Capital Power Corporation ($CPX)

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Capital Power First Quarter 2026 Analyst Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. At this time, I would like to turn the conference over to Mr. Roy Arthur, Vice President of Investor Relations and Investor Partnerships. Sir, please begin.

Good morning, everyone. My name is Roy Arthur, Vice President, Investor Relations and Investment Partnerships. Thank you for joining us to review Capital Power's first quarter 2026 results, which we published earlier today. Our first quarter report and the presentation for this conference call are available on our website. During today's call, our President and CEO, Avik Dey, will provide an update on our business. Following that, our Senior Vice President, Finance and CFO, Kevin MacIntosh, will present a review of the quarter-end financials for the company. Avik will wrap up with a review of our 2030 strategic priorities, after which we will open the floor to questions from analysts in our interactive Q&A session. Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analyses made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on Slide 4 or our filings available on SEDAR+. In today's discussion, we will be referring to various non-GAAP financial measures and ratios, also noted on Slide 4. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in the MD&A prepared as of April 28 for the first quarter of 2026. We acknowledge that Capital Power's head office in Edmonton is located within the traditional and contemporary home of many indigenous peoples of the Treaty 6 region and the Métis homeland. We acknowledge the diverse indigenous communities that are in these areas and whose presence continues to enrich the community and our lives as we learn more about the indigenous history of the lands on which we live and work. With that, I will hand it over to Avik.

Thank you, Roy. Our Q1 2026 results reflect the prudence of our strategy and the resilience of our portfolio even against a volatile macro backdrop. Relentless execution is core to who we are. It's what sets the Capital Power team apart in times of uncertainty, driving durable growth. There are 3 key takeaways we want to leave you with today. First, our business remains stable. Despite heightened macro and geopolitical uncertainty around the world, our business and strategy are unchanged here in North America, and we continue to see multiple pathways to create value. Second, we are benefiting from diversification. Diversification across geographies or electricity markets, technologies, and markets continues to derisk our portfolio and strengthen the opportunity set we can pursue. As we will touch on later in the presentation, we continue to see strong supply and demand fundamentals in each of the core markets where we operate. Importantly, we also see compelling opportunities for growth across our 3 core generation technologies, natural gas, renewables, and storage. Finally, our approach to risk and return has not changed. We remain disciplined and consistent in how we allocate capital with a clear focus on compelling risk-adjusted returns. Our business remains resilient, and we continue to offer compelling long-term value creation supported by stable cash flows and disciplined growth. We continue to make steady progress on our 2026 priorities and remain disciplined in our approach to value creation. Our success reflects the tireless dedication and strong execution of our team across North America. This quarter, we're also pleased to highlight several important leadership updates that further strengthen our organization. Kevin MacIntosh, who joins me on this call, has stepped into the role of Senior Vice President, Finance and Chief Financial Officer. In addition, Andrew Pearson, who has been an integral part of our organization since 2008, has joined the executive team as Senior Vice President, U.S. Commercial, and is based in our newly opened Washington, D.C. office. Looking ahead, effective July 1, 2026, Steve Wollin has decided he will retire after 25 years of outstanding service and leadership. And Mike Toshima will join the executive team as Senior Vice President and Chief Commercial Officer, based in our Edmonton headquarters. We are deeply grateful to Steve for his leadership and the lasting impact he has had on Capital Power. Together, these transitions underscore the depth of our leadership bench and our continued focus on building and sustaining a high-performing team. For Q1 2026, performance highlights include the extension of the Arlington Valley contract through 2038, which reinforces our commercial optimization strategy, securing durable long-term contracts with investment-grade counterparties, and progressing Arlington Valley and Humle upgrades, advancing construction on 4 fully contracted projects totaling roughly 280 megawatts across Canada and the U.S., all with investment-grade counterparties. Operationally, the team delivered another strong quarter, generating approximately 11.5 terawatt hours across the fleet. Importantly, more than half of our generation came from the U.S. portfolio, which continues to underscore the success of our diversification strategy. Finally, our planned outages are progressing on schedule, enhancing the reliability and efficiency of our fleet. For the second consecutive year, we saw the market get off to a rocky start owing to macro disruptions, yet our strategy and our business have stayed consistent. While oil prices and broader market volatility have increased meaningfully, natural gas prices have declined, reinforcing why gas-fired generation continues to be structurally advantaged. Natural gas offers low-cost fuel, operational flexibility, and meaningful insulation from global disruption here in North America, which reinforces our conviction that this fuel source is pivotal to meeting long-term power demand growth and preserving affordability. The bottom line is simple. Positive industry fundamentals remain intact for power generation, and we are staying the course in our pursuit of delivering reliable and affordable power to our customers in pursuit of creating long-term shareholder value. Our return profile reflects a combination of contracted cash flow and merchant generation capacity. From 2021 to 2025, our contracted EBITDA grew at a compounded annual rate of approximately 18% due to a combination of acquisitions, development, and recontracting of existing assets. The contracting successes in Ontario, MISO, and the Durzen Southwest illustrate our ability to unlock meaningful value by optimizing our existing asset base. We continue to make tangible progress delivering the $1 billion of the embedded upside we articulated to you at our Investor Day in December. As a result of the recent contracting agreements at NCB and Arlington Valley, we have already delivered approximately $170 million of contracted EBITDA upside with more to come. We operate approximately 12 gigawatts across our North American portfolio, with roughly 7 gigawatts targeted for contracting or recontracting. That gives us a long and visible runway for incremental value creation from assets already in place. As power market fundamentals continue to tighten, that optionality becomes increasingly valuable, reinforcing that contracting remains one of our most powerful levers for long-term value creation. As we pursue further acquisitions, we will prioritize assets where our platform and expertise can unlock incremental value through commercial optimization. While we have enhanced our diversification in recent years, Alberta remains a meaningful part of our business. It's an attractive market and presents a unique and compelling value proposition for data center investment. We are encouraged by recent regulatory progress, including the Alberta Canada MOU, eliminating the CER for Alberta, and continued progress on the ASOS Phase 1 and 2 data center interconnection processes. These steps improve investment certainty and support continued data center growth while maintaining affordability, reliability, and meaningful economic benefit for Alberta and Canada. We believe Alberta has some structural advantages over other regions looking to attract large data centers. For instance, existing underutilized infrastructure includes generation, transmission, and distribution. The nature of the Phase 1 process puts the focus on generation, but it's important not to lose sight of the transmission and distribution infrastructure. Based on our analysis, the addition of 1.5 gigawatts of load would result in approximately $6 per month savings for the average residential customer in Alberta with existing transmission and distribution spread across more load. In addition to efficient and reliable generation, Alberta benefits from a deep supply of low-cost fuel with forward prices trading below other major North American natural gas sales points. Alberta also has a strong track record of load colocation with approximately 3 gigawatts, about 25% of provincial load co-located with generation. This all reinforces our enthusiasm for this industry to succeed here and create benefits for constituents. Beyond Alberta, diversification continues to benefit our portfolio with growth coming from multiple areas. This geographic and market diversity reduces reliance on any singular regulatory or pricing environment and gives us multiple pathways to create value over time. In PJM, energy forward prices continue to exhibit strong long-term spark spreads with greater visibility to capacity prices out to 2030. In addition, we are encouraged that the recent reliability backstop procurement proposal supports the most cost-effective new capacity, which we believe will include brownfield expansions and upgrades on existing generation. Meanwhile, MISO continues to exhibit strong supply and demand fundamentals. From a bilateral pricing perspective, we were able to recontract MCB, the largest gas cogeneration plant in the U.S., out to 2040 at attractive pricing. Capacity pricing in this region also continues to see significant upward pressure owing to growing demand. Q1 2026 provides a great example of the benefits of diversification in action. Although we saw elevated gas prices and price volatility in PJM, we also saw strong contributions in Ontario and MISO, underscoring the benefits of our diverse and resilient portfolio. In addition to geographic diversification, we continue to focus on 3 core power generation technologies, being natural gas, renewables, and storage. In contrast to the forward outlook, historical power generation growth has been muted over the past 20 years, averaging about 0.5% per annum. However, these 3 technologies have demonstrated significant and consistent growth well in excess of that. Over the past 20 years, natural gas-fired generation has grown steadily as aging coal units retire and rising renewable penetration has increased the need for reliable, dispatchable power. That same push for reliability has also fueled rapid growth in utility-scale battery storage, supported by declining lithium costs and longer storage duration to better integrate intermittent renewables. When we look forward, we continue to see opportunities across all 3 of our businesses. Natural gas, renewables, and storage each play an important role in meeting the needs of the grid as power demand continues to rise. As we indicated at Investor Day, natural gas will play a starring role. Together, this technological mix positions us well to capture rising demand while maintaining flexibility, allowing us to respond to the needs of our customers across our markets. Now I will hand it over to our Chief Financial Officer, Kevin MacIntosh, to provide our financial update.

Thank you, Avik, and good morning, everyone. I'm Kevin MacIntosh, and I'm pleased to join you today as Capital Power's new CFO. We have significant opportunities ahead. And while our ambition is bold, we are starting from a position of incredible strength with a high-quality asset base and strong strategic positioning. Before we walk through the quarter, I'd like to briefly revisit a few of the key themes outlined at Investor Day as they continue to guide how we think about risk, return, and capital allocation across the business. Looking at the past decade, our performance demonstrates a consistent ability to deliver durable growth and strong shareholder returns. First, on returns to shareholders, we have increased our dividend for 12 consecutive years, compounding at roughly 7% annually from $1.51 per share in 2016 to $2.69 per share in 2025. Second, dividend growth has been supported by real business growth. Adjusted EBITDA has grown at approximately 13% compounded annually, increasing from $509 million in 2016 to $1.6 billion in 2025. This growth has been achieved within clear financial guardrails, including maintaining a 30% to 50% targeted dividend payout ratio, approximately 4x net debt to EBITDA, and a largely contracted cash flow base. This is a track record of excellence built through dedication and discipline. I'm excited to be part of this team and build on this legacy, delivering real value for you, our shareholders. Our balance sheet remains a core strength and is the foundation that supports fleet growth, capital deployment, and long-term value creation. In 2026, approximately 75% of our cash flow is secured through long-term contracts or hedges, providing a high level of visibility and durability. That stable cash flow base gives us the flexibility to pursue M&A in merchant markets, grow the dividend, and ultimately deliver strong total shareholder returns. The quality of that contracted base is equally important. Roughly 90% of our PPAs are with A-rated or higher counterparties, reinforcing revenue certainty and credit quality across the portfolio. Our weighted average contract life has consistently remained in the 9 to 11 years range, reflecting the strong positioning of our asset base to meet customer needs. We remain confident in our ability to execute commercial optimization, including long-term contracting throughout our portfolio. Recent examples include the Arlington Valley and MCV contracts, both which extended contract duration on existing assets with investment-grade utility counterparties, adding long-dated higher-value cash flows and highlighting the significant embedded value across our portfolio. Finally, our investment-grade credit ratings across S&P, Fitch, and DBRS validate our asset quality and financial strength, and provide us with efficient access to both Canadian and U.S. public debt and hybrid markets. That low-cost access to capital enhances our ability to commercialize megawatts and finance acquisitions, supporting AFFO per share growth over time. Now let's dive into our first quarter of 2026 results. We delivered a strong quarter, both operationally and financially, with solid execution across the portfolio and meaningful progress on continued investment in our assets in the form of sustaining capital. Looking at the key metrics, adjusted EBITDA for the quarter was $404 million, up $37 million year-over-year due to contributions from the Hummel Station and Rolling Hills facilities acquired in 2025 and partially offset by higher corporate expenses driven by higher staffing costs due to growth in the U.S. and higher equity-based compensation due to the company's share price performance. AFFO for the quarter was $154 million, down $64 million year-over-year, primarily due to higher sustaining capital expenditures, reflecting increased activity across the U.S. flexible generation portfolio, higher financing expense increased current income tax expense, mainly due to less tax depreciation and partially offset by the higher adjusted EBITDA, which I described earlier. Overall, this quarter reinforces our ability to execute our strategy and maintain strong financial performance even as we proactively invest in the reliability and long-term performance of the fleet. Based on our performance year-to-date and our outlook for the balance of the year, we are reaffirming our 2026 guidance ranges for adjusted EBITDA, AFFO, and sustaining capital. As previously disclosed, sustaining capital expenditures in 2026 will be in the range of $290 million to $330 million. This reflects a planned maintenance cycle across the fleet, including 493 outage days and 39 planned outages. This investment is intentional and positions the business to capitalize on strong market fundamentals long-term. Finally, this outlook supports a 2% dividend increase in 2026, subject to Board approval, consistent with the framework we outlined at Investor Day. Overall, these guidance ranges reflect our confidence in the resilience of the portfolio, the durability of our cash flows, and our ability to generate strong financial results while continuing to invest for future growth. With that, I will hand it over to Avik for closing remarks.

Thank you, Kevin, and once again, welcome to the team. We remain confident in our ability to deliver industry-leading performance and generate superior returns for our shareholders over the long term. As we communicated at our Investor Day, by 2030, we are targeting annual AFFO per share growth of 8% to 10%, approximately 50% growth in our U.S. total U.S. owned capacity and 13% to 15% total shareholder return. We will also aim for 2% to 4% annual dividend growth. This combination of compelling risk-adjusted growth and yield positions Capital Power for compelling shareholder value creation. With that, I will hand it back to Roy to close out the call.

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

[Operator Instructions] Our first question or comment comes from the line of Robert Hope from Scotiabank.

I want to start off on the PJM market and the reforms there. And I appreciate the commentary that you provided on the call. So when we look at the potential reforms that are happening there, we do note that your comments regarding how it does support your asset base there. At what point do you think there'll be enough certainty to really kickstart conversations for upgrades and further expansions of your assets there? And I guess, secondly, when you think about concentration, would you be willing to continue to add a merchant in that market?

Thanks for the question, Rob. So I think it's important to recognize when we look at the potential reforms and the announcement of the backstop option, what was concurrently announced was also an extension on the floor and cap on the BRA option. And that was actually reaffirmed this morning in support of the FERC announcement on the approval of the extension of the BRA cap and through 29/30. So when you step back and look at PJM and the dynamic between balancing the capacity market and the energy market, the energy market continues to be attractive, and that's reaffirmed with the DRA options being extended through 29/30. And so from an energy perspective, we look favorably upon PJM. We'd be willing to take on more exposure there, given the specification of our portfolio and the depth of the market to be able to hedge and contract into. In terms of upgraates and upgrades and potential expansions, those conversations have not stalled because of the uncertainty around the PJM auction process. In fact, they've accelerated. So, as you'll know, with PJM's recommendation on the proposed backstop auction, they proposed a bilateral process under which they can match load to supply in advance of that backstop auction. And that process is one that all generators are actively involved in, as are we. So to really cut and get down to the fine point on it is we think the market is active. We continue to be bullish on it. We think there are opportunities, in particular, around the existing generation to add to the portfolio. And I think given that we've got a strong balance sheet, we're investment grade, we're well diversified. We're well-positioned to capitalize on it.

And then maybe moving over to the recontracting initiatives. You've seen a number of successes over the last 12 to 18 months. As you look forward to the remainder or the rest of the asset base, which does have contracts expiring in the next 5 to 7 years, how do you think about timing that? Could you capture some upside now? Or just given that you have had some wins in the past, could you wait to better position yourself to capture upside on a longer-term basis? Just trying to get a sense of how you're thinking about the capture of the upside now versus waiting and maybe getting a little bit more.

That is exactly the calculus we enter into on each and every plant and expiry. It's a commercial decision on what we see the supply-demand outlook versus where we see current pricing versus what we see as current C in each and every market. So what we have done, and we will continue to do is optimize against our current outlook in the market to try and maximize NPV per kW on each and every plant. What we are not doing is trying to schedule and cascade this to be able to hit on a consistent basis an announcement every quarter or every 2 quarters on future contracting. We will do one at each plant as an independent decision on the maximization of NPV per kW. So with that said, we've had active dialogue going on today more than we did last year around recontracting opportunities, and we continue to advance those. But when we announce it, you can be assured we've made the announcement that we feel best maximizes NPV.

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

Welcome, Kevin. I look forward to working with you. Just a quick one for me, too. Avik, you mentioned just in your prior comment, the acceleration of discussions, particularly within the PJM. Just want to get a sense, are you getting a sense that there's kind of an increased sense of urgency for large load customers to bilaterally negotiate on their own terms rather than kind of leave it to the "power tender that we're going to be exposed to?

I love that analogy, Nick. So what we are seeing is definitely increased activity in conversations. I think if you ask any of the generators that are active in PJM, they would say we're all having more conversations. I think PJM has put forward a plan that's encouraging those bilaterals to occur in advance of that backstop auction. But I think we need further visibility on the process. So I think we're seeing more activity, not less. And I think it's good news for everyone if we see more of these bilaterals entered into in advance of the backstop option. The best-case scenario is that we're working down what's required for the auction because we're figuring it out ourselves.

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

Look, I think in our conversations, the administration has been clear with their objective, which is addressing the need for new capacity to address a large load while not compromising the rate payer. And so the push from the Energy Dominance Council is consistent exactly with that. So I think we're in a position right now, which we're all encouraged to find ways to add megawatts to each of the grids in markets that we operate in, that's making the grid more reliable and more affordable to the ratepayer, while addressing the need for large loads. I think that's why PJM has been an advocate of this bilateral process, because it's trying to facilitate load and generation to come together in it.

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

First question, I wanted to ask on Slide 10 of the presentation on the Wild Alberta, you have a 2-gigawatt figure you've highlighted under realized infrastructure. Are you assuming then that, that amount, 1.2 gig Phase 1, 0.8 gigawatt, you expect that not to fall under your own generation?

Thanks, Ben. I would describe it differently. I would say it's our Zoom outlook into Alberta. And when you combine the Phase 1 plus MSSP and available generation, then we think that the capacity is closer to 2. So when Phase 1 was announced, we were consistent with that messaging as well. In our view, that number is closer to 2. And so there's that wiggle room between the 1.2 that was announced and 2, which we expect some accommodation through the Phase 2 dialogue as well. So I would take that as a general comment on the market and our confidence around capacity being available in Alberta without compromising affordability to the rate payer.

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

Yes. Look, I think the MOU is very important in terms of encouraging new build gas generation. I think our ability to take some or any merchant risk around the new build in Alberta will be predicated on our ability to operate a gas plant for the life of that asset. So the importance of repealing CER for Alberta is critical to that. It doesn't mean we can't build gas explicitly for behind-the-fence data centers, but I think the repeal of it opens the market for broader commercial opportunities. And I think our positioning in Alberta as one of the largest generators and with the most efficient fleet that's effectively providing baseload into the market, we're best positioned to price that marginal megawatt, contract that marginal megawatt, and provide energy services through long-term offtakes to large customers.

And maybe one more, just the last one, Alberta. You have your updated hedge for 2028, and yet I noticed that the forward curves have dropped dramatically since the last presentation you had of the quarter. Just maybe talk about directionally your thought process with hedging a certain percentage versus leaving it open, how you think about just Alberta power prices could be going?

Yes. I think first and foremost, our commitment to our balance sheet strength and our IG credit rating is paramount, and maintaining stable cash flows for the company. So our general approach to hedging has not changed in terms of 80, 65, 50, year 1, year 2, year 3. So that approach has not changed, and it will be consistent with that. I think strategically, as we look at it, we do have flexibility at the enterprise level, in particular, now that we're more diversified as a company. So we will hold to that to maintain stable cash flows and maintain our approach to our balance sheet strength. But now that we've got more exposure in more markets, and we've nearly doubled in size in terms of capacity over the last 3 years, we do have more levers to pull to take advantage of that contracted merchant exposure and how to optimize that. So I know it's not a direct answer to your question on what and how much, but I would emphasize that fact as we think about going out in that curve, in particular, year 2, year 3 and beyond, we will stay consistent to the 80, 65-50, but the constitution of what we're hedging where we've got flexibility to optimize given our merchant exposure effectively in PJM, Alberta and CIO.

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

Just following up on the last question, notwithstanding all the regulatory progress and the structural advantage of Alberta, obviously, the 2028 onwards forward is still only a touch higher than the current year, being about high 50s, low 60s. So maybe just focusing on the power price alone and not hedges, like how would you characterize these forwards? And directionally, what do you think the market is missing?

Thanks, Maurice. We had an interesting look back on this one. And if you looked at historically, 2018 or 2020, looking forward into 2023, in the forecast or the forward strip in Alberta, we saw a similar dynamic at play, which is given the lack of liquidity in the back end of the curve and the structural configuration of the market here, the market where you've got steepness of slope in the curve, there isn't the motivation or incentive to lock in at the back end of the curve when you have steeper contango in that curve. And so it's not that the market doesn't understand it. Given the lack of liquidity, there is no incentive to transact. So we continue to rely on the fundamentals in our outlook on pricing. And I would say where you've got the steepness of contango today, what's missing is the understanding of the tightening supply, the tightening of the supply-demand gap here over the next 3 years, and it's underestimating what the future spot price will be. So I can't tell you, Maurice, whether we are going to be at $80 or $90 in Q1 2028. But I can tell you with a high degree of confidence, we see a tightening market here and a return to higher pricing over that 3-year period of time. And to Ben's question before, that's what we're thinking about in terms of medium to long-term hedging and contracting in Alberta. We really like the exposure we have. We think the upside is asymmetric to the upside. In particular, as we look out at potential new builds in the market and data center load coming in, and continued economic growth in Alberta, which, relative to the rest of the country, is running well ahead.

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

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

So obviously, Phase 1 anticipates the demand arriving, call it '27, '28, and then maybe the supply to support that new supply that comes closer to the start of the next decade. If you start seeing demand arriving a little bit later, then perhaps you don't see the spike in price, perhaps later in the decade than '28.

Yes, it's an interesting point. And if you look at the existing market structure and how the marginal electron is priced. And by the way, there's a similar dynamic at play in PJM, where you had a 2-year BRA auction. Historically, that was enough to incentivize generators to go into new build because the cycle of the consecutive DRA auctions allows you enough visibility to FID build in 2 to 3 years and then play into that market dynamic. In Alberta, the dynamic is similar, but there's no capacity payment to incentivize new builds. So historically, the merchant market responded to higher pricing, but we had 2- to 3-year cycle times between FID and COD. And so today, where that cycle time is 4 to 5 years, and the cost of new build is 2 to 3x what it was 5 years ago, I don't think the response time or the elasticity of supply matching demand is the same as it once was. So I think what that means for your question is that the matching of new load to new supply, you and I will all have much more visibility on in the marketplace. So if prices run in Alberta in this merchant market, the probability of seeing new merchant capacity coming in and coming online and dampening the back end of the curve in the back end, I mean, year 2, year 3, year 4, we don't see as viable as it once was just because lead time, supply chain, construction times are much longer for new build. So the resilience of this market from a pricing perspective is looking actually pretty favorable for us.

If I can just finish off with a broader Canadian question. Yesterday, we saw the federal government unveil a number of pillars for its forthcoming national AI strategy. Just wondering what your first takeaways are of this framework. And in particular, whether any difference to the Alberta government's approach may mean better opportunities for Capital Power outside of Alberta?

Well, to talk about my own book here, Maurice, we continue to believe Genesee is one of the most attractive sites to host a data center in North America. Now we're in the business of selling power. So it's not incumbent upon us to do it at the site, but the opportunity exists there. I do believe there's strong alignment between the province of Alberta and the Feds around facilitating investment in AI, creating a sovereign data strategy for Canada. And I think we can play a part in that. And I think the federal government's push to facilitate capital investment and expedite the approval process is all in favor of that. I think the good news in Alberta is that the train has already left the station in terms of Alberta's support of data center capacity, Phase 1 going into Phase 2. But I think any further alignment between federal support for sovereign data centers and Alberta's continued welcoming of that industry without compromising reliability for consumers is moving in that direction. So I think yesterday was a positive in that regard. I think the next step, though, is how do we move that into we need 250 megawatts or 500 megawatts, and we need a COD by date. And I think those are conversations all of us are part of.

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

[Operator Instructions] Our next question or comment comes from the line of Patrick Kenny from NBCM.

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

Pat, thanks for the question. Look, I think from an intertie question, to the extent it's a national security issue and there's support for it amongst provinces, we are and will continue to be an active player in the conversation. But an islanded power market is facilitated by a baseload that's supported by rate payers for transmission and distribution, but it's also supported by generators through private investment. And so how that works in a market with interties where you've got different constituents, I think, is an important consideration because you don't want to undermine any of the existing market structures that exist that support the build-out and ownership of that infrastructure. So if one province is funded through a crown, all by ratepayers, and the other market is supported by private industry and ratepayers for transmission and distribution, you've got to find an equitable way to manage that on behalf of both markets because you can't compromise the market structure in one versus the other. So I don't look at the Intersight conversation as a threat. I think more infrastructure that connects the country and provides better reliability and affordability for customers, and encourages new infrastructure build and new industrial productive capacity. Those are exactly the conversations we should be having as businesses across the country. But we've got to work through the details to understand how it impacts each individual jurisdiction and how it ultimately benefits the whole. So it's something that we're actively in conversations around. We're having input on those conversations. But in itself, I don't see it as a threat because I think ultimately, if it does go through. And I think the economics of it are very, very tough. I'll remind our countries have over 40 million people, just over $2 trillion of annual GDP, and that GDP is half the size of California. So to be able to invest in such a significant amount of infrastructure where you've got relatively small markets, province to province, trying to connect with coasts where a lot of the economic activity occurs, the intertiein itself may not be a great value proposition for the ratepayer. And we just have to understand how all that will work.

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

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

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

Maybe just starting with Genesee and the 466-megawatt grid export cap from the MSSC. You did some testing above 466 megawatts earlier this year and also in 2025. Can you give us an update on how this initiative is going and when you think you might reach the milestone of being able to export 100 or 200 megawatts above that 466 megawatts into the grid?

Yes. Thanks for the question, John. We continue to be in the process of testing on that. As you noted, we've had preliminary tests, and it's an active program that we are working on in partnership with the ISO to advance approval of. We remain confident in getting additional megawatts online, and we hope to provide a further update as testing continues through the year. But I don't have a specific update on when and how much, other than we hope to have an update on that through this year. But the initial testing is moving forward and advancing in a favorable way, but we've got work to do, and we're working in partnership with the ISO on that.

Okay. And then just a bigger picture question on organic development, either renewables or gas and storage, most of your development pipeline will be complete by the end of this year. I think you just got one project due online early in 2027. So what kind of opportunities are you seeing to backfill that organic pipeline? And how do the potential returns compare with what you see in M&A markets right now?

I think we continue to be bullish on the opportunity to develop. I think as we came out from under the repowering project, which was our largest CapEx project we've ever undertaken as a company at Genesee, our focus shifted towards our renewable development. And as we've expanded and grown the company, I think we see a very compelling opportunity to develop around development. I think the best example of that is the backstop auction in terms of what we're starting to see in the market. We're starting to see longer-term PPAs associated with data centers and/or load serving entities looking to secure long-term supply. So at our Investor Day, we said we've got about 1 gigawatt of development pipeline for our company. And I would say, in earnest, we're really focusing on trying to grow that pipeline this year going forward. So I would expect that that's going to be a growing focus for us. In terms of relative returns to acquiring, I think it's a trade-off of duration and tail and contractedness versus short-term realizing of short-term pricing. And the reality is, we have to have a balance of both. But I think what we're seeing in greenfield development is commensurate with us delivering 13% to 15% shareholder returns over time. So we think our cost of capital is competitive. We think there are a number of opportunities, and all 3 actually renewable storage as well as gas, and we're trying to ramp up our origination efforts and build that pipeline. So that's a key focus for us now, given where we are as a company.

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

To the conversation about the 2 gigawatt view you guys have for Alberta versus the 1.2 in Phase 1. Just curious when you think you'll get some clarity on that in Phase 2a. We've seen some working documents from the ASO. And just your view on the 400 megawatts of Genesee being deemed potentially net new megawatts?

I think our dialogue has been constructive and collaborative on that front on Phase 2. We don't have a defined view on timing other than what the ISO has announced in terms of directional timing. But in terms of unlocking our megawatts over and above 466, our expectation is that it would be considered net new megawatts. And we believe the dialogue is consistent with that. So I think everyone -- I think one of the reasons we're so bullish on Alberta and on data centers relative to other markets is Alberta is one of the only jurisdictions right now. And at a high level, we may not have agreed on all the different pieces of how we're executing it. But at a high level, there's alignment between government, regulator, and industry on how to build and bring in new load into this market structure.

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

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

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

Yes. I think if you're looking at stage gates, I would say those are 2 critical stage gates. So, we've been in a position to move quickly at Genesee for 1.5 years. So our ability, we've done the work. We have a site. We know what a site plan looks like. And we continue to be, I think, in an enviable position to contract with anyone who wants to secure long-term energy here in Alberta on any project that they're pursuing, whether it's on our site or otherwise. So for us, it's similar to the conversation we were having on recontracting. In many ways, the arithmetic and the evaluation of how to maximize net present value per KW at the Genesee site, we're balancing everything there, which is we see a tightening market, we see a favorable energy market forming in '28 to '30. We've got expansion capacity at the site. We've got unlocked megawatts. And it's just balancing whether we use those megawatts to support a 10-plus year offtake with someone else on someone else's site, or someone looking for long-term supply, or we use some of those unused megawatts for someone who's co-locating. So I really like our positioning in Alberta right now. I think we're in a very good position on Genesee, where we've got multiple levers to play, and we've got the flexibility to play them.

Then maybe last question, just how would you rank or compare the confidence level or probability of the MOUs for the data centers at Genesee versus Midland today turning into a definitive contract? Do they feel like they're on similar paths and probability? Or one feel you have a higher confidence that this is going to progress to a final contract?

Well, I would answer it differently. I would say what's our probability of contracting and maximizing the value of megawatt at either plant, I would say, very, very high. So on MCV versus Genesee, MCV, we're advancing. I'd say there's high confidence we're going to contract those megawatts. We're advancing the MOU on the data center, but we've got uncontracted capacity that will ultimately optimize. So that's advancing, and we continue to advance Alberta. I would note that we started the NCV process well over a year after we started looking at Genesee as a site. So MCV has greatly benefited from all of the learnings we've had at Genesee and in Alberta, and we've actually come up from behind very quickly at NCV, our team, in terms of working with potential customers there. So I think for us, that's one of our advantages. We've been at this since '23 on multiple sites across North America. And we've been talking to all of the customers around what their site requirements are, what the ramp schedules are, what the reliability needs are, and even what their site configurations and power solutions they require. So we feel pretty good about how we can serve the ultimate customer here.

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

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

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