Good morning. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation second quarter 2026 results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star one one on your telephone keypad. If you would like to withdraw your questi on, please press star followed by one one again. Thank you. Ms. Paris, you may begin your conference. Thank you, Michelle. Good morning, everyone. My name is Stephanie Paris, and I am the Vice President of Investor Relations and Corporate Strategy of TransAlta. Welcome to TransAlta's second quarter 2026 conference call. With me today are Joel Hunter, President and Chief Executive Officer, Mike Politeski, EVP Finance and Chief Financial Officer, and Chris Fralick, EVP Generation and Chief Operating Officer. 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 made available later today, and the transcript will be posted to our website shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide two, detailed further in our MD&A and incorporated in full for purposes of today's call. All amounts referenced are in Canadian dollars unless otherwise noted. The non-IFRS terminology used, including Adjusted EBITDA and free cash flow, are reconciled in the MD&A for your reference. On today's call, Joel and Mike 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 Joel. Thanks, Stephanie. Good morning, everyone, and thank you for joining our second quarter conference call. TransAlta delivered solid operational financial performance during the second quarter 2026, demonstrating our fleet's continued resilience during challenging market conditions. During the quarter, we delivered Adjusted EBITDA of CAD 291 million, free cash flow of CAD 143 million, or CAD 0.47 per share, and average fleet availability of 90.2%. While our Alberta merchant portfolio continues to be impacted by softer prices, our hedging strategy and active asset optimization generated realized prices that were well above spot prices during the quarter, along with our hydro and wind assets providing significant environmental offsets to our gas fleet's 2025 carbon compliance obligation. We remain confident in achieving our 2026 guidance range, which Mike will talk about later. In the quarter, we continued to advance our data center strategy with CPP Investments in Brookfield. More broadly in Alberta, positive recent developments reinforce the momentum and collective commitment across government and industry to develop AI infrastructure. In particular, in June, the government of Alberta published their data center regulations, giving authority to the AESO to proceed with the next phase of their large load integration plan. The regulation includes provisions that permit the AESO to determine underutilized capacity that can be used to serve incremental data center load. Consistent with our messaging at Investor Day, we believe that our gas-fired steam units constitute underutilized generation that can support both grid reliability and the continued build-out of AI infrastructure in the province. Our gas-fired steam units are designed to operate as base load and can produce at capacity factors greater than 90%. The recent performance and lower capacity factors, averaging around 20% in 2025, have been driven by economic decisions, not capability. Speed to power is critical. We view the data center regulations as an important step towards framework clarity. The determination on how underutilized assets will be incorporated into the build-out of AI infrastructure will be made by the AESO, and we remain actively engaged with them. Also in the quarter, we fully integrated the four gas-fired facilities in connection with the acquisition of Far North. In June, the U.S. Department of Energy issued its third temporary order requiring that Centralia Unit 2 remain available for operation if needed for a period of 90 days. TransAlta is adhering to the order, and we plan to submit a request for reimbursement to the FERC for costs related to the second order. Progress continues with the conversion of the unit to natural gas. I am pleased to report that our timeline for a final investment decision in the first quarter of 2027 remains on schedule. Last month, we announced that TransAlta has entered into an agreement to acquire two natural gas-fired peaking facilities in Colorado for US$1 billion, paired with a common share offering for CAD 350 million. Both assets are fully contracted to investment-grade counterparties under long-term tolling agreements that include full cost pass-through of all operations and maintenance, fuel and capital expenses, which meaningfully reduce the risk profile of the acquired assets. The acquisition is expected to deliver CAD 110 million per year in low risk, high-quality Adjusted EBITDA to our portfolio and is immediately accretive to free cash flow per share. We expect closing to occur in the fourth quarter following receipt of all regulatory approvals as well as Canyon Peak Power achieving commercial operations. Adding stable operating assets like this delivers immediate cash flow that can be redeployed into our most compelling growth initiatives, including the Centralia coal-to-gas conversion and Alberta data center projects. Finally, we realigned our executive management team, adding Mike Politeski as our EVP Finance and Chief Financial Officer, and Grant Arnold as our EVP Growth and Chief Commercial Officer. In addition, Nancy Brennan assumed an expanded role as Chief Legal, People, and Corporate Affairs Officer, and Chris Fralick's new title is EVP Generation and Chief Operating Officer. Supported by an exceptional team across the organization, I am confident that we have the right people and structure to execute our strategy and realize long-term value creation for TransAlta. I'll now turn the call over to Mike to talk more about our financial performance in the second quarter of 2026. Thanks, Joel. Good morning, everyone. During the quarter, we generated Adjusted EBITDA of CAD 291 million, despite challenging market pricing in Alberta. Our hydro segment Adjusted EBITDA was CAD 87 million, down CAD 39 million from the same quarter in 2025 due to lower Alberta spot and hedge prices, as well as lower intercompany sales of emissions credits. Our wind and solar segment reported Adjusted EBITDA of CAD 90 million. Consistent with the prior year, as higher U.S. wind resource mitigated lower Alberta pricing and reduced wind resource in Eastern Canada. Within our gas segment, Adjusted EBITDA was CAD 14 million higher than the prior year due to strong optimization of our Alberta fleet and positive contributions from our Far North acquisition. Consistent with prior years, our second quarter results benefited from the realization of emissions credits against our prior year carbon obligation. For the balance of 2026, we expect additional contributions to our segments from the realization of carbon credits against in-year carbon compliance costs. Our energy marketing Adjusted EBITDA decreased by CAD 16 million, primarily due to subdued market volatility in Western Power markets and lower realized gains within the quarter. We expect to have more gains realized by year-end as favorable trade positions settle. In our corporate segment, costs were 8% lower than the prior year due to initiatives to control spend. Finally, our energy transition segment Adjusted EBITDA was lower than the prior year due to the Centralia contract expiry at the end of 2025. We also generated strong free cash flow during the second quarter, totaling CAD 143 million. Our sustaining capital expenditures were down CAD 18 million year-over-year. However, this was primarily timing related, and we continue to expect sustaining capital of CAD 140 million-CAD 160 million in 2026. Turning to the Alberta portfolio, spot prices averaged CAD 29 per MWh in the second quarter, notably lower than the CAD 40 per MW in the second quarter of 2025. The decline was primarily due to seasonally lower demand and continued strong supply in the market. Although prices were low, we enhanced our margins by meeting portions of our higher price hedge commitments through power purchases when market prices were below our variable production costs. We benefited from approximately 2,400 GWh of hedges at an average price of CAD 63 per MWh, which was CAD 34 per MW higher than the average spot price. Our gas fleet realized an average price of CAD 68 per megawatt hour, a significant 134% premium to the average spot price, largely due to our dispatch optimization during high price hours, which materially raised our realized price. The hydro fleet also continued to capture merchant upside, delivering an average realized price of CAD 36 per megawatt hour, a 24% premium to the average spot price. Our merchant wind fleet realized an average price of CAD 14 per MWh, which was impacted by increased thermal production and intermittent wind and solar generation. During the quarter, we also delivered approximately 900 GWh of ancillary service volumes at a 14% premium to the average spot price. Through effective fleet optimization and meeting hedge obligations with purchased power, we consistently address the AESO need for reliability products. We continue to have a strong hedge book to support our Alberta cash flows. For the balance of the year, we have approximately 4,500 GWh of our Alberta generation hedged at an average price of CAD 64 per MWh, well above current forward pricing. For 2027, we have approximately 6,600 GWh hedged at an average price of CAD 64 per MWh, also well above current forward levels. Looking ahead, we continue to expect the Alberta supply and demand imbalance will correct later this decade with anticipated load growth. We believe we are well-positioned to manage through the current pricing environment and to capture growth opportunities to drive long-term value creation for our shareholders. Turning to the balance sheet. In June, Moody's reaffirmed our Ba1 credit rating with a stable outlook, and last week, S&P reaffirmed our BB+ rating while shifting the outlook to negative. We remain committed to strengthening our balance sheet through multiple levers, including asset recycling. The forecast tightening of the Alberta market and recovery of power prices, along with the expected cash flows from Centralia after conversion, will provide cash flow growth to further strengthen our financial position. Overall, we are pleased with our year-to-date operational and financial performance across all our business segments, and we remain confident in our ability to meet our 2026 guidance range. Our contracted fleet, strong hedge position, and consistent optimization provide us with core cash flows even in a low merchant power pricing environment. The Colorado acquisition is not factored into our reaffirmation of guidance, and upon closing, which is expected in the fourth quarter of 2026, will add to our financial results. I'll now turn the call back over to Joel. Thanks, Mike. This year, we remain focused on the following priorities. 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. Maximizing the value of our legacy thermal sites by advancing our Alberta data center strategy, as well as advancing our coal-to-gas conversion at Centralia toward a final investment decision. Pursuing strategic M&A opportunities. Enhancing our financial strength and flexibility through disciplined capital allocation and cost control. I believe TransAlta offers a compelling investment opportunity. We've operated a safe and reliable power generation fleet for over 115 years, providing strong and consistent cash flows. This strength is grounded in a diversified portfolio of hydro, wind, solar, storage, and thermal assets across three countries. It is enhanced by our industry-leading asset optimization and energy marketing capabilities. Our legacy sites continue to represent considerable and increasing value. We are proactively pursuing repurposing initiatives at these facilities to address the growing demand for reliable power in our operating markets. Concurrently, we maintain a leadership position across multiple technologies, consistently prioritizing responsible and reliable generation. We are disciplined in how we grow. Our priority is creating shareholder value as we diversify our portfolio within our core geographies and continue to increase the stability and contracted nature of our cash flows. This strategy is supported by a strong financial foundation. We have a flexible balance sheet and ample liquidity, giving us the ability to pursue and deliver multiple growth opportunities while continuing to return capital to shareholders. Finally, and most importantly, we have our people. Everything we achieve is powered by the dedication and expertise of our employees and contractors. I want to thank them for their commitment and for positioning TransAlta for continued success in 2026 and beyond. Thank you. I'll now turn the call back over to Stephanie. Thank you, Joel. Michelle, 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. In fairness to all, we ask that you please limit yourself to one question and one follow-up. One moment as we compile our Q&A roster. Our first question is going to come from the line of Mark Jarvi with CIBC. Your line is open. Please go ahead. Good morning, everyone. Just in terms of those discussions with the AESO and the underutilized assets, do you have any sense of when you might have clarity and just how that's impacting anything about getting from the MOU to a definitive agreement with Brookfield and CPP? Thanks, Mark, and good morning. It's Joel here. I would say there's ongoing discussions with AESO. Again, we are very encouraged, as mentioned in our prepared remarks, by the data center regulations that really turn over to the AESO to determine what is underutilized capacity here as it relates to our gas-fired steam units. Again, we're working with them very collaboratively here as we move forward. I would say with the MOU and the definitive agreements that we have with CPP Investments and Brookfield, those continue to advance, as we highlighted when we announced the MOU back in February. Again, working alongside those two parties and we continue to remain very confident in our ability to bring forward our data center option here later in the year. The expectation is a matter of months? Could it be a couple of quarters before you have clarity on the underutilized assets? Hard to say. We can't really speak for the AESO, Mark. We are actively engaged with them, we're hopeful it will be in the next quarter or so. We can't speak on behalf of them as to the timing. That might influence how you think about scaling beyond the 230 MWs. If that drags on a little bit, hopefully it doesn't, would you look at maybe moving to FID on the first phase of the 230 MWs from phase one allocation and then subsequent scale-up after that through a follow-on agreement? Is there a way to sequence sort of, I guess, moving through FID? I think that's very possible here, Mark, that we would look to that. It's really up to us along with Brookfield and CPPI to determine that. As we said before, 230, we were very pleased with that in the phase one allocation. Looking forward to how we can build upon that. I'd say that there's possibility here that that could advance the 230 before the remaining here with the underutilized capacity. Okay. I'll leave it there for now. Thanks, Mark. Thank you. Our next question is going to come from the line of Maurice Choy with RBC Capital Markets. Your line is open. Please go ahead. Thank you, good morning, everyone. Just wanted to touch on any updates you have on the asset recycling initiatives that was mentioned earlier to reduce debt. What are some of the things that are influencing the timing and perhaps selection of some of these assets for sale? Yeah. Thanks, Maurice. We are very active. We have a few that are well underway. Obviously, we can't give everything away here as we're in processes, if you will. I think what you'll see going forward here, Maurice, just given the amount of opportunities that we see going forward, whether it's a Centralia coal-to-gas conversion, AI data centers, M&A opportunities, and then further kind of organic growth in our portfolio that we're seeing, that I think portfolio rotation will become more active here. We do have a few processes underway. Can't say anything more, but we are certainly very active in that space right now. Looking forward to hearing more of that. If I could just finish off with just a more broad discussion about forward power prices. I think over the last few weeks since all these announcements were made, we've seen forward prices move up a little bit, particularly for 2029. Yet it still is below the 80 - 120 range that you laid out in Investor Day. You mentioned at the start of the call that you've seen a lot of positive developments in the province thus far. Just curious as to what else you're expecting to hear in the coming months that would prompt the forwards to rise into your projected range. First of all, Maurice, when you look out further, like to Cal 28 and Cal 29, there isn't a lot of liquidity. Generally, when you look at forward pricing, you're out 12 to maybe 18 months at best. When I look at Cal 29 today, I think it's marked around CAD 81. It is actually in the range of that CAD 80-CAD 120, that we highlighted at Investor Day. Certainly, we've seen an improvement, in those forward prices since even the announcement with Meta around their data center project with Kineticor and Pembina. We remain very encouraged by that. I think for the market, as we move forward here, just getting further clarity around the ramping of the load growth, will certainly support further the forward pricing. Again, when I look at where we are today, for Cal 29 from where we were pocket Investor Day at the end of March, we've certainly seen an improvement there. I would expect that over time, as the market sees or has better visibility behind the load ramp, if you will, that will further support these forward prices and could even go higher. Maybe on that last note, a quick follow-up here. Obviously, we know where CONE is in the province. Also historically when we had, I think it was 2021-2023, when we had triple-digit power prices, that led to the regulator looking more into the industry. In this world of affordability, is there such thing as a balance number where pretty much everyone's happy? Yeah. When you look at, again, the CONE or the cost new entry that you referred to, I know that that was something that was highlighted with the recent announcement from Pembina and Kineticor, in the low 100s, if you will, which completely makes sense, right, given the cost of new build that we're seeing today relative to even where we were back in 2021 and 2023, as you referenced, where we saw triple-digit pricing. Again, this I think, is where it's really important to have legacy generation, like we have with our gas-fired steam units to help support the infrastructure build-out that we've talked about. That pricing would be below CONE. Where you're seeing here going forward is the market will continue to tighten. We're not seeing much by way of new supply. We're obviously seeing load growth coming, whether it's organically, in the province, as we highlighted at our Investor Day back in March, along with phase one here. We can't say exactly where that price point would be. I think when you look at Alberta relative to other jurisdictions in North America, we remain very cheap, given the surplus generation that we see here. Again, I think it really supports why legacy generation should be utilized, just given that it is at a price that is below CONE that we're seeing today. Going forward, it'll be what it'll be, if you will, as it relates to if there's new generation required and given the cost of that new generation to ensure that the generation provider is earning a full return on capital. The price will be what it is. Again, I can't say exactly where that price point would be, where there is maybe some kind of, I think, concern around power prices overall for consumers. The other thing to remind yourself of is that when you look at Alberta, when you look at the average power bill, roughly a third is really the price of the electron, and two-thirds is really through the transmission and distribution costs. To the extent that you see additional load come, what you'd hope to see is that the transmission and distribution costs are butter spread more evenly, given the additional load here. That also has to be taken into factor. It's just not the cost of power at the end of the day that impacts consumers. It's all these other costs as well. That's a really good point. Thank you very much for that color, Joel. Thanks, Maurice. Thank you. One moment for our next question. Our next question is going to come from the line of Robert Hope with Scotiabank. Your line is open. Please go ahead. Morning, everyone. Appreciate the commentary on the asset sales potentially strengthening the balance sheet, and I acknowledge that you may be limited on what you can say. That being said, how do you think about an asset sale program when you have quite a large uncertainty out there regarding the Brookfield Hydro option and the potential for it to top up and provide what could be a significant amount of capital for TA? Yeah, Rob. I think it's both. When we look at how we further strengthen the balance sheet here, we certainly factor, at some point in time, we can't predict when, but the option that Brookfield has to convert into the hydro here in Alberta. That's one piece of it, and certainly, would not only get the cash infusion that would come in from a potential top-up, but also CAD 750 million of debt that would essentially come off the balance sheet as it relates to the rate AHCs. That's one important factor or lever, if you will, to strengthen the balance sheet. I think it's all of it. It's also doing additional asset sales, because what we're seeing here is just tremendous opportunities for our company. As I mentioned earlier, when we think about the Central Alberta gas conversions being one. The M&A opportunities that we're seeing out there, like we did with the Colorado acquisition here, just over a month ago, along with just other kind of greenfield opportunities that we're seeing in our portfolio that might be further down in the decade, if you will. That will require capital. Certainly, there's no shortage of uses of capital, if you will. As we look at how we can strengthen our balance sheet, provide incremental cash to the balance sheet, it's obviously Brookfield's conversion is factored there on top of asset recycling. All right. Appreciate that. Maybe just going back to some prior commentary on the BYOG process, as well as the commentary on repurposing some assets. When you think about your asset fleet in Alberta, how do you think about the decision tree of using, we'll call it your steam conversions, on an interim basis as a bridge to, we'll call it a larger brownfield expansion of your project? How do you work through the uncertainty of, you don't quite know what the AESO will ultimately land on? Yeah, I think, part of this is first is really landing on how much capacity, as you said, of the gas-fired steam units that we can use or would constitute underutilized, or bring your own generation, if you will. That's the first part here then is part of that decision tree. Obviously there can be a wide range there, given that we have a very sizable gas-fired steam fleet here. As I mentioned in my remarks, the capacity factor has been around 20%, as relates to 2025. We do see excess capacity there that could be used as bring your own generation. What I really like about that is, for the data center, or AI infrastructure build-out is, as you know, the cost of new build is just so expensive today, and the supply chain constraints are so challenging that using these units to support the AI infrastructure build-out will then lead to new build sometime next decade, because these units won't run forever. It is in a way kind of like a bridge. I don't like to use that term, but that's kind of what this would be, is that you get the AI infrastructure built in the province supported by our existing gas-fired steam units, at some point in time, we would look to then repower those units so they could run for decades after that. That's, again, I see this is where it's very compelling, for Alberta as it relates to the fact that we do have surplus generation. The supply chain constraints that we see that this fits really nicely that we could use this could be gas-fired steam units. There would be a new build down the road that would be underpinned by long-term contracts with our customers. Thank you. Thanks, Rob. Thank you. One moment for our next question. Our next question will come from the line of John Mould with TD Securities. Your line is open, please. Hi. Morning, everybody. Maybe just to follow on that last question. On the repowering projects that you have and, I guess FLIPI, as well on the greenfield side, I guess how active are you on those in terms of costing activities, planning, just to be in a position to proceed rapidly with those if there is some kind of meaningful load growth that drives a need for those? Or should investors really think of those as more of a longer-dated option into the next decade, depending on how, possibly well into the next decade. You flagged the timeline of the coal-to-gas retirements in the past. Just in terms of maybe meeting the provinces' load growth more on a long-term basis. John, when you reference FLIPI, and Keephills 1 and Sundance 5, the total is just over two gigawatts. I'd say there's still a lot of work going on today. It's still very early days. Again, you can see as part of our path forward here, first step is utilizing the underutilized capacity we have with our gas-fired steam units. That makes the most sense. Then look to potentially build out these sites, if you will, next decade. It's not something that we'd look to be building tomorrow because we don't need to. The most effective way is to use the gas-fired steam units. They're the most cost-effective, and it's all about speed to power, too, for AI infrastructure. The assets are there, as you know. The gas is there, the transmission's there, the water's there, everything is there. Use those first, but knowing, again, as mentioned earlier, they're not going to run forever. Then look to these sites like whether it's FLIPI, K1, or Sundance 5, as we talked about, as to repower down the road. It's a stage process here. It's certainly something we're not looking at doing tomorrow. This would be next decade, but the work is underway now because these take a long time, right, to do all the planning, the stakeholder engagement, all those things that's underway. We do have a bit of time here because we view really repurposing our gas-fired steam units is the way to go. Okay. Thanks for that. Then maybe just on your hedges, you layered on about, I think 20% or so incrementally just in terms of volume for next year. What kind of appetite are you seeing from customers to contract at more normalized pricing levels versus holding on to something more like the spot exposure to the AE, and just in terms of how that contributes to your ability to add more meaningful length to your hedges between now and the end of the year? Yeah, John, obviously, we always remain very active as it relates to managing our hedge portfolio. Roughly half of the portfolio is our C&I business, which is, think of those as almost like three-year contracts that continue to roll kind of every year. Those tend to are transacted a bit of a premium over where you would see the forward pricing. The team looks for opportunities here where there's a nice spread that they see that they go, "We're going to lock in these prices." I'm very encouraged by what the team has done so far. If you look at on one of our slides, we show that for next year, we have around 6,700 gigawatt hours already hedged to CAD 64. Again, well above where we're at today when we look at kind of spot pricing. That's due in large part to our C&I business, along with adding financial hedges where we can. This is something that, it's a real core competency, if you will, of TransAlta, that they look for these opportunities to kind of lock in when they can. I expect they will continue to roll in hedges here going forward. I can't say how much, but they will find opportunities. Again, a large part of that is due to the C&I book that we have. Okay. I'll get back in the queue. Thank you. Thank you. One moment for our next question. Our next question is a follow-up question from the line of Mark Jarvi with CIBC. Your line is open. Please go ahead. Yeah, thanks. Just following up on the underutilized assets. If you got a meaningful amount granted by the AESO, like a gigawatt or more, would that likely be used to scale up increased opportunities around Keephills? Are there conversation opportunities to look at another site like Sundance? Depending on what the ultimate number is, we certainly have the land there, the gas supply is there, the transmission is there, to support additional build-outs. If you talk of up to a gigawatt, or even higher, certainly that could be supported at around the Keephills facility. Okay, thanks. Thank you. One moment for our next question. Our next question is going to come from the line of Patrick Kenny with National Bank Financial. Your line is open. Please go ahead. Good morning. I know you guys are still working on the class 3 estimate for the Centralia Unit 2, just wondering if perhaps there's been any progress with potentially tapping into more gas supply and looking at repowering Unit 1. How we should be thinking about the timing of that opportunity, and maybe a comment on how those brownfield returns might stack up to, say, Alberta Greenfield or other U.S. M&A opportunities. Yeah. Pat, when we look at with Centralia, as you highlighted, we are working toward the class 3 estimate. Everything is on schedule, such that we'll be in a position to have that by the end of the year. It to be then on track to make FID very early in 2027. Again, subject to the permits that are required both for ourselves and obviously with PSE, that they get the WUTC approval. That work is well underway there at the facility. When you look at the returns, hard to beat. As we highlighted when we made the announcement for Centralia, and we said, our estimate is a CAD 600 million capital cost at a 5.5 x build multiple. Obviously very attractive. Like any company, I wish we had more of those types of opportunities with those types of multiples. Again, very, very attractive. Again, just shows the value of having legacy assets where you can either repurpose, maybe extend a contract or what have you, that offer very compelling risk-adjusted returns. When you look at the gas supply, just recall that the gas supply for unit 2, that's on for PSE as the customer to provide not only the gas, but obviously the transportation of that gas to the facility. There is enough gas supply there. The gas line is around 1,500 ft away from the facility, so it is very close. As it relates to unit 1, I think this is a longer-term option because we've been having discussions around that, but very early days. That it would be very compelling given where the location, given the transmission's there, the water is there. You are 85 mi south of Seattle. There's a lot of reasons why it would be very good to be able to expand that facility. It comes down to, again, gas supply. It's the Williams Northwest Pipeline that is full today, but certainly something that we're talking to them on. Also, just trying to find, obviously, a customer, like a commercial arrangement. Again, very early days, and this would be kind of next decade. We do see that there could be an option there. I wouldn't put a high probability at this point in time. The focus, again, is on getting unit 2 to FID early next year and moving that project along to get it in service by the fourth quarter of 2028. Okay, that's perfect. Thanks for that. Maybe just on the M&A front, obviously I know you can't comment on specific opportunities, just curious, after the Colorado transaction closes, how you might describe your wish list in terms of geography, asset type, or technology, fuel supply. Just how you're thinking about maximizing the value of the portfolio going forward through M&A, whether it's capturing synergies across the portfolio or otherwise. Yeah, Pat. Again, we're very pleased with the Colorado acquisition. I think this is an acquisition that will serve our shareholders for decades to come, given the weighted average duration is 27 years. As we've talked about before, the full cost pass-through that we have there. A very low-risk investment for us that, again, in a core geography, that now we have a presence in Colorado with these two facilities. We're very happy with that. Going forward, though, the M&A strategy remains the same, focused on our four core geographies. You've seen us transact. The Heartland acquisition was here in Alberta. Hut 8 acquisition was in Ontario, and then this most recent one in Colorado. I would say with technology, we remain agnostic. It's all about the highest risk-adjusted returns. That's the key for us. It just so happens, recently it's been more on the gas-fired side of things. When you look at, again, Hut 8, you look at Colorado, you look at Heartland. If there's opportunities in renewables, we're certainly looking at those as well. Again, it comes down to the highest risk-adjusted returns in our four key geographies. We remain very active there. We're also conscious of our balance sheet and what we can do. This is where, again, I think, as we talked about earlier, active asset optimization, if you are a portfolio rotation, certainly would support those opportunities going forward. It's really more the same, if you will, as it relates to how we look at M&A. Okay. That's great. Thanks, Joel. Thanks, Pat. Thank you. One moment for our next question. Our next question will come from the line of Benjamin Pham with BMO. Your line is open. Please go ahead. Hi. Thank you. Good morning. I want to follow up on our last question around your comments on risk-adjusted returns across the portfolio, including M&A. Can you parse that out a little bit? Because it sounds like if you're going on different risk profiles within energy infrastructure, that return spectrum does change quite a bit, i.e., the Colorado transaction, where it's long-dated cash flows and the return may be a different profile than maybe some of the other assets. Can you maybe put the bookends of the returns and how you adjust for the risk differences? Yeah. I would say, Ben, when we look at the various opportunities, so I'll just give you some relevant examples here. You look at the Heartland acquisition, where not fully contracted but substantially contracted here in Alberta, older vintage assets, and we did that at around a 5.4 x multiple. When you look at Hut 8, again, older assets, shorter contracts, but we believe we'll be able to recontract those assets in five-year increments. Again, we were able to acquire those at a lower multiple. When you look at Colorado, and yes, it was at a higher multiple, but it makes a lot of sense. That this is brand-new generation, 27-year contracts. We have to look at this on a kind of overall portfolio that you're going to get some at a lower multiple, and there's reasons for that. There's going to be some, like Colorado, where it's going to be at a higher multiple that is fair value, given, again, the vintage of the assets, given the contracts and the nature of those contracts, and the like. When we look at our opportunities here going forward, you have to take that all into consideration. I think what was important for Colorado is I know some folks looked at really the multiple. That's one way to look at it, but probably the best way to look at it is really the free cash flow yield. The free cash flow yield on that acquisition is approximately 13%, and our free cash flow yield on TA is around 7%. It's free cash flow accretive at the end of the day. For us, there's a number of ways we look at acquisitions, whether it's an EBITDA multiple, it's a free cash flow yield multiple. We also have to look at the leverage that's on the acquired assets, if any. There's kind of a wide range here. Then you have to compare everything on a per share basis as well, too. That we want to be accretive. At the end of the day, we don't want to do anything that is dilutive, and Colorado was accretive, as I mentioned. Everything has to stack up against on a per share metric basis. Hopefully it gives you some context of how we look at things here. It really depends on the nature of the acquisition. Okay. Got it. Thanks for the color. Can you comment related to that with some of the credit rating updates? Does that constrain your ability at all on your balance sheet to add in more M&A over the next 12 months? If I can just put a time frame to that. Oh, hey, Ben, it's Mike here. Maybe I'll handle this one. The negative outlook from S&P, we kind of view that as a temporary hurdle for us. When you look at the soft Alberta power pricing market right now and Centralia being offline here, as we progress that towards FID, our cash flows have come down. We do see a glide path forward with the recovery of the balance sheet. When you look at the Alberta forward pricing market, you're starting to see that uplift in the back half of 2028 into 2029. If you look at the hedge book we've built here, 2027 sets up pretty nice with 6,600 GW hedged at CAD 64, quite a bit higher than the forward market. If you look at our optimization team and what they are able to do in tough markets, they have pretty amazing capabilities, and you saw that here in the second quarter with what they were able to do. If you look at the data center opportunity in Alberta we are pursuing, and the nature of our assets and the capital light nature of that opportunity, that's very credit positive for us. Joel's earlier comments on Centralia and progressing that towards FID and that looking like a COD timing back half of 2028. That's a wave of cash flows coming. The final piece is the asset recycling program and doing that for multiple reasons. One benefit of that is obviously proceeds in the door, helping the balance sheet. We see a lot of incremental things that will progress the balance sheet to a position where we want it to be in. In the meantime, is it hampering our flexibility? I would say, no, not really. The things we're pursuing right now, we have the flexibility to operate within the bounds of our balance sheet. We are definitely conscious of the leverage levels and how the rating agencies are viewing it, we see that improving here over the next while, it's something we are actively working towards. Okay. Thanks, Mike. Quick one for me to squeeze in, if I may. You mentioned the focus on Keephills respect to the data center opportunity. Can you remind me when you went through the multi-phase process with that asset, was there community engagement involved in that? I know it's industrial site and there's a plant there. Did you do that and work here? It's just the community feedback and support or lack of support for a site. Ben, whenever we have any investment that we make, we have community engagements or stakeholder engagement very early on, right at the development stage and really through the whole life cycle of the asset. Once the asset is developed and then operating, we stay in the community. We remain very engaged with the community. Again, we're an important part of these communities in which we operate in. When you look at Keephills, we are again, very actively engaged there. Within the community, there is certainly a lot of support there, at Keephills, just given the infrastructure is there today. It's been there for many decades. We have to remain very active there and really bring our stakeholders along with us on this journey when we develop any project. It's not only here in Alberta, it's anywhere in which we operate. Stakeholder engagement is just critical. Through, like I said, development and through the operating life of the asset. Again, we are very engaged there. It's really important that we are very transparent with our stakeholders. We have transparent communication. It's really important that we have that because these are our stakeholders, and we want to make sure that we are communicating with them, we're listening to them, understanding what their needs and their concerns are. It really is almost like a partnership at the end of the day, when you are putting infrastructure into a community. I would say with Keephills, we're certainly very actively engaged in that right now and have been for decades because we've been operating there for that long. Okay, got it. Thank you. Thank you. There are no further questions at this time, I would like to hand the conference back over to Stephanie Paris for closing remarks. Thank you, everyone. That concludes our call for today. If you have any further questions, please contact the TransAlta investor relations team. This concludes today's conference call. Thank you for participating. You may now disconnect. Everyone, have a great day.