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

Thank you, Livia. Good morning, everyone. My name is Stephanie Parris, 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 Cusignoris, President and Chief Executive Officer, Joel Hunter, EVP Finance and Chief Financial Officer, Blaine Van Mill, 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 line 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 two, detailed further in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced are in Canadian dollars unless 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 Transaltis 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, Métis, Aboriginal, and Native American communities. And it is with gratitude and respect that we thank the peoples who have lived on these lands for reminding us of the ongoing histories that precede us. Transelda 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 to 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 one year to June 30, 2027. During the quarter, we completed the sale of a 100% interest in the 48-megawatt Poplar Hill facility, as required under the terms of the Heartland Generation Acquisition. And following the quarter, on October 2nd, we also closed the sale of a 50% interest in the 97-megawatt Rainbow Lake facility. The proceeds from the divestitures go to energy capital partners, as agreed to under the terms of the transaction. This marks the successful conclusion of the remaining regulatory requirements for the Heartland acquisition. In August, the ASO 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 compliance pathway under the tier system. This may impact the emission credit market, however, as most of our credits are deployed internally towards our gas fleet's emissions obligations, we do not anticipate this change, if implemented, to be material to our business. And finally, we continue to engage directly and collaboratively with the Government of Alberta and the ASO 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 ASO for 230 megawatts, representing the full allocation awarded to the company through phase one of the ASO's data center large load integration program. In September, Parkland County unanimously approved the rezoning of over 3,000 acres of TransAlta-owned land surrounding our Key Pills 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 two 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 ASO 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 rates. The REM is expected to be implemented in 2027 or 2028, and we will continue our active engagement in the ISO 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 hydrofleet 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 Transelta 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 Transelta, 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 resilient and 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-Sea 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 the adjusted EBITDA of $45 million, in line with the third quarter of 2024. In the gas segment, adjusted EBITDA decreased to $110 million dollars from 141 million dollars 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 and survey of services revenue due to production optimization between the gas and hydro segments the energy transition segment delivered adjusted ebitda of 28 million dollars a six million dollar 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 non-controlling interests. Turning to the Alberta portfolio, the third quarter spot price averaged $51 per megawatt hour, which was lower than the average price of $55 per megawatt hour in 2024. The decline year-over-year was primarily due to incremental generation from the addition of new gas and renewable supply in the province, as well as benign weather. Throughout the quarter, we deployed hedging strategies to enhance our portfolio margins and mitigate the impact of lower merchant power prices. We realized the benefit from approximately 2,500 gigawatt hours of hedges at an average price of $66 per megawatt hour, representing a 29% premium to the average spot price. In addition, our hydro fleet delivered an average realized merchant price of $76 per megawatt hour, a 49% premium to the average spot price, while the gas fleet realized an average merchant price of $79 per megawatt hour, a 55% premium to the average spot price. Our merchant wind fleet, which cannot be used as firm power for hedging activities, realized an average price of $28 per megawatt hour. We were also able to deliver additional ancillary volumes across the Alberta fleet. In the quarter, our average realized price for hydro ancillary service pricing settled at $47 per megawatt hour, an 8% discount to the average spot price. Due to the optimization of ancillary services to the gas segment from hydro during planned outages, the gas segment realized an average ancillary service price of $41 per megawatt hour. Despite relatively benign weather in the quarter, which resulted in lower spot power prices, we captured additional margins by fulfilling a portion of our higher price hedges with purchase 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 dollars 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 dollars per megawatt hour. Currently, we expect the full year spot price to average 46 dollars per megawatt hour. In terms of sensitivity to the Alberta spot power price, one dollar per megawatt hour is expected to have a two million dollar 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 as the aforementioned adjusted EBITDA impacts are partially offset by lower expected current taxes and lower expected distributions to non-controlling interests. Consistent with the past year, we'll provide a fulsome 2026 outlook update on our fourth quarter 2025 conference call in February. I will now turn the call back over to John.

Thank you, Joel. We remain focused on the following priorities for 2025. First, delivering adjusted EBITDA and free cash flow within our 2025 guidance ranges. Second, 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 three countries and complemented by our leading asset optimization and energy marketing capabilities. There is significant and growing value in our legacy thermal sites, which our team is actively working to repurpose to meet the growing need for reliable generation in the jurisdictions in which we operate. We also remain a clean electricity leader with a focus on tangible greenhouse gas emission reductions as we remain on track to achieve our ambitious 2026 CO2 emissions reduction target. We remain disciplined in our approach to growth, focused on delivering value to our shareholders as we work to diversify our portfolio within our core jurisdictions and increase the stability and contractiveness of our cash flows, 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. Livia, would you please open the call for questions from the analysts?

Certainly. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, simply press star 11 again. Please stand by while we compile the K&A roster. Now, first question coming from the line of Robert Hope with Scotiabank. Kaelan is now open.

Morning, everyone, and congrats to John Joel on the announcements.

Thanks, Robert.

Excellent. Okay, maybe on the data center front, so it appears that discussions are going slower than anticipated regarding customers for the data centers in Alberta. Can you maybe add a little 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 two of the ISO process and the Government of Alberta process in terms of large load integration is also critically important. That's taking a little bit of time to sort out because, at least from our own perspective, it isn't just about the initial 230 megawatts that we've got. It's about how we're thinking about phasing a real data center opportunity for the province and for our company. All of this takes time, but we're tracking and we remain 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.

I appreciate that. And then are you in discussions to serve other data center customers in Alberta on a short-term basis? You did mention green light. You do have confidence that it could be in service in 27, 28. What gives you that confidence and And could you be supplying power to them in that time frame as well?

So all of the discussions that we're having, all of the work that we're doing are really around a single opportunity. And, you know, 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, you know, 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. Yeah. Thank you.

Thank you. Our next question coming from the lineoff. Mark Jarvie with CIBC, Yolanda Snellman.

Thanks, everyone, and congrats, Joel and John. To get too far ahead of ourselves, but once you do have the MOU in play, then what? What would be the timeline when you think you can get to a binding agreement? And given the fact it's taken a bit longer to get to the MOU, does that shorten the window from MOU to final agreement?

Mark, good morning. um look we would want to go pretty quickly i would think and we've already begun kind of getting our team ready and getting eternally ready to kind of get to definitive documentations pretty quickly uh to move that forward i can't give you sort of a specific timeline on that uh when that would occur but but certainly um you know 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 a bit easier to proceed. But I think it's going to happen in, like, I think it'll actually be quicker than certainly it's taken to get the MOU done, is what I would say.

Okay. And then, can you use the word counterparties in the plural? Can you get a lot of interest on what that means? Is that on the funding side for the customer? Is it a joint venture on the data center? And you can shed on that and the fact that it is multiple customers. How has that sort of affected the timelines to regenerate years?

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.

And on the last call, you indicated that you took the view that your underutilized coal-to-gas converted units sort of are akin to incremental generation when you think about phase two. And you're trying to have those conversations with the ASO and the How have those progressed, and are you getting traction with that concept?

Yeah, I'm glad you asked about that. So we have had discussions on phase two. Joel and I and Nancy have spent a fair bit of time and Blaine's 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, you know, our senses is being well received by the government would be that, you know, we don't, just to give you a bit of a sense is, one, we don't think that co-location is necessary. We think that it would be better if 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, you know, new generation that would be built into the 2030s to be able to meet that going forward. Because it isn't just about reliability, you know, 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, you know, 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.

So just to follow up on that, John, when you talk about potentially a bridge, are you saying some of the unrealized megawatts would be something that could be viewed as, you know, there for a couple of three to five years until new megawatts come in or potentially as quote-unquote permanent supply in the eyes of phase two process?

Yeah, I'm not sure that at least we're not thinking of it necessarily as permanent supply. But so, for example, if we have a unit and it has a 20% capacity factor, there is a lot of, you know, horsepower left in that particular unit to run and be able to, you know, supply incremental data center needs over a period of time. And so when we look at, you know, Key Pills 2, Key Pills 3, the Sheerness facilities that we have, Sun 6, and our ability to, you know, potentially bring something new to the market in the fullness of time into the 2030s, we absolutely see a bridging role during phase two to get that there.

Understood.

Thank you.

Thank you. Our next question coming from the line of Benjamin Pham with DMO Capital Markets. Your line is now open.

Hi, thanks. Good morning. I wanted to touch base on the delay of your investor day. I can understand the reasons for it. I'm wondering, when you did set the investor day, 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 cap allocation process. 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, you know, 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, you know, 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 to do.

Okay, got it. And your comments on the connection queue and updates, I mean, those in-service states you mentioned are always kind of conservative and they move around.

Does that warrant then perhaps for your projects to look at some outside dates, just given that progress is a bit slower on some of the developments? yeah no i think i think we feel pretty comfortable about where we are um because what what what we're looking remember it's going to be a grid connected opportunity and then we will be um effectively covering the generation needs uh 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, you know, the timeline is going to be driven more by the time it takes to actually build out the data centers and get that infrastructure in place. I think there's a substation we need to put in place, but that's something that we're pretty comfortable from a supply chain and from a timeline perspective to get it done. So we're not, you know, I can tell you that TransAlta today isn't concerned about the kind of timing perspective from our data center opportunity.

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

It is. So I agree. It's like we see it as a significant opportunity and look, 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.

Okay. Thank you. And congrats to both of you, John and Joel. Thanks, Ben. Thanks, Ben.

Thank you. Our next question coming from the line of Maurice Choi with RBC Capital Markets. Yelena is now open.

Thank you, and good morning, everyone. You touched on planning with your customers for phases beyond 230 megawatts, and you also spoke about ASOS Phase 2 being critically important. And 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 timeline to be even later?

Yeah, 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 two. 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. You know, our team is now with very senior people in the government, and there's nothing I have heard that would suggest that that isn't a case. So there isn't, you know, 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 it would be helpful uh from our perspective um to kind of have a bit of a sense on where phase two is going to be landing so that we can plan around that um 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, you know, 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. You know, when our team is thinking about things, it's more the CER, to be honest, that we think about long term as being being something that we need to manage around, you know, phase two is more of a clarity point that we think will be constructed. Hopefully that gives you a sense, Bruce.

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 CR 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 ton but what can you share in terms of your expectations of both how the CR and industrial carbon tax will be through 2030 and beyond?

Look, I'd be speculating. I can tell you that 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 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 is on a customer or is that you, or is that still under negotiation?

So, you know, that's something that, you know, 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 you know, 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 Australia, I would say. You know, Blaine and his team are working on that. It's the same thing there. It's a real focus for us.

And my congrats to John, Joe, to all of you and hope to connect that's investigating. Great. Thanks a lot, Maurice.

Thank you. Our next question coming from the lineup, John Mould with CT Cowan. Yolan is now open.

Hi. Good morning, everybody. Maybe at the risk of going too in the weeds here, just trying to read the tea leaves a little more on these ASO in-service dates. So, you know, the key pills load ISCs as reported by ASO are 100 megawatts by january 2027 and then another 115 mid-year like how should investors view you know the timelines for your projects as provided you know by asos data are those timelines by which the load could actually be online or or more of a timeline for those to be ready you know to connect to the grid from an aso perspective just help us understand that aspect yeah i mean those those dates are um oriented to when we think that we would begin to begin like it's tied to when the connection to the grid would occur and when the load would start ramping

up so so they're not uh they're not not linked john if you see what i'm saying um they're tied so we do see a gradual um feathering and upload over time and and you know we would see you know So 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 first of December of 28, right? So that's what our current expectations are.

Okay. Okay. And then just like to clarify your comments on phase two, you know, do you or your customer need clarity on any aspects of phase two, 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, you know, line of sight on some of that aspirational, maybe it's not aspirational, just the potential multi-stage development uh that you referenced in in your news release and you know what timeline are you hoping for more you know clarity uh to the market on the key aspects of phase two on on the last point um it's pretty clear to us that

the aso and the government are aware of the fact that um having certainty sooner rather than later would be, you know, 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 number one thing, at least from my own perspective on phase two, 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 number one thing just from a planning perspective for us uh going forward and and we're working to develop optionality so we can deal with that whichever way it goes so that's that's something that we continue to work on and and certainly we'd be able to provide more clarity on at our investor day okay thanks for that and maybe just one last one on just your hedging and And, you know, 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, you know, the power pricing environment to normalize, you know, considerably over the next few years. And then, you know, from your side, how you're balancing the potential for that increased appetite with, you know, your aspirations on supplying large loads?

Yeah, look, I might start and then get Blaine to kind of chime in because it's his team that kind of oversees all of that work. I'd say, and Blaine, you can correct me, but I'd say it's been pretty steady. Like I'd say the CNI demand that we have, and I think we're actually the largest CNI player now in the province of Alberta. The CNI 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 tenor, Blaine, is roughly in that three-year kind of range. We have seen some of the recontracting prices come down a little bit, I would say, Blaine, and Blaine 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. You know, when you're looking at kind of 2028 or late 27, 28, which is when we would expect to see kind of a forward curve in the merchant market to tighten up, you know, we're not, I don't think that's impacting a lot of the one year, two year, even three year renewals, Blaine, right now in terms of moving the needle. I mean, I don't know your perspectives are. John, that's exactly right. The business, the C&I business hasn't really faltered even through the lower prices that we have right now.

The recontracting remains very robust. We continue to extract some good premiums over the financial market. And I would expect as we move forward here and as some of this load does start to materialize, already reflected in the forward price that contracting levels will ramp up a little bit as the customers start to We need to plan for those power needs in later 2027, 2028, and 2029.

Okay. Thank you very much for all that color. I will leave it there. Congratulations to both Joel and John on the announcements. Thanks so much, John. Thanks, John.

Thank you. Our next question coming from the line of Jillian, and Mullen-Smith with Jeffries. Your line is now open.

Hey, good morning, team. John, it's been a real pleasure over the years. Joel, congrats. It's been a pleasure to get to know you more recently, and big and exciting shoes to fill here, given the data center opportunity. But back to the opportunity hand here, speaking of which, I just want to understand a little bit more about the green light situation and what got posted by ASO 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 ASO update that was posted? I just want to understand what exactly transpired if there doesn't seem to be necessarily a push in timeline from your perspective, just to clarify that, because clearly the market's pretty perturbed out there about this timeline issue.

Yeah, and look, we know 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 TransAlza. 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 2728, not just them, but actually their customer, too, is what our understanding is. I know that they have a bit of a, 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 our worst case scenarios, if they needed to do a bit of the bottlenecking, 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.

Got it. So there is some focus on a potential for a bit of de-bottleneck in easier terms. But that doesn't seem to be too substantive, despite the statement technically on the website. from what you understand on the practicalities of the transmission seems like it's a fairly minor issue.

Based on my understanding that that 2030 date you know I don't know how to describe it it's almost like a worst case kind of scenario in terms of where they are it's it's sort of an outside uh kind of date and and and look um the idea through phase one 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, you know, full optionality around their opportunity. And candidly, we would be doing exactly the same thing. So, like, I think I can tell you from our company's perspective, we continue to operate and envision things being business as usual.

Excellent. All right. Thank you for the clarification there. I appreciate it. And just a quick follow-up there, just on Centralia. I know that's been a bit of an ongoing question here, but you talk about the 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, both 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 envisioning 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, you know, revenue tenor. It doesn't contemplate that more agreements would be required. It would be the agreement. And we have done a reasonable amount of work, you know, 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, you know, 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, Blaine and his team are working on this one as well, a comprehensive arrangement, Blaine, I would say. I don't know if you want to add anything. No, I think that's right, John. Like you said, we hope here in the next six weeks leading up to Christmas that we'll have something to announce. People to announce. And 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 by non-dactual gas.

Excellent, guys. appreciate the time and again congrats to both of you all the best and thanks julian thanks julian thank you our next question coming from the line of patrick kenney with national bank financial thank you good morning everyone and uh yeah congrats john and joel um just maybe back on the rezoning at sundance and keep hills just given the uh the close proximity of the two sites I'm wondering if you could just speak to how you might be thinking about integrating these two assets for a larger scale customer, just in terms of sharing generation, transmission, even fiber and water licenses, and maybe how that might compare to your sheerness site or perhaps give a competitive advantage over some other phase two proponents.

Yeah, I would say thank you, Patrick, and good morning. Um, you know, what we, what we did is, um, so 3,000 acres is a significant amount of land and, and you know, this, um, our mine is quite comprehensive up there and it, it actually ranges on both sides of the highway and, and Keep Hills 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, we took kind of a, a comprehensive approach from a rezoning perspective to be able to, you know, 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 Keep Hills facility. In fact, I'm just going through my memory, located immediately south of our Keep Hills 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 Keith Hill. 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 we're not really seeing any impediments, but getting the rezoning done was 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 for.

Okay. And then I guess, you know, with all these irons in the fire, and Joel, I'm sure, you know, at Investor Day, you'll be outlining a funding plan. But, you know, 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 two load growth in Alberta or even compared to M&A opportunities that you might be looking down in the U.S. yeah i would say pat when we look at centralia again you know typical with any kind of legacy asset that you can extend the life of with uh you know i would say a capital spending that's a fraction of what it would cost for new build that it would offer you know attractive risk

adjusted returns for us but this is where we'll provide you know 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, a cost perspective, what kind of the build multiple would be for that. But, you know, again, consistent with our strategy, you know, this would be really attractive risk-adjusted returns for us underpinned by, you know, long-term contract. This is kind of how we want to, you know, position ourselves going forward to increase the contractiveness of our portfolio. And similarly with, you know, any opportunities that we see in phase two, these would be underpinned, again, by long-term contracts. with, hopefully, a very attractive risk-adjusted rate of return.

And maybe on the M&A side, Joel, I think we've seen a bit of a – not compression, I can't think of the right word, but kind of a realignment. I mean, maybe talk a little bit about renewable and gas kind of opportunities we're looking at because we haven't talked about it much on the call, but we are actively looking at a number of acquisition opportunities.

Yeah, good point, John. There are a lot of opportunities out there, Pat, that we're looking at, both on the renewable side and on the thermal side. I would say that we're seeing really a convergence in multiples, if you will, where on thermal generation, depending on location, depending on the contract profile, etc., 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 three 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.

Yeah, very return focused, I would say.

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

Thank you. And 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.