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Operator: 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.
Roy Arthur: 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.
Avik Dey: 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.
Sandra Haskins: 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.
Avik Dey: 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.
Roy Arthur: Thanks, Avik. This concludes the formal part of the presentation. Operator, you can now begin the Q&A portion of the meeting.
Operator: [Operator Instructions] Our first question is going to come from the line of Julien Dumoulin-Smith with Jefferies.
Tanner James: 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.
Avik Dey: 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.
Tanner James: 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?
Avik Dey: 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.
Operator: Our next question will come from the line of Patrick Kenny with NBCM.
Patrick Kenny: 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?
Avik Dey: 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.
Patrick Kenny: 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?
Avik Dey: 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.
Patrick Kenny: 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.
Avik Dey: 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.
Patrick Kenny: Okay. Great. And Sandra, congrats on your upcoming retirement.
Operator: Our next question comes from the line of Benjamin Pham with BMO.
Benjamin Pham: 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?
Sandra Haskins: 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.
Benjamin Pham: 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? .
Sandra Haskins: That's right. We would be basically flat next year. So base load flat.
Benjamin Pham: 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?
Sandra Haskins: 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.
Operator: Our next question will come from the line of Maurice Choy with RBC Capital Markets.
Maurice Choy: 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?
Avik Dey: 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.
Maurice Choy: 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?
Avik Dey: 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.
Maurice Choy: 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?
Avik Dey: 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.
Maurice Choy: Congrats yo both Sandra and Scott, we'll catch up at the investor day.
Operator: Our next question comes from the line of John Mould with TD Cowen.
John Mould: 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?
Avik Dey: 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.
John Mould: 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.
Avik Dey: 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.
Operator: Our next question will come from the line of Robert Hope with Scotiabank.
Robert Hope: 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?
Avik Dey: 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.
Robert Hope: 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.
Avik Dey: 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: [Operator Instructions] Our next question will come from the line of Mark Jarvi with CIBC.
Mark Jarvi: 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.
Avik Dey: 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. .
Mark Jarvi: 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?
Avik Dey: 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 .
Mark Jarvi: 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?
Avik Dey: You mean others building gas on our site? .
Mark Jarvi: 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.
Avik Dey: 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.
Mark Jarvi: 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?
Avik Dey: 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. .
Mark Jarvi: Got it. All right. Looking forward to connecting in a couple of weeks.
Operator: 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.
Roy Arthur: 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.
Operator: This concludes today's conference call. Thank you for participating, and you may now disconnect. Everyone, have a great day.