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 Q4 and FY 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 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 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, thank you for joining our Q4 and FY 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 CAD 1.1 billion, free cash flow of CAD 450 million, or CAD 1.73 per share, an 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 CAD 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 MW 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, 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 23rd. 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. Our board of directors has approved an 8% increase to our common share dividend to CAD 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 worked 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, 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 in Brookfield to advance a data center development in Alberta, for which TransAlta will be the exclusive site and power provider. The MOU establishes a framework for phased development at our Keephills site in Parkland County, including initial long-term power purchase agreement for approximately 230 MW and the evaluation of additional phases aggregating up to 1 GW of demand. Our Keephills site provides a strategic platform that leverages its large zoned 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 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 PSE, to convert Centralia Unit Two from coal to natural gas-fired generation. The agreement provides a fixed-price capacity payment, giving PSE the exclusive right to the capacity, energy, and ancillary service attributes and dispatch rights to the 700 MW 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 $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. 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 Two facility remain available, if called upon, to operate for a period of 90 days through March 16th, 2026. As required, TransAlta is complying with the order and continues to advance the conversion in alignment with PSE 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 MW, including the 120-megawatt Iroquois Falls, 110 MW Kingston, 40 MW North Bay, and 40-megawatt Kapuskasing facilities. The assets, which were acquired for CAD 95 million, are expected to add approximately CAD 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 CAD 247 million of Adjusted EBITDA, which was CAD 35 million lower than the fourth quarter of 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 CAD 39 million, compared to CAD 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 CAD 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 CAD 96 million from CAD 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 CAD 16 million, a CAD 10 million decrease year-over-year due to lower Mid-C market prices, partially offset by lower purchased power costs and the settlement of favorable hedge positions. Energy marketing Adjusted EBITDA decreased by CAD 5 million to CAD 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 CAD 27 million, primarily due to lower incentive costs. Free cash flow was CAD 93 million, which was CAD 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 CAD 285 million, in line with our expectations. The decline year-over-year was driven by lower spot and 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 CAD 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 CAD 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 CAD 100 million of Adjusted EBITDA, which increased year-over-year due to lower purchased 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 CAD 85 million. Energy marketing results were impacted year-over-year by subdued market volatility across North American natural gas and power markets. 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 CAD 1.1 billion, and free cash flow was CAD 514 million, or CAD 1.73 per share, which is above the midpoint of our guidance. Turning to our Alberta portfolio, the spot price averaged CAD 44 per MWh in 2025, which was notably lower than the average price of CAD 63 per MWh 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 CAD 66 per MWh, a 50% premium to the average spot price. Our hydro fleet also captured significant merchant upside, delivering an average realized price of CAD 58 per megawatt hour, a 32% premium to the average spot price. Our merchant wind fleet realized an average price of CAD 24 per MWh, 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 purchase power when prices were below our variable cost of production. We realized the benefit from approximately 8,600 GWh of hedges at an average price of CAD 70 per MWh, representing a 59% premium to the average spot price. Last year, we also delivered approximately 3,900 GWh 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 Q4, spot prices averaged CAD 43 per MWh, which was lower than an average price of CAD 52 per MWh in 2025. Our hedge position was strong, with an average price of CAD 73 per MWh, a 70% premium to the average spot price. Our hydro fleet delivered an average realized merchant price of CAD 53 per MWh, a 23% premium to the average spot price, while the gas fleet realized an average merchant price of CAD 65 per MWh, 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 CAD 26 per MWh. In the quarter, our average realized price for hydro ancillary service pricing settled at CAD 35 per MWh, a 19% discount to the average spot price. Looking at this year, we have approximately 8,500 GWh of our Alberta generation hedged at an average price of CAD 65 per MWh, well above the current forward curve of CAD 44 per MWh. We expect to continue to optimize our fleet and reduce production in low-price, high-supply hours by fulfilling our financial hedges and customer requirements with open market purchases. For 2027, our team has increased our hedge position to approximately 4,000 GWh at an average price of CAD 71 per MWh, 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 GW 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 CAD 950 million to CAD 1.1 billion, and free cash flow to be in the range of CAD 350 million to CAD 450 million, or CAD 1.18 to CAD 1.51 per share. There are a number of factors influencing our 2026 outlook. 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. We expect Alberta spot power price to remain under pressure with a range of CAD 40 to CAD 60 per MWh, impacting our Alberta merchant portfolio. Although we are well hedged both financially and through our commercial and industrial business, the average hedge price has decreased from 2025 levels. 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 Monday, March 23rd. 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 have midpoints of CAD 1 billion and CAD 400 million, respectively, maximizing the value of our legacy thermal sites by advancing our Alberta Data Center project, as well as advancing our cold-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 contractedness of our earnings and cash flows. 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, most importantly, we have our people. Our people are our greatest asset. I want to thank all of our employees and contractors for their commitment in setting the company up for success this year and beyond. Thank you. 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? Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. One moment for questions. Our first question comes from Mark Jarvi with CIBC. You may proceed. Yeah, thanks. Good morning. I wanted to see if you could share some more details around the data center opportunity, just does say 2027 +. Just the expectation that the load will start to ramp in 2027, how long before the 230 MW would reach, you know, full capacity? Good morning, Mark. Look, it's difficult for us to give you a lot more detail on the MOU, just, you know, because based on the terms of that, we're really quite restricted on what we can actually say. What I can say is that, you know, 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. 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 a capacity or tolling structure for you? Yeah, I wish, I don't think I can give you those kinds of terms based on the arrangement that we have. What I can tell you, though, is that, you know, we think the commercial framework that we've developed with CPPIB and also Brookfield is an appropriate one, and I think it is reflective of the value of the Keephills unit that we have there. We're pleased with the overall arrangement that we have and think it's a really sound one from a commercial perspective. I would just add to that, too, that the arrangement does include a long-term PPA, which really contracts merchant cash flows. Yeah As well. 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. It talks about, you know, ramping up over time, and just curious where you are in discussions. I've seen some of the engagement feedback on the phase two with the AESO, so just bridging opportunities there to use your quarter gas assets, you know, as you go beyond 230 MW before you'd be able to kind of facilitate a larger repowering potentially. Yeah. Look, the AESO and the provincial government continue to do their deliberations on phase two. As you can imagine, we're actively involved in that process. I can tell you that, you know, 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. Candidly, with both Sundance 6 and Sheerness 1 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 one GW that we're contemplating under the terms of the MOU that we've done with our two partners. Any sense of when you might get some clarity from the AESO on that? We do. Yeah, we do. We do expect to get it, you know, 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. There is a lot going on, but I know there is work being done, and we're fully engaged in that. It's good to hear. Okay, look forward to seeing you on the twenty-third. Thanks so much, Mark. Thank you. Our next question comes from Robert Hope with Scotiabank. You may proceed. Good morning, everyone. Want to go back to the MOU. Along with Q3, you had kind of highlighted that you wanted a bunch of the key items to be largely ironed out, which could accelerate the path, but from a MOU to the contractual signing. As we look forward, is it just ironing out the details that is the key gating factor on moving the MOU to a firm contract? Or are there a number of parallel paths with your customers, on the data center side, which kind of will also weigh into the timeline and the process there? 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, you know, essential commercial elements of the arrangement that we have, both for the first phase on the 230 MW we've been allocated, and the pathways that we could get to an aggregate of a 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 range 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, and 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, you know, who their offtakers are, and just finalizing their offtake strategy, which continues to proceed. You know, our view is that, given their capabilities and the scope of reach that they have, that they're gonna be really successful around that too. There's a lot of work that we need to do, and they need to do as well, but I think it'll 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. 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? Yeah, I'll start. Good morning, Robert. It's the M&A market, I would say, remains very active. We're looking at a lot of various opportunities in various scale, if you will. I'd say that we see both a complement of renewable assets that are coming to market, both wind and solar, and similarly, we're seeing a lot of opportunities in thermal generation as well. Again, we remain very active and very focused with the, you know, the eye on adding shareholder value. It has to be obviously aligned with our strategic priorities going forward here. You know, a good example, again, is the Far North acquisition that we just closed here earlier in the month that we are very happy with. We continue to see a lot of opportunities both, in Canada and the United States, and even some opportunities in Western Australia as well. The only other I would add to that would be it is, as you know, and you know this, it is significantly cheaper to buy than it is to build, right now, particularly if you factor in sort of the timeframes for being able to get a project up and running. All right. Appreciate that. Congrats on the MOU and the pending retirement. Thanks, all. Thanks a lot, Robert. Thank you. Our next question comes from John Mould with TD Cowen. You may proceed. Morning, thanks. Just to, apologies, go back to the data center MOU quickly. 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. Could you give potential timing for, from when we might see a binding agreement? Apologies if I missed it, and, you know, if not, can you give us a sense of what you're targeting broadly for a binding agreement in terms of timeline? We can't actually give you specific dates, John. Good morning, by the way. 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 you know, 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. Thank you. 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 Pippy project, and, you know, you made the comment earlier around the buy versus build cost differential. You know, 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, you know, under what conditions we could potentially see you make an FID on one or more of those repowering opportunities. Yeah, why don't I start. Then Joel, you can jump in. You're right. We have advanced both a Keephills 1 and a Sundance 6 repowering, and also the Pippy project. 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. From our perspective, we've achieved that objective. You know, uniquely, I think, certainly in the context of Alberta, we have. three options now to be able to actually build flexible gas fire 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 worked 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. It is our view that the 2030s will require new build to meet the needs and frankly, to replace some of the retiring generation. You know, our preference as a company, I would say, Joel, would be to see contracted generation. You know, we're not certainly building merchant gas fire generation is much tougher for our company to get its head around here in the province of Alberta. 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. 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. Correct. You know, whether it's for phase two 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 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 on capital within the contract. The reality, John, is, I mean, the supply chain is such that you wouldn't be able to get, you know, turbines, the power island, and the like, for probably five years out. You kind of need to begin, you know, doing the work to be able to get something that would be in place and get to a COD in the early 2030s. Okay. That's great. Thanks very much for taking my questions. I'll look forward to seeing you at the Investor Day. Thanks, John. Thanks, John. Thank you. Our next question comes from Maurice Choy with RBC Capital Markets. He may proceed. Thank you. Good morning, everyone. 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 II in the MOU. Not to mention that two of the sites are probably not even at Keephills. 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? Yeah, I think. Good morning, Maurice. I think the answer to your question is all of the above, to be honest. Look, we're looking at, you know, 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, you know, 2030s, it's something that's going to require us to help them, you know, into the 2040s and beyond. We need to think about how do we get, you know, newer, efficient generation, given the timeframe 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, you know, other opportunities for load growth in the province, other data center opportunities as well. That's something that we're mindful of, and in advancing the three projects, we're just trying to maximize our flexibility. Remember, with K1 and S6, you know, 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. 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? Yeah, Again, I can't get into what the terms are, but I would say this: We view this MOU as a real expression of the intentions, very definitive intentions of the parties to move forward. We have absolute confidence in CPP Investments and Brookfield to be able to move it forward. I mean, they're incredibly experienced global infrastructure players. They have proven capabilities to be able to move this forward. Frankly, I think they too, like we are excited about developing a nascent Canadian, you know, data center industry in the country. You know, although the terms of the MOU were critically important and they took, you know, weeks and weeks and months of discussion, to get done, we have absolute confidence and faith in the parties that we're dealing with to be able to move forward. 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 one and perhaps phase II 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. you know what I, 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, you know, our, our growth going forward. Joel, maybe you can give your perspective. I would just say, you know, Maurice, that, you know, first of all, with phase I, there isn't really a big funding requirement for us for phase I. Certainly as we look to phase II, 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, you know, smoothed out over a couple of years, you know, based on us getting to an FID sometime early next year. Think of that as, you know, spend in 2027 and 2028 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. 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, you know, asset rotation and like here, to the extent that we see, you know, additional opportunities come our way. 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? Yeah. The way it works, Maurice, just for everybody's benefit, is that that option is convertible up until the end of 2028. 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%. 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. It's an option that remains open to the end of 2028, as I mentioned, but it's the option of Brookfield. That's great coverage. Thank you very much, and congrats to both of you, John and Joel, from RBC. Thanks so much. Thanks, Maurice. Thank you. Our next question comes from Benjamin Pham with BMO. You may proceed. Hi, thanks. Good morning. A lot of questions asked so far, maybe just to continue the topic on Keephills. You mentioned phase one. You don't expect a funding need for that. Can you confirm, do you potentially need to spend capital on that as part of the MOU? You know, we can't really. First of all, good morning, Ben. Sorry, I should have started with that. We can't really get into what I would say is, the capital investment required to sort of execute phase one from a TransAlta perspective is negligible, I think is the right way to kind of describe it. Remember, it'll be grid connected. There is a little bit of capital that is required to ensure that the data center will be connected to the grid. There is a substation and some transmission that needs to be built out, but it's very proximate to the site that we have and the interconnection already that we have with the transmission lines. I would say it's very, very modest. You know, when we think of the opportunity, we tend to think of K3 as effectively being the facility that is sort of tied to the opportunity, and K3 itself is in very good shape from an operational perspective. You know, we've maintained that facility very well. We're very pleased with its reliability, and have very manageable sort of sustaining capital requirements for that going forward. It's not at all a burdensome requirement. I would say even when we think of bridging generation, Joel, to, you know, the point in time where we get to potentially having new generation build, which is really in the 2030s, relatively modest capital expenditures from a TransAlta perspective going forward. Okay, got it. I'm wondering too, I know you've been advancing negotiations with customers the last two years. You arrived at Brookfield CPP, ultimately, which are pretty good and well-established customers and counterparties. Can you maybe just walk through maybe, I don't know, qualitatively, the process, the level of demand, the last couple of years experience, the puts and takes you're facing ultimately by choosing the counterparty? Do you also consider just going direct with a hyperscaler as part of those negotiations? We did run actually a pretty comprehensive process with respect to the data center opportunities. One of the things that always, I would say, shaped our approach or our strategy on the data center was sort of the realization that, at least initially, there would be a limited amount of new data center capacity that would come into the province, whether that would be one GW or two, like somewhere in that kind of space. As you saw with phase one, the AESO and the province landed at 1.2 GW. Kind of a gradual, I think, feathering in, is it, to use sort of a TransAlta kind of mindset of the data centers going forward. That actually kind of colored our approach in terms of what was the scale that was available to be able to meet the demands of the individuals that we were speaking to. Our view was that it would be great to have hyperscalers, and we certainly do expect and hope that they end up coming into the jurisdiction. When we began our conversations, it was great to enter into discussions with CPP Investments and Brookfield. They had the kind of ramping profile and sort of load expectations that we thought were reasonable and kind of met the envelope that we thought that we were going to get. It really aligned. And look, you've alluded to it, they're both outstanding infrastructure investors, not just in Canada but globally. They both have a very good understanding of the Alberta market. They have extensive experience, not just experience, but relationships from a digital infrastructure perspective, globally, and we absolutely knew that they had both the expertise and capital depth and execution capability to be able to get this done. You know, although we cast our net, I would say, fairly wide, initially, we were very pleased that we were able to be to have them as partners, because their expectations kind of aligned with sort of the reality of what we thought the pathway was going to be, the development in the province. We consider ourselves quite fortunate to be working with and for them. Okay, that's really good context. See you in about a month or so. Thanks. Thank you. Thank you. Our next question comes from Julien Dumoulin-Smith with Jefferies. He may proceed. Hi, team, it's Tanner on for Julien. Congrats on the announcements, and congratulations to you, John. Thank you. Just, you know, a lot of my questions have been asked and answered here. 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? Also, how would you expect to handle or caveat AESO process uncertainties? Thanks. It's Joel here. Our intention here is to have probably a bit of an outlook out to 2029, that's, you know, reflective of, you know, kind of our assumptions around power prices in Alberta, the impact that will have, obviously, in our merchant portfolio. Obviously, also factoring in some of the, what we see from phase one, along with Centralia, you know, coming into service sometime later in 2028. Our intention is to provide some building blocks for you to see what that could look like here going forward at our Investor Day on March 23rd. Expectations just around pricing generally and how we see the market evolving in the province, for sure. Great. Thank you. That's all I had. Great. Thank you. Thank you. Our next question comes from Patrick Kenny with NBCM. You may proceed. Thank you. Good morning, everybody. We're hearing more and more about, you know, Alberta's desire to beef up its interties with neighboring power markets. I was just curious, you know, your thoughts on how that might influence your outlook for the Alberta power market over time, and also, you know, how TransAlta might be able to participate either directly or indirectly in those changing dynamics? Good morning, Patrick. I would say that we are fairly optimistic about it, to be honest. I think we're still at an early stage of having some of those discussions, but we actually think it creates a considerable amount of opportunity for certainly our company and candidly, for the province as a whole. What we are seeing. When I think of the opportunity, I'm thinking of it, to be honest, less east-west, more north-south, to be candid. You know, we think that, you know, load growth requirements in the Pacific Northwest, you know, into the Rocky Mountain states, frankly, all the way down to the desert Southwest, that even California will remain high. We think that reliability will continue to be a real priority in that part of the world. I think the ability to build new firming generation, kind of in the western part of the continent, will remain challenged, I think, at times, as will transmission generally to move it around. We actually see an opportunity in Alberta, not just to kind of meet the ongoing needs for data center demands, really from a Canadian perspective, but also to be a bit of a reliability agent, if I can use that term, for kind of the WECC, ideally, as kind of a an opportunity set that we're seeing. Look, it's going to take work and investment to be able to see that come through, but I know, I'm excited about it, and I think, Joel, that it weighs heavily on the three new plants even that we're working to develop. Maybe your thoughts? Yeah. No, Pat, I agree with John. It's an exciting opportunity for us here, that we can use existing generation in the interim and then a real possibility here for new generation, going forward, whether it's, you know, east-west, or north-south. You know, what we see in our neighboring jurisdictions, again, is a need for firming power. A growing one, actually. A growing one. You know, what I really like here, too, is that you've got strong policy support here within the province. Yeah T o be kind of an energy superpower, where we could see, you know, additional gas, generation being developed in the province, for export to neighboring markets. 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, you know, see opportunities, in the future. Yeah, it's an important thrust, I think, Patrick. Okay. No, that's great color, guys. Appreciate that. Maybe just to 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, you know, perhaps push back your FID decision on the conversion? Yeah. Why don't I start, maybe I'll turn it over to Nancy to see if there was anything I didn't really cover off. Look, the initial 90-day order expires mid-March. You know, we are fully in compliance with the order in the sense of being available, should we be asked to run. We don't expect that, given kind of, you know, how flush the hydro situation is in Washington State right now. I think our primary focus is more on getting clarity on the existing order. We do have the ability to recoup our expenses, which is why we're not, you know, we're not particularly concerned about that from a 2026 perspective. Certainly, Nancy and her team and our commercial team are focused on getting clarity around, you know, the mechanics of that going forward. With respect to the coal-to-gas conversion at Centralia, we continue to work that through in a very uninterrupted sort of way. Our general sense is that Not our general sense, the reality is the conversion is supported by Washington State. They need it. They're accepting of that facility being converted, and they see that the need for that facility to provide reliability into the mid-2040s is critically important. In tandem, so does the U.S. Department of Energy. The federal government in the United States is also supportive of what we're trying to do there and understands it. I don't. You know, regardless of kind of the trajectory of 202(c) on the facility, it is our expectation that it won't impede the work that we're trying to do from a coal-to-gas conversion. Like I can tell you, it's full steam ahead from a regulatory and planning perspective for us and for Puget, candidly, as they look to get the rate base. Nancy, I don't know if you have any additional perspectives on that? Thanks, John, and good morning. I think John's covered it well. I think the only thing I would add to maybe sort of a fine point on some of his comments is, you know, we've had very good communication and collaboration, both at the state and federal levels. Yes. I think in respect of, you know, we can't predict whether or not we will receive another order. At the same time, should that occur, sort of the building blocks, I think, are in place in respect of the work we're doing now to continue to progress through and to continue to proceed with the conversion. Again, as we stated at the outset, working very closely with our customer, PSE, also. You know, I don't think at this time we foresee any obstacles should that occur. Okay. Thank you. That is great color. I'll leave it there. Great. Thanks, Patrick. Thank you. 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.