Capital Power Stock

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.

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.

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.

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.

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.

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

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

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?

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.

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?

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.

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

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?

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?

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?

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.

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

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?

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.

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?

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.

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?

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.

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

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.

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.

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?

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.

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

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?

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.

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?

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.

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

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.

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.

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

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.

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?

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?

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.

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?

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.

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

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?

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.

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?

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.

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.

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.

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

Hello, and welcome to Capital Power's Second Quarter 2026 Analyst Conference Call. [Operator Instructions]

I would now like to hand the conference over to Roy Arthur. Sir, you may begin.

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 second quarter 2026 results, which we published earlier today. The report and the presentation for this call are available on our website.

Before we begin, allow me to describe how we will spend our time on today's call. First, our President and Chief Executive Officer, Avik Dey, will walk through our business highlights, including recent commercial optimization efforts and why we remain excited about the future of our business. Following that, our Senior Vice President, Finance and Chief Financial Officer, Kevin MacIntosh, will highlight our growing confidence in the upside embedded in our business in addition to reviewing the quarterly results. Avik will then provide concluding remarks before we open the floor to analyst questions.

Now that I've described the agenda for the call, allow me to address a couple of housekeeping items before handing it over to Avik. First, we acknowledge that Capital Power's head office in Edmonton is located within the traditional and temporary home of many indigenous people of the Treaty 6 region and Métis homeland. We acknowledge the diverse indigenous communities that are in these areas and whose presence continues to enrich the community and our lives as we learn more about the indigenous history of the lands on which we live and work.

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 Pages 4 and 22 of the presentation for the applicable disclosures.

With that, I'll turn it over to Avik.

Thanks, Roy. Before we begin, I just wanted to acknowledge and thank the number of investors, customers, partners and community leaders that joined us at the Calgary Stampede this year in July in our home province of Alberta. The Stampede this year welcomed more than 1.4 million visitors. And in particular, this year, it was incredibly exciting to see how much energy there was around all the great things happening in Alberta and Canada exemplified by the number of announcements that were made and it just continues to excite us what the business outlook for the province in Canada is.

And secondly, I just wanted to take a moment also to recognize my 800 colleagues across North America, who worked tirelessly to deliver reliable and affordable electricity and be active stakeholders in the communities in which we operate. None of our success could happen without their contributions.

Our second quarter results reflect a business that is capturing demand and delivering on the opportunity in front of us. There are 3 key takeaways we'd like to leave you with today. First, as I mentioned before, Alberta is open for business. Policy clarity is improving confidence, attracting investment and positioning Alberta as a leader among North American data center markets. New customers combined with growing demand from Alberta's established industries means the province will need significantly more reliable power in the years ahead. Our recently announced energy supply agreement is tangible evidence of our differentiated approach in action, taking capacity already embedded in our portfolio and converting it into durable long-term contracted cash flows.

Second, our business has significant embedded growth potential. Our large and diverse portfolio offers a number of opportunities to create incremental value from a merchant and contracted perspective. Our confidence in being able to optimize around our business continues to increase as we execute on our strategy, and we are pleased to be providing an update on this today.

Third, our returns remain balanced. We continue to target compelling risk-adjusted returns combining meaningful cash flow growth with an attractive and growing dividend.

Turning to our Q2 highlights. You will see how we continue to execute through contracting, optimization and disciplined capital allocation, translating opportunity into results.

Turning the page. We continue to progress our 2026 priorities. These include optimization and renewable growth while maintaining a disciplined focus on long-term value maximization. Our second quarter highlights included securing a 250-megawatt long-term energy supply agreement with Meta, a premier hyperscale customer subsequent to quarter end.

Next, advancing capacity upgrades across our WECC and PJM portfolios, adding approximately 45 megawatts of incremental capacity in 2026 and a further 25 megawatts in '27.

Executing on our growth projects with North Carolina Solar under construction and East Windsor nearing completion with commissioning now underway, generating 10.1 terawatt hours across the portfolio up 12% year-over-year with 60% coming from our U.S. fleet, reinforcing once again the success of our diversification strategy.

And lastly, advancing our 2026 maintenance cycle, with 66% of planned outage days now complete, strengthening the reliability and efficiency of our fleet. Our progress reflects the strength of our people and the culture we've built, one that values ownership, collaboration and disciplined decision-making. By bringing together expertise from across the org, we identify opportunities that create value for our customers and shareholders. The agreement to provide power to Meta is a recent example of that capability at work.

Our recently executed energy supply agreement in Alberta demonstrates our ability to unlock value through commercial optimization with investment-grade counterparties. Under the agreement, we will provide 250 megawatts of capacity and energy expected to commence in the second half of 2028, over a term of more than 10 years. Strategically, this transaction does several important things. It converts existing merchant power generation into stable, long-duration contracted cash flows, and it does so with no capital investment.

Additionally, the agreement is at the portfolio level and does not encumber any of our assets. This preserves our commercial optimization upside at Genesee, our flagship facility, where we see significant opportunities ahead. In Alberta, we continue to see strong demand from data centers and other large customers seeking reliable power, providing more opportunities to generate incremental value from our existing fleet. This is a significant milestone and reflects the broader trend across our fleet as we continue to secure attractive contracts and enhance the value of our capacity.

Recent contracting activity across Alberta, WECC and MISO highlights the strong positioning of our fleet. Over the past 5 years, we have consistently captured value through strategic recontracting across our portfolio. These efforts have enhanced cash flow visibility while generating attractive risk-adjusted returns. We continue to use replacement cost economics as an important benchmark and are negotiating to ensure we are appropriately compensated for the value and reliability our assets provide. We continue to see meaningful opportunities to maximize value per kilowatt through disciplined contracting and commercial optimization. Beyond the value we are creating through contracting, we're encouraged by the opportunities across our markets where strong fundamentals support both development and merchant upside.

We operate across multiple power markets, each with its own drivers of value. Throughout our footprint, policy clarity, tightening supply-demand fundamentals and increasing reliability needs are creating opportunities to contract existing capacity at attractive prices and unlock additional value from our portfolio. These dynamics support both commercial optimization today and future growth opportunities across our fleet.

We also benefit from diversification across technologies with natural gas renewables and storage, allowing us to meet a wide range of customer and market needs. Taken together, our portfolio gives us the flexibility to allocate capital where opportunities are most attractive, reduce reliance on any single market and continue creating value across a range of market environments.

With that, I'm pleased to turn it over to Kevin who will take you through our financial results and highlight how the opportunities we've discussed are increasingly reflected in the value we're creating across our business.

Thank you, Avik, and good morning, everyone. Before I get into the quarterly results, I want to take a moment to reflect on my first 4 months as Capital Power's CFO. I've been most impressed by the quality of the people that make up the Capital Power team, the discipline they bring to our approach to operational excellence and the care they have for the assets in our fleet, the discipline they bring to the commercial optimization of the business and the track record of disciplined capital allocation. It is an exciting time to be in the industry and be part of the Capital Power team.

Let me walk through what I'll cover today. As Avik highlighted, we continue to see significant incremental cash flow generation potential embedded in our business. I'll start there, then provide an update on our guidance and outlook before walking through our second quarter financial results.

We've delivered significant value for shareholders over the past several years, reflected in both our growing adjusted EBITDA and share price performance. But what's most exciting is that the opportunity in front of us has continued to improve. Alberta demand growth is accelerating, power market fundamentals are strengthening and we're seeing tangible evidence that customers are willing to pay for reliable, dispatchable power.

While our total return proposition includes disciplined M&A and development, it's important to recognize that significant value can be created from the portfolio we already own through commercial optimization, which includes contracted and merchant opportunities, operates and operational excellence, we have multiple avenues to grow cash flow and increase earnings over time. That's exactly what our embedded EBITDA opportunity reflects.

In December, we outlined approximately $1 billion of annual EBITDA upside embedded in our business. Since then, we have made meaningful progress on recontracting and have gained greater confidence in the outlook for merchant power pricing in Alberta. As a result, we are increasing our estimate of embedded annual adjusted EBITDA upside to approximately $1.25 billion. Of that total, approximately $400 million to $550 million relates to contracted upside primarily from our U.S. flexible generation assets as legacy contracts expire between 2029 and 2032, as well as upgrade opportunities across several natural gas facilities. An additional $375 million to $700 million relates to merchant upside, reflecting the value creation potential in PJM, along with the benefit of stronger pricing expectations in Alberta. Importantly, this represents value that is already embedded within our existing portfolio. Our focus is on realizing that value through disciplined commercial optimization and continued operational execution. As we make progress, we look forward to providing further updates.

Based on our performance year-to-date and our outlook for the balance of the year, we are reaffirming our 2026 guidance ranges. We continue to expect adjusted EBITDA of $1.565 billion to $1.765 billion, AFFO of $890 million to $1.01 billion and sustaining capital of $290 million to $330 million. As previously disclosed, our sustaining capital reflects a planned maintenance cycle across the fleet. This investment is intentional and positions the business to capitalize on strong market fundamentals over the long term. Overall, these ranges reflect the confidence in the resilience of the portfolio, the durability of our cash flows and our ability to generate strong financial results while continuing to invest for the future.

Turning to our financial performance. The second quarter and year-to-date results reflected the strength of our diversified portfolio. In the quarter, adjusted EBITDA was $351 million, up $29 million from the second quarter of 2025. The increase was primarily driven by the contribution from our expanded PJM portfolio, partially offset by lower results from our U.S. flexible generation segment due to planned maintenance outages and lower capacity revenues as well as higher corporate expenses related to strategic initiatives.

AFFO was $328 million, up $93 million year-over-year, benefiting from the higher adjusted EBITDA contribution and the recognition of Canadian clean Tech ITC government grants. These ITCs are the result of the investment we made in Halkirk Wind and Ontario battery energy storage projects in Ontario. As we filed our final claims in Q2, the ITCs have been recognized in AFFO. We expect to receive a portion of the funds in 2026 and the balance in the first half of 2027. The ITC benefits were partially offset by higher sustaining capital expenditures associated with our Alberta maintenance program and increased activity across our U.S. flexible generation fleet as well as higher finance and income tax expenses.

Year-to-date adjusted EBITDA increased to $755 million, up $66 million, while AFFO increased to $482 million, up $29 million versus the prior year. These results reflect the contribution from our expanded PJM platform, government grant proceeds from the -- related to Clean Tech ITCs and continued disciplined execution across the portfolio. Overall, the results demonstrate the strength of our diversified fleet and our ability to deliver consistent cash flow and earnings growth while continuing to invest in the long-term reliability and value of our assets.

Over the past decade, we have consistently delivered a balanced return proposition combining meaningful cash flow growth and yield. Since 2016, we have expanded our portfolio from approximately 3 gigawatts to more than 12 gigawatts, growing capacity at roughly 15% annually. That growth has been driven by disciplined capital allocation with more than $12 billion invested across organic growth and M&A opportunities. At the same time, we have historically increased our dividend at an annual rate of approximately 6%. As previously communicated, we have reduced growth rate guidance of 2% to 4%, which is a reflection of our confidence in pursuing value-accretive M&A and development.

Consistent with our 2026 guidance, we are increasing our dividend by 2% for this year, marking our 13th consecutive year of dividend increases. This track record reflects our ability to deploy capital prudently, grow cash flows and deliver attractive risk-adjusted returns for shareholders through multiple market cycles.

With that, I'll turn it back to Avik for closing remarks.

Thanks, Kevin. As I wrap up, I'd like to come back to 3 themes I highlighted at the onset of our call. First, Alberta is open for business. Strengthening fundamentals and growing customer demand are creating meaningful opportunities and we, Capital Power, are uniquely positioned to capture them.

Second, our business has significant embedded growth potential. As we emphasized last year at our Investor Day and continue to discuss with our investors at large, our portfolio offers upside with limited capital in addition to expansion opportunities, and we are excited about the forward plan to deliver those.

Third, our returns remain balanced. We continue to target compelling risk-adjusted returns through a combination of cash flow growth and an attractive growing dividend. We remain confident in our ability to generate attractive long-term returns for our shareholders. Our 2030 outlook is grounded in the same strategy that has driven our strong historical performance, disciplined capital allocation, growth of our U.S. platform, continued optimization of our existing fleet and a commitment to a growing dividend. The strong shareholder returns we have delivered reinforce our confidence in both our strategy and the opportunities we see across our core markets.

With that, I'll turn it back to Roy.

Thanks, Avik. This concludes the formal part of the presentation. Operator, we are now ready to take questions.

[Operator Instructions] Our first question comes from the line of Shar Pourreza with Wells Fargo.

It's actually [ Constantine ] here on for Shar. Maybe starting off on the most recent PJM RBP proposals just with the most recent developments and increasing clarity, what level of participation do you anticipate? And maybe how are you thinking about new resource additions versus any color on advancing commercial arrangements that would utilize those existing capacity?

Shar, thanks for the question. Obviously, we've been paying close attention to the recent announcements, the amalgamation of the RBP and [ connected management ] process is a significant change. We feel really good about our existing fleet at Hummel and Rolling Hills. We continue to see opportunities on the bilateral side. And I think the recent auction just reaffirms our bullishness on the medium to long term in PJM.

So we think the movements have been positive for incumbent generators. We think we've got a strong fleet between Hummel and Rolling Hills. And overall, I think the opportunity for bilaterals is stronger than it was previously. So that's how we're thinking about it.

And would you be looking for, I guess, opportunities to put new capital to work kind of versus some of the EBITDA opportunities that you highlighted on the call?

We absolutely are looking for development opportunities on both sides of the border. In particular, Alberta, we see development opportunities to support growing data center load. And then our ongoing efforts in the U.S. are opening a number of opportunities on that front, largely stemming from our positions in our existing markets.

Excellent. And maybe a quick follow-up to that. Maybe any updated thoughts around capital allocation. And I appreciate, Kevin, with a little bit of history there. But any kind of opportunities or thresholds that would cause you to pull forward any incremental capital deployment? Any specific IRR threshold? Is it more focused on the specific commercial arrangements?

Well, we're obviously -- thanks for the question. We're obviously very focused on delivering our committed 13% to 15% annual TSR. We are excited about the growth opportunities in front of us, particularly as it relates to organic development opportunities that Avik just touched on. And my view is that increasingly, we're seeing a speed to power premium in the economic cases that are coming forward. So stay tuned. No major departures from our capital allocation framework, but we feel really excited about the growth opportunity ahead of us.

Excellent. I appreciate that. And maybe just a quick housekeeping one kind of with the Meta agreement, kind of the PJM, BRA, RBP auctions, stronger curves and hedging. Are you seeing any ways to capitalize any of the upsides from kind of that -- the upside that you highlighted to the EBITDA versus the kind of 8% to 10% AFFO growth target? Or is that too early to call?

I would underscore that we've just updated the embedded EBITDA opportunity that we see in front of us from $1 billion to $1.25 billion. The Meta example is one of the examples that underpins that increase. So yes, we're really optimistic about the organic opportunity in our base business.

Our next question comes from the line of Robert Hope with Scotiabank.

I have a question on Genesee. So we saw G1/G2 test above 600 megawatts a couple of weeks ago. Are we getting closer to being allowed to run at a higher capacity there? And also, when you think about bringing your own power and bridging, is the intention on a longer-term basis to use that capacity as a bridging capacity, which will then support potentially an organic opportunity in Alberta?

Rob, yes, in short is the answer to your question. The way we look at Genesee is the incremental capacity over and above 466 would qualify under the Phase 2 bring your own generation, which also, I think, could be considered as part of the bridging solution.

So as we've said for the last 1.5 years, we continue to believe Genesee is one of the most attractive sites in all of North America for data center development, but most importantly, without compromising affordability and reliability to the consumers that we serve in Alberta. So our optionality at that site is significant in terms of how we manage through Phase 2 and/or bridging solutions and/or future development of new capacity to serve it.

With regards to the testing of 600, that is true, and we continue to work with the ISO in terms of reaffirming our solution there and/or alternative solutions to increase capacity there, and those are proceeding.

All right. Excellent. And then maybe a follow-up question there. With just the increase or becoming more increased clarity on the bring-your-own generation framework in Alberta as well as the initial Meta announcements. Can you provide an update on where discussions that you're having with bringing incremental data center customers to the province?

Sure. What I can say, Rob, is this is a journey that for us started 3 years ago, and we've been doing work on our site and working in partnership with government stakeholders, potential customers for that entire 3-year period inclusive of having an important role in bringing Meta to the province.

So as you can expect, we are having multiple conversations around the future of Genesee and how to work within the existing Phase 2 framework. I'm not in a position to comment on any particular customer or any particular project. But I can tell you, we are having multiple conversations today around how and when and at what quantum to develop that site.

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

Just following up on the last question. Are you able to share how the contracted price compares to where the forward prices are. And if there's any discounts, how should we think about how this pairs up with any associated pass-through of risk and cost.

Thanks for the question, Maurice. So we have limited disclosure around the specific contract terms for the 10-plus year contract with Meta. That is investment grade, and I'll reaffirm 10-plus years. What I would say in terms of how our approach has been, and I think this is actually one of our big advantages in this market. Our core competency as a company for 17-plus years has been contracting with investment-grade counterparties for medium- to long-term contracting. So as it relates specifically to Alberta and this contract, we have our view on where long-term CONE is going, and we have a firm view on how risk sharing should work. And I can tell you that this contract is consistent with our medium- to long-term outlook for the Alberta market.

And I would just make note that we think that, that isn't necessarily reflected completely in the existing pool price outlook in terms of strip given the relatively low liquidity that you see in the out years for it. But I think the best way to answer it is the contract is reflective of appropriate risk sharing between ourselves and the counterparty, one; and two, reflective of our own view of CONE as we look out medium term for the market.

That's great color. Maybe as a quick follow-up. How do you see this relationship possibly progressing from here and hopefully beyond this 250-megawatt ESA?

We are hopeful. We have great confidence in our capability to be a partner of choice for utilities and hyperscalers across North America. We have great confidence in our abilities as a leading operator of utility scale generation, in particular, natural gas. And I think we've demonstrated ourselves to be very collaborative and constructive with stakeholders in all the jurisdictions we're in.

And so I'm quite optimistic about our ability to build and forge broader and deeper relationships with our with our key customers. As we've demonstrated time and time again, whether it's in Michigan with CMS, Arizona with our future additional recontracting. So quite bullish on that, Maurice.

If you just finish up with an opportunity in the U.S. And I apologize that this was asked earlier already. I guess when you think about your partnership with Apollo, it's about 8 months since you've announced it. We've seen during the quarter, at least in the recent few months that Apollo has got involved with other third-party power projects in the U.S. Would you be able to share where this partnership is in terms of sourcing opportunities? And what, if any, have been the challenges in sourcing an appropriate deal?

Yes. I would say the partnership with Apollo has been going well in the sense that we're actively working together, evaluating multiple opportunities. We have not yet transacted. We've looked at and evaluated multiple opportunities. And I think the most important point there is we continue to be disciplined about the opportunities that we're trying to source.

I think as we look and it's probably more -- it's less about Apollo actually, Maurice, more about the market. I think we are trying to be very disciplined around the assets that we acquire have to be -- have to have tangible upside that we can quantify and qualify around future upgrades, upgrades recontracting opportunities. And they have to meet our minimum threshold for accretion to make our investment case.

So we've been looking at some larger transactions. The deal pipeline is bigger today than it was last year. And I feel confident about our ability to ultimately source the right type of transaction. We continue to focus on merchant opportunities with them. And so to date, I don't feel like there's been deals done away from us, and we will find something in due course.

Our next question comes from the line of Nick Amicucci with Evercore ISI.

Avik, Kevin, just I have a couple of quick ones. So as we kind of think about -- we kind of got over the hurdle now with the Meta ESA for 200 megawatts in over 10 years plus as you alluded to. Just as we think about kind of the various stages of discussion with other prospective colocation customers, which of your sites are you guys kind of targeting and kind of screen best for kind of the next type of offtake agreement? And where should we kind of level set expectations? Like is it over the next 12 months? I mean I don't want to back you into a box and put a shock clock on it, but over the next 12 months, over the next 24 months, how should we think about it?

Nick, thanks for the question. So absent the shot clock question, which it is a shot clock question. I do think we've got multiple opportunities in front of us. Michigan continues to be interesting. La Paloma is a potential site. We continue to see opportunities in Arizona. And then obviously, first and foremost is our opportunity set at Genesee.

I would say, multiple sites in our fleet on both sides of the border, one being Genesee in Alberta, the others being in the U.S. all have opportunities to contract or and/or expand to either serve a large load customer or a data center. So we continue to see those. I think much like my response has been over the last few years on recontracting, I would emphasize that this whole recontracting effort for us is equal parts art and science, and that decision to optimize that recontracting window and extension to maximize NPV per kW is all about being able to serve the customer what they need when they need it. And it's also incumbent upon us to have that right value proposition that benefits our shareholders as well, whether we're augmenting that with an upgrade, looking at a potential expansion.

So I'd be very hesitant to put a time line on it, all but to say we continue to be disciplined. Maximizing NPV per kW is our overarching approach to how we drive those decisions. That's not going to change. And I'm hopeful that what we are demonstrating to you and to our shareholders is that we've got a deep enough inventory of opportunities that it's repeatable over time, and we'll have a good cadence of delivering those.

Well, I didn't answer your question exactly, but hopefully, that gives you enough color and confidence in what we're trying to do.

Yes. No, that's perfect, Avik. And I wasn't expecting a direct time constraint for what it's worth. Then I just wanted to ask quickly on Maple Leaf and the Hornet Solar projects. It seemed to have slipped a little bit. Just wanted to see what kind of drove those scheduling revisions? And if there's any kind of broader cost or supply chain pressure that we should be considering?

No, I would -- thanks for the question, Nick. It's Kevin. Yes, there's nothing material going on there. We've seen slight slippage in terms of the solar project schedule, but nothing material. And from a cost perspective, again, largely coming in on budget. Little -- there's some cost pressure, but nothing material.

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

This is Tanner on for Julien. Maybe following up on the discussion here. Your broader energy market commentary, it screens relatively constructive across a number of the regions. You guys just mentioned several markets. Michigan WECC, et cetera. Maybe to ask the question explicitly here.

Relative to PJM. how might those be screening in terms of project development, policy visibility, potential transaction structures? How are you sort of dedicating this -- you have some M&A upside built into the guidance. Just how should we think directionally about how you're thinking regarding these markets specifically and how they may -- how you may ultimately look to transact or maybe a priority ordering of a couple of regions would be helpful as well.

Thanks for the question. I think for us, we have a large position in PJM in terms of megawatts, but it's concentrated in 2 critical assets. One being Hummel in Pennsylvania and two being rolling hills in Ohio. So when we think about the overarching market dynamics, what that play between the BRA, the interim resource adequacy service and then the ultimate bilateral opportunity set, it's fair to say you should concentrate that attention around Rolling Hills and how we think about the forward development of Rolling Hills. So our concentration around physical capital investment to expand or add megawatts is generally focused around how and where we could -- how, when and where we can build out capacity there in service of future customers.

And Hummel continues to have very interesting wholesale opportunities. So that combination when we underwrote that transaction, that ability to have that portfolio of highly efficient CCGT with a peaker site with expansion capacity, I think, uniquely positions us there with our own fleet. And I think the dynamic nature of that market, especially given the high-quality nature of our assets, access to existing gas supply in Rolling Hills, multiple points of gas supply, access to transmission and distribution, I think, uniquely positions us off of those two assets in a market that's dynamic. And I would reemphasize the point that a market that once again at the latest auction didn't clear reserve margin. So I think we feel very good about the opportunity set, but our attention is fairly focused and how and when and where we would delay capital against our existing fleet. Hopefully, that answers the question for you.

That's great. I appreciate that. Maybe given the steeper forward curve in Alberta and there's obviously an availability of potential contracting opportunities there. Is there any change in the view you guys provided in December regarding your target geographic or your target international mix over time?

No change in that regard because if you recall, we didn't actually geographically parse our capital allocation targets. It was divided between thermal, renewable and other. So I think, as Kevin stated earlier, no imminent change on capital allocation. But I think the flexibility within how and where we allocate capital for thermal, whether it's to acquire or expand or develop. And we have flexibility there, but it's not something that we're at a point where we would allocate between geographies there.

Understood. The additional owned U.S. capacity of 3.5 gig, call it, that's unchanged, correct?

Correct.

Our next question comes from the line of Benjamin Pham with BMO.

I'm just wondering if you can comment a bit on managing the social risk of building data centers, which seems to have increase quite a bit of late, especially in the U.S. You've taken more of a [indiscernible] approach with data center development, we're still out of some metal. And then just related to that, we've been getting a lot of questions on the Alberta [indiscernible], whether it's impacting the stocks of late. And more curious, your thoughts on really the Alberta perception of data center is independent public review? And do you think it could tie into some sort of maybe more broader government policy shift and change?

Thanks for the question, Ben. Here's our view on it. And I feel very strongly that we've been very consistent around the opportunity set around data centers, really from Q3, Q4 2023, when we said we didn't necessarily view the behind-the-meter opportunity as the one that would ultimately win the day because you had to have an approach of engagement with stakeholders for you to have the license to operate.

It's been -- I think I've been fairly a broken record on that point around you can't compromise affordability and reliability. And I think we've been true to that in terms of where we've spent our time as a company where we've allocated people capital and effort towards the opportunity sets around data centers. And what I mean by that is we haven't really been focused on behind-the-meter opportunities where I think those will be most impacted by the considerations around community and impacts on affordability and reliability of the grids.

What we have been focused on is our existing fleet in cooperation and coordination with stakeholders. So as we've said over -- and we talked about this at our Investor Day, that trifecta of managing the operators, the regulators, the customers and finding solutions that work for all of them is where our attention has been focused. We'll continue to be focused, and we see a growing opportunity to work with utilities and hyperscalers with that locked arms balanced energy solutions approach that we've been professing over the last 3 years.

I do take your point that there will be growing efforts and considerations and political pressure on when and where these data centers can be introduced. But I think we're pretty uniquely positioned in the markets we're in to do that in a very constructive and collaborative way.

With regard to sort of your question on Alberta polling for data centers. I think yes, on the Alberta question, I think it's going to be very regional, and it's going to be locally driven support or not. And it's going to be incumbent upon project proponents to be engaged with their stakeholders and work within the existing system.

So I think for us, I think Alberta in many ways, as all of you have heard me talk about over the years, I think Alberta has been in front in terms of trying to coordinate a regulatory environment that supports large load. Obviously, we didn't agree with the approach in Phase 1 in terms of how the volumes were allocated, but we did support and highly agree with the approach that the government was taking in terms of trying to be balanced about how to introduce this large load. And in many ways, what we're seeing in PJM now is following what Alberta has done. It's a different market structure. But in terms of how do you introduce large load, how do you manage some of the connecting -- connect and manage situation and then ultimately allow for new capacity on the generation side and new data centers. So short answer for Alberta, I think it's a local question, and it's one that's going to require continued engagement and cooperation.

Okay. Got it. So it sounds like this [ ledger poll ] that the National Poll has been talking about saying [indiscernible] are concerned around that it's probably not going to get too concerned about is what it sounds like.

I wouldn't say I'm not concerned about it. I think it's incumbent upon every market participant to have strong engagement. If anything, it's a warning that you've got to be a constructive and cooperative and collaborative partner in infrastructure development, which has always been the case. I think where we are on data centers is it's very front of mind for us just given the capital cost and magnitude of it. But I absolutely don't take it lightly. I think it just reaffirms the importance of engagement.

Understood. There's a quick follow-up on that $1.25 billion opportunity set. So was the -- and I think one for the detail on what's driving that. In terms of the exercise, was it mostly a mark-to-market on the forward prices that you're seeing? And then in there, is the Meta uplift contract in those buckets somewhere as well?

Yes. Thanks for the question, Ben. So yes, let's break it down. I would say the biggest impact is actually in the recontracting space where we've had a lot of very productive conversations over the course of the last 6 months as everybody is aware. We've seen CONE creep up over that period of time. And I think increasingly, our customers are realizing that recontracting earlier than they might otherwise in light of the cost pressure on CONE, we're seeing quicker engagement, and that engagement is very constructive from a pricing perspective.

Yes, we also see the impact of effectively derisking some of the merchant portfolio with the Meta contract. And as it relates to the merchant exposure in those cases, it is a more constructive view of the fundamental. And I'll say, spark spread, not just power price, but views on gas as well. So it's not just a pure mark-to-market. I would call it a derisking of our view on the fundamental prices that we assume for the future.

Our next question comes from the line of Patrick Kenny with National Bank Capital Markets.

Maybe shifting gears to Ontario, not the highest profile market right now, but just given the higher utilization, as you noted. Wondering if you could update us on how your portfolio stands to benefit from this rising demand for flex gen megawatts and perhaps even policy shaping up to attract data center proponents as well. What growth opportunities your team might be working on or planning to work on over the near term? And I guess how these opportunities might stack up from a risk-return standpoint relative to your other, like you said, higher profile jurisdictions?

Pat, the way I think about Ontario, Ontario has been an active region for us in terms of capital deployment for upgrades, upgrades. We've got 2 battery projects there. So I think, first and foremost, I would focus on our existing fleet and our positioning of that fleet, in particular, around flexible dispatchable gas in serving growing load in that market.

We continue to be very interested and keen in developing capacity in the province. So we're looking towards those policy shifts as potential. But I think as Kevin described, our $1.25 billion of adjusted EBITDA upside, part of that is reflected in what we see as a more constructive market environment in Ontario. But our fleet right now, given the capital that we've invested in operating that existing fleet expansion at East Windsor, addition of batteries at York and Goreway, I think it's really well positioned because we're through that capital investment cycle and now we get to reap the benefits of that growing market. But with respect to specific projects, today, we've got an active business development pipeline, but nothing specific identified for Ontario.

Got it. Makes sense. And maybe a quick follow-up for Kevin on the Alberta power market. So I guess with the clarity on the carbon tax now into next decade, the bridging capacity likely coming off the grid. Just curious how you're thinking about the cadence of spot prices recovering over the coming years relative to, say, where the strip is at and how that might influence your hedging strategy through the back half of the year as you look to lock in more positions from '27 to '28?

Yes. Thanks for the question, Patrick. Yes. As you know, we do have a very disciplined risk management approach that protects our IG rating. I'd say that the team has done a really good job, [indiscernible] trading team has done a really good job at opportunistically locking in some '27, '28 Alberta prices as we've seen increased optimism, let's say, in the -- more in the '28 window.

I would say at this point, we got a lot of hedging in place today as it relates to 2027 in Alberta, certainly not completely hedged, but let's just call it, a significant majority is already in place. And as I say, the team is very disciplined and sophisticated in terms of when they decide to lock in those prices. [ So 2027, ] I think we'll continue to see some weakness in '27. It's really -- we are really seeing '28 respond to the Phase 2a nicely.

And maybe, Pat, I'll just add to Kevin's comments. In terms of our approach to hedging and short, medium-term outlook, there's really no change. And I think we benefit greatly from Genesee and the sheer volume of which of the megawatts that we manage in this market and our investment-grade balance sheet. So our ability to manage short, medium term contracting and hedging around that fleet without having to pledge volumes from specific assets gives us considerable flexibility.

And as Kevin said, that's what our commercial teams in supply and trading work through quarter in, quarter out, month in, month out in terms of how to manage being long short in a given market period, given that we're inherently along the molecule and the megawatt.

And now that we've got a new set of customers, we've got more flexibility to do more contractedness, which is just a positive read-through in terms of how we manage our contractedness and reaffirm our approach to being and staying investment grade.

Our next question comes from the line of John Mould with TD Securities.

Maybe just going back to PJM and M&A, just given all the regulatory movement there, and it's not just limited to capacity procurement in the RBP, how is PJM stacking up against other markets for incremental M&A in the context of the Apollo MOU? Are you seeing better risk-adjusted opportunities elsewhere in the U.S.? Or does that ongoing regulatory uncertainty potentially create some opportunity for you?

Thanks, John. I would say I would say it's fairly balanced. What we're seeing in the marketplace is there's still -- because of the regulatory, as you call it, uncertainty or ambiguity, I think what we haven't seen is a flood of new entrants into the market.

So the buyer universe is slightly deeper. I think we're starting to see infrastructure funds and utilities play in the market. So it's deeper than it was 1.5 years ago where there was probably 6 or less players who are the active buyers of the market.

But I think just given the construct of financing and how these assets are levered, we continue to see really good opportunities in PJM. I would say the underwriting of those assets is still largely similar. And I think with the BRA construct of the cap and the floor, it limited, I would say, the run-up in valuations there. So we continue to be very interested in PJM. We continue to evaluate opportunities that's there.

We are seeing more broader interest from buyers in the other markets now as I think the broader market is shifting their focus away from PJM. But I wouldn't sit here today and say there's the opportunity set in PJM is less. I would reaffirm our interest in that market because of what we're seeing today in that market with reserve with the BRAs not clearing or continue to see the trades at the cap. And I think with success through the RBP process, we'll see some stabilization in the market over the next few years.

So I think more interest in other markets, I'd say, flat interest in PJM, but more confidence in the medium-term outlook for existing generation in PJM is how I would characterize it.

Okay. And then maybe just going back to La Paloma, I think it's your nearest term contract expiry with resource adequacy agreements gradually rolling off. It's fair to say that it's not a very transparent market. Can you provide a little more color on how your commercial efforts are advancing there either on incremental resource adequacy agreements or other contracting possibilities?

We continue to believe that La Paloma is a uniquely positioned asset and it's a critical asset for reliability in California, given where it sits on that North-South transition line in California. I can say that we're looking at multiple opportunities on how to commercialize it, whether it's RA or alternatives.

But at this moment, I can't say much more than that. But other than to say there's active conversations on multiple opportunities there. So we feel, notwithstanding the market volatility and the pressure that batteries are putting on the market overall, we still feel good about what our options and opportunity set is at La Paloma?

[Operator Instructions] Our next question comes from the line of Mark Jarvi with CIBC.

I know you didn't want to give any specific details, Avik, to Rob's question about Genesee, but just broadly with the policy clarity, Meta now making a substantial commitment in Alberta. Just how have the conversations with potential customers changed over the last handful of months? And is there an increased breadth of customer interest now in Alberta?

Thanks, Mark. What I would say is the announcement -- so I would tier those conversations. I think amongst the large players, in speaking about hyperscalers, I don't think the announcement made any difference because we've been seeing that growing interest for the last 6 months. So I think what's happening is there's more broader market recognition that this is a viable market. So I think that second tier of entrants trying to do whether it's multiclient data centers or more bespoke data centers that may not be the hyper data center size. I think -- and it's what we were talking about 2 or 3 years ago. The key was to bring in a big player to validate the market. And then we would see growth in the broader market over time.

So it's certainly been very impactful in terms of the broader universe of capacity data center providers, potential developers looking and evaluating the opportunity set because it was such a big announcement for the province in the country. But I would say amongst the hyperscalers, they were already there prior to that announcement. So it's not like the phone rang the day after the announcement, since Meta's there, we should look at it. I think they've all been moving in that direction in terms of understanding the opportunity set here. It's not one that is still today is the same as it was a year ago. Not every hyperscaler is focused on Alberta. But I think they recognize that it's a very viable market. And there's a constructive market dynamic here where the stakeholders are eager and keen to work with them, and it's one that's inviting in terms of capital investment.

And just with the progress on the testing of the MSSC limit and then Phase 2a rules, what the existing customers you've engaged with? Does it feel like a bunch of the items that need to be clarified had been clarified and you're getting closer to commercial terms on discussions?

I think what I can say, Mark, is all sides are constructive and collaborative working to find solutions to grow the industry here. And I think all of the announcements from the Alberta government with regard to Phase 2, Phase 2a bridging have been constructive and there's not one announcement that would negatively impact our Genesee site, it's probably the best way to characterize it. They're all -- all of the rules and announcements would support Genesee for being a very viable and attractive large site.

Got it. And then just on that upside from the U.S. recontracting, which is a big part of the $250 million increase on that upside. You made a comment about a greater appreciation for what the real cost of new entry is now. Would you say the conversation in the last 6 months have gotten to the point now where those customers you've engaged with and yourselves are getting closer to, I guess, consensus on what pricing needs to be for your units? And does it feel like the conversation is moving quick enough that you can move towards some contracts here in the next few quarters?

Thanks, Mark. I would actually say the following. I don't know that the gap was what the view on CONE and contract pricing was. Kevin alluded to it in his comments, the whole game has been focused on speed to power. And the matching of the regulatory changes to accelerate when a data center could connect to the grid while not compromising affordability and reliability. And then affirming the path to power, that's been more of the critical path than what the PPA price was.

I think if you talk to hyperscalers or utilities in the U.S. or those of us that are market participants, I think we would all tell you, if we could guarantee COD date, we could sign a PPA very quickly, subject to all the other stage gates having been met. But I think it's still the speed to power that's critical path.

Ladies and gentlemen, I'm showing no further questions in the queue. I would now like to turn the call back over to Roy for closing remarks.

Thank you. Since there are no more questions, we will conclude our conference call. Thank you once again for joining us today. We appreciate your interest in the Capital Power story. Today's presentation and webcast will be made available on our website. Have a great day.

You may now disconnect.

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Capital Power First Quarter 2026 Analyst Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.

At this time, I would like to turn the conference over to Mr. Roy Arthur, Vice President of Investor Relations and Investor Partnerships. Sir, please begin.

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 first quarter 2026 results, which we published earlier today. Our first quarter report and the presentation for this conference call are available on our website.

During today's call, our President and CEO, Avik Dey, will provide an update on our business. Following that, our Senior Vice President, Finance and CFO, Kevin MacIntosh, will present a review of the quarter-end financials for the company.

Avik will wrap up with a review of our 2030 strategic priorities, after which we will open the floor to questions from analysts in our interactive Q&A session.

Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analyses made by the company.

Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on Slide 4 or our filings available on SEDAR+.

In today's discussion, we will be referring to various non-GAAP financial measures and ratios, also noted on Slide 4. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore, are unlikely to be comparable to similar measures used by other enterprises.

These measures are provided to complement the GAAP measures in the analysis of the company's results from management's perspective.

Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in the MD&A prepared as of April 28 for the first quarter of 2026.

We acknowledge that Capital Power's head office in Edmonton is located within the traditional and contemporary home of many indigenous peoples of the Treaty 6 region and the Métis homeland.

We acknowledge the diverse indigenous communities that are in these areas and whose presence continues to enrich the community and our lives as we learn more about the indigenous history of the lands on which we live and work.

With that, I will hand it over to Avik.

Thank you, Roy. Our Q1 2026 results reflect the prudence of our strategy and the resilience of our portfolio even against a volatile macro backdrop.

Relentless execution is core to who we are. It's what sets the Capital Power team apart in times of uncertainty, driving durable growth. There are 3 key takeaways we want to leave you with today.

First, our business remains stable. Despite heightened macro and geopolitical uncertainty around the world, our business and strategy are unchanged here in North America, and we continue to see multiple pathways to create value.

Second, we are benefiting from diversification. Diversification across geographies or electricity markets, technologies, and markets continues to derisk our portfolio and strengthen the opportunity set we can pursue.

As we will touch on later in the presentation, we continue to see strong supply and demand fundamentals in each of the core markets where we operate.

Importantly, we also see compelling opportunities for growth across our 3 core generation technologies, natural gas, renewables, and storage.

Finally, our approach to risk and return has not changed. We remain disciplined and consistent in how we allocate capital with a clear focus on compelling risk-adjusted returns.

Our business remains resilient, and we continue to offer compelling long-term value creation supported by stable cash flows and disciplined growth.

We continue to make steady progress on our 2026 priorities and remain disciplined in our approach to value creation. Our success reflects the tireless dedication and strong execution of our team across North America.

This quarter, we're also pleased to highlight several important leadership updates that further strengthen our organization. Kevin MacIntosh, who joins me on this call, has stepped into the role of Senior Vice President, Finance and Chief Financial Officer.

In addition, Andrew Pearson, who has been an integral part of our organization since 2008, has joined the executive team as Senior Vice President, U.S. Commercial, and is based in our newly opened Washington, D.C. office.

Looking ahead, effective July 1, 2026, Steve Wollin has decided he will retire after 25 years of outstanding service and leadership. And Mike Toshima will join the executive team as Senior Vice President and Chief Commercial Officer, based in our Edmonton headquarters.

We are deeply grateful to Steve for his leadership and the lasting impact he has had on Capital Power. Together, these transitions underscore the depth of our leadership bench and our continued focus on building and sustaining a high-performing team.

For Q1 2026, performance highlights include the extension of the Arlington Valley contract through 2038, which reinforces our commercial optimization strategy, securing durable long-term contracts with investment-grade counterparties, and progressing Arlington Valley and Humle upgrades, advancing construction on 4 fully contracted projects totaling roughly 280 megawatts across Canada and the U.S., all with investment-grade counterparties.

Operationally, the team delivered another strong quarter, generating approximately 11.5 terawatt hours across the fleet. Importantly, more than half of our generation came from the U.S. portfolio, which continues to underscore the success of our diversification strategy.

Finally, our planned outages are progressing on schedule, enhancing the reliability and efficiency of our fleet. For the second consecutive year, we saw the market get off to a rocky start owing to macro disruptions, yet our strategy and our business have stayed consistent.

While oil prices and broader market volatility have increased meaningfully, natural gas prices have declined, reinforcing why gas-fired generation continues to be structurally advantaged.

Natural gas offers low-cost fuel, operational flexibility, and meaningful insulation from global disruption here in North America, which reinforces our conviction that this fuel source is pivotal to meeting long-term power demand growth and preserving affordability.

The bottom line is simple. Positive industry fundamentals remain intact for power generation, and we are staying the course in our pursuit of delivering reliable and affordable power to our customers in pursuit of creating long-term shareholder value.

Our return profile reflects a combination of contracted cash flow and merchant generation capacity. From 2021 to 2025, our contracted EBITDA grew at a compounded annual rate of approximately 18% due to a combination of acquisitions, development, and recontracting of existing assets.

The contracting successes in Ontario, MISO, and the Durzen Southwest illustrate our ability to unlock meaningful value by optimizing our existing asset base.

We continue to make tangible progress delivering the $1 billion of the embedded upside we articulated to you at our Investor Day in December.

As a result of the recent contracting agreements at NCB and Arlington Valley, we have already delivered approximately $170 million of contracted EBITDA upside with more to come.

We operate approximately 12 gigawatts across our North American portfolio, with roughly 7 gigawatts targeted for contracting or recontracting. That gives us a long and visible runway for incremental value creation from assets already in place.

As power market fundamentals continue to tighten, that optionality becomes increasingly valuable, reinforcing that contracting remains one of our most powerful levers for long-term value creation.

As we pursue further acquisitions, we will prioritize assets where our platform and expertise can unlock incremental value through commercial optimization.

While we have enhanced our diversification in recent years, Alberta remains a meaningful part of our business. It's an attractive market and presents a unique and compelling value proposition for data center investment.

We are encouraged by recent regulatory progress, including the Alberta Canada MOU, eliminating the CER for Alberta, and continued progress on the ASOS Phase 1 and 2 data center interconnection processes.

These steps improve investment certainty and support continued data center growth while maintaining affordability, reliability, and meaningful economic benefit for Alberta and Canada.

We believe Alberta has some structural advantages over other regions looking to attract large data centers. For instance, existing underutilized infrastructure includes generation, transmission, and distribution.

The nature of the Phase 1 process puts the focus on generation, but it's important not to lose sight of the transmission and distribution infrastructure.

Based on our analysis, the addition of 1.5 gigawatts of load would result in approximately $6 per month savings for the average residential customer in Alberta with existing transmission and distribution spread across more load.

In addition to efficient and reliable generation, Alberta benefits from a deep supply of low-cost fuel with forward prices trading below other major North American natural gas sales points.

Alberta also has a strong track record of load colocation with approximately 3 gigawatts, about 25% of provincial load co-located with generation. This all reinforces our enthusiasm for this industry to succeed here and create benefits for constituents.

Beyond Alberta, diversification continues to benefit our portfolio with growth coming from multiple areas. This geographic and market diversity reduces reliance on any singular regulatory or pricing environment and gives us multiple pathways to create value over time.

In PJM, energy forward prices continue to exhibit strong long-term spark spreads with greater visibility to capacity prices out to 2030. In addition, we are encouraged that the recent reliability backstop procurement proposal supports the most cost-effective new capacity, which we believe will include brownfield expansions and upgrades on existing generation.

Meanwhile, MISO continues to exhibit strong supply and demand fundamentals. From a bilateral pricing perspective, we were able to recontract MCB, the largest gas cogeneration plant in the U.S., out to 2040 at attractive pricing.

Capacity pricing in this region also continues to see significant upward pressure owing to growing demand. Q1 2026 provides a great example of the benefits of diversification in action.

Although we saw elevated gas prices and price volatility in PJM, we also saw strong contributions in Ontario and MISO, underscoring the benefits of our diverse and resilient portfolio.

In addition to geographic diversification, we continue to focus on 3 core power generation technologies, being natural gas, renewables, and storage.

In contrast to the forward outlook, historical power generation growth has been muted over the past 20 years, averaging about 0.5% per annum.

However, these 3 technologies have demonstrated significant and consistent growth well in excess of that. Over the past 20 years, natural gas-fired generation has grown steadily as aging coal units retire and rising renewable penetration has increased the need for reliable, dispatchable power.

That same push for reliability has also fueled rapid growth in utility-scale battery storage, supported by declining lithium costs and longer storage duration to better integrate intermittent renewables.

When we look forward, we continue to see opportunities across all 3 of our businesses. Natural gas, renewables, and storage each play an important role in meeting the needs of the grid as power demand continues to rise.

As we indicated at Investor Day, natural gas will play a starring role. Together, this technological mix positions us well to capture rising demand while maintaining flexibility, allowing us to respond to the needs of our customers across our markets.

Now I will hand it over to our Chief Financial Officer, Kevin MacIntosh, to provide our financial update.

Thank you, Avik, and good morning, everyone. I'm Kevin MacIntosh, and I'm pleased to join you today as Capital Power's new CFO.

We have significant opportunities ahead. And while our ambition is bold, we are starting from a position of incredible strength with a high-quality asset base and strong strategic positioning.

Before we walk through the quarter, I'd like to briefly revisit a few of the key themes outlined at Investor Day as they continue to guide how we think about risk, return, and capital allocation across the business.

Looking at the past decade, our performance demonstrates a consistent ability to deliver durable growth and strong shareholder returns. First, on returns to shareholders, we have increased our dividend for 12 consecutive years, compounding at roughly 7% annually from $1.51 per share in 2016 to $2.69 per share in 2025.

Second, dividend growth has been supported by real business growth. Adjusted EBITDA has grown at approximately 13% compounded annually, increasing from $509 million in 2016 to $1.6 billion in 2025.

This growth has been achieved within clear financial guardrails, including maintaining a 30% to 50% targeted dividend payout ratio, approximately 4x net debt to EBITDA, and a largely contracted cash flow base.

This is a track record of excellence built through dedication and discipline. I'm excited to be part of this team and build on this legacy, delivering real value for you, our shareholders.

Our balance sheet remains a core strength and is the foundation that supports fleet growth, capital deployment, and long-term value creation.

In 2026, approximately 75% of our cash flow is secured through long-term contracts or hedges, providing a high level of visibility and durability. That stable cash flow base gives us the flexibility to pursue M&A in merchant markets, grow the dividend, and ultimately deliver strong total shareholder returns.

The quality of that contracted base is equally important. Roughly 90% of our PPAs are with A-rated or higher counterparties, reinforcing revenue certainty and credit quality across the portfolio.

Our weighted average contract life has consistently remained in the 9 to 11 years range, reflecting the strong positioning of our asset base to meet customer needs.

We remain confident in our ability to execute commercial optimization, including long-term contracting throughout our portfolio.

Recent examples include the Arlington Valley and MCV contracts, both which extended contract duration on existing assets with investment-grade utility counterparties, adding long-dated higher-value cash flows and highlighting the significant embedded value across our portfolio.

Finally, our investment-grade credit ratings across S&P, Fitch, and DBRS validate our asset quality and financial strength, and provide us with efficient access to both Canadian and U.S. public debt and hybrid markets.

That low-cost access to capital enhances our ability to commercialize megawatts and finance acquisitions, supporting AFFO per share growth over time.

Now let's dive into our first quarter of 2026 results. We delivered a strong quarter, both operationally and financially, with solid execution across the portfolio and meaningful progress on continued investment in our assets in the form of sustaining capital.

Looking at the key metrics, adjusted EBITDA for the quarter was $404 million, up $37 million year-over-year due to contributions from the Hummel Station and Rolling Hills facilities acquired in 2025 and partially offset by higher corporate expenses driven by higher staffing costs due to growth in the U.S. and higher equity-based compensation due to the company's share price performance.

AFFO for the quarter was $154 million, down $64 million year-over-year, primarily due to higher sustaining capital expenditures, reflecting increased activity across the U.S. flexible generation portfolio, higher financing expense increased current income tax expense, mainly due to less tax depreciation and partially offset by the higher adjusted EBITDA, which I described earlier.

Overall, this quarter reinforces our ability to execute our strategy and maintain strong financial performance even as we proactively invest in the reliability and long-term performance of the fleet.

Based on our performance year-to-date and our outlook for the balance of the year, we are reaffirming our 2026 guidance ranges for adjusted EBITDA, AFFO, and sustaining capital.

As previously disclosed, sustaining capital expenditures in 2026 will be in the range of $290 million to $330 million. This reflects a planned maintenance cycle across the fleet, including 493 outage days and 39 planned outages.

This investment is intentional and positions the business to capitalize on strong market fundamentals long-term. Finally, this outlook supports a 2% dividend increase in 2026, subject to Board approval, consistent with the framework we outlined at Investor Day.

Overall, these guidance ranges reflect our confidence in the resilience of the portfolio, the durability of our cash flows, and our ability to generate strong financial results while continuing to invest for future growth. With that, I will hand it over to Avik for closing remarks.

Thank you, Kevin, and once again, welcome to the team. We remain confident in our ability to deliver industry-leading performance and generate superior returns for our shareholders over the long term.

As we communicated at our Investor Day, by 2030, we are targeting annual AFFO per share growth of 8% to 10%, approximately 50% growth in our U.S. total U.S. owned capacity and 13% to 15% total shareholder return.

We will also aim for 2% to 4% annual dividend growth. This combination of compelling risk-adjusted growth and yield positions Capital Power for compelling shareholder value creation.

With that, I will hand it back to Roy to close out the call.

Thanks, Avik. This concludes the formal presentation part of the call. Operator, we are now ready to take questions.

[Operator Instructions]

Our first question or comment comes from the line of Robert Hope from Scotiabank.

I want to start off on the PJM market and the reforms there. And I appreciate the commentary that you provided on the call.

So when we look at the potential reforms that are happening there, we do note that your comments regarding how it does support your asset base there.

At what point do you think there'll be enough certainty to really kickstart conversations for upgrades and further expansions of your assets there? And I guess, secondly, when you think about concentration, would you be willing to continue to add a merchant in that market?

Thanks for the question, Rob. So I think it's important to recognize when we look at the potential reforms and the announcement of the backstop option, what was concurrently announced was also an extension on the floor and cap on the BRA option.

And that was actually reaffirmed this morning in support of the FERC announcement on the approval of the extension of the BRA cap and through 29/30.

So when you step back and look at PJM and the dynamic between balancing the capacity market and the energy market, the energy market continues to be attractive, and that's reaffirmed with the DRA options being extended through 29/30. And so from an energy perspective, we look favorably upon PJM.

We'd be willing to take on more exposure there, given the specification of our portfolio and the depth of the market to be able to hedge and contract into. In terms of upgraates and upgrades and potential expansions, those conversations have not stalled because of the uncertainty around the PJM auction process.

In fact, they've accelerated. So, as you'll know, with PJM's recommendation on the proposed backstop auction, they proposed a bilateral process under which they can match load to supply in advance of that backstop auction. And that process is one that all generators are actively involved in, as are we.

So to really cut and get down to the fine point on it is we think the market is active. We continue to be bullish on it. We think there are opportunities, in particular, around the existing generation to add to the portfolio.

And I think given that we've got a strong balance sheet, we're investment grade, we're well diversified. We're well-positioned to capitalize on it.

And then maybe moving over to the recontracting initiatives. You've seen a number of successes over the last 12 to 18 months.

As you look forward to the remainder or the rest of the asset base, which does have contracts expiring in the next 5 to 7 years, how do you think about timing that?

Could you capture some upside now? Or just given that you have had some wins in the past, could you wait to better position yourself to capture upside on a longer-term basis?

Just trying to get a sense of how you're thinking about the capture of the upside now versus waiting and maybe getting a little bit more.

That is exactly the calculus we enter into on each and every plant and expiry. It's a commercial decision on what we see the supply-demand outlook versus where we see current pricing versus what we see as current C in each and every market.

So what we have done, and we will continue to do is optimize against our current outlook in the market to try and maximize NPV per kW on each and every plant.

What we are not doing is trying to schedule and cascade this to be able to hit on a consistent basis an announcement every quarter or every 2 quarters on future contracting.

We will do one at each plant as an independent decision on the maximization of NPV per kW. So with that said, we've had active dialogue going on today more than we did last year around recontracting opportunities, and we continue to advance those.

But when we announce it, you can be assured we've made the announcement that we feel best maximizes NPV.

Our next question or comment comes from the line of Nick Amicucci from Evercore ISI.

Welcome, Kevin. I look forward to working with you. Just a quick one for me, too. Avik, you mentioned just in your prior comment, the acceleration of discussions, particularly within the PJM.

Just want to get a sense, are you getting a sense that there's kind of an increased sense of urgency for large load customers to bilaterally negotiate on their own terms rather than kind of leave it to the "power tender that we're going to be exposed to?

I love that analogy, Nick. So what we are seeing is definitely increased activity in conversations.

I think if you ask any of the generators that are active in PJM, they would say we're all having more conversations. I think PJM has put forward a plan that's encouraging those bilaterals to occur in advance of that backstop auction.

But I think we need further visibility on the process. So I think we're seeing more activity, not less. And I think it's good news for everyone if we see more of these bilaterals entered into in advance of the backstop option.

The best-case scenario is that we're working down what's required for the auction because we're figuring it out ourselves.

And then I guess as we think about it, too, I mean, I think you guys are somewhat more strategically positioned just given that we had -- I guess, the administration's initial intent seems like it was directed towards new build gas gen, where now we do have the ability to have up rates and kind of more leveraging of efficiencies at existing assets. Is that a fair characterization?

Look, I think in our conversations, the administration has been clear with their objective, which is addressing the need for new capacity to address a large load while not compromising the rate payer.

And so the push from the Energy Dominance Council is consistent exactly with that. So I think we're in a position right now, which we're all encouraged to find ways to add megawatts to each of the grids in markets that we operate in, that's making the grid more reliable and more affordable to the ratepayer, while addressing the need for large loads.

I think that's why PJM has been an advocate of this bilateral process, because it's trying to facilitate load and generation to come together in it.

Our next question or comment comes from the line of Benjamin Pham from BMO.

First question, I wanted to ask on Slide 10 of the presentation on the Wild Alberta, you have a 2-gigawatt figure you've highlighted under realized infrastructure.

Are you assuming then that, that amount, 1.2 gig Phase 1, 0.8 gigawatt, you expect that not to fall under your own generation?

Thanks, Ben. I would describe it differently. I would say it's our Zoom outlook into Alberta. And when you combine the Phase 1 plus MSSP and available generation, then we think that the capacity is closer to 2.

So when Phase 1 was announced, we were consistent with that messaging as well. In our view, that number is closer to 2. And so there's that wiggle room between the 1.2 that was announced and 2, which we expect some accommodation through the Phase 2 dialogue as well.

So I would take that as a general comment on the market and our confidence around capacity being available in Alberta without compromising affordability to the rate payer.

And you also mentioned the CER and the MOU, potentially improving the data center build or supporting it. Can you clarify what you meant by that?

Yes. Look, I think the MOU is very important in terms of encouraging new build gas generation. I think our ability to take some or any merchant risk around the new build in Alberta will be predicated on our ability to operate a gas plant for the life of that asset.

So the importance of repealing CER for Alberta is critical to that. It doesn't mean we can't build gas explicitly for behind-the-fence data centers, but I think the repeal of it opens the market for broader commercial opportunities.

And I think our positioning in Alberta as one of the largest generators and with the most efficient fleet that's effectively providing baseload into the market, we're best positioned to price that marginal megawatt, contract that marginal megawatt, and provide energy services through long-term offtakes to large customers.

And maybe one more, just the last one, Alberta. You have your updated hedge for 2028, and yet I noticed that the forward curves have dropped dramatically since the last presentation you had of the quarter.

Just maybe talk about directionally your thought process with hedging a certain percentage versus leaving it open, how you think about just Alberta power prices could be going?

Yes. I think first and foremost, our commitment to our balance sheet strength and our IG credit rating is paramount, and maintaining stable cash flows for the company.

So our general approach to hedging has not changed in terms of 80, 65, 50, year 1, year 2, year 3. So that approach has not changed, and it will be consistent with that.

I think strategically, as we look at it, we do have flexibility at the enterprise level, in particular, now that we're more diversified as a company. So we will hold to that to maintain stable cash flows and maintain our approach to our balance sheet strength.

But now that we've got more exposure in more markets, and we've nearly doubled in size in terms of capacity over the last 3 years, we do have more levers to pull to take advantage of that contracted merchant exposure and how to optimize that.

So I know it's not a direct answer to your question on what and how much, but I would emphasize that fact as we think about going out in that curve, in particular, year 2, year 3 and beyond, we will stay consistent to the 80, 65-50, but the constitution of what we're hedging where we've got flexibility to optimize given our merchant exposure effectively in PJM, Alberta and CIO.

Our next question or comment comes from the line of Maurice Choy from RBC Capital Markets.

Just following up on the last question, notwithstanding all the regulatory progress and the structural advantage of Alberta, obviously, the 2028 onwards forward is still only a touch higher than the current year, being about high 50s, low 60s.

So maybe just focusing on the power price alone and not hedges, like how would you characterize these forwards? And directionally, what do you think the market is missing?

Thanks, Maurice. We had an interesting look back on this one.

And if you looked at historically, 2018 or 2020, looking forward into 2023, in the forecast or the forward strip in Alberta, we saw a similar dynamic at play, which is given the lack of liquidity in the back end of the curve and the structural configuration of the market here, the market where you've got steepness of slope in the curve, there isn't the motivation or incentive to lock in at the back end of the curve when you have steeper contango in that curve.

And so it's not that the market doesn't understand it. Given the lack of liquidity, there is no incentive to transact. So we continue to rely on the fundamentals in our outlook on pricing.

And I would say where you've got the steepness of contango today, what's missing is the understanding of the tightening supply, the tightening of the supply-demand gap here over the next 3 years, and it's underestimating what the future spot price will be.

So I can't tell you, Maurice, whether we are going to be at $80 or $90 in Q1 2028. But I can tell you with a high degree of confidence, we see a tightening market here and a return to higher pricing over that 3-year period of time.

And to Ben's question before, that's what we're thinking about in terms of medium to long-term hedging and contracting in Alberta. We really like the exposure we have.

We think the upside is asymmetric to the upside. In particular, as we look out at potential new builds in the market and data center load coming in, and continued economic growth in Alberta, which, relative to the rest of the country, is running well ahead.

Just as a quick follow-up to that. When you think about the supply and demand dynamics that drive the timing of this potential spike, maybe supply doesn't come any earlier, but any thoughts on where the demand arrives a little later?

Sorry, I don't understand the question. Maybe you could repeat that, Maurice.

So obviously, Phase 1 anticipates the demand arriving, call it '27, '28, and then maybe the supply to support that new supply that comes closer to the start of the next decade.

If you start seeing demand arriving a little bit later, then perhaps you don't see the spike in price, perhaps later in the decade than '28.

Yes, it's an interesting point. And if you look at the existing market structure and how the marginal electron is priced. And by the way, there's a similar dynamic at play in PJM, where you had a 2-year BRA auction.

Historically, that was enough to incentivize generators to go into new build because the cycle of the consecutive DRA auctions allows you enough visibility to FID build in 2 to 3 years and then play into that market dynamic.

In Alberta, the dynamic is similar, but there's no capacity payment to incentivize new builds. So historically, the merchant market responded to higher pricing, but we had 2- to 3-year cycle times between FID and COD.

And so today, where that cycle time is 4 to 5 years, and the cost of new build is 2 to 3x what it was 5 years ago, I don't think the response time or the elasticity of supply matching demand is the same as it once was.

So I think what that means for your question is that the matching of new load to new supply, you and I will all have much more visibility on in the marketplace.

So if prices run in Alberta in this merchant market, the probability of seeing new merchant capacity coming in and coming online and dampening the back end of the curve in the back end, I mean, year 2, year 3, year 4, we don't see as viable as it once was just because lead time, supply chain, construction times are much longer for new build.

So the resilience of this market from a pricing perspective is looking actually pretty favorable for us.

If I can just finish off with a broader Canadian question. Yesterday, we saw the federal government unveil a number of pillars for its forthcoming national AI strategy.

Just wondering what your first takeaways are of this framework. And in particular, whether any difference to the Alberta government's approach may mean better opportunities for Capital Power outside of Alberta?

Well, to talk about my own book here, Maurice, we continue to believe Genesee is one of the most attractive sites to host a data center in North America.

Now we're in the business of selling power. So it's not incumbent upon us to do it at the site, but the opportunity exists there. I do believe there's strong alignment between the province of Alberta and the Feds around facilitating investment in AI, creating a sovereign data strategy for Canada.

And I think we can play a part in that. And I think the federal government's push to facilitate capital investment and expedite the approval process is all in favor of that.

I think the good news in Alberta is that the train has already left the station in terms of Alberta's support of data center capacity, Phase 1 going into Phase 2.

But I think any further alignment between federal support for sovereign data centers and Alberta's continued welcoming of that industry without compromising reliability for consumers is moving in that direction.

So I think yesterday was a positive in that regard. I think the next step, though, is how do we move that into we need 250 megawatts or 500 megawatts, and we need a COD by date. And I think those are conversations all of us are part of.

And my congratulations to Kevin, Andrew, and Mike for the appointments, and best of luck to Steve for his upcoming retirement.

[Operator Instructions]

Our next question or comment comes from the line of Patrick Kenny from NBCM.

Just on the East-West transmission build-out discussion these days for national security. I was just wondering, as an incumbent IPP here in Alberta, what you see as some of the major benefits or drawbacks to expanding Intertide capacity and how you might be positioning the company to either capitalize on these market opportunities or mitigate risks associated with more interties down the road, whether it be east-west or North-South?

Pat, thanks for the question. Look, I think from an intertie question, to the extent it's a national security issue and there's support for it amongst provinces, we are and will continue to be an active player in the conversation.

But an islanded power market is facilitated by a baseload that's supported by rate payers for transmission and distribution, but it's also supported by generators through private investment.

And so how that works in a market with interties where you've got different constituents, I think, is an important consideration because you don't want to undermine any of the existing market structures that exist that support the build-out and ownership of that infrastructure.

So if one province is funded through a crown, all by ratepayers, and the other market is supported by private industry and ratepayers for transmission and distribution, you've got to find an equitable way to manage that on behalf of both markets because you can't compromise the market structure in one versus the other.

So I don't look at the Intersight conversation as a threat. I think more infrastructure that connects the country and provides better reliability and affordability for customers, and encourages new infrastructure build and new industrial productive capacity.

Those are exactly the conversations we should be having as businesses across the country. But we've got to work through the details to understand how it impacts each individual jurisdiction and how it ultimately benefits the whole.

So it's something that we're actively in conversations around. We're having input on those conversations. But in itself, I don't see it as a threat because I think ultimately, if it does go through. And I think the economics of it are very, very tough.

I'll remind our countries have over 40 million people, just over $2 trillion of annual GDP, and that GDP is half the size of California.

So to be able to invest in such a significant amount of infrastructure where you've got relatively small markets, province to province, trying to connect with coasts where a lot of the economic activity occurs, the intertiein itself may not be a great value proposition for the ratepayer.

And we just have to understand how all that will work.

And then maybe just a housekeeping question here on your recontracting outlook. I know it's a relatively small part of the portfolio, but given the contract is expiring in 6 months or so, I believe, any update on extending the island generation facility with BC Hydro, or I guess, how you might be looking to monetize or maximize the value of the asset if recontracting doesn't work out?

We are looking at a number of alternatives for island generation, but we don't have an update on that at this point. And I would note your comment, it's relatively small in terms of our overall portfolio and contribution.

Our next question or comment comes from the line of John Mould from TD Cowen.

Maybe just starting with Genesee and the 466-megawatt grid export cap from the MSSC. You did some testing above 466 megawatts earlier this year and also in 2025.

Can you give us an update on how this initiative is going and when you think you might reach the milestone of being able to export 100 or 200 megawatts above that 466 megawatts into the grid?

Yes. Thanks for the question, John. We continue to be in the process of testing on that. As you noted, we've had preliminary tests, and it's an active program that we are working on in partnership with the ISO to advance approval of.

We remain confident in getting additional megawatts online, and we hope to provide a further update as testing continues through the year. But I don't have a specific update on when and how much, other than we hope to have an update on that through this year.

But the initial testing is moving forward and advancing in a favorable way, but we've got work to do, and we're working in partnership with the ISO on that.

Okay. And then just a bigger picture question on organic development, either renewables or gas and storage, most of your development pipeline will be complete by the end of this year.

I think you just got one project due online early in 2027. So what kind of opportunities are you seeing to backfill that organic pipeline? And how do the potential returns compare with what you see in M&A markets right now?

I think we continue to be bullish on the opportunity to develop. I think as we came out from under the repowering project, which was our largest CapEx project we've ever undertaken as a company at Genesee, our focus shifted towards our renewable development.

And as we've expanded and grown the company, I think we see a very compelling opportunity to develop around development. I think the best example of that is the backstop auction in terms of what we're starting to see in the market.

We're starting to see longer-term PPAs associated with data centers and/or load serving entities looking to secure long-term supply.

So at our Investor Day, we said we've got about 1 gigawatt of development pipeline for our company. And I would say, in earnest, we're really focusing on trying to grow that pipeline this year going forward.

So I would expect that that's going to be a growing focus for us. In terms of relative returns to acquiring, I think it's a trade-off of duration and tail and contractedness versus short-term realizing of short-term pricing. And the reality is, we have to have a balance of both.

But I think what we're seeing in greenfield development is commensurate with us delivering 13% to 15% shareholder returns over time. So we think our cost of capital is competitive.

We think there are a number of opportunities, and all 3 actually renewable storage as well as gas, and we're trying to ramp up our origination efforts and build that pipeline. So that's a key focus for us now, given where we are as a company.

Our next question or comment comes from the line of Mark Jarvi from CIBC.

To the conversation about the 2 gigawatt view you guys have for Alberta versus the 1.2 in Phase 1.

Just curious when you think you'll get some clarity on that in Phase 2a. We've seen some working documents from the ASO. And just your view on the 400 megawatts of Genesee being deemed potentially net new megawatts?

I think our dialogue has been constructive and collaborative on that front on Phase 2. We don't have a defined view on timing other than what the ISO has announced in terms of directional timing.

But in terms of unlocking our megawatts over and above 466, our expectation is that it would be considered net new megawatts. And we believe the dialogue is consistent with that.

So I think everyone -- I think one of the reasons we're so bullish on Alberta and on data centers relative to other markets is Alberta is one of the only jurisdictions right now.

And at a high level, we may not have agreed on all the different pieces of how we're executing it. But at a high level, there's alignment between government, regulator, and industry on how to build and bring in new load into this market structure.

Okay. And then you obviously got the MOU out there for Genesee. Are there any other conversations you're having with data center customers around something else for Genesee, whether it's just offtake or colocation?

Has anything changed in the last couple of months?

So we have multiple conversations ongoing in Alberta around whether it's offtake or colocation of data centers. That actually hasn't changed in the last 1.5 years, and they continue to be active conversations, not just passing ones.

So yes, we continue to be just as bullish as we were on the opportunity set, and we're actively working it.

And with the VB with some clarity on Phase 2, CER, and the Upper MOU being finalized, can those conversations move to the next phase?

Yes. I think if you're looking at stage gates, I would say those are 2 critical stage gates. So, we've been in a position to move quickly at Genesee for 1.5 years. So our ability, we've done the work. We have a site. We know what a site plan looks like.

And we continue to be, I think, in an enviable position to contract with anyone who wants to secure long-term energy here in Alberta on any project that they're pursuing, whether it's on our site or otherwise.

So for us, it's similar to the conversation we were having on recontracting. In many ways, the arithmetic and the evaluation of how to maximize net present value per KW at the Genesee site, we're balancing everything there, which is we see a tightening market, we see a favorable energy market forming in '28 to '30.

We've got expansion capacity at the site. We've got unlocked megawatts. And it's just balancing whether we use those megawatts to support a 10-plus year offtake with someone else on someone else's site, or someone looking for long-term supply, or we use some of those unused megawatts for someone who's co-locating.

So I really like our positioning in Alberta right now. I think we're in a very good position on Genesee, where we've got multiple levers to play, and we've got the flexibility to play them.

Then maybe last question, just how would you rank or compare the confidence level or probability of the MOUs for the data centers at Genesee versus Midland today turning into a definitive contract?

Do they feel like they're on similar paths and probability? Or one feel you have a higher confidence that this is going to progress to a final contract?

Well, I would answer it differently. I would say what's our probability of contracting and maximizing the value of megawatt at either plant, I would say, very, very high.

So on MCV versus Genesee, MCV, we're advancing. I'd say there's high confidence we're going to contract those megawatts. We're advancing the MOU on the data center, but we've got uncontracted capacity that will ultimately optimize.

So that's advancing, and we continue to advance Alberta. I would note that we started the NCV process well over a year after we started looking at Genesee as a site.

So MCV has greatly benefited from all of the learnings we've had at Genesee and in Alberta, and we've actually come up from behind very quickly at NCV, our team, in terms of working with potential customers there.

So I think for us, that's one of our advantages. We've been at this since '23 on multiple sites across North America. And we've been talking to all of the customers around what their site requirements are, what the ramp schedules are, what the reliability needs are, and even what their site configurations and power solutions they require.

So we feel pretty good about how we can serve the ultimate customer here.

I'm showing no additional questions in the queue at this time. I'd like to turn the conference back over to Mr. Roy Arthur for any closing remarks.

Thank you, operator. If there are no more questions, we will conclude our conference call.

Thank you once again for joining us and for your continued interest in Capital Power. Today's presentation and webcast will be made available on our website. Have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may now disconnect. Everyone, have a wonderful day.

Hello, and welcome to the Annual Meeting of Shareholders of Capital Power Corporation. Please note that today's meeting is being recorded.

If you participate in today's meeting and disclose personal information, you will be deemed to consent to the recording, transfer and use of same. If you disclose personal information of another person in today's meeting, you will be deemed to represent and warrant to Computershare and the company that you first obtained all required consents for the disclosure, recording, transfer and use of such personal information from all appropriate person before your disclosure.

It is now my pleasure to turn today's meeting over to the Chair of the meeting, Jill Gardiner. The floor is yours.

Good afternoon. It is just after 1:00, so I'll ask that the meeting come to order. My name is Jill Gardiner, and I am the Chair of the Board of Capital Power Corporation. In accordance with the company's bylaws, I'm pleased to act as Chair for this meeting. In the spirit of reconciliation, Capital Power respectfully acknowledges that we operate within the ancestral homelands, traditional and treaty territories of the Indigenous peoples of Turtle Island or North America.

Capital Power's head office is located within the traditional and contemporary home of many Indigenous peoples of the Treaty 6 territory and Métis Homeland. We acknowledge the diverse indigenous communities that are located in these areas and whose presence continues to enrich the community.

With me today are Avik Dey, President and Chief Executive Officer; Pauline McLean, Senior Vice President, External Relations, Chief Legal Officer and Corporate Secretary; and Roy Arthur, Vice President, Investor Relations and investment partnerships.

To ensure a smooth flow of the business matters we will be dealing with today, Avik Dey and Pauline McLean will move and second formal motions. They will be called upon as needed. To clarify, this procedure is not an attempt to discourage participation, but merely to expedite proceedings in a virtual environment. Unless a different proxy holder has been indicated on management proxies, Avik Dey will act as proxy holder for such proxies.

We are using a virtual-only format for this meeting. As noted in our management proxy circular dated March 13, 2026, shareholders can vote by proxy or can vote virtually during the meeting. Any questions pertaining to the business of the meeting will be addressed at the appropriate time.

Following the meeting, an archived recording of the meeting will be made available on Capital Power's website. There will be no corporate presentation. However, after the termination of the formal portion of the meeting, we will hold a question-and-answer session during which the CEO, the Chief Legal Officer and the Vice President, Investor Relations and investment partnerships will be available to answer any questions from shareholders and duly appointed proxy holders that relate to the business of the company.

If you experience any technical difficulties during the meeting, please contact Computershare by calling 1 (888) 724-2416 or if international, +1 (781) 575-2748.

Computershare Trust Company of Canada is the company's registrar and transfer agent for its common shares. Today, Stephanie Tuss of Computershare has been appointed to act as scrutineer. In accordance with the company's bylaws, Pauline McLean will act as Secretary of the meeting. Stephanie Tuss will report on the shareholders present virtually or by proxy and compute the votes on any polls taken. We will conduct votes on the items of business by electronic balloting.

Most registered shareholders have already voted by proxy. However, for those of you who did not vote in advance by proxy and need to vote today, we will conduct a vote on each motion during the meeting. We will let you know when the electronic balloting opens. To vote, simply click on the Vote tab on the right side of your screen, at which point the resolutions and voting options will appear. If you previously provided a proxy, you should not vote by electronic ballot today unless you wish to change your vote.

Close the voting and tabulate the ballots after all matters have been put forward and discussed so that the meeting is not paused at each matter for the scrutineer to calculate preliminary results. If you have a question on any of the matters of business to be addressed at this meeting, please submit your question now using the Q&A tab on the virtual interface. Please do not wait for the matter to be open for discussion.

At this time, we want to thank all of you who submitted proxies in advance and remind you that only registered shareholders or duly appointed proxy holders may participate and ask questions during the meeting.

Under the notice and access system for communicating with shareholders, the company mailed a notice of meeting with a form of proxy or a voting instruction form commencing on March 24, 2026. The notice informs shareholders about the time and place of our meeting, the business of the meeting and stated management proxy circular was posted on our website at www.capitalpower.com/AGM as well as on SEDAR+. The notice also stated that any shareholder could request a printed copy of the management proxy circular in advance of today's meeting. The Secretary of the meeting has provided me with an affidavit of mailing prepared by Computershare Trust Company of Canada. She will see that this affidavit is filed with the minutes of this meeting.

The Secretary of the meeting has received the report of the scrutineer and advises me that there is a quorum present. On the basis of this report, I declare that the meeting has been regularly called and properly constituted for the transaction of business.

The Secretary of the meeting will also file the report of the scrutineer with the minutes of this meeting. I request that the scrutineer launched the electronic ballots to the registered holders of common shares and duly appointed proxy holders.

The polls are now open, and at this point, all registered shareholders and duly appointed proxy holders who have properly logged in with their control numbers and wish to vote will be able to see on the screen all motions being brought forward at this meeting. If you have already registered your vote in one of the manners specified in the management information circular, you do not need to vote by electronic ballot at this meeting unless you wish to change your vote.

The next item of business is the presentation to the meeting of the consolidated financial statements of Capital Power for the year ended December 31, 2025, and the report of the auditor thereon. The integrated annual report of the company, which contains the consolidated financial statements, together with the report of the auditor thereon, and the company's business report was mailed to each shareholder who requested a copy. The integrated annual report is also available on the company's website and on SEDAR+.

On behalf of the directors, I now place before the meeting the consolidated financial statements and auditor's report thereon for the year ended December 31, 2025. Are there any questions on the consolidated financial statements?

Chair, there are no questions at this time.

Thank you. As there are no questions, I declare that the consolidated financial statements and the auditor's report have been received.

The next item of business is the election of directors. In accordance with the bylaws of the company and pursuant to a resolution of the Board of Directors, a total of 10 directors will be elected at today's meeting by the holders of common shares. Information regarding the nominees being proposed for election is set out in the management proxy circular.

As of 1:00 p.m. Friday, April 24, 2026, which was the deadline for the receipt of proxies, management had received proxies for 79,658,970 common shares within excess of 98.7% of shares represented by proxy voting in favor of each of management's nominees to the Board of Directors named in the management proxy circular. We will now proceed with the nomination and election of the 10 directors to be elected by holders of common shares. Only registered holders of common shares or their duly appointed proxy holders are entitled to nominate and vote for the election of these directors.

Avik Dey, may I ask you for a nomination of each of the 10 directors to be elected by holders of common shares?

Chair, on behalf of the Board of Directors, I nominate each of the following 10 persons as named in the management proxy circular for election as directors to hold office until the close of the next annual meeting, until their successors are duly elected or appointed: Jill Gardiner, Gary Bosgoed, Avik Dey, Carolyn Graham, Kelly Huntington, Barry Perry, Jane Peverett, Neil Smith, Keith Trent and George Williams.

Thank you, Avik. Pauline McLean, would you please second the nominations?

Chair, I second the nominations.

Thank you, Pauline. In the absence of the receipt of notice of any further nominations in accordance with bylaw #3 of the company, I declare the nominations closed.

Have we received any questions on this matter?

Chair, there are no questions at this time.

Thank you. As there are no questions received, we will now proceed with the election of the nominated directors. The election of directors will proceed by way of electronic ballot. Votes will be cast in favor of or against each nominated director individually. The votes cast in favor of the election of a director nominee must represent a majority of the common shares voted at the meeting. If the number of shares voted against equals or exceeds the number of shares voted in favor of the director, then the director shall not be elected. In the event that an incumbent director nominee is not elected, they may be permitted to remain as a director until the earlier of 90 days after the date of the election or the date on which their successor is elected or appointed.

Only registered holders of common shares or their duly appointed proxy holders are entitled to vote on the election of these director nominees. Any shareholders present virtually may have already filed their proxies. Unless they wish to withdraw their proxy, these shareholders should not complete the electronic ballot and their shares will be voted in accordance with the instructions contained in the proxies granted to their proxy holders. If you have not already submitted a proxy, please mark your electronic ballots in the vote tab. To cast your vote, select for or against. We will pause to give you time to vote.

[Voting]

The scrutineer will review the electronic ballots and prepare the final scrutineer's report reflecting the results of the proxies and ballots. A report on the voting results will be filed on SEDAR+ after the meeting. In addition, we will publish the results of this matter in next year's management proxy circular.

Next on the agenda is the appointment of the auditor. Management has received proxies representing 79,658,970 common shares within excess of 99.72% of shares represented by proxy voting in favor of the auditors named in the management proxy circular. Pauline McLean, may I have a motion to appoint the auditor of the company?

Chair, I move that KPMG LLP Chartered Accountants, be appointed auditor of the company to hold office until the close of the next Annual Meeting of Shareholders with compensation to be fixed by the Board on the recommendation of the Audit Committee.

Thank you, Pauline. Avik De, will you second the motion?

Chair, I second the motion.

Thank you, Avik. Have we received any questions on this matter?

Chair, there are no questions at this time.

Thank you. As no questions have been submitted on this matter, we will now proceed with the vote. If you have not already submitted a proxy, please mark your electronic ballot. Cast your vote, click for or withhold. We will pause to enable voting.

[Voting]

Next on the agenda is the advisory vote on executive compensation, also known as the shareholder say on pay. Capital Power Corporation conducts an annual advisory shareholder say on pay vote. Management has received proxies representing 79,658,970 common shares within excess of 98.2% of the shares represented by proxy voting in favor of the advisory vote on executive compensation. As Capital Power's approach to executive compensation has been disclosed in the management proxy circular, I do not propose to reiterate the details now. Avik Dey, may I have a motion regarding this matter?

Chair, I move that it be resolved on an advisory basis and not to diminish the role and responsibilities of the Board of Directors that the shareholders accept the approach to executive compensation disclosed in Capital Power's management proxy circular delivered before its 2026 Annual Meeting of Shareholders.

Thank you, Avik. Pauline McLean, will you second the motion?

Chair, I second the motion.

Thank you, Pauline. Have we received any questions on this matter?

Chair, there are no questions at this time.

Thank you. As no questions have been submitted on this matter, we will now proceed with the vote. If you have not already submitted a proxy, please mark your electronic ballot. To cast your vote, click for or against. We will pause to give you time to vote.

[Voting]

That now completes the formal business of the meeting. Accordingly, the electronic balloting will close in 30 seconds. Once the polls close, the voting page will disappear and your votes will automatically be submitted.

[Voting]

The polls are now closed. I request that the scrutineer review the electronic ballots and tabulate the votes.

I will now declare the preliminary results of voting. A report on the final voting results will be filed on SEDAR+ after the meeting.

With respect to the election of directors, each nominee has received a majority of the votes cast at this meeting. Accordingly, I declare that each nominee is duly elected as director of the company to hold office until the close of the next Annual Meeting of Shareholders or until their successors are elected or appointed.

On the matter of appointment of an auditor, I declare that the motion is carried and KPMG LLP is appointed auditor of the company to hold office until the close of the next Annual Meeting of Shareholders.

On the matter of the advisory vote on executive compensation, I declare that the motion is carried.

Unless there are any questions from shareholders or their duly appointed proxy holders, that now concludes the formal business of the meeting.

Chair, I move that the formal portion of the meeting be terminated.

Thank you, Avik. Pauline McLean, will you please second the motion?

Chair, I second the motion.

Thank you, Pauline. The motion is carried, and I declare the formal portion of today's meeting terminated.

We will now address questions relating to the business of the corporation with responses from the CEO, the Chief Legal Officer and the Vice President, Investor Relations and investment partnerships. To ask a question, please type it into the Q&A tab virtual interface. We will address as many questions as time permits. Thank you for your participation.

Chair, there is a question. [indiscernible] Sadana is asking a question on behalf of shares Canadian Institutional Investor Clients. In its 2025 integrated annual report, Capital Power acknowledges that climate change, along with reliability and affordability will continue to be primary themes driving the industry, and physical risks can disrupt operations and supply chains and affect reliability and market prices. [indiscernible] this out of 17 of your's self-identified peers, Capital Power is 1 of only 3 companies with no emissions reduction targets.

Thank you for your staff agreeing to meet with us following the AGM. My question today for the Board is directed to the Chair of the HS&E Committee, Gary Bosgoed. Other power producer peers face the same demand growth yet maintain net zero emission commitments while expanding. Why is Capital Power's situation unique and not compatible with emissions reduction targets? When you retired your previous targets, what analysis did the Board review to confirm all risks are being evaluated and managed?

Thank you, Roy. As this question does not pertain to the business of the meeting, Avik Dey, President and CEO, will respond. I would point out that our HS&E Chair, Gary Bosgoed, has reviewed and agrees with management's response to the question.

Capital Power is working to meet the growing demand for reliable and affordable power while tackling the urgent challenge of climate change by delivering grid-critical capacity, pursuing lower carbon power solutions and making strategic investments to optimize our existing power generation assets. Management works closely with the Capital Power Board who provides ongoing oversight and leadership to the executive team on climate and ESG-related matters. The Board also has an ongoing role in the development and approval of Capital Power strategy. When management reassessed our targets in late 2024, in light of our evolving strategy, we conducted a thorough review of our pathway to net zero by 2045. The pathway in our targets reflected the information and assumptions available at the time they were set. However, subsequent events, including shifts in market conditions, technology and the broader regulatory landscape required us to reassess the feasibility of the target. Based on the ambitious nature of the target and the timing within which it would need to be delivered, we determined this was not something we could commit to.

The carbon capture and storage project at Genesee formed a critical component of meeting our net zero target. And the cancellation of this project factored prominently into our decision to retire both our interim and net zero targets. Capital Power continues to believe in the technical viability of carbon capture technology. However, the Genesee project was discontinued due to lack of economic feasibility at the time.

With that said, Capital Power is well positioned to continue supporting the lower carbon transition. Projects that demonstrate our ongoing commitment to decarbonization include completion of the Genesee repowering in 2024, reducing Scope 1 CO2 emissions by 3.4 MT annually, getting Capital Power and Alberta off coal, development of approximately 1.5 gigawatts of renewable capacity across Canada and the U.S. with approximately 180 megawatts currently under construction.

Successful completion of 170 megawatts of utility scale battery storage to enhance grid reliability in Ontario, continued partnership with Ontario Power Generation to explore small modular nuclear reactors in Alberta and evaluation of carbon capture and storage opportunities beyond Alberta, including in Michigan and California.

Capital Power remains committed to responsible emissions management, balanced with reliability and affordability.

Thank you, Avik. We received any other questions?

Chair, there are no questions.

Okay. All questions asked and answered during the meeting will be posted to our website following the meeting. We have now completed the meeting for today.

You may now disconnect.

Good day, and thank you for standing by. Welcome to Capital Power's Fourth Quarter and Year-end 2025 Results Conference Call. [Operator Instructions]. Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Roy Arthur at Capital Power, you may begin.

Good morning, everyone. My name is Roy Arthur, Vice President, Investor Relations and investment partnerships. Thank you for joining us today to review Capital Power's fourth quarter and year-end 2025 results, which we published earlier today. Our integrated annual report and presentation for this conference call are available on our website. During today's call, our President and CEO, Avik Dey, will provide an update on our business. Following that, Scott Manson, our Interim CFO, will present a review of the quarter and our year-end financials for the company. Avik will then conclude the formal part of the presentation before we open the floor to questions from analysts in our interactive Q&A.

In the spirit of reconciliation, Capital Power perspectively acknowledges that we operate within the ancestral home lands, traditional and treaty territories of the indigenous people of Turtle Island or North America. We acknowledge the diverse indigenous communities located in these areas and whose presence continues to enrich the community.

Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information or our regulatory filings on SEDAR+.

In today's discussion, we will be referring to various non-GAAP financial measures and ratios also noted on the same slide. These measures are not defined financial measures according to GAAP and do not have standardized meaning prescribed by GAAP, and therefore, are unlikely to be comparable to other similar measures used in other enterprises. These measures are provided to complement the GAAP measures that are included in the analysis of the company's results from management's perspective. The reconciliations of these non-GAAP measures to their nearest GAAP measures can be found in our integrated annual report.

With that, I will hand it over to Avik.

Thank you, Roy. Good morning, everyone, and thank you for joining us. Relentless execution is core to who we are. It's what sets the Capital Power team apart and underpins our ability to deliver on our strategic priorities with excellence as we did in 2025 and sets us up for continued success in 2026 and beyond. With precision and passion, our team has executed on our strategic priorities. We have acquired 2.2 gigawatts of generation capacity through our PJM acquisition. We've optimized contracts across 2 gigawatts of contracted capacity, upgraded and expanded 385 megawatts across our fleet, extending asset life and maximizing value and advanced or completed 300 megawatts of new capacity, growing our renewable power portfolio, acquire, optimize develop. These are the pathways by which we create value.

Our strategy is straightforward, but how we execute is our competitive advantage. 2025 was an exceptional year for Capital Power. Our results perfectly highlight our strategy in action. Deliberate growth and durable performance driving superior returns. In addition to the strategic wins I just highlighted, our operations team also delivered with excellence in 2025. Specifically, we generated a record 45 terawatt hours of power across our portfolio, with 52% of total generation coming from our U.S. portfolio, underscoring the successful strategic diversification of our generation portfolio. These achievements are driven by our people. The dedicated experts, innovators and professionals who are passionately powering North America 24/7, 365.

Our 2025 performance demonstrates our team's ability to consistently deliver, diversify our portfolio and relentlessly execute to drive long-term shareholder value. At our 2025 Investor Day, we outlined our disciplined approach to value creation through growth and clearly defined optimization pathways. When we acquire assets, we take a strategic approach to value creation. We systematically add value through three optimization pathways.

First, we focus on operating and optimizing the assets themselves, driving reliability, availability and performance across the fleet. Second, we enhance value commercially through contracting and hedging using our market expertise to improve cash flow, visibility and risk-adjusted returns. And third, we create value at the enterprise level leveraging our differentiated funding model to lower our cost of capital and improve overall returns. Together, these three pillars enable us to consistently unlock value beyond the initial acquisition, positioning us to meet or exceed our return target of 13% to 15%.

Our 2025 performance is a clear example of this strategy in action. As we look to build on our performance in 2026, our approach to growth through acquisitions remains purpose-driven. We acquire assets in high demand markets that enhance our strategic position and diversify our portfolio. Why does that matter? By buying the right assets, we are increasing our scale, allowing us to optimize a large complementary flexible generation fleet diversing our footprint, increasing our exposure to multifaceted demand growth across North America. And finally, enhancing fleet efficiency, lowering the age and heat rates of our assets positions us to create value on a merchant basis and for long-term contracts.

The operation, optimization and integration of our PJM assets demonstrate another clear example of our disciplined growth and ability to execute. In the first two quarters under Capital Power ownership, the Hummel and Rolling Hills facilities delivered strong adjusted EBITDA contribution, performing ahead of expectations with higher dispatch and strong pricing. That transaction increased diversification of our cash flows and lowered market-specific risks, with no single market representing more than 30% of our total flexible generation capacity. At the fleet level, we continue to apply our industry-leading expertise to optimize our assets. Asset optimization is core to Capital Power's DNA we deliberately acquire assets with strong optimization potential and apply disciplined operating maintenance and risk management practices to deliver reliable megawatts and enhance value.

We have added or are in the process of adding 385 megawatts to our fleet from asset optimization, including 170 megawatts through our two battery energy storage facilities in Ontario. 110 megawatts in capacity upgrades across three facilities, York, Goreway and Arlington Valley, and advanced 105 megawatts in expansion capacity at East Windsor. As we continue to grow through acquisition, this sets us apart from other buyers in the market, enabling us to identify and deliver values others cannot. It's our competitive advantage compared to other IPPs. The returns associated with optimizing existing capacity are strong and reinforce our focus on existing generation as a way to address society's need for more power.

At a portfolio level, our approach to commercial optimization is fundamental to driving incremental value. We have been very deliberate in constructing a portfolio of assets in regions with strong supply-demand fundamentals. In the regions where we operate, we see customers looking to contract supply much earlier than in the past, owing to growing demand. These discussions are anchored in cost of replacement rather than recovery of costs as they have been in the past. As a result, Capital Power's contracted portfolio is poised to see significant growth in contracted EBITDA through recontracting, enhancing margins, reducing volatility and improving returns for longer duration.

Our new contract for MCV announced last fall is a prime example of the strategy in action extending in 2040, this new long-term contract provided 10 years of incremental contracted cash flow. The contract is expected to generate a full year increase in adjusted EBITDA for the facility of approximately $100 million annually, representing an 85% increase over current contract pricing for the whole facility. To kick off 2026, we also completed the recontracting of Arlington Valley. The extension of the summer tolling agreement through 2038 secures 13 years of contracted revenue includes a 35-megawatt up rate and reset pricing at 140% above the existing contract, positioning us for continued growth and value creation in the U.S. Southwest.

Commercial optimization is about maximizing the value of our capacity with a continued focus on contracting longer duration at better pricing. Our North American portfolio includes 12 gigawatts of total capacity with 4.8 gigawatts long-term contracted between 2032 and 2047, 2.4 gigawatts medium-term contracts expiring in the '26 to '31 window and 4.8 gigawatts of merchant primarily in Alberta and PJM. Looking forward, our focus is the merchant and medium-term portfolio where we can extend duration when pricing is attractive. As always, we will continue to hedge our merchant generation to manage risk near term, but preserve the ability to realize long-term upside.

I'll now hand it over to Scott to discuss the enterprise optimization and financial performance.

Thanks, Avik. Our proven return-driven model forms the foundation of how we optimize at an enterprise level. It underpins all that we do, improving efficiency and strengthening organizational resilience. We are focused on maintaining our investment-grade balance sheet, which enables us to acquire high-value assets, secure low-cost capital and become the counterparty of choice for utilities and other high credit quality counterparties, driving a clear competitive advantage and stronger returns. Disciplined capital allocation, allowing us to offer a rise on dividend while most of our cash flow will be reinvested to fund our strategic fleet expansion.

Enhancing our differentiated funding model positions us to accelerate our growth pathways through partnerships like our MOU with Apollo. Enterprise optimization creates resilient, long-term shareholder value. It drives cost discipline, process improvements and enables disciplined growth without proportional increases in overhead. Our full year 2025 results reflect the execution we outlined throughout the year and underscores the strength of our increasingly diversified portfolio.

We delivered adjusted EBITDA of $1.58 billion, an increase of $237 million or 18% compared to 2024, and AFFO of $1.07 billion, up $242 million or 29% year-over-year. The increase in adjusted EBITDA was driven primarily by higher contributions from our U.S. flexible generation segment, reflecting the acquisition of Hummel and Rolling Hills in June 2025 and the full year contribution from La Paloma and Harquahala, which were acquired in February 2024. Results were further supported by lower emission costs in Canada following the repowering of Genesee in late 2024 and lower corporate expenses following the 2024 reorganization. These gains were partially offset by lower contributions from our Canadian Renewables segment following the sell-down transaction we executed in December 2024.

The AFFO increase reflects higher EBITDA and lower current income tax expense, partially offset by higher finance expense associated with increased borrowings to fund growth. While net income for the year was lower than 2024, this primarily reflects noncash items, including unfavorable changes in unrealized fair value adjustments on commodity derivatives and emission credits, higher depreciation and amortization related to assets acquired or placed into service and the absence of prior year divestiture gains. Importantly, these items do not detract from the underlying cash generation strength of the business.

Overall, 2025 was a transformative year that strengthened our platform, expanded our U.S. flexible generation footprint and materially increased cash flow positioning the company well for sustained long-term value creation. Our performance in 2025 reinforces that our people, processes and strategy are aligned and built for this moment. We see three fundamentals clearly. Power demand growth is strong. Natural gas is critical and Capital Power is well positioned to win. We have a proven platform, deep expertise and a track record of disciplined execution that differentiates us as we move into 2026.

We are reaffirming our 2026 guidance for the year that we laid out at Investor Day. Our outlook reflects the strength of the platform we've built, a larger, more diversified fleet, increased exposure to U.S. flexible generation and more stable, predictable cash flows. The guidance is supported by three factors: full year contributions from 2025 acquisitions, structural improvements that carry forward and conservative market assumptions supported by disciplined hedging and capital allocation.

As discussed at Investor Day, sustaining capital in 2026 will be higher than historical levels. This increase is planned and deliberate, reflecting the scale and composition of today's portfolio. Is not catch-up spending or related to asset performance, but proactive investment to maintain reliability, protect cash flows and support long-term earnings durability. Our MCV recontract is a great example. We've secured a contract that extends through the facilities 50th year of operation.

Executing commercial optimizations like this is only possible with the requisite investment needed to ensure extension of the life of the facility. Even with higher sustaining CapEx, we continue to generate strong AFFO and support the dividend within our targeted payout ratio. We remain focused on disciplined growth supporting the dividend and maintaining balance sheet strength exactly as outlined at Investor Day.

At Investor Day, we highlighted something really important. We have multiple opportunities on our existing asset base that require little to no growth capital that can grow adjusted EBITDA by up to $1 billion per year. That growth primarily comes from two levers: resetting contracts with superior pricing for longer duration and capturing rising merchant power prices in Alberta and PJM. This is embedded upside in our existing fleet. And importantly, we're already executing. We've recontracted MCV in Arlington Valley, extending duration and materially improving economics. This materially derisks a significant portion of the $1 billion of potential. That's why we see existing capacity represents the most compelling opportunity for growth. The assets are already built, operating and positioned to capture higher value.

Our 2030 targets remain unchanged and continue to frame our long-term strategy with capital allocation decisions, explicitly prioritized towards opportunities that drive AFFO per share growth, support disciplined U.S. expansion and maintain balance sheet strength. Our 2026 strategic priorities will set the foundation for meeting our 2030 targets.

Thanks, Scott. Before we begin Q&A, I would like to highlight our recent announcement regarding our leadership. We are pleased to have Kevin MacIntosh join Capital Power as our incoming CFO. Kevin has over 30 years of experience as a finance leader working in large complex organizations within the global energy industry and brings expertise across multi-jurisdictional operations, cross-border transactions, energy trading, and diverse regulatory landscapes. On behalf of the Board, the executive team and all of Capital Power, I would like to extend our gratitude to Scott Manson for his strong leadership and expertise and a service across many parts of the organization and as interim CFO. Scott will continue to support the onboarding process and transition until the end of April 2026.

With that, I will hand the call back over to Roy.

Thanks, Avik. This concludes the formal part of the presentation. Operator, you can now begin Q&A portion of the meeting.

[Operator Instructions] And our first question comes from Nick Amicucci of Evercore ISI.

I just wanted to touch quickly, Avik, on the -- I'm just kind of -- it's something that you guys outlined in the annual report here. The ASO and just the ability and kind of ongoing negotiations at Genesee units 1, 2 and 3 to kind of upgrade those. Just -- is there any kind of sense of timing or any clarity to be gleaned surrounding any of those, like the potential increase in generation?

Yes. And to be clear, it's not an uprate. We have volumes that are already available and subject to a maximum capacity limit on the grid. And so we've got an engineering solution to try and unlock those in our 2026 plan, we're expecting those volumes to be unlocked towards the back end of the year. But just to reiterate, we do have significant expansion capacity at the Genesee site. We see it as probably one of the most attractive generation sites anywhere in North America with access to land, access to water, access to transmission.

Right. Okay. Great. Perfect. And then just as we think about -- just because we know the -- I guess, some of the Calpine assets are going to be hitting the market soon within the PJM, the ones that need to be divested and everything. As we think about kind of the right way or the right asset and kind of portfolio allocation between PJM and Alberta. Any kind of -- and since we're at kind of that 60% that was previously conveyed. Any kind of direction that we should be looking or kind of threshold that we should be seeking when we think of it from a -- to the portfolio competition perspective?

Sure. We are deeply committed to maintaining our investment grade rating. Our contracted for 60% were near 75% today. As you think about our portfolio, we are currently not evaluating any acquisition opportunities in Alberta. Our acquisition effort is heavily focused on U.S. generation or generation that can increase overall contractedness. So we will maintain being above that floor of 60%, but we're comfortable with where we are with regard to our ratings. But that is a strategic barrier and threshold that we wouldn't expect to fall below .

And our next question comes from Robert Hope of Scotiabank.

Hoping you can add a little bit of color on the conversations that are ongoing at MCV regarding the 250-megawatt data center I'll take. Have you opened up that process to other parties as I see it's no longer exclusive?

We have not, Rob. We continue to work with our partners there and continue to advance it.

All right. And then in your prepared remarks, you mentioned that recontracting pricing is now moving to cost of replacement versus a cost recovery model. And in the annual report, you do highlight that recontracting is a focus for 2026. Can you provide an update on how those discussions are going? And you've already announced one recontracting in 2026. Should we assume that there could be some incremental recontracting announcements for the balance of 2026.

I think it's safe to assume that we are actively evaluating multiple recontracting opportunities in the U.S. We've got multiple plants that have -- that are expiring between '29 and '31 between [ Freddie ], La Paloma and Decatur. So -- and I think if you reflect back to our Investor Day, we've got $1 billion of adjusted EBITDA opportunity to go capture. And within that or over and above that, we've got incremental recontracting opportunities. So I won't pinpoint a specific outcome in a specific period of time. But I think we've delivered on that already between the announcements that MCV in Arlington Valley and continue to explore other opportunities. We feel confident about the opportunity set though.

And our next question comes from John Mould of TD Cowen.

Maybe just starting with the environment or gas-fired M&A. Could you just maybe give us a sense of how that's evolving relative to the last time we dug in this a bit at the Investor Day and maybe initial progress on the MOU with Apollo and your discussions there?

Sure. Thanks for the question, John. I'd say it's a robust market for M&A, and there are a lot -- there's a number of opportunities in the marketplace for us. As Avik mentioned earlier, it's a focus on finding the right opportunities, ensuring that it fits within our mix and ensures we remain investment grade. And for us, the ability to partner with someone like Apollo opens up the aperture of opportunities for us to ensure that we remain investment grade and on-site or 60% contracted mix. So it gives us a number of incremental opportunities to look at as a result of that.

We continue to work through to agreements with Apollo and we'll update once we have something to update on that front, but making some progress there.

I would just add to that, John, just a general market commentary. We're seeing increasing focus from market participants on the value of contractedness which we think the market is coming towards us in terms of capabilities. And overall, I think we're seeing a broader opportunity set of acquisition opportunities that extend beyond PJM. I think last year, it was heavily focused on PJM and ERCOT. And I think we're seeing a broader opportunity set than that now. So we're encouraged.

Okay. And then maybe just turning to Alberta. Thoughts on your progress on the overall regulatory framework for additional data center load. And I can appreciate you can get into the leads on how the Phase 2 process is going, but I'm thinking more just bigger picture, how are you feeling about the progress in creating the right conditions in Alberta to attract additional data center load beyond the initial 1.2 gigawatts from ASO Phase 1 that's making its way through FID processes right now.

I'd just go back to my comment to the next question, John. We feel really good about the value of Genesee. I could not be more emphatic about the fact that we think we've got a world class site that can materially increase generation. And I think from the DC perspective, between the government into Phase 1 now into the Phase 2 process, the market environment is increasingly becoming more attractive for Alberta. The pace at which the announcements are coming out, may not be at the pace that the market is expecting. But I think below the surface, the work that's being done to facilitate new generation coming in, the work around contracting and how that will work and then the general market environment of Alberta, where prices are, where transmission distribution is.

And the upfront work that I think the ministry, the regulator has put in place to allow for new load coming in, I think, has been, in some ways, leading North America. So when you compare and contrast that against PJM, who just recently announced, the special auction in many ways, Alberta's move on Phase 1 front run, what other markets are looking to do in the U.S. So I think we continue to be excited about it, frankly, more excited today than I've been at any other point in time, but it's not changing our disciplined approach to monetizing what we think is the best site in North America. And I recognize the boldness of that statement, but I think the facts support just how high quality Genesee is.

And our next question comes from Maurice Choy of RBC Capital Markets.

Thank you, and good morning, everyone. I just wanted to first touch on the statement of principles by the White House and certain PJM governors. What do you see as being the biggest risk to what's being recommended? And what PJM or FERC do to avoid that risk.

Maurice. Yes. I think the biggest risk we as generators see is somehow bifurcating the market in PJM between existing gen and new gen and the risk of somehow new gen being supported by a different pricing regime. That's the conversation we and all the generators are having. And I think from a supply and demand perspective, the good news is if you're a state governor looking at increasing reliability and affordability issues, the incentive through the existing auction process to provide incentives to the existing BRA process for existing generators is still there. What I find incredibly interesting through that exercise is the call to action 4, 12 gigawatts through the RBA process was coupled with a call for extension of the existing cap and floor.

So I think that's the single biggest risk. I think we and all generators in PJM take a great deal of comfort in two key facts, which is the existing cap and 4 is not clearing the market currently. So it's showing that existing short- to medium-term demand is in excess -- well in excess of what existing supply can take but also secondly, the spread between cone and existing generation at, call it, $60 a megawatt is a wide enough spread that you're still going to need to encourage new generation and existing generation to increase capacity through the existing BRA process.

Does the 12-gig RBA motivate someone like yourself to want to partake it from a new gen perspective? Or do you think the extension of the collars of 2030 as far as you want to go in this market.

No, I think like any generator when you have the opportunity to capture 15-year PPAs with what would notionally be investment-grade counterparties, you have to look at that. So now whether that is for new build or expansions at existing sites, that remains to be seen and negotiated. But we feel I shouldn't say we feel confident, but we're hopeful that we will have opportunities to do that as well. But the short answer and clear answer is, yes, we are evaluating it and we'll look at it. .

That's great color. And if I could finish off with the revised social objectives agreement, SOA with the City of Edmonton. From your perspective, what flexibilities were you trying to achieve or perhaps any risks that you are trying to avoid with this new agreement? And I'm hoping that you could focus your comments on the two things that special limited voting share as well as the head office location. .

So the head office location, I'll start with that secondly. There was no objective there other than to reaffirm our commitment to the city of Edmonton through this agreement. Edmonton is our home. It's been our head office. It's where the company was created. And frankly, it's a huge advantage. The core that we have built in Edmonton. It's probably one of the best cities in North America to build out technical, engineering, construction, project management expertise anywhere in North America. And our track record has demonstrated the formidable team that we've built from Edmonton in that regard.

So I would say that the SOA piece of this was really about our reaffirming and extending our commitment to the city, which is what the agreement provided for. The real key for this was the special voting share what others would refer to as the golden share. And when the company spun off in 2009, there was a special golden share that gave certain and specific rights to the city to in effect have a veto over the organization.

And so it was important for us to have full governance control and be in full alignment with our shareholders. And so it was an opportunity that we took and brought to the city to say look, the company has been incredibly successful. We're growing. We've emerged as a leading IPP in North America, and that and as a result, having flexibility around our governance commensurate with other large publicly traded companies was the right thing to do and the city supported us in that.

Our next question comes from Mark Jarvi of CIBC.

I just want to go back to PJM. Avik, just in terms of the comments about the RBA. Just where are you with conversations with clients? Is there a bit of an impasse until there's clarity on how this kind of comes out with the government in the White House proposal? Just interested in terms of conversations you're having right now with potential customers?

We are not having active conversations yet with customers. The ball is in the PJM's court in terms of -- in response to the governors and National Energy Defense Council. So they've responded in kind with -- they've received the recommendation and are now evaluating it. We and other generators are in consultation with PJM on what the framework for that could be.

And I think I'm sure some of us are having conversations, but we're focused on ensuring that the framework works for us and all generators currently. And then in due course, we'll prepare. But what I would say separate and aside from that, since closing the acquisition last year, we've been actively marketing our capacity from a wholesale perspective. So it's not like we're not actively marketing it, but I would say we have not specifically responded to the RBA with an outreach tied to the RBA yet.

Can you just clarify what that means in terms of the wholesale marketing efforts?

It's -- we're talking to any and all potential wholesale customers on long-term offtakes for capacity and energy .

And they're willing to contract before like the range of customers until there's clarity on the RBA?

Yes. That hasn't changed in the market.

Okay. And just going back to the...

I'll just clarify that. And the reason is that when you look at the RBA process, that RBA processes specifically for hyperscalers for 15-year PPAs that are looking at CODs that are 2030 or later. So if I'm in the market now, then your needs haven't changed, which is why I think this is important as investors consider this RBA auction, because it's a one-to-one, but we're sitting here today in the BRA process, and we're not clearing the auctions. So short, medium-term demand isn't exclusively being driven by data center demand. But the RBA process is explicitly focused for long-term data center demand.

Okay. And just go back to the comments on the Apollo partnership. It's still at the MOU stage, would that limit your ability to do any larger transactions until you turn that into a definitive deal? Or do you think that can get ironed out in the next couple of weeks or months, and that keeps you having all that sort of ample opportunity and breadth that Scott mentioned in terms of M&A potential?

What I would say, Mark, simply is we've been advancing the MOU with Apollo. They've been a great partner to date and we can walk in to government at the same time.

Got it. And then just with the Alberta Fed MOU starting to get closer to us here in April, just updated views in terms of where you think there's making progress in terms of how [ tier ] gets revisited and whether or not the CR goes away?

We expect it to go away. The negotiations are ongoing. We participated in the outreaches for consultation as requested. I don't have a further update than that, but we expect it to get ratified as was stated by the Prime Minister in the premier back in December. .

Any possibility there's an extension just given, obviously, there's a lot of different things that have to get solved here?

I don't have visibility on that today. .

And our next question comes from Benjamin Pham of BMO.

I wanted to first start off with the ASO Phase 2 large load allocation. Can you comment on what you or the industry expect to see from that to get the DC in actually continuing to go forward?

Yes. The Phase 2, Ben, Phase 2, we'll expect to see bring your own generation result in deals and data center announcements. I think we're explicitly focused on monetizing Genesee, as I've stated a few times today. And what that means for us is we're in the business of selling power and getting PPAs with strong counterparties. So that's going to be our focus. I think the continuing focus across North America on reliability and understanding how additional transmission distribution affects affordability for consumers, particularly in the U.S. as we're in an election year, running up until midterms is continuing to draw interest in Alberta.

So relative to last year to the year before, I would say there's more interest in Alberta today than there ever has been. And I think Phase 2, we're focused on investment-grade counterparties that can sign long-term PPAs. I think the broader universe of opportunities, there will be others that come in that will look more like merchant data centers, I think rising tides lift all boats. So I think any and all activity in the province is going to support increased demand and closing that supply, closing that supply/demand gap. But our attention, if it's not clear, is on large customers that can find long-term PPAs that are credit worthy.

And maybe to follow up on that a bit more. I mean the bring-on generation, that's been discussed for some time. You had the Phase 1 where it was a prorated allocation. Do you expect Phase 2, it's more in the vein of X megawatts each year over a set period of time, RFP like style allocation? Or is it something totally different than that?

No. I think our indications are is the government means what they've said, which is they will work with parties so long as they're not unduly burdening consumers with that solution. So I think the trick will be not can you go do a deal if you have behind the fence generation, I think the province has been incredibly clear that they welcome that. I think the trick becomes is if you need a grid connect, what does that mean, how are those costs borne and that's the distinction between Phase 1 and Phase 2.

So I think Phase 2 will result in transactions coming forward. I think the question is going to be, and how do you support? And by the way, this is the same issue that is in the U.S. There's a pipeline of over 50 gigs in ERCOT of development deals that have been announced. But the next phase of that is how do you convert that into a revenue model between long-term contract and potential energy exposure. So we're not in a position to say, I'll just be very blunt for us as Capital Power, would I go do a greenfield power plant in Alberta with a 15-year PPA in a merchant market unlikely, unless it had full contract coverage or material contract coverage that allowed us to make our rate of return.

Now do we have more flexibility to do a lot more on what I think is North America's leading site at Genesee? Yes, which is why I'm able to speak with such confidence around our positioning in the market. So at the end of the day, for me, the opportunity in Alberta because the market structure affords us the ability to go sell power flexibly with duration, pricing and shape.

It allows us to meet whatever the customer needs, whether it's on the energy side, selling energy or it's through co-location or building a site. So we feel really good about the opportunity set. It's just taking -- it will take time to get the right deal. We could go do any deal tomorrow, we're going to do the right deal. And I think I've been consistent in that messaging for the last two years.

Okay. Got it. And then maybe one more topic from me the Genesee 1, 2, 3 MSCC. Let's say you get the clearance this year is 500 megawatts of additional supply. I know you spent the CapEx, it makes a lot of sense for that. I'm just wondering -- I'm not too sure the market wants [indiscernible] supply in the silver supply market right now. Is that MSCC? Is that more of a bridge to the MOU you may be working on or Phase 2 opportunity?

I wouldn't read anything into that, whether it's a bridge or a subsequent negotiation. It's a technical requirement, the 466 of the ASO for a single node limit. I think we're committed to unlocking those megawatts for the grid, which we think is net beneficial because we are effectively baseload for the province given our efficiency and heat rate on those plants. So in any scenario where you look at the merit curve having more efficient megawatts is net beneficial to the grid and then even within our own complex when you look at G1, G2 versus G3, it's a net benefit to have more from G1 and G2 versus G3.

So I think in the context of how the province and the ISO look at overall megawatts, I think all of us are collectively aligned in the interest of the consumers to unlock those volumes. We've just got to get through the permitting process and the testing process.

And our next question comes from Patrick Kenny of NBCM.

Just maybe back on the PJM market and the RBA. Wondering if you could dive a little bit deeper into the opportunity for Rolling Hills just in terms of what a balance of plant investment opportunity could look like in terms of potential size and scope. I know your team is still working on the technical aspects, but just wondering if you had some ballpark figures that you can throw out there.

Pat, I don't have ballpark figures that I can refer to on Rolling Hills other than to say it was a plant that we acquired that was running at a 20% capacity factor. We're doing materially better than that. We've got permits that are air permits that give us capacity of almost twice that. And then we've got land available on transmission available that would allow for potential expansion that would allow for a potential repowering. So we are excited about the opportunity set around Rolling Hills, but I'm not in a position to quantify CapEx or timing or capacity at this point.

Okay. Fair enough. And I guess now that we have clarity on capacity prices through 2028 and the pricing cap is being held in place there through the end of the decade. I wondering if you can get an update for us on your financial outlook from Hummel and Rolling Hills now that things have changed since you initially announced the transaction last year relative to your initial capacity price and utilization assumptions.

Thanks for the question, Patrick. I'd say overall, to date, the assets have performed better than expected from a cash flow perspective. And as we look out into the future capacity auctions, including the couple of expected ones that are coming as a result of the RBA. The price expectation that we had is very low relative to where we've seen the auction settled to date and also the relative shortfall that we're seeing coming into the two upcoming auctions here. So it is a case for our cash flows were more conservative and the expectation is that it is going to outperform through that 2030 period.

Okay. That's great. Last one, if I could, just on -- just a follow-up on the Alberta Phase 2 process. The 2% levy on new data center investments, I guess, 0% is fully off the grid, 1% somewhere in the middle. Can you just provide us with any feedback, if you have any on how potential customers are viewing this in terms of competitiveness of the legislation and whether or not you see this as helping or impeding the development of large-scale projects in the province.

[Technical Difficulty]

I'm able to hear you now.

Thank you. Well, if there are no more questions, at this point we [indiscernible] to conclude the call. So we do thank everyone for joining and listening today and continue to follow the Capital Power story.

This concludes today's conference call. Thank you for participating, and you may now disconnect.

Good morning. Welcome to Capital Power's 2025 Investor Day. I'm Roy Arthur, Vice President, Investor Relations and Investment Partnerships. On behalf of our entire team, I would like to extend a warm welcome to all of you and welcome you -- those with in person as well as those who have joined us virtually.

During the course of today's presentation, you will hear the management team make reference to forward-looking statements, which are subject to uncertainty. The presentation has a forward-looking statement slide with cautionary language that we encourage you to read. All amounts will be in Canadian dollars, unless otherwise noted.

I would like to begin by respectfully acknowledging that today's event takes place in the traditional territories of many nations, including the Mississaugas of the Credit, the Anishinaabeg, the Chippewa, the Haudenosaunee, and the Wendat peoples who have called this land home since time immemorial, and is now the home to many diverse First Nations, Inuit and Métis peoples. We recognize the enduring presence of Indigenous People on this land. Capital Power is committed to our journey of learning, respect and meaningful relationship building and we are grateful to have the opportunity to work on this land.

Today, you will have the opportunity to hear from several members of our leadership team as they present the elements of the agenda. And at the conclusion of the formal presentation, we'll have a Q&A session, during which time, microphones will be available for people to ask questions in the room.

Our agenda today has been crafted to convey while we continue to have conviction in the critical role natural gas will play and meeting the needs of North American grids, amid structural long-term demand growth. And more importantly, we will walk you through how our differentiated business model continues to position us to extend our track record of producing superior risk-adjusted returns.

In addition to the presenters that we have here on the stage, we have our full executive team here with us and several key leaders from the organization, and I would encourage you, who are here in person, to interact with them at the conclusion of the Q&A session. And with that, I will kick off our presentation.

Deliberate Growth and Durable Performance. Deliberate growth, durable performance, that is our standard. There are 3 key things I would like to press upon you about this standard to which we hold ourselves to. First, we have delivered outsized returns relative to major indices and peer groups. Two, this has been a direct result of our relentless execution, balance between growth and return of capital. And three, our progress has accelerated since our last Investor Day in 2024. Through deliberate growth and durable performance, we're powering superior returns to investors while preserving reliability and affordability for constituents in the regions where we operate.

As a demonstration of our durable performance, over the past decade, Capital Power has delivered a 20% total annual shareholder return, outperforming all Canadian.

IPPs, all Canadian midstream entities and both the S&P TSX and S&P 500. This performance has been a combination of share price appreciation and dividends, which we have consistently grown as well, all while remaining within our financial guardrails. Taken together, we've delivered $65 per share of value, consisting of $20 per share from dividends and the balance from share price appreciation.

So how did we deliver this? It was a team effort from a group of experts and innovators that are the driving force behind our success. They set us apart and drive us forward. Over the last 10 years, our team has delivered robust inorganic growth, including 10 acquisitions. This, along with our organic growth, has driven a quadrupling of our power generation capacity across our portfolio. Along the way, we paid in excess of $2 billion of dividends. To be clear, as a result of that growth, we are not just a bigger version of our business 10 years ago. Beyond greater scale, we have diversified, lowered our cost, reduced our carbon intensity. And most importantly, we now have a portfolio with a robust pipeline of growth opportunities for further shareholder value creation. You will hear more about this as part of today's Investor Day.

At our previous Investor Day 2 years ago, we made 4 commitments: first, expand flexible generation; second, grow our renewables portfolio; three, enhance returns through trading; four, create balanced energy solutions. In meeting each of those commitments, we have entered PJM, the world's largest power market, with a material foothold, organically grown our renewables and storage business in Canada and the United States. We have expanded the reach of our trading platform to support our growing fleet, and successfully launched balanced energy solutions for our customers, including 2 MOUs, representing 500 megawatts of data centers at 2 of our sites within our portfolio, one of which we announced this morning.

Now that I have given you the story that has brought us here, we would like to share with you a quick video that highlights the team that makes this success possible, and following that, Avik Dey, our President and CEO, will discuss the natural gas expansion era that we are so excited about. Thank you for being here today with us.

[Presentation]

Good morning, everyone. And on behalf of 800 fellow employees from across North America at Capital Power, welcome to our Investor Day. Today, we are going to talk about natural gas. Natural gas, today, is the most important technology to power North America's energy need. That's a theme you've heard from us before. But today, the need for natural gas has never been more pronounced. We are entering an era of natural gas expansion. And it's as a result of growing electricity demand, and today's story will be about why we believe natural gas demand is critical to meeting growing demand and why Capital Power is best suited to meet that moment.

Our company, from inception, has been focused on natural gas-fired generation. That is what we do, that's what we've always done, and that's what we will continue to do. And our mission is to own and operate those assets, add value to them and be stewards of providing reliable, affordable and effective generation to those markets we're in. Today, we believe that CPX is one of the most attractive plays in North American infrastructure because we do utility-scale power and we do it exceptionally well, and have done it since inception of our company. We've never left, we never pivoted, and we've always stayed the course.

We've demonstrated that through business cycles, we can deliver strong returns by operating safely and efficiently, while we invest in those same assets to make them more efficient and operate them for longer. And that's not hyperbole for us. Since our inception in 2009, we've grown our capacity 4x. And during that same period of time, when we started, we had a natural gas weighting of under 25%. Today, it's 90%. We were committed to natural gas then as we are today. Our people, processes and strategy are all built for this moment.

We are going to talk about growth. So let's start with the case for natural gas. Why gas and why now? We have 2 major thematics at play that both drive more dispatchable power now. Firstly, it's the AI infrastructure boom. We've talked a lot about what that means for the economy, and we've talked a lot about the growth around AI. And it's not just data centers, and we'll talk about that in a moment. That underlying theme is creating exceptional electricity demand growth in the market.

When you combine that with what we've already been seeing across North America, which is growing reliability concerns around grid, reliability, meeting, dispatchable, firm electricity demand. We've got 2 major thematics at play, all requiring more power from all sources and more dispatchable power. And what that means, in our view, is that we ultimately need more natural gas. So let's start with U.S. infrastructure growth. Today, what we see in front of us is at least 100 gigawatts of new electricity demand capacity coming from AI alone. And those numbers range from anywhere from 100 gigawatts to 150 gigawatts. And when we talk about that capacity coming online in that demand, what's important for us from a natural gas perspective is natural gas is cleaner, faster, more efficient and more economic. And so we're not talking about gigawatt 50 to 100 or 100 to 150, the first 50 are going to have to come from natural gas because it's the first electron that can be made available to the market.

So when we look out over the course of that next 5 years, and you look at that capacity build, this trend is already here. So over the past 3 years, we've seen a 50% CAGR in demand increase for CapEx. It's nearly $600 billion a year of CapEx that's already going out towards this initiative. So we're just getting started on this trend. When we talk about where the market is, at our last Investor Day, we stood before all of you and predicted electricity demand growth and a changing sentiment toward natural gas. We declared that renewables would be one component of meeting growing demand, but that more had to be done, and natural gas was a key part of that answer.

Today, the market signals are clear and the path paved for capital investment. Higher prices for power and longer contract link is a realized fact as demonstrated by our announcements at MCV and our Alberta PPA. We believe that there is more to come. The signals, market and investment could not be clearer for natural gas because it is the only near-term source of firm supply that can be delivered economically, reliably and quickly.

Focusing on the U.S. market, it's forecast that by 2030, the U.S. alone will need 20% more power generation. That's only 5 years from now, a time line that demands utilizing the low cost and fastest speed-to-market solution that can deliver at scale. And what's interesting about that is natural gas today represents 43% of all U.S. power generation, implying a capacity factor of around 33%, meaning natural gas is the largest and most underutilized source of reliable power generation. There is a wealth of capacity at existing natural gas assets waiting to be unlocked, and our business model is focused on acquiring and optimizing existing natural gas generation assets. That's why we are so excited about opportunities like recontracting.

In addition, natural gas generation is fast and cheap. Let me repeat that. Natural gas is fast and cheap. As we've continuously advocated, meeting electricity demand growth is about doing more of everything. We need more renewables, we need more storage, we need more nuclear, every single one of them. However, if we're building a foundation for a rising pyramid of demand growth, the bottom or the foundation must be strong, durable and reliable. It must support the weight of an expanding network of infrastructure above it. Only gas can meet that moment today. We just mentioned on the previous page that existing gas infrastructure is only being used at a capacity factor of 33%. That means it can deliver power at 1/3 of the cost of new build gas and 4 to 5 years faster than new build. If we expand that comparison to nuclear, we are talking at 1/10 to 1/4 of the cost and 5 to 9 years faster.

So how do we deliver value? Well, our business is simple. It's the same one that we've been running since 2009. It's 3 key businesses: our natural gas generation business, which represents 90% of our existing capacity and fleet; second, a growing storage and renewables business to support that natural gas business in the markets that we're in and serve our customers; and thirdly, a supply and trading business that's built around our existing generation to support in optimizing those assets and trade natural gas, power and credits in all the markets and around North America. And those 3 businesses work in conjunction with each other to go deliver outsized shareholder returns in our expectation.

Combined, this platform delivers operational discipline and determined focus on building, operating, optimizing and commercializing utility scale power generation assets, and it has resulted in a scalable, stable and growing platform. And most importantly, it's how we take molecules, convert them to megawatts, and ultimately monetize them and turn them into money. We've successfully invested and acquired over $8 billion in assets since 2016 and operate across 5 key North American markets. And we have a simple strategy where we acquire assets or develop them to grow, but then we optimize them to add more value. And we do this across 3 key areas or steps as shown in the page.

First, operation and optimization of our assets. Last year, we talked about operational excellence, and we'll talk later about that operational discipline and how we own these assets and turn them into value and upgrade them, upgrade them and operate them more efficiently. Those of you that joined us yesterday at Goreway got to see that firsthand. Secondly, we'll talk about the commercialization of our megawatts at Capital Power. How do we contract them? How do we hedge them? How do we deliver PPAs to off-takers and customers?

And then lastly, we'll talk about the benefits of the enterprise architecture that we have and our approach to how we fund and develop and manage and find creative solutions to support our ongoing business. Combined, this approach generates, at our expectation, outsized returns of 13% to 15% or potentially higher. Later in the presentation, our leaders will describe how we deliver value through our optimization across each step of this stack.

Something new that we're reporting on is also the deep pipeline of opportunity that we have here at Capital Power. That is 2x the size of our existing fleet today. On the left, we have nearly 8 gigawatts of opportunities to optimize our existing fleet or within the footprint of our existing fleet. This includes everything, from an upgrade of an existing plant, to improve performance, to colocation of a data center, all the way to full repowering at the end of life.

In addition, we have an active pipeline of external opportunities that includes acquisitions and greenfield opportunities. Today, our focus is clearly on acquiring existing capacity, given the strong value proposition we see on buying and optimizing assets versus building them ourselves. We do expect this to converge over time and come into balance. But for the short to medium term, we remain steadfast in our focus on acquisitions around existing gas generation assets, particularly in the U.S. market. And to further advance our acquisition efforts in that U.S. market, we are excited to be entering into an MOU for an investment partnership with funds managed by affiliates of Apollo Global Management. Together, we aim to jointly invest up to USD 3 billion in acquiring new merchant gas power plants. The partnership with Apollo Funds would accelerate our growth, protect our balance sheet, and enhance returns for our shareholders. We're honored to be partnering with one of the world's leading investment firms.

A repeating theme throughout our presentation will be, we've been there and done that. We have a proven playbook for value creation rooted in 3 key pillars. Again, we're not pivoting. We're not opening new business lines. We're not expanding into new geographies. Same, proven, reliable playbook. First, the platform. Assets, balance sheet and the ability to execute because of the 800 people that are deeply committed to powering change by changing power. Second, our edge. Simply put, it's our ability to commercialize, trade and operate megawatts. This creates a unique advantage that's difficult to replicate.

The combination of the 3 results in Capital Power's edge of delivering clear value creation to our shareholders through our unique optimization pathways. Lastly, our outlook for growth and the multiple ways to win. Whether it's growing electricity demand as a thematic, AI infrastructure demand from the AI infrastructure boom or the increasing need for grid reliability, natural gas generation is a proven winner. It's cheaper, it's faster, and it's already installed. At a market level, we have available capacity in the right markets. Shown on this map, you'll see the 5 critical markets we operate in: Alberta, Ontario, MISO, PJM and WECC.

Each market has a significant appetite for demand growth, creating a total of 100 gigawatts opportunity for Capital Power. And as I mentioned earlier, we are one of the only platforms in North America that has the in-house capabilities to operate, commercialize and trade megawatts on both sides of the border. Operational discipline sits at the nexus of our approach. When we do all things well, good things happen, like long-term contracts and PPAs for data centers. The ability to operate safely and efficiently, in combination with prudent risk management for trading and the ability to partner and cooperate with offtakers, load serving entities and utilities, is our game. This is our edge. That's how we win.

To support that ambition, we've put out 2030 targets, and this is why we're excited to announce them to you today. Over the next 5 years, we anticipate delivering 8% to 10% cash flow growth, 50% growth in our U.S. capacity, 3.5 gigawatts of capacity net to the company over the next 5 years, and we're increasing our total shareholder return expectations to 13% to 15%, 100 bps higher than what we had expected and forecast at our 2024 Investor Day. Underpinning all of that is natural gas demand will grow, and we, at Capital Power, are best positioned to deliver.

We would like you to walk away with a few key takeaways from today's presentation and arm you with the proof points that demonstrate our ability to deliver on our commitments, like we have done in the past. First and foremost, our strategy works. It's clear, consistent and has proven to deliver returns while growing to meet the market opportunity at our fingertips. Second, natural gas is critical. There is no substitute to power the North American economy that matches the reliability, affordability and economics of natural gas. It is the lowest cost and fastest speed-to-market solution to meet the demands of the demand super cycle that we are in midstride on.

Third, our fleet and operational capabilities are perfectly aligned to capture this opportunity today, delivering unmatched value when compared to our peers. And finally, the growth opportunity off of our platform focused on acquisitions. We are primed to deliver unmatched value against our peers, funded through a continued disciplined approach to capital allocation.

I'd now like to turn it over to Steve Wollin, our Senior Vice President and Chief Operating Officer, to kick off an important discussion around what operational discipline is, a key driver of performance and reliability across our organization. Over to you, Steve.

Thank you, Avik. So good morning. Today, Jason, Andrew and I will be speaking about how our approach to operational discipline drives value creation across operations, commercial and our trading teams. These 3 pillars are critical to the Capital Power advantage. Our ability to deliver all 3 is truly unique. Asset optimization is in our DNA at Capital Power, and our disciplined approach to operations, maintaining and optimizing our assets delivers reliable megawatts and maximize the capacity of our sites. We deliberately obtain assets with high optimization potential and then apply our expertise to deliver that potential, equipped with deep experience in life cycle, risk management, maintenance, best practices, we're in a prime position to recognize high potential plant value. This sets us apart from other buyers in the market, enabling us foresee and deliver value others cannot unlock.

Our ability to add value through the optimization of our fleet is supported by our capabilities as best-in-class operators, our superior assets and our experience and track record in optimizing assets. Starting with the best-in-class operations. Our performance is demonstrated by our track record of running safe, cost-effective, efficient and highly available plants. As operators, we have over 480 years of combined operational expertise just in our plant managers. We have reputation for knowing generation and taking care of our fleet. This resonates really well with our people, attracts the best in the industry. Good operators want to be at good plans. We don't just buy and operate as delivered. We buy and we transform our acquisitions to create optimal value as many of you saw yesterday in the Goreway tour.

We've developed a team of technical specialists on the ground that are empowered and very passionate to take our assets to the next level in capacity, efficiency and reliability. These teams are highly involved in our planned maintenance work. For example, over the last 5 years alone, they've supported over 150 planned outages, ensuring the health and reliability of our assets. Paired with our in-house construction and engineering teams, in the same time period, we've delivered over 1,300 new megawatts to our fleet through construction projects. And through our sustaining capital program, delivered over $25 million in annual EBITDA.

In lockstep with our growth strategy, we have a dedicated integration team that quickly and efficiently ushers new acquired assets into our fleet, instilling our operation philosophy and moving them along to the next -- along the road to optimization. And well-run assets are safe assets. Excellence in operations equals excellence in safety, with our health and safety performance among the best in the industry.

So supported by top-notch operations, we also have the right assets to deliver results. We focus on acquiring assets with the right characteristics. These include optimal size, age, and technology, which enables superior asset performance, including higher availability, higher efficiency and lower operating costs. I believe our track record demonstrates that we have the right plans with the right qualities to deliver top-tier performance.

For example, starting with size. At our IPO in 2009, our average gas plant size was 112 megawatts. Today, it's 770 megawatts compared to the U.S. average of 585 megawatts. Larger plants drive economies of scale, pushing down support costs and more importantly, demonstrate our conviction to grow and stay in this business. Our plants are also younger than the North American average, with a fleet average age of 23 years compared to the North American average of 28 years. Newer plants are more reliable, efficient and allow us to influence the plant life cycle early by implementing optimal processes and procedures to drive plant performance.

Finally, selecting the right technologies enable standardization, better parts availability and broader sharing of operations knowledge, all of which enable superior performance, which is demonstrated and how we consistently deliver top quartile fleet availability with an average equivalent availability factor of 91% over the last 5 years, well ahead of the industry average of 83%. Optimization and responsible operations also results in a cleaner and more efficient fleet, again, demonstrated by the gas fleet efficiency with our heat rate, 8% below the U.S. industry average. We maintain our availability by spending money efficiently in the right places, with fleet capital cost at $8 per kilowatt before our peer average.

I really want to draw your attention to the slide. In fact, I had quite a few questions about this topic last night. It explains why, how and when we spend our dollars. And why in some cases, we can buy plants that are -- have a bit of hair on them, and make them into higher performers. The design level of a gas plant typically transitions through 4 phases. In Phase 1 right after construction, costs typically start off a bit high through the first years of growing pains. This is the phase we currently are in at Genesee, currently as we kind of fine-tune that asset, get to where we want it. In Phase 2, costs then stabilize between years 5 and 20. This is the current case with Goreway and Hummel.

In Phase 3, I would say the most important of the 4, we see kind of a midlife jump-in cost between year 20 and 25 as turbines, balance of plant equipment such as cooling towers, motors, pumps, need to be refurbished. Managing this phase is critical to the reliability of assets as they enter into the last half of design life into the potential -- and potential life extension. La Paloma, Harquahala, Rolling Hills are all currently in this phase with higher investment in progress.

Finally, in Phase 4, cost drop off, stabilized again for the remaining 25 to 40 years of design life until then you decommission the plant or you're going to a major life extension. This is the phase that Arlington Valley, Decatur and Frederickson are just entering and MCV is just moving out of this phase and moving into a life extension program with initial higher costs. For plants that are new to Capital Power, depending -- obviously, depending on their history, we typically plan on an uptick in costs for the first 2 or 3 years of ownership as we bring them up to our performance standard. But by making the right front-end investments, we deliver superior long-term cost and operational performance. This represents Capital Power's edge in operations. We invest at the right times in the right places with a long game in mind.

Enabled by our operations performance and the right assets, we have the know-how and the technical teams to deliver continuous asset optimization. Examples of that optimization include the repairing project that just delivered at Genesee last year, where we added 512 new megawatts to that plant and actually transformed it into the most efficient gas plant in Canada, which I think many of you saw last year in our tours.

Battery storage projects like those at Goreway and York, with COD this year, expansion projects like the 78 gas turbine under construction at East Windsor site, to run upgrade projects like that at Decatur, York and Goreway, providing more megawatts and improved heat rates. And as we continue to recontract our plants, we deliver important life extension programs like the one currently in progress at MCV to ensure we deliver reliable megawatts well into the future.

So how does our automation strategy affect our long-term assets? So looking back on our track record. For the thermal assets we've owned since 2019, we've been able to add nearly 900 brownfield megawatts. These are megawatts added well below the cost of new entry. The strong relationship between our technical teams and our ops teams has enabled us to deliver these megawatts through in-service upgrades, which minimizes disruption to ongoing generation of megawatts and revenue. In parallel to optimizing our equipment, we've continued to drive our operations philosophy into the culture of these assets. This optimization in concert with the asset life cycle has driven down cost of capital on major maintenance by 23%. And with the addition of more efficient megawatts, we've also driven down our carbon intensity by 37%. Optimization leads to a cleaner and more cost-effective fleet.

So looking ahead, our assets are prime for continued expansion. Our existing assets alone offer up to 3 gigawatts of additional capacity, all below the cost of new entry. These 3 gigawatts are made of a combination of potential upgrades, additional turbines, repowering projects, all of which we have experienced in delivery and a proven track record of delivering.

So in conclusion today, I trust that we've demonstrated that through our focus on top-tier operations, our proven track record at acquiring and building the right assets and our continuous focus on optimization that we're positioned to grow and deliver the balanced energy solutions needed to support the North American power industry today and into the future.

Thank you. And with that, I will turn it over to Jason Comandante, SVP, Supply & Trading, who will lead the next part of our conversation on operational discipline, focusing on commercial optimization.

Okay. Thanks, Steve, and good morning, everybody. In addition to Capital Power's operations edge, we also hold a commercial competitive advantage. That commercial advantage is what allows us to capture the right value for our reliable and dispatchable megawatts.

Capital Power's long-standing thesis is playing out. The value of reliable megawatts is increasing. We've built the North American power portfolio to express that view, and our operations team has set the stage for our commercial, balanced energy solutions and supply and trading teams to optimize it. Throughout this portion of the presentation, Andrew and I are going to talk to you about the value of our megawatts and how we're going to capture that value. I'll start with supply and trading in merchant markets, and Andrew will then later focus on contracting.

This is a simple but important picture. This is what we do. We buy for and schedule natural gas to our facilities. We operate those facilities that turn fuel into reliable megawatts, and we monetize those megawatts. It's simple, fuel in, value out. The key question here is what is the right value for our product? What is the right value for our megawatts? Broadly speaking, in any industry, the long-run price for a good or service will equal the all-in cost of producing that good or service. And power is no different.

We're coming out of a period during which natural gas-fired megawatts have been undervalued. This was due to trends such as energy efficiency decelerating or altogether temporarily pausing demand growth, the proliferation of renewables, adding supply, and the threat of natural gas-fired generators lives being shortened due to prioritization of decarbonization over reliability and affordability.

During that period of undervaluation, Capital Power remains steadfast in our view and seize the opportunity to build a fleet and a platform around that fleet, and we remained patient. While we waited for our view to play out in markets, we honed our integrated operational, commercial and trading crops. Our competitive advantage now is our ability to excel across all 3 of those crafts, and Steve already spoke to you about operations.

Commercially, we've developed deep synergistic relationships with our off-takers that convert into value-add contracting opportunities, and we prepared our sights for growth and the potential to serve on-site load. From a supply and trading perspective, we've translated our experience managing inputs and outputs of power generation facilities into a commodity optimization competitive advantage across power, gas and environmental products. And we did this while standing up our balanced energy solutions business in anticipation of the emergence of a new customer class stemming from AI-driven load growth.

The graphic on this slide brings it all together. Starting at the bottom, we have our foundation. Our 12 gigawatts of capacity split between contracted and merchant megawatts. The section above that, foundation, represents our asset expansion potential. Those are the megawatts, and above that set the dollars. Operational excellence is crucial for those dollars and our ability to commercialize. It's what allows us to hedge into markets and contract with customers with confidence. The circles above are assets and their expansion potential represent how we commercialize our product. On the left is our commercial team that contracts our contracted assets with off-takers. On the right is our supply and trading team that deploys hedging programs, optimization strategies and proprietary tactics across deregulated markets to drive value from our merchant assets. And in the center is our balanced energy solutions business designed to transcend our contracted and merchant assets and capture those large volume, high complexity, multi-jurisdictional customers, such as those in the AI space.

Fast forward to today, in our core merchant markets, forward prices are pointing towards supply and demand coming into balance. They are reflecting the all-in cost of new production. In Alberta, power prices from 2025 to 2030 are expected to rebound and increase by 80%. But more importantly, clean spark spreads are expected to increase by 130% from $30 to $70 a megawatt hour. Simply put, the gross margin for a baseload power plant in Alberta is projected to more than double. To put that in perspective, a $40 per megawatt hour increase on 1 terawatt hour of generation equates to roughly $40 billion -- $40 million of additional EBITDA. Capital Power's baseload generation portfolio generates well over 10x that volume. And this isn't an Alberta phenomenon.

In PJM, where we have 2 gigawatts of capacity, market prices, inclusive of energy and capacity, are projected to increase more than 50% from 2025 levels as we approach the end of the decade. Our supply and trading team takes a disciplined, responsible approach to commodity optimization, ensuring we strike the right balance of pursuit of the upside and prudent risk management. All of this trading activity fits within a structured set of dynamic, executive-supported and Board-approved commodity and credit risk policies, procedures and guidelines.

In 2026, our supply and trading team will buy roughly $1 billion worth of natural gas for our merchant facilities that will generate well over $2 billion worth of power revenue. We do this through combining the quantitative, such as deployment of advanced analytics and proprietary modeling, with the qualitative, our long tenure of experience with commodity markets and disciplined approach to creating value.

Heading into 2026, the final year of the price trough, this active commodity portfolio management has led us to be well hedged, but we're far less hedged in 2027 and beyond in anticipation of price recovery.

In closing, our North American class supply and trading team optimizes Capital Power's 6 major merchant facilities across all 3 energy commodities competing in 5 major deregulated power markets. And importantly, we run this all out of one central office in downtown Calgary with a highly experienced leadership team that has created a cohesive culture driving at a single focus, being the best asset-backed energy trader in our space.

I'll now turn things over to Andrew Pearson, Vice President, U.S. Thermal, to talk about contracting, the successes we've had and opportunities in our future.

Thanks, Jason, and welcome, everyone. Capital Power's recontracting opportunity across its fleet has never been brighter. As Jason mentioned, Capital Power has organized its commercial optimization around 3 teams: supply and trading, balanced energy solutions, and commercial. Today, I'll be focusing on the commercial and balanced energy solutions teams.

As shown in this graphic, Capital Power's North American portfolio represents 12 gigawatts of capacity, underpinned by over 4 gigawatts of long-term contracted assets well into the late 2030s and beyond, 3 gigawatts of contracted capacity opening up in the 2029 to 2032 time frame, and 5 gigawatts of merchant capacity predominantly in Alberta and PJM. This mix is intentional. It maximizes choice on when and how to lock in value.

I'll be focusing on the 3 gigawatts of currently contracted megawatts with expirations in the next 4 to 7 years. We are leaning into earlier engagement, higher prices and longer duration across our contracted fleet. With that optionality laid out, let me quantify that what that means in dollars.

Over the last 3 years, demand growth has accelerated and supply constraints are requiring new generation builds in the markets our contracted assets are in. This thematic has offtakers now looking to contract as early as possible for long term, and pricing is dictated by the cost of replacement, which continues to rise. As a result, Capital Power's contracted portfolio is poised to see significant growth in contracted EBITDA through recontracting starting in 2029. Across the approximately 3 gigawatts of contracts, a 50% increase in contract pricing by 2033 would result in an increase of over $220 million EBITDA when compared to 2026 values, and requires little to no incremental capital expenditures. We also continue to have discussions on extending tenor with counterparties valuing reliable megawatts over the long term. This supports our cash flow visibility and weighted average contract life.

As Steve mentioned, Capital Power consistently delivers top quartile in availability through prudent execution of our capital plan. This investment and track record -- our U.S. thermal fleet is the premier partner for long-term contracts with utilities and hyperscalers. Case in point is the transformative recontracting at MCV. The newly secured 10-year contract at MCV stands out as a milestone for Capital Power. It delivers an impressive 85% increase in price compared to the current agreement, and the 10-year term is 5 years longer than the previous extension. This clearly demonstrates our ability to partner long term with strong investment-grade utilities. This proactive approach underscores our commitment to long-term value creation and stability for our stakeholders and our counterparties.

Expanding our commercial reach, Capital Power is also advancing towards definitive agreements for 250 megawatts with a leading colocation data center developer. This initiative highlights our agility in responding to evolving needs of the energy market, particularly the surge in demand from hyperscale data centers and AI infrastructure. By leveraging our balanced energy solutions business, we are able to offer tailored, reliable power solutions that meet the stringent requirements of these sophisticated customers. Together, these activities illustrate the significant potential for EBITDA growth through both strategic recontracting and innovative commercialization.

Our ability to secure premium, long-duration contracts well ahead of market cycles and to tap into new high-value customer segments positions Capital Power at the forefront of value optimization in the North American power sector. Our balanced energy solutions team tailors solutions for hyperscaler, enterprise AI loads and other large-scale customers. We bring value to these customers through reliable power, fast deployment, strategic sites with land, essential infrastructure and future-ready compliance. We are actively marketing 5 sites with over 3,000 megawatts of potential data center load. This is designed to crystallize value at superior pricing and longer durations versus wholesale alternatives.

Why we win? We have the know-how to excel at development, contracting and operations, all underpinned by highly reliable generation and our investment-grade profile. This all aligns with the needs of the hyperscaler customer. Here's a concrete example we can speak to in Alberta. In Alberta, we are monetizing our Phase 1 allocation by progressing an investment-grade data center developer PPA at 250 megawatts for 10-plus years, leveraging our merchant fleet to lock in long-duration premium pricing. This is what we mean by crystallizing merchant value, converting market upside into stable contracted cash flow while keeping operational flexibility. Pulling the pieces together, recontracting plus balanced energy solutions plus merchant momentum leads to a $1 billion opportunity. I want to bring all of this together to highlight the significant commercial opportunity that's in front of Capital Power.

Absent any growth capital, Capital Power can grow its adjusted EBITDA by up to $1 billion, simply through increasing contract rates and capturing rising merchant power prices in Alberta and PJM. This EBITDA growth is underpinned by the following drivers: higher recontract prices at assets with contracts expiring in the early 2030s, and realization of already higher forward prices. With its supply and trading balanced energy solutions and commercial teams, Capital Power is organized to capitalize on this unprecedented opportunity to add value throughout the value chain.

Next up is Roger Huang, Vice President, Corporate Development and U.S. Renewables, to walk us through how we create value through growth.

Thank you, Andrew. Good morning, everyone. I'm excited to be here today to walk you through how Capital Power is well positioned for long-term growth. I'll spend time discussing our acquisition strategy and how we'll continue adding megawatts to fuel our optimization pathways.

Capital Power, at its core, is a natural gas-focused growth platform. To reiterate Avik's remarks, North American power demand is growing at unprecedented rates, and natural gas generation is critical to supplying the demand. In our view, the best way to participate in this thematic is through the acquisition of natural gas generation. Acquisitions offer an attractive return profile, driven by a clear and large dislocation in asset prices. Acquisitions also provide Capital Power, the fastest path to meaningfully grow AFFO per share. We have a large opportunity set, 17 gigawatts, of which we only need to action 20% to meet our 2030 goals.

Over the past decade, Capital Power has completed 10 acquisitions, representing more than $8.5 billion of assets and 9 gigawatts of capacity. We're proud of our track record, and it's a foundation for our continued growth. Early on, we focused on acquiring fully contracted assets to drive stability and value. But as power demand has accelerated, fueled by a growing reliability gap and the rapid growth in AI-related compute, we have strategically shifted towards acquiring merchant facilities where we can unlock value.

With each acquisition, we have honed our ability to identify and capture value. As an example, take this year's $3 billion Rolling Hills and Hummel acquisition, our largest acquisition to date and entry into a new market. We engage a seller in a bilateral process, selected the assets of our choice, and acquired them at attractive value. Ultimately, our track record shows that we skate to where the puck is heading, and should reinforce to shareholders that Capital Power will remain disciplined in M&A.

This chart is at the core of why we see acquisitions as the most attractive avenue to invest in growing North American power demand. The cost of new build gas generation, roughly $2,500 of KW, is nearly 2x the cost of acquiring existing plants. This value gap is unsustainable and is a clear signal that energy and capacity prices will rise. Put simply, new supply must be built to meet growing demand. Prices must increase to incentivize new build. As a result, existing asset prices -- existing assets will see an increase in prices and higher plant utilization. This will lead to an increase in values for existing assets. And we're seeing these recent dynamics across our portfolio.

Our MCV plant saw an 85% increase in price, and the PJM market saw a 22% increase in capacity prices. These trends are being reflected in the M&A market, with the recent transactions clearing at $1,500 in KW, a 50% increase from 6 months prior. While the opportunities from the value gap remain open, we are well positioned to take action. Acquisitions are just the start. Over the past 10 years, we have been disciplined buyers and have acquired assets at around 7x EBITDA. But the real story is what happens after the deals close. Through our optimization pathways, we have increased EBITDA by over 20%, adding nearly $1.6 billion of enterprise value. For shareholders, that means $200 million and additional cash flow per year with minimal CapEx investment. This includes the 180 megawatts of upgrades that Steve mentioned, and the contract extensions at MCV that Andrew presented.

Value creation have reduced implied acquisition multiples from 7x to 6x EBITDA across our portfolio. And our optimization pathways give us a clear competitive advantage in M&A processes. Our acquisition strategy is straightforward, and we've consistently executed for the past decade. We buy mid-life natural gas assets where we identify clear optimization pathways. We'll continue to pursue contracted assets, but we see the greatest value in merchant plans. We are often asked why we have been and will continue to be successful in M&A.

Several factors in our strategy work to our advantage. First, a distinct execution of our execution acquisition playbook. We have a clearly defined set of core markets and asset characteristics allowing us to prioritize opportunities. Once we've identified an opportunity, we can move quickly through acquisition, integration and optimization. Second, pattern recognition. Our long history in M&A means we've seen many of these assets before, whether they have traded hands previously, we have owned them or they share technologies we already operate. This familiarity reduces uncertainty and accelerates value creation.

Lastly, buyer credibility and competitive dynamics. We are often the advantaged buyer, especially where other IPPs face market concentration limits or private equity lacks operating capabilities. The take away is simple. The market is moving, competition is rising, but our relative position has strengthened. We bring speed, certainty and value, and ultimately, we have the right to win.

Our current M&A pipeline is 16 gigawatts and reflects actionable opportunities. We expect our pipeline to expand as higher valuations and capital rotation bring more assets to market. This pipeline can be broken up into 3 categories: number one, existing partnerships, where our partners on existing assets at finite investment periods and when they exit, we are the natural buyer. Number two, single-asset opportunities. These are highly competitive processes, but we bring more value than most buyers. This is our bread and butter. And lastly, platforms, which are multi-asset or multi-region portfolios. These are more complex but also more compelling. The competitive dynamics are attractive, processes are quieter and buyer pools are smarter.

Taken together, this pipeline gives us a multiyear runway of executable M&A. As Avik mentioned, this morning, we're excited to announce an MOU to form a $3 billion equity partnership with Apollo Funds to acquire merchant natural gas assets in the U.S. This is a potential, one-of-a-kind partnership with one of the world's largest institutional investors. The key point here is alignment. Both organizations share a strong conviction and the long-term growth of North American power demand and the essential role that existing natural gas generation will play immediate.

For Apollo, Capital Power represents a proven operator with a long track record of disciplined M&A and post-acquisition value creation. For Capital Power, Apollo is a differentiated and highly complementary partner, having deployed $40 billion into next-generation infrastructure since 2022. To summarize the partnership, it enables us to buy more merchant, natural gas assets at greater speed and scale, while maintaining our contracted merchant risk balance, and preserving our balance sheet strength and investment-grade rating.

Furthermore, our shareholders benefit due to the management and performance fees we earn. Of the $3 billion as contemplated by the MOU, Apollo funds will commit $2.25 billion, and Capital Power will commit $750 million or at least 25% of the total pool over a 5-year investment period. Capital Power originate opportunities and can choose to pursue them independently or offer them to the partnership. Together, Capital Power and Apollo are creating a platform with a clear competitive advantage to pursue the most attractive opportunities in the market.

While M&A is our primary growth engine in the near term, we expect greenfield development to become a meaningful part of the supply equation beyond 2030. We have the capabilities today, and are continuing to build the capabilities required to execute greenfield projects. To date, we have brought more than 1 gigawatts of greenfield assets online and have another gigawatt in the pipeline. We're actively advancing several storage opportunities, and expect our best pipeline to expand significantly in 2026. Our greenfield strategy is simple, every project must have the right customer, the right contract and the right opportunity.

Looking ahead, Capital Power is exceptionally well positioned for long-term growth. We have a multitude of ways to win, and we can materially grow our size and footprint. Our existing fleet alone has up to 8 gigawatts of embedded growth opportunities. In addition, we have more than 17 gigawatts in our M&A and development pipeline and opportunity set that will continue to expand. Together, our proven playbook, our enhanced funding partnership with Apollo and our existing consistent execution of optimization pathways, give us confidence that we can convert this pipeline from opportunity into reality.

With that, I'll hand it over to Scott, our interim CFO, to walk through our returns-driven financial model.

Thanks, Roger. Capital Power's business platform is uniquely positioned to create sustainable long-term value in this natural gas expansion era. As Avik said, we are natural gas, leveraging our skill to grow, optimize and deliver top-tier shareholder value. How do we make this happen? Our proven return-driven financial model is key. This is how we optimize at the enterprise level to outperform.

Steve, Andrew, and Jason have talked about our asset and commercial optimization pathways. And sitting on top of it all is our enterprise optimization. Our investment-grade balance sheet enables us to acquire high-value assets, secure top-tier, low-cost capital and become the counterparty of choice for PPAs and hedging activities. This drives a clear competitive advantage and stronger returns for Capital Power. The Apollo deal announced earlier today accelerates our ability to grow and offer enhanced returns without compromising balance sheet strength.

Our business is optimized to drive enterprise-level growth and value. Our disciplined capital allocation offers a rising dividend, while most of our cash flow will be reinvested to fund our strategic fleet expansions. Maintaining investment-grade credit ratings across 3 agencies sets us apart and allows us to continue to access the low-cost capital in both Canada and the U.S. market. This ensures we can prudently fund growth at the most competitive rates. Our differentiated funding model is further strengthened by the Apollo partnership and allows us to accelerate those growth pathways.

Capital Power has a 12-year record of dividend growth with a 6% CAGR over that period, while also delivering 12% adjusted EBITDA CAGR and a 20% total shareholder return CAGR, clear proof of our commitment and ability to deliver strong shareholder returns. Now how do we do that? It's the result of our disciplined capital allocation strategy, which I will walk through on the next slide.

Our ongoing commitment to reinvest in the business with a differentiated approach to value creation through optimization pathways underpins our confidence in achieving a robust total shareholder return of between 13% and 15%. We are pleased to provide guidance reaffirming our previously communicated dividend growth rate of 2% to 4% through 2030. And we do so from a stable base that maintains our dividend payout within our AFFO target range of 30% to 50%. This approach ensures that the majority of our cash flows will be reinvested in our business, supporting high-growth opportunities that Roger highlighted earlier today. This investment in our business is within a capital allocation target of approximately 80% natural gas and 20% to renewables and storage. This allocation is roughly consistent with our current portfolio composition today.

Our strong balance sheet is the foundation for fleet growth and is managed prudently within a stable base. Approximately 75% of our cash flows in 2026 are secured under long-term hedges or contracts, ensuring steady cash flow available for M&A, optimizations, dividends, and ultimately delivering total strong shareholder returns. 90% of our PPAs are with A-rated or higher counterparties, providing revenue, certainty and visibility. Our contract life on PPAs average around 9 to 11 years, which has been consistent over time and highlights the quality of our assets.

As Andrew discussed earlier today, contracts expiring are well positioned to be recontracted at higher prices for longer duration. This leverage is the increased demand for reliable power that we're very well positioned to capitalize on. The recently announced MCV contract adds 10 years of contract duration, with the contract running through 2040 at prices that are 85% higher than current contract.

Lastly, our investment-grade credit ratings across 3 agencies validate our financial strength and provide superior access to low-cost capital in both the Canadian and U.S. debt and hybrid markets. It also enhances our ability to commercialize megawatts at lower credit costs. We can acquire assets like Hummel and Rolling Hills and finance them in an investment-grade platform at lower cost, enhancing overall returns.

Looking at our 2026 guidance. This shows the summary of our expectations for adjusted EBITDA, AFFO, sustaining CapEx and dividend growth. Our adjusted EBITDA is anticipated to be in the range of $1.565 billion to $1.765 billion, reflecting a modest increase relative to our '25 revised range. And this is a reflection of our strong contracted asset base, significant hedging activities and a full year contribution from the Hummel and Rolling Hills acquisition.

AFFO is expected to be between $890 million to $1.01 billion, and is slightly lower year-over-year, reflecting higher sustaining CapEx, taxes, as well as the full year financing from the acquisitions previously noted. We anticipate an uptick in sustaining CapEx in 2026 with a range between $290 million and $330 million. This will occur over 493 outage days across 39 planned outages, 24 of which are from our gas facilities. The sustaining CapEx positions our business to capitalize on strong market fundamentals beyond 2026. This will be accompanied by a 2% dividend increase in 2026, subject to Board approval.

Overall, the guidance range reflects our confidence in our business strategy and our ability to deliver and generate strong financial results that position us well to capitalize on future growth. As you've heard throughout our presentation, we have multiple pathways to be able to deliver our 8% to 10% AFFO per share growth targets. Our outlook is powered by operational discipline at every level. Steve walked you through how our asset optimizations and best-in-class operations team deliver reliable, safe, efficient megawatts, the foundation for everything that we do.

Jason and Andrew demonstrated how we capture and lock in value through commercial excellence and recontracting, with a potential $1 billion-plus annual opportunity on existing assets. Roger highlighted how disciplined M&A and post-acquisition optimization scale our platform for long-term growth. That's why we're confident in our ability to deliver on our 25-plus gigawatt pipeline, our 5 gigawatts of merchant upside in PJM in Alberta, and our 3 gigawatts of contracting and other upsides. We are very well positioned to convert this into long-term reliable cash flow growth. This is the Capital Power edge.

With that, I'll turn it over to Avik for closing remarks.

Thank you, Scott. With our advantage, we're confident in our ability to deliver industry-leading performance, driving returns for you, our shareholders, underscoring our growth and value creation strategy by 2030, I want to affirm that we are targeting the following: 8% to 10% cash flow growth, 50% U.S. growth through additionally owned capacity of 3.5 gigawatts, and finally, 13% to 15% TSR. That's a 100 bps CAGR from our 2024 Investor Day last May. This is why Capital Power is one of the best long-term natural gas plays in North America.

Thank you, Scott, Jason, Andrew, Steve, Roger, for sharing your insights and expertise today on behalf of our 800 other colleagues who are working across our fleet and offices across North America. As you've heard today, Capital Power is one of the best positioned IPPs to create long-term shareholder value in the North American energy sector. We have a proven platform, industry-leading expertise and a demonstrated track record of execution that's delivered enhanced value creation well over a decade. That is what sets us apart. And our advantage is our shareholders' advantage.

Today, North America needs more power, and natural gas is critical to meeting this demand across the continent. Capital Power has the track record, strategy, expertise and momentum to continue to meet this demand through delivering strategic growth through acquisitions. We have an unparalleled ability to deliver excellence across asset optimization, commercialization and enterprise optimization. That's what we refer to as our optimization pathways. When put together, this platform enables us to methodically add value beyond just the front-end acquisition. That results in the top line returns that we provide to our shareholders. With our bold strategy and relentless execution, we are positioned to win.

Before we kick off with the Q&A, I'd just like to offer a couple of quick acknowledgments. First to Roy and Noreen. Roy and Noreen, over the past 2 years, have done an absolutely phenomenal job of being the front-facing stewards of our Investor Relations program. And many of you whom interact with us, they are our frontline. I just want to acknowledge the phenomenal work that both of them do. So thank you to both Roy and Noreen.

And then lastly, I would like to acknowledge Sandra Haskins, who is retiring at the end of the year. And as our CFO and a long-tenured employee of Capital Power over the past 24 years, has made an incredible mark on our organization and the industry at large. So Sandra, thank you.

So with that, we'll kick off our Q&A. We'll be taking questions from those in the room. Please raise your hand if you have a question, and a mic will be brought to you.

It's Ben Pham, BMO Capital Markets. A couple of ones from me on the U.S. merchant acquisition allocation process. I mean, historically, you've been more contracted gas and extending contracts and creating value through that. Could you talk about this newer strategy in a sense? I don't how many hills versus the contract strategy? Is it better to buy merchant over contracted gas assets? A bit more color would be appreciated.

Yes. Thanks for the question, Ben. So as Roger alluded to in the growth section, we see this amazingly great opportunity to acquire assets at a value significantly lower than what new build is. That was the spread between, call it, 1,000 a kW between -- and 2,500 a kW newbuild.

Our historic strategy was a merchant portfolio in Alberta and contracted portfolio elsewhere. As the market has tightened, and we see more demand growth, the opportunity to acquire assets like MCV, like Rolling Hills, where they have lower capacity factors and opportunities to apply asset optimization, opportunities to wholesale, opportunities to recontract, we see those more in merchant assets.

So as Scott mentioned, our adherence to and commitment to our investment-grade balance sheet is as pronounced today as it always has been, but the opportunity to be able to acquire merchant assets, and now do that in partnership with Apollo, gives us an opportunity to accumulate an inventory of assets that has significant internalized growth opportunities. And so we see a very compelling opportunity to continue doing that.

So for us, it's maintaining that mix of contractedness merchant, exposure in the aggregate portfolio to maintain our balance sheet strength, maintain our ability to support our dividend, maintain our ability to reinvest cash flow, but we also see this growing opportunity to accumulate assets that are merchant that have more runway in them than a contracted asset would.

And maybe a follow-up on that, sticking with the U.S. gas merchant, Apollo. Opportunity, you've mentioned you can certainly do acquisition yourself, CPX 100%. And you mentioned early too, just how you think about the 2 pathways. But can you clarify a bit more at context on what is the right for CPX 100% versus going into Apollo?

So the Apollo JV is focused on U.S. merchant assets. And specifically, for those assets that we can't acquire wholly and require a partner, we've come to agree with Apollo that we will pursue those opportunities together. I'm less focused on what we can do stand-alone. I think this opportunity is a phenomenal opportunity to partner with a world-class investment firm who sees the same thematics at play as we do. And we get to lock arms and go pursue these assets together, whereas historically, our approach would be each and every asset, in particular, ones at scale, we would have to pull capital together, find a partner once we've identified and advanced in the process.

Whereas now, we get to accelerate our approach, we enhance our overall capacity to pursue these types of assets, and frankly, we can do more faster and larger deals in partnership with them. But to specifically answer your question, it would be the difference between a contracted asset and a merchant asset. We're primarily focused on merchant in partnership with Apollo. So if we were to do something solely, it would be something that's more contracted in nature.

Nick Amicucci with Evercore ISI. Avik, I just wanted to try and parse out a little bit, just on the 16 gigawatts of current M&A pipeline. I think Roger had mentioned existing partnerships, single asset opportunities and platforms. Can we break that down just kind of -- even directionally? And as well, if we can just kind of get a sense of where the enhancement in margin opportunity lies amongst those 3?

So we haven't broken it out specifically in buckets, but I'll describe them. So the existing partnerships would be assets we already own in partnership with others. So the opportunity, to the extent they're financial partners, they will all generally have explicit hold periods, and we'd look to be the partner of choice there. And in the other 2 buckets, that's why we walk through the value proposition of our asset optimization pathways.

Each and every asset that we've acquired since 2016, we've been able to acquire and identify those asset optimization pathways, whether it's asset upgrades, efficiency upgrades, enhancements, expansions, repowerings. So when we acquire an asset, we've been consistent in our communication to shareholders around when we buy things, we typically model them based on what we see as a 5-year forecast run rate average EBITDA. And generally, we've been able to deliver 6% to 8% AFFO per share accretion off of those.

Well, what comes -- what contributes to those accretion dilution numbers, which is why we show the 4% to 6% increase from buy-in to output is our ability to go in and recontract that asset, upgrade that asset and better trade around it. And that's how that all rolls together. So when we look at that internal opportunity and the external one, it's a combination of assets in the market, bilateral relationships that we're talking about bespoke deals and then what's inherent in our partnered portfolio today. Does that answer the question?

Yes.

Rob Hope, Scotiabank. I want to go back to the merchant versus contracted balance. So Slide 64 shows kind of the breakdown between renewals and natural gas, very skewed to natural gas. What would that look like on merchant versus contracted? Really, what I'm trying to get at is, do you need to add a little bit of contractedness just to keep that balance in the overall portfolio?

Well, it's interesting, actually, when you look at the allocation, so renewables today will be 10%, and we're looking at that the allocation of 20%. So the 80-20 split, to answer your question specifically, no, it doesn't really make a difference because as Scott said, in the finance section, our average contractedness is 9 to 11 years. And so when you look against our investment-grade balance sheet and how we manage our 2 metrics to maintain that. When you're allocating to such a small percentage of that overall portfolio, it takes a lot to move that needle on overall contractedness.

Why we like renewables isn't because of contractedness. We do see, over the medium term, a convergence of the sectors, which we're all going to be in the business of delivering power. We're focusing here on natural gas. But in the markets we are an important player around natural gas generation, we do see the benefits of having a renewable portfolio and a renewable strategy that supports it. So it's not inherently because of the contractedness it brings. It's because we strategically believe that if we're going to commercialize megawatts, we need to be able to be in that business and be able to play in that stack.

As I said in the beginning of my section, it's going to take all kinds of technology. Gone are the days you could be a fossil player or a clean player. Today, we're emerging into the marketplace that you have to be able to deliver electrons, you have to be able to understand complex regulatory and market structures, and you have to understand complex transmission and distribution systems. And so we're in the business of building, managing, operating and delivering electrons. So you cannot not be in that business, and we see a strategic benefit to being in it.

All right. And then maybe switching gears, going back to the Apollo partnership as well as your goal to get an increase of 3.5 gigs. It seems that the 750 megawatts over 5 years -- or $750 million over 5 years, like as a -- is something that could be probably larger. Maybe can you speak to how we got to that $750 million, and it does appear to get to that 3.5 gigs, you're going to need more than that?

Yes. So the way I would describe the partnership is it's USD 3 billion of equity, of which we're committing up to $750 million, and Apollo was committing upfront $2.25 billion. But there's flexibility within that. So $3 billion of equity, if you conservatively consider leverage in that at 50-50, $3 billion becomes a USD 6 billion war chest to go acquire assets. What we have in place in the JV is an ability asset to asset to scale our ownership interest from 25% to 50%. So whether that number goes above $750 million and we deploy more capital, there's flexibility from Apollo and from us to make that work. But we wanted to ensure upfront was a commitment that worked well within our own funding capacity over the next 3 to 5 years.

Maurice Choy from RBC Capital Markets. I'm just going to ask both my questions right here. The first one is on Apollo, second one is on funding. On the Apollo MOU, can we just come back to how this MOU came about in the first place? How you chose Apollo versus other alternatives? Where your investment criteria risk models may align or differ?

And the second question on funding. There's clearly a lot of capital requirements here. And just your view about funding plan for all this, including capital -- including common equity issuances and asset sales? And what is the credit metric guardrails here, debt to EBITDA or FFO debt?

Great. Why don't we -- Scott, why don't you start on the last one on credit and then I'll come back to the Apollo JV?

Sure. Yes. In the near term, very well positioned. So our floor from an FFO to debt perspective is 20%. We've got cushion above that. So the inverse, when you look at debt-to-EBITDA target to be in the mid-3 range, we have incremental capacity from a hybrids perspective as well. And our business generates significant free cash flow. So when you look at 2026, for example, you take the middle of that AFFO range, call it, 950, you take dividends off from that net of the DRIP, you're still going to end up with about $600 million in discretionary cash flow. And as Avik talked about the leverage perspective, so at 50-50 leverage, that allows you the opportunity to do well over $1 billion with your existing balance sheet in place. So very well positioned from that perspective.

Thanks, Scott. So in terms of Apollo, when I rewind the clock back to 2023 when I joined the company, we have a company that, for well over a decade, has a great track record of acquiring assets and optimizing them. That's been our ethos since inception. And we also have this demonstrated success of being able to find creative financing solutions to pull together assets we want to acquire. And that's been reliant on partnership capital from great financial institutions like BlackRock and Manulife. But it's been a strategy that was primarily focused around finding capital when we find an asset and being in competitive dynamics that were much less competitive in the 2010s, frankly. So in many instances, they were limited buyers for assets, and we had the luxury of time and flexibility to pull that capital together once we were in processes.

And as the market started to evolve over the last couple of years and the market became more and more competitive, and our success and track record of delivering against this acquisition strategy and gas became more public and our competitors saw our capabilities there, we've been approached by multiple parties over the last couple of years. We could have entered into a partnership at any point in time in the last couple of years, but the value proposition for us was what problem are we trying to solve.

And so what we're really excited about Apollo and why we landed with Apollo was they brought a constructive and creative solution to the table that solved our issues. And our issues were the following: we wanted to be in a position to acquire more assets without compromising our balance sheet and our investment grade credit rating. And we wanted to be able to go into process processes with that established partner in hand. Secondly, we wanted a partner that understood and was invested in the same thematics that we are, that had flexible balance sheet, flexible pools of capital to bring that to bear and relationships across the broader infrastructure space, including hyperscalers, utilities and the broader financial community. Apollo brought that to bear.

And then thirdly, if we were going to commit ourselves to a partnership and a vehicle, have some form of enhanced return profile for our shareholders for bringing and being able to monetize those operating skills that we brought to the table and to that partnership. So whereas before, when you're raising capital, when you have a deal and you've got a deadline coming at you more quickly than you can talk to multiple parties, we were able to capture all of that in the partnership with Apollo, and have an aligned partner that wants to grow an asset base and recognize the value of what we brought to the table.

Just a quick follow-up. Is this an exclusive agreement where you cannot pursue something outside of this JV? Or is this one where they get first rights? And if they say no, you can pursue it with other partners?

So upfront, we are exclusive with them for a period of time until we hit definitive agreements, but it's solely for projects that we don't -- that we require a partner for. So it's much more complicated than just that straight answer. But we intend to -- any acquisition for a gas-fired power plant, that's merchant that we require a partner, we intend to work with Apollo on.

Mark Jarvi from CIBC. In terms of the 8% to 10% per share cash flow, when you guys think about forecasting that, how would you internally think about the uplift from the existing assets or capital light versus capital intensive growth?

I wouldn't -- maybe to take the first part, not the last part. We think nearly half, over the next 5 years, will come from internally generated opportunities to either upgrade, upgrade or expand within the perimeter of our existing fleet. So that will have some component of capital intense in capital light as we described in that section. But those are the most accretive opportunities in the entire fleet because it's within the footprint of our existing fleet.

And then in terms of the doubling of the U.S. capacity, again, internally, how do you see the split between acquiring new assets versus leveraging existing assets and just conviction level on repowerings at this point?

I would say there's no repowerings within that window included. So it could include expansions and acquisitions, very levered towards acquisitions. But as we described that 3 gigawatt opportunity set within the existing fleet, there's timing, you'll have to apply your own risk to how and when that comes into play, but it's what gives us the confidence on forecasting out the AFFO because there's multiple ways to win there, whether it's recontracting expansions, PPAs with data centers, or the acquisition to support that.

Last question was just you talked about competitive dynamic, some more competition for assets, but lots of opportunities to create upside. How would you define going in IRRs today in the upside case for those versus maybe 2 years ago?

So what's really interesting about that, Mark, is that our underwriting case is pretty much the same as it was before. So when we came into our last Investor Day, we reaffirmed our TSR around 12% to 14%. And our underwriting approach was look at a 5-year average EBITDA. And generally, we were underwriting some form of a recontract. And in aggregate, we were looking to get a 12% to 14% return. Our realized returns have been mid-teens across the board.

So today, when you look at the value appreciation, Roger made mention to the clearing price on some CCGTs at $1,500 a kW. Over the last 5 years, you more anchor on CCGTs at, call it, $900 to $1,100. When you do the math on that, what hasn't changed in IPP land in the U.S. over the last 5 years is funding availability. Primarily, on a single asset basis, these assets are getting funded with Term Loan Bs. So your funding model is, at best, 50-50, 60-40 leverage to equity. So if I was borrowing $550 a kW for a PJM asset 5 years ago, even though the capacity market is now double, triple, quadruple, I'm still able to borrow that same amount.

And so unlike other industry verticals where you've got top line revenue increasing, value multiple -- valuation multiples increasing, equity value increasing, you generally see the funding availability -- debt funding availability go up. We haven't seen that in gas-fired generation as much because you have to post ISDA, you have to post LCs, you have to hedge, and the leverage model clears, sweeps all the free cash flow back to the lenders before equity participates.

So the value increase that we've seen is really a pass-through on the first, call it, PJM, for example, the capacity market. So the PV goes up $1,000 a kW to $1,300 a kW, that's basically passed through on the capacity. So the equity is still taking the same risk. Can you own it? Can you go add value to it? And how are you playing the capacity versus the energy market? So when we come out and say that asset we're buying at $1,300 a kW and we're roughly taking the same risk, underwriting the same value proposition, it's the same as when we did it 2 or 3 years ago, the difference is the lender is the one that you're passing through those first dollars on. It's a long-winded answer, but it's a question I get a lot. So I thought I'd take a minute to describe how we think about it.

Tanner James at Jefferies. Sorry. Just a question here, maybe following up on Mark's question, specifically on some of the very recent bid-ask activity that you're seeing for existing gas assets. We heard from GE Vernova yesterday, some recent greenfield order and pricing acceleration that they're seeing specific to the fourth quarter. And you identified on the presentation, this near-term dislocation between brownfield and greenfield. Just to what extent is there a flow-through of this price that could potentially occur in real time to the existing assets? Or conversely, maybe as we're thinking about the M&A market at large, could this price movement perhaps further dislodge existing assets, albeit as you're moving within or above the $1,000 to $1,500 a kW range in the market currently?

I don't think it actually dislodges, I think it goes the other way. And the reason why I believe that is -- so turbine orders have gone up. IRPs are getting updated every year now. And load serving entities are trying to figure out how do I bring forward capacity into rate base. And yet we've got 550-plus gigawatts of capacity that's being used 1/3 of the time effectively in the U.S.

What we're not seeing, at large, is 20-year PPAs for all those turbines being ordered. And so the game here today, more than any other time in the last 25 years, is how do you recontract assets, how do you work with load serving entities and how do you be a bridge to offtakers to help make it all work? So whereas historically, IPPs versus utilities was a zero-sum game, today, I don't think it is anymore.

And I think the proof point of that is what we were able to do in partnership with CMS in Michigan. Historically, relationship between an IPP and a utility would have said, "Look, I'm going to contract this out," and that's at in opposition to what their plans are in terms of what they want to add to rate base. In this situation, we proactively went to CMS and said, "We have this asset. We could recontract to you. We'd like to do a data center. How do we help you help us? How do we make this work for the market, for you, and for us and offtakers?" And those solutions, I think, are what are going to manifest themselves into that conversation.

So if it's a utility ordering turbines for a rate base, there's going to be opportunities to contract existing supply, and we're going to see that convergence. We may not see it in terms of duration. So we may not get 20-year contracts on existing supply, but we will certainly have to get 10 to 20-year contracts. And if there's opportunities to operate, repower, expand on existing sites, that will always get done before a new build. Why? Because I can put it online, faster and cheaper than that new build.

Pat Kenny, National Bank. Avik, just wanted to get your thoughts on this recent push here to build out Canada's data sovereignty. So now that we've got the grand bargain, MOU and the Alberta government formulating a game plan by July. We had Microsoft's announcement earlier this week. Just curious what that could mean for your Alberta or Ontario fleet in terms of contracting opportunities, and maybe you can speak to what you see as your competitive advantage for offering these customers, maximum data security and redundancy.

Yes. Our federal government has been unequivocal in the importance of building infrastructure in Canada, increasing economic productivity in this country and the importance of data sovereignty, in addition to national defense. When we embarked on this journey on data centers in Canada, we saw an incredible opportunity in Alberta because all of the physical economic infrastructure ingredients were there to create a large ecosystem to support AI build-out. But we had a big problem, and that problem was the clean electricity regulations physically prevented any build-out of natural gas generation anywhere in the country because it, in fact, wasn't net zero, it was physical zero by 2050. And so we had this challenge.

Now at Capital Power, we had the advantage of having what's probably one of the best sites in all of North America at Genesee because we had overbuilt through repowering and we have 500 megawatts of available capacity today, access to transmission and distribution, access to water, physical acreage and footprint to go co-locate data centers. So the announcement between Alberta and Canada is a formidable one in that it allows us a pathway to building new natural gas-fired power generation in Alberta. We need to complete that process and solidify what a carbon regime is under that exception. So that's yet to be done.

So today, I don't have an active data center project in Alberta similar to where we were in June, but I am much more excited about the proposition going forward once we resolve that. The data sovereignty piece just adds a -- other layer to it, which is the national importance of having that capacity here inside our borders. But fundamentally, Alberta was an attractive regime. It would have been 3 or 4 years ago, a Tier 4 regime. And today, it has the opportunity to become a Tier 2 regime with speed to market as the critical advantage.

What I would also say, and I think is the most important point, is the advantage for Alberta today is one thing and one thing only, it's speed to market. So what data sovereignty focus in Canada does is it adds a longer tail.

Right. And the 250-megawatt MOU announced today, I mean, you alluded to the fact that that's just a fraction of your capacity at Genesee, let alone your Alberta portfolio. So how should we be thinking about, perhaps within that MOU, ramping up phases beyond 2028? Or adding new customers, new MOUs as we go throughout the years.

Well, the way I think you should think about our Alberta portfolio is we have the youngest, most efficient and largest fleet in the entire province. So our ability to commercialize megawatts for customers is better than any of our competitors, on top of which we have an investment-grade balance sheet. So if you are a counter party wanting to invest billions of dollars into Alberta and want a sound counterparty to contract power with over a long term, we're a pretty good counterparty for it.

And so the 250 megawatts and rewind the clock back to June when we elected not to pursue a sub-400 megawatt data center, is we didn't pursue it because we felt this was the best way for us to maximize the opportunity for our shareholders. Our business is selling power. We happen to have one of the best locations for a data center at Genesee and we will monetize that when appropriate. But the best way to leverage this opportunity set is for us to sell power for longer for higher prices.

So from our standpoint, I think it's a macro call on Alberta. Do you think that market is going to tighten. And then the second question is who is going to benefit from it. I would argue we're best positioned to benefit from it, to the extent there's going to be customers that need long-term suppliers of electricity for balance sheet, for scale and efficiency of our fleet.

I don't know, Jason, do you want to add anything to that?

John Mould, TD Cowen. Sorry, I'm over here. Maybe just following up on that question a little bit, and apologies if I missed this, but do you have time line for when you're hoping to finalize that 250-megawatt MOU? Is there a potential to expand it further? And I guess, in your -- this is kind of a 2-part question, I guess. But in the context of your comments just now on Genesee and the opportunity set that it presents, how does that MOU play, I guess, effect, I'm going to use that phrasing, the potential for you to do something broader down the line at Genesee and beyond clarity on this Phase 2 process with AESO. What else needs to fall in place to allow you to maximize that optionality of the Genesee site more broadly?

Yes. In terms of the MOU, the MOU does not, in any way, impede our ability to go do a data center at Genesee. Just think of it as our normal course business of commercializing megawatts from a fleet that does 10,000 gigawatt hours a year. So it's our normal course portfolio optimization. It just happens to be with a investment-grade data center or counterparty that needed long-term power. So that's point one. We expect to conclude it sometime in 2026. And yes, we think there's potential for expansion there with that party or others.

So I think for us, what's important is we've maintained full flexibility here and demonstrated that the opportunity set is there for Alberta. And really, the most important point is we expect a tightening market in Alberta, and we expect to see that over the course of the next 3 or 4 years, and this is the first step of that. So Jason talked about that tightening market and the impact on our own spark spreads and margin. And we -- as you saw in that spark spread graph, in 2026 is the trough. But after that, we see a significant upside in that portfolio that's going to require 0 CapEx from capital power. So that investment in repowering, we start seeing the fruits of that investment really coming through '27 to 2030 and materially so.

Okay. And maybe then just one on your broader approach to M&A. When you're looking at gas-fired M&A, how do you consider the potential for solar plus storage to cannibalize the reliability attributes of gas-fired power over time? And even though it's really long dated, it will throw in SMRs as well just for completion.

So SMRs aren't going to get done until 2040 plus. So that's my answer on SMR. It's going to be an important player in the markets that already have established nuclear as a regime. But for context of wholesale markets, where you're 20 million a megawatt, it's not going to be a significant player.

Solar and -- solar plus storage, I mean, the perfect poster child for this is what we've seen play out in places like California. So what solar and storage does is it flattens the duck curve, right, the peak versus trough demand. So we see less of those high-priced hours at play. We've seen that in Alberta as well, not because of solar plus storage, but because of how much renewable capacity we have in that market.

The challenge in many of these markets is going to be voltage stability for the underlying grids. So there's a capacity constraint to what you can do in solar and storage. So on the margin, it's going to negatively impact pricing outlook, the more solar and storage we do, but it doesn't change the reliability imperative around natural gas. So what it will do is it will deter price signals for new build, but I don't think it will change the underlying economic proposition for existing capacity. Existing capacity will win 100% of the time for 2 reasons. It's installed -- actually 3 reasons. It's installed, cheaper and faster.

Great. Well, if nothing else, once again, thank you for attending this snowy, wet morning here in Toronto. It was a pleasure to host all of you. Thank you for your time. We know you've got lots of really important things to do, and it means a lot to us at Capital Power that you choose to spend your time with us and choose to invest in our 800 people who are powering change by changing power. So thank you all, and look forward to having a conversation after.

Good day, and thank you for standing by. Welcome to the Capital Power Third Quarter 2025 Analyst Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. speaker today, Roy Arthur. Please go ahead, sir.

Good morning, everyone. My name is Roy Arthur, Vice President, Strategy, Planning and Investor Relations at Capital Power. Thank you for joining us today to review our third quarter 2025 results, which we published earlier today. Our third quarter report and presentation for this conference call are available on our website. During today's call, our President and CEO, Avik Dey, will provide an update on our business. Following that, Sandra Haskins, our SVP Finance and CFO, will present a review of the quarter and the financials for the company. Avik will then conclude the formal part of the presentation before we open the floor to questions from analysts in our interactive Q&A.

Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to our cautionary statement on forward-looking information on Slide 3 of our regulatory filings available on SEDAR.

In today's discussion, we will be referring to various non-GAAP financial measures and ratios also noted on Slide 3. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used in other enterprises. These measures are provided to complement the GAAP measures, which are included in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in our integrated annual report.

We acknowledge that Capital Power's head office in Edmonton is located within the traditional and contemporary home of many indigenous peoples of the Treaty 6 region and Metis Homeland. We acknowledge the diverse indigenous communities that are in these areas. Their presence continues to enrich the community and our lives as we learn more about the indigenous history of the land in which we live and work. With that, I will hand it over to Avik.

Thank you, Roy. Good morning, everyone, and thank you for joining us. Before I begin, I'd like to thank and recognize our people who power our strategy forward and deliver on our growth and long-term resilience each and every quarter. The success we have achieved would not be possible without their efforts. I will also take a moment to acknowledge the upcoming retirement of Sandra Haskins, whose leadership and contributions have been instrumental to Capital Power's success I'll share a few more words about Sandra at the end of today's presentation.

With that, I will now review Capital Power's 2025 third quarter results. This quarter perfectly highlights our strategy in action. With execution and value creation on multiple fronts, including contracts for assets with terms to 2040 and beyond in Canada and the U.S. and more recontracting opportunities in the near term. These efforts clearly demonstrate our ability to enhance contractedness across volume, price and duration.

This quarter, we have further strengthened our position as one of North America's leading independent power producers. Key highlights for the third quarter include advancing commercial optimization with the execution of a long-term contract with improved economics for Midland Cogeneration Venture. This extension enhances visibility of future cash flows and demonstrates our ability to unlock value for existing natural gas generation.

Also commissioning our first 2 Ontario battery storage project at York and Goreway, adding 170 megawatts of capacity contracted through 2047. And delivered on time and under budget. These projects enhance our contractedness, portfolio diversification and Ontario's grid reliability. With an excellent safety record after nearly 12 months of construction, these projects are a testament to our project execution capabilities.

Continued construction of 3 solar projects in North Carolina, all on schedule and within budget, demonstrating our commitment to enhancing our renewables platform. The successful financial integration of our newly acquired PJM assets, Hummel Station and Rolling Hills, the largest acquisition in our history. These facilities performed above expectations in their first full quarter contributing meaningfully to adjusted EBITDA and adding over 45 new employees and contractors to our legacy of operational expertise.

And finally, we generated 13.4 terawatt hours across our portfolio and completed 65% of planned outage days for the year. As we talked through our accomplishments, a consistent theme emerges of long-term lower risk growth across our portfolio. And at the core, we have this compounding growth of energy expertise and knowledge from the people at Capital Power.

Together, these achievements reinforce our team's ability to consistently deliver, diversify our portfolio and execute with discipline to drive long-term shareholder value. In September 2025, we executed a new long-term contract with improved economic terms for Midland Cogeneration Venture, the largest natural gas fired combined electric and steam generation facility in the U.S. extending the contract to 2040 and providing 10 years of incremental contracted revenue. Michigan is an attractive and growing market for electricity. This contract is an important milestone for Capital Power as it reinforces the critical role of fished natural gas assets like MCV play in maintaining grid reliability as power demand grows.

Starting in June 2030, MCV will receive enhanced payments under a new PPA for 1,240 megawatts or approximately 75% of its capacity. This will provide long-term revenue stability and increase annual adjusted EBITDA by roughly USD 100 million, an 85% increase over current contract pricing that the facility received today. When we talk about recontracting our assets, we often talk about preserving optionality for other opportunities. We are excited to see one of those opportunities advancing with a signed letter of intent with a leading colocation data center developer for a potential 250-megawatt project, highlighting how our flexible generation platform can serve new load growth reliably and efficiently. This presents an opportunity to secure superior economics from contracted capacity and build a relationship with a leading colocation data center.

Developer. The MCV recontracting and other near-term recontracting opportunities tell a very clear story. That our strategy of commercial optimization is delivering. We can extend contracts, improve economics and secure long-term visible cash flows across core markets. all without taking on new build risk. It's a disciplined way to create value while strengthening the reliability customers depend on, and it builds on the theme of long-term lower risk growth in years to come.

This quarter, our battery energy storage project achieved commercial operations. We are proud to add the 120-megawatt York and 50-megawatt Goreway best project to the Ontario grid, strengthening reliability and adding a new technology to our asset base. Not only were these our first-ever battery storage project, but they were also delivered on time, under budget and with an excellent safety record, a testament to our team's discipline and execution.

Contracted through 2047, these facilities will add approximately $35 million in annual adjusted EBITDA over time. In addition to achieving operation of our best assets, we completed 70 megawatts of capacity upgrades at York and Goreway with contracts to 2035. Through our various growth and recontracting efforts, this portfolio has extended its weighted average contract life from approximately nearly 5 years to 11 years.

Together, the Ontario projects demonstrate how our expertise in gas renewables and storage come together to deliver reliable, flexible power and long-term value. Our disciplined approach is driving success across our North American platform. It's another example of long-term lower risk growth that we believe we can continue.

In our first full quarter under Capital Power ownership, the Hummel and Rolling health facilities achieved financial integration and delivered a strong adjusted EBITDA contribution performing ahead of expectations with higher dispatch and strong pricing.

The energy price outlook in PJM is strong, and we continue to crystallize value for these assets using hedges with investment-grade counterparties having put in place approximately 9 gigawatts of hedges through 2027. We're also encouraged by continued strength in capacity pricing coming in at the cap of $329 per megawatt day for the '26-'27 auction, approximately 20% higher than the '25-'26 auction.

The operation optimization and integration of Hummel and Rolling Hills demonstrate another clear example of our disciplined growth and ability to execute, and it's reflected in the strong financial results Sandra will walk you through next.

Thank you, Avik, and good morning, everyone. Our third quarter results highlight the strength of our diversified portfolio and disciplined execution. We continue to deliver on what we said we would do: growth, stable cash flows and a balance sheet that supports future expansion.

In Q3, adjusted EBITDA was $477 million up approximately 20% from the same period last year. This increase was driven by strong contributions from our U.S. flexible generation portfolio following the addition of our PJM assets. The gains in the U.S. flexible generation portfolio were partially offset by lower results from La Paloma and Decatur, which were driven by generation.

AFFO for the quarter was $369 million, up approximately 20% year-over-year reflecting higher adjusted EBITDA, current income tax recovery and partially offset by higher finance expense. For the 9 months of 2025, adjusted EBITDA totaled $1.166 billion, 15% higher than the same period last year, driven by the same factors impacting Q3 and lower emission costs and corporate expenses. AFFO for the 9 months ended September 2025 was $882 million, up 40% from the same period last year driven by the same factors impacting Q3 and a credit for parts at La Paloma and settlement of the off-coal compensation.

The 2025 year-to-date financial performance positions us well to deliver strong 2025 results. To ensure portfolio reliability and better position our business to capitalize on stronger market fundamentals beyond 2026, we are updating the Alberta plant maintenance schedule. Updates to the maintenance schedule include an outage on our G3 unit in Q4 of 2025, previously planned for 2026. This will allow G3, which is the most efficient coal-to-gas converted unit in Alberta to be available through 2026 when we are conducting planned outages on all our other units in our Alberta portfolio. All newly installed turbines such as those at Genesee 1 and 2 undergo an infancy period, during which greater monitoring and maintenance is required to ensure long-term smooth operation. As such, G1 and G2 will have previously scheduled maintenance outages in 2026 extended but will still allow for normal operations in the interim. For Canadian flexible generation, the 2026 maintenance schedule will include approximately 40% more outage days than in 2025 and with an expected capital cost of approximately $25 per kW of nameplate capacity.

For our U.S. flexible generation assets, we expect sustaining capital costs of approximately $30 to $35 per kW of nameplate capacity for the same time. While elevated compared to prior years, we believe this investment to be prudent to maximize asset life and efficiency, and we expect cost on a dollar per kW basis to decline in future years closer to $25 per kW on average across the fleet. It is also important to note that these costs are consistent with our expectations and do not reduce our view on the return potential for our assets that we have conveyed in the past. Current Alberta forward pricing indicates that implied spark spreads for Alberta merchant capacity are projected to rise by approximately 90% between 2026 and 2028. Earlier this year, the same forward suggested a more modest increase. The shift in expectations strengthens our conviction that 2026 is the optimal window for executing these outages. From both operational and financial point of view, this approach best positions us to capitalize on strengthening fundamentals in Alberta beyond 2026.

Despite updates to planned outages and delays on Alberta projects, we are reaffirming guidance ranges that we updated in Q2 across our key metrics. For 2025, we continue to expect adjusted EBITDA between $1.5 billion and $1.65 billion. AFFO between $950 million and $1.1 billion and sustaining CapEx between $215 million to $245 million. These ranges reflect strong execution year-to-date and confidence in our diversified portfolio's ability to deliver stable growing cash flows. With that, I'll hand it back to Avik to conclude the call.

As we reflect on the third quarter, it's clear that 2025 has been a year of delivery. We've completed all our priorities for shareholder value creation as outlined on our January guidance call, from strengthening our U.S. platform to securing enhanced long-term contracts. The story here isn't just about individual milestones. It's about the strength of the collective, the team and the consistency. Our platform is doing exactly what we designed it to do, generate stable contracted cash flows while maintaining flexibility to capture upside in dynamic markets. That's the value of scale, diversification and disciplined capital allocation working together.

Today, Capital Power stands as one of North America's top natural gas focused independent power producers. With a 12 gigawatt portfolio balanced across 5 core markets and backed by an experienced and passionate team. That balance allows us to manage risk, sustain growth and fund new opportunities, all while protecting the strength of our investment-grade balance sheet. Looking ahead, the foundation we built this year positions us to meet the accelerating demand for reliable power and deliver sustained value creation for shareholders in 2026 and beyond.

This morning, we announced Sandra's plan to retire from her role on December 31, 2025. Sandra has been an integral part of our company's story, growth and success. Since joining in 2002, Sandra has led with integrity, strategic vision and an unwavering commitment to excellence. We're immensely grateful for her 23 years of service. Congratulations Sandra on your well-earned retirement.

Scott Manson, our Chief Accounting Officer and Treasurer, will transition to Interim SVP Finance and CFO. A search for a new SVP Finance and CFO is underway, and a successor will be announced in due course. Sandra will support a smooth leadership transition by remaining in an advisory role until the end of Q1 2026.

Before we begin our Q&A, I'd like to remind you that we will be hosting our 2025 Investor Day event on December 9 and 10 in Toronto. Our Investor Day will provide a deeper look at how our portfolio of natural gas renewables and storage forms the backbone of reliability today and the foundation for growth tomorrow. We're excited to demonstrate how disciplined execution, thoughtful capital allocation and a focus on operational excellence will continue to drive superior shareholder value and we look forward to sharing our long-term vision and the next phase of Capital Power's growth journey with all of you in person. With that, I will hand the call back over to Roy.

Thanks, Avik. This concludes the formal part of the presentation. Operator, you can now begin the Q&A portion of the meeting.

[Operator Instructions] Our first question is going to come from the line of Julien Dumoulin-Smith with Jefferies.

This is Tanner on for Julien. Congratulations, Sandra. I just wanted to ask on the -- or start with here on the AESO large load Phase I, it's obviously in the pre-engagement phase. I just wanted to check in on your updated expectations for process. or ultimately, what could be the scope and how you're viewing -- how you're level-setting expectations going into the engagement phase beginning later this year.

Thanks for the question. As we've said before, firstly, we're excited about Phase 1 and potential parties coming into the province and really kicking -- kick starting the data center business. For Phase 2, we are going to be engaged. We think we're well positioned for Phase 2, given the excess capacity that we have at Genesee and we're overall constructive. As we said last quarter, we think the option value of our site at Genesee combined with the excess load that we have at Genesee positions us very well for that phase, but also just as importantly for anyone that's coming in through Phase I we believe we're best positioned to provide VPPAs for it.

So I would say initial indications on Phase 1 are positive, which leads us to be more positive on Phase 2. And at the end of the day, this is an infrastructure play. So our positioning of having generation in place that we're in the process of unlocking in addition to the attractiveness of our site. Ultimately, we think that positions us well.

Great. And maybe here, we can dive a little deeper into the discussion around MSSC, you mentioned in the quarterly report. Obviously, this proposed reform that's come up before and absent a technical solution, which I know you're exploring with AESO, it seems as though AESO kind of needs a philosophical change in its view of system risk due to singular unexpected failure or outage just prospectively, what are some signposts that we can look forward to indicate progress in these discussions or perhaps some evolution in AESOs thinking? And then should we still view long-term resolution of this issue as directly tied to FFR or [ FDR ] process outcomes?

It's a great question. Look, I think the AESO has been very constructive in their perspective on the MSCC (sic) [ MSSC ] limit to begin with was that for the G1 and G2 capacity originally, that 466 was the original capacity for G1 and G2. And I think the leading indicator on their constructiveness is going to be through the 2-way dialogue that we're having right now on the [ HESO ] solution because that will, one, validate single modal capacity over above 466, although our solution ensures that we work within the existing MSSC limits.

So as we contemplate, this will be part of the Phase 2 conversation as well. But I think overall, I think it's up to us to demonstrate the technical viability of our solution, which we feel very good about. As you would have seen in the AESO disclosures. We've gone through preliminary testing already. And the AESO has been very constructive in working with us as we work to really cements the viability of 1-odd option. And then secondly, for the broader market, address the limit of 466. and potential increase of it. So I can't say much more than that, but I think the biggest indicator is going to be how we perform on validating our own HESO.

Our next question will come from the line of Patrick Kenny with NBCM.

I guess starting with the co-location opportunity at MCV, just wondering if you could provide a bit more color on the potential timing for finalizing the PPA there and when the customer could potentially be online? And then also, if you could just remind us what the ultimate brownfield potential might look like for the site itself. And if you're able to scale this opportunity or perhaps bring in other data center customers over time as well?

Yes. Thanks for the question, Pat. As you know, the capacity at MCV is just over 1,600 megawatts. We've entered the long-term contract extension with CMS that speaks for 75% of that capacity. And then this 250-megawatt contract or LOI with the data center provider is a long-term contract in nature, but it does speak to 100% of the capacity at the site. .

We do see potential expansion opportunities in and around our plants at MCV. I can't speak to specifics around that. But in addition, I would say our customer here has broader ambitions as well. And I think part of the optionality of MCV site specifically is what's resonating. So I can't speak specifically to how many megawatts or acreage are available and what that pathway is. But what I would say is, although we haven't addressed pricing specifically yet on the contract, our outlook is quite constructive, point one.

Point two, we're talking about long-term contracts that are you can assume them to be well in excess of 10 years, closer to 15 years. And we've got capacity and access to transmission, distribution and potential upside in Michigan as well and at the site. So I think as we've indicated, we've got a handful of sites that all have this capacity and potential, and we're actively working to monetize those available megawatts.

Okay. Great. And then on the PJM assets, I think both Hummel and Rolling Hills ran at higher capacity factors in the quarter relative to your base guidance. Just wondering if that was just seasonal strength through the summer? Or if you're now thinking this higher level of generation might be sustained going forward? And if so, if you might be thinking about offering more capacity into the auction market this December from either facility?

Yes, we're not in a position to comment on what our plans for the upcoming auction are, I would say, early in terms of this past quarter, I would say you can presume it to be more around seasonality. But we're overall constructive of what we're seeing both in [indiscernible] and generation and dispatch of have been constructive. So I think the outlook for the auctions is equally constructive, but early signs are positive for the quarter and what we've seen.

Okay. And then on the Arizona assets, if I could, just curious, on the back of the recent Transwestern pipeline announcement, I'm wondering if that's helped spur any new commercial discussions with data center customers at either Arlington or Harquahala or perhaps accelerate some recontracting discussions with the local utilities just knowing that more gas supply is coming by the end of the decade to support the continued build-out of data center capacity across the state.

Yes. Look, in terms of affirming the long-term value of natural gas, I think this pipeline announcement is probably one of the biggest single data points for natural gas-fired generation in the U.S. in the last to 10 years, a major pipeline expansion, $5 billion project, 42-inch line only gets done with customers in place and offtake in place.

So in terms of our own position between Arlington and Harquahala, we've had very constructive dialogue over the last -- the course of the last 1.5 years on whether it's upgrades, recontracting, potential growth opportunities. And those continue. I wouldn't say that they're better because of the announcement of the pipeline. The fact of the matter is we've been in those conversations over the last 2 years and been part of that overall dialogue affirming load growth in Arizona and the need for more gas to serve those load-serving entities. So I would say there's continuing interest in the market. I wouldn't say it's more because of the pipeline announcement, but I think our conversations and others have been a contributing factor to the pipeline and the firming of the outlook for the market in Arizona.

Okay. Great. And Sandra, congrats on your upcoming retirement.

Our next question comes from the line of Benjamin Pham with BMO.

I also wanted to, first off, congratulate Sandra on the retirement as well. A couple of questions then on Alberta. If I can ask about that first. Look, with your maintenance schedule that you have here into 2026, is that really positioning for a different maintenance schedule beyond '26, i.e., instead of every 2-year cycle, you can just run the plants hard for 4 years to capitalize on the pricing situation?

No, Ben. It's not related to that at all. We did have scheduled maintenance plan for next year as normal course outages for those units. And what we're actually doing is addressing a larger scope of work just based on some of the identified operational changes that we want to make through the early days of commissioning. So they have identified incremental work that they want to do. And as a result of that, because the joint ventures that we have in Alberta are also going throughout each next year. It was going to be a really heavy outage year, which has prompted us to move G3 forward into 2025. It is an increase next year relative to what you've seen in the last few years where we've had relatively low planned outage days in Alberta as we went through the repowering of Genesee 1 and 2. As we get through '26 and '27 and start to see prices go up, we'll be at a period of time where we'll be back to a more normal cadence of outages at that point.

So the scope of work, of course, will be dependent on run hours and what have you. But it's more just addressing some of those issues early on, which is consistent with our maintenance and operational practices. So prudent that we address everything early on and be able to have the availability and reliability going forward. So this doesn't create an incremental delay or pushing out further maintenance just gets us back on to a more normal schedule as we get through this initial period.

Okay. Got it. And just give me your hedge position to you on your deck in the back and the 12 gigs for 2026, it doesn't look like just because you're shifting some maintenance around G3, [ Ford ]. It doesn't look like you're overhedged for '26, just doing a quick high-level math on, is that correct? .

That's right. We would be basically flat next year. So base load flat.

Okay. And then maybe last one, maybe some comments on the forward curve for a pretty big upward move there versus beginning of the year. Can you talk about the trading liquidity in those other years? And is that almost just Phase 1 being priced into the forward curve?

We did see a jump up after the announcement of Phase 1 in those later years. So that definitely is a driver just as well as just normal course you expect as more supply gets absorbed in the market, you do start to see prices move up. But yes, Catalyst is definitely the Phase 1 announcement. So as far as our hedge position and the liquidity, I would say we're more hedged than we maybe would have been when you're looking out through '27 and '28. Just given some of the longer duration hedges that we have. So the liquidity still is not as robust as you would see in the more near term. But yes, we're fairly significantly hedged in -- through '27 and to a lesser extent, when you get to '28 where we're more modestly hedged.

Our next question will come from the line of Maurice Choy with RBC Capital Markets.

Just wanted to come back to your comments on Phase 1 of the AESO large load connection. Earlier, Avik mentioned that you could offer VPPAs as part of Phase I. We also know that a third-party developer has secured over 900 megs of the 1.2 gigawatts of allocation. So can I first confirm if you still have your 375 allocation from Phase I. And if not, what the big picture strategy here is for you?

Yes, Maurice. I can confirm that we don't have our 375. We made note of that at the last quarter. In terms of what may or may not be captured. I can't comment on that because it's not been announced or listed -- or disclosed at AESO. But I think we feel pretty good that there are going to be projects in Alberta, and we also feel pretty good that for anything that needs to have an in-service date in '29 or earlier that we're going to be in a good position to provide them energy. Energy risk management or a PPA if and when they get announced.

Understood. And I would just follow-up to that. Like what do you think still remains in terms of the milestones before that gets announced? Is it just government policy? Is it just crossing the Ts and dotting the Is, how close are we to that to your VPPA?

Well, it's not our project. So I can't comment on where another project may be in the queue in their own negotiations. But I can say by virtue of our position in the market and our own decision-making around the 375, we understand that there's multiple projects in play that are advancing in the queue and will likely come out of the Phase I process.

And what I would go back to on this, Maurice, is the decision on the 375 for us versus maintaining option value on the 1000 it's really about our whole business plan and focusing on long-term contractedness and optimizing the value per megawatt at our plants, NTE per KW and long-term pricing. And so we do have a strong bias in Canada, in particular, towards these larger projects because we think they're more likely to yield long-term contracts. That's not the case in the U.S. because of how mature the market is there and how much capital and how many players are chasing capacity in that market, where Alberta is a new and emerging data center market we continue to favor scale because of the likelihood of converting that into long-term PPAs.

Understood. And maybe just to finish up on the same theme. There's obviously been a lot of discussion about potentially introducing nuclear energy in Alberta. I know that -- we've talked about this before by -- and I recognize that it's very early days.

From Capital Power's perspective, what do you see your role being? And what are the conditions that you need to see before potentially investing in this technology in the province?

Well, I think if we put technology aside, specific [ FFR ] technology and just look through it, the lens of is nuclear viable in Alberta. We've engaged in this. We've got a best-in-class partner with OPG and the province and the federal government have been supportive of us looking at the viability of nuclear in Alberta. The province has been very clear in its interest to determine the viability of nuclear in Alberta. And so we're still in that early phase of, a, consultation; b, validating the technology; and c, understanding how nuclear would work within the existing framework, the electricity framework for the province. .

So we do think that there is ultimately a role for nuclear. But we don't yet have the validation for how we would contract those assets in the existing energy-only market. But you can't get ahead of -- we can't get ahead of ourselves through the process. This would be a long-term commitment. We haven't had load like this. There's initial investment required to bring the industry to Alberta. And [indiscernible] has been to date that the existing market structure will continue, and you have to find commercial ways to bring in load. And so today, where these projects are longer duration, highly capital-intensive.

Today, they are not economic to do or to FID or spend material capital on. But as we look out, our role is to manage that load growth over 10, 20, 30 years from a system planning perspective and understand that technology and understand when and if it's approved as a viable technology, how do we ultimately commercialize it. So it's a long-winded answer to really say that today, it's not economic. We're excited about it. We're exploring it with best-in-class experts. We're collaborating with government, and we're keen to move to the next step. But from a capital power perspective in terms of capital allocation, we're putting risk capital towards it. It's not something we expect to do in the short to medium term unless there's something material that changes commercially.

Congrats yo both Sandra and Scott, we'll catch up at the investor day.

Our next question comes from the line of John Mould with TD Cowen.

Starting off, I'd just like to pass on my congratulations to Sandra. I appreciate all your hope over the years, and congrats to Scott as well. Going back to MCV you've been able to both extend that contract and have this potential colocation piece the merchant capacity. Looking across the rest of the U.S. fleet, are there other sites with similar characteristics where you can potentially do both? Or is it really more a case of one or the other, either extending your existing contracts or looking to do something on the colocation side. And in those markets, how does the customer appetite for the colocation solution compared with the interest you saw in Michigan?

Thanks, John, for the question. So we have multiple opportunities at multiple sites. So I would say in the range of outcome, the things that we're focused on are upgrades expansions, recontracting and the data center opportunity.

On our fleet, we have one or more of those opportunities on Hummel, Rolling Hills, Arlington, Harq, La Paloma. And I would highlight those as the ones that are most near term. What I would say, and this is something that we projected and advocated at our Investor Day in 2024 was we think that this is really about finding balanced energy solutions. And what that really means today is you have to work with and cooperate and collaborate with low-serving entities.

As we demonstrated in MCV. So for us, the way we're attacking this opportunity set is really talking to everybody and understanding how we balance the needs of our partners and fellow players in the market, load serving entities and what their objectives are with what our customers' objectives are, whether it's a data center provider or some other large loads. And finding ways we can make win-win solutions, whether it's through upgrades, expansions, working with load-serving entities and then ultimately marrying those opportunities with our own whether it's behind the fence colocation or grid integrated grid connected opportunities.

On the data center opportunity, specifically, as I've said before, we don't believe there's a large opportunity to do these data centers behind the fence because of reliability requirements. You can do it but the cost of generation to support 99.999% reliability will greatly exceed the economics of the price per megawatt to make that work. So we think being able to grid connect is a significant advantage. And then being able to work with stakeholders in those markets will be critical to successful outcomes.

It's once again why we're bullish on the Alberta opportunity set, because there is transmission distribution and whether our role is to sell power and/or provide a site that we can sell. This is what we've seen and learned in the U.S. market, and that's what we've been leveraging in our approach in Alberta.

Okay. Great. And then maybe pivoting to that Alberta opportunity. Just in terms of an early look on the Phase 2 pre-engagement, it seems like bring your own power requirements going to be likely in some fashion for Phase 2 to reach that gigawatt scale opportunity, if you did host something at Genesee, which would you need to add new build there. I note that in existing to the spare capacity you've got at Genesee 1 and 2, you do have a 1.5-gigawatt early-stage combined cycle project there in the connection list. So how are you thinking about that? And how do you think about the relative attractiveness of deploying capital into potential new build in Alberta versus additional gas M&A in the U.S.

Yes, great question. So one, we're not contemplating new build in Alberta as part of our entry into that Phase 2. Second, we could contemplate it if there was a customer for it. but you need to look at the life of these assets versus contracting terms. We would not take merchant exposure on new build in Alberta. Third, relative to the U.S. or Alberta, I think whether it's -- and I'll focus more on expansion and repowering than a straight new build because I think it will be unlikely we will take on a new build, unless we've got strong partners and a strong offtake agreement, but those opportunities seem more prevalent in the U.S. today than they are in Canada. But I think from the expansion and repowering perspective, we see those as better near-term opportunities because you've got a better line of sight of having, a, in-service date that meets the needs of the customers. .

So as we think about new build capacity in Alberta, the trick becomes, how do you look at a new build and have an in-service thing that meets the need of a customer. Again, that's why we feel so strongly about our position in the market. We've already paid for completed new build capacity through our repowering project in Alberta that's available now. And so we think that positions us very well relative to the market. But I think the new build piece for construction exposure or development capital exposure we have a bias to the U.S. market today.

Our next question will come from the line of Robert Hope with Scotiabank.

My congrats as well to Sandra and Scott. Maybe carrying on the conversation on Phase 2. Has there been any changes to the customers that you're speaking there or the level of support that you're seeing for your kind of next phase of projects for Phase 2?

No, I can't say we've seen a different owner of different conversations or more conversations. The interest has been there for Alberta. Now that we have the guardrails for Phase I and Phase 2, there continues to be interest. So I expect when we get better visibility on what came out of Phase 2 expect to see more interest in particular, around larger customers. But I would say we haven't seen more interest or less it's continue to be the same.

Okay. I appreciate that. And then just as a follow-up on that. So the Phase II process, as was outlined by the AESO is quite long. When you think about your positioning and the fact that you have 450 megs at Genesee that are unused right now, like is there a way to potentially fast track that process? And are you in consultation with the government or the AESO because your situation is a bit different than a pure, bring-your-own-power-solution.

I think overall, the AESO and the ministries have been constructive on how to go into Phase 2. And I think there will be some bespoke conversations with parties. I think our focus right now is very clearly getting our technical solution approved which will unlock us to 566. And then over and above that, we've got additional capacity available. So for us, the sequencing, which is independent of the Phase 2 process, is let's get our technical solution validated and let's get the AESO on board with our solution and get those volumes unlocked. And I think we'll have constructive conversations in Phase 2.

But I think most importantly, Rob, as you look at our portfolio, the way we look at it is whether it's through Phase 2 or Phase 1 and you look at the strip in Alberta on full price, our job is to go maximize value per megawatt on our plants and our dispatch. And so whether we're in Phase 1 or Phase 2 is less important than what's the probability we can go contract pricing, contract volumes at attractive pricing, short, medium and long term. So we feel really good about that opportunity set right now.

And so the longer Phase 2 takes and the more volumes that get taken up in Phase 1 and the more interest there is in the market, I think the better liquidity we'll see in the back end of the curve and the more opportunities there will be for us to go contract, which is how we're looking at the opportunity set.

We will continue to have this option on Genesee because our -- I firmly believe our site is one of the most attractive sites on the continent for a large data center because of our access to fiber because of our access to water because of our interconnect and because of the topography and location where we are at Genesee outside of Edmonton. So all those things are positive for the market overall. But most importantly, we feel strongly we're best positioned to sell power into this tightening market over the short to medium term.

The outlook for Alberta is quite good right now as we look out from a tightening of the market and a pricing perspective and the limited number of generators there are in capacity there is. And being at the right end of the merit curve here with the lowest heat rate plant most efficient plant in the country and the largest plant providing net -- power net to grid, we think that we're pretty well positioned.

[Operator Instructions] Our next question will come from the line of Mark Jarvi with CIBC.

Congrats Scott and Sandra and thanks for all the time over the last couple of years, Sandra, it's been great to work with you. Just on Midland. In the data center customer, can you talk about any regulatory approvals, the contract structure, what has to get done there? And then I think Pat asked the question of like when the load could ramp, if you could maybe just share some color in terms of when this could move forward.

Yes. Thanks for the question, Mark. So yes, there will be some regulatory procedural approvals required. And then secondly, we're not in a position to say when an in-service date would be for this project. We do think that over the next 6 to 12 months, we can firm up the opportunity in the contract in partnership with our customer here. But I think I can't give you more color than that right now. But you can assume that the in-service date, given the fact that we have existing power, given that we have existing capacity is it's short to medium term, not long term. .

Understood. And then coming back to the concept of the Phase 1 monetization in VPPA, like relative to when you brought up this concept on the Q2 call to now how would you say confidence level? Is it higher today than 3 months ago?

Yes. Well, just on the concept itself of us being able to sell power into this market. The confidence is the same because we had high confidence in Q2 on it as we work through it. So I don't think our confidence could be higher than it was then. It's the same in our ability to price power into this market. I think the only thing that's probably the market has more exposure to is there's rumor to be projects that are coming online. So we're excited to see which one -- which projects actually come through and get announced and how we can support their build .

Understood. And then it does seem like you think -- well, obviously, the megawatts that can't dispatch right now at Genesee could be counted as new megawatts for Phase 2, didn't seem too keen on building new generation unless you got a long-term contract. What about other technologies, battery, any solar? Or would you look to maybe power any data center site at Genesee through virtual PPAs with other developers providing gas?

You mean others building gas on our site? .

No, but more like a VPPA where they might build it or refurbish existing assets. And then part of the solution for the data center at Genesee might be some generation either co-located or adjacent plus some power through VPPAs.

Yes. I mean we're totally open-minded on that front. I think that's really -- that's been our point all along, which is I think we're one of the best, if not the best, in finding creative solutions to contracting power for customers, whether it's bespoke or whether it's in partnership with others. To answer your question of would we be open to other investments at our site, solar? No. Batteries? Maybe. But again, it's really going to come down to contractedness in terms and can we make our cost of capital.

I think the growing opportunity, and I think this is a point I've made previously, our job in this market, whether it's us or any of our competitors as an industry, our goal is to sell more power and bring in more demand. And I think as an industry, we're doing a good job of that. And on a relative basis, I think we're exceptionally well positioned to sell that power given our fleet.

So on Genesee, I think we're open-minded. So I'm not opposed to building. But today, I don't see it a long-term PPA to substantiate that investment. If and when that comes at us, we'll look at it, we'll pursue it. I think Phase 2, we'll see what other customers come to the table. But yes, overall, I feel pretty good. I don't -- I think -- I can't remember who asked the question, but in terms of the outlook on full prices and the more bullish curve that we have into '27, '28, yes, there was an upward movement post June around the announcement of Phase 1. But that was more than 4 months ago.

So that firming of that price scenario in '27-'28, I think just more broadly speaks to the market's confidence that there will be growing demand in Alberta. And I think it's just a timing question now. Do we see much of that load in '27, '28 or '29. But overall, the support for higher prices and tightening supply, I think, is pretty favorable for Alberta.

Understood. Makes sense. And then you identified some sites in the U.S. with multiple options, I think Arlington Valley, Harquahala, Rolling Hills, Hummel, are any of those sites gas constrained if you do try to do uprates or expansions?

Well, I can't make a blanket answer on that because each site is different. So for example, we aren't constrained as I said, when we acquired Rolling Hills, we have available capacity at Rolling Hills, but we do not, at Hummel, we do think we have upgrade opportunities at a couple of our plants in WECC. But we don't see viability for a data center, or colocation of a data center upfront. But -- so I think the way I look at our portfolio today is, we've got, call it, 2.6 gigawatts of contracted capacity in the U.S. that expire between '29 and 2032. And we've got just over a couple of gigawatts of fully merchant capacity in the U.S., and we're trying to find ways to optimize that and increase it. So it's a site-by-site response. But as I said earlier in the call, those sites that I pointed out, there's one or more of those opportunities at each one of those sites. .

Got it. All right. Looking forward to connecting in a couple of weeks.

Thank you. And I'm showing no further questions at this time. And I would like to hand the conference back over to Roy Arthur for closing remarks.

Thank you, everyone, for joining us today. We appreciate your continued interest and support from the Capital Power story. We will conclude the call now. Thank you.

This concludes today's conference call. Thank you for participating, and you may now disconnect. Everyone, have a great day.