TransAlta Corporation (TAC) Q2 2026 Earnings Report, Transcript and Summary

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 speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star then 1 on your telephone keypad. If you would like to withdraw your question, please press star then 1 again. Thank you. Ms. Paris, you may begin your conference.

Thank you, Michelle. Good morning, everyone. My name is Stephanie Ann Paris, and I am the Vice President of Investor and Corporate Strategy of TransAlta. Welcome to TransAlta's second quarter 2026 conference call. With me today are Joel E. Hunter, President and Chief Executive Officer, Mike Politeski, EVP Finance and Chief Financial Officer, and Christopher D. 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 2, 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 and financial performance during the second quarter of 2026. Demonstrating our fleet's continued resilience during challenging market conditions. During the quarter, we delivered adjusted EBITDA of $291 million, free cash flow of $143 million or $0.47 per share and average fleet availability of 90.2%. 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 continue to advance our data center strategy with CPP Investments and 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, 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 buildout of AI infrastructure in the province. Our gas-fired steam units are designed to operate as baseload and can produce 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, and we view the data center regulations as an important step towards framework clarity. The determination on how underutilized assets will be incorporated into buildout of AI infrastructure will be made by the AESO, and we remain actively engaged with them. Also in the quarter, 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 and 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 $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 $110 million per year in low-risk, high-quality adjusted EBITDA to our portfolio, 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, Alberta data center projects. And finally, we realigned our executive management team, adding Mike Politeski as our EVP Finance and Chief Financial Officer, Grant Arnold as our EVP Growth and Chief Commercial Officer. In addition, Nancy L. Brennan assumed an expanded role as Chief Legal, People, and Corporate Affairs Officer and Christopher D. 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 will 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 $291 million despite challenging market pricing in Alberta. Our Hydro segment adjusted EBITDA was $87 million, down $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 $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 $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 $16 million primarily due to subdued market volatility 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. And 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 $143 million. Our sustaining capital expenditures were down $18 million year over year. However, this was primarily timing related and we continue to expect sustaining capital of $140 million to $160 million in 2026. Turning to the Alberta portfolio, spot prices averaged $29 per megawatt hour in the second quarter. Notably lower than the $40 per megawatt hour 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 2.4 thousand gigawatt hours of hedges at an average price of $63 per megawatt hour, which was $34 per megawatt hour higher than the average spot price. Our gas fleet realized an average price of $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 $36 per megawatt hour, a 24% premium to the average spot price. Our merchant wind fleet realized an average price of $14 per megawatt hour, which was impacted by increased thermal production and intermittent wind and solar generation. During the quarter, we also delivered approximately 900 gigawatt hours 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 addressed the AESO's 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 4.5 thousand gigawatt hours of our Alberta generation hedged at an average price of $64 per megawatt hour. Well above current forward pricing. For 2027, we have approximately 6.6 thousand gigawatt hours hedged at an average price of $64 per megawatt hour, also well above current forward levels. Looking ahead, we continue to expect the Alberta supply-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 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. In addition, the forecast tightening of the Alberta market and recovery of power prices along with 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 will 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, and enhancing our financial strength and flexibility through disciplined capital allocation and cost control. I believe TransAlta offers a compelling investment opportunity. We have 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, that 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. And 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, and I will 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. Star 1 on your telephone, and wait for your name to be announced. To withdraw your question, please press star then 1 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.

Yeah. 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 is impacting anything about getting from the MOU to a definitive agreement with Brookfield and CPP?

Yeah. Thanks, Mark, and good morning. It is Joel here. I would say there is ongoing discussions with the AESO. And 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, really, our gas-fired steam units. So, again, we are 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. So 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.

So the expectation is a matter of months could be a couple quarters, before you have clarity on the underutilized assets?

Yeah. Hard to say. We cannot really speak for the AESO, Mark. But we are actively engaged with them. So, we are hopeful it will be in the next quarter or so, but, we cannot speak on behalf of them as to the timing.

And then obviously, that might influence how you think about scaling beyond the 230 megawatts. So if that dragged on a little bit, hopefully, does not, would you look at maybe moving to FID on the first phase of the 230 megawatts from phase 1 allocation and then subsequent scale up after that through a follow-on agreement? Or, like, is there a way to sequence sort of, I guess, moving through FID?

I think that is very possible here, Mark, that we would look to that again, and it is really up to, you know, us along with Brookfield and CPP Investments to determine that. But as we said before, you know, 230, we were very pleased with that in the Phase 1 load allocation. And then looking forward to how we can build upon that. So I would say that there is possibility here that could advance the 230 before we get the remaining cure with the underutilized capacity.

Okay. I will leave it there for now.

Thanks, Mark.

Thank you. And 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, and 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 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 cannot give everything away here because we are in processes, if you will. I think what you will see going forward here, Maurice, just given the amount of opportunities that we see going forward, whether it is a Centralia coal-to-gas conversion, AI data centers, M&A opportunities and then further kind of organic growth in our portfolio, that we are seeing that, I think portfolio rotation will become more active here. So we do have a few processes underway. I cannot say anything more, but, we are certainly very active in that space right now.

I am looking forward to hearing more on that. And 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 have seen forward prices move up a little bit. Particularly for 2029, yet it still is below the $80 to $120 range that you laid out in Investor Day. You mentioned at the start of the call that you have seen a lot of positive developments in the province thus far. So just curious as to what else you are expecting to hear in the coming months that would prompt the forwards to rise into your projected range?

You know, first of all, Maurice, when you look out further like to Cal 2028 and 2029, you know, there is not a lot of liquidity. Generally, when you look at kind of forward pricing, you are out, you know, 12 to maybe 18 months at best. And when I look at Cal 2029 today, I think marked around $81. So it is actually in the range of that $80 to $120, you know, that we highlighted at Investor Day. And, certainly, we have seen an improvement in those forward prices since, you know, even announcement with Meta around their data center project with Kineticor and Pembina. So we remain very encouraged by that. I think for the market, as we move forward here, just getting further kind of clarity around the ramping of the load growth will certainly support further, the forward pricing. So, again, when I look at where we are today for Cal 2029 from where we were at our Investor Day at the end of March, we have certainly seen an improvement there, but I would expect that over time, as the market sees or has better visibility behind kind of the load ramp, if you will, that will then further support these forward prices and could even go higher.

Maybe on that last note and a quick follow-up here. Obviously, we know where CONE is in the province. But, also, historically, when we had I think it was 2021 to 2023 when we had triple-digit power prices. That led to the regulator looking more into the industry. In this world affordability, like, is there such thing as a balanced number where, you know, pretty much everyone's happy?

You know, yeah, when you look at the, again, the CONE or the cost of new entry that you referred to, and I know that was something that was highlighted with the recent announcement from Pembina and Kineticor. You know, kind of in the low 100s, if you will. Which completely makes sense, right, given the cost of new build that we are seeing today relative to even where we were back in 2021 and 2023 as a reference where we saw triple-digit pricing. I think this is where it is really important to have kind of legacy generation like we have with our gas-fired steam units. To help support, their infrastructure buildout that we have talked about that, you know, that pricing would be, you know, below CONE. What you are seeing here, you know, going forward is the market will continue to tighten. We are not seeing much by way of new supply, but we are seeing load growth coming, whether it is organically in the province as we highlighted at our Investor Day back in March. Along with phase 1 here. So we cannot say exactly where that price point would be, but 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. And, 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 are seeing today. But going forward, it will be what it will be, if you will, as it relates to if there is new generation required and given the cost of that new generation to ensure that the generation provider is earning a full return of and on capital, the price will be what it is. And so again, I cannot say exactly where that price point would be where there was maybe some kind of, I think, concern around power prices overall for consumers. That thing to remind yourself of is that when you look at Alberta, when you look at the average power bill, roughly one-third is really price of the electron, and two-thirds is really through the transmission distribution costs. So to the extent you see additional load come, what you would hope to see is that the transmission distribution costs are kind of butter spread more evenly given the additional load here. So that also to be taken into the factor. It is just not the cost of power at the end of the day that impacts consumers. It is all these other costs as well.

That is a really good point. Thank you very much for the color, Joel.

Thanks, Maurice.

Thank you. And one moment for our next question. Next question is going to come from the line of Robert Hope with Scotiabank. Your line is open. Please go ahead.

Good morning, everyone. So I appreciate the commentary on the asset sales potentially strengthening the balance sheet with and acknowledge that you may be limited on what you can say. But that being said, how do you think about an asset sale program when you have, you know, quite a large uncertainty out there regarding the Brookfield hydro option. And the potential to for it to top up and provide, you know, what could be a significant amount of capital for TA?

Yeah, Robert. I think it is both. When we look at how we further strengthen the balance sheet here, we certainly factor at some point in time, we cannot predict when, but the option that Brookfield has to convert into the hydro here in Alberta. That is one piece of it, and certainly, would you know, not only get the cash infusion that would come in from a potential top up, but also $750 million of debt that would essentially come off the balance sheet as it relates to the rating agencies. So that is one important factor or lever, if you will, to strengthen the balance sheet. But I think it is all of it. It is also doing additional asset sales. Because what we are seeing here is just tremendous opportunities for our company. As I mentioned earlier, I think the Centralia coal-to-gas conversion as being one. The M&A opportunities that we are seeing out there, we did with the Colorado acquisition here, just over a month ago. Along with just other kind of greenfield opportunities to we are seeing in our portfolio that might be further down in the decade, if you will, that will require capital. So certainly, there is no shortage of uses of capital, if you will. So as we look at how we can strengthen our balance sheet, provide incremental cash to the balance sheet, it is obviously Brookfield's conversion is factored there on top of asset recycling.

Sure. Appreciate that. And then 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, you know, using, we will call it, your steam conversions on an interim basis as a bridge to, we will call it, a larger brownfield expansion of your project. And how do you work through the uncertainty of, you know, you do not quite know what the, you know, what the AESO will ultimately land on.

Yeah. I think, you know, part of this is, you know, first is really landing on, you know, how much capacity of the, 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 is the first part here then is part of that decision tree. And so, obviously, there can be a wide range, given that we have a very sizable gas-fired steam fleet here. And as I mentioned in my remarks, the capacity factor has been around 20% as it relates to 2025. So we do see excess capacity there that could be used as bring your own generation. What I really like about that is, you know, for the data center or AI infrastructure buildout, is, as you know, like, 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 buildout will then lead to new build sometime next decade because these units will not run forever. So it is, in a way, kind of like a bridge. I do not like to use that term, but that is 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. And then at some point in time, we would look to then repower those units so they can run for decades after that. So that is again, I see this is where it is very compelling for Alberta as it relates to the fact that we do have surplus generation. You know, the supply chain constraints that we see, that this fits really nicely that we could use this, the gas-fired steam units, but then there would be a new build down the road that would be underpinned by long-term contracts with our customers.

Thank you.

Thanks, Robert.

And one moment for our next question. Next question will come from the line of John Mould with TD Securities. Your line is open. Please go ahead.

Good morning, everybody. Maybe just a follow-on that last question. On the repowering projects that you have and, I guess, Keephills as well on the greenfield side. I guess, how active are you on those in terms of costing activities, you know, planning, just to be in a position to proceed rapidly with those if there is, you know, some kind of meaningful load growth that drives the need for those? Or should investors really think of those as, you know, more of a longer dated option into the next decade, you know, depending on how, possibly well into the next decade, you know, you flag the timeline of the coal gas retirements in the past. Mike, just in terms of maybe meeting the province's, you know, load growth more on a long-term basis?

Yes, John. When you referenced Keephills 1 and Sundance 5, there are, you know, the total is just over, you know, 2 gigawatts. You know, I would say there is still a lot of work going on today. It is still very early days. But, 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. And then look to potentially build out these sites, if you will, next decade. So it is not something that we would look to be building tomorrow, so we do not need to. The most effective way is to use the gas-fired steam units. They are the most cost effective. And it is 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. So use those first. But knowing, again, as mentioned earlier, they are not going to run forever, and then look to these sites, like whether it is Keephills 1 or Sundance 5 as we talked about, as to repower down the road. So that is kind of, you know, it is kind of a staged process here. So it is certainly something we are 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 is underway. But 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. And 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, you know, more normalized pricing levels versus holding on to, you know, something more like the spot exposure today and just in terms of how that contributes to your ability to, you know, add more meaningful length, to your hedges, you know, between now and the end of the year.

Yeah. You know, we have, 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. And those tend to be transacted of a premium over where you would see, like, the forward pricing. So, you know, the team looks for opportunities here, you know, where there is a nice spread that they see that they go, we are going to lock in these prices. So I am very encouraged by, you know, what team has done so far. If you look at one of our slides, we show that for, you know, next year, we have around 6.6 thousand gigawatt hours already hedged at $64 again, well above where we are at today when we look at kind of spot pricing, and that is due in large part to our C&I business along with adding financial hedges where we can. So this is something that it is a real core competency, if you will, of TransAlta. That they look for these opportunities to kind of lock in when they can. And I expect that we will continue to roll in hedges here, you know, going forward. And I cannot say how much, but they will find opportunities. And, again, a large part of that is due to the C&I book that we have.

Okay. I will get back in the queue. Thank you.

Thank you. And 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, or are there conversation opportunities look at another site, like Sundance?

You know, right now, Mark, we are focused around Keephills. That, depending on what the ultimate number is, that we certainly have the land there. The gas supply is there. The transmission is there. To support, you know, additional buildout. So if you talk of up to a gigawatt or even higher, certainly, could be supported at around the Keephills facility.

Okay. Thanks.

Thank you. And one moment for our next question. Our next question is going to come from the line of Patrick Kenny with National Bank Capital Markets. Your line is open. Please go ahead.

Yeah. Good morning. I know you guys are still working on the Class 3 estimate for the Centralia Unit 2, but just wondering if perhaps there has been any progress with potentially getting to 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, you know, how those brownfield returns might stack up to, say, Alberta greenfield or other U.S. M&A opportunities?

Yeah, Patrick. You know, when we look at, with Centralia, as you highlighted, we are working toward the Class 3 estimate. Everything is on schedule such that we will be in a position to have that by the end of the year. It would 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 Puget Sound Energy, to get the WUTC approval. So that work is well underway there at the facility. It is, you know, when you look at the returns, I mean, hard to beat. You know, as we highlighted when we made the announcement for Centralia, and we said, you know, kind of our estimate is a $600 million capital cost at a 5.5x build multiple. So, obviously, very attractive. I wish we have, like, any company, I wish we had more of those types of opportunities with those types of multiples. So, again, very, very attractive. And, again, just shows the value of having, you know, 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 is on Puget Sound Energy as the customer. To provide not only the gas, but obviously the transportation of that gas to the facility, and there is enough gas supply there. The gas line is around 1.5 thousand feet away from the facility, so it is very close. As it relates to Unit 1, I think this is longer term because we have been having discussions around that. But very, very early days. That it would be very compelling given the, where the location given the transmission's there, the water is there. You are 85 miles south of Seattle. So there is 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 is the Northwest, Williams Northwest Pipeline that, you know, is full today, but certainly something that we are talking to them on. And then also, you know, just trying to find, you know, see a customer like a commercial arrangement. But, again, very, very early days, and this would be kind of next decade. But, you know, we do see that there could be an option there, but I would not put a high probability at this point in time. And 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 is perfect. Thanks for that. And then maybe just on the M&A front, obviously, I know you cannot comment on specific opportunities, but just curious after the Colorado transaction closes, how you might describe your wish list in terms of geography, asset type, or, you know, technology, fuel supply, just how you are thinking about maximizing the value of the portfolio going forward through M&A whether it is capturing synergies across the portfolio or otherwise?

Yeah, Patrick. You know, again, we are very, 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 and we have talked about before, the full cost pass-through that we have there. So 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, so we are very, very happy with that. Going forward, though, the M&A strategy remains the same, focused on our four core geographies. So you have seen us transact, you know, the Heartland acquisition was here in Alberta. Hut 8 acquisition was in Ontario, and then this most recent one, you know, in Colorado. I would say with technology, we remain agnostic. It is all about the highest risk-adjusted returns. That is the key for us. And so it just so happens, you know, recently, it has been more in the gas-fired side of things. When you look at, you know, again, Hut 8, you look at Colorado, you look at Heartland. But if there is opportunities in renewables, we are certainly looking at those well. Again, it comes down to the highest risk-adjusted returns. In our four key geographies. So we remain very active there. But we are also conscious of our balance sheet and what we can do. And this is where, again, I think as we talked about earlier, active asset, you know, optimization, if you are, portfolio rotation. Certainly would support those opportunities going forward. So it is really kind of more of the same, if you will, as it relates to how we look at M&A.

Okay. That is great. Thanks, Joel.

Thanks, Patrick.

Thanks. Thank you. And 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 wanted to follow up on our last question around your comments on risk-adjusted returns across the portfolio, including M&A. Can you parse out a bit of sounds like if you are going on different risk profiles, within energy infrastructure, that returns spectrum does change quite a bit. i.e., the Colorado transaction where it is long-dated cash flows and the return may be different profiles and maybe some better assets. But can you maybe put the bookends of the returns and how you adjust for the risk differences?

Yeah. You know, I would say, you know, Benjamin, we look at the various opportunities, so I will just give you some relevant examples here. You look at the Heartland acquisition, we are not fully contracted, but substantially contracted. Here in Alberta, older vintage assets, and we did that at around a 5.4x multiple. When you look at Hut 8, again, older assets, shorter contracts, but we believe we will be able to recontract those assets, you know, for in five-year increments. Blaine, we were able to acquire those at a lower multiple. When you look at Colorado, yes, it was a higher multiple, but it makes a lot of sense, right? That this is brand-new generation, 27-year contracts. So we have to look at this on a kind of an overall portfolio. That, you know, you are going to get some at a lower multiple, and there is reasons for that. And there is gonna be some like Colorado where it is going to be at a higher multiple, that is fair value. Given, you know, again, the vintage of the assets. Given the contracts and the nature of those contracts. And the like. So, when we look at our opportunities here, you know, going forward, you have to take that all into consideration. I think what was important for Colorado is I know some folks looked at, you know, really the multiple. That is 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 around 7%. So it is free cash flow accretive. At the end of the day. So, you know, for us, there is a number of ways we look at acquisitions. Whether it is an EV to EBITDA multiple, or a free cash flow yield multiple. We also have to look at the leverage that is, you know, on the acquired assets, if any. So there is kind of a wide range here, but I think and, you know, and then you have to compare everything on a per-share basis as well too, right, so that, you know, we want to be accretive. At the end of the day, we do not wanna do anything that is dilutive and Colorado was accretive, as I mentioned. So everything has to stack up, you know, against on a per-share metric basis. So, 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? For your balance sheet? To add in more M&A over the next 12 months so I can just put a time frame to that?

Oh, hey. Hey, Benjamin. It is Mike here. Maybe I will handle this one. Yes, so 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 right now and Centralia being offline here as we progress that towards FID. You know, our cash flows have come down. But we do see a glide path forward with recovery of the balance sheet. And when you look at the Alberta, you know, forward pricing market, you are starting to see that uplift in the back half of 2028 into 2029. If you look at the hedge book we have built here, 2027 sets up pretty nice with 6.6 thousand gigawatt hours hedged at $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 in the nature of our assets and the capital-light nature of that opportunity, that is very credit positive for us. And Joel's earlier comments on Centralia and progressing that towards FID and that, you know, looking like a COD timing, back half of 2028, that is a wave of cash flows coming in. And then the final piece is the asset recycling program and, you know, doing that for multiple reasons, but one benefit of that is, obviously proceeds in the door, helping the balance sheet. So 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 are pursuing right now, we have the flexibility to operate within the bounds of our balance sheet. But we are definitely conscious of the leverage levels and how the rating agencies are viewing it, and, you know, we see that improving here over the next while, and it is something we are actively working towards.

Okay. Okay. And that is fine. One quick one for me to squeeze in, if I may. You mentioned work on the focus on Keephills with respect to the data center opportunity. Can you remind me when you went through the multiphase process with that asset? Was it community engagement in, well, then that I know it is industrial side and there is a plant there? Did you do that work here? Just the community feedback and support or lack of support for that site?

Yeah, Benjamin. You know, whenever we have any investment that we make, you know, 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. So once the asset is developed, and operating we stay in the community. We remain very engaged with the community. Because, again, we are an important part of these communities in which we operate in. So 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 has been there for many decades. But, you know, we have to remain very active there and really bring our stakeholders along with us on this journey when we develop any project. And it is not only here in Alberta, it is anywhere in which we operate. Stakeholder engagement is just critical. And through, like I said, development and through the operating life of the assets. So again, we are very engaged there. It is really important that we are very transparent with our stakeholders. We have transparent communication. It is really important that we have that because these are our stakeholders. And so we wanna make sure that, you know, we are communicating with them. We are listening to them. Understanding what their needs and their concerns are. Because it really is almost like a partnership at the end of the day when you are building infrastructure into a community. I would say with Keephills, we are certainly very, very actively engaged in that right now and have been for decades. We have been operating there for that long.

Okay. Got it. Thank you.

Thank you. There are no further questions at this time. And I would like to hand the conference back over to Stephanie Ann 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.