Transalta Corp Q4 FY2025 Earnings Call

Good morning. My name is Josh, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Fourth Quarter 2025 and Full Year Results Conference Call. Thank you. Ms. Paris, you may begin your conference.

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

Thank you, Stephanie. Good morning, everyone, and thank you for joining our fourth quarter and full year conference call for 2025. TransAlta delivered strong performance during 2025 while meaningfully advancing our business and strategic priorities. During 2025, we delivered adjusted EBITDA of $1.1 billion, free cash flow of $415 million or $1.73 per share and average fleet availability of 92.3%. Lower power pricing in Alberta, subdued market volatility and lower wind resources impacted our operating environment during the year. As a result, adjusted EBITDA came in at the lower end of the range of our expectations, while free cash flow came in slightly above the midpoint of our 2025 guidance. In 2025, we had record safety performance with a total recordable injury frequency rate of 0.12 compared to 0.56 in 2024 and our target of 0.37. We entered into a tolling agreement with Puget Sound Energy for the redevelopment of our Centralia facility. We amended and extended our committed credit facilities totaling $2.1 billion with our syndicate of lenders, significantly improving our financial flexibility and ability to execute project financing, which was a strategic priority. We acquired Far North Power, adding 315 megawatts of dispatchable generation in our core market of Ontario. We optimized our Alberta portfolio with a strategic decision to mothball Sundance 6 and Sheerness 1, thereby maintaining the long-term optionality of the units while minimizing costs in the near term. We fully integrated Heartland, which we acquired late in 2024 into our company, providing additional contracted cash flows and realized synergies. We successfully completed our ERP system on time and on budget, and we significantly advanced three natural gas generation projects in Alberta to provide us with optionality to support data centers and grid reliability in the province for decades to come, which we will speak to at our upcoming Investor Day on March 23. Today, we're also very pleased to announce that we have entered into a memorandum of understanding with CPP Investments in Brookfield to advance our data center opportunity at Keephills, which Joel will be speaking to in more detail shortly. And our Board of Directors has approved an 8% increase to our common share dividend to $0.28 per share on an annualized basis, which represents our seventh consecutive annual dividend increase, affirming our company's commitment to returning value to our shareholders. Before turning the call over to Joel, I'd like to acknowledge that this will be my last quarterly conference call with all of you. It has been a privilege and an honor to lead TransAlta since 2021, working with such a committed and talented team. I would also like to thank all of you for your partnership as we work to advance our company for the benefit of our shareholders. I fully support Joel as the next President and CEO of TransAlta, and I'm confident that he is the right person to advance its strategy during this exciting time of opportunity. Joel, I'll now turn it over to you to talk about our financial performance in 2025 and our strategic priorities for 2026.

Thanks, John, and good morning, everyone. I'd like to start by offering congratulations to John on his upcoming retirement and thank him for his leadership, guidance, and strategic vision for TransAlta as well as his active support of my appointment. I look forward to working with the team to continue executing our strategic priorities, and I will announce the CFO successor in coming months. As John mentioned, today, we are pleased to announce that we've entered into an MOU with CPP Investments and Brookfield to advance the data center development in Alberta for which TransAlta will be the exclusive site and power provider. The MOU establishes a framework for phase development at our Keephills site in Parkland County, including initial long-term power purchase agreement for approximately 230 megawatts and the evaluation of additional phases aggregating up to 1 gigawatt of demand. Our Keephills site provides a strategic platform that leverages its large zone land position, existing transmission, natural gas and water infrastructure, and on-site generation to support long-term project scale. We are pleased to be working with CPP Investments in Brookfield and to serve as the exclusive site and power provider for the project. As experienced global infrastructure investors, they have the capability to deliver projects of this size and complexity. We look forward to advancing digital infrastructure capacity and unlocking future investments in Alberta. In December, we announced the signing of a long-term tolling agreement with Puget Sound Energy, or PSC, to convert Centralia Unit 2 from coal to natural gas-fired generation. The agreement provides a fixed price capacity payment, giving PSC the exclusive right to the capacity, energy, and ancillary service attributes and dispatch rights to the 700-megawatt facility. Once converted, the unit will be fully contracted until 2044, providing continued reliable power to the region long beyond its original retirement date and with a lower emissions profile of about 50%. Approximately USD 600 million of capital expenditures will be required to extend the useful life of the facility and convert it from coal to natural gas-fired generation, delivering an anticipated build multiple of 5.5x. The target commercial operation date is late 2028, and we anticipate declaring a final investment decision after receipt of all required approvals currently targeted for early 2027. In December 2025, the U.S. Department of Energy issued a temporary order requiring that the Centralia Unit 2 facility remain available if called upon to operate for a period of 90 days through March 16, 2026. As required, TransAlta is complying with the order and continues to advance the conversion in alignment with PSC in order to achieve the targeted commercial operation date. In November, we announced the acquisition of Far North Power Corporation, and I'm pleased to share that the transaction closed earlier this month. Far North's portfolio consists of four natural gas-fired generation facilities totaling 310 megawatts, including the 120-megawatt Aqua Falls, 110-megawatt Kingston, 40-megawatt North Bay and 40-megawatt Campus casing facilities. The assets, which were acquired for $95 million are expected to add approximately $30 million of average adjusted EBITDA per year with approximately 68% of the portfolio's gross margin contracted to 2031. Beyond the contract period, these assets are attractively positioned for recontracting opportunities and add to our reliable and increasingly diversified portfolio. This acquisition demonstrates progress towards our priority of pursuing strategic M&A. During the quarter, we generated $247 million of adjusted EBITDA, which was $35 million lower than the fourth quarter 2024, primarily due to lower Alberta and Mid-C power prices as well as subdued market volatility impacting energy marketing results. Hydro segment adjusted EBITDA decreased to $39 million compared to $57 million last year due to lower spot power and ancillary prices in Alberta as well as lower merchant volumes. The wind and solar segment produced adjusted EBITDA of $102 million, which was higher quarter-over-quarter due to higher wind resource and availability across the fleet. In the Gas segment, adjusted EBITDA decreased to $96 million from $116 million in 2024, mostly due to lower realized power prices in Alberta, along with higher carbon pricing, partially offset by the addition of the Heartland assets, higher production from Sarnia, and favorable hedge positions settled. The Energy Transition segment delivered adjusted EBITDA of $16 million, a $10 million decrease year-over-year due to lower mid-market prices, partially offset by lower purchase power costs and the settlement of favorable hedge positions. Energy Marketing adjusted EBITDA decreased by $5 million to $21 million, primarily due to comparatively subdued market volatility across North American natural gas and power markets. Corporate costs were lower than last year at $27 million, primarily due to lower incentive costs. Free cash flow was $93 million, which was $47 million higher than the same period last year due to the items noted previously as well as lower overall sustaining capital expenditures. Shifting now to our full year 2025 results. The Hydro segment generated adjusted EBITDA of $285 million, in line with our expectations. The decline year-over-year was driven by lower spot ancillary power prices, partially mitigated by positive contributions from hedging, higher production, and higher environmental and tax attributes being utilized against the Alberta gas fleet's carbon obligation. The wind and solar segment delivered adjusted EBITDA of $338 million, a 7% increase compared to 2024, primarily due to the full year contribution of the Oklahoma wind assets, higher environmental and tax attributes revenues and higher wind resource in Eastern Canada and the U.S. The Gas segment continued to have solid availability and delivered adjusted EBITDA of $438 million. The year-over-year decline was largely due to lower power prices in Alberta, higher fuel and operating costs, and increased dispatch optimization from our Alberta gas fleet, partially offset by the addition of Heartland and our favorable hedge position in Alberta. The Energy Transition segment delivered $100 million of adjusted EBITDA, which increased year-over-year due to lower purchase power costs and higher availability at Centralia. Our Energy Marketing segment delivered performance in line with our 2025 guidance range for gross margin, contributing adjusted EBITDA of $85 million. Energy Marketing results were impacted year-over-year by subdued market volatility across North American natural gas and power markets. And finally, corporate costs marginally increased year-over-year, primarily due to increased spending to support our strategic growth initiatives and associated costs with the Heartland acquisition, which was partially offset by cost-saving initiatives. In aggregate, adjusted EBITDA was $1.1 billion and free cash flow was $514 million or $1.73 per share, which is above the midpoint of our guidance. Turning to our Alberta portfolio. The spot price averaged $44 per megawatt hour in 2025, which was notably lower than the average price of $63 per megawatt hour in 2024. The decline year-over-year was primarily due to incremental generation from the addition of new gas, wind, and solar supply in the province as well as the impact of milder weather throughout the year. The gas fleet exceeded our expectations by capturing an average price of $66 per megawatt hour, a 50% premium to the average spot price. Our hydro fleet also captured significant merchant upside, delivering an average realized price of $58 per megawatt hour, a 32% premium to the average spot price. Our merchant wind fleet realized an average price of $24 per megawatt hour, which was impacted by increased intermittent wind and solar generation in the Alberta merchant power market. Despite relatively benign weather last year, which resulted in lower power prices on average, we captured additional margins by fulfilling a portion of our higher-priced hedges with purchased power when prices were below our variable cost of production. We realized the benefit from approximately 8,600 gigawatt hours of hedges at an average price of $70 per megawatt hour, representing a 59% premium to the average spot price. Last year, we also delivered approximately 3,900 gigawatt hours of ancillary service volumes at a modest 14% discount to the average spot price. By optimizing our fleet throughout the year and fulfilling hedges with purchase power, we were able to respond to higher demand from the AESO and delivered an increase of 9% in ancillary service volumes from our Alberta portfolio compared to the prior year. Turning now to the fourth quarter. Spot prices averaged $43 per megawatt hour, which was lower than the average price of $52 per megawatt hour in 2025. Our hedge position was strong with an average price of $73 per megawatt hour, a 70% premium to the average spot price. Our hydro fleet delivered an average realized merchant price of $53 per megawatt hour, a $0.23 premium to the average spot price, while the gas fleet realized an average merchant price of $65 per megawatt hour, a 51% premium to the average spot price. Our merchant wind fleet, which cannot be dispatched and is subject to wind resource, realized an average price of $26 per megawatt hour. In the quarter, our average realized price for hydro ancillary service pricing settled at $35 per megawatt hour, a 19% discount to the average spot price. Looking at this year, we have approximately 8,500 gigawatt hours of our Alberta generation hedged at an average price of $65 per megawatt hour, well above the current forward curve of $44 per megawatt hour. Going forward, we expect to continue to optimize our fleet and reduce production in low-priced, high-supply hours by fulfilling our financial hedges and customer requirements with open market purchases. For 2027, our team has increased our hedge position to approximately 4,000 gigawatt hours at an average price of $71 per megawatt hour, which remains significantly above current forward pricing levels. We believe the forward price does not fully factor the impact of the REM or 1.2 gigawatts of data center load that will be coming online. We expect the anticipated increase in load will rebalance the current oversupply of generation in the province later in the decade and drive opportunities for growth in the long term. Our dispatchable thermal and hydro fleet has existing capacity to provide reliability and serve the expected load growth, which we'll speak further to at our upcoming Investor Day. Turning now to our 2026 outlook. We expect adjusted EBITDA to be in the range of $950 million to $1.1 billion and free cash flow to be in the range of $350 million to $450 million or $1.18 to $1.51 per share. Now there are a number of factors influencing our 2026 outlook. First, Centralia ceased to operate at the end of 2025, which will have a sizable impact to our adjusted EBITDA and free cash flow until the plant comes back online post conversion to natural gas. Our outlook does not include any impact from the 202(c) order as we expect to recover related costs. Second, we expect Alberta spot power price to remain under pressure with a range of $40 to $60 per megawatt hour, impacting our Alberta merchant portfolio. Third, although we are well hedged both financially and through our commercial and industrial business, the average hedge price has decreased from 2025 levels. And finally, we'll have lower contributions from Sarnia due to a step-down in contracted pricing as well as the expiry of the contract and decommissioning of our Ada facility in Michigan. We'll have higher contributions to our Alberta portfolio through the expected realization of carbon credits against in-year carbon compliance costs in addition to the 2025 carbon compliance costs in Alberta. The confidence in our EBITDA and free cash flow guidance is supported by the performance of the contracted fleet as well as our hedging and optimization strategies, which represents approximately 80% of our expected revenue from our generating facilities. Given that we've now signed our MOU for data centers in Alberta and a definitive tolling agreement at Centralia, we are pleased to announce that we will hold our Investor Day in Toronto on March 23. The presentation will commence at 9:00 a.m. Eastern Time. We will provide an overview of the company's strategic priorities, long-term plan, financial outlook, and growth opportunities. Our Investor Day is open to the investment community and will be hosted in a hybrid format with in-person and live webcast attendance options available. For 2026, our priorities are the following: improving our leading and lagging safety performance indicators while achieving strong fleet availability; delivering adjusted EBITDA and free cash flow within our 2026 guidance ranges that at midpoint of $1 billion and $400 million, respectively; maximizing the value of our legacy thermal sites by advancing our Alberta data center project as well as advancing our coal-to-gas conversion at Centralia toward FID, pursuing strategic M&A opportunities, and maintaining our financial strength and flexibility. Stepping in as CEO next quarter, I believe TransAlta offers a compelling investment opportunity. We are a safe and reliable operator with resilient cash flows underpinned by a diversified hydro, wind, solar, and thermal generation portfolio located across three countries, complemented by our leading asset optimization and energy marketing capabilities. There is significant and growing value in our legacy thermal sites, which our team is actively working on this year to repurpose to meet the growing need for reliable generation in the jurisdictions in which we operate. We also remain a leader across diverse technologies focused on responsible generation. We meaningfully reduced our greenhouse gas emissions, achieving our 2026 emissions reductions target ahead of schedule. We remain disciplined in our approach to growth, focused on delivering value to our shareholders, and we work to diversify our portfolio within our core geographies and increase the stability and contractiveness of our earnings and cash flows. And our company has a sound financial foundation. Our balance sheet is flexible, and we have ample liquidity to pursue and deliver multiple growth opportunities, along with the ability to return capital to our shareholders. Finally and most importantly, we have our people. Our people are our greatest asset, and I want to thank all of our employees and contractors for their commitment and setting the company up for success this year and beyond. Thank you. And I'll now turn the call back over to Stephanie.

Thank you, John and Joel. Josh, would you please open the call for questions from the analysts?

And our first question comes from Mark Jarvi with CIBC.

I wanted to see if you could share some more details around the data center opportunity, just does say, 2027 plus. Just is the expectation that the load will start to ramp in 2027, how long before the 230 megawatts would reach full capacity?

Mark. Look, it's difficult for us to give you a lot more detail on the MOU just because based on the terms of that, we're really quite restricted on what we can actually say. What I can say is that speed to power does remain a priority for our two customers there. We're excited about the partnership that we have with them. Our focus right now, and I know their focus is to get our definitive documents done. And as soon as those documents are completed, which we expect to happen in the year, I think they'll proceed to start making the kinds of investments that they need to up at our Keephills site and get us moving forward. And it will be a gradual ramping up.

Can you mention anything about terms of risk sharing, like who takes the gas price risk and carbon pricing risk and sort of like the structure net back to TransAlta if it's kind of like more capacity or tolling structure for you?

Yes, I cannot provide specific terms related to our arrangements. However, I can share that we believe the commercial framework established with CPPIB and Brookfield is appropriate and reflects the value of the Keephills unit. We are satisfied with the overall arrangement and consider it a solid one from a commercial standpoint.

And I would just add to that, too, that the arrangement does include a long-term PPA, which really contracts merchant cash flows as well.

And is that the rough terms of the PPA been settled at this point, even if you can't disclose anything about it?

I would say that the key elements of the PPA are laid out in the MOU.

Okay. And then it talks about ramping up over time. And just curious where you are in discussions. We've seen some of the engagement feedback on the Phase 2 with the AESO. Just bridging opportunities there to use your coal-to-gas assets as you go beyond 230 megawatts before you'd be able to kind of facilitate a large repowering potentially?

Yes. Look, the AESO and the provincial government continue to do their deliberations on Phase 2. As you can imagine, we're actively involved in that process. I can tell you that our view is that it will be critically important for the province to be able to rely on underutilized generation in essence, as a form of bring your own power, which has been one of the hallmarks of what the government has been talking about to permit a data center industry to develop in a meaningful way in the province of Alberta. I think we've been heard on that. And I think we're in a unique position to be able to ramp up given the sort of breadth of generation that we have in the province of Alberta to actually meet that need. And candidly, with both Sundance 6 and Sheerness I being mothballed, just those two units alone provide a pretty clear path where we could certainly be able to ramp up and meet the up to 1 gigawatt that we're contemplating under the terms of the MOU that we've done with our two partners.

And any sense of when you might get some clarity from the AESO on that?

Yes, we do expect to get it I would expect in the first half of this year. I'm not sure that we're going to get it by the end of this quarter, but I do think they're very mindful about giving clarity to the marketplace. They've got a lot going on, as you can imagine, with the REM and the work that is being done between Alberta and the federal government on the MOU that the two have signed. So there is a lot going on, but I know there is work being done, and we're fully engaged in that.

Our next question comes from Robert Hope with Scotiabank.

I want to revisit the Memorandum of Understanding. In your Q3 update, you mentioned that you aimed to resolve several key items, which could speed up the transition from the MOU to a formal contract. Looking ahead, is it mainly about finalizing the details that will determine the timing for moving the MOU to a firm contract? Or are there multiple parallel efforts with your customers in the data center sector that will also influence the timeline and process?

What I can tell you is that the MOU is an extensive one. There was a lot of discussion and a lot of settlement of terms around essential commercial elements of the arrangement that we have both for the first phase on the 230 megawatts that we've been allocated and the pathways that we could get to an aggregate of gigawatt going forward. As you can imagine, there are a number of definitive agreements that need to be finalized and settled in order for us to be able to move forward and they arrange everything from a definitive PPA with all of the terms to even just lease arrangements related to the actual land that is there. That takes time to be able to do. We're motivated to move that quickly, and our team is ready. They are too. And I think we'll move that, I think, in a very orderly way going forward. The two proponents also have work that they're doing behind the scenes in terms of who their offtakers are and just finalizing their offtake strategy, which continues to proceed. And our view is that given their capabilities and the scope of reach that they have, that they're going to be really successful around that, too. So there's a lot of work that we need to do and they need to do as well, but I think it will all be executable in a normal sort of way. We remain really confident. I can't tell you how pleased we are that we were able to announce it today.

Excellent. And I'll ask you a non-data center question. Can you give us an update on the M&A market and your views on gas assets as well as renewable assets and M&A as a potential form of growth?

Sure, Robert. Joel, why don't you start?

Yes, I'll start. The M&A market remains very active. We are exploring numerous opportunities of various scales. We are seeing a mix of renewable assets, including both wind and solar, on the market. Additionally, there are many opportunities in thermal generation as well. We are focused on adding shareholder value while ensuring any acquisitions align with our strategic priorities moving forward. A strong example is the Far North acquisition that we just completed earlier this month, which we are very pleased with. We continue to identify numerous opportunities in Canada, the United States, and even some in Western Australia.

It is significantly cheaper to buy than to build right now, especially when you consider the timelines required to get a project up and running.

Our next question comes from John Mould with TD Cowen.

Just to apologies, go back to the data center MOU quickly. I just want to see if there's anything you can share in terms of like key gating items to get from MOU to binding agreement? And could you give potential timing for when we might see a binding agreement? Apologies if I missed it. And if not, can you give us a sense of what you're targeting broadly for a mining agreement in terms of time line?

So we can't actually give you specific dates, John. But what I can tell you is that we do expect definitive agreements to be completed in year and frankly, to begin pretty immediately in terms of our engagement. Our team is ready to do that. And we're hopeful that in the coming few months, we'll be able to get those put in place and then be in a position to be able to share with the market more detailed terms once those definitive agreements are in place.

Okay. No, that's helpful. And then I'd just like to ask about on the development side for gas or I should say, brownfield development, you've brought back the Keephills 1 and Sundance 6 repowerings, at least from a regulatory perspective. You've also got the Flipi project. And you made the comment earlier around the buy versus build cost differential. Can you maybe just prioritize some of those repowering opportunities in terms of attractiveness versus what you're seeing in the M&A market? And under what conditions we could potentially see you make an FID on one or more of those repowering opportunities?

Yes. Why don't I start and then Joel, you can jump in. So you're right. We have advanced both Keephills 1 and a Sundance 6 repowering and also the Flipi project. And it was critical from our perspective to do that certainly from a regulatory and permitting perspective before the end of last year because our goal was to be able to qualify all three projects under the existing framework for new gas-fired generation that would be able to run in an unabated way before the end of the year. And from our perspective, we've achieved that objective. So uniquely, I think, certainly in the context of Alberta, we have options now to be able to actually build flexible gas-fired generation in the province to meet the needs of the province going forward in the 2030s and beyond. Candidly, right to 2050 before the terms of the CER would impact that new build generation. It may be that we're successful under the terms of the federal and provincial MOU and the CER goes away, but we certainly didn't want to take that chance and we work through to make sure that regardless of the regulatory regime, we had those options ready. I think to answer your question in terms of new build, it is really hard given the existing suite of generation that we have in the province to utilize or acquire kind of legacy assets to meet incremental load growth. So it is our view that the 2030s will require new build to meet the needs and frankly, to replace some of the retiring generation. Our preference as a company, I would say, Joel, would be to see contracted generation. We're not certainly building merchant gas-fired generation is much tougher for our company to get its head around here in the province of Alberta. But we think we can make the math work on those projects. We're beginning to ramp up our supply chain arrangements in respect of executing them. And there is development and design work that goes on to meet kind of the maximum optionality that we can get under those. So hopefully, that gives you a sense. Joel, I don't know if you want to add anything to that.

The only thing I would add is that we use our existing generation as a bridge to new generation, whether it's for Phase 2 of a data center or some other opportunities that we might see here in the province. Just given the time it takes for new build, the cost of new build in this environment. And to the extent that we do, do new build later this decade, early next decade, it would have to be underpinned by long-term contracts to ensure that we earn a full return of and on capital within the contract.

And the reality, John, is, I mean, the supply chain is such that you wouldn't be able to get turbines, the power island and the like for probably five years out. So you kind of need to begin doing the work to be able to get something that would be in place and get to a COD in the early 2030s.

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

Just picking up on these three natural gas generation projects that you're working on. If I'm not mistaken, the total capacities of these are obviously greater than the 1 gig Phase 2 and MOU, not to mention that two other sites are probably not even at Keephills. So is the idea here for you to help deliver solutions for the two counterparties beyond just Keephills? Or are there other data center customers that you may be looking to serve and secure?

Yes. Maurice, I think the answer to your question is all of the above, to be honest. Look, we're looking at our partners at Keephills are looking at making a significant investment in that part of the world that's going to require us to provide them with reliable generation for a long, long time. It's not just 2030s. It's something that's going to require us to help them into the 2040s and beyond. So we need to think about how do we get newer efficient generation given the time frame for our existing generation to actually meet those particular needs. Our discussions on other potential opportunities have not stopped. So we continue to receive inbounds and we continue to do other work to bring other opportunities for load growth in the province, other data center opportunities as well. And that's something that we're mindful of. And in advancing the three projects, we're just trying to maximize our flexibility. And remember, with K1 and we would be utilizing existing infrastructure with the idea to kind of get a build cost for that new generation to be lower than it would be if we would be doing a pure greenfield site.

And maybe just as a quick follow-up to all this discussion about MOU. I recognize that MOUs are generally not legally binding. Is there a termination fee if the project doesn't proceed?

Yes. I can't share the specific terms, but I consider this MOU to be a strong indication of the parties' commitment to move forward. We have complete confidence in CPP Investments and Brookfield to advance this initiative. They are highly experienced in global infrastructure and have demonstrated their ability to take this forward. We believe they share our enthusiasm for fostering a developing Canadian data center industry. While the terms of the MOU were very important and required extensive discussions to finalize, we trust the parties involved to successfully proceed.

That makes sense. If I could just finish off with a question on funding. Given that you do have a number of funding needs for Centralia, Keephills, Phase 1 and perhaps Phase 2 as well. Can you speak to what you see as being your remaining investment capacity, say, through the end of the decade after you factor in some of these projects on an equity self-funded basis?

Sure. What I would say, Maurice, look, I'm going to turn it over to Joel, but we have a lot of levers that we can pull as a company to meet the funding requirements of our growth going forward. But Joel, maybe you can give your perspective.

Yes. And I would just say, Maurice, that, first of all, with Phase 1, there isn't really a big funding requirement for us for Phase Certainly, as we look to Phase 2, there could be. But again, there thinking about using our existing generation as a bridge to new generation shouldn't require a lot of significant capital spending for that as well. As it relates to Centralia, it's smoothed out over a couple of years based on us getting to an FID sometime early next year. So think of that as spend in '27 and '28 with an in-service kind of later in 2028 that would be very manageable with our existing free cash flow generation along with kind of incremental debt capacity that we have today. So we remain very kind of confident in our ability to fund these opportunities, whether it's data centers here in Alberta, along with Centralia. And we do have a number of levers available to us, including asset rotation and the like here to the extent that we see additional opportunities come our way. So again, we remain very confident in our ability to fund this growth going forward.

I remember in the past, Joel, you mentioned your expectation that the Brookfield debt and hybrids will convert to hydro equity. Is that still your existing assumption?

Yes. So the way it works, Maurice, just for everybody's benefit is that, that option is convertible up until the end of 2028. And so again, it's at the discretion of Brookfield to exercise that option. To the extent that they want to increase the ownership in the hydro assets, they can go up to 49%. But there are certain things that are required for that to occur. And if that were to happen, then certainly, there would be additional cash injection into the company as a result of that. So it's an option that remains open to the end of '28, as I mentioned, but it's the option of Brookfield.

Our next question comes from Benjamin Pham with BMO.

A lot of questions asked so far. Maybe just to continue the topic on Keephills. You mentioned Phase 1, you don't expect the funding need for that. But can you confirm, do you potentially need to spend capital on that as part of the MOU?

First of all, Ben, I apologize for not mentioning this earlier. The capital investment required to execute Phase 1 from TransAlta's perspective is quite minimal. It is important to note that the data center will be grid connected, so there is some capital needed to ensure that connection, including the construction of a substation and some transmission lines. However, this is in close proximity to our existing site and interconnections with the transmission line, making it very modest. We consider K3 as closely tied to this opportunity, and K3 itself is in excellent condition operationally. We have maintained it well, and its reliability is strong, with manageable capital requirements moving forward. Therefore, it is not a significant burden. Even when we look ahead to bridging generation until new generation starts to come online in the 2030s, the capital expenditures will remain relatively modest from TransAlta's perspective.

I understand your point. I'm curious about the progress you've made in negotiations with customers over the past two years. You partnered with Brookfield CPP, which are established players in the market. Could you explain the process and the level of demand you've encountered during this time, as well as the considerations you face when selecting a counterparty? Additionally, do you ever consider negotiating directly with the hyperscalers?

Yes. We conducted a thorough evaluation of data center opportunities. One key factor influencing our strategy was the understanding that there would initially be a limited amount of new data center capacity, around one to two gigawatts. As indicated in Phase 1, the AESO and the province agreed on 1.2 gigawatts, with a gradual integration of data centers moving forward. This understanding shaped our approach regarding the scale needed to meet the demands of potential partners. We believe it’s important to attract hyperscalers, and we remain optimistic about their interest in this market. Our discussions with CPP Investments and Brookfield were encouraging, as they demonstrated a reasonable load expectation that matched our forecasts. Both are exceptional infrastructure investors, with a strong grasp of the Alberta market and extensive global experience in digital infrastructure. We were confident in their ability to execute the project due to their expertise and financial strength. Although we initially explored a wide range of options, we were pleased to partner with them since their expectations aligned with our development plans in the province. We feel fortunate to be collaborating with them.

That's really a good context. See you in about a month or so.

Our next question comes from Julien Dumoulin-Smith with Jefferies.

It's Tanner on for Julien. Congrats on the announcements and congratulations to you, John. A lot of my questions have been asked and answered here, but I did want to see if maybe you would frame expectations for what's in play on the long-term financial plan to be provided next month. Are you going to be looking to provide guidance assuming base business as currently integrated in the portfolio? Or is baseline guidance likely to presume some execution of the MOU or other items? And also, how would you expect to handle or caveat AESO process uncertainties?

Yes, it's Joel here. Our goal is to present an outlook extending to 2029 that reflects our assumptions about power prices in Alberta, which will affect our merchant portfolio. We'll also consider the developments from Phase 1 and the expected service of Centralia sometime in late 2028. Our plan is to offer some foundational information for you to understand what this might look like moving forward at our Investor Day on March 23.

And expectations just around pricing generally and how we see the market evolving in the province for sure.

Our next question comes from Patrick Kenny with NBCM.

We're hearing more and more about Alberta's desire to beef up its interties with neighboring power markets. I was just curious your thoughts on how that might influence your outlook for the Alberta power market over time and also how TransAlta might be able to participate either directly or indirectly in those changing dynamics?

I would say that we are quite optimistic about it. Although we are still at an early stage of discussions, we believe it presents significant opportunities for our company and for the province as a whole. When considering the opportunity, I am focusing on it more from a north-south perspective rather than east-west. We anticipate that load growth requirements in the Pacific Northwest extending into the Rocky Mountain states, down to the Desert Southwest and even California, will remain high. Reliability will continue to be a priority in that region. However, we expect challenges in building new firming generation in the western part of the continent, as well as in transmission to facilitate movement. We see Alberta as an opportunity not only to meet the ongoing demand for data centers from a Canadian perspective but also to serve as a reliability agent for the WEC. Achieving this will require work and investment, but I am excited about the potential. I believe this significantly impacts the three new plants we are developing. What are your thoughts?

Yes. No, Pat, I agree with John. It's an exciting opportunity for us here that we can use existing generation in interim and then a real possibility here for new generation going forward, whether it's east-west or North-South, what we see in our neighboring jurisdictions, again, is a need for firming power. a growing one, actually. growing one. And what I really like here, too, is that you've got strong policy support here within the province to be kind of an energy superpower where we could see additional gas generation being developed in the province for export to neighboring markets. So we see it as a very exciting opportunity. I'd say as a bridge though, again, using our existing generation will be very important to that to the extent that we see opportunities in the future.

Yes, it's an important thrust, I think, Patrick.

Okay. That's great color, guys. I appreciate that. And then maybe just a follow-up on Centralia. I know it's a fluid situation, but just wanted to confirm if you had any more clarity on the 90-day order or if you had any recourse if things are extended and perhaps push back your FID decision on the conversion?

Yes, I'll begin and then I'll turn it over to Nancy to cover anything I might have missed. The initial 90-day order is set to expire in mid-March, and we are fully compliant with it, meaning we are ready to proceed if called upon. However, given the current hydro situation in Washington state, we don't anticipate needing to operate. Our main focus is on obtaining clarity regarding the existing order, and we have the ability to recover our expenses, which alleviates any concerns from a 2026 standpoint. Nancy and her team, along with our commercial team, are actively working on understanding the mechanics of this moving forward. As for the coal-to-gas conversion at Centralia, we are making steady progress. The conversion is endorsed by Washington State, which recognizes the necessity of the facility being transformed to ensure reliability until the mid-2040s. The U.S. Department of Energy also supports our efforts and comprehends the importance of our project. Regardless of how 202(c) develops for the facility, we believe it will not hinder our coal-to-gas conversion plans. We are moving forward diligently on regulatory and planning aspects, as is Puget, as they prepare for the rate base. Nancy, do you have any additional insights on this?

Thanks, John. I believe John has addressed it well. I would like to emphasize that we have had excellent communication and collaboration at both the state and federal levels. While we cannot predict if we will receive another order, I feel that we have laid a strong foundation through our current work to ensure continued progress and conversion. Additionally, as mentioned earlier, we are working closely with our customer, PSC. Therefore, at this time, we do not anticipate any obstacles should that situation arise.

There are no further questions at this time. I would now like to turn the call back over to Stephanie Paris for any closing remarks.

Thank you, everyone. That concludes our call for today. If you have any further questions, please contact the TransAlta Investor Relations team.

Thank you. This concludes today's conference. You may now disconnect.