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 qualifications set out here on slide 2, detailed further in our MD&A, and incorporated in full for the purposes of today's call.

All amounts referenced are in 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 34 cents 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, hosted 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 and Brookfield for data center development in Alberta, with TransAlta as the exclusive power and site provider.

We continue to be actively engaged with our counterparties. We are making progress towards definitive agreements.

Last month, the AESO released an updated draft process for Phase 2A of their large load integration. It's important to note that this is draft, which does not represent final outcomes, and will continue to evolve as discussions progress.

TransAlta continues to participate in the AESO's Large Load Integration Working Group, and we look forward to hearing additional details as they finalize their process in the coming months. In March, the U.S.

Department of Energy issued another temporary order requiring Centralia Unit 2 to remain available for operation if needed for a 90-day period ending on June 14th. TransAlta is adhering to the order and recently submitted its request for reimbursement to the FERC for costs related to the initial order.

Progress continues with the conversion, and I'm pleased to report that our timeline for a final investment decision in the first quarter 2027 remains on schedule. In the quarter, we achieved adjusted EBITDA of $204 million, a decrease of $66 million compared to the first quarter 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 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 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 in 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 by-product sales.

Energy Marketing adjusted EBITDA decreased by $4 million to $17 million, primarily due to higher incentive costs associated with higher unrealized mark-to-market gains. Corporate costs of $37 million were 10% lower when compared to the first quarter 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 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-price hedge commitments through power purchases when market prices were below our variable production costs.

We benefited from approximately 2,400 gigawatt hours of hedges, an average price of $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 addressed the AESO's demand for reliability products. Looking at the balance of the year, we have approximately 6,900 gigawatt hours of Alberta generation hedged at an average price of $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-price, 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 23rd, 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 two new executives to our leadership team.

I'm pleased to welcome Mike Politeski to TransAlta as he takes on the role of Executive Vice President and Chief Financial Officer. Mike brings over 25 years of experience in the energy sector.

Over the course of his career, he has played a significant role in large-scale transactions and business transformation, and brings deep experience in investor relations, governance, and capital allocation. His established reputation as a strong, collaborative leader will be important as we pursue our strategic objectives.

I'm also pleased to welcome Grant Arnold as our Executive Vice President, Growth and Chief Commercial Officer. Grant brings over 30 years of leadership, commercial, and technical experience in the power generation and energy sector.

He has contributed to and led prior companies through significant growth, expanding their operating and development portfolios across North America. I'm confident that Mike and Grant will strengthen TransAlta's high-caliber leadership team, where together we will execute our strategy focused on disciplined growth and operational excellence.

I'll now turn the call over to Mike to offer a few words as he steps into the role.

Thanks, Joel. I've been impressed by what TransAlta has built: an operationally strong business with a clear strategy and meaningful opportunity set ahead.

I'm grateful for the warm welcome I've received externally as well as inside the organization, and I'm looking forward to working with all of you as we deliver on our strategy. My focus will be straightforward: I plan to continue to strengthen our financial position and support the execution of our strategic priorities.

We will operate with excellence, grow with discipline, and maximize value for our shareholders, all while ensuring we maintain our financial strength and flexibility through disciplined cost and capital management. I'll now turn the call back over to Joel.

Thanks, Mike. For 2026, we remain focused on the following priorities: improving our leading and lagging safety performance indicators while achieving strong fleet availability; delivering adjusted EBITDA and free cash flow within our 2026 guidance ranges; maximizing the value of our legacy thermal sites by advancing our Alberta data center project, as well as advancing our coal-to-gas conversion at Centralia toward a final investment decision; pursuing strategic M&A opportunities; and enhancing our financial strength and flexibility through disciplined capital allocation and cost control.

Stepping in as CEO, I believe TransAlta offers a compelling investment opportunity. We operate a safe and reliable fleet that generates strong and consistent cash flows.

That strength is grounded in a diversified portfolio of hydro, wind, solar, and thermal assets across three countries, and it's enhanced by our industry-leading asset optimization and energy marketing capabilities. Our legacy thermal sites continue to represent considerable and increasing value.

We are proactively pursuing repurposing opportunities at these facilities to address the growing demand for dependable power in our operating markets. Concurrently, we maintain 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.

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?

Morning, everyone. 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?

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. Can't give you a definitive timeline on that other than it is progressing as planned, and it is a very collaborative effort between both ourselves and Brookfield and CPPI.

All right, appreciate that. Then maybe moving over to the M&A market, it is highlighted as a 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?

Rob, I would say that there is certainly a lot of deal flow. We are constantly looking at opportunities really within our core geographies.

When we look at to Canada, for example, most recently we've just announced the acquisition obviously Far North Power Corporation. We're seeing opportunities here and in the US, in particular in the WECC, and it's across all technologies, whether it's thermal, wind, solar.

It is quite competitive, we have to remain very disciplined in how we approach M&A. We kind of look at it through the lens it has to be accretive to our cash flow per share.

It can't harm the balance sheet, we have to preserve our balance sheet strength going forward. Would say 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. It's critically important that when we look at opportunities, that it comes with a strong contract profile or at least a pathway to re-contracting in the future.

I would say to you overall, it's a very robust market, it is very competitive, and we just remain very disciplined in how we approach these M&A opportunities.

That's great. Appreciate the color.

Thank you.

Thanks, Rob.

Thanks. Good morning, everyone.

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

Mark, I would say that we have 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 Chief Administrative Officer, and Mark Flickinger, who is our head of major construction projects.

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 strategies here going forward. Very comfortable where we're at, Mark, here with our executive team, along with the rest of our employees, whether it's from VPs right down to people in the field, wherever, there'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. Then, with them settling into the seats, does that potentially push out any sort of M&A timelines out a few more quarters?

Then just curious 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 timelines before you get to definitive agreements, just given the fact that they've just come on board with the company?

Mark. To answer your first question with respect to M&A, no, it's actually very active.

Again, we have a strong team that actually reports into Grant, that's with respect to M&A and kind of corporate development, that they're very active right now. That's certainly not going to slow down things at all as it relates to M&A.

Similarly, with the data center file as well, the teams that are really responsible for delivering that report into Grant, Grant's even though he starts today, is actively engaged with the team here, and we certainly don't see any slowdown here with that, given the progress that we've made to date both with the MOU with CPPI and Brookfield. It certainly helps having two kind of executives like Mike and Grant to come in and offer their views and things and really support where we need to go with executing on these major initiatives, but certainly not slowing us down.

That's good to hear. Last question for me is just you brought up the draft, the 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 in the market with existing generation, and it 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 GW in Phase 1?

Mark, certainly there's active dialogue between ourselves, the AESO, and the government. Nothing has changed from what we highlighted in Investor Day on March 23rd as we looked at our coal-to-gas units here in Alberta, which is roughly 2.7 GW of installed capacity that last year ran at around a 20% capacity factor.

We point to those units to say there is surplus capacity there that could be used as, call it almost like a bridge, if you will, for Phase 2 to new generation in the future. I think that's acknowledged at all levels that there is the 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.

Very active dialogue, and we know that the AESO wants to get it right. We understand that, and they are concerned about reliability in the province, but they also see the real opportunity here for data centers to come to the province.

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 that would be required to facilitate more usage of the existing assets?

I would just say to you, Mark, that those are things that we do when 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, this surplus capacity, how best to utilize it 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 CER going away, that when we think about data centers here in Alberta, this is a long-term investment opportunity for both the data centers and for ourselves. When I look at our existing fleet, they're not going to be around forever, 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.

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 could 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.

Makes sense. Thanks for the time this morning.

Thanks, Mark. Thank you.

Hey, morning. First off, congratulations to Mike and Grant on their appointments.

I wanted to go back to the timing of the Alberta MOU. I wanted to clarify.

Is TransAlta still sticking with that expectation for definitive agreements by end of year?

Yes, Ben, that's what we're working toward. Again, the 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. We are now again working toward various definitive agreements, and our expectation is it's going to be in-year.

Just can't give you a definitive time around that, but it's certainly something that is a top priority for us, and I believe for our counterparties as well.

Sounds good. Then I wanted to ask next on your MD&A package, you've broken up your development pipeline between mid-stage and early stage, and I can see the mid-stage one includes mostly the Centralia conversion.

I think that's what's in there. Can you unpack the thermal more for us?

There's about 1.9 GW. Is that mostly the Alberta redevelopment sites in there?

There is that there, we highlighted three sites in Alberta here with Keephills 1, Sundance 5, and Flippy, that's part of it. 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. The key here is with the team is, 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.

Very good. Thank you.

Thanks, Ben.

Thank you, and good morning to everyone. If I could just start with something that, Joel, you mentioned on the press release specifically about how near-term headwinds in Alberta are materializing.

Wonder if you could just elaborate a little bit on that and what you meant on that.

Maurice, and good morning. What we meant by that is if you look at again our first quarter results, that the average spot price being $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 even 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 really put pressure obviously on our results here in Alberta for the first quarter. That's really the headwinds that we experienced.

When you look for the balance of the year, as mentioned in my prepared remarks, 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 of $40 to $60 per megawatt hour for the year. What gives us confidence, though, Maurice, right now is a couple 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.

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 near times in the market when it tightens up and pricing does spike. 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. Again, we remain convinced 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. Maybe just a quick follow-up since you discussed forward curves.

I recall that in the past when we start thinking about 2028 and beyond, there is discussion about whether or not the forward curves are truly representative of what you think it's going to occur. Could you just share your thoughts of what you think about where the forwards are for those years, if you think that that's right or could go up?

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 in '29, is not reflective to what we believe. I think what we pointed to in Investor Day is that between now and 2025, we see here in Alberta just over a gigawatt of net change in load, and due in large part obviously to Phase 1 being 1.2 GW of load in the province, along with just normal demand growth over this period of time of roughly 600 MW.

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, potentially a restoration of the intertie, that when you combine it all together, we see, again as mentioned, this net load increase of about 1.1 GW. When 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.

Nothing has changed with that, given that we do see the market kind of tightening up here over the next four or five years with not a lot by way of new supply coming.

Thank you. Just to finish off on the carbon tax policy, it feels like maybe we are approaching a point where we're going to hear something.

Just curious whether or not, A, what have you 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?

I would say to you again as much as we do right now with respect to the MOU and kind of that glide path on the carbon tax, which recall 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.

Nothing is really changed for us. We look at the MOU, it's directionally positive, I think, for the energy industry overall here in Alberta.

We're waiting the final outcomes of that like everyone else. Nothing has changed with respect to how we're thinking about things here in Alberta or in Canada in general today versus where we were even a month ago.

Is that a gating item for your MOU?

No, I don't believe so.

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

Thank you.

Thanks, Ben.

Oh Maurice.

Hey, morning, everybody. I'd really just like to focus on your hedge update.

You've added a meaningful volume of hedges for 2027 relative to what you disclosed at the end of year. I guess on 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 line of sight on material market tightening?

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. 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, 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 load growth we've talked about on the call today?

John, good morning. I would say to you that as we look out to 2027 and beyond, but focusing more on 2027, yeah, we did add hedges throughout the quarter.

Today, as I mentioned in my prepared remarks, we're around 5,500 GWh hedged at an average price 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.

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 tenor 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 relates to the amount of generation they require. 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.

I would say also that, if we saw forward pricing that is below where we expect it to be, based on my prior comments and what we said at Investor Day, I think the team would hold back saying that the forward curve isn't reflective of where we think pricing will ultimately go to. 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 that forward curve isn't reflective of where we expect pricing to go, think of this back in really 2021, '22, and '23.

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

Thankfully we did that, and again, as remember, as I said earlier, we are hedged at $64 for this year, and last year we were hedged at $71. Again, we have a strong team that is constantly looking at the markets and saying, okay, what's best here to either lock in at current forward pricing or remain open?

Hopefully, it gives you some context around it. 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 what we think it will go.

Okay. That's great.

All my other questions were answered, I'll leave it there. Congrats to Mike and Grant.

Thanks, John. Thank you.

Hey, good morning, everybody. Just back on the MOU at Keephills, outside of your commercial discussions, just wondering if you could provide an update on 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?

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. Obviously we've got our allocation under Phase 1 here at the AESO, as you well know.

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

That's great. 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?

I guess if still online, if your team sees any opportunity to start generating some positive cash flow from the facility through the summer?

Pat, yeah, 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 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-C market, which today is around $42 for the balance of the year, and looking at the variable costs of production from the facility, it's well in excess of that, we don't expect that the facility will run.

We are again complying with the order. I think it's also important to note that we continue to advance the coal-to-gas conversion with the facility and working with PSE.

We were encouraged by PSE filing for their 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.

Thanks for that. Then last one for me, Joel, just from a balance sheet perspective as you navigate this weaker period of free cash flow in Alberta, well, 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?

Pat. It's a couple of things I would just observe.

As we said at Investor Day is that our metrics, our debt-to-EBITDA being the key metric here, could drift above that four times. 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 along with having Centralia come online that will generate roughly $150 million per year of EBITDA for us starting really in 2029.

Again, there is a glide path here that we see. To your point around to create additional, I'll call, dry powder, we are looking at the portfolio.

We have a few things that we're looking at right now that we're very actively engaged on where we may look to rotate some assets here within the portfolio to create some of that dry powder, given that we are seeing, the question earlier around the M&A opportunities, it remains very robust. 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, and again, the risk-adjusted returns meet our hurdle rates, and it's accretive on a per-share basis, that we would look to pursue that opportunity, but at the same time, not overly stretching the balance sheet.

Then on top of capital rotation, if 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.

Then you always have common equity for something that is transformational there. Again, any opportunities that we look at have to be accretive.

That's great. Thanks, Joel.

Appreciate the comments.

Thanks, Pat.

Thank you, everyone. That concludes our call for today.

If you have any further questions, please contact the TransAlta Investor Relations team.