Transalta Corp Q3 FY2025 Earnings Call

Good morning. My name is Olivia, and I'll be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Third Quarter 2025 Conference Call. Thank you. Ms. Paris, you may begin your conference.

Thank you, Olivia. Good morning, everyone. My name is Stephanie Paris, and I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta's Third Quarter 2025 Conference Call. With me today are John Kousinioris, President and Chief Executive Officer; Joel Hunter, EVP, Finance and Chief Financial Officer; Blain van Melle, EVP, Commercial and Customer Relations; and Nancy Brennan, EVP, Legal and External Affairs. Today's call is being webcast, and I invite those listening on the phone lines to view the supporting slides that are posted on our website. A replay of the call will be available later today, and the transcript will be posted to our website shortly thereafter. All the information provided during this conference call is subject to the forward-looking information statement qualification set out here on Slide 2, detailed further in our MD&A, and incorporated in full for the purposes of today's call. All amounts referenced are in Canadian dollars, unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA and free cash flow, are reconciled in the MD&A for your reference. On today's call, John and Joel will provide an overview of TransAlta's quarterly results. After these remarks, we will open the call for questions. With that, I will turn the call over to John.

Thank you, Stephanie. Good morning, everyone, and thank you for joining our third quarter conference call for 2025. As part of our commitment towards reconciliation, I want to begin by acknowledging that our company operates on the traditional territories of indigenous peoples across Canada, Australia, and the United States. We recognize the rich and diverse histories, cultures, and contributions of the First Nations, Inuit, Metis, Aboriginal and Native American communities. And it is with gratitude and respect that we thank the peoples who have lived on these lands, for reminding us of the ongoing histories that precede us. TransAlta delivered solid performance during the third quarter, demonstrating our fleet's resilience during challenging market conditions. Our Alberta portfolio hedging strategy and active asset optimization continued to generate realized prices well above spot prices, while availability remained high across the fleet. During the quarter, we delivered adjusted EBITDA of $238 million, free cash flow of $105 million or $0.35 per share and average fleet availability of 92.7%. Based on our results to date and expectations for the fourth quarter, we remain confident in achieving our 2025 guidance range. We're tracking to the lower end of the adjusted EBITDA range and the midpoint of free cash flow, which Joel will speak to later in the call. As you all know, a key priority for our company is to progress our legacy thermal opportunities, which we continue to do during the quarter. In Alberta, our data center project will contribute to powering a new industry in the province. And in Washington, our Centralia project will support reliability for decades to come. Commercial negotiations for both projects continue to progress during the quarter. And while we remain confident in our advancement of these key priorities, we've decided to shift the timing of our Investor Day to the first quarter of 2026, following data center and Centralia announcements. We will provide you with detailed updates on both projects and their impact on our company, as well as the opportunities we see across all of our core markets at that time. Returning to the quarter, we executed agreements to extend our committed credit facilities totaling $2.1 billion with our syndicate of lenders. Our syndicated facility of $1.9 billion now has a maturity of June 30, 2029, and our bilateral credit facilities of $240 million were extended by 1 year to June 30, 2027. During the quarter, we completed the sale of a 100% interest in the 48-megawatt Poplar Hill facility, as required under the terms of the Heartland Generation acquisition. And following the quarter, on October 2, we also closed the sale of a 50% interest in the 97-megawatt Rainbow Lake facility. The proceeds from the divestitures go to Energy Capital Partners, as agreed to under the terms of the transaction. This marks the successful conclusion of the remaining regulatory requirements for the Heartland acquisition. In August, the AESO announced its final design for the restructured energy market, or REM, which I will speak to momentarily. The government of Alberta also introduced proposed amendments to the TIER regulations. The proposed changes include recognition of on-site emissions reduction investments as a compliance pathway under the TIER system. This may impact the emission credit market. However, as most of our credits are deployed internally towards our gas fleet emissions obligations, we do not anticipate this change, if implemented, to be material to our business. And finally, we continue to engage directly and collaboratively with the Government of Alberta and the AESO, on the Alberta data center strategy and their approach to large load integration. Turning more specifically to the work that we're doing in realizing the value of our legacy generation sites. At our Centralia site, we're actively engaged in commercial negotiations with our customer and expect to be in a position to execute a definitive agreement before year-end. At that time, we will be able to share our detailed development plans for the site. We also continue to progress our Alberta data center strategy and the associated commercial negotiations. Recently, we entered into a demand transmission service contract with the AESO for 230 megawatts, representing the full allocation awarded to the company through Phase 1 of the AESOs data center Large Load Integration program. In September, Parkland County unanimously approved the rezoning of over 3,000 acres of TransAlta-owned land surrounding our Keephills and Sundance facilities to support future data center development. We're grateful for this community support, which represents an important milestone to advance the opportunity for new investment, job creation, and economic growth in the region. We continue to work closely with our counterparties on their data center project and are steadily progressing towards the finalization of a memorandum of understanding. We also continue to engage directly with the provincial government and the ISO on Phase 2 of the Large Load Integration program. We're excited about the data center opportunity in Alberta and the meaningful investment it can bring to the province. In August, the AESO announced its final design for the Alberta restructured energy market or REM. The structure is consistent with our expectations, adds greater certainty to the market, and supports system reliability, something our diverse and dispatchable generating fleet in Alberta is well suited to provide. Notably, the REM will help ensure appropriate price signals are received by generators to enable reliable generation investment and ensure Alberta is competitive with other jurisdictions. The REM contemplates an increase in the provincial price cap to $1,500 per megawatt-hour and eventually to $2,000 per megawatt-hour, with additional administrative scarcity pricing during periods of tight system conditions. The REM also creates a new ramping product to enhance system reliability, which our dispatchable fleet is well positioned to serve and mitigates against any adverse impact from the adoption of locational marginal pricing for incumbent generators through the allocation of financial transmission lines. The REM is expected to be implemented in 2027 or 2028, and we will continue our active engagement in the AESO consultation process, which is now focused on implementation. We believe that the changes to the market provided by the REM, coupled with the anticipated load growth from the fully allocated 1.2 gigawatts of data center system access granted by the ISO will see Alberta's power supply and demand imbalance improve, and lead to a recovery in the merchant power price in the province, benefiting our diversified legacy fleet. The forward price has begun to reflect the changing supply and demand dynamic in the province, driven by electrification, data center load, and population increases, along with the slowdown in incremental new supply coming online, which makes our existing generating fleet increasingly valuable. There appears to be a reaction today to a reference to Project Greenlight's data center in-service date being pushed out to 2030. Our understanding is that this is very much an outside date and that Kineticor and their customer are still driving to have the project in service in 2027 or 2028. It remains our view, based on the information that we have, that forward prices do not yet fully factor in the impact of the REM or 1.2 gigawatts of data center load that will be coming online. The gradual increase in load we now expect will rebalance the current oversupply of generation in the province and drive opportunities for growth in the long term. TransAlta's dispatchable thermal and hydro fleet have existing capacity to provide reliability and serve the expected load growth. Before I turn the call over to Joel, I'd like to offer a few words on my upcoming retirement. As we announced today, I will be retiring from TransAlta and its Board, effective April 30, 2026. It has been an honor to lead TransAlta, and to work with such a committed and talented team. Together with our Board, we have evolved our business and built a strong foundation for the future by increasing shareholder returns, delivering strong financial results, navigating regulatory change, diversifying our business, and positioning our fleet to meet the customer needs of the future. I fully support Joel, as the next President and CEO of TransAlta. He's a proven leader and the right person to advance TransAlta's strategy. I look forward to working with him, management, and the Board, over the coming months to ensure a successful transition. I'll now pass the call over to Joel.

Thanks, John, and good morning, everyone. I'd like to start by offering my congratulations to John on his upcoming retirement, and thank him for his leadership, guidance, and strategic vision for TransAlta, as well as his active support of my leadership. I look forward to working together to ensure a smooth transition and continued execution of our strategic priorities. We will announce the CFO successor in the coming months. Turning now to our third quarter results. I'll start with an overview of the period, where our fleet demonstrated resilience in softer market conditions. During the quarter, we generated $238 million of adjusted EBITDA, which was $77 million lower than the third quarter of 2024, due to lower Alberta and Mid-C power prices, subdued market volatility impacting energy marketing and trading results, and lower contract revenue from our Centralia facility. Turning to our segmented results relative to the same period of 2024. Hydro segment adjusted EBITDA decreased to $73 million compared to $89 million last year due to lower spot power prices in Alberta, as well as lower ancillary services revenue, which was impacted by lower availability from higher planned maintenance outages. Through optimization, we were able to reallocate these services to our gas fleet, maintaining our market share of the associated ancillary revenues. Environmental and tax attribute revenue to third parties was also lower than last year. The wind and solar segment produced adjusted EBITDA of $45 million, in line with the third quarter of 2024. In the gas segment, adjusted EBITDA decreased to $110 million from $141 million in 2024, mostly due to lower realized power prices in Alberta, along with higher carbon pricing, partially offset by the addition of the Heartland assets, which increased contracted production, along with incremental ancillary services revenue due to production optimization between the gas and hydro segments. The energy transition segment delivered adjusted EBITDA of $28 million, a $6 million decrease year-over-year due to lower market prices, partially offset by lower purchase power costs and a higher volume of favorable hedge positions settled. Energy marketing adjusted EBITDA decreased by $25 million to $17 million, primarily due to comparatively subdued market volatility across North American natural gas and power markets and lower realized settled trades in the quarter compared to last year. And corporate adjusted EBITDA was in line with last year at $35 million. As a reminder, our adjusted EBITDA excludes the impact of ERP costs as the integration is not reflective of ongoing operations or the performance of our operating assets. Overall, free cash flow was $105 million in the third quarter, which was $26 million lower than the same period last year. Lower adjusted EBITDA and higher net interest expense was partially offset by lower current income tax expense and lower distributions paid to noncontrolling interests. Turning to the Alberta portfolio. The third quarter spot price averaged $51 per megawatt-hour, which was lower than the average price of $55 per megawatt-hour in 2024. The decline year-over-year was primarily due to incremental generation from the addition of new gas and renewable supply in the province, as well as benign weather. Throughout the quarter, we deployed hedging strategies to enhance our portfolio margins and mitigate the impact of lower merchant power prices. We realized the benefit from approximately 2,500 gigawatt hours of hedges at an average price of $66 per megawatt-hour, representing a 29% premium to the average spot price. In addition, our hydro fleet delivered an average realized merchant price of $76 per megawatt-hour, a 49% premium to the average spot price, while the gas fleet realized an average merchant price of $79 per megawatt-hour, a 55% premium to the average spot price. Our merchant wind fleet, which cannot be used as firm power for hedging activities, realized an average price of $28 per megawatt-hour. We were also able to deliver additional ancillary volumes across the Alberta fleet. In the quarter, our average realized price for hydro ancillary service pricing settled at $47 per megawatt-hour, an 8% discount to the average spot price. Due to the optimization of ancillary services to the gas segment from hydro during planned outages, the gas segment realized an average ancillary service price of $41 per megawatt-hour. Despite relatively benign weather in the quarter, which resulted in lower spot power prices, we captured additional margins by fulfilling a portion of our higher priced hedges with purchased power when prices were below our variable cost of production, leading to an overall realized price per megawatt-hour produced of $103 compared to $90 per megawatt-hour in the same period last year. For the balance of the year, we have approximately 1,900 gigawatt hours of our Alberta generation hedged at an average price of $72 per megawatt-hour, well above the current forward curve of $57 per megawatt-hour. Going forward, we expect to continue to optimize our fleet and reduce production in low-priced, high-supply hours by fulfilling our financial hedges and customer requirements with open market purchases. Looking at next year, our team has increased our hedge position to approximately 7,800 gigawatt hours at an average price of $66 per megawatt-hour, which remains well above current forward pricing levels. Based on our year-to-date results and balance of year expectations, we remain confident in our 2025 outlook. We are currently tracking towards the lower end of our adjusted EBITDA range, largely due to the Alberta spot power price tracking to the lower end of the outlook range of $40 to $60 per megawatt-hour. Currently, we expect the full year spot price to average $46 per megawatt-hour. In terms of sensitivity to the Alberta spot power price, $1 per megawatt-hour is expected to have a $2 million impact on our adjusted EBITDA for the balance of the year. Other factors influencing adjusted EBITDA include lower wind resource and subdued market volatility. Free cash flow is tracking to the midpoint of the outlook range and the aforementioned adjusted EBITDA impacts are partially offset by lower expected current taxes and lower expected distributions to noncontrolling interests. Consistent with the past year, we'll provide a fulsome 2026 outlook update on our fourth quarter 2025 conference call in February. I will now turn the call back over to John.

Thank you, Joel. We remain focused on the following priorities for 2025. First, delivering adjusted EBITDA and free cash flow within our 2025 guidance ranges; second, improving our leading and lagging safety performance indicators while achieving strong fleet availability; third, maximizing the value of our legacy thermal energy campuses by capturing the opportunity presented by securing a data center customer at Alberta thermal as well as advancing our coal-to-gas conversion at Centralia; fourth, successfully pursuing any strategic M&A opportunities that may arise; fifth, maintaining our financial strength and flexibility; and finally, successfully implementing the upgrade to our ERP system. I believe TransAlta offers a compelling investment opportunity. We're a safe and reliable operator with strong cash flows, underpinned by our diversified hydro, wind, solar, and gas portfolio located across 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. Olivia, would you please open the call for questions from the analysts?

Our first question is from Robert Hope with Scotiabank.

Congrats to John and Joel on the announcements.

Thanks, Robert.

Thanks, Robert.

Maybe on the data center front. So it appears that discussions are going slower than anticipated regarding customers for the data centers in Alberta. Can you maybe add a little bit of color of what is driving this, as well as has your confidence in securing a project increased or decreased since the Q2 call?

Robert, we remain confident in our ability to progress the data center opportunity that we have here in the province. Look, it's a big initiative, both for our prospective customers and for our company. It takes time to make sure that all of the details that we need to work with. And frankly, there are multiple parties involved in bringing it forward. It just takes time to do all of that. Phase 2 of the ISO process and the Government of Alberta process in terms of large load integration is also critically important. That's taking a little bit of time to sort out because, at least from our own perspective, it isn't just about the initial 230 megawatts that we've got. It's about how we're thinking about phasing a real data center opportunity for the province and for our company. All of this takes time, but we're tracking, and we remain in the confidence that we had last quarter and in other earlier times of the year to move it forward. It is very much a key priority for our company.

Are you in discussions to serve other data center customers in Alberta on a shorter-term basis? You did mention Greenlight. You do have confidence that it could be in service in '27, '28. What gives you that confidence? And could you be supplying power to them in that timeframe as well?

So all of the discussions that we're having, all of the work that we're doing are really around a single opportunity. And we've taken, at least from a TransAlta perspective, an exclusive approach with those prospective customers. So that's the way we're looking at it. It's also our expectation that once we're able to announce our MOU and begin moving forward that we'll be able to start seeing load come into our sites gradually and probably a bit earlier than what Kineticor is currently anticipating that they would have coming in. So hopefully, that gives you a little bit of color.

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

Congrats, Joel and John. Not to get too far ahead of ourselves, but once you do have the MOU in place, then what would be the sort of timeline when you think you can get to a binding agreement? And given the fact it's taking a bit longer to get to the MOU, does that shorten the window from MOU to final agreement?

Mark, good morning. We want to move forward quickly, and we are already preparing our team to finalize the documentation soon. While I can't provide a specific timeline for when this will happen, I will be encouraging our team to complete it as quickly as possible. A crucial aspect of the MOU is to ensure we have clear details and an understanding of the arrangements between us and our customers, which will help facilitate the final documentation. I expect this process to be quicker than the time it has taken to reach the MOU.

You used the word counterparties in the plural. Can you elaborate on what that means? Is that on the funding side for the customer? Is it a sort of joint venture in the data center? Anything you can shed on that? And the fact that it is multiple customers, how has that sort of affected the timeline to reach MOU?

Yes. We are working with more than one customer. We're working together to see the opportunity come through. And that's been the case throughout, candidly, our engagement. And given where we are in the process and how we're working through it, there isn't a lot more that I can give you, Mark. I wish I could, but I can't.

On the last call, you indicated that you took the view that your underutilized coal-to-gas converting units sort of are akin to incremental generation when you think about Phase 2 and you're trying to have those conversations with the AESO and the government. How have those progressed? And are you getting traction with that concept?

I'm glad you asked about that. We have had discussions on Phase 2, and Joel, Nancy, and Blain have been working on it as we move forward. I want to share our company's position, which is being well received by the government. To give you an overview, we believe that colocation isn't necessary; it's better not to have to co-locate the data center with the generation moving forward. We firmly believe that underutilized generation, like our coal-to-gas units, could provide additional supply and meet the demand for incoming data centers as a bridge to new generation planned for the 2030s. This transition is not just about reliability, sustainability, and cost; speed is also important, and those units are well-suited for this purpose, especially considering current supply chain challenges. The reality is that obtaining equipment like turbines or transformers could take several years. Thus, these units play a crucial role in getting us from our current state to the market we envision. We've been advocating for this, and I think the government understands and values our position.

Just to follow up on that, John. When you talk about potentially a bridge, are you saying some of the underutilized megawatts would be something that could be viewed as there for a couple of 3 to 5 years until new megawatts come in or potentially as permanent supply in the eyes of the Phase 2 process?

Yes. We're not viewing it as a permanent supply. For instance, if a unit operates at a 20% capacity factor, there is significant unused capacity to support additional data center requirements over time. When we consider Keephills 2, Keephills 3, the Sheerness facilities, and Sun 6, we believe we can potentially introduce something new to the market by the 2030s, and we clearly foresee a transitional role during Phase 2 to facilitate that.

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

I wanted to touch just base on the delay of your Investor Day. I can understand the reasons for it. I'm wondering, when you did set the Investor Day, you go back, was your priorities to get the MOUs on both of these projects? I vaguely recall it was more related to updating your long-term strategic capital allocation process. Or has that changed as time has progressed?

No, Ben, we scheduled the date with the hope of having more certainty and clarity on our data center strategy and other initiatives, including Centralia. It has taken us longer to finalize these aspects than anticipated. We could have proceeded with the Investor Day, but we believe it wouldn’t have met our standards for effectively informing our investors and the investment community about the impact of these projects on the company. We want to ensure that everything is in place for a comprehensive understanding of our future strategy. We initially selected a date we felt confident we could meet, but we're still working through the details. Our confidence remains intact; we just want to ensure we hold a productive Investor Day that benefits our investors. That’s why we made this decision.

Your comments on the connection queue and updates, I mean, those in-service dates you mentioned are always, tend to be conservative, and that they move around. Does that warrant then perhaps for your projects to look at some outside dates just given that progress is a bit slower on some of your developments?

Yes, we feel quite confident about our current position because we are focused on grid-connected opportunities. We are equipped to meet the generation needs of the entity. From a power perspective, we believe we can satisfy our customers' supply requirements, and we are in good shape regarding that. The timeline will primarily depend on how long it takes to construct the data centers and establish the necessary infrastructure. There is a substation that we need to set up, but we feel comfortable with the supply chain and the timeline to complete it. I want to emphasize that TransAlta is not worried about the timing of our data center opportunities.

Just if I may, the 3,000 acres, I mean, I think that's a massive amount of megawatts you can theoretically add on to that acreage.

It is. I agree. It's a significant opportunity. And we're grateful for the engagement that we've received from Parkland County, who also see the opportunity for the county to have a real hub for data centers just west of the City of Edmonton there. So all the work that we're doing, as I mentioned earlier in the call, isn't just for the 230. It's as we envision kind of the broader campus that we hope to develop over time.

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

You mentioned planning with your customers for phases beyond 230 megawatts and highlighted the importance of AESO's Phase 2. Looking ahead to your Investor Day in Q1, what do you see as the main factor that could delay your timeline?

Yes, it's difficult to speculate. All I can say is that we continue to work diligently to establish our facility and navigate the permitting process for our opportunities. We do not foresee any significant timing issues from TransAlta's perspective. We are collaborating with our customers as they also have important factors to consider in order to secure their plans and better understand future pathways. We are confident in Phase 2 and believe that the government and the ISO are committed to developing a data center industry in Alberta as a priority. Our team is engaging with senior government officials, and I have not encountered anything to suggest otherwise. Therefore, I do not see any significant obstacles to our progress.

Is there any regulation or policy, whether federal or provincial, that you consider essential for clarity regarding this MOU and the definitive agreement moving forward?

It would be helpful for us to have a better understanding of where Phase 2 is headed so we can make our plans accordingly, as we believe we can align with that. It's important to get this done. Another area we've previously discussed is the clean electricity regulations, which continue to pose some challenges for us. We are working diligently to maximize our options to comply with those existing regulations and fulfill the potential we envision from the data center projects. As our team considers future plans, the clean electricity regulations are something we feel we need to navigate long-term. Phase 2, in contrast, is more about gaining clarity, which we think will be beneficial. Hopefully, that gives you some insight, Maurice.

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

Great. Thanks a lot, Maurice.

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

I'm looking to gain further insight into the AESO in-service dates. According to AESO, the Keephills load is expected to be 100 megawatts by January 2027 and an additional 115 megawatts by midyear. How should investors interpret the timelines for your projects based on AESO's data? Are these timelines indicating when the load will be operational, or are they more about when the projects will be ready to connect to the grid from AESO's viewpoint? Please clarify this for us.

Yes, those dates relate to when we anticipate starting to connect to the grid and when the load will begin to increase. They are not directly linked, so to speak, but they are related. We expect a gradual increase in load over time. The project we are working on, which includes the substation, is designed to support the full ramp-up of generation over that period. Additionally, it’s important to note that the ISO requires the load to be in place by December 1st, 2028, which aligns with our current expectations.

I would like to clarify your comments on Phase 2. Do you or your customer need clarification on any aspects of Phase 2, even if it's just early details regarding bring your own power or allocations needed to finalize an agreement? This would help in gaining insight into the potential multistage development referenced in your news release. What timeline are you expecting to provide more clarity to the market on the key aspects of Phase 2?

On the last point, it's pretty clear to us that the AESO and the government are aware of the fact that having certainty sooner rather than later would be positive. So I can't give you a specific date on when we would get that, but I know that they're trying to move at an appropriate pace to be able to give us that level of clarity. I'd say the #1 thing, at least from my own perspective, on Phase 2 is just getting a better understanding of what that bringing incremental power is all about and what role our legacy facilities where we do have capacity can bring in that context. That's probably the #1 thing just from a planning perspective for us going forward. And we're working to develop optionality so we can deal with that whichever way it goes. So that's something that we continue to work on. And certainly, we'd be able to provide more clarity on at our Investor Day.

Just one last one on just your hedging and midterm pricing. I'm wondering what kind of interest you're seeing from C&I customers around signing mid- to long-term deals, just given the potential for the power pricing environment to normalize considerably over the next few years? And then from your side, how you're balancing the potential for that increased appetite with your aspirations on supplying large loads?

Yes. I'll start and then let Blain add to this since it's his team overseeing that work. I would say it's been quite steady. We have seen stable demand in the commercial and industrial sector, and I believe we are currently the largest player in that segment in Alberta. Our renewal and incremental business continue as usual, with customers renewing at an average tenure of about three years. We have noticed some slight reductions in re-contracting prices, which Blain can elaborate on, as they are rolling off contracts that were signed when power prices were higher. This process takes time to reflect in our pricing, but we still view those prices positively. As we look towards late 2027 and 2028, when we expect the merchant market to tighten, it doesn't seem to be significantly affecting the one to three-year renewals at this moment, but I'd be interested to hear your thoughts on this, Blain.

John, that's exactly right. The C&I business hasn't really faltered even through the lower prices that we have right now. The re-contracting remains very robust. We continue to extract some good premiums over the financial market. And I would expect, as we move forward here and as some of this load does start to materialize already reflected in the forward price that that contracting levels will ramp up a little bit as the customers start to meet to plan for those power needs in later 2027, 2028, and 2029.

Yes.

Congratulations to both Joel and John on the announcements.

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.