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Good morning. My name is Andrew, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Third Quarter 2026 Results Conference Call. [Operator Instructions] Thank you.

Ms. Paris, you may begin your conference.

Thank you, Andrew. 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 2026 Conference Call. With me today are Joel Hunter, President and Chief Executive Officer; Mike Politeski, EVP, Finance and Chief Financial Officer; and Chris Fralick, EVP, Generation and Chief Operating Officer.

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 made available later today, and the transcript will be posted to our website shortly thereafter.

All the information provided during this conference call is subject to the forward-looking statement 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, free cash flow are reconciled in the MD&A for your reference.

On today's call, Joel and Mike 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 third quarter conference call. TransAlta delivered strong third quarter operational and financial performance, demonstrating our fleet's ability to continue to deliver results 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 our diversified fleet.

During the quarter, we delivered adjusted EBITDA of $264 million, free cash flow of $93 million or $0.29 per share and average fleet availability of 92.6%. Due to our strong performance year-to-date and expectations [Audio Gap], we remain confident in achieving our 2026 guidance range, which Mike will cover in more detail.

In October, we closed the acquisition of 2 natural gas-fired peaking facilities in Colorado for USD 1 billion, which collectively will provide approximately $110 million of low-risk, high-quality adjusted EBITDA per year. These operating assets totaling 318 megawatts add immediate stable cash flow that can be redeployed into our most compelling growth initiatives, including the Centralia conversion and Alberta data centre projects. We also closed the sale of a 49% interest in our 502-megawatt Oklahoma wind portfolio to Ares Infrastructure funds for USD 305 million. This transaction monetizes a portion of our investment in a noncore geography, while retaining operational control.

We look forward to partnering with Ares and leveraging our combined strengths to enhance the value of the assets. Proceeds from the sale will strengthen our balance sheet and support our accretive growth opportunities as large load growth, electrification and onshoring, increased power demand across our core geographies. Progress continues with the conversion of Centralia to natural gas. We expect to receive our environmental permits by year-end, and we continue to advance towards the final investment decision next year.

In September, the U.S. Department of Energy issued its fourth order under Section 202C, requiring Centralia Unit 2 to remain available for operation for an additional 90 days. We continue to comply with the directive and remain confident in our ability to recover our associated costs. Yesterday, we notified the AESO that we will be mothballing our Battle River units and extending the Sundance 6 mothball outage. Doing so maintains the long-term optionality units, while optimizing our Alberta portfolio in the near term. We retain the flexibility to return the assets to service along with Sheerness 1 when market fundamentals strengthen, particularly as data centre load develops across the province. Our remaining Alberta fleet will operate at higher capacity factors to support our hedging strategy, provide reliability and capture value during higher priced hours.

And finally, together with our partners, Brookfield, CPP Investments and BGRE, we continue to make meaningful progress on the Keephills data centre project, now known as the Boreal Technology Hub. On October 7, the Boreal team hosted a community open house welcoming local stakeholders and other interested parties to learn about the project, ask questions and share feedback. Boreal is located directly south of our Keephills generating facilities where we are the exclusive land and power provider. At full build-out, Boreal is currently anticipated to provide up to 1.6 gigawatts of electrical load. Power will be provided from our initial 250-megawatt grid allocation, capacity from our underutilized gas-fired steam fleet and longer term, potentially from the Sundance 5 and Keephills 1 redevelopment projects.

I'm pleased to share we received AUC approval for the Keephills 1 project in October. We continue to make meaningful progress with AESO on a solution to serve data centre load from our underutilized generation, including our mothballed units. Our gas-fired steam units are designed to operate as baseload generation at capacity factors greater than 90%. Using underutilized generation will help serve new load, while continuing to provide affordable and critical reliability to Alberta's electricity system.

The Boreal project is currently pursuing their master site development permits, which is the next major milestone ahead of construction commencing. This project is a significant opportunity for TransAlta, partners, Alberta and the local community, and will establish one of Canada's largest AI and digital infrastructure hubs.

I'll now turn the call over to Mike to talk more about our third quarter financial performance.

Thanks, Joel, and good morning, everyone. During the quarter, we generated adjusted EBITDA of $264 million, a strong outcome given the soft price environment in Alberta. Our Hydro segment adjusted EBITDA reflected the optimization of hedge positions and higher intercompany sales of emissions credits. Our Wind and Solar segment reported increased adjusted EBITDA as higher wind resource across all regions provided additional upside.

Within our Gas segment, adjusted EBITDA was 29 million, higher due to the continued strong optimization of our Alberta fleet, realization of emissions credits and positive contributions from our facilities in Eastern Canada. Energy Marketing performed well in the third quarter, up 13 million year-over-year, reflecting strong performance from our trading desks across U.S. power and natural gas markets. In our Corporate segment, we continue to control our costs, which were 20% lower than the prior year.

And finally, our Energy Transition segment reflects the cessation of coal-fired generation at Centralia at the end of 2025. As Joel previously mentioned, we continue to comply with 202C orders received from the DOE.

Our renewable assets provided considerable environmental offset to our gas fleet's 2026 year-to-date carbon compliance obligation, resulting in a $51 million reduction in our carbon obligation during the quarter, reflecting the value of our diversified fleet in Alberta. Going forward, we expect the realization of emissions credits to better match our carbon compliance costs in the period incurred, which should provide a clearer view of the quarterly performance of each segment.

Finally, we also generated strong free cash flow during the quarter, totaling $93 million. Year-to-date, our sustaining capital expenditures are down $22 million. However, we expect higher maintenance capital in the fourth quarter, keeping our aggregate sustaining capital within the previously guided $140 million to $160 million range.

Turning to the Alberta portfolio. Spot prices averaged approximately $36 in the third quarter, down from $51 in the third quarter of 2025. The decline was primarily due to continued strong supply, mild weather and relatively limited periods of market tightness. We enhanced our margins by fulfilling portions of our higher priced hedge commitments through power purchases and monetization of positions when market prices were below our variable production costs. We benefited from approximately 2,500 gigawatt hours of hedges at an average price of $65, which represented a $28 premium to the average spot price.

Our Gas fleet realized an average merchant price of $55, which was a 53% premium to the average spot price, largely due to our dispatch optimization during high-priced hours. Our Hydro fleet also continued to capture merchant upside, delivering an average realized price of $43 and 19% premium to the average spot price. Our merchant wind fleet realized an average price of $19, reflecting increased thermal production in the market and the timing of intermittent wind and solar generation.

During the quarter, we also delivered approximately 2,800 gigawatt hours of ancillary service volumes at an 11% premium to the average spot price. Through effective fleet optimization and meeting hedge obligations with purchase power, we consistently address the AESO's need for reliability products. We continue to have a strong hedge book to support our Alberta business. For the balance of the year, we have approximately 2,100 gigawatt hours of Alberta generation hedged at an average price of $67, significantly above current forward pricing.

Looking ahead to 2027, we have approximately 6,700 gigawatt hours hedged at an average price of $65, also well above current forward levels. We will continue to opportunistically manage our hedge position to ensure we protect our cash flows, while capturing upside as market conditions evolve. Our gas-fired steam units continue to operate well below their potential and have the ability to run at significantly higher capacity factors. As higher priced hours emerge, that flexibility allows us to increase our generation and capture additional value. Our fleet decisions position us well for the current pricing environment, while preserving meaningful upside as market fundamentals improve. Our focus remains on optimizing the portfolio today, while maintaining the flexibility to capture growth longer term.

Turning to our financial position. We remain focused on strengthening our balance sheet and maintaining our financial flexibility. Asset recycling continues to be an important lever, as demonstrated by the recent sale of a minority interest in our Oklahoma wind portfolio. Longer term, improving Alberta power prices, potential contracting of underutilized generation and the expected cash flows from Centralia post conversion, will provide cash flow growth to further strengthen our financial position.

We are well-positioned to meet our 2026 guidance. Contracted fleet, strong hedge position and consistent optimization provide us with core cash flows, even in a low merchant power pricing environment. The net effect of the Colorado acquisition and Oklahoma disposition has a relatively modest impact to 2026, further contributing to the reaffirmation of our guidance.

With that, I will turn the call back over to Joel.

Thanks, Mike. As we move through the balance of the year, our priorities remain clear and our focus remains firmly on execution, specifically 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 centre strategy as well as our coal-to-gas conversion at Centralia, pursuing strategic M&A opportunities where we see a compelling fit within our portfolio and enhancing our financial strength and flexibility for disciplined capital allocation and cost control.

I believe TransAlta offers a compelling investment opportunity built on the strength of the business we have today and the significant opportunities we see ahead. We have operated a safe and reliable power generation fleet for over 115 years, providing strong and enduring cash flows. This strength is grounded in a diversified portfolio of hydro, wind, solar, storage and thermal assets across 3 countries, enhanced by our industry-leading asset optimization and energy marketing capabilities.

Our legacy sites continue to represent considerable and increasing value. We are proactively pursuing repurposing initiatives at these facilities to address the growing demand for reliable 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 shareholder value as we diversify our portfolio within our core geographies and continue to increase the proportion of stable and contracted 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.

And finally, and most importantly, we have our people. Everything we accomplish starts with the expertise, commitment and dedication of our employees and contractors. I want to thank them for everything they do to safely and reliably power our customers, execute our strategy and position TransAlta for continued success.

Thank you, and I'll now turn the call back over to Stephanie.

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

[Operator Instructions] Our first question comes from the line of John Mould with TD Securities.

Maybe I'd just like to start with the mothballing of the Battle River units. Wondering why now, just given the soft pricing environment and let's say, relatively soft dispatch volumes that you highlighted in your prepared remarks? And then why the Battle River units versus other lower utilization coal-to-gas units, and I'm thinking of Sheerness 2 as an example. And how should we think about what market conditions or contracting opportunities could drive returning any of these units to service ahead of the time lines you've laid out?

Yes. Thanks, John. It's Joel here. I'd say that we spent a lot of time kind of analyzing this, similar to previous mothballs that we've announced. With Battle River, when you look at the capacity factors for both Units 4 and 5, they're very low currently, and they were low last year. This is purely an economic decision and really to preserve the long-term optionality for both of these assets as load will increase over time with data centres coming into the province.

So again, a lot of time spent kind of analyzing this and how do we kind of lower our costs. So it is an economic decision. We communicated this with the government, with the AESO. Nothing to read into it here. We still remain very confident in our ability for data centre load to come to the province. This is simply to position these assets really longer term. And so as we think longer term, with data center load, we expect that we would have long-term contracts that would underpin these assets, including potentially Battle River 4 and 5 as part of this.

So again, a lot of time considered here to this mothball, but it really is an economic decision. And in fact, we're not even with the employees there, John, there's 45 employees there that will remain on site here and really to ready these assets for longer term here. And as we've mentioned before, Battle River 4 and 5, similar to our other gas-fired steam units, can easily flex up to over 90% kind of a capacity factor with very little kind of capital behind them. So again, we're just trying to preserve the long-term optionality here as logo come to the province longer term.

Okay. And then maybe just moving on to the data centre MOU at Keephills, and thanks for all that information on the open house that you had. There is a reference, as you noted, to up to 1.6 gigawatts of capacity there. The original MOU that you announced early in the year referenced 1 gigawatt. Has the MOU scope been formally increased to support this 1.6 gigawatts? And in terms of timing, you previously pointed to definitive documentation in 2026. Is that still your expectation given where you're at in the underutilized generation discussions with AESO and then the bring your own generation process more broadly?

Yes, John, I would say you think about when we signed the MOU back in February, there were still a lot of unknowns. We had our 230 megawatts under Phase 1 of a large load integration. And our customers at Brookfield and CPPI investments, they wanted to look to increase that. And so we said up to 1 gigawatt at the time. Since then, with the data centre regulations that we saw from the government back in June, really recognizing that underutilized generation should be considered here as part of kind of for it to serve data centre load, allowed us to go up to this 1.6. I would say this is initial based on the site that we have today. And so we remain very encouraged by that. And the ability to think not only how we can serve that 1.6, which would come from a function of the 230 under Phase 1, also the assets that we have right there with Keephills and Sundance being right next door and really our whole fleet, if you will, along with kind of longer term how we can look to rebuild those facilities here, repower them kind of in the next decade.

Your question around this year for the definitive agreements, I would just say to you that they continue to be ongoing, and we remain very encouraged by it and working very collaboratively with our customers. And I can't say definitively if it will be this year or sometime, obviously, in 2027. I think once we have a full understanding of what the underutilized generation that we can actually use here will be an important step forward to really kind of advance the definitive agreements here to the final stage here.

So I wouldn't say it's probably 2026. It's probably into -- sometime early to 2027 at this point in time once we understand exactly the amount that we can offer our customers as it relates to our underutilized generation.

Your next question comes from the line of Mark Jarvi with CIBC.

Just picking up on those comments, Joel, just curious in terms of the time line for the discussions with the AESO on the underutilized assets. Is that possible to wrap up by year-end and then you move to the final negotiation with Brookfield, CPP? Or is that also something that probably you get clarity in early '27?

Yes, Mark, I can't really obviously speak for the AESO, other than, as we've said before and it continues to be the case, that we work very collaboratively with them, ongoing discussions with the AESO here. And we expect something in the near term is all I can say. I -- We don't have anything definitive at this point in time. As I mentioned in responding to John's question, I think once we have clarity on what we're actually -- the amount that we have, then as far as the definitive agreements, they will come together, I would expect relatively quickly here, given that they are very well advanced at this stage. It's really just trying to fill in the blank, if you will, as to how much we're actually offering beyond kind of our Phase 1 allocation here.

But again, discussions remain very fluid with the AESO, very collaborative. And we're trying to achieve a common call here where we know we want to bring data centres to the province, but we want to ensure reliability for the grid along with affordability for Alberta here going forward.

Just to follow up on that, Joel, then just with the discussions, is it the terms of the usage of the assets that is requiring the most effort right now? Is it the scope of megawatts? And then in terms of the potential terms around either curtailment or restrictions on the units, can you share anything in terms of what might be amenable or you guys would be comfortable with on those units?

Mark, I can't really because it does remain kind of confidential here with respect our discussions that we have with AESO. But I would say it's all of the above, right, that we want to ensure that we get it right here as to, first of all, what's the allocation and how curtailment will work. And I think what we said before is then we have obviously a product that we can then offer to our customers that they can then offer to their customers.

And so again, it really is all of the above that you mentioned there. But again, it remains very constructive at this point and well advanced. I just can't give you a time line other than we expect to hear something probably in the near term.

Okay. And then just on the repowering projects, just curious where you guys -- where you're seeing them right now in terms of costing and equipment availability? Are you actively out there looking to price out the repowerings right now? Or is that sort of something that's going to happen in the next year or 2?

I would say to you that we are -- we remain very active knowing that the lead times here, Mark, are very long. Nothing has really changed from our last update where if you look at for a large frame unit to get a turbine, for example, you're looking at 5-plus years from the time you actually get into the queue to actually taking delivery. So as we think into really -- we're thinking into the next decade here as it relates to repowering here. And so those discussions, obviously, we're putting a lot of effort behind it right now that -- just given the lead times that we see.

We are in the queue for a large frame unit, which is very good, and we're looking for other opportunities right now and obviously forming a business case for the usage of these units. But I think really in the near term, the best use is our underutilized generation. That is the cheapest and it's speed to power for data centres. And so that is really the focus and then really thinking more longer term, how do you repower those facilities. And those are discussions, obviously, we're having with our customers right now here because, again, they're not going to sign up for 5, 10 years. They're looking for longer term as they make large capital investments for data centres. And so certainly, we have an ability here to power those facilities with their existing generation for the medium term, if you will, and then we would look to repower kind of longer term.

And our next question comes from the line of Maurice Choy with RBC Capital Markets.

Just wanted to take a step back and look at the power markets more broadly across North America. With the changing market dynamics, policies and politics in certain power markets in the U.S., have you seen a different tone from your prospective data center customers when they are looking at Alberta as an option?

Yes, Maurice, I would say the short answer to that is yes. We have, and it's positive tool. When you look at the moratoriums that are out there today, just pick a few markets, for example, there's moratoriums in Texas, Pennsylvania, New York that -- and what we know is the demand for power is not abating, that it's -- yes, and we've talked about this before, where there's just so much demand, far exceeds the amount of power that's kind of available in the near term that all of a sudden when you look at Alberta here, where there's obviously strong policy support from the government, strong support from the AESO, we are the only jurisdiction that really, I'd say, is long power within North America.

So again, we talked about speed to power, I think that there is a real opportunity here for Alberta. And again, I applaud the -- what the government and what the AESO have done here. They've been very deliberate and very focused on ensuring they don't want to compromise reliability or affordability here for Albertans. And so at times, people might feel a bit frustrated by that, but I think it's actually very intentional and being very focused not only in the medium term, but the long term. And because we've seen what's happened in other jurisdictions where maybe the build-out has gone too quickly.

And as a result, it requires a lot more infrastructure that results in higher utility bills for customers. And as a result of that, we've seen the moratorium. So I think -- all that being said, I think it's been directionally positive here for Alberta as we move forward here to bring data centres to the province.

And if I could just finish off with a deeper exploration about the Battle River mothballed position, but taking a little bit of an alternate approach here. When the Heartland Generation deal closed at the end of 2024, I had thought that this unit would have been mothballed a lot sooner and certainly not almost 2 years after the deal closed. Assuming you agree with that, can you just help me dissect what was the outlook for this facility back then and then comparing that outlook to what actually transpired over the last 2 years?

Yes. I would say when we looked at when we closed the acquisition back in December of 2024, really at that point in time, data centres and the discussion around data centres in Alberta was really starting to come into place, if you will. And so we're very fortunate actually, when we think about Battle River 4 and 5, when we -- the initial kind of investment thesis didn't contemplate data centres coming to the province and was thinking probably more of a longer term kind of repowering opportunity for that facility, knowing that it is an older facility, has a higher heat rate and therefore, won't be -- the capacity factor is going to be lower.

You fast forward to today where things look a lot differently, and this is what's really encouraging for our employees here at TransAlta when we -- when I talk to our folks out in the field, especially for our gas-fired steam units, knowing that -- and we've been saying this all along that you have this surplus capacity, how best can you use it and ensure reliability within the province. And so I think this is a real win-win where all of a sudden we're bringing new load to the province here with data centres and at the same time, these units will run for longer and they can run for longer, and that ensures reliability for the province, which is critically important here.

So a lot has changed, Maurice, since the initial thesis around the Heartland acquisition. But certainly, right now, looking back on it, it looks we're very fortunate to have made this acquisition and acquiring it at the multiple that we did, and we got some really great assets out of it that I think really create a lot of long-term optionality for our company here as it relates to data centres and just future opportunities that we see there.

Because what we do know is that having steel in the ground is very important. When you think about access to natural gas, water, transmission, that's one thing you see with our units, whether it's Battle River 4 and 5, Sheerness 1, Sundance 5, you pick any one of them, they all have that in common that they are ideally situated and they're located on industrial lands, too, which is important because we hear a lot about NIMBYism.

And really, that's -- we don't see that here. We are very actively engaged with our stakeholders in these regions and looking for future development here. And these are the assets that have been around for decades. And we hope that they're around for decades to come here.

Our next question comes from the line of Benjamin Pham with BMO.

I know you mentioned that you're waiting for the AESO outcome with respect to utilize capacity to perhaps firm up a definitive agreement for the Keephills/Boreal project. You did mention that you need to wait to the Phase 2a intake results to drive that. Is there a reason for that?

I'd say, Ben, first of all, again, as I mentioned earlier, we're well advanced with the Phase 1, the 230. And as I think about when -- as I mentioned earlier, when we announced the MOU back earlier, I guess in February, we talked about the 1 gigawatt, while we now know that, that could be a higher number, and you saw that from the open house here. They are linked together that, we're not only looking for 230, but how big can this be.

And so our team here is working very closely with the teams at Brookfield and CPPI around that to put those definitive agreements in place here. So it is important to kind of understand that how big are we talking about here. And again, I think we're -- hopefully, we'll hear back in the near term around our underutilized generation and what that will kind of constitute. And then from there, I would expect, that the definitive agreements, I would expect would come together relatively quickly after that.

Got it. And Joel, you mentioned earlier, you're defining the 1.6 at Boreal as Phase 1. Can you unpack that a bit? Is that analogous to the Greenlight project where they broke it up into 2 phases, but they call it one phase?

I mean I'm not sure, Maurice -- or Ben, I'm sorry, if I look at it that way. I think when I look at the 1.6 -- and we showed this at our -- at the open house where kind of call it Phase 1 is the kind of initial data centre, which would be kind of one facility, which would be around 230 megawatts, up to 300 megawatts. And then going from there, I think we could have up to 6 facilities on site there. So I'm not comparing this to Greenlight. I'm looking at this as kind of -- just kind of in phases. And what we wanted to show for Phase 1 because, of course, we have clarity on that allocation at 230 -- So at the open house, we really kind of focused on that, and we talked about kind of the water usage, for example, that we would see for Phase 1. We talked about the economic benefits, the number of people we'd employ for Phase 1.

But again -- and as we learn more about what the ultimate -- how much we have, then we'll be able to share more there. But that's the way I kind of look at this is it's kind of within phases within our project, if you know what I mean.

And our next question comes from the line of Robert Hope with Scotiabank.

Maybe a follow-up question on that. As you're thinking about the buildup of Keephills, when you're envisioning that 1 moving up to 1.6, would that all be under kind of the Brookfield, CPP agreement? Or are you envisioning the potential kind of, we'll call it, further phases to be supported by other customers? And are you in discussions regarding that?

Yes, Rob, we obviously remain very focused working with Brookfield and CPPI on this, as evidenced by the open house, up to 1.6. But we do have the optionality, if you will, to work with others here. And so our focus -- again, we want to keep everybody laser-focused on the price here and really thinking about what we've got here at Boreal with our partners. But to the extent that we see further the ability to do more, then it could be with them, but it also could be with other customers.

As you can well imagine, there's a lot of interest given, as I mentioned earlier, where we do have moratoriums elsewhere within North America, where I think there's a lot of focus on Alberta at this point in time. But we do remain focused working on the Boreal Technology Hub with our partners, but it doesn't preclude us to working with others as well.

All right. And then maybe a broader question just in terms of recycling of capital. So we saw the transaction in Oklahoma a couple of weeks ago. How are you thinking about monetizing other assets in noncore geographies and/or modalities?

Rob, it's Mike. Maybe I'll take this one. Yes. So asset recycling important for us right now. It's going to be -- play a part in getting our balance sheet back to where we want it to be. Happy with the start that we had with the Oklahoma sale and the proceeds we brought in there, partnering with Ares, great, great partner and happy with how that transaction played out.

If you look going forward, the internal team here is continuing to move and advance other opportunities. I think we've talked before around the size of our portfolio. We have over 90 assets in the portfolio. Many of them are outside of our core areas. lots of smaller assets that aren't contributing much. And you saw that actually during the quarter, we moved out a small asset and brought in $27 million kind of under the radar, but there's lots of opportunities within the portfolio that we can look to monetize and bring in proceeds.

We're going to be patient. We're going to be thoughtful. We're going to ensure the deals are making sense and we're bringing in fair value. But for sure, the team has stood up and advancing other initiatives. And I guess stay tuned for further progress on this front.

[Operator Instructions] Our next question comes from the line of Patrick Kenny with National Bank Capital Markets.

Joel, just back on Boreal, it sounds like there wasn't much in the way of negative feedback from the open house, but perhaps you can confirm if there are any key concerns from the community that you might look to address at your November 12th meeting and how you might be positioning the project to address or get ahead of any of those outstanding issues?

Yes. Thanks, Pat. I would say, overall, we were very pleased with the open house. It ran for 4 hours. There was just over 180 people there, a lot of, obviously, local folks there, very interested in the project. I think the takeaway was they want to understand more around data centres. It's still -- even though we talk a lot about data centres, it's still relatively new. And they have questions around, for example, like, what's the amount of noise that will come from the facility, what's the amount of water that would be used, for example. And these will be covered in further detail as part of the technical sessions going forward here, really to address any kind of concerns or questions that our stakeholders may have around that.

But I'd say, overall, Pat, we were very pleased. I thought the team did a really great job being very well-organized. We had kind of like 30 kind of storyboards, if you will, there at the site so that people can walk around and ask questions of the team. And so it was very, very engaged. There was no protests or anything like that. It was really people just trying to get more information. And again, I think this is something for TransAlta -- We have been in this area for over 70 years with the Keephills and Sundance facilities. So it's certainly an area that we are very familiar with. We're very engaged with the local communities and First Nations as well.

And I would say, overall, we are very pleased with the outcome, and we look forward to the next kind of technical sessions here, which will, I think, do more of a deeper dive on some of the technical questions that arise, as I mentioned earlier, from a project of this size.

Okay. And then I guess early days on getting the keys to the Colorado facility, but curious, any early indications or opportunities that you might be seeing to leverage your position in the region to either expand your presence in the U.S. WECC market, either from a trading or additional M&A perspective?

Yes. I would say this goes back to when we announced the transaction back in June, kind of our thesis around making this acquisition. As you highlighted there, when we look at the WECC, the Western United States, it's a core market, core geography for us. And today, we don't have a lot or we didn't prior to the acquisition. It was really our investment in Centralia.

Now having 2 brand-new facilities of 318 megawatts fully contracted for 27 years with 2 very high-quality counterparties, I think does create a lot of opportunity for us going forward within Colorado. Today, Colorado burns roughly 20%, 25% of the power from coal, and they will move off of coal to natural gas. So I think that in and of itself can create an opportunity here for TransAlta that we didn't have prior to making this acquisition.

We also have a new partner, if you will, with Kindle through Blackstone. This is who we acquired the assets from, where they're looking for other opportunities as well within the WECC that certainly TransAlta might be able to partner with them and especially really leveraging our marketing and trading capabilities, as you mentioned, here as they look for future development there. So I think it's, again, a real opportunity here for us. Early days, but now we have a platform to really build off within a core market for us.

So I'm very happy with the transaction. It closed kind of on time and the commissioning went extremely well with the last unit coming online. And Chris Fralick had the opportunity to be out there on Friday and came away very encouraged by the team there and obviously, the assets. And now we will look for future opportunities there to further develop our presence in Colorado and within West.

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 Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Second Quarter 2026 Results Conference Call. [Operator Instructions]

Ms. Paris, you may begin your conference.

Thank you, Michelle. 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 Second Quarter 2026 Conference Call.

With me today are Joel Hunter, President and Chief Executive Officer; Mike Politeski, EVP Finance and Chief Financial Officer; and Chris Fralick, EVP Generation and Chief Operating Officer. 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 made available later today, and the transcript will be posted to our website shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualification settled here on Slide 2, detailed further in our MD&A and incorporated in full for 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, Joel and Mike 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 second quarter conference call. TransAlta delivered solid operational and financial performance during the second quarter of 2026, demonstrating our fleet's continued resilience during challenging market conditions. During the quarter, we delivered adjusted EBITDA of $291 million, free cash flow of $143 million or $0.47 per share and average fleet availability of 90.2%. While our Alberta merchant portfolio continues to be impacted by softer prices, our hedging strategy and active asset optimization generated realized prices that were well above spot prices during the quarter, along with our hydro and wind assets providing significant environmental offsets to our gas fleets 2025 carbon compliance obligation.

We remain confident in achieving our 2026 guidance range, which Mike will talk about later. In the quarter, we continued to advance our data center strategy with CPP investments in Brookfield. More broadly in Alberta, positive recent developments reinforce the momentum and collective commitment across government and industry to develop AI infrastructure. In particular, in June, the government of Alberta published their data center regulations, giving authority to the ASO to proceed with the next phase of the large load integration plan. The regulation includes provisions that permit the ASO to determine underutilized capacity that can be used to serve incremental data center load. Consistent with our messaging at Investor Day, we believe that our gas-fired steam units constitute underutilized generation that can support both grid reliability and the continued build-out of AI infrastructure in the province.

Our gas-fired steam units are designed to operate as baseload and can produce at capacity factors greater than 90%. The recent performance and lower capacity factors averaging around 20% in 2025 have been driven by economic decisions, not capability. Speed to power is critical, and we view the data center regulations is an important step towards framework clarity. The determination on how unutilized assets will be incorporated into the build-out of AI infrastructure will be made by the ASO, and we remain actively engaged with them.

Also in the quarter, we fully integrated the 4 gas-fired facilities in connection with the acquisition of -- for North -- in June, the U.S. Department of Energy issued its third temporary order requiring that Central Unit 2 remain available for operation, if needed, for a period of 90 days. TransAlta is adhering to the order, and we plan to submit a request for reimbursement to the FERC for costs related to the second order. Progress continues with the conversion of the unit to natural gas, and I am pleased to report that our time line for a final investment decision in the first quarter of 2027 remains on schedule. Last month, we announced that TransAlta has entered into an agreement to acquire 2 natural gas-fired peaking facilities in Colorado for USD 1 billion paired with a common share offering for $350 million. Both assets are fully contracted to investment-grade counterparties under long-term polling agreements that include full cost pass-through of all operations and maintenance, fuel and capital expenses, which meaningfully reduced the risk profile of the acquired assets.

The acquisition is expected to deliver $110 million per year in low-risk, high-quality adjusted EBITDA to our portfolio and is immediately accretive to free cash flow per share. We expect closing to occur in the fourth quarter following receipt of all regulatory approvals as well as Canning Peak Power achieving commercial operations. Adding stable operating assets like this delivers immediate cash flow that can be redeployed into our most compelling growth initiatives, including the Centrale coal-to-gas conversion and Alberta data center projects.

And finally, we realigned our executive management team, adding Mike Politeski, as our EVP, Finance and Chief Financial Officer; and Grant Arnold is our EVP Growth and Chief Commercial Officer. In addition, Nancy Brennan assumed an expanded role as Chief Legal People and Corporate Affairs Officer; and Chris Felix, new title is EVP, Generation and Chief Operating Officer. Supported by an exceptional team across the organization, I am confident that we have the right people and structure to execute our strategy and realize long-term value creation for TransAlta.

I'll now turn the call over to Mike to talk more about our financial performance in the second quarter of 2026.

Thanks, Joel. Good morning, everyone. During the quarter, we generated adjusted EBITDA of $291 million despite challenging market pricing in Alberta. Our Hydro segment adjusted EBITDA was $87 million, down $39 million from the same quarter in 2025 due to lower Alberta spot and hedge prices as well as lower intercompany sales of emissions credits. Our Wind and Solar segment reported adjusted EBITDA of $90 million consistent with the prior year, as higher U.S. wind resource mitigated lower Alberta pricing and reduced wind resource in Eastern Canada. Within our Gas segment, adjusted EBITDA was $14 million higher than the prior year due to strong optimization of our Alberta fleet and positive contributions from our Far North acquisition.

Consistent with prior years, our second quarter results benefited from the realization of emissions credits against our prior year carbon obligation. For the balance of 2026, we expect additional contributions to our segments from the realization of carbon credits against in-year carbon compliance costs. Our energy marketing adjusted EBITDA decreased by $16 million primarily due to subdued market volatility in Western power markets and lower realized gains within the quarter. We expect to have more gains realized by year-end as favorable trade positions settle. In our Corporate segment, costs were 8% lower than the prior year due to initiatives to control spend.

And finally, our Energy Transition segment adjusted EBITDA was lower than the prior year due to the Centralia contract expiry at the end of 2025. We also generated strong free cash flow during the second quarter, totaling $143 million. Our sustaining capital expenditures were down $18 million year-over-year however, this was primarily timing related, and we continue to expect sustaining capital of $140 million to $160 million in 2026.

Turning to the Alberta portfolio. Spot prices averaged $29 per megawatt hour in the second quarter, notably lower than the $40 per megawatt hour in the second quarter of 2025. The decline was primarily due to seasonally lower demand and continued strong supply in the market. Although prices were low, we enhanced our margins by meeting portions of our higher-priced hedge commitments through power purchases when market prices were below our variable production costs. We benefited from approximately 2,400 gigawatt hours of hedges at an average price of $63 per megawatt hour which was $34 per megawatt higher than the average spot price. Our gas fleet realized an average price of $68 per megawatt hour, a significant 134% premium to the average spot price largely due to our dispatch optimization during high-priced hours, which materially raised our realized price.

The hydro fleet also continues to capture merchant upside delivering an average realized price of $36 per megawatt hour, a 24% premium to the average spot price. Our merchant wind fleet realized an average price of $14 per megawatt hour which was impacted by increased thermal production and intermittent wind and solar generation. During the quarter, we also delivered approximately 900 gigawatt hours of ancillary service volumes at a 14% premium to the average spot price. Through effective fleet optimization and meeting hedge obligations with purchase power, we consistently address the ASOs need for reliability products. We continue to have a strong hedge book to support our Alberta cash flows -- for the balance of the year, we have approximately 4,500 gigawatt hours of our Alberta generation hedged at an average price of $64 per megawatt hour, well above current forward pricing.

For 2027, we have approximately 6,600 gigawatt hours hedged at an average price of $64 per megawatt hour, also well above current forward levels. Looking ahead, we continue to expect the Alberta supply demand imbalance will correct later this decade with anticipated load growth. We believe we are well positioned to manage through the current pricing environment and to capture growth opportunities to drive long-term value creation for our shareholders.

Turning to the balance sheet. In June, Moody's reaffirmed our Ba1 credit rating with a stable outlook. And last week, S&P reaffirmed our BB+ rating while shifting the outlook to negative. We remain committed to strengthening our balance sheet through multiple levers, including asset recycling. In addition, the forecast tightening of the Alberta market and recovery of power prices along with the expected cash flows from Centralia after conversion will provide cash flow growth to further strengthen our financial position.

Overall, we are pleased with our year-to-date operational and financial performance across all our business segments, and we remain confident in our ability to meet our 2026 guidance range. Our contracted fleet strong hedge position and consistent optimization provide us with core cash flows even in a low merchant power pricing environment. The Colorado acquisition is not factored into our reaffirmation of guidance and upon closing, which is expected in the fourth quarter of 2026, will add to our financial results.

I'll now turn the call back over to Joel.

Thanks, Mike. This will 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 strategy as well as advancing our coal-to-gas conversion Centria toward a final investment decision, pursuing strategic M&A opportunities, and enhancing our financial strength and flexibility through disciplined capital allocation and cost control.

I believe TransAlta offers a compelling investment opportunity. We have operated a safe and reliable power generation fleet for over 115 years, providing strong and consistent cash flows. This strength is grounded in a diversified portfolio of hydro, wind, solar, storage and thermal assets across 3 countries that is enhanced by our industry-leading asset optimization and energy marketing capabilities. Our legacy sites continue to represent considerable and increasing value. We are proactively pursuing repurposing initiatives at these facilities to address the growing demand for reliable 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 shareholder value 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 for continued to return capital to shareholders.

And 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, and I'll now turn the call back over to Stephanie.

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

[Operator Instructions] Our first question is going to come from the line of Mark Jarvi with CIBC.

Just in terms of those discussions with the ASO and the unrealized assets, do you have any sense of when you might have clarity and just how that's impacting anything about getting from the MOU to a definitive agreement with Brookfield and CPP.

Yes. Thanks, Mark. It's Joel here. I would say there's ongoing discussions with ASO. And again, we are very encouraged as I mentioned in our prepared remarks, by the data center regulations that really turn over to the -- as to determine what is underutilized capacity here as it relates to our -- really our gas-fired steam units -- so again, we're working with them very collaboratively here as we move forward. I would say with the MOU and the definitive agreements that we have with CPPI investments in Brookfield, those continue to advance as we highlighted when we announced the MOU back in February. So again, working alongside those 2 parties, and we continue to remain very confident in our ability to bring forward our data center option here later in the year.

So the expectation is a matter of months? Could it be a couple of quarters before you have clarity on the underutilized assets.

Hard to say. We can't really speak for the ASO mark, but we are actively engaged with them. So we're hopeful it will be in the next quarter or so, but we can't speak on behalf of them as to the timing.

And then obviously, that might influence how you think about scaling beyond the 230 megawatts. So if that drags on a little bit, hopefully, it doesn't. Would you look at moving to like FID on the first phase of the 230 megawatts from Phase 1 allocation and then subsequent scale-up after that through a follow-on agreement? Or is there a way to sequence sort of, I guess, moving through FID?

I think that's very possible here, Mark, that we would look to that. Again, and it's really up to us along with Brookfield and CPPI to determine that. But -- as we said before, 230, we were very pleased with that in the Phase I allocation and then looking forward to what -- how we can build upon that -- so I'd say that there's a possibility here that, that could advance the 230 before the remaining here with the underutilized capacity.

Our next question is going to come from the line of Maurice Choy with RBC Capital Markets.

Just wanted to touch on any updates you have on the asset recycling initiatives that was mentioned earlier to reduce debt? Where are some of the things that are influencing the timing and perhaps selection of some of these assets for sale?

Yes. Thanks, Maurice. We are very active. We have a few that are well underway. Obviously, we can't give everything away here as we're in processes, if you will. I think what you'll see going forward here, Maurice, just given the amount of opportunities that we see going forward, whether it's a central coal-to-gas conversion, AI data centers, M&A opportunities and then further kind of organic growth in our portfolio that we're seeing that I think portfolio rotation will become more active here. So we do have a few processes underway. I can't say anything more, but we are certainly very active in that space right now.

Looking forward to hear more of that. And if I could just finish off with just a more broad discussion about for power prices. I think over the last few weeks, since all these announcements were made. We've seen oil prices move up a little bit, particularly for 2029. Yet it still is below the $80 to $120 million range that you laid out at Investor Day. You mentioned at the start of the call that you've seen a lot of positive developments in the province thus far. So just curious as to what else you're expecting to hear in the coming months that would prompt the forwards to rise into your projected range?

First of all, Maurice, when you look out further, like the Cal 28 and Cal 29, there isn't a lot of liquidity. Generally, when you look at kind of forward pricing you're 12 to maybe 18 months at best. And when I look at Cal 29 today, I think it's marked around $81. So it is actually in the range of that $80 million to $120 million that we highlighted at Investor Day. And certainly, we've seen an improvement in those forward prices since even the announcement with Meta around their data center project with Connecticore and Pembina. So we remain very encouraged by that.

I think for the market, as we move forward here, just getting further kind of clarity around the ramping of the load growth will certainly support further the forward pricing. So again, when I look at where we are today for Cal 29 from where we were at Packet Investor Day at the end of March, we've certainly seen an improvement there. But I would expect that over time, as the market has better visibility behind kind of the load ramp. If you will, that will then further support these forward prices and could even go higher.

Maybe on that last note and a quick follow-up here. Obviously, we know where 1 is in the province, but also historically, when we had, I think it on to 2023 when we had triple-digit power prices that led to the regulator looking more into the industry. In this world of affordability, like is there such thing as a balanced number where pretty much everyone is happy.

Yes. When you look at the -- again, the con or the cost new entry that you referred to, and I know that, that was something that was highlighted with the recent announcement from Pembina Connecticor kind of in the low 100s, if you will which completely makes sense, right, given the cost of new build that we're seeing today relative to even where we were back in 2021 and 2023 as a reference where we saw triple-digit pricing. Again, this, I think, is where it's really important to have kind of legacy generation like we have with our gas-fired steam units to help support the infrastructure buildout that we've talked about that, that pricing would be below cone. But what you're seeing here going forward is the market will continue to tighten -- we're not seeing much by way of new supply, but we're obviously seeing load growth coming, whether it's organically in the province as we highlighted at our Investor Day back in March, along with Phase 1 here -- so we can't say exactly where that price point would be.

But I think when you look at Alberta relative to other jurisdictions in North America, we remain very cheap given the surplus generation that we see here. And again, I think it really supports why legacy generation should be utilized just given that it is at a price that is below 1 that we're seeing today. But going forward, it will be -- what it will be, if you will, as it relates to if there's new generation required and given the cost of that new generation to ensure that the generation provider is earning a full return of on capital. The price will be what it is. And so again, I can't say exactly where that price point would be where there was maybe some kind of I think, concern around power prices overall for consumers.

The other thing to remind yourself is that when you look at Alberta, when you look at the average power bill, roughly 1/3 is really the price of the electron and 2/3 is really through the transmission and distribution costs. So to the extent you see additional load come, what you'd hope to see is that the transmission and distribution costs are kind of butter spread more evenly given the additional load here. So that has to be taken into factor. It's just not the cost of power at the end of the day that impacts consumers. It's all these other costs as well.

Our next question is going to come from the line of Robert Hope with Scotiabank.

So I appreciate the commentary on the asset sales potentially strengthening the balance sheet with an acknowledge that you may be limited on what you can say. But that being said, how do you think about an asset sale program when you have quite a large uncertainty out there regarding the Brookfield Hydro option and the potential for it to top up and provide what could be a significant amount of capital for TA.

Yes, Rob, I think it's both. When we look at how we further strengthen the balance sheet here, we certainly factor at some point in time, we can't predict when, but the adoption that Brookfield has to convert into the hydro here in Alberta. That's 1 piece of it and certainly would only get the cash infusion that would come in from a potential top-up, but also $750 million of debt that would essentially come off the balance sheet as it relates to the rating agencies. So that's 1 important factor or a lever, if you will, to strengthen the balance sheet. But I think it's all of it. It's also doing additional asset sales because what we're seeing there is just tremendous opportunities for our company. As I mentioned earlier, you think about the Central gas conversion has been 1 the M&A opportunities that we're seeing out there, like we did with the Colorado acquisition here just over a month ago, along with just other kind of greenfield opportunities that we're seeing in our portfolio that might be further down in the decade, if you will, that will require capital.

So certainly, there's no shortage of uses of capital, if you will, so as we look at how we can strengthen our balance sheet, provide incremental cash to the balance sheet, it's obviously Brookfield conversion is factored there on top of asset recycling.

Appreciate that. And then maybe just going back to some prior commentary on the BYOD process as well as the commentary on repurposing some assets. When you think about your asset fleet in Alberta, how do you think about the decision tree of using, we'll call it, your steam conversions on an interim basis as a bridge to, we'll call it, a larger brownfield expansion of your project? And how do you work through the uncertainty of you don't quite know what the ACA will ultimately land on.

Yes. I think part of this is, first is really landing on how much capacity as you said, of the gas-fired steam units that we can use or would constitute underutilized or bring your own generation, if you will. That's the first part here that is part of that decision tree -- and so obviously, there can be a wide range there, given that we have a very sizable gas-fired steam fleet here. And as I mentioned in my remarks, the capacity factor has been around 20% as it relates to 2025. So we do see excess capacity there that could be used as bring your own generation. And what I really like about that is for the data center or AI infrastructure build-out is, as you know, the cost of new build is just so expensive today, and the supply chain constraints are so challenging that using these units to support the AI infrastructure build-out will then lead to new build sometime next decade because these units won't run forever.

So it is in a way kind of like a bridge. I don't like to use that term, but that's kind of what this would be is that you get the AI infrastructure built in the province, supported by our existing gas-fired steam units. And then at some point in time, we would look to then repower those units so they can run for decades after that. So that's -- again, I see this is where it's very compelling for Alberta as it relates to the fact that we do have surplus generation. The supply chain constraints that we see that this fits really nicely that we could use this gas-fired steam units but then there would be a new build down the road that would be underpinned by long-term contracts with our customers.

Our next question will come from the line of John Mould with TD Securities.

Maybe just a follow-on on that last question. On the repowering projects that you have and I guess, pole as well on the greenfield side, I guess how active are you on those in terms of costing activities, planning, just to be in a position to proceed rapidly with those. If there is some kind of meaningful load growth that drives the need for those? Or should investors really think of those as more of a longer-dated option into the next decade, depending on how -- like possibly well into the next decade, you flagged the time line of the coal gas retirements in the past. Like just in terms of maybe meeting the provinces, load growth more on a long-term basis.

Yes, John, when you look -- when you reference Flipp and KPL and SUN5, the total is just over 2 gigawatts I'd say there's still a lot of work going on today. It's still very early days. But again, you can see as part of our path forward here. First step is utilizing the underutilized capacity we have with our gas-fired steam units. That makes the most sense and then look to potentially build out these sites, if you will, next decade. So it's not something that we'd look to be building tomorrow, so we don't need to. The most effective way is to use the gas-fired steam units, they're the most cost effective, and it's all about speed to power too, for AI infrastructure -- the assets are there. As you know, the gas is there, the transmission is there, the waters there. Everything is there. So use those first. But knowing, again, as mentioned earlier, they're not going to run forever.

And then look to these sites like whether it's WipK1 or SunFas we talked about, as to repower down the road. So that's kind of -- it's kind of a stage process here. So it's certainly something we're not looking at doing tomorrow. This would be next decade. But the work is underway now because these take a long time, right, to do all the planning, the stakeholder engagement, all those things that's underway. But we do have a bit of time here because we view really repurposing our gas-fired steam units is the way to go.

And then maybe just on your hedges, you layered on about, I think, 20% or so incrementally just in terms of volume for next year. What kind of appetite are you seeing from customers to contract at more normalized pricing levels versus holding on to something more like the spot exposure today? And just in terms of how that contributes to your ability to add more meaningful length to your hedges between now and the end of the year?

Yes. We've -- John, obviously, we always remain very active as it relates to our matching our hedge portfolio. Roughly half of the portfolio is our C&I business, which is -- think of those as almost like 3-year contracts that continue to roll kind of every year. And those tend to transacted a bit of a premium over where you would see like the forward pricing. So the team looks for opportunities here where there's a nice spread that they see that they go, we're going to lock in these prices. So I'm very encouraged by what the team has done so far -- if you look at 1 of our slides, when we show that for next year, we have around 700 gigawatt hours already hedged at $64, again, well above where we're at today. When we look at kind of spot pricing, and that's due in large part to our C&I business, along with adding financial hedges where we can.

So this is something that it's a real core competency, if you will, of TransAlta that they look for these opportunities to kind of lock in when they can. And I expect that will continue to roll in hedges here going forward. And I can't say how much, but they will find opportunities. And again, a large part of that is due to the C&I book that we have.

Our next question is a follow-up question from the line of Mark Jarvi with CIBC.

Just following up on the unutilized assets. If you got a meaningful amount granted by the ASO like a gigawatt or more, would that likely be used to scale up increased opportunities around key pills? Or are there conversations opportunities to look at another site like Sundance?

Right now, Mark, we are focused around key pills that depending on what the ultimate number is that we certainly have the land there. The gas supply is there. The transmission is there to support additional build-out. So if you talk to a or even higher. Certainly, that could be supported around the Key pills facility.

Our next question is going to come from the line of Patrick Kennedy with National Bank Capital Markets.

I know you guys are still working on the Class 3 estimate for the Centralia Unit 2. But just wondering if perhaps there's been any progress with potentially tapping into more gas supply and looking at repowering Unit 1, how we should be thinking about the timing of that opportunity? And maybe a comment on how those brownfield returns might stack up to, say, Alberta greenfield or other U.S. M&A opportunities?

Yes, Tod. When we look at with Centralia, as you highlighted, we are working toward the Class III estimate, everything is on schedule such that we'll be in a position to have that by the end of the year. It to be then on track to make the FID very early in 2027, again, subject to the permits that are required both for ourselves and obviously with PSC to get the WTC approval. So that work is well underway there at the facility. It is -- when you look at the returns, I mean, hard to beat. As we highlighted when we made the announcement for Centralia, we said kind of our estimate is a $600 million capital cost at a 5.5x build multiple. So obviously very attractive. I wish we have -- like any company wish we had more of those types of opportunities with those types of multiples.

So again, very, very attractive. And again, just shows the value of having legacy assets where you can either repurpose maybe extend a contract or what have you that offer a very compelling risk-adjusted returns. When you look at the gas supply, just recall that the gas supply for Unit 2, that's on for PSC as the customer to provide not only the gas but the transportation of that gas to the facility, and there is enough gas supply there. The gas line is around 1,500 feet away from the facility. So it is very close. As it relates to Unit 1, I think this is a longer-term option because we've been having discussions around that, but very, very early days that it would be very compelling given the -- where the location, given the transmission is there, the water is there. You are 85 miles south of Seattle.

So there's a lot of reasons why it would be very good to be able to expand that facility. It comes down to, again, gas supply. It's the Northwest Williams Northwest pipeline that is full today, but certainly something that we're talking to them on and then also just trying to find, obviously, a customer like a commercial arrangement. But again, very, very early days, and this would be kind of next decade, but we do see that there could be an option there, but I wouldn't put a high probability at this point in time. And the focus, again, is on getting Unit 2 to FID early next year and moving that project along to get it in service by the fourth quarter of 2028.

Okay. That's perfect. And then maybe just on the M&A front, obviously, I know you can't comment on specific opportunities. But just curious, after the Colorado transaction closes, how you might describe your wish list in terms of geography, asset type or technology, fuel supply. Just how you're thinking about maximizing the value of the portfolio going forward through M&A, whether it's capturing synergies across the portfolio or otherwise?

Yes, Pat, no. Again, we're very, very pleased with the Colorado acquisition. I think this is an acquisition that will serve our shareholders for decades to come, given the weighted average duration is 27 years. And as we've talked about before, the full cost pass-through that we have there. So a very low-risk investment for us that, again, in a core geography that now we have a presence in Colorado with these 2 facilities. So we're very, very happy with that. Going forward, though, the M&A strategy remains the same, focused on our 4 card geographies. So you have seen us transact the Heartland acquisition was here in Alberta -- had acquisition was in Ontario and then this most recent 1 in Colorado.

I would say with technology, we remain agnostic. It's all about the highest risk-adjusted returns. That's the key for us. And so it just so happens recently, it's been more in the gas-fired side of things. When you look at again Hue, you look at Colorado, you look at Heartland. But if there's opportunities in renewables, we're certainly looking at those as well. But again, it comes down to the highest risk-adjusted returns in our 4 key geographies. So we remain very active there but we're also conscious of our balance sheet and what we can do. And this is where, again, I think, as we talked about earlier, active asset optimization, if you were a portfolio rotation certainly would support those opportunities going forward. So it's really kind of more of the same, if you will, as it relates to how we look at M&A.

Our next question will come from the line of Benjamin Pham with BMO.

I want to follow up on our last question around your comments on risk-adjusted returns across the portfolio, including M&A. And can you pass a little bit because it sounds like if you're going on different risk profiles with an energy infrastructure that return spectrum most changed quite a bit, i.e., the Colorado transaction where it's long-dated cash flows and the return may be a different profile than maybe some later assets. Can you maybe put the bookends of the returns and how you adjust for the risk differences?

Yes. I'd say, Ben, when we look at the various opportunities, so I'll just give you some relevant examples here. You look at the Heartland acquisition, were not fully contracted, but substantially contracted here in Alberta, older vintage assets, and we did that at around 5.4x multiple. When you look at hot As, again, older assets, shorter contracts, but we believe we'll be able to recontract those assets for -- in 5-year increments. Again, we were able to acquire those at a lower multiple. When you look at Colorado, yes, it was a higher multiple, but it makes a lot of sense, right, that this is brand-new generation, 27-year contracts -- so we have to look at this on a kind of overall portfolio that you're going to get some at a lower multiple, and there's reasons for that.

And there's going to be some like Colorado, where it's going to be at a higher multiple that is fair value given, again, the vintage of the assets given the contracts and the nature of those contracts and the like. So when we look at our opportunities here going forward. You have to take that all into consideration. I think what was important for Colorado is I know some folks looked at really the multiple -- that's 1 way to look at it, but probably the best way to look at it is really the free cash flow yield. The free cash flow yield on that acquisition is approximately 13% and our free cash flow yield at TA is around 7%. So it's free cash flow accretive at the end of the day.

So for us, there's a number of ways we look at acquisitions, whether it's EV-EBITDA multiple to free the leverage that's on the acquired assets, if any, so there's kind of a wide range here. But I think -- and then you have to compare everything on a per share basis as well, too, right? So that we want to be accretive. At the end of the day, we don't want to do anything that is dilutive, and Colorado was accretive, as I mentioned. So everything has to stack up against -- on a per share metric basis. So hopefully, it gives you some context of how we look at things. Here, it really depends on the nature of the acquisition.

Okay. Got it. And can you comment really just with some of the credit rating updates, does that constrain your ability at all to your balance sheet to add on more M&A over the next 12 months? I can just pay your time.

Thank you. Ben, it's Mike here. Maybe I'll handle this one. Yes, so the negative outlook from S&P, we kind of view that as a temporary hurdle for us -- when you look at the soft Alberta power pricing market right now and Centralia being offline here as we progress that towards FID, our cash flows have come down. But we do see a glide path forward with the recovery of the balance sheet. And when you look at the Alberta forward pricing market, you're starting to benefit of that is obviously proceeds in the door helping the balance sheet.

So we see a lot of incremental things that will progress the balance sheet to a position where we want it to be in. In the meantime, is it hampering our flexibility, I would say, no, not really. The thing pursuing right now, we have the flexibility to operate within the bounds of our balance sheet. But we are definitely conscious of the leverage levels and how the rating agencies are viewing it. And we see that improving here over the next while and it's something we are actively working towards.

Okay. That's a quick 1 for me to squeeze if I may. You mentioned the work on the focus on details with respect to the data center opportunities. Can you remind me, when you went through the multiphase process with that asset, was it community engagement in well, I know it's industrial side and there's a plant there. Do you do that and work here just the community feedback and support or lack of support for site?

Yes, Ben. Whenever we have any investment that we make, we have community engagement our stakeholder engagement early on right at the development stage and really through the whole life cycle of the asset. So once the asset is developed and then operating -- we stay in the community. We remain very engaged with the community because again, we're an important part of these communities in which we operate in.

So when you look at Key pills, we are, again, very actively engaged there within the community. There is certainly a lot of support there at Key pills, just given the infrastructure is there today. It's been there for many decades. But we have to remain very active there and really bring our stakeholders along with us on this journey when we develop any project. And it's not only gets here in Alberta.

It's anywhere in which we operate stakeholder engagement is just critical and through, like I said, development and through the operating life of the assets. So again, we are very engaged there. It's really important that we are very transparent with our stakeholders, we have transparent communication. It's really important that we have that because these are our stakeholders. And so we want to make sure that we are communicating with them, we're listening to them, understanding what their needs and their concerns are because it really is almost like a partnership then the day when you are putting infrastructure into a community. And I would say with key pills, we're certainly very, very active.

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. You may now disconnect. Everyone, have a great day.

Thank you. Good afternoon, everyone. My name is Stephanie Paris, and I'm the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome, and thank you for joining our call.

This afternoon, we announced that TransAlta has entered into a purchase and sale agreement to acquire 2 new natural gas peaking facilities near Denver, Colorado, along with a concurrent common share offering. We look forward to providing you more information during this call.

With me today to discuss this announcement are Joel Hunter, President and Chief Executive Officer; and Mike Politeski, EVP, Finance and Chief Financial Officer.

Today's call is being webcast, and I invite those listening in to view the supporting slides and press release that are posted on our website. A replay of the call will be available for a 12-month period through the link provided in the press release.

All information provided during this conference call is subject to the forward-looking statement qualification set out here on Slide 2. All amounts referenced during the call are in Canadian currency 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, Joel will provide an overview of the acquisition and Mike will speak to the financial benefits and funding plan. Given the concurrent equity offering, there will be no question-and-answer session following the remarks.

With that, I will turn the call over to Joel.

Thank you, Stephanie. I'm pleased to announce that TransAlta has entered into an agreement to acquire 2 natural gas-fired peaking facilities in Colorado. Both assets are fully contracted to investment-grade counterparties under long-term tolling agreements and include full cost pass-through of all operations and maintenance, fuel and capital expenses, which meaningfully reduced the risk profile of the acquired assets.

The transaction valued at USD 1 billion is inclusive of the assumption of USD 750 million of senior secured asset level debt and USD 250 million to be raised via concurrent bought deal equity financing for CAD 350 million. The acquisition is expected to deliver immediate accretion to free cash flow per share, adding value to TransAlta and its shareholders. We expect closing to occur in the fourth quarter of this year following receipt of all regulatory approvals as well as Canyon Peak Power achieving commercial operations.

Together, the 2 facilities are expected to contribute approximately USD 80 million per year in low-risk, high-quality adjusted EBITDA to our portfolio. Additionally, there is upside potential through availability incentive payments, which reward strong operational performance. Given operational excellence is a competitive advantage of ours, we are confident in our ability to realize this upside.

We also expect to unlock synergies by bringing asset management in-house as well as realizing insurance benefits through the integration of these assets into our existing portfolio-wide programs. Additionally, we expect to generate tax efficiencies by leveraging our current U.S. tax pools. Collectively, these advantages enhance the acquisition's financial profile with mid-single-digit free cash flow per share accretion projected in the first full year of ownership.

The 27-year weighted average contract tenure represents a fundamental component of the acquisition's value proposition. With the addition of these assets, TransAlta's overall contractedness meaningfully increases and our average contract duration is extended, while also simultaneously reducing the average age of our fleet. Additionally, the comprehensive pass-through provisions for all fuel, operations and maintenance and capital costs, we have effectively mitigated the majority of associated risks.

With today's announcement, we are expanding our physical presence in the Western United States, a core geography for us by adding essential infrastructure to our portfolio that enhances reliability in the region. Our established energy marketing and trading operations reinforce our confidence in the region's strong fundamentals.

Notably, Colorado's growth is accelerating, driven by population increases, electrification and rising data center demand. Establishing a physical position near our U.S. head office in Denver provides a strategic platform for future opportunities in the region. This acquisition is consistent with our strategy and builds on our established track record of identifying value-enhancing opportunities that leverage our core competitive advantages. As we continue to evaluate our broader capital allocation strategy, adding stable operating assets like this delivers immediate cash flows to be redeployed into our most compelling growth initiatives, including the Centralia coal-to-gas conversion and Alberta data center projects. I am pleased to share that these projects remain our top priority and continue to make meaningful progress. We have a clear path to improving credit metrics and assets like these, immediately enhance our overall business risk profile.

The Colorado Gas portfolio consists of 2 new fully contracted facilities that together have a generating capacity of 318 megawatts. Mountain Peak Power is a 162-megawatt facility that achieved commercial operation in September 2025. The facility utilizes 6 GE gas turbines, which is a proven and reliable aeroderivative technology that TransAlta has an extensive operating experience with. The facility is contracted for 30 years through United Power, which is A-rated.

The contract is structured as a 100% fixed capacity with full pass-through of fuel, operations and maintenance and capital costs, providing a highly predictable derisked revenue stream. Project financing associated with the facility is USD 365 million at a 6.2% interest rate and is amortized over the contract life, eliminating any refinancing risk.

Canyon Peak Power is a 156-megawatt facility expected to reach commercial operation in the third quarter of 2026 prior to the close of the acquisition. It employs the same GE turbine configuration as Mountain Peak, ensuring operational consistency across the portfolio. Canyon Peak is contracted for 25 years to CORE Electric Cooperative, which is rated AA-. The same favorable contract structure will apply to this facility, 100% fixed capacity with full pass-through of costs. Associated project financing is USD 385 million, also at 6.2% and amortizes over the life of the contract.

Our disciplined M&A track record reflects a disciplined, criteria-driven strategy that has consistently delivered value for our shareholders, and this acquisition is no exception. When considering an M&A opportunity, it must be immediately accretive on a free cash flow per share basis, largely contracted with strong counterparties, not compromise our financial position and provide a platform for future growth.

Between the acquisitions of TransAlta Renewables, Heartland, Far North and now the Colorado Gas portfolio, we're adding assets at attractive risk-adjusted multiples and with high levels of contracted cash flow with optionality upside, all within our core geographies as discussed in detail at our recent Investor Day.

I'll now pass it over to Mike to discuss the details and metrics.

Thanks, Joel. I'm pleased to share some additional financial details on the acquisition. The transaction value is priced below the cost of new gas-fired peakers with none of the associated construction or supply chain risk. This is a critical point in today's environment where supply chain disruptions, labor shortages and permitting delays are pressuring greenfield costs and time lines.

On a Canadian dollar basis, the assets are expected to generate $110 million of adjusted EBITDA per year and $45 million of annual free cash flow which translates to a 13% free cash flow yield. As Joel noted, our return profile reflects upside from the utilization of our existing U.S. tax pools, insurance synergies and bringing operations in-house. We have the ability to capture operational incentive payments by realizing availability over 95% on an average basis across the 2 assets.

The acquisition meaningfully benefits our portfolio where our average weighted contract life increases from approximately 10 to 11 years from the addition of just these 2 assets and installed contracted megawatts moved from 50% to 52%. We will also see an approximate 10% increase in our adjusted EBITDA using the midpoint of our 2026 guidance as a base, adding scale through this transaction.

The total transaction value of USD 1 billion includes the assumption of USD 750 million of senior secured project level debt, which is fully amortizing over the contract duration and carries investment-grade ratings. The remaining value of USD 250 million will be raised via a concurrent CAD 350 million bought deal common share offering, which we announced today. The offering will also include a 15% over-allotment option, exercisable by the underwriters for 30 days after closing of the offering.

We will continue to actively manage our capital structure through multiple levers including active portfolio optimization and asset recycling opportunities, combined with the expected recovery of Alberta power prices and the return to service of Centralia. Credit metrics are expected to strengthen while our business risk profile is immediately enhanced with the addition of these contracted assets.

With that, I'll turn the call back over to Joel.

Thanks, Mike. I believe TransAlta offers a compelling investment opportunity. We have operated a safe and reliable power generation fleet for over 115 years, providing strong and consistent cash flows. That strength is grounded in a diversified portfolio of hydro, wind, solar and thermal assets across 3 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 initiatives 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. And today's announcement is very aligned with our strategic priorities. 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.

And 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.

In summary, today's announced acquisition is on strategy and consistent with our value proposition, providing a long-term stable cash flow horizon, attractive risk-adjusted returns and delivers immediate accretion, creating durable long-term shareholder value.

Thank you. I'll now turn the call back over to Stephanie.

Thank you, everyone. That concludes our call for today, and please visit our website for more information.

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. [Operator Instructions] Thank you. Ms. Paris, you may begin your conference.

Thank you, Shannon. 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 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; 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 made 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 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 $204 million, free cash flow of $102 million or $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 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, host our Investor Day, providing an overview of our strategy and context on the current and future operating environment, and 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 is the exclusive power insight 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 the process in the coming months.

In March, the U.S. Department of Energy issued another temporary order requiring Centralia Unit 2 to remain available for operation if needed for a 90-day period ending on June 14. 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 time line for a final investment decision in the first quarter of 2027 remains on schedule. In the quarter, We Achieved adjusted EBITDA of $204 million, a decrease of $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 $35 million, down $12 million compared to the first quarter of 2025 due to lower Alberta spot and hedge power prices, lower ancillary prices, reduced merchant volumes and fewer emissions credit sales to third parties.

The wind and solar segment reported adjusted EBITDA of $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 $93 million, $11 million lower than first quarter 2025, primarily due to lower Alberta spot and hedge 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 $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 $4 million to $17 million, primarily due to higher incentive costs and realized and associated with higher unrealized mark-to-market gains. And corporate costs of $37 million were 10% lower when compared to the first quarter of 2025.

In the first quarter, free cash flow totaled $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 $32 per megawatt hour in the first quarter, which was notably lower than the average price of $40 per megawatt hour in the first quarter of 2025.

The decline year-over-year was primarily due to a mild winter and the addition of new gas generation in the market. The gas fleet exceeded merchant market pricing by realizing an average price of $48 per megawatt hour, a 50% premium to the average spot price of $32 per megawatt hour.

The hydro fleet also continued to capture merchant upside, delivering an average realized price of $46 per megawatt hour, a 44% premium to the average spot price. The merchant wind fleet realized an average price of $20 per megawatt hour, 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 priced hedge commitments through power purchases when market prices were below our variable production costs. We benefited from approximately 2,400 gigawatt hours of hedges at an average price of $66 per megawatt hour, $34 per megawatt hour higher than the average spot price.

During the quarter, we delivered approximately 1,000 gigawatt hours of ancillary service volumes at a modest 9% discount to the average spot price. Through effective fleet optimization and meeting hedge obligations with purchase power, we consistently address the AESO 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 $64 per megawatt hour, well above the current forward curve of $41 per megawatt hour. 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 gigawatt hours hedged at an average price of $65 per megawatt hour, well above current forward pricing levels. As discussed at Investor Day on March 23, we continue to expect the anticipated increase in load will rebalance the current oversupply of generation in Alberta later this decade and drive opportunities for growth in the long term.

Last month, we announced the addition of 2 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 3 countries and 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 our 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.

And 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, and 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.

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

Maybe to start off with, and I know it's early days, but 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?

Yes, Robert, Joel here. 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. I can't give you a definitive time line 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. And then maybe moving over to the M&A market. It is highlighted as a strategic opportunity for 2026. Can you comment on 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?

Yes, 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 Canada, for example, most recently, we just announced the acquisition of Far North Power Corporation. We're seeing opportunities here and in the U.S., in particular, in the WAC. And it's across all technologies, whether it's thermal, wind, solar. It is quite competitive. So we have to remain very disciplined in how we approach M&A. And we kind of look at it through the lens, it has to be accretive to our cash flow per share.

I can't harm the balance sheet, we have to preserve our balance sheet strength going forward. So it has to be in strategy, and it has to be highly contracted. 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 contractedness over time.

So it's critically important that when we look at opportunities that it comes with a strong contract profile or at least a pathway to recontracting in the future. So I'd say the 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.

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

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

Yes, 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 senior management team here, Chris Fralick and Nancy Brennan, are here with me today, along with Jane Fedoretz, who's our Head of -- our Chief Administrative Officer; and Mark Flickinger, who is our Head of major construction projects.

So we have the right team in place. And 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. So 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 people in the field, wherever it's a very, very strong team of people that we have in our organization.

And it goes to my closing remarks that if it wasn't for our people, we wouldn't be able to execute day-to-day safely and efficiently with our operations or execute on our strategy.

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

Yes, Mark. So 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 with respect to M&A and kind of corporate development that they're very active right now. So that's certainly not going to slow down things at all as it relates to M&A.

And similarly, with the data center file as well that the teams are really responsible for delivering that report into Grant. So Grant, he starts today, is actively engaged with the team here, and 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 2 kind of executives like Mike and Grant to come in and offer their views and things 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. And the last question for me is just you brought the draft of Phase 2a. Just 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 the existing generation and can avoid costly grid upgrade charges. Just 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 gigawatts in Phase 1?

Yes, Mark, it's -- certainly, there's active dialogue between ourselves, the AESO and the government. And nothing has changed from what we highlighted at Investor Day on March 23 as we looked at our coal gas units here in Alberta, which is roughly 2.7 gigawatts of installed capacity that last year ran at around a 20% capacity factor. So we point to those units to say there is surplus capacity there. that could be used as I call it like almost like a bridge, if you will, for, call it, Phase 2 to new generation in the future. I think that's acknowledged at all levels that there is a spare capacity.

And I think 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.

So very active dialogue, and we know that the AESO wants to get it right. We understand that they are concerned about reliability in the province, but they also are -- they see the real opportunity here for data centers to come to the province. So active dialogue, as you can well imagine here, and we remain optimistic using our coal-to-gas fleet here going forward beyond Phase 1.

Would there be an expectation that you'd make some other commitments if you're going to 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 those are things that we do and we do have discussions that we do bring up here. We're trying to find a solution here where we see that there's, again, the surplus capacity and how best to utilize it to insure -- but to ensure that we improve the reliability, if you will, of the grid.

I think it's safe to say, though, that 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. And so when I look at our existing fleet, they're not going to be around forever. So if we can get data centers here in Alberta, then in all likelihood, we would look to deploy more capital in the province to support the needs of that load longer term.

So again, we remain encouraged by, again, what we're seeing from a policy standpoint. We remain encouraged with our discussions with our customers here that we're taking a very long-term view. And ultimately, if we can get to a point where we are building new facilities here, it would be underpinned obviously by a long-term contract with our customers if we got to that point.

Our next question comes from the line of Benjamin Pham with BMO.

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, you -- is TransAlta still sticking with that expectation for definitive agreements by end of the year?

Yes, Ben, that's what we're working toward. Again, things are well advanced. And 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.

And we are now, again, working toward various definitive agreements. And our expectation is it's going to be with 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. And then I wanted to ask on your MD&A package, you've broke 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 about 1.9 gigawatts. Is that mostly the Alberta redevelopment sites in there?

There is that there. We highlighted 3 sites in Alberta here with Keephills [indiscernible]and Flipi, that's part of it. And we are exploring opportunities south of the border as well in Wyoming and Arizona. Again, early days on that, but our corporate development team is looking for thermal opportunities there that would be considered greenfield.

So the key here is with the teams, and we talked about this last year when we outsourced really our renewables development to [ Nova Clean ] that the focus internally here for our team at TransAlta has been more on thermal here in Alberta and south of the border. And we have some opportunities as well in Western Australia that we're looking at.

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

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?

Yes, Maurice, what we meant by that is if you look at, again, our first quarter results that the average spot price being $32 per megawatt hour what we experienced in the first quarter here in Alberta and really in the West, if you will, taking into consideration in the Mid-C market is there was really no weather.

It was very mild, very benign. And 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's really put pressure, obviously, on our results here in Alberta for the first quarter. So that's really the headwinds that we experienced.

When you look for the balance of the year, as I mentioned in my prepared remarks, the forward right now, forwards are right around $41, kind of still within our range at the lower end of our range, if you will, in the guidance that we provided at $40 to $60 per megawatt hour for the year.

What gives us confidence, though, Maurice, right now is a couple of things. One, obviously, our hedges hedged at $64 here. For the balance of the year, which is very good. But also, we just look forward that there could be a weather event. And 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 those times in the market when it tightens up and pricing does spike.

So 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 $102 million. And again, we remain stated that our guidance for the year is in line with the midpoint that we talked about at $1 billion of EBITDA and $400 million of free cash flow.

That's great. And 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, there's a discussion about whether or not the forward curves are truly representative of what you think is going to occur. Could you just share your thoughts what you think about where the forwards are for those years if you think that's right or could go up.

Yes. Maurice, I think it's very similar to what we discussed at Investor Day that the forward curve today, when you look out to '28 and '29 is not reflected to what we believe. And I think what we pointed to at Investor Day is that between now and 2025, we see here in Alberta, just over 1 gigawatt of net change in load and due in large part, obviously, to Phase 1 being 1.2 gigawatts 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 potential unit upgrades at other facilities that obviously are not owned by TA and potentially a restoration of the inner tie that when you put it all together, we see that, again, as mentioned, this net load increase of about 1.1 gigawatts.

And we put that through the models, that would translate to power prices or forward prices in that kind of north of $85. And I think what we used in Investor Day was roughly $100 a megawatt hour by 2029. So nothing has changed with that, given that we do see the market kind of tightening up here over the next 4 or 5 years with not a lot by way of new supply coming.

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

Yes. 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 we recall in the MOU would be up to $130 per ton. I think the question is what's the time to get to there. That's the discussion obviously between the Alberta government and the federal government there.

So nothing has really changed for us. I mean it's -- we kind of -- we know if we look at the MOU, it's directionally positive, I think, for the energy industry overall here in Alberta. And we're awaiting the final outcomes of that like everyone else in that. But 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 MOU?

No. I don't believe so.

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

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. And I guess first part is how are you thinking about further firming those up as you're able to, just given where forwards are sitting relative to maybe where they might get to if there's a line of sight on material market tightening. And I realize that's a little inconsistent with when the load might arrive, but we've seen forwards move around pretty substantially on longer-dated expected changes in load.

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

Yes, John, I would say to you that as we look out to 2027 and beyond by focusing more on 2027, yes, we did add hedges throughout the quarter. Today, as I mentioned in my prepared remarks, we're around 5,500 gigawatt hours hedged at an average price of $65, again, well above where we're at on the forwards today.

If you look at the forward curve right now, it's around $46 just to put it into context. We have -- recall that with our hedging, it's not only financial. The large part of it actually is our C&I book. And these tend to be an average tenure of 3 years. And they tend to attract a premium over the forward given that our customers want that certainty for their 3-year period as it relates to the amount of generation they require.

So our team remains very active in that market. And 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 '28 and '29, 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. But I would say also that we saw forward pricing that is below where we expected 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 is reflective of where we think pricing will ultimately go to. And we've done this in the past, where a number of years ago, where we looked at the forward curve and we really looked at it and said the forward curve isn't reflective of where we expect pricing to go. So think of this back in really 2021, '22 and '23.

And we benefited from that, that we were a bit, I would call more open. And then similarly, the team saw a tightening or loosening in the market, if you will, there was going to be more supply really in '24 and '25 and became very active in the hedging. And thankfully, we did that.

And again, as I said earlier, we are hedged at $64 for this year. And last year, we were hedged at $71. And 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. So hopefully, that gives you some context around it. We are focused on '27 and really '28, '29 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..

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

Just back on the MOU Keephills outside of your commercial discussions. Just wondering if you could provide an update on where things are at with the site development plans and the permitting process. Maybe just comment on 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?

Yes. I would say to you, Pat, 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.

And obviously, we've got our allocation under Phase 1 here at the AESO, as you well know. So 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. And then on Centralia, just wondering if you had an update or any clarity on the mandate being potentially terminated or perhaps extended beyond mid-June. And I guess, if still online, if your team sees any opportunity to start generating some positive cash flow from the facility through the summer?

Yes. Pat, so yes, you're referring obviously to the 202(c) order that we received that's out to kind of, call it, mid-June. Obviously, TransAlta continues to comply with the order. We're also actively engaged both with the state of Washington and the DOE as it relates to the order.

It hasn't run thus far, and our expectation is that it likely will not run here through the order. Given that when you look at pricing in the mid-sea market, which today is around $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.

So we don't expect that the facility will run, but 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 the rate filing here back in the first quarter.

And we are doing the front-end engineering design work right now at the facility, which is good. To get to a final investment decision sometime in Q1 of next year. What we do know is Centralia is critical to the reliability needs in the market that everybody is in agreement that the coal-to-gas conversion is essential. And again, we have really good dialogue between the State of Washington and the DOE.

Okay. And then last one for me, Joel, just from a balance sheet perspective, as you navigate this weaker period of free cash flow in Alberta, while at the same time, 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 ensure a strong financial position and have some dry powder ahead of any future opportunities that might come along.

Yes, Pat, a couple of things I would just observe. First one, as we said at Investor Day is that our metrics, our debt to EBITDA being the key metric here can drift above that 4x, but 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, that will generate about $150 million per year of EBITDA for us starting really in 2029. So again, there is a glide path here that we see. But to your point around to create additional, I call it, 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 might look to rotate some assets here within the portfolio to create some of that dry powder given that we are seeing 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, aligned with our strategy, a highly contracted asset, we want to -- and 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.

And then on top of capital rotation, there was a transformative type opportunity. There's other levers that we can pull as well, including the Brookfield conversion here for the hydro assets that we have. That's one. And then you obviously have common equity for something that is transformational here. But again, any opportunities that we look at have to be accretive.

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. I'm the conference operator. And at this time, I would like to welcome everyone to TransAlta Corporation's Annual and Special Meeting of Shareholders. Thank you for joining us. Mr. Dielwart, you may begin your meeting.

Thank you. Good morning, fellow shareholders. Welcome to TransAlta's 2026 Annual and Special Shareholders Meeting. I'm John Dielwart, Chair of the Board of Directors. Today's meeting is being hosted virtually, which provides shareholders the ability to access and participate in the meeting regardless of their location.

While virtual in format, the meeting will be conducted in the same manner as an in-person meeting. There will be no management presentation following the formal business of the meeting. With me here today is Joel Hunter, formerly Executive Vice President, Finance and Chief Financial Officer; and effective today, President and Chief Executive Officer of the corporation, congratulations to Joel.

Also here with me today is Nancy Brennan, our Executive Vice President, Legal, External Affairs and Corporate Secretary. I now call this meeting to order. I will ask -- I will serve as Chair of the meeting, and Nancy Brennan will serve as Secretary. I will first address a few procedural matters for the meeting. Only registered shareholders who held shares at the close of business on March 12, 2026, the record date for this meeting or such shareholders' duly appointed proxy holders are entitled to vote or ask questions at this meeting.

To vote during the meeting, please use the electronic ballot that will appear on your screen in the online portal. You may begin voting now or at any time throughout the meeting. To ask a question, please enter it in the text box on your screen and follow the instructions in the online portal. Questions may be submitted now and throughout the meeting.

When submitting a question, please provide your name and indicate whether you are a registered shareholder or proxy holder. Responses to any questions not answered during the meeting will be posted on our website.

The Secretary has provided proof that the notice of meeting, management proxy circular, forms of proxies and voting instruction forms were mailed on March 31, 2026, to shareholders of record at the close of business on the record date. These documents and our integrated report containing our audited consolidated financial statements for the fiscal year ended December 31, 2025, made are also available electronically on TransAlta's SEDAR+ profile.

Gloria Gherasim of Odyssey Trust Company, TransAlta's registrar and transfer agent, will serve as scrutineer for the meeting. A quorum for this meeting is at least 2 persons present, representing at least 25% of the outstanding shares. The scrutineer has provided me with a preliminary report on attendance, which indicates that 63.55% of TransAlta's issued and outstanding common shares are currently represented at this meeting.

I therefore declare that a quorum is present, and this meeting is properly constituted for the transaction of business. A copy of the scrutineer's final report will be filed with the records of the meeting. We will address 5 items of formal business today, the details of which are provided in our management proxy circular.

Prior to moving to the first item of business and opening the polls for voting, I am pleased to report that we have received a sufficient number of proxies to carry each item of business, including the election of each nominated director. Nonetheless, we encourage shareholder participation at the meeting, and we will now proceed presenting each item of business so that it may be formally approved.

Before addressing our first term of business, the election of directors, I wish to take a moment to acknowledge Alan Fohrer and Candace MacGibbon, who are retiring from the Board this year. Alan and Candace have served on the Board since 2013 and 2023, respectively. During their tenures, Alan and Candace have each made significant contributions as directors and played an instrumental role in advancing TransAlta's strategy.

On behalf of the Board and TransAlta's management team, I wish to thank each of them and extend our best wishes for their future. I'd also like to acknowledge retiring CEO, John Kousinioris. John has been with the company in multiple roles, including General Counsel, Chief Operating Officer and for the last number of years, President and Chief Executive Officer.

He's been an integral part of the team as the company managed its way from predominantly coal-fired power producer to now an integrated renewables and thermal producer. John, thank you very much for all you have done for your shareholders. And I personally want to thank you for your help to me.

Moving now to the election of directors. Our 9 proposed director nominees are set out in the management proxy circular. These individuals are Brian Baker, Laura Folse, Joel Hunter, Thomas O'Flynn, Bryan Pinney, James Reid, Manjit Sharma, Sandra Sharman and myself, John Dielwart. Can I please have a motion to approve the appointment of our Board -- to our Board of each of the 9 nominated directors?

I move that the following director nominees be elected to the Board of Directors to hold office until the next Annual Meeting of Shareholders or until their respective successors are elected or appointed. Brian Baker, John Dielwart, Laura Folse, Joel Hunter, Thomas O'Flynn, Bryan Pinney, James Reid, Manjit Sharma and Sandra Sharman.

Thank you. May I have the motion seconded?

I second the motion.

Thank you. Nancy, have we received any questions or comments related to the election of directors?

No, Mr. Chair, I confirm we have not. Thank you.

Given there have been no comments, we will now proceed to a vote. You are now able to vote for or against each of the individual director nominees.

The next item of business is the presentation of TransAlta's annual consolidated financial statements for the fiscal year ended December 31, 2025 and auditor's report. These materials are included in the 2025 Integrated Report, which has been made available to shareholders, both on SEDAR+ and on our website.

The 2025 financial statements have been audited and approved by the Board. Ms. Anne Brockett, a representative of Ernst & Young LLP, is also available to answer questions with respect to the financial statements. Nancy, have we received any questions or comments on the financial statements?

No, Mr. Chair, I confirm we have not. Thank you.

Thank you, Nancy. The next item of business is the reappointment of TransAlta's auditors, Ernst & Young LLP. This appointment is for the upcoming year with the corresponding fees fixed by the Board. I will now ask for a motion for the reappointment of Ernst & Young LLP as TransAlta's auditors.

I move that Ernst & Young LLP be appointed as auditors of TransAlta until the close of its next Annual Meeting of Shareholders and the directors of TransAlta Corporation be authorized to fix their remuneration.

Thank you. May I have that motion seconded?

I second the motion.

Thank you. Nancy, have we received any comments or questions on this matter?

No, Mr. Chair, I confirm we have not. Thank you.

Thank you, Nancy. The next item of business is on an advisory basis, an ordinary resolution approving TransAlta's approach to executive compensation, commonly known as say-on-pay, set out on Page 39 of this year's management proxy circular. I will now ask for a motion to pass the resolution set out on Page 39 of the management proxy circular regarding TransAlta's approach to executive compensation.

I move that the nonbinding advisory resolution regarding TransAlta's approach to executive compensation be passed by shareholders of the corporation.

Thank you. May I have the motion seconded?

I second the motion.

Thank you. Nancy, have we received any questions or comments on this matter?

No, Mr. Chair, I confirm we have not.

Thank you, Nancy. The next item of business is an ordinary resolution to approve the increase in the number of shares reserved for issuance under the corporation's share unit plan. Full details on the plan and proposed resolution are provided on Pages 40 and 41 of the management proxy circular. I will now ask for a motion to approve the increase in the number of shares reserved for issuance under TransAlta's share unit plan.

I move that the ordinary resolution regarding the increase in the number of shares reserved for issuance under the share unit plan as set out on Page 41 in the management proxy circular be passed by shareholders of the corporation.

Thank you. May I have the motion seconded?

I second the motion.

Thank you. Nancy, have we received any questions or comments on this matter?

No, Mr. Chair, I confirm we have not. Thank you.

Thanks again, Nancy. This brings us to the end of the items of business for this meeting. Nancy, prior to the closing of polls, can you confirm if any questions or comments on any matter of business have been received?

No, Mr. Chair, I confirm we have not received any questions or comments on the formal items of business. Thank you.

Thank you, Nancy. There being no further business, I now declare the polls open for voting -- sorry, the polls for voting to be closed. We'll just wait a brief minute for the tabulation. I am pleased to advise that we now have received the voting results. I am pleased to report that each of the resolutions on the items of business discussed at today's meeting have been approved by the shareholders. A press release and report on voting results on all items of business will also be publicly filed after this meeting on SEDAR+. That concludes the formal business of the meeting. Accordingly, I now declare the formal portion of the meeting to be terminated. The meeting is now open for questions. Nancy, do we have any questions?

I confirm we have no questions. Thank you, Mr. Chair.

There being no questions, I now declare the meeting terminated. I wish to thank our shareholders for their continued support of TransAlta and your participation in the meeting today.

Good morning, everyone, and welcome to TransAlta's 2026 Investor Day. My name is Stephanie Paris, and I'm the Vice President of Investor Relations and Corporate Strategy. We're very pleased to have you all here with us in Toronto and joining us virtually as well. Today's presentation is being recorded, and a replay of the event and transcript will be posted on our website.

As we begin our session, please note that this presentation includes forward-looking statements which are subject to risks and uncertainties, many of which are set forth on this slide. I encourage you to read the statements at your own convenience. This presentation also contains references to non-IFRS measures, including adjusted EBITDA and free cash flow. Such measures may not be comparable to those presented by other companies. Please refer to our MD&A for more information. All amounts referenced during this presentation are in Canadian dollars, unless noted otherwise.

With us here today is a subset of the broader leadership team of TransAlta, including John Kousinioris, President and Chief Executive Officer; Joel Hunter, Executive Vice President, Finance and Chief Financial Officer; Chris Fralick, Executive Vice President, Generation; and Nancy Brennan, Executive Vice President, Legal and External Affairs. We're excited to discuss our strategic plan, the role of our assets in Alberta and key priorities across our business. Following the presentation, we'll commence a question-and-answer session.

And now I'd like to welcome John Kousinioris, President and Chief Executive Officer, to the stage. He will begin our presentation today with an overview of TransAlta. Welcome, John.

Thank you, Stephanie, and welcome, everyone, and thank you for being with us today. I'd like to begin our presentation today by outlining for all of you, our 7 key takeaways. First, TransAlta is uniquely a proven operator across diverse technologies. And that operating track record matters in a world where reliability is increasingly scarce and increasingly valued and customers seek customized hybrid solutions to meet their needs.

Second, the outlook for power has never been stronger. And we believe that both existing and new generation will play a critical role in meeting future load requirements. Demand is rising, and companies like ours have tremendous opportunity in meeting that demand while balancing affordability, reliability, sustainability and speed to power.

Third, we're focused on the right geographies for growth, markets where we see supportive fundamentals and where our capabilities translate directly into competitive advantage. Fourth, we believe we're best positioned to capture expected load growth in Alberta. We have the right assets, the right optionality, the right market expertise to benefit as fundamentals tighten later in the decade.

Fifth, Centralia is essential for reliability in Washington State. It is a critical asset that supports the region and underpins stable value creation for TransAlta. Sixth, we have a demonstrated track record of disciplined, accretive M&A. We've executed value-creating transactions that have strengthened our platform and improved our long-term cash flow profile.

And finally, we're entering this exciting period for our industry and our company from a position of strength. Our strong financial position and disciplined capital allocation give us the flexibility to drive attractive long-term growth. These points underpin everything you'll hear today: a resilient base business, embedded upside and a company that's purpose-built for the power markets we're operating in now and the ones we see ahead.

I'd like to now shift to a brief overview of TransAlta and its accomplishments. We're proud of our company and all that it has accomplished since it was founded 115 years ago. While TransAlta has evolved and grown, we have consistently generated the electricity required to power and empower our communities and economy. It is a time of great opportunity for our company, and we are well positioned to capture it.

We have 4 key competitive advantages that drive our success, enable us to meet the unique needs of our customers and create value for our shareholders. They also differentiate us from other power producers across the regions in which we operate.

Our advantages include exceptional safety performance and operational excellence, with extensive experience across diverse fuel types, including wind, hydro, solar, storage and natural gas. We operate one of Canada's largest wind fleets, Alberta's largest hydro fleet and one of Canada's largest gas fleets.

We have leading optimization, energy marketing and trading expertise that provides extensive in-house market intelligence and forecasting capabilities, especially in our core market of Alberta.

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 affordable and reliable generation in the jurisdictions in which we operate. And we have a solid financial foundation and the financial flexibility to pursue our growth strategy and generate value for our shareholders.

In each of our core jurisdictions, we see unique and growing power needs where customers are looking to partner with someone with in-depth experience in the realities of the energy evolution. They know that we can help them achieve their goals as a proven and trusted partner. Half of our generating fleet is contracted with a weighted average contract life of 9 years, and over 85% of our associated customers are backed by an investment-grade credit rating, highlighting the quality of our cash flow profile.

Our contractedness has been enhanced by our recently acquired Ontario and Heartland facilities, which increased our contracted generation in Alberta to the point where it now exceeds our merchant production. Our contracted assets span regions and fuel types and provide us with stability, diversification and clear visibility to earnings and cash flow. And we're focused on increasing our contractedness over time to further enhance the size and stability of our cash flows and enable disciplined growth for the benefit of our shareholders.

Our contracted portfolio is not just diversified across technologies, but also across industries and customers. Since 1911, we've been supplying contracted power in Alberta and have diversified our customers across multiple regions. In Alberta, we provide behind-the-fence power and steam to large E&Ps and integrated supermajors.

In British Columbia, Washington State, Ontario, Quebec, New Brunswick, North Carolina and Western Australia, we provide contracted power to local and state-owned utilities. In Ontario, we power manufacturing, refining, health care and industrial operations. And in the U.S., we have long-term renewable power purchase agreements with hyperscalers.

Our contracted portfolio and associated customer base is the foundation of our business, and we're in the process of expanding our portfolio to power data centers in Alberta. The North American power industry consists of a complex mix of regional markets, each with their own set of rules, regulations, products and generation and transmission systems.

For over 30 years, we have traded power across North America, and energy marketing has become a strategic and core capability of our company, providing us with detailed knowledge, market expertise and customer relationships across Canada and the United States.

Our marketing and trading business delivers 3 key value propositions to our company. First, our optimization and energy marketing teams are responsible for hedging, marketing, dispatching and scheduling our generating fleet in Alberta, Ontario and the United States.

This includes dispatch and capacity scheduling for our gas, hydro and wind fleets. The team also manages the procurement of gas, pipeline transport and short-term gas storage for our generating facilities.

Second, the team supports our growth initiatives by providing market intelligence and due diligence support. Our energy marketing team has established relationships with hundreds of participants, power pools, customers and suppliers across North America. And finally, our energy marketing team has accountability to generate a stand-alone gross margin separate and distinct from the value that they provide to our asset businesses.

We have a strong focus on physical power trading as a baseline strategy, but also trade products such as transmission and congestion rights and engage in both term and real-time trading. Our gas desk provides physical and financial gas positions and supports our understanding of the natural gas pipeline network given the interplay between gas and power in the North American marketplace.

And our emissions desk manages the sales of all credits generated by our assets, the obligations incurred in our physical power flow business and enters into stand-alone proprietary emission strategies, including the trading of carbon products ranging from offsets to allowances to renewable energy credits in markets across North America.

Over the past 5 years, our energy marketing team has delivered almost $800 million of adjusted EBITDA to our business, separate from the value created by our asset optimization activities, and is a consistent cornerstone of our business. Our company has been transformed since 2020, when we were the largest coal-fired generator in Canada.

Since then, we have evolved our strategy significantly while remaining focused on prudent growth and expansion to strengthen TransAlta and create long-term value for our shareholders.

Since 2020, we have converted 1.7 gigawatts of coal-fired generation to natural gas-fired generation in our core market of Alberta, acquired a 122-megawatt fully contracted solar portfolio in North Carolina, built 250 megawatts of contracted wind facilities in Alberta and a further 500 megawatts of contracted wind facilities in Oklahoma.

Built a hybrid solar and battery solution for one of our long-standing customers in Australia, expanded and strengthened our position in Alberta with the addition of Heartland's 1.7 gigawatts of gas-fired assets, which are flexible, competitive and serve leading industrial companies in the province; acquired a 310-megawatt largely contracted gas portfolio in our core market of Ontario; and significantly simplified our corporate structure by bringing TransAlta and TransAlta Renewables back together, and in the process, increased our economic ownership in 1.2 gigawatts of high-quality contracted generating assets.

More recently, we've continued to advance the company with the 700-megawatt tolling agreement signed for our soon-to-be natural gas-fired facility in Centralia and the memorandum of understanding we entered into to provide up to 1 gigawatt of power to support data center development in Alberta.

This transformation has significantly strengthened the strategic positioning of our company since 2020 by increasing the size of our contracted fleet by 158%, significantly increasing our adjusted EBITDA and free cash flow, improving our operational performance with outstanding safety outcomes, fleet availability in excess of 90% and emissions reductions of 55% and realizing a total shareholder return of 108%, reflecting the increasing value of our company and the opportunities ahead of us.

Increasing our contractedness, simplifying our corporate and financial structures, strengthening our balance sheet, repositioning our Alberta business and extracting value from our legacy generating facilities has created a solid foundation for TransAlta. Our company is in a great position to succeed with considerable optionality in its generating base and an exciting growth outlook.

Before turning the session over to Joel, I'd like to acknowledge that this will be my last Investor Day with all of you. It has been a privilege and an honor to lead TransAlta since 2021, working with an incredibly committed and talented team. I'd like to thank all of you for your support as we collectively work to advance the 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 our strategy during this exciting time of opportunity.

I'll now pass the floor over to Joel to provide you with our strategic overview.

Thanks, John, and good morning, everyone. The power industry is entering one of the most exciting chapters in decades, and we're in excellent position to participate. The opportunity set for power generators today is unprecedented. We're witnessing structural change due to the acceleration in demand for electricity across our markets, with no signs of slowing down. Electrification, data centers and industrial reshoring are key drivers, and the grid requires reliable, affordable power to meet it.

TransAlta is well positioned to grow in our core geographies where supply and demand fundamentals are tightening, market design is evolving, and our existing assets, optimization capabilities and development platforms give us a clear advantage. We have a well-defined strategy with a clear purpose.

We aim to maximize value from our base business while selectively investing in growth opportunities that enhance returns, contracted cash flows and long-term flexibility. The combination of strong market fundamentals, advantage positioning and disciplined execution underpins our strategy.

So why are we so optimistic? Power demand is accelerating everywhere we operate at a pace we haven't seen in decades. In the U.S., peak load demand is expected to increase by 100 gigawatts over the next 5 years, driven by data centers, reshoring and electrification. Data centers alone now represent approximately 55% of forecast U.S. electricity demand growth through the end of the decade.

Here in Canada, we are seeing similar shift, as electricity demand is expected to grow by more than 60% between now and 2050, and regulators are reviewing data center proposals equivalent to powering roughly 70% of Canadian households. By 2030, data centers currently under review could represent close to 14% of total Canadian electricity demand.

In Western Australia, industrial electrification tied to mining and heavy industry are expected to drive electricity requirements nearly 5x today's levels. And so it's not only about additional megawatts, it's about when power is needed. Load growth increasingly requires 24/7 power, adding the need for dispatchable, firm capacity to maintain grid reliability.

Overall, across our core markets, demand is rising rapidly. Intermittency is increasing, and reliable generation is becoming more valuable. It's this combination that underpins the opportunity set that we're focused on. The evolving energy landscape offers a great opportunity for TransAlta that we'll pursue while balancing 4 key pillars: reliability, affordability, the rapid deployment of power and decarbonization.

In recent years, policymakers and industry stakeholders have placed increased emphasis on decarbonization that resulted in substantial investment in renewable infrastructure is essential for achieving long-term carbon reduction objectives. Due to the intermittent nature of renewable energy, there is increased focus on ensuring grid reliability, which is further heightened by rising demand from AI applications.

Coupled with the necessity to replace aging infrastructure, the imperative and rapid deployment of power solutions has become a central consideration. It's essential to ensure that power services facilitate our economic growth rather than becoming a limiting factor.

Major shifts in the macro environment are creating new opportunities for power producers. As demand for dependable and affordable electricity surges, supply chain pressures in making installed infrastructure and existing generation assets increasingly valuable. With the tremendous potential of AI and ongoing technological advancements, substantial investment in affordable and reliable energy infrastructure is necessary. Supporting this growth requires an all of the above strategy as it relates to forms of power generation.

In the case of TransAlta, this means additional investment in thermal generation and renewable technologies, including wind, solar, hydro and battery storage.

We remain confident in our ability to capture these opportunities, whether it's our cost-effective fleet, which ensures affordability, our diversified, flexible and responsive generation to meet grid and customer reliability, our legacy sites that can be repurposed quickly and economically, or our best-in-class marketing trading capabilities, TransAlta is well positioned to capture future growth.

Our growth strategy is focused on 4 key geographies: Alberta, Ontario, the Western United States and Western Australia. In these 4 regions, we have an ability to capitalize on our competitive strengths, including those arising from our well-established operations, our marketing and trading expertise and our deep understanding of local regulatory frameworks.

We base our strategy on long-term fundamentals and believe there are growth opportunities in these regions that ultimately delivers long-term shareholder value. Ontario presents promising opportunities for us, driven by increasing demand, favorable policy, nuclear refurbishments and the growing value of steel on the ground. With over 30 years of operational experience here and a diversified portfolio comprised of natural gas, hydro and wind facilities, we are well positioned to capitalize on these prospects.

Our assets offer strong recontracting and expansion possibilities, supported by adjacent land available for future development. We've also identified M&A opportunities that complement our existing fleet and align with our strategy to expand our contracted asset base, as evidenced by the recent acquisition of the Far North assets.

Electricity demand throughout the Western U.S. is projected to increase substantially over the next decade, driven by expanding data center infrastructure, reshoring, electrification and economic growth.

The rising demand coincides with the retirement of legacy thermal generation and the growing reliance on intermittent renewable energy sources, reinforcing the need for reliable and dispatchable power generation. The bilateral structure of the WEC supports development of new projects underpinned by long-term contracts.

We also see opportunities to capitalize on our expertise in energy marketing and trading, leveraging our long-standing experience and market intelligence to achieve a competitive advantage.

This year marks our 30th anniversary in Western Australia. Our fully contracted operations mainly support the mining sector, featuring distinctive remote islanded operations that deliver reliable power using a mix of natural gas, solar and battery generation. We believe hybrid energy solutions are increasingly needed to ensure stable and dependable power supply in the region.

There's also growing demand for expanded grid capacity to facilitate electrification and the shift from diesel to renewable and natural gas fired generation. Our ability to operate diverse technologies with a portfolio approach, coupled with our existing footprint, positions us well to participate in future growth opportunities.

Our largest and longest existing market is Alberta, which is unique in Canada as it's the only fully competitive energy-only electricity market, which has driven both innovation and volatility over the past decade. Knowing this framework, it's critical to understanding pricing dynamics, investment signals and the direction of the market.

Alberta is also one of the only markets in North America that is long power, which is one of its key advantages that has created the opportunity for growth in the data center industry that you'll hear more about later this morning from Chris.

As we approach the end of the decade, our strategy remains focused on maximizing both the value of our business and shareholder value. Now we'll accomplish this by focusing on a number of key priorities. Our first priority is to operate with excellence by ensuring safety, reliability, efficiency, actively optimizing our Alberta fleet and strengthening our financial flexibility through thoughtful capital allocation and strict cost management.

Our second priority is disciplined growth. We plan to advance our legacy projects, including Centralia and Alberta data centers, pursue value-accretive M&A and advance our high-quality, well-defined project development pipeline for long-term investment opportunities. Successful execution of our strategy will ensure our business remains resilient, geared for growth and responsive to the shifting energy landscape.

As we look out to 2029, successful execution of these initiatives is expected to have a meaningful impact on our adjusted EBITDA and cash flow. Completion of our Centralia Coal to Gas project in late 2028, together with improved supply and demand dynamics in Alberta, including our 230-megawatt Phase 1 allocation to Keephills, will have a positive impact on our financial performance.

Upside will be influenced by the pace at which 1.2 gigawatts of data centers are commissioned in Alberta, as well as other factors that Chris will address momentarily. It is also worth noting that increases to our adjusted EBITDA from value-enhancing M&A and greenfield developments are not included here. We intend to reinvest our expanding cash flows into attractive contracted opportunities that foster consistent and ratable growth for the long term.

I will now turn the floor over to Chris to provide additional details regarding our operating strategic priorities.

Thanks, Joel, and good morning, everyone. I'm Chris Fralick, the EVP of Generation. I'm pleased to discuss some of the essential elements of the business, starting with safe, reliable operations. Our operational performance is strong and continues to improve. We are unique in our ability to operate a highly diverse portfolio of technologies and to do so dynamically across our assets within a single market. That flexibility matters as system conditions change and reliability becomes increasingly valuable.

We're relentlessly focused on efficiency. Across the fleet, we're driving higher availability, better cost control and smarter deployment of capital to ensure our assets are operating where they create the most value. Flexibility, efficiency and disciplined execution are what underpin reliability and performance, you'll see reflected in our results.

Our operations fleet is founded on 4 core principles. Our hydro fleet, largely based on Alberta is unique and perpetual. These assets are critical in meeting peak energy needs and in providing grid support through its leading position in the province and ancillary services market, a market that we expect to grow as data centers come into the province and general load continues to increase.

Our gas fleet, consisting of our dispatchable and cogen facilities, these assets serve customers critical to the industrial sectors within our markets and also underpin the reliability needs of the grids. Our larger contracted wind and solar fleet, which provides predictable, stable cash flows and earnings, creating steady base to balance our merchant fleet. And our highly capable energy marketing and trading team, which I will speak about shortly.

Our company has a diversified and resilient generating fleet and leading trading optimization and growth capabilities, all guided by a single leadership team driving operational and financial synergies.

Let me share with you some of the key aspects that I believe differentiate TransAlta's operations and underpin our competitive advantage. At TransAlta, safety is our core value, and we live by the mantra, safe production is the only production. We firmly believe that a strong safety culture will result in a safer, more engaging and more successful business.

Highlighting our total recordable incident frequency, we are very proud of our results. 2025 was our best safety performance on record, and well below the industry benchmark for electric power generation. While these results are positive, we continue to work towards reducing the number of incidents we're focusing on our leading safety indicator of safety report frequency and the identification and mitigation of high energy hazards.

We leveraged thousands of reports to identify trends and share learnings across the organization in our pursuit of continuous safety improvement. Our environmental performance has been excellent, reflective of the emphasis that we place on prevention and strong job planning execution.

Our operational strategy is built on our rich history and our experienced team to deliver our current and future operational goals. From the foundation of a fleetwide asset management strategy that leverages real-time asset condition and market knowledge, we are able to optimize our portfolio in both the short and long term.

Our operations team has a strong culture of innovation with the belief that we can get a little bit better every shift. Through our efforts, we find ways to maximize operational efficiencies and reduce costs, which ultimately benefit our customers and deliver shareholder value.

Regarding availability, we have had strong performance, which we continue to optimize. There is a healthy tension between availability and ensuring that we are there to deliver reliable power when we are really needed. Being flexible is critical. Sometimes it doesn't make sense to pay to shorten an outage if the demand isn't there. Given the option of maximizing gross margin or pure technical availability, gross margin wins every time.

Looking deeper into our strategy to achieve reliable operations is how we think about operational excellence. Our ability to optimize our performance is built on a disciplined foundation of asset management. By defining what we are solving for, we tailor our strategy to the asset and develop plans to manage each site through its life cycle accordingly, which we execute through adherence to good operational work management and project management practices.

Our asset plans encompass economic factors, mode of operation, age, location and customer requirements, all of which is underpinned by a risk management framework and a focus on spend management. We further optimized our plans in real time by leveraging equipment condition knowledge by extracting insights from operational data analytics, which we align to real-time commercial conditions to inform optimal maintenance decisions.

I will now shift to our core region that has our largest operating footprint, Alberta. We're entering a period where fundamentals are beginning to shift. Load growth is coming from data centers, population growth and electrification. And over that time, the market will tighten as conditions increase the value of flexible, reliable and dispatchable generation.

While Alberta remains one of the only markets in North America that has long power today, it's also a volatile market. Success in this environment requires actively managing the portfolio, optimizing dispatch decisions and positioning assets to perform as conditions evolve.

This is where TransAlta is truly differentiated. We're the only operator in the province that operates across 6 technologies, supported by best-in-class optimization and trading capabilities. That diversity allows us to respond across different market conditions and positions us extremely well to recapture value and as the market tightens and growth accelerates.

The Alberta power market is one of the only fully competitive electricity markets in North America. It is also unique, given that over 50% of its load comes from industrial demand. The market has undergone significant change since 2020. Load has grown at a steady pace. However, supply has rapidly increased over the past 5 years, driving significant movement in the power price.

In 2020, coal made up over 5 gigawatts of the installed capacity, or approximately 1/3 of supply. And by 2024, the last coal-fired plant in the province underwent conversion to natural gas-fired generation. At the same time that coal units are being retired or converted, wind, solar and natural gas generation rapidly expanded, far outpacing the demand that the province required.

Given Alberta is the only merchant market in Canada, renewables were built to support sustainability initiatives in other jurisdictions without the corresponding need for physical power. The generation build-out has led to the current oversupply, which our team anticipated and hedged accordingly.

While near-term prices are suppressed and given most jurisdictions are short power, Alberta is seen as an attractive location for data center development, which would increase load and rebalance with supply.

Our generating fleet in Alberta is the backbone of our company and where we started at 115 years ago, supplying power to the City of Calgary from hydro on the Bow River. Over time, our fleet has evolved to be largely coal-based and has since undergone further transition, moving away from coal fired generation to being a diverse mix of hydro, wind, solar, storage and natural gas-fired generation.

The Alberta generation assets are managed and operated as an integrated dynamic portfolio. Our objective is to maximize value through a combination of hedging and contracting and realizing price premiums in the spot market by dispatching our gas and hydro facilities according to market signals at the times of highest value.

Our units are dispatched in real time based on the relative efficiencies and costs in order to achieve the highest margin in any given hour, respecting the capabilities of our assets and the unique characteristics of our hydro portfolio.

In addition to energy revenues, our gas and hydro assets are valuable providers of ancillary services and operating reserve to the AESO. So our team evaluates the optimal allocation of total generation capacity between these markets in each hour. We manage our sustaining capital and operating costs in an efficient manner. Across the fleet, we have held our cost per installed megawatt hour below the rate of inflation and flat through the balance of the decade.

Our commercial and industrial business acts as a trusted retailer to thousands of customers in Alberta and is an important source of liquidity as part of our portfolio management and hedging strategy to secure predictable revenue and margins. Through this business, we provide both standardized and bespoke energy solutions for our customers and other retail partners.

To enhance the competitiveness of our portfolio, our emissions trading desk continuously evaluates the optimal allocation of the emissions credits our renewable generation portfolio creates, whether to use for our own obligations or to execute transactions with third parties.

Longer-term strategic decisions are based on our internal analytical capabilities. Because of this internal strength, we can be confident in our decisions for capital planning, investment, M&A activity, and structuring long-term commercial partnerships.

By utilizing our portfolio approach, our Alberta business has performed exceptionally well. The optimization team forecast pricing trends years in advance using complex models that take thousands of scenarios of supply and demand and load into account.

At the beginning of the decade, we had lower hedge positions relative to now, as we saw tightness in supply and the potential to capture more high-priced hours. In 2023, we forecasted the overbuild of supply from renewables and new gas generation. And we started to lock in a higher hedge position at attractive prices for 2024 through 2027, which overall has resulted in strong realized pricing year after year.

Our ability to achieve higher realized pricing and exceptional ancillary service value is highlighted by our historical performance, where we have consistently realized premium pricing to spot. For hydro, our trading and optimization team has been able to strategically use our units to achieve higher-than-average pricing by saving water during periods of low demand and releasing it during periods of high demand.

For gas, this is largely due to the work that we have done to improve the flexibility of our units. While this premium may narrow in the near term during the period of oversupply. As loan growth increases, we expect our ability to optimize our premiums will improve.

This figure illustrates an example of being there when we're needed. This is from last September, showing how our fleet can respond to capture higher priced hours. During periods of lower renewable generation and hot weather, we saw more volatile and stronger prices.

Our dispatchable fleet, inclusive of our hydro and CTG units, were able to quickly ramp up and respond to market tightness when they were needed. Going forward, opportunities for flexible generators should increase as supply tightens over the next few years, and our units are situated to capture both the incremental volume and more frequent higher-priced hours while not running through periods of $0 pricing. This plays to the strength of our portfolio optimization and the unique capabilities of our fleet.

In August of 2025, the AESO announced its final design for the Alberta restructured energy market, or REM. The structure is consistent with our expectation and adds greater certainty to the market, something our diverse and dispatch regeneration fleet in Alberta is well suited to provide.

The REM is expected to be implemented in 2028, and we will continue our active engagement in the AESO consultation process, which is now focused on implementation. The revised market design favors dispatchable generation. And as I have illustrated, TransAlta's increasingly flexible approach makes us very well positioned.

We have calculated the reserve margin here in a similar format to the AESO. The reserve margin has historically shown the tightness, and more recently, the loosening of the margin based on the supply and demand dynamics previously discussed. Our forecast shows that the reserve margin will tighten and existing generation will become increasingly valuable.

We expect new firm supply in Alberta to be limited to less than 700 megawatts over the coming 4 years. Assuming the most severe single contingency or MSSC, is raised, along with a modest amount of additional new gas generation and intertie restoration.

The current oversupply and potential new additions will be offset by demand growth in the province, which we expect to continue to be 1.5% annually. Data center growth of 1.2 gigawatts is also included, based on the AESO's allocation through the Phase 1 Large Load Integration process. The timing of the data center load ramp will be variable and dependent on customer schedules.

We believe that the new load will outpace supply in the short term by a net amount of 1.1 gigawatts, leading to a tightening market. We assume that weather will be normalized, and the load does not account for hotter summers or colder winters. Due to the current oversupply in the Alberta market, our 2.6 gigawatts of coal to gas-fired facilities shown at the bottom of the slide do not run that often.

As evidenced last year, when they ran less than 20% of the time, despite being close to 20% of the total installed dispatchable generation. This is largely due to economics and the corresponding management of our Alberta portfolio.

The takeaway here is that while this demonstrates our coal to gas units have had a limited role in the current market, they are the main source of supply to benefit from incremental load coming to the province. Our coal to gas units are designed to operate as baseload and are fully capable of operating at 90% capacity factors.

Their recent performance has been driven by economic decisions, not capability, and any planned maintenance can be timed and scaled to meet market conditions. Most of our coal to gas units have regulatory end-of-life dates in the back of the half of the 2030s. And our team's ability to effectively operate the facilities has allowed us to run them through the peak lows and lows of the market throughout their operating lives.

Our internal modeling shows that the expected low growth will drive higher priced hours. TransAlta's merchant fleet is largely made up of dispatchable units such as our hydro fleet, our converted natural gas units and the peaking gas units acquired in the Heartland transaction.

They are operated by a capable team to capture these high-priced hours and provide reliability when supply gets tighter. Based on the previously discussed supply and demand assumptions resulting in a net change of load of 1.1 gigawatts through 2029, we expect the Alberta power price to recover through the end of the decade.

We have sensitized the impact on price by changing the net position by plus or minus 200 megawatts, as actual results will vary based on supply assumptions, weather and load ramp. We've assumed that the 1.2 gigawatts of data center load ramps through 2028 and is fully online by 2029. The actual load profile may differ materially from what is presented and is intended to illustrate what the potential impact could be.

We do not believe that the forward curve is yet pricing in the incremental load. In fact, we believe the current forward curve offers a decent representation of the power price outlook in the event that load does not increase for data centers.

However, we remain confident that data center load will come, beginning with our initial 230-megawatt allocation, as well as our peers' 970 megawatts. Longer term, we expect power prices to moderate in the $85 to $100 per megawatt hour range as supply and demand keep the market relatively balanced and incremental data center load is assumed to be matched with incremental supply.

That concludes my section, and I look forward to addressing your questions during the Q&A panel at the end of the presentation. I will now turn it over to Stephanie.

Thank you, Chris. We'll take a short break now before we continue, and we'll restart the presentation with our next session in about 15 minutes. Thank you.

[Break]

Welcome back, everyone, and hopefully, everybody had a chance to top up their coffee here for the second part of our presentation today.

So I'm pleased to share our growth priorities, which advance our strategy to the end of the decade. We're advancing targeted long-term growth opportunities where we'll leverage our existing infrastructure and market expertise to generate attractive risk-adjusted returns. Our data center strategy is intentionally structured to begin with a low capital cost investment that will produce contracted cash flows with high-quality counterparties. This opportunity will provide us with visible platform for future growth.

Centralia is also essential to our growth strategy and will be a major focus for us over the next few years. Once complete, Centralia would produce long-term contracted cash flows and support much needed reliability in the state of Washington, creating a strong foundation to fund future growth.

We also have a strong track record of M&A. Our 3 most recent transactions were immediately accretive, improve the quality of our cash flows and strengthen our platforms across our core markets. Taken together, our growth strategy prioritizes returns, maintains financial flexibility and consistently enhances shareholder value.

Now before diving into specific projects, I want to begin outlining our investment criteria, which serve as a basis for how we assess opportunities. Along with ensuring that projects are aligned with our strategy, we set hurdle rates for each technology type that offers appropriate risk-adjusted spreads over our cost of capital.

From there, we analyze factors that might increase or decrease the risk premium above these hurdle rates. We constantly weigh risk and return trade-offs and compare each project against other possible uses of our capital, which I'll talk more about later this morning. Importantly, we do not target a specific asset mix or a number of megawatts in the portfolio. Instead, we direct capital to the most value-accretive opportunities.

Our growth strategy is concentrated within our key geographic regions that includes Alberta, Ontario, the Western United States and Western Australia. In addition to pursuing opportunities at our legacy sites, we are advancing a portfolio of development projects designed to position TransAlta for future growth throughout this decade and beyond.

For example, in the Western U.S., we are exploring thermal opportunities in Arizona and Wyoming, and we're also progressing a firming expansion initiative at our South Hedland site in Western Australia, alongside several small-scale development projects. We'll provide further details on these early-stage projects as they evolve.

Now Alberta presents distinct geographic advantages for data centers. Notably, our natural gas fuel generation sites are situated near competitively priced and accessible natural gas supplies.

Furthermore, both the Alberta and federal governments have demonstrated their commitment to fostering growth in data center sector within Alberta, along with the AESO, as evidenced by its Phase 1 allocation for Large Load Integration and continued efforts with Phase 2.

TransAlta is well positioned to meet the increasing demand from data center customers by providing timely, cost-effective, reliable and sustainable energy solutions. And this is facilitated by our current portfolio, along with the advancement of our development projects.

In connection with our fourth quarter and year-end 2025 results, we announced an MOU with CPP Investments and Brookfield for data center development in Alberta, where TransAlta is the exclusive power and site provider. The Keephills site in Parkland County will see a phased development, beginning with a long-term power purchase agreement for approximately 230 megawatts and a potential expansion up to 1 gigawatt.

Keephills offers a compelling platform with extensive zone land, existing transmission, natural gas, water infrastructure and on-site generation. We look forward to partnering with CPP Investments and Brookfield, both experienced global infrastructure investors capable of delivering large-scale projects. As we advance our data center strategy, we'll endeavor to share as much as possible with you.

Now last year, we made meaningful progress on 3 natural gas generation projects in Alberta, creating low-cost options for future expansion. Although these 3 developments may not be required in the near term, having multiple alternatives available at this stage provides us with optionality and a competitive advantage.

Repowering initiatives for Sundance 5 and Keephills 1 originally launched in 2019, but paused due to market oversupply and economic challenges, remains viable. Each project has the potential to generate up to 800 megawatts of electricity by leveraging existing sites and infrastructure, potentially reducing cost and construction time lines.

Additionally, the Flipi gas plant acquired last year is an advanced stage project, is a 460-megawatt natural gas combined cycle power project near Rimbey, Alberta, which can be expedited subject to suitable contracting opportunities.

All 3 projects have been submitted as planned units according to Canada's Clean Electricity Regulations and have been filed with the Alberta Utilities Commission following active stakeholder engagement. Whether the CER restrictions are lifted or not, we have a relative speed to power advantage over other Phase 2 options. We are optimistic about these projects and their alignment with the Phase 2 Large Load Integration objectives, and we look forward to advance them, if supported by long-term contracts.

Now this slide explains the concept behind repowered combined cycle plant, providing insight into what our Sundance 5 and Keephills 1 projects might involve. Repowering coal-to-gas facilities involves adding new gas turbines and generators. Electricity generated by these new units is delivered to the grid via our existing transmission infrastructure.

Hot exhaust gases from the gas turbines are directed through heat recovery steam generators, providing steam. This steam then feeds into existing steam turbines and plant infrastructure, which maximizes energy output while lowering carbon emissions. A repowered combined cycle facility blends both newly installed and existing equipment, resulting in efficiency measured by heat rate that is comparable to that of a completely new combined cycle gas turbine plant and an overall lower capital cost.

In December, we signed a long-term pulling agreement with Puget Sound Energy to convert Centralia Unit 2 from coal to natural gas. The tolling agreement gives PSE exclusive rights to Centralia's 700 megawatts of capacity, energy ancillary services and dispatch rights at a fixed capacity price through 2044.

The USD 600 million conversion will reduce emissions by approximately 50% and anticipated build multiple of 5.5x with a projected completion date in late 2028 and an FID expected after receipt of all required approvals in early 2027.

Last week, the United States Department of Energy issued another temporary order requiring that Centralia remain available if called upon to operate for a period of 90 days through June 14. As required, TransAlta is complying with the order and continues to advance the conversion, in alignment with PSE, in order to achieve the targeted commercial operation date. The project has continued to progress, and I'm pleased to share that PSE recently submitted its associated rate case, advancing the regulatory time line on schedule.

Now the conversion of coal boilers to natural gas is technically a straightforward process, as demonstrated by the successful modifications completed at 7 facilities within our Alberta fleet, which will inform our approach to the boiler conversion at Centralia.

Transitioning to natural gas offers considerable advantages, including reduced overall cost, greenhouse gas compliance expenses and OM&A. The conversion involves replacing coal burners with gas burners and installing new gas field control systems. Gas boiler conversions also simplify the production process as they remove the necessity for major plant components such as rail-based coal imports, coal handling equipment and ash handling equipment.

Now Centralia's capital costs fall into 3 main categories. The largest is for the coal and gas conversion, covering items related to boiler burner upgrades, gas regulation equipment and fan upgrades.

The second category is related to planned life extension to maintain operations until 2044, including our auxiliary boiler and feedwater heater replacements, cooling tower rebuilds, software updates and installing a new natural gas supply line. The third category covers reliability and maintenance for major turbine and generator work, control repairs, boiler tube and piping repairs and safety valve overhauls.

Our engineering and construction teams are actively preparing to advance the conversion upon declaring an FID in early 2027, with a focus on maintaining the planned schedule and keeping capital costs as low as possible. So while our near-term development is focused on our legacy sites, longer term, we are advancing unique opportunities that leverage our competitive advantages and are grounded by our investment principles.

Our development platform is designed to provide strategic optionality and deliver ratable long-term growth. We are advancing smaller, high-returning power solutions in both Alberta and Western Australia that can augment our portfolio. In parallel, we have identified other legacy site opportunities in Western Australia, Ontario, Washington and Wyoming that leverage existing landholdings, infrastructure and relationships.

In the Western U.S. We are focused on gas development in states like Wyoming and Arizona, where demand is growing, planning processes point to continue to need for dispatchable generation and regulation is supportive. We also continue to value technology diversification as market conditions evolve. Our investment in Nova Clean Energy gives us exclusive access to a pipeline of renewables and storage projects, and we retain an option to acquire projects when returns meet our thresholds.

In Western Australia, our legacy sites give us a platform to grow. Customers continue to electrify both mining and other industrial activities, where reliability is paramount. We are well positioned to deliver firm, reliable power in a market where demand is growing and alternatives are limited. In total, this pipeline opportunity exceeds 5 gigawatts and gives us optionality and positions TransAlta for long-term ratable growth.

Now in addition to developing projects, we have a proven history of executing value-enhancing M&A. When considering an M&A opportunity, it must be immediately accretive on a free cash flow per share basis, largely contracted with strong counterparties, does not compromise the balance sheet and provides a platform for future growth. Our disciplined approach has translated into results following the transactions that we've executed since 2023.

Between the acquisitions of TransAlta Renewables, Heartland and Far North, we added assets at attractive multiples with high levels of contracted cash flow and with a clear recontracting and optionality upside. These transactions were immediately accretive, enhance our contractedness, and in the case of TransAlta Renewables, simplified the corporate structure, all while strengthening our balance sheet and financial flexibility. Going forward, we'll stay selective, contrarian when appropriate and focused on long-term value creation.

Next, I'm going to address the priority of enhancing our financial flexibility. Our financial position is strong and it gives us meaningful flexibility, and we're seeing attractive EBITDA growth potential driven by load growth in Alberta and Centralia. These opportunities are well aligned with our strategy where we are leveraging existing assets, improving contracted cash flow and supporting long-term capital allocation.

We have a diverse set of levers available to us, which I'll go over in more detail here shortly. This flexibility allows us to deliberately funding growth where risk-adjusted returns are compelling, strengthen the balance sheet and return capital to shareholders when appropriate. Taken together, our strong financial position underpins our ability to grow with discipline while maintaining flexibility across economic cycles.

These 7 financial principles underpin our decision-making process. We are committed to enhancing the contractedness of our portfolio, which will in turn improve our ability to finance assets with long-term capital.

While we're comfortable maintaining our BB+ rating in the near term, we recognize that achieving investment-grade status remains a key objective over the longer term. We value simplicity in our corporate structure, as it contributes both to value creation and operational efficiency.

Our approach to capital allocation will remain disciplined, focused on per share accretion, and we'll maintain strong focus on cost control. Active management with the capital markets will continue to be a priority, and we will continue to unlock value through portfolio management. Establishing these key guidelines upon joining the company was a priority for me, and I'm confident that its steadfast adherence to them will strengthen our financial position and enhance shareholder value over the long term.

Our balance sheet remains strong, supported by ample liquidity and a well-structured debt maturity profile. Last year, we amended and extended our committed credit facilities totaling $2.1 billion, enhancing our financial flexibility and capacity, and refinanced over $900 million of long-term debt in the Canadian and U.S. debt capital markets at favorable all-in funding levels.

We continue to target a long-term debt-to-EBITDA ratio of 3x to 4x, though near-term market conditions in Alberta and Centralia being offline during its conversion to natural gas may result in a modest deviation from this range, which is anticipated to be short-lived. We have a number of funding levers available to support our growth initiatives, which contribute to a stronger business risk profile and further reinforce our credit quality.

Turning to our capital allocation framework. Free cash flow serves as a foundation for our capital allocation strategy. Approximately 15% to 25% of our free cash flow is allocated to returning value to shareholders via dividends, with the remainder either reinvested in the business or returned to shareholders via share repurchases.

This year, we project a dividend payment of around $80 million, representing a payout ratio of approximately 20% based on the midpoint of our free cash flow guidance of $400 million. We anticipate that our payout ratio will decrease towards the end of the decade as free cash flow continues to grow at a higher pace than our dividend growth rate.

The remaining 75% to 85% of our free cash flow is earmarked for growth opportunities. We evaluate all growth opportunities on a per share basis to ensure we are creating shareholder value without compromising our balance sheet. Any opportunities must meet our hurdle rates, be underpinned by a long-term contract and be considered against alternative uses of capital.

Our approach represents a disciplined and measured strategy that aims at maximizing long-term shareholder value. Should suitable opportunities not arise, we will consider returning additional capital to shareholders through share repurchases.

Now I'd like to emphasize the effectiveness of our share buyback program over the past 5 years. Between 2020 and 2025, we returned CAD 366 million to shareholders via share buybacks, representing approximately CAD 1.25 per share. Returning capital to shareholders has been very effective, particularly during periods in which our share price experienced downward pressure.

Going forward, we will continue to carefully evaluate growth opportunities in conjunction with decisions regarding returning capital to shareholders.

Our 2026 adjusted EBITDA guidance is projected to be approximately CAD 1 billion at the midpoint of the range. Looking ahead, we anticipate that the Centralia coal-to-gas conversion will contribute an additional CAD 150 million in annual EBITDA by 2029, subject to FID and assuming commercial operation beginning in late 2028.

As discussed on Slide 44 regarding Alberta's net load growth sensitivity, a net change of 900 megawatts in load, inclusive of our Phase 1 data center allocation of 230 megawatts, could generate approximately CAD 200 million in incremental EBITDA relative to 2026 levels. Should load increase more rapidly or if additional supply is not made available, an additional 200 megawatts of net demand could contribute an additional CAD 150 million of EBITDA, with an additional 200 megawatts in a high-case scenario potentially adding CAD 300 million. It is important to note that TransAlta's exposure to near-term load growth impacts both volume and pricing, as our coal to gas units currently represent underutilized generation capacity within the province.

Our projected free cash flow by the end of the decade, combined with additional debt capacity, assuming an approximate 3.5x debt-to-EBITDA ratio, puts us in a strong position not only to meet our commitment to fund common share dividends and the conversion of Centralia, but also additional contracted investment opportunities.

For example, in the event there is a 900-megawatt net load change in Alberta, free cash flow for reinvestment combined with incremental debt capacity would be about CAD 2 billion. In the event that net load increases by 1.3 gigawatts over the period, we estimate an additional CAD 2 billion would be available for reinvestment.

As we look to redeploy these cash flows longer term, our strategy is clear. We are developing attractive, largely contracted opportunities that reinforce long-term shareholder value creation. We see multiple scalable reinvestment paths that will largely depend on opportunities that provide the most attractive returns.

We can advance up to 1 gigawatt of contracted data center load at our Keephills with an additional Phase 2 opportunities that could build upon that platform. We also have legacy site development potential, leveraging existing infrastructure to deliver speed to power and attractive economics.

Beyond that, we have a refined greenfield development pipeline that is focused on bilateral contracted solutions. Importantly, this capital redeployment will be executed with our long-term financial framework, developing ratable growth with a self-funding model that is scaled to our free cash flow and debt capacity. And finally, we retain flexibility for disciplined accretive M&A, in line with our strategy.

Our main source of funding continues to be operating free cash flow, but we also have access to several other attractive funding options. We have the ability to finance growth with long-term debt at either the corporate or asset level in both the Canadian and U.S. debt capital markets.

The amount of debt capacity is governed by our leverage levels, commensurate with maintaining our current credit ratings. We'll also consider selling noncore assets to raise capital for high-value opportunities and further narrow our focus in main geographic areas. We continuously review our portfolio and weigh the advantages and current market value of potential divestitures.

Partnerships, especially for large capital-intensive projects, are another lever. There's significant interest in our opportunities, and we currently have several partnerships in place. Potential partnerships will be based on our funding requirements, strategic fit and ability to diversify financial exposure across projects, portfolios or regions as needed.

After reviewing free cash flow, debt portfolio rotation and partnerships, we consider issuing common equity. Now this option is reserved for highly accretive opportunities such as M&A or major growth projects, depending on deal size and the time to cash flow. We always evaluate the impact on earnings and free cash per share when issuing equity, ensuring alignment with our strategy.

So turning now to our closing remarks before we open the floor to Q&A. Our strategic priorities are focused on maximizing value. First, we'll operate with excellence through safe, reliable and efficient operations, proactive optimization of our Alberta fleet, enhancing our financial flexibility through disciplined capital allocation and cost control.

Second, we will continue to grow with discipline through the advancement of our legacy site projects, including Centralia and Alberta data centers, pursue accretive M&A opportunities focused first in our core geographies and progression of high-quality refined development pipeline for long-term development opportunities. Successful execution of these priorities will ensure our business remains resilient, growth focused and aligned with the evolving energy landscape that ultimately delivers shareholder value.

Now I'd like to close by highlighting what I think makes TransAlta an attractive investment and great value opportunity. We are a safe and reliable operator with strong cash flow underpinned by our diversified hydro, wind, solar and thermal generation 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 on to repurpose to meet the growing need for reliable generation in the jurisdictions in which we operate in. We remain disciplined in our approach to growth, focused on delivering value for our shareholders as we look to diversify our portfolio within our core geographies and increase the stability and contractedness of our cash flows.

And our company has a sound financial position. 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. And finally, and most importantly, we have our people. Our success is based on our people, 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.

Now that concludes my prepared remarks, and we look forward to taking your questions. But before turning the floor over to Ben, I'd like to take the opportunity to thank John again for his leadership, strategic vision and his meaningful contributions to TransAlta. On behalf of the company, thank you, and we wish you all the best, John, in retirement. I'll now turn it over to Ben.

Thank you, Joel. Good morning, everyone. My name is Ben Harris, and I'm the Manager of Investor Relations. We'll now begin the question-and-answer period. [Operator Instructions] I'd like to invite John, Joel, Chris and Nancy to join us on stage now to begin taking questions.

All right. Rob Hope from Scotiabank. I was hoping you could add a little bit more color on Slide 70 on the potential EBITDA uplift in the data center scenarios. I just want to get a better sense of that incremental $200 million of EBITDA for the 900 megawatts. Is that also including the uplift in pricing across the portfolio, such as the wind and hydro? And then also, kind of what capture or increasing utilization of those coal-to-gas units are you implying there?

Yes. I'll start here, Rob, with it. Yes, it's -- that scenario assumes obviously the higher pricing that you saw in the graph that Chris walked everyone through, which we believe is not reflected today in the forward pricing. And particularly when you look out to 2028, 2029, that we see that forward pricing today is not indicative of where we see pricing going. And I think we have a demonstrated track record of really being accurate forecasters or where we see our pricing going within the province.

So it is reflective of the 900 megawatts, which really benefits our entire portfolio. Which, again, Chris showed earlier where our coal to gas units that are running less than 20% capacity last year. Certainly, we'll benefit from that. But we also see some uplift in our hydro fleet, although they're running near full capacity today at most times, but we do see an opportunity for our hydro fleet, even our wind fleet that's not contracted in Alberta to also benefit from the uplift that we'd see in pricing, along with what's in that number would be what we deem to be kind of the contracted portion from our Phase 1 allocation of 230 megawatts. So it's all kind of in that bucket, Robert.

All right. I appreciate that. And then maybe just as a follow-up question. If I take a look at Slide 48, which has your outlook for power pricing in Alberta relative to the forward pricing. So in 2028, we have, we'll call it, $75 to $100 pricing versus the forwards and 60s. Can you maybe talk to why you are above the forward market? And does that include some step in data centers in '28?

It does, Robert. If you look at where forward pricing was even towards the end of last year, it was in that kind of $80 range when you look out to 2028. And I think even north of $80 in 2029. There hasn't been a lot of liquidity in both CAL '28 and CAL '29 that we've seen this year. So it doesn't take much to remove the pricing. And there's a big bid/ask spread, if you will, in the forward curve right now.

I think what's really going to improve that forward outlook will be when you see further announcements for data centers. So obviously, there's a competitor out there that has 970 megawatts under Phase 1. When they get to a point of announcing their project, I think that's when you probably see the market get further comfortable to say this load is actually coming in the time period that we expect where we see the ramp-up, they occur in '27 through 2029. So again, I think that will be a key moment there.

And I think when we get to our definitive agreements, too, that for our 230 megawatts, I think, further support that confidence, if you will, in forward pricing. So again, we kind of go back, we spend a lot of time with our forecasting analysis that you heard Chris talk about. We met thousands of different scenarios.

We have a full team on this, and we firmly believe in our pricing scenario that we have on that chart today that's not reflective in the forward pricing due to that load liquidity that we're seeing. And I think, again, not a lot of visibility quite yet. Our confidence maybe from the market on the 1.2 gigawatts of load that's coming.

All right. Thank you, Robert. Our next question comes from an investor online. How does the company evaluate the potential of acquiring or creating a new gas asset versus a renewables asset?

Yes. It's about risk-adjusted returns for us. So we're not looking to say, okay, we have to have so many megawatts in our portfolio that's renewable or natural gas. It really comes down to what our customers are looking for and then evaluating, okay, on a risk-adjusted basis, what offers the highest returns for us and our shareholders.

We'd say right now, we're seeing more opportunity in natural gas, no surprise there, in all of our 4 geographies in which we operate in. As I mentioned in my prepared remarks, we see opportunities right now in Wyoming, in Arizona. These are still early days, but we are seeing real opportunity there and real support, both from a policy side and from customers to build new thermal generation there.

But at the same time, there's still interest in renewables. And this is 1 of the reasons why last year we made the decision to invest in Nova Clean Energy and really, I kind of say outsource our renewables development platform to them. They are increasingly focused on the WEC.

And for them, the benefit they get from TransAlta is not only financial support, but they get to really leverage our marketing and trading expertise in the region. So we could see real opportunities where we're actually coupling both thermal and renewable generation together in certain geographies like Wyoming, for example, or even maybe in Arizona.

So the question really is around how do you evaluate it. It does come down, like I said, to what customers want and where are we going to get the highest risk adjusted returns. We have to have a long-term contract where we get a full return of and on capital within that contract period.

All right. Our next question comes from Maurice Choy from RBC.

Maurice Choy, RBC. Two questions. I'm just going to ask it right away. First question is, can you give us a sensitivity? Not that we don't believe your assumptions, but if you give us every $10 change in the 1,100-megawatt scenario, what every $10 change means to your EBITDA?

And the second question is ultimately, to your point about free cash flow per share and that ultimately drives how you view things, could you give us an idea as to what that CAGR looks like and/or what drivers are changing between now and 2029? Because your $2 billion of FCF effectively triangulates to over 20% CAGR. So I wanted to make sure my math is right.

Thanks, Maurice. I'll address the second part of your question. First, you're correct in that high scenario when we showed you the EBITDA, that would translate to probably just over 20% CAGR, whereas at the low end, we're probably around 11% or 12%. And what's interesting there is very capital light for us, right?

Not a lot of spending on Phase 1 for 230 megawatts and really dependent upon where the market goes, and it tightens up, as Chris mentioned in his prepared remarks. So we do see a lot of upside in our EBITDA. It will ultimately depend on where the pricing settles in at, but just based -- we want to get to give you that range here today.

When we look at the conversion of EBITDA to free cash flow, I think the good rule is to use roughly 45%, maybe 50%. One example that I'll give you that's really interesting, though, is when we look at Centralia, for CAD 150 million, that effectively is all cash flow. There's no real interest associated with that asset. There's no project financing in place. And we have loss carryforwards in the U.S., such that our cash taxes remain very low. So that's a really unique opportunity where CAD 150 million of EBITDA essentially drops down to free cash flow. So that's part of the reason why I say that 45% to 50%. There's certain opportunities here like Centralia where it's actually going to be 100%. But when you put it all together, it's around that 45% to 50%.

When you talk about the sensitivity here, I think whenever we look at kind of our sensitivity for every kind of dollar change, it's anywhere from $2 to $3 of EBITDA for us. So think of it as $1 but 1 -- $2 million to $3 million of additional EBITDA. So to give you kind of that sensitivity in the model.

And I would say depending on our hedge position. So as we're more open, I would say, in the future, it might be a bit higher than that.

Good point, John.

Any idea how much higher?

Yes.

On that note, congrats, John.

No, no. I mean it's -- like all joking aside, it could be -- I mean, you could see sort of it nudging up towards 4, I would say, depending on where we are. But it also depends on fuel costs and whatnot, Joel, I would say. So it's a bit of a malleable number.

Yes.

Thanks, Maurice. Our next question comes from online. So in the past, TransAlta has been quite tied to its assets. So Joel, how are you thinking about asset rotation?

Yes. So we have 92 assets in the portfolio today. And in my remarks, I said that we would look to portfolio rotation here to fund future growth. For us, it really depends on the opportunities, what's the use of proceeds whenever we look to raise capital, whether that's in the debt capital markets or rotating capital, there has to be a clear use of proceeds.

We also consider the geography. We also consider the ability to recontract that specific facility and take that all under consideration. But I would say to you that we're very excited about the opportunities that we see in front of us both in the near term, but also in the longer term in our core geographies. So I do expect that portfolio management will become a more active funding lever, if you will.

The last point I would make is as we talk about our geographic focus, if you look at the map, we still have some assets that are kind of outside of that, if you will. So I think those would be assets that we would look at potentially monetizing here down the road. But again, it comes down to the use of proceeds here that -- we don't want to give up cash flows or EBITDA, if you will, and not have a go anywhere.

So we have to have clear use for that. And we are seeing that. When we look at, for example, Centralia, that spend will ramp up starting next year in 2028. So there could be a potential there, we would like to rotate assets. But right now, our funding model would indicate that our free cash flow and debt capacity should be able to fund that project.

Next question comes from Ben Pham from BMO.

First question for Joel is you've -- as you think about taking the baton from John, just thinking about 2029 numbers, you have a good sense of 2026. Can you give us some very high-level viewpoints of where you think the business is going to go?

I'm thinking particularly contracted percentages, geographic mix? And anything else you can share around that, just in terms of your ideal scenario where you see things going?

Yes, Ben, I think the first thing is being increasingly contracted is really important for us. That's going to add value for our shareholders longer term. What we're experiencing right now in Alberta, the volatility that we see by having a merchant component. We want to reduce that as much as we can over time.

So whether that's going to Centralia under a 16-year contract, for example, or as we look to development opportunities that we're seeing in Alberta, those would all be underpinned by long-term contracts such that over time, we see the merchant component of our portfolio decreasing.

So by 2029, ideally, if we could be at least 70% contracted, that would be ideal. If we could go higher than that, even the better. I think that translates into a stronger business risk profile, which may allow us to improve our credit ratings. But more importantly, I think we get a better valuation in the marketplace. And for us, providing that visibility and stability that we see in our EBITDA and cash flows going forward really helps us plan our strategy. So that's the key, I think, for us.

And as I look at taking the baton, the strategy remains the same here as we focus on our key geographies. So again, when we see opportunities in Alberta, we see opportunities in the Western United States. And in particular, as mentioned, right now, we're looking at opportunities in Arizona and Wyoming. I think having more physical assets in that region, given our marketing and trading capabilities is really important for us.

So again, we're very excited by that. We have a team that's in place. I was actually down in Denver a few weeks ago meeting with the team, and I was pretty excited by what I was seeing with those opportunities that they're identifying.

Early days, but we're looking at opportunities here in Ontario. It's great. We've got some existing assets like Sarnia, for example. There's an ability here to do more with that facility. Then in Western Australia, the same thing. The team sees lots of opportunities, albeit smaller scale, kind of in that 10 to 50-megawatt kind of size, but ultimately, they could get some larger opportunities as well.

So really having that discipline on geographic focus, underpinned by long-term contracts, that's what we're looking for here. But also being able to fund it kind of living within our means, if you will, with our free cash flow, debt capacity to the extent that we see portfolio rotation, we'll do that.

Okay. And maybe a related question. Now you have Alberta power mix, roughly, what, 50% today, give or take. And then you have some pretty good sensitivities you provided in terms of the uplift there, plus you got Phase 2 potentially. And I'm not against -- or I should say again, I'm thinking about that portfolio mix, Alberta increasingly shifting very high, looking at what I'm seeing today is -- how do you think about that -- I'm not made putting all the eggs on a basket is the right term for it, but is there a constraint or a limit of how much you want Alberta to be? Or do you feel that TransAlta is the best play in Alberta and do you want to move towards that path?

For us, I think what Chris identified is we have these underutilized assets today with our coal to gas fleet around 2.6 gigawatts that have potential upside here with really very little, if any, kind of capital investment for us. And so as you look out to 2029, yes, a lot of this is really due to power pricing in Alberta because the rest of our fleet is essentially contracted.

Our job will be to take those cash flows to the extent they are merchant and convert them into contracted opportunities. So yes, we see an opportunity here from 2026 out to 2029 that Alberta is going to generate a lot of that cash flow. But our job will be to take those cash flows and like I said, redeploy them elsewhere, even in Alberta.

So if we think about Phase 2, we identified the 3 facilities that we have real optionality there, whether the CER stays or goes, which I think is really critical here. We're talking up to 2 gigawatts there with those 3 facilities. The objective there would be to invest in 1 of those or maybe all of them over time, they have to be underpinned by a long-term contract. But you think about where we're at today, where it's all about speed to power. Right? So we got all this load growth coming in, looking for areas that are long power. Alberta happens to be one of them.

So we see there's a real opportunity to bridge, if you will, that growth with our existing units and knowing that we will eventually have to replace those units kind of post 2030. So that's what we're thinking about today. But when we make that capital investment in any new opportunity in Alberta, rest assured, it's underpinned by a long-term contract. So again, the objective here, Ben, is to, over time, take those cash flows and redeploy them elsewhere in cases -- maybe in Alberta, but underpinned by a long-term contract.

Yes. Our next one comes from Mark Jarvi in room.

So in the press release this morning talks about ratable growth, Joel. And you painted the upside of 2029. How do you frame this for investors beyond that in terms of how people can expect the growth to come from deploying free cash flow? There's not a big greenfield development pipeline in front of us here today. So is it largely M&A? Or how else do you instill confidence about the growth rate beyond '29?

Yes, Mark, I would say this is something that's really important for all of us is part of our strategy where we want to have, call it, ratable growth where you have that amount of your capital allocated toward kind of greenfield, brownfield development kind of every year, hopefully quick time to cash flow, depending on the investment opportunity that you're seeing. Complemented at times for M&A that is really viewed as being opportunistic, if you will, if you could feather that in as well.

But what's really important here is that we are -- always have capital spending, but assets coming into service, using that free cash flow from that investment opportunity then to redeploy elsewhere. So we talk about ratable growth. It's where we have projects like a Centralia. Maybe not that same size, but we're spending money every year, and you see assets coming into service kind of almost every year, that kind of regular cadence. That's what we refer to ratable growth. That's -- that's how I view it. We're not quite there yet, but we're working on it.

So when we talk about our pipeline, we said the 5 gigawatts because we're thinking about post 2029. We know with supply chain constraints and that it takes a long time to get anything built. We're fortunate, though, in this period of time with Centralia and what we're doing there. We're fortunate what we could see here in Alberta with the uplift in pricing, along with our Phase 1 230 megawatts, as mentioned, that we're good.

We're seeing this out to 2029, and so what do we do with that cash flow after? So we have to be thinking about that today so that ideally, we started spending money maybe later this decade, maybe get an asset in service in 2030, 2031. Maybe another 1 a few years later, that type of thing. That's that ratable growth.

But to the extent that we don't see opportunities that meet our hurdle rates, then we'll look to other opportunities, whether it's putting back to the shareholder. And that's what we did over the last few years.

We didn't have that ratable growth. So for example, in 2025, we bought back about $145 million of our shares at just over $10. That was good. That was the best use of the proceeds at that point in time. But ideally, we want to get to that more kind of ratable greenfield brownfield growth, supplemented at times with opportunistic M&A.

When should we expect you guys to be able to put that in front of investors, then?

I think it will be kind of continuous, Mark, as these evolve. So as we see these opportunities -- and we know that some things will be advancing, some will be pulled out and others go in. So again, part of our financial tenets is obviously active communication with the capital markets. We're out all the time talking to our investors.

I think it's important that we continuously update where we're at with certain projects that we're looking at. So a lot of them right now are still very early days, but we remain optimistic and the team is focused on that.

And what's key here is that we're not looking at like 30 different projects either. We're very focused on how we look at our corporate development. So laser focused, obviously, right now in certain regions I talked about in the Southwest or Wyoming. We're focused obviously in Alberta. We're certainly focused on Centralia.

And then the great thing is with Nova Clean is that we're kind of relying on them, they could start bringing projects forward as early as 2028. So -- but so long as it meets our expectations, we have right of first offer, if you will, on those opportunities as well. So we can't forget about that at Nova Clean. They've got over 2 gigawatts kind of very advanced in their pipeline right now that we could start having a look at to see if that's something we want to invest in or not.

And just going back to the power price outlook, you talked about your own vision, where it should be relative to the forward curve. And just how would you communicate that to the market in terms of where the minimum level of contracting would be then for TransAlta is 85%, sort of the low end of the range that you'd accept the price in a long-term contract?

Or would you be willing to flex a little bit on the low end, provide that contracting us, what you think is important for the cost of capital and the valuation of the stock?

Yes, Mark, I think it depends. I would say certainly not at 50%, but you're kind of right. I think around that 80%, 85% area would be ideal, if not higher. But I think it depends.

So for example, given our marketing and trading capabilities, for example, in the WEC, could we look for an opportunity whether it's M&A related or what have you, that, say, 75%, 80% contracted, knowing that there's probably some asymmetric upside? Given our capabilities, we would look to that. But I think overall, as we look at how we allocate our capital going forward, whether it's greenfield, brownfield or M&A, it has to be largely contracted.

Thank you, Mark. Our next question comes from online. What role does TransAlta see new technologies such as lithium ion batteries, hydrogen, where SMR is playing in its long-term plan?

So I'll start with that, and I know, Chris, you might want to chime in on this one. I think we remain open to all technologies. Our focus, obviously, is around thermal, hydro, wind, probably to a lesser extent, solar. We do have some investments in batteries, both in Western Australia and in Alberta.

Hydrogen is interesting. I think the economics are very challenging right now. We have looked at opportunities with hydrogen fueled power, for example, but it is just very difficult to make that math work. But these are still evolving technologies. And I think that we have to remain kind of open to that and keep our eye on the ball, which we do as these technologies evolve.

I think with SMRs, very interesting. I think that's going to take a lot of time. And I think we all believe that nuclear is going to play a very important role as it relates to power generation globally and obviously helping reduce emissions in providing reliable power.

It's not a business that we're in today. We've got enough on our plate as it is, but we certainly kind of keep an eye on how that technology emerges as well. So again, I think the key takeaway here is we look at all these technologies, it will be an evolving landscape, but the economics have to work before we look to deploy capital in them.

Great. Next question coming from online is what upcoming recontracting opportunities are you seeing for your Far North assets and any others?

Sure. So with Far North, there's 4 assets there, total around 310 megawatts. All 4 were part of the MT2 contracting, which actually takes effect in May of this year and runs through 2031. The plan would be then to look to extend those contracts beyond 2031 for another 5-year period. .

So again, when we looked at making that investment in Far North, we just stepped back and looked at the fundamentals. That's always key in making capital allocation decisions. And we looked at the fundamentals of Ontario and realize that gas is going to play a very important role here going forward.

We really like these assets, complemented with our largest asset at Sarnia as well to say that when we think about going out too from 2026 to 2031 and the recontracting that would occur there, we feel very good at this point in time that we'll have an ability, not only with those Far North assets, in particular, the Kingston and the Iroquois Falls assets.

Those are the 2 largest, Cochrane Casing, North Bay being smaller. We feel very confident that we'll have the ability to recontract those and similar to some of our other assets that we're seeing, whether it's Sarnia. We were part of the MT2 program here with our Wolfe Island assets just outside Kingston. So again, feeling very good right now in our ability to recontract those assets going forward.

I think maybe just to supplement that. I think we're also looking at Wyoming wind, as that PPA comes to an end, as being something that we could recontract. And Joel, maybe just chat a little bit about how we're seeing our merchant gas in Alberta potentially being available as a bridge, because I do see those coal to gas units as being sort of contracted in the context of a bridge for a data center opportunity.

Yes. That's a good point, John. So again, as we talked about earlier, and you saw in Chris' remarks, that our coal to gas units, which is roughly 2.6 gigawatts in Alberta, they're running at less than 20% capacity.

And knowing the supply chain constraints that we're seeing today and actually seeing really no new incremental supply coming into the province through the end of the decade, other than what Chris mentioned, where we see some operate in certain assets outside of our portfolio inside our company, along with maybe an increase in intertie that our assets could serve as a bridge to a new generation.

And so it's really important to note that, that we've got a lot of optionality there with our assets. We are actively working with the AESO and the Alberta government to really demonstrate that as we think about Phase 2 of Alberta data centers and what can be done there because it's all about bringing your own power, their generation, if you will, which we fully agree with.

But we think there's an opportunity to use these assets. And the benefit for the province there is these assets stay in service. They could serve a data center customer or customers, but at the same time, really ensure the reliability of the province, which is critical for the government to ensure that there is that reliability there.

At the same time, it actually could reduce costs overall. So when you look at your power bill on any given day in Alberta, roughly 1/3 of it is for the electrons and the other 2/3 are really for the transmission. So if you can have more load in the province, you could actually lower that part of the invoice for our bill for customers.

So it actually overall benefit, even though we might see rising power for the electrons, the rest of it actually comes down. So again, I think our assets in Alberta are a great bridging opportunity to new generation, next decade.

Final call for questions in the room. John Mould from TD.

I'd like to start with the Alberta data center levy. There were some second, I think it's fair to say around the changes that were made in the last couple of weeks. Just wondering how have those factored into your broader data center conversations?

Do you think the changes are sufficient? Do you see the levy at all as a headwind to seeing some real final investment decisions in the province on data centers this year?

Yes. I'll start, and Nancy, you want to maybe add a few things, or John or Chris. I'd say to you that, first of all, we're dealing with our counterparties being CPPI and Brookfield, right? So we're the power provider to them. And it's really up to them to say, okay with the levy. That's all, I think, been taken under consideration. We can't speak for them.

But this has been known for some time. And I think obviously, what we saw over the last few weeks that it got refined. Certainly, what we're seeing here is still Alberta is a very competitive jurisdiction as it relates to power supply for data centers. And we remain still very optimistic by it. And I think it provides clarity, which is good for our customers to understand what do those levies look like.

And maybe -- sorry, John, just to supplement that. Our discussions aren't just with CPPIB and Brookfield. As you can imagine, we're speaking to other parties too in terms of the future trajectory. The levy, I mean it'd be better not to have the levy, just being honest about that, but it doesn't seem to be a big determinant.

You know what I mean, one way or the other in terms of interest, I would say, for people from an inbound perspective coming into the jurisdiction. That hasn't -- like it hasn't featured all that high in those kinds of conversations, I would say, so far.

Okay. Great. And maybe just clarity on the assumptions that have gone into the big EBITDA slide. Just curious what you can tell us about, a, carbon pricing, how that's considered? And I appreciate there's a lot up in the air on that right now. And then b, how you've considered the potential for Brookfield to convert its securities into an ownership in your hydro assets?

Yes. So as it relates to carbon, we certainly see carbon pricing is staying, and it's going to rise gradually there as part of our assumptions. What we've heard with the MOU is that we see an increase up to $130. The question will be at what pace that grows at.

And well, I think we'll learn a lot more here they are not too distant future as it relates to the MOU between Alberta and the federal government around that. So we've made some assumptions around the carbon pricing staying. We're not being overly conservative in that. I think that the reality is that carbon pricing would stay.

With the Brookfield conversion, that became exercisable on the first of January last year, and it's exercisable to the end of 2028. And recall, what this is for is they provided $750 million to TA back in 2019 for a conversion into our hydro assets in the province. There are certain other mechanisms in place where depending on where our share price is at, where they could flex up to ultimately get to the 49% threshold that they could get to.

So if our shares are trading at $14 above, they can add an additional 10%, that would be a cash infusion to the company. Then if our shares are trading above $17, they could flex all the way up to 49%, depending on the trailing EBITDA over the last 3 years for the initial conversion of the $750 million.

So our assumptions right now is that it's probably sometime in '27, but '28 at the latest. We factor that into our model here that we haven't factored in the flex up, but just the initial conversion of the $750 million. The dialogue with Brookfield is excellent. We have 2 nominees in the Board of our directors, which are fantastic.

And so a really good relationship there. I think they still remain very interested in those hydro assets, but it's really going to be up to them as to when they want to convert, knowing that, that option expires at the end of 2028, so they might wait.

And John, just as you recall, the carrying costs of the debt and the preps that we have right now is broadly equivalent to what their ownership interest in the EBITDA would be. So it was broadly neutral on a free cash flow basis.

Our final question comes from online. How is your data center project with CPP Investments and Brookfield progressing? And does the strong progress underpin your confidence in your outlook?

Yes. The big accomplishment was the MOU being signed here that we announced earlier in the year, actually in connection with our Q4 and year-end 2025 results. And that was the culmination of a lot of work between ourselves and CPPI and Brookfield that really went back to probably the summer of 2025.

This isn't your standard MOU. It's a very comprehensive document. A lot of the commercial terms have been landed on with the MOU. So we're very pleased with the progress thus far. Next step is really to get toward definitive agreements here throughout this year. But I would say, so far, we're very pleased to have CPPI and Brookfield.

Again, 2 major players in this market that we feel very confident in and the fact that they would like to scale up to 1 gigawatt. The fact that they've selected our Keephills facility as their site and we're the power provider is fantastic.

So really, the next steps here is just to really work towards the definitive agreements through this year. And as more unfolds, we'll be sure to share that with you because I know a lot of people are really asking us a lot. We can't say a lot at this point. It's confidential, obviously, but as more unfolds here, we'll be sure to share it with you.

I'll now turn it over to Stephanie for closing.

Thanks, Ben. That concludes our 2026 Investor Day. Thank you all very much for taking the time to be with us today. If you have any further questions, please feel free to reach out to the TransAlta Investor Relations team, and have a great day.

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.