Capital Power Corp (CPWPF) Q3 2026 Earnings Call Transcript

Operator: Good day, and thank you for standing by. Welcome to Capital Power Q3 2026 Analyst Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to turn the conference over to Roy Arthur. You may begin.

Roy Arthur: Good morning, everyone. My name is Roy Arthur, Vice President, Investor Relations and Investment Partnerships. Thank you for joining us to review Capital Power's third quarter 2026 results, which we published earlier today. The quarterly report and presentation for this call are available on our website. Before we begin, let me outline how we will spend our time today. First, our President and Chief Executive Officer, Avik Dey, will walk through our key messages and a business update, including the strength of our contractual foundation, the upside embedded in our business and our growth potential that we see beyond that. Subsequently, our Senior Vice President, Finance and Chief Financial Officer, Kevin MacIntosh, will review our third quarter highlights and financial results. Avik will then close with a few remarks before we open the floor to questions. A quick housekeeping item. I'd like to remind everyone that today's discussion includes forward-looking information and references to non-GAAP financial measures and ratios. Please refer to Slide 19 of the presentation for the applicable disclosures. With that, I'll turn it over to Avik.

Avik Dey: Thank you, Roy, and good morning, everyone. Before I begin today, I just want to acknowledge the results of the Alberta referendum on October 19. Firstly, an incredible day for Canadians and a great expression of democracy from Albertans. We experienced historic border turnout and soundly approved and endorsed a strong Alberta within a United Canada. I think it's a great day for Alberta, a great day for Canada and importantly, a great day for Capital Power as a strong and proud Alberta company. There are three key messages we want you to take away today. First, we have a solid foundation of high-quality contracted cash flows. Our earnings base is stable and includes long-term contracts with a diverse set of investment-grade counterparties. Second, we have significant embedded upside with a derisked path to execution. That upside sits within the assets we already own with contracting in merchant value driving our AFFO per share growth. We have already made significant progress crystallizing this upside. As you'll hear Kevin talk about, our foundation of contracted cash flows together with our merchant upside delivered a record adjusted EBITDA this quarter. This reflects the strength of our diversified business and its underlying fundamentals. And third, strong fundamentals in our core markets are creating new development and contracting opportunities. In addition to the potential for M&A, we are seeing value beyond the embedded upside through contracted development opportunities at our sites with utilities and large load customers. With that as a backdrop, I will add some context around each of these. Let me start with our contracted cash flow. It underpins a significant portion of our growth. Services our debt and funds our growing dividend. About 75% of our EBITDA is under long-term contracts. That's by design. Long-term contracting has always been core to how we run the business, and our contracts have historically averaged 9 to 11 years weighted average contract life. These contracts are also high quality between 80% and 90% of our contracted EBITDA is with investment-grade counterparties and more than 70% is with utilities or system operators. This contracted base gives us stability. In addition, we have upside for merchant power prices and our supply and trading team actively manages that risk. Together, they offer a balanced and compelling total return proposition. Our contracted portfolio also offers a clear path to growth, and our track record continues to show we can deliver on it. In 2025 and '26 to date, we have contracted nearly 2 gigawatts, inclusive of projects brought into service. In the near to midterm, approximately 3 gigawatts in our portfolio is available to contract as legacy contracts expire starting in 2029 with upgrades at our existing sites adding further optionality within that. Beyond the embedded upside, we see meaningful opportunity to develop and contract new generation at our existing sites. The opportunities I've just walked through and the discipline we bring to capturing them reinforce our confidence in meeting our 2030 targets which includes 8% to 10% growth in AFFO per share and 13% to 15% total shareholder returns. As previously highlighted, since '25, we have contracted and put into service approximately 2 gigawatts across multiple jurisdictions at materially higher prices with a weighted average contract life of approximately 15 years. This represents approximately 14% of our fleet, about twice the peer average over the same period. Our recent contracting success is not a one-off. It is a strategy we have proven and one we continue to execute. This contracting opportunity is part of a larger story. Across our portfolio, we see up to $1.25 billion of incremental annual adjusted EBITDA upside above our 2026 base. There are 2 parts to that upside. The first is approximately $400 million to $550 million from recontracting and upgrades across about 3 gigawatts of capacity. A further $375 million to $700 million represents merchant upside linked to Alberta and PJM power prices across approximately 5 gigawatts of capacity. Tightening supply and demand fundamentals in both markets support this opportunity and our existing assets position us well to benefit. What makes this upside compelling is how it is captured. It requires no new shares, no new project debt and limited growth capital, which makes it highly accretive to AFFO per share. This upside is not theoretical. We are already making meaningful progress delivering on this opportunity. We have hedged over 40 terawatt hours of power in PJM and Alberta from 2027 and beyond in addition to recently contracting nearly 2 gigawatts of capacity. Together, this not only derisks our long-term growth profile, but also reduces the amount of M&A needed to achieve our 2030 growth targets. Where we do pursue M&A, our focus is on expanding this embedded opportunity set. I've talked about the value in our existing fleet and it's significant, but it highlights the question, what comes next? Strong demand across our core markets is creating development opportunities beyond the embedded $1.25 billion of adjusted EBITDA upside I just discussed. And we see multi-gigawatt potential across our key markets. As demand grows, customers not only value speed to power, but reliability, commodity risk management and commercial regulatory expertise. We've talked about that before. It's the combination of these elements that makes us, Capital Power stand out. We are an investment-grade counterparty with a proven operating track record and deep customer relationships in the markets we operate. Our commercial and trading expertise lets us structure these agreements and manage the risk behind them. Our sites at a brownfield advantage on top of that embedded upside. We can potentially use our existing land generation and interconnect to add new generation faster and at a lower cost than an alternative greenfield project. We've built a trusted presence in our host communities through years of proactive engagement. No location is a better example of this than Genesee right here in Alberta. Speed to power also depends on equipment and turbine supply has been one of the industry's biggest constraints. That's starting to shift. Recently, we've seen more credible listings of complete or unused turbine packages, though asking prices remain high. We've seen this pattern before in previous cycles. It's too early to call a turn, but these early signs give us confidence that we can secure the equipment we need to deliver development growth in line with or better than our stated return targets. With that, I'll turn it over to Kevin to take you through our third quarter results.

Kevin MacIntosh: Thank you, Avik, and good morning, everyone. I was reflecting this morning about this being such an important time of the year. Teams across Capital Power are putting finishing touches on 2027 plans while also staying laser-focused on finishing 2026 strong. This takes incredible commitment, and I'm so proud of how teams across the company continue to deliver. I'll start our third quarter highlights, then walk through our financial results, which include record quarterly adjusted EBITDA contribution and close with an update on our 2026 guidance. During the quarter, we announced a 250-megawatt long-term energy supply agreement with Meta. We also continue to advance upgrades at Arlington Valley and Hummel with completion expected in 2027. On the development front, approximately 180 megawatts of solar capacity is advancing towards commercial operation in 2026 and 2027. Operationally, we generated approximately 14.5 terawatt hours across the portfolio, up 8% year-over-year, with 60% coming from our U.S. fleet. We have also now completed 68% of our total planned outage days for 2026. Turning to our financial results. In the third quarter, adjusted EBITDA was $553 million, up $76 million from the third quarter of 2025. This record quarterly adjusted EBITDA contribution demonstrates the strength of our diversified portfolio. The increase was driven mainly by higher contributions from Hummel Station and Rolling Hills, which benefited from stronger PJM power prices and summer demand. Our Canada Flexible Generation segment also delivered higher results. Favorable portfolio optimization, higher generation and pricing at Goreway and contributions from our Ontario battery storage projects more than offset lower spot power prices and lower generation in Alberta. These gains were partially offset by a lower contribution from La Paloma, where the financial hedges put in place after the acquisition settled less favorably than last year. AFFO was $306 million, down $63 million year-over-year. Despite higher adjusted EBITDA, AFFO reflects higher sustaining capital spending, mainly from a heavy maintenance schedule across our Alberta fleet, rotor replacements at Rolling Hills and Harquahala and planned maintenance at Hummel Station and Rolling Hills. We also had higher year-over-year net finance expense and current income tax expense. Year-to-date, adjusted EBITDA was $1.308 billion, up $142 million. That increase was driven by a full 9 months of operations at Hummel Station and Rolling Hills, along with the same factors as the quarter. AFFO was $788 million, down $34 million compared with the prior year. That reflects the same pressures from sustaining capital, finance expense and taxes. These were partially offset by $174 million in Clean Technology Investment Tax Credits recognized in the second quarter for eligible Canadian renewables projects. Bottom line, this was a record quarter for adjusted EBITDA, where parts of the portfolio were softer, gains elsewhere more than made up for it, which shows the value of our diversified portfolio. Based on our performance year-to-date and our outlook for the rest of the year, we are reaffirming our 2026 guidance for adjusted EBITDA of $1.565 billion to $1.765 billion and AFFO of $890 million to $1.010 billion. Strong performance supports these metrics remaining within range. The guidance range for 2026 sustaining capital expenditures has been revised to $350 million to $370 million. Previously $290 million to $330 million, reflecting unplanned outage work primarily for the U.S. flexible generation fleet and the advancement of a planned outage from 2027 into the fourth quarter of 2026 to ensure high reliability through 2027. The increase is event-driven and a significant portion relates to insurable events. Insurance recoveries anticipated in 2026 and 2027, together with concessions from original equipment manufacturers are expected to meaningfully offset the cash impact associated with higher sustaining capital. Overall, we remain confident in the resilience of our portfolio and the durability of our cash flows. Our contracted base provides stability and our embedded contracted and merchant upside give us a clear path to growing cash flow per share. Before we move on, I want to point to something that sets Capital Power apart, our long record of dividend growth. Since 2016, our dividend has grown from $1.51 per share to now $2.79 based on our 2026 estimate, an increase of about 85%. We kept that growth going through commodity cycles, market changes and big shifts in our portfolio. During the quarter, we announced a 2% dividend increase for 2026, marking our 13th straight year for dividend increases. We have set this at the low end of our previously communicated 2% to 4% annual dividend growth through 2030. This reflects our confidence in the cash flow from our contracted fleet while keeping room to fund the growth opportunities in front of us. Our message is consistent. We invest with discipline, grow our cash flow and return a meaningful share of it to shareholders. With that, I'll turn it back to Avik for closing remarks.

Avik Dey: Thank you, Kevin. Before we open it up for questions, I'll bring us back to where we started. Everything we've talked about today rests on a stable state. Our long-term contracts with investment-grade counterparties give us predictable cash flow, and that stability is what lets us invest with confidence and keep growing the dividend year after year. On top of that base, we have growth that doesn't depend on buying anything new. It already sits within the assets we own. As we contract and capture merchant value across the fleet, that upside is the clearest driver of our AFFO per share growth through 2030, and we have a well-defined path to deliver it. Beyond that, demand from utilities and large load customers is creating real contracting and development opportunities at our existing sites. With M&A on top of that, we have more levers to create value and a runway that extends well beyond the near term. The takeaway is simple. A stable base growth already within our assets and new opportunities taking shape. We're confident in where Capital Power is headed, and we're moving with discipline to capture it. Together, that is a business with the stability of the utility and the growth of an IPP. We're excited about the opportunities ahead. With that, I'll turn it back to Roy.

Roy Arthur: Thank you, Avik. Operator, we are now ready to take questions.

Operator: [Operator Instructions] Our first question will be coming from the line of Robert Hope of Scotiabank.

Robert Hope: Can you maybe give us an update on what the M&A environment is looking for, both for on the contracted side as well as, we'll call it the merchant side on the PJM market? Kind of what headwinds and tailwinds are you seeing in terms of your evaluation as we have seen assets continue to transact?

Avik Dey: Thanks for the question, Rob. I would say this year has been a tale of 2 stories. The year started out with considerable activity, in particular, around larger transactions. On the single plant side, we were seeing less come to market. And then with the regulatory environment, moratoriums and some of the announcements in the year, I think the back half of the year has more or less been locked up. So I think there's been very few assets come to market. So in the context of the overall strategy, I think '26 feels like a pause in the M&A market relative to single asset opportunities. And I think the larger transactions, we know the ones that have already traded, but I expect to see '27 become more active again on single plant transactions. So hopefully, that answers the question. I think just while I've got the mic on M&A, I can say, overall, the partnership with Apollo as we've evaluated opportunities continues to be strong. I think there's strong alignment there in terms of how we view the landscape on U.S. generation. We continue to be excited about the merchant opportunity set. And I think if anything, I would say our focus will be going forward, really trying to identify those single plan opportunities and probably more of a focus on the bilateral side of it in sourcing and originating opportunities with a continued focus on PJM and where opportunities present themselves or ones that we originate in MISO and potentially WECC, less of a continued focus on ERCOT from the M&A standpoint. Hopefully, that answers the question.

Robert Hope: Yes. That's great. And then can we go back to the commentary on turbine availability in the prepared remarks. So what specifically is driving your view that there could be a turn in the market? Are we seeing some competing projects falling away, increasing supply? Is the supply chain catching up? Are there other factors? And I guess, secondly, there, does this potentially accelerate or move forward your operate thinking?

Avik Dey: Yes. So I think my overall comment would be -- and I think we've been consistent on this. Our business plan has been focused on stability and predictability. And as you've heard me say time and time again, we're focused on high-quality counterparties and focused on hyperscalers and large-scale data centers. What we've observed in the market as moratoriums have come to fruition in the U.S. and many of these slots were taken by other counterparties is in the chase for speed to power, in certain instances, we're seeing the ability to swap slots and take deliveries in '28, '29, '30. So I wouldn't call it enough to pick the trend, which is what my comments were. But I think if we needed turbines on a specific project, we're seeing a better ability to capture them, and it's really about trading slots near term in exchange for longer term and working with counterparties or even the parties that actually own those turbines directly. So I think we feel better about it. Again, not ready to call a trend. I don't think there's anything structural in the market happening that's saying supply chain is catching up or competing projects are falling away. As I said last year a number of times, we continue to see the market high-grading the data centers, the data centers, not a data center, not a data center. So the ones that are near term that are high-quality counterparties that are having chip deliveries in the next 2 to 4 years, I think those projects are all going to go forward. And I think we're going to have better access to equipment and supply chain over the coming 2 to 3 years. Again, not enough to call a trend, but I think we're seeing an opportunity there for companies like us who have stayed the course on trying to stay focused on contracted opportunities.

Operator: Our next question will be coming from the line of Benjamin Pham of BMO.

Benjamin Pham: Maybe I just want to start off with the organic growth pipeline. You have a number of projects you're advancing now. You have Windsor now coming into service, the U.S. storage pipeline tracking your expectations and you seem quite bullish on that look going forward. Maybe just give us an update perhaps how we should be thinking about the replenishment of the organic growth pipeline and perhaps any sort of timing on it?

Avik Dey: Thanks, Ben. The way I would characterize how we're thinking about growth is I would anchor on the $1.25 billion of adjusted EBITDA coming at us through the combination of upgrades, recontracting and merchant exposure. As we think about replenishing the inventory to your question, I think we've got nearly 3 gigawatts of available capacity, so nearly 25% of our fleet that's up for opportunities, including uprates and expansions. On the greenfield side, I would say we don't have an active portfolio of new sites. I think as we continue to work with partners and to my earlier response to Rob's question on fleet availability, we've continuously evaluated site potential, but it's always been in the construct of having a party willing to contract with us and potentially in tandem with existing capacity. So I think whether we're acquiring new plants with that expansion capacity, like what we did at Rolling Hills, looking at new sites, I think the inventory will fill in and around that 3 gigawatts on the existing fleet. So I would draw a perimeter around our existing markets and say Capital Power is going to do what they do in places that require natural gas for baseload or critical capacity in markets we can wholesale power and contract. And if there's opportunities to expand or potentially build on a contracted basis, we'll evaluate that. Does that answer your question, Ben?

Benjamin Pham: Yes. No, it does. And maybe just on a separate question related on capital allocation. You mentioned M&A quite slow this year, but could pick up next year. You have recontracting opportunities. I notice your stock is down quite a bit quarter-to-quarter and it's reflecting the corporate expense from what I can see. How are you feeling about stock buybacks against the growth side of those things?

Kevin MacIntosh: Ben, it's Kevin. Thanks for the question. Obviously, it's an option, but it's not one that I think we're going to execute unless we see considerable further weakness. We're in an enviable situation in that we have very little in terms of major capital commitments as it relates to organic growth. And so we do have lots of options. We obviously monitor the question of share buybacks. But I would say no imminent plan to initiate an NCIB.

Operator: Our next question will be coming from the line of Mark Jarvi of CIBC.

Mark Jarvi: Just continue on the commentary on M&A, Avik. Just obviously, positive commentary around the upside in existing assets and being able to hit the targets. How do we interpret your comments? Is it reduced reliance on M&A to get to the 8% to 10%? Or do you still feel like M&A can be there and you're hitting potentially top end or exceeding the 10% AFFO per share target?

Avik Dey: Well, I won't anchor myself on your comment, but I say the latter is more likely than not. So I would not say a diminished focus on M&A. In fact, I think '27 is going to be more active than less, given that '26 was effectively a pause. But I would really call into focus that my comments were around the fact that we don't need it. We've got so much embedded growth on the existing portfolio and fleet. In the last 2 years, we've recontracted 2 gigawatt of capacity alone. So I think as you look out and you look at the opportunities that we are going to be even more laser-focused on finding opportunities to acquire that meet the criteria for us of having embedded upside that because of our focus on operational excellence and commercial execution that we can garner excess returns as a result. So I think if anything, it's just going to be more refined focus on M&A rather than looking at everything in the market, it's going to be back to basics for us on trying to find and identify those plants that we think we can really add value for ourselves and for our customers.

Mark Jarvi: Okay. And then just given the amended RBP in PJM and IRAS not going through, just where does that land you right now? Like could you contract Hummel as it stands right now? Given some of the uncertainty, how is that informing what you're either actively working on or contemplating at Rolling Hills today?

Avik Dey: Well, I won't pick out Rolling Hills or Hummel specifically. But what I would say in PJM is that we continue to see activity around bilaterals. We expect that to continue to happen. I think the recent announcement with Google and Constellation really speaks to that in terms of operates supporting the bilaterals in response to linear own generation. So we continue to see that trend. But to answer your question directly, we are evaluating multiple opportunities there. And I think the market as a whole is pushing forward even with IRAS on delivering capacity against the rate payer pledge as well as the bilateral as a result.

Mark Jarvi: Just a follow-up on that. Are you indicating then that you think contracts are tied to some incremental megawatts at the site? Or can it be contracting without having to change the capacity of the units?

Avik Dey: So specific to us, I would say we're more than 80% hedged when you look over a 3 to 4-year period of time. So we do have the opportunity to contract there. I would say all of us who are players in PJM are very focused on new capacity for contracting, but that ability to contract continues to be there. I think our focus where it is really around needing incremental power in support of the bilaterals as part of the broader process in the PJM.

Operator: And our next question will be coming from the line of Shar Pourreza of Wells Fargo.

Shahriar Pourreza: Just PJM a little bit, just in light of the deals we've seen and obviously, in the RTO and Google obviously didn't take sort of the clean energy attributes for Constellation. As we're thinking about the capacity obligations, are you thinking sort of CT storage? And should we assume new capacity bringing on is around 25% to 30% of the hyperscalers' needs? Because that seems to be a bit of a rule of thumb on new capacity.

Avik Dey: I think I can speak to our perspective, and I think more broadly for the market, I think you're bang on with that estimate. When you look at our fleet, in particular, how we marry new capacity, and I would say, today, we're primarily focused on CT. But that amalgamation of CT, CCGT storage, I think is where we are going. And in particular, on the storage side, what it does is it helps alleviate some of the pressure around grid reliability. So it serves multiple purposes by incorporating that into overall energy solutions. And we're seeing the same thing in Canada. We've already seen it in Ontario around utility scale batteries and what it does to support resiliency. We have 2 of those projects that are co-located on thermal sites. But I think it's a good rule of thumb. I think for us, in particular, when you look at Rolling Hills, that's obviously the solution. But I think there's a broader opportunity there as well down the road. It's not one that we're specifically focused on today in terms of the CCGT potential on that site. But I think the opportunity is there in medium to longer term.

Shahriar Pourreza: Okay. Got it. Perfect. And then as you highlight the $400 million to $550 million of incremental opportunity on contracting and upgrades, does the margin economics on that change if it's a portfolio deal versus co-located or asset specific? And any kind of direction in negotiations or the inbounds you're getting at this point?

Avik Dey: So I wouldn't say there's a difference whether -- actually, let me answer it this way. The ability to price that marginal electron is predicated on duration, counterparty and speed to market. And there's competing value in each of those pillars. And I think we've demonstrated over 17 years, we're pretty good at identifying how to maximize NPV per KW based on our assessment of the commercial opportunity, the opportunity cost and the CapEx. When you look at where we're headed on the RBP in PJM, because I think your question is most relevant to PJM, the market is focused on the upgrade opportunity because in the 15-year contract period, it's the upgrades that are going to be very competitive relative to CONE. And so there is a pricing difference when we're looking at contracting existing assets on existing capacity versus new capacity around and operate in service of bringing your own generation. So that's really more tied to what's on the denominator of total CapEx versus here's what the pricing sensitivity is to the customer, if that makes sense.

Operator: Our next question is coming from the line of John Mould of TD Cowen.

John Mould: I guess I'd like to start maybe just at Genesee, the efforts that you've made there to be able to bring more capacity either to the market or for some kind of contracting opportunity. Just wondering how that effort is going, how you're thinking about the work you've done with AESO there, potential time lines for getting some of that incremental capacity unlocked. And then maybe not to cast that too widely, but just more broadly, like the kind of how you're thinking about the Genesee site just in terms of longer-term contracting opportunities and how you're thinking evolved over the course of the year as you've had various discussions on that potential?

Avik Dey: Thanks, John. Let me start by saying Genesee continues to be our crown jewel asset as a company. Just put it into scope. And John, I know you've seen the site and many of you have, Manhattan is 15,000 acres in terms of aerial extent. The Genesee site is 26,000 acres. It's 1.7x the size of Manhattan. And it happens to be in a location that's 50 kilometers from a major center and within reach of 3 points of contact on fiber, critical access to water, critical access to pipeline, critical access to high-voltage transmission. So you've all heard me say that time and time again. The difference today versus a year ago, and it's a result of a lot of hard work by not just ourselves, but our peers in the industry, AESO, Minister Glubish and his team in the province overall. I would say today, Alberta is ahead of many of the jurisdictions across North America because in effect, Alberta took their moratorium 2 years ago in how they established Phase 1 and Phase 2. So today, where we look across the U.S. and there's hundreds of moratoriums in place, we're now well into the process of bringing new capacity through Phase 2. So when I sit back and look at Genesee, I see a site that's got significant potential because of the existing infrastructure, the existing footprint, our relationship with communities in and around our site, given our long 40-year operating history. And I think because we've been at the forefront of -- in partnership with government on putting together and supporting the Phase 1 and Phase 2 initiatives, I think the market overall is in a position where we're now bringing forward projects, whether it's ours or others. So today, we're very proactively looking and talking about potential opportunities through Phase 2 at Genesee. I think you can expect us to advance those efforts. I think Phase 2 in terms of establishing the rules of the road for bringing your own generation, we're getting closer to resolution on that. And I can say we're in active conversations around building a power solution for potential customers on that site. I can't give a sense of timing. I can't give a status update on where we are. But I would say things are progressing, and it's really a testament. We've always known we had one of the most attractive sites in North America because we've got excess capacity that's able to be in service today, technically speaking. Obviously, we have to continue down the regulatory path to unlock those megawatts. But I think more importantly, the tenor of how Alberta's viewed as a market for hyperscalers and how it concurrently addresses reliability and affordability concerns of the consumer while also bringing new capacity to the market. I think Alberta is in an enviable position today relative to other markets, and we're excited to be right at the forefront of that.

John Mould: Okay. That's helpful. And then maybe just one on La Paloma. And I know I asked this last quarter. But just wondering what you're seeing in the resource adequacy market just given it's quite a bit more opaque than some of the other markets we might see. How you're thinking about contracting that capacity via resource adequacy agreements versus other options? And I know you're not doing '27 guidance today, but just how should we think about the step down next year in that resource adequacy contracting versus the overall gradual step down into 2029?

Avik Dey: Yes. So I would say, as you step back and look at the California market, you highlight the weakness in the RA market. We continue to look at contracting opportunities, not in a position to comment on that. Obviously, batteries is having an impact on the market there. I think medium to longer term, we're more constructive and seeing a market that gets back into the double digits, well into the double digits. So I think overall medium to long term, we're more bullish than bearish. And I would say small be bullish. But we continue to think of La Paloma as a site that's critical to reliability in California and an important part of delivering grid reliability there. And we've got multiple options to whether expand or contract around that site. So I know it's a bit of an open-ended response, but I think generally, recognizing short-term pressures there, we feel like we've got some options to commercialize there.

Operator: And our next question comes from the line of Maurice Choy from RBC Capital Markets.

Maurice Choy: I just want to come back again to Alberta. Just wanted to see what you are hearing as to why the AESO Phase 2 announcement seems to be taking a longer time to get over the line.

Avik Dey: Maurice, we continue to expect to see resolution there in the coming weeks and measurable in low single-digit number of months. I think the -- I wouldn't say the delay is really just working through the logistics and details of it as the province prepares to bring forward legislation around it. So I think it's really nothing more than that.

Maurice Choy: And maybe just a quick follow-up. What's your expectation as to when the first intake will take place?

Avik Dey: I think I would just refer you back to my comment, measured within weeks to low-digit months, but I don't have more certainty than that. But I would say imminent.

Maurice Choy: That's great color. And my second question, if I could just look at your $1.25 billion of incremental EBITDA upside from recontracting and merchant power upside. I believe this is obviously up from $1 billion back in the Investor Day last year and something that you've been socializing a little bit more since September. So can you just refresh us on how much of this $1.25 billion will actually be realized before the end of this decade, thereby contributing to your 8% to 10% CAGR and how much you think could be post decade?

Avik Dey: Yes. I'll take a first crack at that, Kevin, feel free to add. So the only reason we don't anchor on 2030 is because a few of those recontractings, the upside is on the outside of 2030 calendar year. And you can point to some of the recontractings we've announced. So I would say without being able to be very specific, the majority of that is actually captured prior to 2030 and inclusive of 2030. But the reason we put it as an approximation is only because technically, some of that -- some of the higher contracting rates start in a post 2030 time line, not dramatically later than that, but we couldn't pinpoint it to '29 Q4, which is why we've given the guidance we have. But I think the economic value of it has been captured now, and that's how we've elected to show it to you from a portfolio perspective. Kevin, anything you want to add there?

Kevin MacIntosh: No. The only thing I'll add is that it's a function of commercial discussions. So we understand the importance of understanding the timing of the cash flows. And once we get deals done, we'll make sure that the disclosure is clear so that you understand both impact on EBITDA as well as on AFFO.

Maurice Choy: Maybe as a quick follow-up to that. One of the disclosures that you made today was that one of your facility maintenance has moved from 2027 to Q4 this year. Is this moving of the maintenance timing driven by what you see in the market? Or is this something where the facility requires immediate work?

Kevin MacIntosh: Maurice, it's Kevin. We went in and did a bore scope inspection in the third quarter. And there was some debate as to whether we could make it all the way to the spring or not. When you just think about the calendar, we thought economically, it made sense to bring the unit down now so that next spring, we're ready to go with very high reliability on that asset heading in the summer.

Operator: And our next question will come from Patrick Kenny from NBCCM.

Patrick Kenny: Maybe just back on the data center front and outside of the regulatory delays being experienced on both sides of the border. Just wanted to get your thoughts on the level of local support or any opposition you might have to deal with on the ground across the portfolio, how your team might be looking to get ahead of any of these NIMBY challenges that might come up, whether it's at Genesee, Midland, Rolling Hills or elsewhere?

Avik Dey: Yes. Thanks, Pat. And I appreciate the question because I think this is one of our core competencies and competitive advantages. And I think most importantly, you articulated at the beginning of your question, the local response. This is about local engagement, and it can't be in response to bringing in large load at the time you want to bring it in. It's really about that ground game engagement with your plants in the communities and then open conversations and communications with stakeholders. And I think we've demonstrated we've done that for 17 years of our existence in the communities that we're in. Our legacy having come out of municipal-owned utility predicated that the importance of that engagement with local communities. So whether it's our community teams, our stakeholder engagement teams, our regulatory, our GR folks, it's a multifaceted approach that requires expertise, it requires people, it requires boots on the ground. And I think we've established that report and that dialogue in each of our key markets. Obviously, we are new to Ohio and Pennsylvania. So those are 2 arenas that we're working to establish ourselves in the same light that we are better established in places like Arizona and Alberta and Ontario and Michigan. But that approach is not about data centers. It's about being good stewards and partners in the markets we're in as a power generator. And as part of that -- and you've heard me say this for 3.5 years. I said it in Q3 of 2023. We did not see these opportunities coming forward unless you were partnered with stakeholders and delivering affordability and reliability improvements and enhancements to customers in the markets we serve. This, to me, is the single largest infrastructure challenge we've faced in the last 75 years. And we're connecting 40-year regulated infrastructure to 20-year data centers that are fueling 5-year chips and 80% of the CapEx is sitting in the 5-year chips. So the scale of what's in front of us is what we've never seen the complexity of it is, also more complex than we've ever seen. And it's about building large infrastructure for customers that have long-term needs. And that means it looks like it feels like hard work. And I think we've demonstrated that we can do that as a power generation provider.

Patrick Kenny: Okay. That's great color. And then maybe just operationally, as it relates to the milder temperatures here and these El Nino conditions likely to persist through the winter, resulting in perhaps lower generation as well as lower pricing volatility. Just curious how you might be thinking about mitigating or optimizing the fleet through the winter, including perhaps accelerating any turnaround or upgrade opportunities?

Kevin MacIntosh: Patrick, it's Kevin. Just as a reminder, we actually had 1 day yesterday -- or sorry, last week where we kind of settled, it was like -- it was over $250 a megawatt hour on -- it was 1 day last week, right? So it just kind of underscores that the market is pretty volatile. I think some participants are pricing their marginal megawatts fairly aggressively. I think that when we think about 2027 from a hedge perspective, we've got 80% kind of across the portfolio. And so the team will be looking pretty opportunistically to lock in more hedges when it makes sense. It's interesting, some of these super El Nino case studies, there are some where, obviously, it's very, very warm, but there are others where there are periods of deep, deep cold. That said, no real plan to advance turnarounds or move the timing of turnarounds at this point in time.

Operator: And I'm showing no further questions from our phone lines. I'd now like to turn the conference back over to Roy Arthur for any closing remarks.

Roy Arthur: Thank you, operator, and thank you to everyone for joining us for the call today. This brings the call to a conclusion. We thank you for your continued interest in Capital Power. Have a great day.

Operator: Thank you. This does conclude today's program. Thank you for participating. You may all disconnect. Everyone, have a wonderful day.