Capital Power Corporation (CPX) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Capital Power Corporation's First Quarter 2025 Analyst Conference Call. [Operator Instructions] As a reminder today's program is being recorded. And now I'd like to introduce your host for today's program, Roy Arthur, Vice President, Strategic Planning and Investor Relations. Please go ahead, sir.

Good morning, everyone. My name is Roy Arthur, Vice President, Strategy Planning and Investor Relations. Thank you for joining us to review Capital Power's First Quarter 2025 results, which we published earlier today. Our first 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 quarterly and financials for the company. Avik will wrap up with a review of 2025 strategic priorities, after which we will open the floor to questions from analysts in our interactive Q&A session. Before I 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 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, unlikely to be comparable to similar measures used in other enterprises. These measures are provided to complement the GAAP measures, which are provided 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 people of Treaty 6 region and the Métis Nation of Alberta Region 4. 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.

Thanks, Roy. Good morning, everyone, and thank you for joining us today. In the first quarter of 2025, we created value and delivered on our strategy on multiple fronts. We delivered 9.6 terawatt hours of reliable power across our strategically positioned portfolio with strong contributions from all 4 of our revised segments which we will describe in more detail later in the presentation. We continue to deliver operational excellence by optimizing and maintaining our assets, completing 43% of our scheduled outage days for the year. After the end of the quarter, we announced the largest acquisition in our company's history and entered North America's most meaningful and liquid power market, PJM. We are delivering balanced energy solutions for our customers while advancing developing projects and new opportunities, including data centers in Canada and the U.S. and exploring small modular reactors in Alberta. In summary, we continue to make tangible progress in delivering on our strategy. Our business remains resilient and continues to offer compelling risk-adjusted return potential. Amid considerable market turmoil, we have continued to invest in natural gas. Why? The answer is simple. The demand growth potential we see is insensitive to economic and other forms of disruption. Over the past 25 years, U.S. natural gas power generation has grown at a 5% compound annual growth rate, far outpacing the total power generation and real U.S. GDP. During this time, the U.S. experienced 3 recessions and significant renewables growth. Despite these events, natural gas has continued to grow and since 2015, has been the #1 source of U.S. power generation with no real competition for this title. Looking forward, we remain encouraged by the long-term fundamentals that underpin the need for natural gas-fired power generation. Just as the broader natural gas thematic is resilient, so is our business. We procure our feedstock and monetize our power domestically in both Canada and the U.S. Our strategically positioned assets are in regions with strong fundamentals and disproportionate C&I demand. Our cash flows are highly contracted with high-quality counterparties with over 90% of our PPAs with A-rated entities. In summary, our business is largely insulated from tariffs and other macro impacts. This was demonstrated this quarter when we grew our portfolio and delivered strong results during a period of extreme uncertainty. One notable growth area highlighting the need for natural gas power is data centers. In Alberta and beyond, our proactive engagement seeks to achieve mutually beneficial outcomes. In Alberta, we have completed and continue to pursue proactive and extensive engagement with the AESO to understand their concerns and communicate the needs of our target market of off-takers. Simultaneously, we are working with potential commercial counterparties and have conducted detailed engineering to understand the key parameters for a co-located data center at the Genesee site. Regarding our broader U.S. portfolio, we are evaluating a wide variety of potential site configurations and commercial constructs. With the addition of assets in PJM, we will have greater than 2 gigawatts of incremental capacity available to be contracted. The data center opportunity remains robust for our business. As part of our growth and evolution, we are revising the way we report on our business. Going forward, we intend to disclose in 4 segments: U.S. flexible generation, Canada flexible generation, U.S. renewables and Canada renewables. As we continue to grow and diversify, we believe that these categories better capture the composition of our business and how we manage it internally. Let's zoom in on our flexible generation segments. Key pillars of our significant value creation. Starting with Canada, our strong flexible generation portfolio is seeing growth and improvement across multiple areas. We've added capacity through repowering and have 5 ongoing optimization projects in Ontario. These efforts increase scale and efficiency across this segment, lowering portfolio's average age and lengthening its weighted average contract life. Exemplifying the strategic positioning of these assets is the recent performance of Goreway. This facility had a record quarterly capacity factor providing reliability for the Ontario grid during major outages at a large nuclear facility in the region. We expect the combination of nuclear outages and growing demand to drive strong utilization of this facility and our other assets in the province for years to come. Turning to the U.S. We are using our strategic and highly accretive acquisitions to drive value. Our U.S. portfolio is growing in scale, efficiency and lowering its age after adding these 2 new assets in PJM, Rolling Hills and Hummel. Similar to our Canadian flexible generation assets, strong demand in our key markets continues to drive elevated capacity factors with Arlington Valley and MCV seeing record quarterly capacity factors in the past 12 months. Focusing in on the quarter, we saw a significant year-over-year increase in generation at Decatur, driven by nuclear outages in the area. Decatur's high availability during the quarter allowed the plan to fully capture the upside from the TVA dispatch. These portfolio improvements and overall asset performance reflect our shareholder value creation priorities in action and highlight the benefits they create. The addition of Hummel and Rolling Hills to our portfolio also increases diversification of cash flows and lowers market-specific risks, with no single market representing more than 30% of our total pro forma capacity of 11.8 gigawatts once the transaction closes. In addition, this transaction diversifies our merchant generation capacity outside of Alberta and creates additional opportunities to contract with commercial counterparty and access new demand centers. I'll now pass it to Sandra.

Thank you Avik and good morning everyone. Before I talk about our first quarter 2025 results, I would like to highlight our ability to finance our growth as demonstrated with the acquisitions or Hummel and Rolling Hills. We have a strong track record of maintaining financial flexibility and discipline while optimizing our cost to capital and enhancing shareholders value. The consideration for our most recent acquisition was a mix of cash on hand, new corporate debt and discrete common equity offering. The discrete common offering consisted of $667 million in common equity and a concurrent private placement with AIMCO. We are proud to be solidifying our proforma capital structure with this financing while enhancing the institutional support for our business with this high quality investor. We are especially proud to have this level of institutional backing during a period where so few entities were able to access capital markets to fund their growth. Outside of M&A and the completion of Genesee Repowering project, in 2025, we will continue to invest approximately $600 million in development CapEx advancing the projects that make our portfolio larger, lower carbon, younger, and more efficient. We have history of 11 years of consecutive dividend growth with a low dividend payout ratio. Our ability to deliver sustainable dividends to our shareholders while maintaining a low risk capitalization structure and investing in attractive growth opportunities drives our value for our shareholders. Now to dive into our first quarter of 2025 results. Capital Power delivered a strong quarter of financial and operational performance. For the quarter adjusted EBITDA of $367 million was $88 million higher period-over-period largely driven by lower emission cost from the Genesee Repowering and Goreway's record quarterly dispatch in the Canada flexible generation portfolio. U.S. flexible generation contributions driven by favorable performance of our Desert Southwest portfolio and overall higher generation for our portfolio relative to 2024. AFFO for the quarter was $218 million, up $76 million from Q1 2024. Primarily driven by higher adjusted EBITDA as described above and decreased current income tax expense. This was partially offset by increased financing expenses and higher sustaining capital expenditure. Overall, the quarter is evidence of our ability to progress on our strategic initiatives despite uncertainty in the macro environment. The slide highlights the period-over-period adjusted EBITDA variance for each of our 4 new reporting segments. Q1 2025 saw a 42% increase in the contribution of adjusted EBITDA from our U.S. flexible generation fleet. This was driven by a full first quarter contribution from Harquahala and La Paloma, which we added to our portfolio midway through Q1 2024 and strong dispatch from our U.S. flexible generation assets. There was a 16% increase in the contribution from our Canadian flexible generation portfolio with Goreway seeing record dispatch. Higher generation at our repowered Genesee unit, which did not incur carbon tax in the quarter allowed for margin expansion year-over-year despite capture price declining by $9 per megawatt hour. Our renewable portfolio continues to meaningfully contribute to our overall adjusted EBITDA with minimal variance year-over-year. After the sell-down of 49% of Quality Wind and PDN in December 2024, Canadian renewables are down in Q1 2025 to $33 million compared to $44 million in 2024. The results shown here are fully consolidated to ease comparison to the prior period. The uplift in adjusted EBITDA through asset recycling of these assets will be reflected in the U.S. flexible generation segment post closing of the recent acquisition. We are on track relative to our 2025 guidance and are reaffirming it for the year. We will provide revised guidance, including the previously announced PJM acquisition closer to the closing of the transaction. Altogether, the results from Q1 and our recent acquisition underscores the resilience and effectiveness of our strategy and our ability to create meaningful long-term shareholder value through a variety of market conditions. I'll now pass it back to Avik.

We are immensely proud of our accomplishments year-to-date. Our team is delivering excellence and driving results across our business as demonstrated by our significant portfolio growth and strong quarterly results from our existing assets. In our January guidance call, we outlined our strategic priorities for the year, and we are making meaningful progress on all our priorities, including fully executing on expanding our flexible generation portfolio. We look forward to providing further updates on the other priorities as the year progresses. And with that, I will hand it back to Roy.

Thanks, Avik. Operator, we are now ready to take questions.

And our first question comes from the line of Thomas Meric from Janney Montgomery Scott.

Two questions for me on the U.S. assets. I'll start with kind of PJM capacity question and then a follow-up on La Paloma. But what are your thoughts on the auction results upcoming this July? And then second part of that is when you think RTO will get back on schedule for running the auctions kind of relative to the 3-year forward look?

Thanks for the question, Thomas. So on the second one, I think that's an open question. I think we expect that resolution on scheduling to occur over the coming 12 months, but we don't have a view as of yet when we'll get back on specifically. But we understand that, that's being worked out as we speak. With regards to forward outlook, when we looked at these assets, what underpinned our underwrite was the high-quality nature of both assets on Hummel a low heat rate and underpinning our view on the market was a mean view on what capacity markets would do. And as we said on the call, when we announced the transaction, our outlook is within the range of the floor and the cap on market outlook.

And follow-up on La Paloma. I appreciate the color on Decatur and Midland Cogen that you made. Just curious if you could dig into La Paloma as well for the quarter, looked like pretty strong results out of that asset. And that's it for me.

Yes. Thanks for the question. On La Paloma in terms of generation, we saw strong generation out of the first quarter and overall performance, it was better than expected, but it just really speaks to the positioning of the asset within Queso and just the optimization that our team was able to deliver on the trading side. But overall, as we -- we like La Paloma because of its positioning, given its specific gas supply and then our ability to hedge and optimize that asset, with strong deliverability. So you can see the results on our generation on that quarter-over-quarter. But that's what was reflected in the market. But I would say it was asset specific more than it was market-specific.

And our next question comes from the line of Robert Hope from Scotiabank.

There's been a couple of changes in the REM in Alberta over the last couple of weeks. Maybe just kind of your thoughts on the changes that the AESO is making and the implications for your business?

Yes. Obviously, there's been a few additional changes here over the last 4 weeks in particular, the removal of the day-ahead market. I think in aggregate, the fundamentals of the market being an energy-only market biased heavily towards efficient units. And so the fundamentals of where we are on pricing and outlook that we're oversupplied. I think ultimately, putting a premium on dispatchable generation and efficient generation is what will carry the day. And the government is really trying to pinpoint the policy that allows for that, but still intense new build and sending the right price signal is key. So from a Capital Power perspective, we support the changes that the government is trying to put in place, and there's a high-level engagement. There was a CEO forum where these changes were discussed a little over a month ago. But it's really important that the price signals remain to one intense new builds. And it looks as though the government is looking to put those in place. So, you know, we weren't expecting the change on the removal of the day ahead market, but the replacement of that with dispatchability products is a positive indication and one that I think benefits our fleet in particular, and Genesee in particular.

All right. Good to hear. And then just taking a look at the presentation for the quarter, like in the 2025 strategic priorities, acquisitions and expanding the generation portfolio is still listed as a strategic priority. Are you still looking at assets? Or does the focus turn now to integrating the PJM assets and then maybe take a look again in 2026?

The priority is definitely focused on integrating the PJM assets. But I would say on M&A, it's not something you can start and stop. I think our company, in particular, over a decade has demonstrated that we can maintain a deep pipeline of opportunities, both bilateral and participate in broad auctions. And hopefully, we've demonstrated a strong capability to execute. And so we will continue looking at opportunities. But make no mistake, the priority for this year will be to one, close the transaction, and two integrate these 2 assets, in particular because we're in a new market.

And our next question comes from the line of Patrick Kenny from NBF.

I guess just with respect to the AESO approving really any data center interconnections in the province. It sounds like based on the Premier's comments yesterday, the federal government now has about a 6-month window to withdraw or at least revise the CER to align with the provinces net 0 time line. So I just wanted to confirm if Q4 is still a realistic time line for potentially securing a colocation agreement at Genesee? And also any color on how your commercial discussions have been progressing relative to your initial expectations coming into the year?

We continue to progress on the data center initiative and Alberta continues to be very compelling for customers. And as I've mentioned before, in particular, because of in-service dates being attractive coming in at 2028 or earlier. And given our positioning of having excess capacity, a highly efficient unit, and where we -- where the grid is in Alberta, nothing's changed in that regard. So we continue to advance discussions and negotiations there. With regard to CER, I would say CER does not impact our ability to contract in Alberta specifically at Genesee today because the capacity is built out. It will obviously have a clear impact on any new build that occurs in the province and has a later in-service date. But at Genesee specifically, we don't see that as a barrier. But I would emphasize, we still do believe CER as it's currently contemplated does not meet the needs of Alberta's grids and the repeal of it or a significant modification of it would be required to enable a safe, efficient and reliable grid for Albertans.

And I guess until we see data center load come into the province, just looking at your Alberta power hedging profile, it doesn't look like there's been much opportunity to add significant positions for 2026 or beyond. And with the forward curve down, call it, $10 a megawatt hour since the beginning of the year. How are you thinking about mitigating your exposure beyond next year? Or perhaps do you see a disconnect between where the forwards you're at and your own internal forecast?

Yes. I think that when you look at our hedging profile out in the next couple of years, it is actually more hedged than historically we would have, and that's just because of the longer contracts that we put in place before. So we're able to be somewhat patient before locking in more hedges. I think what we saw with some of the depression in the forward with just some uncertainty around carbon tax pricing and where that would settle out post election. So I think with the levels being in -- remaining in power that you might see some rebound there. But from our perspective, I think we would continue to hedge out that book probably when we get a little more closer to 2026 and you have some of the retail load looking to hedge out. So we're comfortable with the level of hedges that we have now and we're not feeling any urgency. So we can be somewhat flexible in terms of our position.

And our next question comes from the line of Mark Jarvi from CIBC.

Maybe Sandra, picking up on your last comment with the forward curves and maybe the market pricing in sort of a flat or change in industrial carbon price. What are you guys hearing in terms of that? Is that holding you off from doing any additional hedging in the near term in terms of your expectation on what happens there?

I don't think it would be -- I would say that it's holding us off, but certainly, it is one that we think that there's a little bit more clarity now in terms of what that policy is likely to be. So as I said, we still look for opportunities in the curve to step into positions, and we'll continue to do that. But I'm not expecting a material shift until we get a little farther into the year as we sort of expect the forward curve is softer, given that we are seeing softer prices now. So to the extent there's any kind of volatility in prices or clarity on policies, I think we'll get a clearer view as this year progresses as to where the forward for '26 will be in our ability to transact in an opportunistic fashion.

So your assumptions at this point are continued $15 a ton increases annually? Or are you hearing some indications or hearing from government potentially a pause or potentially revisiting sort of the -- what's going to happen in terms of the forward increases on the carbon price?

We're not hearing anything different than the baseline assumption that it would still continue to grow $15 a year up to $170, but we'll see whether or not anything is worth coming on that. It's always been our expectation that large emitters would continue to see carbon taxes. And if there was a change in government or a change in thinking on carbon pricing, it would be more at the consumer level. So we've always anticipated this level. I would just note that at Genesee, for example, we did this quarter ignore -- we are able to be below the intensity benchmark for carbon tax. So I think for us, most meaningful story in the quarter around carbon tax is the fact that our repowered units have hit a level of efficiency that we were expecting. And seen a fair bit of uplift in our results in the quarter as a result of the repowering units performing as expected.

Got it. And then going back to the topic of capacity prices, maybe the MISO auctions that came out recently. Avik, just give your perspective on that, what that means for that market? What that means maybe for counterparties a sense of urgency to contract at Midland? And maybe even just going broadly to your other U.S. assets in terms of opportunities to secure contracts. Is that a 2025 expectation? Or is that more 2026?

Yes. With respect to the summer auction at MISO, it's a trend that we've been seeing over the course of the last 2 years, as you'll recall, last year, we had a record quarter of generation out of MCV as well. So we're seeing the same dynamic play out in multiple markets, whether it's Queso for reliability, Desert Southwest for ongoing generation demand. Decatur, we experienced that positive uplift because of nuclear outages. And the thematic that we've been chasing over the last decade of finding really strong mid-merit gas plants with proven gas supply where gas is a critical product for reliability, that thematic has played out in each and every one of our plants. So implications on MISO for us at MCV, MCV is contracted, so there'll be no immediate uplift to that market, but we are having multiple conversations there as well as other plans around recontracting and data centers. So it's -- we expected that. We continue seeing pressure. New build continues to be challenged with the cost of new entry. So that's what you're seeing play out in multiple markets, existing dispatchable generation is becoming more and more valuable. And when you have it on an existing interconnect, that's what you're seeing play out in the market. So we expected the tightening in the market in MISO and we continue to see more demand in those key markets.

And just in terms of timing for recontracting or conversations continue to progress well. Do you think something in the cards in the next couple of quarters? If you have an update around those?

I can't comment on that. What I would say, like I said last quarter, we've got multiple conversations on recontracting. And I think it's -- I think the opportunity for us to recontract is there. I think the decision for us in specific negotiations is whether we can agree on commercial terms that both sides are satisfied with. And we have to look at those options relative to our other alternatives, whether it's expansion or doing something with the data center. So these are -- they're ongoing conversations. They are all favorable in nature. We're not having one conversation where we're looking out and we're not getting better returns than where we currently are. The demand is generally working in our favor on this. So I can't comment when we'll be able to deliver it. But given that we're having many of these conversations at facilities much earlier, and much further away from the expiry of the existing contracts, they take time. But I think constructive dialogue on multiple facilities, engaged counterparties, and it feels like both sides are working towards mutually beneficial outcome. So going in the right direction, I can't say whether we'll announce something in the next 2 quarters or not.

Makes sense. And then maybe just last quick question. Just Alberta data centers, are you only looking at co-location style agreements for Genesee? Or are there other options on the table based on some of the customers you're talking to?

So just generally, across North America, we're looking at multiple options. I would say, in Alberta, as is indicated by our interconnect applications, the priority is definitely a co-location. That is we have the interconnect, we have capacity within the framing of what the Government Minister, Neudorf, Minister Glubish have telegraphed to the market in terms of appetite for behind the fence colocated or fully behind-the-meter alternatives. Genesee is just very well positioned for that. And I think as I said last quarter, our big advantage in this conversation is the -- our in-service date being sooner than almost anywhere in North America. So that benefits from colocation if we can work through the regulatory aspects of that with the AESO and the ministry and the agency. So I think everyone in Alberta is working hard to getting to that outcome for the province. And we're focused on delivering a product that meets the needs of a customer and also as Premier Smith has said time and time again, having a project that doesn't compromise reliability and affordability to consumers is paramount. So we're trying to work within those bookends. But things are continuing to move forward. And right now, it's just getting the rule book for Alberta to bring this industry to bear in the province, and we're trying to work within that framework.

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

I know you mentioned that you have 90% of [ EBITDA ] contracted or hedged for 2025. But if I look beyond this year and look at your pro forma portfolio, the PJM assets are obviously mostly merchant cash flows. So my 2-part question is this, when you exclude hedges, what percentage of your assets are contracted pre and post the PJM acquisition? And second part question is big picture, you think about the positive outlook for power growth across North America, how do you see taking on incremental merchant power exposure, fully recognizing that the rating agencies quite have a minimum level that you've got to adhere to.

When we talk about our level of contractedness, we do exclude hedges that are put on in the year or short-term duration hedges. So when we're looking at being contracted or long-term hedges of above our 60% threshold for this year, excluding the PJM acquisition, we were well in the high 70% contracted for the year. When you add in PJM, we still remain with a cushion above that 60%. So that's part of the process that we would have gone through with the rating agencies looking out over course of our plan and what our contracted level was. So the exposure we take on in PJM does bring us in line with that threshold of 60% to 65% contracted. And we expect that, that will remain the level for the next number of years, absent more acquisitions.

And your thoughts on the benefits are of taking on incremental merchant power exposure, given the focus?

Yes. So I think what we've been talking about for some time now is that we are seeing rising prices that when you contract, you definitely derisk your cash flows, but you are giving up some of the upside. And so where we're looking to capture that upside would be when we look to recontract assets where we think that we can contract at higher prices than would have been would have been anticipated looking back a couple of years ago. As far as that merchant exposure for us, the question becomes what markets do you want to have that merchant exposure and how much to take advantage of the upside you can realize from the returns in our merchant market with higher pricing than what you would contract for. So we would be looking at the near-term fundamentals of the various merchant exposures that we have and deciding where to allocate that 40% exposure to optimize returns. But as you know, our view has always been to derisk our cash flows to maintain enough cushion to make sure that we are resilient. So we would be employing all of those fundamentals and deciding on how much exposure we would take in a given year and how much we'd be looking to hedge out or to contract.

Understood. And just to finish off and another strategy question, I guess. So you made your initial entry into the PJM market with this deal that you've announced. Just thoughts on how do you leverage that initial position to improve the returns beyond just holding it? Is there a contemplation that you would seek a more portfolio approach to that market? And then -- or would you want to enter a new market like in other markets like ERCOT for example?

One of the reasons we're so excited about these 2 assets is it's large enough and the combination of a CCGT in a large peaker allows us to take a portfolio positioning in PJM. So for us, the priority is, first and foremost, to go in and take over ownership and stewardship of those assets and find ways to optimize those assets. I think Hummel in particular, it's a 2018 vintage CCGT, so it's one of the most efficient and newer plants in the whole market. But at Rolling Hills, we see significant opportunities there that we have not modeled and are not baked into the models that over the course of the first 2 to 4 quarters of ownership, we'll look to find those opportunities. In terms of our market assessment across North America, we highlighted in our 2024 Investor Day that PJM and ERCOT were 2 interesting markets for us. PJM, we prioritized over the course of 2024 because of the market dynamics, because of the capacity market and just because of the size and scale of that market. As we looked at ERCOT, I would say at the beginning of 2024, we looked at both of those on an equal playing field. And as we think about portfolio construction, we are diversified now where no single market post-closing will be more than 30%. And as we look at ERCOT relative to our own position in Alberta, where it's a similar market structure, we think we have comparative advantages in Alberta, whereas in ERCOT, given the competitiveness of it, we like the market. If there was something opportunistic there, we'd evaluate it. But we think in terms of portfolio construction, contractedness, merchant exposure, those dollars are more appropriately allocated towards Alberta if and when opportunities exist there. So I would say continuing to expand and optimize our business in PJM through upgrades, trading in origination, contracting opportunities, potential expansion of the fleet over time is a focus, and we see those same opportunities in MISO, Desert Southwest and potentially Ontario as well.

And our next question comes from the line of Benjamin Pham from BMO.

Just looking at your new segmenting renewables in particular. Can you comment on the outlook there for those 2 segments? And then can you also comment on with renewables, is it better to buy right now or to build?

Just in terms of outlook, as you know, between our Canadian and U.S. business, it's mostly contracted. We are seeing more broadly multiple compression and valuation pressure on the renewable side. I would say, to buy versus build, I think on the build side, if you've got existing security of supply, in particular on the U.S. side as the tariff conversation continues, I think there's compelling returns to be had. I think we, last year, going into the second half of 2024, we were expecting valuation to acquire assets to start being more compelling and more in line with our own multiples. And that was really the noise we were hearing in the market that didn't transpire as quickly as we thought. But I do suspect that over the course of this year, in particular, lower contracted assets, so I would say sub-15 over 10-year contractedness on operating renewables as there continues to be more market pressure on the segment. We think there could be some compelling opportunities in renewables there. In particular, ones where you have to apply the expertise that we have in terms of understanding construction, repowering opportunities, contracting opportunities and working with regulators. So I think if there was something interesting there and compelling that would meet our return threshold, that would be it. It would be those assets that don't naturally fit infrastructure firms or the big renewable players because they don't have quite the length of contractedness that they would like, but it would be accretive to us on contractedness and require operational engineering and construction expertise to go realize that. So I'm actually -- it's a space where I think we've always been in. We've found it hard to acquire. So that's never been a focus, but we're definitely monitoring it.

Yes. Understood. And say on the acquisition side, you've mentioned, it's something going to continue to evaluate. Maybe you can share in the last 12, 24 months, you shared some good tidbits on the opportunities that remains robust, your target geographies and whatnot. Are you seeing any change there in terms of the amount of volumes you're seeing on your desk? Is there more of these $3 billion type deals that are of that size out there?

There's definitely opportunities that are multibillion in nature. Obviously, Constellation transacting on Calpine sent a significant market signal. But the number of players that are corporate in nature or pools of assets that are owned by single owners is few and far between. So I would say, third quarter going into fourth quarter last year, significant pickup in terms of number of assets coming to market through auctions. And we largely didn't play in most of those auctions. And I think as we rolled into this year before the tariffs were announced, I think there was an expectation of a number of assets coming to market this year. So definitely more assets in the market, definitely more players in the market. I would say debt capital markets have not materially improved for the sector in terms of borrowing base capacity for merchant natural gas assets. And as a result, I think it's more difficult for private equity and/or infrastructure funds to play. So I do think in the greater than $1 billion transaction size, there's still a limited number of buyers that have the capability and capacity to operate, optimize trade and originate around the assets. And so I do think that will continue to be a niche area for us to exploit relative to the universe is getting more and more competitive.

Understood. And maybe just one last, one on the balance sheet side of things. Do you think that's nimble enough to take advantage of it, just given your recent history with equity offerings and partnerships and whatnot?

I think if anything, Ben, we've demonstrated that we can be flexible and creative in finding capital. And we've been incredibly fortunate to have investors support our strategy and approach to the market, which is underpinned by a decade-long consistent approach to underwriting. So I think we have to continue to be creative. We are committed to maintaining our investment-grade status in our existing balance sheet strength. So it just means we've got to find more partners and be more creative and stick to our knitting of doing what we do well. So we'll continue to do that. I think we're -- and it's one of the reasons why the priority is integrating these assets. But we'll continue to be in the market looking for interesting opportunities that fit what we do well. And maybe one last point there is we continue to see -- we continue to get inbound from parties wanting to partner with us on opportunities. So I don't think there's a shortage of capital available to us to go pursue these.

And our next question comes from the line of Julien Dumoulin-Smith from Jefferies LLC.

This is Tanner on for Julien. Maybe I'll follow up on the M&A angle here. Following the PJM acquisition, is this M&A digestion period more a reflection of financing considerations? Or is it really just about enabling strategic integration? Like for instance, is there a sort of FFO to debt or leverage target that would signal you've properly digested the acquisition and will look to become active again? Or if it's an operational consideration, what milestone would indicate you're satisfied with the integration and ready for another phase of inorganic growth?

Yes. Thanks for the question, Tanner. I would say the latter is the first priority. I think we have clear guidelines and indications from rating agencies on what's required, and we feel we're within those parameters. But for us, table stakes is ensuring we integrate these assets safely and efficiently and position them well inside our organization. So I think for us, not -- I don't want to telegraph the timing of when we would do the next thing other than to say we have an active pipeline. We continue to expand that pipeline. And obviously, with this transaction, we were able to transact with a formidable and industry-leading counterparty like LS, we're just honored to have been able to transact and take these assets on. And so the phone is definitely ringing, but we want to be prudent about our approach here. So we're not in a rush to do the next thing. We're evaluating the market and priority is to integrate these assets.

Great. And from a portfolio construction standpoint, I think you touched on this earlier from -- on a market-by-market standpoint. But zooming out what is the ideal U.S./Canada mix going forward? And then is there a threshold perhaps to cross where it makes increasing sense to begin looking into formally pursuing the dual listing?

Yes. So from our perspective, we've always considered that the timing of a U.S. listing would be timed with an acquisition. So we haven't really set a threshold in terms of the mix of business, Canada, U.S., it's a number of different considerations, including your overall market cap, investor interest, and we certainly see very strong momentum in all of those areas. So thinking that the time to do a list of that opportunity could be available to us. Certainly, there are stock requirements as well, and we are focused on ensuring that we align with those requirements before going down that path. So we continue to monitor that and expect that it would be something that we would have in our financing toolkit and potentially the next couple of transactions out, if not sooner, but we'll continue to monitor it.

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

Going back to the Alberta data center opportunity. So wondering if you can give us maybe a bit of a preview of what you're hoping for, from AESO next month in terms of how they're going to approach that methodology for allocating available capacity. And how your view on available capacity in the market for data centers has evolved? What you've -- based on what you've seen in the power market so far this year?

Look, I think the AESO has been very clear in their approach to the allocation and trying to find objective measures in how to fairly allocate that capacity. We've continued to provide input to that as all producers have and generators have in the province. We are very confident that Genesee is well positioned for that and are hopeful that we'll have material allocation given the fact that we've just recently repowered and have excess capacity and the positioning in Genesee relative to the grid. So I think we have our interconnect applications in place. We've got capacity there. We've got ongoing dialogue and the AESO is working hard to find that best objective approach that also ensures grid reliability, and we feel like we're well positioned for that. So I can't really comment more than that because we don't know when that will come out. We have an expectation that it will be in the next 4 weeks, but we're not privy to the specifics and how that will roll out, but I feel good about our positioning. With regards to the commercial opportunity in Alberta, the conversation, it's fantastic that we've got a number of projects in queue and the prominence of Alberta has emerged as an industry location for data centers. This is not about Genesee and Capital Power building a data center. It's really about forming the foundation for an industry supercenter. And so we welcome all the projects that are coming in. But the most important thing is a near-term in-service date. That's what the hyperscalers are focused on. And those that have the nearest term in service dates are the ones that are going to fill first. And so the opportunity for Alberta is to come up with the rules of the road that service the industry so that we can, one, build the first one, and then sanction all of the others. And I'm very excited about where Alberta is in this regard because as I said last year, it's one of the only jurisdictions in North America where you have government, the Ministry of Utilities, Ministry of Technology, industry players, all aligned in wanting the industry there. And so if we're able to put this framework forward, we'll be one of the first jurisdictions post generative AI that's actually laid the ground -- the road map for how to go do this while not compromising reliability and affordability. So I think this -- the next 4 to 8 weeks is very important in terms of how the government and the AESO align on putting forth that allocation. And then the rules coming behind it is a really big opportunity for the province. So that's our view, and those are the conversations we've been having with not just counterparties, but government.

Okay. That's great. And then maybe on the phased low growth approach. And you've made that, I think, comment the last couple of quarters. And as you noted, you've got early 2027, I think, ISDs in your applications. Just this -- let's say, clarification on phase load growth. Is that more of a reflection of customer preference for gradual growth, the realities of equipment and labor constraints in terms of what can get built? What the grid can handle? And how much of that is maybe driven by broader economic considerations just in terms of the pace of potential customer CapEx? Your thoughts on all that would be great.

Yes. And John, this is a conversation I've had quite a lot over the last 2 or 3 quarters. I would say it started with for us anyways. I don't know about other generators and their conversations with hyperscalers. But when we were introduced to this opportunity set in second quarter of 2023, the conversations we've consistently had with hyperscalers, data center providers and other interested parties was they needed the flexibility to come in at a material level, call it, 300 megawatts plus and have the option to scale that to much higher numbers and that was their need, not grid restrictions. And so as the conversation has evolved and as the hyperscalers have refined their own requirements, then it becomes a local market conversation. And so the answer is it's actually both, it's customer need. And then on the other side, it's capacity availability, grid reliability and transmission and distribution constraints. And so that's one of the reasons why all of these deals are taking longer across North America is you're having to come forward with multipath, multilateral agreements that are bringing to the table of stakeholders as well as offtakers as well as generators. So I think most deals we'll see will have some level of contingency in scaling, and that is going to accommodate both sides, whether it's the system operator or the utility and what their needs for reliability and new generation are as well as the customer having some flexibility as well to scale. I think it's less about supply availability. I think it's less about access to chips and more about the commercial needs of what the hyperscalers are and when and how they want to scale.

That's great. And maybe just one last one for Sandra. Just on the year-over-year EBITDA growth in Canadian flexible generation was about $28 million. Can you give us a sense of how that growth split between the Alberta and Ontario assets, just given the improved cost structure at Genesee, but again, the increased dispatch at Goreway, which I wouldn't have guessed would have been a huge impact, but that would be helpful.

No. Yes. So I would say probably about 80% of it is Alberta, so Ontario would be less. So Goreway maybe in the neighborhood of $5 million, $5-plus million and the rest of it would be on the Alberta assets.

Thank you. This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Roy Arthur for any further remarks.

Thank you, operator. This concludes our call for today. We greatly appreciate those of you who dialed in and for your continued interest in our story. Have a great day.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.