TransAlta Corporation (NYSE:TAC) Q2 2025 Earnings Call Transcript

TransAlta Corporation (NYSE:TAC) Q2 2025 Earnings Call Transcript August 1, 2025

TransAlta Corporation beats earnings expectations. Reported EPS is $0.13, expectations were $0.07.

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

Stephanie Paris: Thank you, Olivia. Good morning, everyone. My name is Stephanie Paris, and I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta’s Second 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 statement qualification set out 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, John and Joel will provide an overview of TransAlta’s quarterly results. After these remarks, we will open the call for questions. With that, I will turn the call over to John.

John Harry Kousinioris: Thank you, Stephanie. Good morning, everyone, and thank you for joining our second quarter conference call for 2025. As part of our commitment towards reconciliation I want to begin by acknowledging that our company operates on the traditional territories of Indigenous Peoples across Canada, Australia and the United States. We recognize the rich and diverse histories, cultures and contributions of the First Nations, Inuit, Métis, aboriginal and Native American communities. And it is with gratitude and respect that we thank the people who lived on these lands for generations for reminding us of the ongoing histories that precede us. TransAlta delivered exceptional results during the second quarter. Our Alberta portfolio’s hedging strategy and active asset optimization generated realized prices well above spot prices, while our Hydro and Wind assets provided significant environmental offsets to our Gas fleet’s carbon compliance obligation, highlighting the value of our diverse and integrated generating fleet.

We were also pleased with the performance of our contracted fleet, which exceeded our expectations. During the quarter, we delivered adjusted EBITDA of $349 million, free cash flow of $177 million or $0.60 per share and average fleet availability of 91.6%. We also successfully recontracted our Melancthon 1, Melancthon 2 and Wolfe Island wind facilities in Ontario. The new contracts will replace the current energy contracts for the 3 Wind facilities when they expire, extending their respective contract dates to 2031 for Melancthon 1 and to 2034 for Melancthon 2 and we’ll file it. Wholesale electricity prices in Ontario are rising, signaling a growing tightness in the supply and demand balance in the province, which sets our fleet up well for recontracting in the next decade.

We continue to engage directly with the government of Alberta and the AESO on the Alberta data center strategy and their approach to large load integration as well as the restructured energy market design or ramp. In June, the AESO released details on Phase 1 of its approach to data centers, which involve the allocation of 1,200 megawatts of system capacity to data center proponents within the province, including TransAlta. The AESO has now commenced work on Phase 2 of its data center strategy, which will establish the framework for incremental data center development in the province. The government of Alberta continues to express their commitment to the development of the data center industry in a manner that enables investment while maintaining an affordable and reliable electricity system.

And we remain confident that the province will develop a framework that will support our data center ambitions, which in turn, will see significant investment dollars come to Alberta. Turning more specifically to the work that we’re doing in realizing the value of our legacy generation sites. We’re pleased with the progress that we’re making on our Alberta data center strategy and the associated commercial negotiations, which now reflect the AESO’s approach to large load integration. The AESO currently expects demand transmission service contracts to be executed in mid- September, which will secure each proponent’s access to system capacity. We continue to work closely with our counterparties and are progressing towards the execution of a data center memorandum of understanding in relation to our system capacity allocation.

We’re excited about the data center opportunity in Alberta both for the meaningful investment it brings to the province as well as the anticipated increase in load, which we expect will rebalance the current oversupply of generation in the province, an added benefit for our diverse Alberta portfolio. At our Centralia site, we’re actively engaged in commercial negotiations and continue to target executing a definitive agreement before year-end. We expect to be able to share detailed development plans for Centralia in the coming months as we firm our plan forward for the site. I’ll now pass the call over to Joel.

Joel E. Hunter: Thanks, John, and good morning, everyone. We are pleased with our second quarter operational and financial performance, and remain confident in our ability to meet our 2025 guidance range. During the quarter, we generated $349 million of adjusted EBITDA, which was $33 million higher than the second quarter of 2024 due to favorable ancillary service pricing, the use of environmental and tax attributes in Alberta and the optimization of our assets to capture price volatility in Alberta and at our Centralia site in Washington State. Turning to our segmented results relative to the same period in 2024. Hydro segment adjusted EBITDA increased to $126 million relative to $83 million last year, due to higher intercompany sales of emissions credits to the Gas segment to fulfill our 2024 GHG obligation as well as higher production and ancillary prices.

The Wind and Solar segment produced adjusted EBITDA of $89 million in line with the second quarter 2024, primarily due to higher environmental and tax attributes revenue in Alberta that was offset by lower tax attributes revenue from our Oklahoma assets and lower Alberta power pricing for the merchant wind fleet. In the Gas segment, adjusted EBITDA decreased to $128 million from $142 million in 2024, mostly due to lower realized power prices in Alberta and higher carbon and natural gas pricing, which was partially offset by the addition of the Heartland and previously mentioned higher quantity of internally generated emissions credits utilized through several portions of our 2024 GHG obligation. The Energy Transition segment delivered adjusted EBITDA of $19 million, a $17 million increase year-over-year due to higher market optimization benefits and higher availability at our Centralia facility which had an extended turnaround in the second quarter of last year.

Energy Marketing adjusted EBITDA decreased by $13 million to $26 million, primarily due to comparatively subdued market volatility across North American natural gas and power markets and lower realized settled trades in the quarter compared to last year. Corporate adjusted EBITDA was in line with last year at $39 million, largely due to increased spending to support our strategic and growth initiatives and the addition of corporate costs related to the acquisition of Heartland. As a reminder, 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, this strong performance generated free cash flow of $177 million in the second quarter in line with the same period last year.

Our higher adjusted EBITDA was offset by higher sustaining capital expenditures in our gas fleet during the quarter as well as higher net current tax and interest expenses. Turning to the Alberta portfolio. The second quarter spot price averaged $40 per megawatt hour, which was lower than the average price of $45 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 benign weather. Throughout the quarter, we deployed hedging strategies to enhance our portfolio margins and mitigate the impact of lower merchant power prices and realized the benefit of approximately 1,900 gigawatt hours of hedges at an average price of $70 per megawatt hour, representing a 75% premium to the average spot price.

In addition, our Hydro fleet delivered an average realized merchant price of $82 per megawatt hour, a 105% premium to the average spot price, while the gas fleet realized 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 $23 per megawatt hour. We were able to deliver additional ancillary volumes across the Alberta fleet. In the quarter, our average realized price for ancillary service pricing settled at $42 per megawatt hour, a 5% premium to the average spot price. Despite relatively benign weather in the quarter, which resulted in lower spot power prices, we captured additional margins by fulfilling a portion of 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 $111.

Looking at the balance of the year, we have approximately 4,300 gigawatt hours of our Alberta generation hedged at an average price of $69 per megawatt hour, well above current forward curve of $48 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 7,000 gigawatt hours at an average price of $67 per megawatt hour, which remains well above current forward pricing levels. I’ll now turn the call back over to John.

John Harry Kousinioris: Thank you, Joel. We remain focused on the following priorities for 2025. First, delivering adjusted EBITDA and free cash flow within our 2025 guidance range; 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 centering the opportunity presented in securing a data center customer at Alberta Thermal as well as the coal to gas conversion at Centralia; fourth, successfully pursuing any strategic M&A opportunities that may arise; fifth, maintaining our financial strength and flexibility, which Joel and his team advanced through the extension of our credit facilities in July, and finally, implementing the upgrade to our ERP program.

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. We’re 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. There is significant and growing value in our legacy thermal sites, which our team is actively working to re-purpose to meet the growing need for reliable generation in the jurisdictions in which we operate. We remain disciplined in our approach to growth, focused on delivering value to our shareholders within our core jurisdictions as we work to diversify our portfolio and increase the stability and attractiveness of our cash flows.

And our company also 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 through dividends and share repurchases. 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 second half of 2025. Thank you. I’ll now turn the call over to Stephanie.

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

Q&A Session

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

Robert Hope: First question on the data discussions with your customers there. What are the gating factors to successfully execute an MOU there? As well as if additional capacity does come up for grabs just given the fact that two developers have dropped out, do you have, we’ll call it, enough demand in pocket to go after those as well?

John Harry Kousinioris: Robert, in terms of sort of the additional stage gating items, it isn’t that there sort of is any significant impediment to us moving forward. It just takes time for us to finalize all of the terms associated with the MOU. We’re working with our customers. They have work that they’re doing as well. We had a shift in the approach that the AESO was taking around data centers. And all of that just takes time. But what I can tell you is that we’re very, very pleased with the progress that we’re making and are confident in the project as we’re envisioning it going forward. In terms of additional capacity, look, we’re focused on the capacity that’s been allocated to us. And we’re also focused on what subsequent stages of development could occur at the site, and that takes a bit of time to think through with our counterparties. So those would be the main things. Right now I’m not seeing any significant impediments. We’re just working things through.

Robert Hope: Great. I appreciate that. And then maybe turning attention to south of the border, midlife natural gas M&A. Can you update us on how you’re thinking about that market? And is this an increasing focus for the organization?

John Harry Kousinioris: The short answer is, Yes. It is an increasing focus for the organization. We’re actually seeing quite a few opportunities south of the border. But actually, in places also north of the border, I would say, around natural gas. Our focus is obviously on facilities that would be in the core markets that we’re focused on, which is the West, in particular, the PAC Northwest and also I would say the Desert Southwest. There’s also opportunities potentially in Ontario that we’re looking at. So it is very active for our team. We like the multiples that we see those assets being traded at right now. They work for us. And given our energy marketing expertise, they really are a priority. But I would say we are also seeing selectively opportunities around renewables as well as there’s been a bit of compression in the multiples, both on the renewables and at the same time, a bit of an increase in the multiples on gas.

So to a certain point, they actually overlap a little bit. Joel, I don’t know if you want to add anything to that?

Joel E. Hunter: I think, John, you said more than I would have.

John Harry Kousinioris: No, it’s a busy time for our team.

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

Maurice Choy: Just a quick one on Phase 1, and also just my broad question here. It sounds like you have really good momentum here towards securing your MOU. I’m just curious if the time line has changed in terms of your expectations since the Q1 call. It sounds like you would have been able to announce an MOU on this call had it not been a decision to move the AESO decision to mid-September. And then just more broadly, do you think Alberta is capable of delivering power to say, gigawatt scale data centers, even if it’s over phases and what would that require?

John Harry Kousinioris: Yes. On the first point, look, when we talked about sort of midyear, roughly speaking, to get an MOU done, that was on the basis of the best knowledge we had at the time in that first quarter. We are actively involved right now. We are making progress. There has been an evolution in kind of the way that we envisioned the project, developing not just in terms of our immediate allocation, but over time, and that just takes time to work through. We’re diligently progressing that and we do expect to advance that in a very orderly way in the coming period. On the second part, on delivering additional megawatts here. Look, all of the discussions that we are having, all of the discussions that we’re having with the AESO, I think the vision that the province has on seeing incremental load come into the province and develop a healthy and vibrant data center industry in the province, I think remains unabated.

I would say we’re focused on bringing subsequent phases of load on our site. We have all these great attributes at our facilities there to see it through. We’re not alone in the province in that regard. And I think we’re confident. I know our company is confident that we will see a pretty vibrant data center industry develop in the province over time. The other thing I would say is — and this shouldn’t be lost on people. It will serve to also rebalance load in the province, which is a particular benefit, I would say, to a company like ours that has that diversity, a fleet that can benefit through the portfolio and the great optimization team that we have.

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

Benjamin Pham: I want to stay on the same topic and maybe just one for you, John. Can you elaborate, you mentioned — versus Q1 or maybe a different time line the project materializing a bit differently than how you envisioned. Can you expand on that a bit? Is that size or counterparties? I guess, just any additional details would be helpful.

John Harry Kousinioris: No. It isn’t about counterparties or even particularly about size. It’s more around getting clarity in June from the AESO in terms of how the phase was going to actually play out. Up until that time, we were not really guessing but sort of anticipating the pathways that it could take and how our facilities could fit into that. And we got clarity a month and a bit ago, and we’re working with our customers to kind of realize it now that we’ve got clarity and also spending time with them to figure out what subsequent stages look like and what the timing would be. So it’s not that there is a deviation or a significant change in the process that we’re doing. It just takes time to get it done in the way that makes sense for everybody. But we remain very confident. In fact, I’d say, more confident now and very pleased in the process that we’re making.

Benjamin Pham: That’s good to hear. And then I know you mentioned the mid-September DTS execution, but that doesn’t suggest from your eyes that an MOU is around that time line. It sounds like it just — your time lines have shifted a bit from your initial expectations?

John Harry Kousinioris: That’s right. I mean, we’re working on — so the DTS execution time line is something we’re obviously aware of because we’re focused on securing our position. So we will be entering into that contract on that date. But honestly, our MOU is working kind of in a pathway that is separate from a timing perspective to that. So that DTS contract component is a given from our perspective, if I can put it that way.

Benjamin Pham: Okay. Got it. And maybe just a last one, same topic here is let’s just assume what you have here to allocation Phase 1 year, you shored up MOU and in contract. Is there additional opportunity from available other assets to engage in additional PPAs with data centers that are built at grid power, which is strategy maybe some other folks may be taking?

John Harry Kousinioris: Yes. What I would say to that is the way that we are working with our customer right now would sort of see us, at least in the immediate phase being a comprehensive solution for the customer that we’re working with. So we’re not currently envisioning that we’re breaking that up or parceling it at this point in time.

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

John Mould: Maybe just starting with potential fleet investments in Alberta, and that’s in the context of the data center opportunity in the scenario of a material market tightening, your older coal to gas units, I mean, presumably, we wouldn’t see them running at 90% capacity factors outside of K3. What kind of normalized capacity factor could we see from the Sundance or Sheerness assets if the market does tighten by 1 or 2 gigawatts, let’s say? And are there any additional investments that you need to make on your end to maintain that level of utilization?

John Harry Kousinioris: John, so look, it depends on the pace at which the data centers come into the province, but in the scenario that you described, where the full 1.2 gig ends up coming into the province, reliability in the province would absolutely require our fleet to be running at relatively high capacity factors. It doesn’t take too much for the observed margin in the province to actually tighten up with the result that our units have both significantly higher capacity factors and also an associated increase in the realized spot price in the province beyond, I would say what the forward curve is currently indicating. In terms of capital investment that we would need to make sure that we do this so that we’ve got the units in the appropriate kit in the context of also our own data center obligations.

It is relatively modest, I would say. We’re not talking numbers that are beyond another tens of millions of dollars, normal core sustaining capital for the units to make sure that they’re able to run, and then what is required on the part of our company, which is work that we’re doing now is envisioning what do the 2030s look like as we get into the next decade to meet in an efficient manner, load growth over that period of time. So I think we’re in a good place because we’ve got a lot of optionality around our fleet, and it is in physically, operationally in a very good place.

John Mould: And then maybe on your comments around the Phase 2 expansion and engaging with counterparties there. Just wondering what those discussions are like so far in terms of the timing that customers are hoping to see? And what kind of initial dialogue you’ve had with government or AESO regarding Phase 2, how they’re approaching it, the pace that could be achieved on that consultation and giving the market clarity there?

John Harry Kousinioris: Yes. I’ll maybe start with the back part of your question and then flip to the front part of the question, John. Look, the discussions with the AESO and even the government are, I would say, at a relatively early phase. We understand that they want to encourage the development of the industry while making sure that we have reasonable prices in the province at an appropriate level of reliability. That makes a lot of sense to us in terms of the way that they’re progressing that. So the work and the discussions are at an early phase. But I think in principle, that makes a lot of sense and is very logical. In terms of timing, I can tell you that we’re encouraging them to do it as promptly as they possibly can.

I mean, ideally, we would end up getting some certainty before the end of the year. Maybe it drifts into the early part of the next year. But I think it’s important from a planning perspective for companies like ours, given where the supply chain is, if you see what I’m saying in terms of our need to envision the 2030 and beyond to be able to have that certainty to get the planning that we need to move forward. The AESO understands that, and they’re acutely aware of that going forward. In terms of our discussions with our customers with respect to that, there isn’t a lot that I can candidly say on the call other than it is a focused area for them. They do have a view on what a ramp up could potentially be, and we’re working with them to be able to plan that and make sure that we serve their needs in an appropriate manner as we go forward.

John Mould: Maybe one last one on carbon credit sales. Those were up year-over-year, and I appreciate some of that’s a function of the tier program structure. Alberta asset, it will freeze the tier price. Obviously, that’s in conflict with the minimum national carbon price from the federal government. How are you thinking about your carbon credit portfolio more broadly? And then a bit of an aside, but does that remain a tool in the data center discussion? Or is the carbon aspect of that data center conversation what’s relevant right now?

John Harry Kousinioris: Yes. Look, I would be remiss if I started sort of predicting where kind of a province will end up from a TIER perspective at the $95 level where we are today versus kind of the escalation that is required from a policy perspective at the federal government. For much of the planning that we do, we tend to think of a continuation of carbon pricing. I think that’s sort of a conservative view that we take in terms of the fleet, but I think that’s what we determined to be candid, John. In terms of our environmental attribute portfolio in the province, it is a real advantage that we have, both on the Hydro side, and on the Wind side, it is able to provide a meaningful reduction in the impact of the emissions that we have in our fleet which tends to be a little bit less efficient than some of the new facilities that have been built, but it basically nullifies that differential between ours and those kind of facilities.

And the values are pretty significant. So we see a lot of value in those attributes. We’ll continue to — I think, Joel, probably the right word is monetize those assets as we go forward and use them to ensure the competitiveness of our fleet, but also in a cost-effective way to meet the needs of our data center customer going forward. So it’s a real asset, I would say that we have.

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

Mark Thomas Jarvi: Are you able to state how much allocation you received in Phase 1?

John Harry Kousinioris: Mark, we haven’t stated how much allocation we have, and we’re not in a position to actually give that right now. What I would say is we’re comfortable with it, and we’re working around it, and our customers are also comfortable with it, and particularly in the context of how they envision the development of our site working forward. And our focus with them is as much on subsequent stages as it is on the base amount.

Mark Thomas Jarvi: And then have you made changes in terms of which assets do you think you would use to serve the customer on the allocation group Phase 1, like even before like Keephills Unit 2 was there? Is it more thinking Unit 3 or combining with Hydro, you just kind of made a comment about the Hydro offsets being something that might be a tool you can use for your customer?

John Harry Kousinioris: Yes. So I think there are sort of two parts to that question. I think one of them would be in terms of physical location for the data center that would very much be in and around our Keephills site. That is the work that we’re doing and all of the — everything from permitting right through to geotechnical work, it’s all with a view to developing the physical site there for the center. And as you know it requires the largest footprint to be able to do that. In terms of how we serve the load, we can serve it more broadly from, I would say, our entire fleet. It isn’t just wedded to Keephills 2. As we think of subsequent phases, it might be a little bit — potentially a little bit more unit contingent, if I can put it that way.

But right now, we absolutely have our entire — based on the structure of Phase 1, we absolutely have our entire portfolio to be able to use to basically serve the needs of our customers going forward, which is really, really helpful. It’s great having that portfolio.

Mark Thomas Jarvi: That’s great to hear. And then do you need clarity on Phase 2 to get to a definitive agreement with your customer? Or can you do it in sort of stages where using the first allocation, you can move to commercial final contract and then have sort of a ability to contract beyond that or subsequent megawatts?

John Harry Kousinioris: Yes. I think it’s more of the — if I remember your statement, more of the latter part. In other words, we’re looking at — so the finalization of our MOU will not require the finalization of Phase 2 of the consultation process. I think we have a number of tools to be able to deal with a subsequent staging going forward. So hopefully, that gives you a sense.

Mark Thomas Jarvi: That’s helpful. And lastly, just for me on this topic here is just the decision not to try to buy allocations from other people. Obviously, it would have been upfront payment for that. But versus having to invest to bring in new capacity this year, new load, which I believe is the criteria that will come through in Phase 2. I’m just trying to square those two opportunities to get as much can now through Phase 1 versus a bit more of a capital-intensive opportunity set through Phase 2?

John Harry Kousinioris: Yes. I’m not going to, Mark, kind of sort of speculate or get into discussions on the reallocation of the megawatts that end up taking place going forward. Look, what I would say is I agree that the second phase is going to — our working assumption is it’s going to require incremental generation to be provided. But what I would say in response to that, and this is a point that we’re working to speak to government and the AESO about that underutilized facilities are akin to incremental generation being brought on in the province. If something has a capacity factor of 20%, it has a lot of room to provide additional generation to serve the needs of a data center customer, whether it’s in front of the fence or behind the fence candidly, to be able to see it through. So that’s just something that we need to be very mindful of and is certainly a speaking point for us.

Mark Thomas Jarvi: Maybe just one last one was just the units that you had earmarked for the Pinnacle project. Are those things that you can re-purpose for a data center customer?

John Harry Kousinioris: Potentially, yes.

Operator: Our next question coming from the line of Julian Demoulin-Smith with Jefferies.

Tanner William James: This is Tanner on for Julian. Maybe just a follow-up on John’s question regarding the developing Phase II discussion. Are the potential counterparties you’re speaking with the same kind of subset and type of customers, the same types of goals as that as Phase 1? And do you see discussions progressing similarly to the ones you’ve had over the past year?

John Harry Kousinioris: Yes. What I would say is that our discussions are with a singular, I would say, customer and they would encompass not only sort of Phase 1, but Phase 2.

Tanner William James: Okay. Great. And then I just wanted to follow up on your Centralia commentary and the extended timing. Do you still view the opportunity through the lens of a specific and singular customer with a well-defined development plan on site? Or are they, at this point, competing visions or counterparties under deliberation.

John Harry Kousinioris: Yes. So the work that we’re doing at Centralia is with respect to meeting the needs of a singular customer in that jurisdiction, and it is around literally devoting the entire facility to that customer on a coal converted to natural gas-fired generation basis for an extended period of time. It would be sort of a long term — or purchase arrangement or tolling agreement for that facility. There would need to be capital spend to do the conversion from the coal to the natural gas, but it literally is in terms of the existing facilities we have on site all around Centralia Unit 2 and how we would bring that forward. Having said all of that, we do have a very large geographic footprint in the region, and our team is also exploring potential opportunities to add other generation there, likely because of the gas constraints, at least initially more in the vein of renewables, whether that would be solar or wind or possibly even storage on-site.

That could be for that singular customer or it could be for other customers. And that’s something that is developing. The site is great. I mean it’s about, I don’t know, 80 kilometers, 60 miles or so away from the city of Seattle. It’s a great footprint. We have a skilled workforce there. Transmission is ample. To use the Canadianism, it’s really center ice of kind of the grid there. And we view the unit as being critical to the reliability of the grid in that part of the world.

Operator: There are no further questions in the queue. I would now like to turn it back to Stephanie Paris for any closing remarks.

Stephanie Paris: Thank you, everyone. That concludes our call for today. If you have any further questions, please don’t hesitate to reach out to the TransAlta Investor Relations team.

Operator: This concludes today’s conference call. Thank you for your participation, and you may now disconnect.