something that is a top priority for us and I believe for our counterparties as well.

Okay. Sounds good. I wanted to ask too next on your MD&A package. You've broken up your development pipeline between mid stage and early stage. I can see the mid stage one includes most of the Centralia conversion. I think that's what's in there. Can you unpack the thermal more for us? There's, what, 1.9 GW. Is that mostly the Alberta redevelopment sites in there?

There is that there. You know, we highlighted, you know, three sites in Alberta here with Keephills Unit 1, SunHills and Flippy. That's part of it. We are, you know, exploring opportunities south of the border as well, in Wyoming and Arizona. Again, you know, early days on that, but our corporate development team is looking for thermal opportunities there that would be considered greenfield. You know, the key here is with the team, and we talked about this last year when we outsourced really our renewables development to NovaClean, that the focus internally here for our team at TransAlta has been more on thermal here in Alberta and south of the border.

We have some opportunities as well in Western Australia that we're looking at.

Okay. Very good. Thank you.

Thanks, Ben.

As a reminder, to ask a question at this time, please press star one one on your touchtone telephone. Our next question comes from the line of Maurice Choy with RBC Capital Markets. Your line is now open.

Thank you. Good morning, everyone. If I could just start with something that Joel, you mentioned on the press release, specifically about how near-term headwinds in Alberta are materializing. I wonder if you could just elaborate a little bit on that and what you meant on that.

Maurice, and good morning. What we meant by that is if you look at again our first quarter results, that the average spot price being CAD 32 per MWh. What we experienced in the first quarter here in Alberta and really in the West, if you will, taking into consideration even the Mid-C market, is there was really no weather. It was very mild, very benign. As a result, we didn't really see really any spikes in pricing that we normally would experience kind of in the winter in those markets. That, really put, you know, pressure obviously on our results here in Alberta for the first quarter. That's really the headwinds that, you know, we experienced.

When you look, you know, for the balance of the year, as mentioned in my prepared remarks, you know, the forward rate now. Forwards are right around CAD 41, kind of still within our range, at the lower end of our range, if you will, in the guidance that we provided at CAD 40-CAD 60 per MWh for the year. What gives us confidence though, Maurice, right now is a couple things. One, obviously our hedges, hedged at CAD 64, here, for the balance of the year, which is very good. Also we just, you know, look forward that there could be a weather event.

You know, the important thing here, Maurice, is that our fleet is available so that when that does happen, that we can flex up the portfolio very quickly to respond, to the, those, these times in the market when it tightens up and pricing does spike. So you know, again, we're confident still in our outlook for the year, despite the challenges that we faced in the first quarter. I was very pleased, though, that we generated very strong free cash flow in the quarter of CAD 102 million. Again, you know, we remain, you know, convinced that, you know, our guidance for the year is in line with the midpoint that we talked about at CAD 1 billion of EBITDA and CAD 400 million of free cash flow.

That's great. Maybe as a quick follow-up, since you discussed forward curves. I recall that in the past when we start thinking about 2028 and beyond, you know, there's discussion about whether or not the forward curves are truly representative of what you think is gonna occur. Could you just, you know, share your thoughts of whether or not what you think about where the forwards are for those years, if you think that that's right or could go up?

Yeah, you know, Maurice Choy, I think it's very similar to what we discussed at Investor Day, that the forward curve today when you look out to 2028 and 2029 is not reflected to what we believe. I think what we pointed to at Investor Day is that between now and 2025, we see here in Alberta just over a gigawatt of net change in load. Due in large part obviously to phase I, being 1.2 GW of load in the province, along with just normal demand growth over this period of time of roughly 600 megawatts. There's some incremental supply that would come, as we highlighted at Investor Day, including, you know, potential unit upgrades at other facilities that obviously are not owned by TransAlta.

Potentially, a restoration of the intertie. That when you combine it all together, you know, we see that again, as mentioned, this net load increase of about 1.1 GW. When we put that through the models, that would, you know, translate to, you know, power prices or forward prices in that kind of north of CAD 85. I think what we used at Investor Day was roughly CAD 100 MWh by 2029. Nothing has changed with that. You know, given that we do see the market, you know, kind of tightening up here over the next four years or five years, with not a lot by way of new supply coming.

Thank you. Just to finish off on the carbon tax policy, it feels like maybe we're approaching a point where we're gonna hear something. Just curious whether or not, you know, what, A, what have you been hearing on that? B, how much of the MOU that you have in front of you is highly dependent on this carbon tax outcome?

Yeah, I would say to you, again, you know as much as we do right now with respect to the MoU and kind of that glide path on the carbon tax, which recall in the MoU would be up to CAD 130 per tonne. You know, I think the question is, you know, what's the time to get to there? You know, that's the discussion obviously between the Alberta government and the federal government there. You know, nothing has really changed for us. I mean, it's, we know, we look at the MOU, it's directionally positive, I think, for the energy industry overall, here in Alberta. We are, we're awaiting the final outcomes of that like everyone else.

You know, nothing has changed with respect to how we're thinking about things here in Alberta, or in Canada in general, today versus where we were even a month ago.

Is that a gating item for your MOU?

No. I don't believe so.

Understood. Thanks for that. Congratulations again to both of you, Joel and Mike, on your new positions.

Thank you.

Thanks, Ben.

No worries.

Our next question comes from the line of John Mould with TD Cowen. Your line is now open.

Hey, morning, everybody. I'd really just like to focus on your hedge update. You've added a meaningful volume of hedges for 2027 relative to what you disclosed at the end of year. I guess, first part is how are you thinking about further, you know, firming those up as you're able to, just given where forwards are sitting relative to, you know, maybe where they might get to, if there's a line of sight on, you know, material market tightening? I realize that's a little inconsistent with, you know, when the load might arrive, but, you know, we've seen forwards move around pretty substantially on, you know, longer dated expected changes in load.

I guess, you know, as a follow-up to that, what are you seeing in terms of, you know, appetite from customers to lock in prices at a level that, you know, are maybe higher relative to where things are sitting this year, but conversely, you know, could be pretty attractive relative to where, you know, pricing might move to if we get a more balanced and normalized environment, driven by some of the low growth we've talked about on the call today?

Yeah, John. You know, good morning. You know, I would say to you that, as we look out to 2027 and beyond, but focusing more on 2027, yeah, we did add hedges throughout the quarter. Today, as I mentioned in my prepared remarks, we're around 5,500 GWh hedged at an average price is CAD 65, again, well above where we're at on the forwards today. If you look at the forward curve right now, it's around CAD 46, just to put it into context. You know, recall that with our hedging, it's not only financial. The large part of it actually is our C&I book.

These tend to be an average tenor of three years, and they tend to attract, you know, a premium over the forward, given they, you know, our customers want that certainty for their three year period as relates to the amount of generation they require. Our team remains very active in that market. I think it is one of our core capabilities that we have here in Alberta to really manage that book, if you will. I would say to you that when we look to 2028 and 2029, there's really no liquidity out there at this point in time. Generally, what we see when we're looking at putting on any type of hedges, it's kind of about 18 months forward, if you will.

I would say also that, you know, if we saw forward pricing that is below where we expect it to be, so based on my prior comments and what we said at Investor Day, I think the team would hold back saying that the forward curve isn't reflective of where we think pricing will ultimately go to. And, you know, we've done this in the past where, you know, a number of years ago, where we looked at the forward curve and we would really look at it and said the forward curve isn't reflective of where we expect pricing to go. Think of this back in really 2021, 2022, and 2023. And we benefited from that we were a bit, I would call, more open.

Then similarly, the team saw a tightening or a loosening in the market, if you will. There was gonna be more supply really in 2024 and 2025 and became very active in the hedging. You know, thankfully, we did that. Again, as I said earlier, you know, we are hedged at CAD 64 for this year. Last year, we were hedged at CAD 71. Again, we have a strong team that is constantly looking at the markets and saying, "Okay, what's best here to either lock in at current forward pricing or remain open?" Hopefully it gives you some context around it.

You know, we are focused on 2027 and really 2028, 2029 remain open right now, given there's not a lot of liquidity out there, and the forward curve is not reflective of where we think it will go.

Okay. That's great. All my other questions were answered, so I'll leave it there. Congrats to Mike and Grant.

Thank you.

Thanks, John.

Our next question comes from the line of Patrick Kenny with National Bank Capital Markets. Your line is now open.

Hey, good morning, everybody. Just back on the MoU at Keephills, outside of your commercial discussions, just wondering if you could provide an update on, you know, where things are at with the site development plans and the permitting process? Maybe just comment on, you know, how things have progressed from an overall regulatory approval standpoint to build out the full gigawatt potential, just relative to your initial assumptions coming into the year?

Yeah. I would, I would say to you, Patrick, you know, first of all, this is one of the advantages of using Keephills. It's an operating facility today. All its permits are in place. What was key last year was with Parkland County getting the rezoning approved by Parkland County, and we got that, which was a significant step forward for us as it relates to data center development there. Obviously, we've got our allocation under phase I here at the AESO, as you well know.

Everything is well in hand because it is an operating facility here that there's nothing meaningful here that we need by way of permits here to continue to advance the opportunity that we have in front of us at Keephills today.

Okay, that's great. On Centralia, just wondering if you had an update or any clarity on, you know, the mandate being potentially terminated or perhaps extended beyond mid-June? I guess if still online, if your team sees any opportunity to start generating some positive cash flow from the facility through the summer?

Patrick, you're referring obviously to the 202(c) order that we received that's out to call it mid-June. You know, obviously, TransAlta continues to comply with the order. We're also actively engaged both with the State of Washington and the DOE as relates to the order. You know, it hasn't run thus far, and our expectation is that it likely will not run here, you know, through the order, given that when you look at pricing in the Mid-C market, which today is around CAD 42 for the balance of the year. And looking at the variable cost of production from the facility, it's well in excess of that. We don't expect that the facility will run. We are, again, complying with the order.

I think it's also important to note that we continue to advance the coal to gas conversion with the facility and working with PSE. We are encouraged by PSE filing for their rate filing here back in the first quarter. We are doing, you know, the front-end engineering and design work right now at the facility, which is good, to get to, you know, a final investment decision sometime in Q1 of next year. What we do know is Centralia is critical to the reliability, you know, it needs in the market that everybody's in agreement that the coal to gas conversion is essential. Again, we have really good dialogue, you know, between the State of Washington and the DOE.

Okay. Thanks for that. Then last one for me, Joel. Just, you know, from a balance sheet perspective, as you navigate this weaker period of free cash flow in Alberta, while at the same time, you know, still keen to look at M&A opportunities outside the province. Just wondering how you might be thinking about asset divestitures across the portfolio, say over the near to medium term, just to, you know, ensure a strong financial position and have some dry powder ahead of any, you know, future opportunities that might come along.

Yeah. Pat, it's a couple of things I've just observed. First one, as we said at Investor Day, is that our metrics are get the EBITDA being the key metric here, could drift above that 4x. It would be temporary, that when you look at where we see our EBITDA going in Alberta, with stronger prices in that kind of post 2027 time period, that there's certainly a glide path out. Along with having Centralia come online, it will generate about CAD 150 million per year of EBITDA for us, starting really in 2029. Again, there is a glide path here that we see.

To your point around, you know, to create additional, I call dry powder, we are looking at the portfolio. We have a few things that we're looking at right now that we're very actively engaged on, where we may look to rotate some assets here within the portfolio to create some of that dry powder, given that we are seeing, you know, the question earlier around the M&A opportunities. It remains very robust, so that we want to be in a position that, again, if there's an opportunity out there that's, again, in line with our strategy, a highly contracted asset.

Again, and the risk-adjusted returns meet our hurdle rates and it's accretive on a per share basis, that we would look to pursue that opportunity, but at the same time, not overly stretching the balance sheet. Then, you know, on top of, you know, capital rotation, you know, there was a transformative type opportunity. There's other levers that we can pull as well, including, you know, the Brookfield conversion here for the hydro assets that we have. That's one. Then you obviously have common equity for something that is transformational here. Again, any opportunities that we look at have to be accretive.

Okay. That's great. Thanks, Joel. Appreciate the comments.

Thanks, Pat.

Thank you. There are no further questions at this time. I would now like to turn the conference back to Stephanie Paris for 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. You may now disconnect.

Good morning. My name is Josh, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Fourth Quarter 2025 and Full Year Results Conference Call. [Operator Instructions] Thank you. Ms. Paris, you may begin your conference.

Thank you, Josh. 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 Fourth Quarter and Full Year 2025 Conference Call. With me today are John Kousinioris, President and Chief Executive Officer; Joel Hunter, EVP, Finance and Chief Financial Officer; 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 information provided during this conference call is subject to the forward-looking 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.

Thank you, Stephanie. Good morning, everyone, and thank you for joining our fourth quarter and full year conference call for 2025. TransAlta delivered strong performance during 2025 while meaningfully advancing our business and strategic priorities. During 2025, we delivered adjusted EBITDA of $1.1 billion, free cash flow of $415 million or $1.73 per share and average fleet availability of 92.3%. Lower power pricing in Alberta, subdued market volatility and lower wind resources impacted our operating environment during the year. As a result, adjusted EBITDA came in at the lower end of the range of our expectations, while free cash flow came in slightly above the midpoint of our 2025 guidance. In 2025, we had record safety performance with a total recordable injury frequency rate of 0.12 compared to 0.56 in 2024 and our target of 0.37. We entered into a tolling agreement with Puget Sound Energy for the redevelopment of our Centralia facility. We amended and extended our committed credit facilities totaling $2.1 billion with our syndicate of lenders, significantly improving our financial flexibility and ability to execute project financing, which was a strategic priority. We acquired Far North Power, adding 315 megawatts of dispatchable generation in our core market of Ontario. We optimized our Alberta portfolio with a strategic decision to mothball Sundance 6 and Sheerness 1, thereby maintaining the long-term optionality of the units while minimizing costs in the near term. We fully integrated Heartland, which we acquired late in 2024 into our company, providing additional contracted cash flows and realized synergies. We successfully completed our ERP system. on time and on budget, and we significantly advanced three natural gas generation projects in Alberta to provide us with optionality to support data centers and grid reliability in the province for decades to come, which we will speak to at our upcoming Investor Day on March 23. Today, we're also very pleased to announce that we have entered into a memorandum of understanding with CPP Investments in Brookfield to advance our data center opportunity at Keephills, which Joel will be speaking to in more detail shortly. And our Board of Directors has approved an 8% increase to our common share dividend to $0.28 per share on an annualized basis, which represents our seventh consecutive annual dividend increase, affirming our company's commitment to returning value to our shareholders. Before turning the call over to Joel, I'd like to acknowledge that this will be my last quarterly conference call with all of you. It has been a privilege and an honor to lead TransAlta since 2021, working with such a committed and talented team. I would also like to thank all of you for your partnership as we work to advance our company for the benefit of our shareholders. I fully support Joel as the next President and CEO of TransAlta, and I'm confident that he is the right person to advance its strategy during this exciting time of opportunity. Joel, I'll now turn it over to you to talk about our financial performance in 2025 and our strategic priorities for 2026.

Thanks, John, and good morning, everyone. I'd like to start by offering 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 appointment. I look forward to working with the team to continue executing our strategic priorities, and I will announce the CFO successor in coming months. As John mentioned, today, we are pleased to announce that we've entered into an MOU with CPP Investments and Brookfield to advance the data center development in Alberta for which TransAlta will be the exclusive site and power provider. The MOU establishes a framework for phase development at our Keephills site in Parkland County, including initial long-term power purchase agreement for approximately 230 megawatts and the evaluation of additional phases aggregating up to 1 gigawatt of demand. Our Keephills site provides a strategic platform that leverages its large zone land position, existing transmission, natural gas and water infrastructure and on-site generation to support long-term project scale. We are pleased to be working with CPP Investments in Brookfield and to serve as the exclusive site and power provider for the project. As experienced global infrastructure investors, they have the capability to deliver projects of this size and complexity. We look forward to advancing digital infrastructure capacity and unlocking future investments in Alberta. In December, we announced the signing of a long-term tolling agreement with Puget Sound Energy, or PSC, to convert Centralia Unit 2 from coal to natural gas-fired generation. The agreement provides a fixed price capacity payment, giving PSC the exclusive right to the capacity, energy and ancillary service attributes and dispatch rights to the 700-megawatt facility. Once converted, the unit will be fully contracted until 2044, providing continued reliable power to the region long beyond its original retirement date and with a lower emissions profile of about 50%. Approximately USD 600 million of capital expenditures will be required to extend the useful life of the facility and convert it from coal to natural gas-fired generation, delivering an anticipated build multiple of 5.5x. The target commercial operation date is late 2028, and we anticipate declaring a final investment decision after receipt of all required approvals currently targeted for early 2027. In December 2025, the U.S. Department of Energy issued a temporary order requiring that the Centralia Unit 2 facility remain available if called upon to operate for a period of 90 days through March 16, 2026. As required, TransAlta is complying with the order and continues to advance the conversion in alignment with PSC in order to achieve the targeted commercial operation date. In November, we announced the acquisition of Far North Power Corporation, and I'm pleased to share that the transaction closed earlier this month. Far North's portfolio consists of four natural gas-fired generation facilities totaling 310 megawatts, including the 120-megawatt Aqua Falls, 110-megawatt Kingston, 40-megawatt North Bay and 40-megawatt Campus casing facilities. The assets, which were acquired for $95 million are expected to add approximately $30 million of average adjusted EBITDA per year with approximately 68% of the portfolio's gross margin contracted to 2031. Beyond the contract period, these assets are attractively positioned for recontracting opportunities and add to our reliable and increasingly diversified portfolio. This acquisition demonstrates progress towards our priority of pursuing strategic M&A. During the quarter, we generated $247 million of adjusted EBITDA, which was $35 million lower than the fourth quarter 2024, primarily due to lower Alberta and Mid-C power prices as well as subdued market volatility impacting energy marketing results. Hydro segment adjusted EBITDA decreased to $39 million compared to $57 million last year due to lower spot power and ancillary prices in Alberta as well as lower merchant volumes. The wind and solar segment produced adjusted EBITDA of $102 million, which was higher quarter-over-quarter due to higher wind resource and availability across the fleet. In the Gas segment, adjusted EBITDA decreased to $96 million from $116 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, higher production from Sarnia and favorable hedge positions settled. The Energy Transition segment delivered adjusted EBITDA of $16 million, a $10 million decrease year-over-year due to lower mid market prices, partially offset by lower purchase power costs and the settlement of favorable hedge positions. Energy Marketing adjusted EBITDA decreased by $5 million to $21 million, primarily due to comparatively subdued market volatility across North American natural gas and power markets. Corporate costs were lower than last year at $27 million, primarily due to lower incentive costs. Free cash flow was $93 million, which was $47 million higher than the same period last year due to the items noted previously as well as lower overall sustaining capital expenditures. Shifting now to our full year 2025 results. The Hydro segment generated adjusted EBITDA of $285 million, in line with our expectations. The decline year-over-year was driven by lower spot ancillary power prices, partially mitigated by positive contributions from hedging, higher production and higher environmental and tax attributes being utilized against the Alberta gas fleet's carbon obligation. The wind and solar segment delivered adjusted EBITDA of $338 million, a 7% increase compared to 2024, primarily due to the full year contribution of the Oklahoma wind assets, higher environmental and tax attributes revenues and higher wind resource in Eastern Canada and the U.S. The Gas segment continued to have solid availability and delivered adjusted EBITDA of $438 million. The year-over-year decline was largely due to lower power prices in Alberta, higher fuel and operating costs and increased dispatch optimization from our Alberta gas fleet, partially offset by the addition of Heartland and our favorable hedge position in Alberta. The Energy Transition segment delivered $100 million of adjusted EBITDA, which increased year-over-year due to lower purchase power costs and higher availability at Centralia. Our Energy Marketing segment delivered performance in line with our 2025 guidance range for gross margin, contributing adjusted EBITDA of $85 million. Energy Marketing results were impacted year-over-year by subdued market volatility across North American natural gas and power markets. And finally, corporate costs marginally increased year-over-year, primarily due to increased spending to support our strategic growth initiatives and associated costs with the Heartland acquisition, which was partially offset by cost-saving initiatives. In aggregate, adjusted EBITDA was $1.1 billion and free cash flow was $514 million or $1.73 per share, which is above the midpoint of our guidance. Turning to our Alberta portfolio. The spot price averaged $44 per megawatt hour in 2025, which was notably lower than the average price of $63 per megawatt hour in 2024. The decline year-over-year was primarily due to incremental generation from the addition of new gas, wind and solar supply in the province as well as the impact of milder weather throughout the year. The gas fleet exceeded our expectations by capturing an average price of $66 per megawatt hour, a 50% premium to the average spot price. Our hydro fleet also captured significant merchant upside, delivering an average realized price of $58 per megawatt hour, a 32% premium to the average spot price. Our merchant wind fleet realized an average price of $24 per megawatt hour, which was impacted by increased intermittent wind and solar generation in the Alberta merchant power market. Despite relatively benign weather last year, which resulted in lower power prices on average, 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. We realized the benefit from approximately 8,600 gigawatt hours of hedges at an average price of $70 per megawatt hour, representing a 59% premium to the average spot price. Last year, we also delivered approximately 3,900 gigawatt hours of ancillary service volumes at a modest 14% discount to the average spot price. By optimizing our fleet throughout the year and fulfilling hedges with purchase power, we were able to respond to higher demand from the AESO and delivered an increase of 9% in ancillary service volumes from our Alberta portfolio compared to the prior year. Turning now to the fourth quarter. Spot prices averaged $43 per megawatt hour, which was lower than average price of $52 per megawatt hour in 2025. Our hedge position was strong with an average price of $73 per megawatt hour, a 70% premium to the average spot price. Our hydro fleet delivered an average realized merchant price of $53 per megawatt hour, a $0.23 premium to the average spot price, while the gas fleet realized an average merchant price of $65 per megawatt hour, a 51% premium to the average spot price. Our merchant wind fleet, which cannot be dispatched and is subject to wind resource, realized an average price of $26 per megawatt hour. In the quarter, our average realized price for hydro ancillary service pricing settled at $35 per megawatt hour, a 19% discount to the average spot price. Looking at this year, we have approximately 8,500 gigawatt hours of our Alberta generation hedged at an average price of $65 per megawatt hour, well above the current forward curve of $44 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. For 2027, our team has increased our hedge position to approximately 4,000 gigawatt hours at an average price of $71 per megawatt hour, which remains significantly above current forward pricing levels. We believe the forward price does not fully factor the impact of the REM or 1.2 gigawatts of data center load that will be coming online. We expect the anticipated increase in load will rebalance the current oversupply of generation in the province later in the decade and drive opportunities for growth in the long term. Our dispatchable thermal and hydro fleet has existing capacity to provide reliability and serve the expected load growth, which we'll speak further to at our upcoming Investor Day. Turning now to our 2026 outlook. We expect adjusted EBITDA to be in the range of $950 million to $1.1 billion and free cash flow to be in the range of $350 million to $450 million or $1.18 to $1.51 per share. Now there are a number of factors influencing our 2026 outlook. First, Centralia ceased to operate at the end of 2025, which will have a sizable impact to our adjusted EBITDA and free cash flow until the plant comes back online post conversion to natural gas. Our outlook does not include any impact from the 202(c) order as we expect to recover related costs. Second, we expect Alberta spot power price to remain under pressure with a range of $40 to $60 per megawatt hour, impacting our Alberta merchant portfolio. Third, although we are well hedged both financially and through our commercial and industrial business, the average hedge price has decreased from 2025 levels. And finally, we'll have lower contributions from Sarnia due to a step-down in contracted pricing as well as the expiry of the contract and decommissioning of our Ada facility in Michigan. We'll have higher contributions to our Alberta portfolio through the expected realization of carbon credits against in-year carbon compliance costs in addition to the 2025 carbon compliance costs in Alberta. The confidence in our EBITDA and free cash flow guidance is supported by the performance of the contracted fleet as well as our hedging and optimization strategies, which represents approximately 80% of our expected revenue from our generating facilities. Given that we've now signed our MOU for data centers in Alberta and a definitive tolling agreement at Centralia, we are pleased to announce that we will hold our Investor Day in Toronto on March -- on Monday, March 23. The presentation will commence at 9:00 a.m. Eastern Time. We will provide an overview of the company's strategic priorities, long-term plan, financial outlook and growth opportunities. Our Investor Day is open to the investment community and will be hosted in a hybrid format with in-person and live webcast attendance options available. For 2026, our priorities are the following: improving our leading and lagging safety performance indicators while achieving strong fleet availability. delivering adjusted EBITDA and free cash flow within our 2026 guidance ranges that at midpoint of $1 billion and $400 million, respectively. maximizing the value of our legacy thermal sites by advancing our Alberta data center project as well as advancing our coal-to-gas conversion at Centralia toward FID, pursuing strategic M&A opportunities and maintaining our financial strength and flexibility. Stepping in as CEO next quarter, I believe TransAlta offers a compelling investment opportunity. We are a safe and reliable operator with resilient cash flows underpinned by a diversified hydro, wind, solar and thermal generation portfolio located across three countries, 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 on this year to repurpose to meet the growing need for reliable generation in the jurisdictions in which we operate. We also remain a leader across diverse technologies focused on responsible generation. We meaningfully reduced our greenhouse gas emissions, achieving our 2026 emissions reductions target ahead of schedule. We remain disciplined in our approach to growth, focused on delivering value to our shareholders, and we work to diversify our portfolio within our core geographies and increase the stability and contractiveness of our earnings and 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 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 of our employees and contractors for their commitment and setting the company up for success this year and beyond. Thank you. And I'll now turn the call back over to Stephanie.

Thank you, John and Joel. Josh, would you please open the call for questions from the analysts?

[Operator Instructions] And our first question comes from Mark Jarvi with CIBC.

I wanted to see if you could share some more details around the data center opportunity, just does say, 2027 plus. Just is the expectation that the load will start to ramp in 2027, how long before the 230 megawatts would reach full capacity?

Mark. Look, it's difficult for us to give you a lot more detail on the MOU just because based on the terms of that, we're really quite restricted on what we can actually say. What I can say is that speed to power does remain a priority for our two customers there. We're excited about the partnership that we have with them. Our focus right now, and I know their focus is to get our definitive documents done. And as soon as those documents are completed, which we expect to happen in the year, I think they'll proceed to start making the kinds of investments that they need to up at our Keephills site and get us moving forward. And it will be a gradual ramping up.

Can you mention anything about terms of risk sharing, like who takes the gas price risk and carbon pricing risk and sort of like the structure net back to TransAlta if it's kind of like more capacity or tolling structure for you?

Yes. I wish -- again, I don't think I can give you those kind of terms based on the arrangements that we have. What I can tell you, though, is that we think the commercial framework that we've developed with CPPIB and also Brookfield is an appropriate one. And I think it is reflective of the value of the Keephills unit that we have there. So we're pleased with the overall arrangement that we have and think it's a really sound one from a commercial perspective.

And I would just add to that, too, that the arrangement does include a long-term PPA, which really contracts merchant cash flows as well.

And is that the rough terms of the PPA been settled at this point, even if you can't disclose anything about it?

I would say that the key elements of the PPA are laid out in the MOU.

Okay. And then it talks about ramping up over time. And just curious where you are in discussions. We've seen some of the engagement feedback on the Phase 2 with the AESO. Just bridging opportunities there to use your coal-to-gas assets as you go beyond 230 megawatts before you'd be able to kind of facilitate a large repowering potentially?

Yes. Look, the AESO and the provincial government continue to do their deliberations on Phase 2. As you can imagine, we're actively involved in that process. I can tell you that our view is that it will be critically important for the province to be able to rely on underutilized generation in essence, as a form of bring your own power, which has been one of the hallmarks of what the government has been talking about to permit a data center industry to develop in a meaningful way in the province of Alberta. I think we've been heard on that. And I think we're in a unique position to be able to ramp up given the sort of breadth of generation that we have in the province of Alberta to actually meet that need. And candidly, with both Sundance 6 and Sheerness I being mothballed, just those two units alone provide a pretty clear path where we could certainly be able to ramp up and meet the up to 1 gigawatt that we're contemplating under the terms of the MOU that we've done with our two partners.

And any sense of when you might get some clarity from the AESO on that?

Yes, we do expect to get it I would expect in the first half of this year. I'm not sure that we're going to get it by the end of this quarter, but I do think they're very mindful about giving clarity to the marketplace. They've got a lot going on, as you can imagine, with the REM and the work that is being done between Alberta and the federal government on the MOU that the two have signed. So there is a lot going on, but I know there is work being done, and we're fully engaged in that.

Our next question comes from Robert Hope with Scotiabank.

I want to go back to the MOU. So, along with Q3, you had kind of highlighted that you wanted a bunch of the key items to be largely ironed out, which could accelerate the path from an MOU to the contractual signing. As we look forward, is it just ironing out the details that is the key gating factor on the -- moving the MOU to a firm contract? Or are there a number of parallel paths with your customers on the data center side, which kind of will also weigh into the time line and the process there?

What I can tell you is that the MOU is an extensive one. There was a lot of discussion and a lot of settlement of terms around essential commercial elements of the arrangement that we have both for the first phase on the 230 megawatts that we've been allocated and the pathways that we could get to an aggregate of gigawatt going forward. As you can imagine, there are a number of definitive agreements that need to be finalized and settled in order for us to be able to move forward and they arrange everything from a definitive PPA with all of the terms to even just lease arrangements related to the actual land that is there. That takes time to be able to do. We're motivated to move that quickly, and our team is ready. They are too. And I think we'll move that, I think, in a very orderly way going forward. The two proponents also have work that they're doing behind the scenes in terms of who their offtakers are and just finalizing their offtake strategy, which continues to proceed. And our view is that given their capabilities and the scope of reach that they have, that they're going to be really successful around that, too. So there's a lot of work that we need to do and they need to do as well, but I think it will all be executable in a normal sort of way. We remain really confident. I can't tell you how pleased we are that we were able to announce it today.

Excellent. And I'll ask you a non-data center question. Can you give us an update on the M&A market and your views on gas assets as well as renewable assets and M&A as a potential form of growth?

Sure, Robert. Joel, why don't you start?

Yes, I'll start. Robert, it's -- the M&A market, I would say, remains very active. We're looking at a lot of various opportunities in various scale, if you will. I'd say that we see both a complement of renewable assets that are coming to market, both wind and solar. And similarly, we're seeing a lot of opportunities in thermal generation as well. So again, we remain very active and very focused with the eye on adding shareholder value. It has to be obviously aligned with our strategic priorities going forward here. A good example, again, is the Far North acquisition that we just closed here earlier in the month that we are very happy with, but we continue to see a lot of opportunities both in Canada and the United States and even some opportunities in Western Australia as well.

And the only other I would add to that would be it is -- and you know this, it is significantly cheaper to buy than it is to build right now, particularly if you factor in sort of the time frames for being able to get a project up and running.

Congrats on the MOU and the pending retirement.

Our next question comes from John Mould with TD Cowen.

Just to apologies, go back to the data center MOU quickly. I just want to see if there's anything you can share in terms of like key gating items to get from MOU to binding agreement? And could you give potential timing for when we might see a binding agreement? Apologies if I missed it. And if not, can you give us a sense of what you're targeting broadly for a mining agreement in terms of time line?

So we can't actually give you specific dates, John. But what I can tell you is that we do expect definitive agreements to be completed in year and frankly, to begin pretty immediately in terms of our engagement. Our team is ready to do that. And we're hopeful that in the coming few months, we'll be able to get those put in place and then be in a position to be able to share with the market more detailed terms once those definitive agreements are in place.

Okay. No, that's helpful. And then I'd just like to ask about on the development side for gas or I should say, brownfield development, you've brought back the Keephills 1 and Sundance 6 repowerings, at least from a regulatory perspective. You've also got the Flipi project. And you made the comment earlier around the buy versus build cost differential. Can you maybe just prioritize some of those repowering opportunities in terms of attractiveness versus what you're seeing in the M&A market? And under what conditions we could potentially see you make an FID on one or more of those repowering opportunities?

Yes. Why don't I start and then Joel, you can jump in. So you're right. We have advanced both Keephills 1 and a Sundance 6 repowering and also the Flipi project. And it was critical from our perspective to do that certainly from a regulatory and permitting perspective before the end of last year because our goal was to be able to qualify all three projects under the existing framework for new gas-fired generation that would be able to run in an unabated way before the end of the year. And from our perspective, we've achieved that objective. So uniquely, I think, certainly in the context of Alberta, we have options now to be able to actually build flexible gas-fired generation in the province to meet the needs of the province going forward in the 2030s and beyond. Candidly, right to 2050 before the terms of the CER would impact that new build generation. It may be that we're successful under the terms of the federal and provincial MOU and the CER goes away, but we certainly didn't want to take that chance and we work through to make sure that regardless of the regulatory regime, we had those options ready. I think to answer your question in terms of new build, it is really hard given the existing suite of generation that we have in the province to utilize or acquire kind of legacy assets to meet incremental load growth. So it is our view that the 2030s will require new build to meet the needs and frankly, to replace some of the retiring generation. our preference as a company, I would say, Joel, would be to see contracted generation. We're not certainly building merchant gas-fired generation is much tougher for our company to get its head around here in the province of Alberta. But we think we can make the math work on those projects. We're beginning to ramp up our supply chain arrangements in respect of executing them. And there is development and design work that goes on to meet kind of the maximum optionality that we can get under those. So hopefully, that gives you a sense. Joel, I don't know if you want to add anything to that.

The only thing I would add is that we use our existing generation as a bridge to new generation, whether it's for Phase 2 of a data center or some other opportunities that we might see here in the province. Just given the time it takes for new build, the cost of new build in this environment. And to the extent that we do, do new build later this decade, early next decade, it would have to be underpinned by long-term contracts to ensure that we earn a full return of and on capital within the contract.

And the reality, John, is, I mean, the supply chain is such that you wouldn't be able to get turbines, the power island and the like for probably five years out. So you kind of need to begin doing the work to be able to get something that would be in place and get to a COD in the early 2030s.

Our next question comes from Maurice Choy with RBC Capital Markets.

Just picking up on these three natural gas generation projects that you're working on. If I'm not mistaken, the total capacities of these are obviously greater than the 1 gig Phase 2 and MOU, not to mention that two other sites are probably not even at Keephills. So is the idea here for you to help deliver solutions for the two counterparties beyond just Keephills? Or are there other data center customers that you may be looking to serve and secure?

Yes. Maurice, I think the answer to your question is all of the above, to be honest. Look, we're looking at our partners at Keephills are looking at making a significant investment in that part of the world that's going to require us to provide them with reliable generation for a long, long time. It's not just 2030s. It's something that's going to require us to help them into the 2040s and beyond. So we need to think about how do we get newer efficient generation given the time frame for our existing generation to actually meet those particular needs. Our discussions on other potential opportunities have not stopped. So we continue to receive inbounds and we continue to do other work to bring other opportunities for load growth in the province, other data center opportunities as well. And that's something that we're mindful of. And in advancing the three projects, we're just trying to maximize our flexibility. And remember, with K1 and we would be utilizing existing infrastructure with the idea to kind of get a build cost for that new generation to be lower than it would be if we would be doing a pure greenfield site.

And maybe just as a quick follow-up to all this discussion about MOU. I recognize that MOUs are generally not legally binding. Is there a termination fee if the project doesn't proceed?

Yes. We're -- again, I can't get into what the terms are. But I would say this. We view this MOU as a real expression of the intentions, very definitive intentions of the parties to move forward. We have absolute confidence in CPP Investments and Brookfield to be able to move it forward. I mean they're incredibly experienced global infrastructure players. They have proven capabilities to be able to move this forward. And frankly, I think they, too, like we are excited about developing a nascent Canadian data center industry in the country. So although the terms of the MOU were critically important and they took weeks and weeks and months of discussion to get done, we have absolute confidence and faith in the parties that we're dealing with to be able to move forward.

That makes sense. If I could just finish off with a question on funding. Given that you do have a number of funding needs for Centralia, Keephills, Phase 1 and perhaps Phase 2 as well. Can you speak to what you see as being your remaining investment capacity, say, through the end of the decade after you factor in some of these projects on an equity self-funded basis?

Sure. What I would say, Maurice, look, I'm going to turn it over to Joel, but we have a lot of levers that we can pull as a company to meet the funding requirements of our growth going forward. But Joel, maybe you can give your perspective.

Yes. And I would just say, Maurice, that, first of all, with Phase 1, there isn't really a big funding requirement for us for Phase Certainly, as we look to Phase 2, there could be. But again, there thinking about using our existing generation as a bridge to new generation shouldn't require a lot of significant capital spending for that as well. As it relates to Centralia, it's smoothed out over a couple of years based on us getting to an FID sometime early next year. So think of that as spend in '27 and '28 with an in-service kind of later in 2028 that would be very manageable with our existing free cash flow generation along with kind of incremental debt capacity that we have today. So we remain very kind of confident in our ability to fund these opportunities, whether it's data centers here in Alberta, along with Centralia. And we do have a number of levers available to us, including asset rotation and the like here to the extent that we see additional opportunities come our way. So again, we remain very confident in our ability to fund this growth going forward.

I remember in the past, Joel, you mentioned your expectation that the Brookfield debt and hybrids will convert to hydro equity. Is that still your existing assumption?

Yes. So the way it works, Maurice, just for everybody's benefit is that, that option is convertible up until the end of 2028. And so again, it's at the discretion of Brookfield to exercise that option. To the extent that they want to increase the ownership in the hydro assets, they can go up to 49%. But there are certain things that are required for that to occur. And if that were to happen, then certainly, there would be additional cash injection into the company as a result of that. So it's an option that remains open to the end of '28, as I mentioned, but it's the option of Brookfield.

Congrats to both of you, Joe and Joel from RBC.

Our next question comes from Benjamin Pham with BMO.

A lot of questions asked so far. Maybe just to continue the topic on Keephills. You mentioned Phase 1, you don't expect the funding need for that. But can you confirm, do you potentially need to spend capital on that as part of the MOU?

We can't really -- so first of all, Ben, sorry, I should have started with that. We can't really get into the -- what I would say is the capital investment required to sort of execute Phase 1 from a TransAlta perspective is negligible, I think, is the right way to kind of describe it. Remember, it will be grid connected. So there is a little bit of capital that is required to ensure that the data center will be connected to the grid. So there is a substation and some transmission that needs to be built out. But it's very proximate to the site that we have and the interconnection already that we have with the transmission line. So I would say it's very, very modest. When we think of the opportunity, we tend to think of K3 as effectively being the facility that is sort of tied to the opportunity. And K3 itself is in very good shape from an operational perspective. We maintained that facility very well. We're very pleased with its reliability and have very manageable sort of sustaining capital requirements for that going forward. So it's not at all a burdensome requirement. And I would say, even when we think of bridging generation, Joel, to the point in time where we get to potentially having new generation build, which is really in the 2030s, relatively modest capital expenditures from a TransAlta perspective going forward.

Okay. I got it. And I'm wondering to provide -- I know you've been advancing negotiations with customers in the last two years. You arrived at Brookfield CPP ultimately, which are well-established customers and counterparties. Can you maybe just walk through maybe, I don't know, qualitatively, the process, the level of demand in the last couple of years you experienced, the puts and takes you're facing ultimately by choosing the counterparty? And then do you also consider just going direct with the hyperscaler as part of those negotiations?

Yes. So we did run actually a pretty comprehensive process with respect to the data center opportunities. And one of the things that always, I would say, shaped our approach or our strategy on the data center was sort of the realization that at least initially, there would be a limited amount of new data center capacity that would come into the province, whether that would be a gigawatt or 2, like somewhere in that kind of space. And as you saw with Phase 1, the AESO and the province landed at 1.2 gigawatts kind of a gradual, I think, feathering in is it to use sort of a TransAlta kind of mindset of the data centers going forward. So that actually kind of colored our approach in terms of what was the scale that was available to be able to meet the demands of the individuals that we were speaking to. So our view was that it would be great to get to have hyperscalers, and we certainly do expect and hope that they end up coming into the jurisdiction. When we began our conversations, it was great to enter into discussions with CPP Investments and Brookfield. They had the kind of ramping profile and sort of load expectations that we thought were reasonable and kind of met the envelope that we thought that we were going to get. So it really aligned. And look, you've alluded to it. They're both outstanding infrastructure investors, not just in Canada, but globally. They both have a very good understanding of the Alberta market. They have extensive experience, not just experience, but relationships from a digital infrastructure perspective globally. And we absolutely knew that they had both the expertise and capital depth and execution capability to be able to get this done. So although we cast our net, I would say, fairly wide, initially, we were very pleased that we were able to be -- to have them as partners because their expectations kind of aligned with sort of the reality of what we thought the pathway was going to be to development in the province. So we consider ourselves quite fortunate to be working with them for them.

That's really a good context. See you in about a month or so.

Our next question comes from Julien Dumoulin-Smith with Jefferies.

It's Tanner on for Julien. Congrats on the announcements and congratulations to you, John. A lot of my questions have been asked and answered here, but I did want to see if maybe you would frame expectations for what's in play on the long-term financial plan to be provided next month. Are you going to be looking to provide guidance assuming base business as currently integrated in the portfolio? Or is baseline guidance likely to presume some execution of the MOU or other items? And also, how would you expect to handle or caveat AESO process uncertainties?

Yes. So it's Joel here. Yes, our intention here is to have probably a bit of an outlook out to 2029 that's reflective of kind of our assumptions around power prices in Alberta, the impact that will have, obviously, on our merchant portfolio, obviously, also factoring in some of the -- what we see from Phase 1 along with Centralia coming into service sometime later in 2028. So our intention is to provide some building blocks for you to see what that could look like here going forward at our Investor Day on March 23.

And expectations just around pricing generally and how we see the market evolving in the province for sure.

Our next question comes from Patrick Kenny with NBCM.

We're hearing more and more about Alberta's desire to beef up its interties with neighboring power markets. I was just curious your thoughts on how that might influence your outlook for the Alberta power market over time and also how TransAlta might be able to participate either directly or indirectly in those changing dynamics?

I would say that we are fairly optimistic about it, to be honest. I think we're still at an early stage of having some of those discussions, but we actually think it creates a considerable amount of opportunity for certainly our company and candidly, for the province as a whole. What we are seeing -- and when I think of the opportunity, I'm thinking of it, to be honest, less east-west, more north-south, to be candid. We think that load growth requirements in the Pacific Northwest into the Rocky Mountain states, frankly, all the way down to the Desert Southwest and even California will remain high. We think that reliability will continue to be a real priority in that part of the world. I think the ability to build new firming generation kind of in the western part of the continent will remain challenged, I think, at times, as will transmission generally to move it around. So we actually see an opportunity in Alberta, not just to kind of meet the ongoing needs for data center demand, certainly from a Canadian perspective, but also to be a bit of a reliability agent, if I can use that term, for kind of the WEC ideally as kind of an opportunity set that we're seeing. So look, it's going to take work and investment to be able to see that come through. But I know I'm excited about it. And I think, Joel, that it weighs heavily on the three new plants even that we're working to develop. So maybe your thoughts.

Yes. No, Pat, I agree with John. It's an exciting opportunity for us here that we can use existing generation in interim and then a real possibility here for new generation going forward, whether it's east-west or North-South, what we see in our neighboring jurisdictions, again, is a need for firming power. a growing one, actually. growing one. And what I really like here, too, is that you've got strong policy support here within the province to be kind of an energy superpower where we could see additional gas generation being developed in the province for export to neighboring markets. So we see it as a very exciting opportunity. I'd say as a bridge though, again, using our existing generation will be very important to that to the extent that we see opportunities in the future.

Yes, it's an important thrust, I think, Patrick.

Okay. That's great color, guys. I appreciate that. And then maybe just a follow-up on Centralia. I know it's a fluid situation, but just wanted to confirm if you had any more clarity on the 90-day order or if you had any recourse if things are extended and perhaps push back your FID decision on the conversion?

Yes. Why don't I start and then maybe I'll turn it over to Nancy to see if there was anything I didn't really cover off. So, look, the initial 90-day order expires mid-March. And we are fully in compliance with the order in the sense of being available should we be asked to run. We don't expect that given kind of how flush the hydro situation is in Washington state right now. I think our primary focus is more on getting clarity on the existing order, and we do have the ability to recoup our expenses, which is why we're not particularly concerned about that from a 2026 perspective. But certainly, Nancy and her team and our commercial team are focused on getting clarity around the mechanics of that going forward. With respect to the coal-to-gas conversion at Centralia, we continue to work that through in a very uninterrupted sort of way. Our general sense is that the conversion -- not our general sense, but the reality is the conversion is supported by Washington State. They need it. They're accepting of that facility being converted, and they see that the need for that facility to provide reliability into the mid-2040s is critically important. And in tandem, so does the U.S. Department of Energy, the federal government in the United States is also supportive of what we're trying to do there and understands it. So I don't regardless of kind of the trajectory of 202(c) on the facility, it is our expectation that it won't impede the work that we're trying to do from a coal to gas conversion. And like I can tell you, it's full steam ahead from a regulatory and planning perspective for us and for Puget candidly, as they look to get the rate base. Nancy, I don't know if you have any additional perspectives on that.

Thanks, John. I think John has covered it well. I think the only thing I would add to maybe sort of bit of a fine point on some of his comments is we've had very good communication and collaboration, both at the state and federal levels. And I think in respect of -- we can't predict whether or not we will receive another order. But at the same time, should that occur, sort of the building blocks, I think, are in place in respect of the work we're doing now to continue to progress through and to continue to proceed with the conversion. And again, as we stated at the outset, working very, very closely with our customer, PSC also. So I don't think at this time, we foresee any obstacles should that occur.

There are no further questions at this time. I would now like to turn the call back over to Stephanie Paris 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.

Thank you. This concludes today's conference. You may now disconnect.

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.

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.

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.

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.

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.

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

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

Congrats to John and Joel, on the announcements.

Thanks, Robert.

Thanks, Robert.

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?

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.

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?

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.

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

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?

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.

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?

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.

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?

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.

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?

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.

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

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?

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.

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?

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.

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.

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.

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

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?

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.

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?

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.

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?

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.

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?

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.

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

Great. Thanks a lot, Maurice.

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

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.

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.

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?

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.

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?

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.

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.

Yes.

Congratulations to both Joel and John on the announcements.

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

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.

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.

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.

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.

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?

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.

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 --

Yes.

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.

That's right.

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

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.

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.

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.?

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.

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.

Yes.

-- because we haven't talked about it much on the call, but we are actively looking at a number of acquisition opportunities.

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.

Yes, very return focused, I would say.

Yes.

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.

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.