Thank you for standing by. This is the conference operator. Welcome to Capital Power's First Quarter 2023 Results Conference Call. As a reminder, all participants are in listen-only mode, and the conference call is being recorded today, May 1st, 2023. I will now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead. Good morning. Thank you for joining us today to review Capital Power's first quarter 2023 results, which we released earlier this morning. Our first quarter report and the presentation for this conference call are posted on our website at capitalpower.com. Joining me this morning are Brian Vaasjo, President and CEO, and Sandra Haskins, Senior Vice President, Finance and CFO. We will start with opening comments. Then open the lines to take your questions. Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on slide 2. In today's discussion, we'll be referring to various non-GAAP financial measures and ratios as 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 by other enterprises. These measures are provided to complement the GAAP measures, which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in our first quarter 2023 MD&A. Before I turn it over to Brian, I want to 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 Nation of Alberta Region 4. We acknowledge the diverse Indigenous communities that are in these areas and whose presence continues to enrich the community and our lives as we learn more about the Indigenous history of the lands on which we live and work. Okay, over to Brian for his remarks starting on slide 4. Thanks, Randy. Good morning. To begin, I'd like to announce some very good news. Last week, we executed a 6-year contract extension for Gorew ay relating to its successful efficiency upgrade bid in IESO's Same Technology Upgrade Solicitation. The efficiency upgrade of approximately 40 MW will increase Gorew ay's combined contracted capacity from 840- 880 MW. The new combined contracted capacity of 880 MW will apply to the existing IESO contract upon project completion and extend the clean energy supply contract from 2029 to 2035. The upgrade, which will enhance the efficiency of the existing turbines, is expected to be finished in 2025. We also submitted an efficiency upgrade bid for our York Energy Centre facility. Discussions with IESO are ongoing, and we are optimistic York will also be awarded a contract extension. Turning to slide 5, I'll provide an update on the Genesee One and Two Repowering Project. The project is on schedule to achieve simple cycle commissioning of both units in the fourth quarter of this year, followed by combined cycle operations in the second quarter of 2024. The current repowering project costs of CAD 1.1 billion, with an additional CAD 195 million for the battery energy storage system. The availability of trades labor continues to be an industry-wide issue, and the repowering project is experiencing modest labor cost increases. We are working closely with the EPC contractor and labor providers to assess the impact and develop further mitigation strategies. The cost pressures, however, are expected to be substantially offset by the lower estimated cost of an alternative solution to the BESS project. Overall, we continue to be on track to meet our goal of being off coal later this year. Moving to slide 6, we continue to advance our decarbonization plans to meet our net zero by 2045 target. The board is expected to approve the Genesee CCS project in principle by this summer, with a final investment decision in October. The FEED study is essentially completed with results better than original expectation. This includes finalizing capital costs, confirmation of technology, and the discussions of performance guarantees by Mitsubishi. The 2023 federal budget that was announced at the end of March included positive developments for the Genesee CCS project. This included reaffirmation of the role and mandate for the Canada Growth Fund to support de-risking of large-scale decarbonization through instruments such as carbon contracts with differences and enhancements to the 50% refundable ITC for carbon capture, utilization, and storage. We continue to have ongoing discussions with the federal government relating to financial support. This includes discussions with Innovation, Science and Economic Development Canada in the Canada Infrastructure Bank. These discussions are progressing well and on track with the schedule. I'll now turn it over to Sandra. Thanks, Brian. Starting on slide 7, I'll touch on the financial highlights for the first quarter of 2023. Overall, it was a strong quarter year-over-year. In fact, adjusted EBITDA of CAD 401 million was the highest quarter on record and was up 15% year-over-year, while revenues and other income before mark to market was up 34% compared to the prior year. Financial results benefited from higher realized Alberta power prices, partly offset by milder temperatures across most North American regions that reduced the dispatch of facilities such as Decatur. Adjusted EBITDA further benefited from the acquisition of Midland Cogen facility in September 2022. AFFO of $210 million was up 5% year-over-year, reflecting the strong adjusted EBITDA results and fewer turnaround activities, which was partially offset by higher current income tax expense. Net cash flows from operating activities were primarily impacted by higher receivables at our Alberta commercial facilities and changes in forward prices on our commodity derivative positions. Turning to slide 8, I'll touch on our Alberta Power and Natural Gas hedge positions, which are shown as of March 31st, 2023. Since the end of 2022, our power hedge volume for 2024 has increased from 7,000- 8,000 GW hours and from 6,000- 6,500 GW hours for 2025. Our hedge position for 2026 is 4,000 gigawatt hours. The weighted average hedge prices for all three years are in the low $70 per megawatt hour range. The hedge positions include long-duration origination contracts as another mechanism to manage price risk. The graph on the left shows the relative magnitude of hedges that are long duration extending out to years where we will see lower forward power prices. We've also increased natural gas hedges since year-end. Natural gas volumes of 70,000 TJs in 2024, 60,000 in TJs in 2025, and 35,000 TJs in 2026 have been hedged at favorable prices compared to current forwards, as noted in the table on this slide. Moving to slide 9. The chart here illustrates the movement in Alberta power price forwards compared to the forward curve that determined our 2023 financial guidance, which is shown by the blue line and averaged CAD 136 per megawatt hour. To explain this further, the yellow line shows the year-to-date actual settled prices and current forward prices that average CAD 154 per megawatt hour for the year. This strengthened since we held our Q4 analyst call on March 1st, as shown by the orange line. At that time, the settled price and balance of year forward prices averaged CAD 135 per MW hour. As you can see, there is significant increase to both previous benchmarks. Although we're well hedged for the year, the remaining open position of our non-baseload assets are well positioned to capitalize on volatile market conditions. On slide 10, I'll conclude my remarks by reviewing our first quarter performance, our 2023 targets and outlook. Sustaining CapEx was CAD 23 million in Q1. There are several planned outages remaining this year at Clover Bar, York Energy, Decatur, and Midland. Sustaining CapEx is on track to meet its 2023 target of CAD 135 million-CAD 145 million. Considering planned outages, we are on track to achieve the 94% availability target. For 2023, we are targeting CAD 1.455 billion-CAD 1.515 billion in adjusted EBITDA and CAD 805 million-CAD 865 million in AFFO. Capitalizing on the positive outlook in Alberta forward prices would move results to the upper end of these guidance ranges. Our growth outlook for 2023 is positive. This includes our well-positioned natural gas facilities in Ontario to address the capacity gap in the province, starting with the six-year contract extension for Goreway that Brian highlighted. As part of our CAD 600 million of committed growth capital target, we expect to make an investment decision on 2 renewable projects this year. Overall, we expect 2023 to be an excellent year, both financially and strategically. I'll now turn the call back over to Randy. Thanks, Sandra. Charisse, we're ready to take questions. Thank you. We will now begin the question-answer session. To join the question queue, you may press Star, then 1 on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press Star then 2. We will pause for a moment as callers join the queue. The first question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead. Yeah. First question is just on the contract with Goreway. Brian, can you maybe explain in terms of how the pricing works, whether or not you've brought down the capacity payments to get the extension, if they're flat, you know, to 2035, or do they step down when you get into the six-year extension? Mark, it's Sandra. We're limited on how much we can disclose at this point, given that the AESO is still having ongoing negotiations with ourselves and others as part of this process. I can say that when the contract kicks in in 2025 and COD, we'll see a modest uptick in our adjusted EBITDA as a result of the extension and then see a step down in the post-contract period, which is the last six years. Okay. Any indication in terms of cost to deliver on the upgrade? That's part of what we're not able to disclose. I think once this process is through, we'll be able to provide more details on the contracts and their costs and relative economics. Okay. All right. We'll wait for that then. Just in terms of the costs and the higher labor at Genesee, are you able to sort of roughly quantify that? I guess relative to where you are now and to what has to get done, is there any real, I guess, sort of timing in terms of where you might face the biggest kind of cost creep? You know, are you going through that right now? Is it, you know, is there more labor to come through the balance of the summer as you go through completion? Maybe just kinda how much visibility you have on costs and any pressures remain to completion? Mark, in terms of the cost increases that we're seeing at Genesee, as we indicated, it's substantially related to the cost of labor. We still are seeing some pressures around the interconnection. In terms of labor, we've got a very good handle on hours and so on and so forth. We're not expecting that kind of variance. It boils down to the cost per hour for various trades and, you know, where those costs are coming in and the cost pressures from a competitive perspective in terms of other projects that are going on, and maintenance that's taking place in Alberta. We're currently working through that coming up with revised estimates and expectations. I can say at this point, when we're looking at the project and including BESS, when you sort of put it together, we expect it, at the end of the day, to be relatively in the same spot. Not an expectation of very significant changes in overall costs. With you spelling out the BESS costs of, you know, around CAD 200 million, so you're implying that the labor costs could eat a good chunk of that, and then you'd have to shave or find some cost savings around the BESS alternative. You're sort of in a 10% of total budget sort of increase potential from labor. Is that right? In terms of total labor, again, we're going through that right now. Our expectation is in July, we'll have a much fuller description of where we expect costs to go and the ultimate costs associated with the BESS alternatives. And again. Okay. In combination, expect to end up in the same spot. Understood. Just coming to the CCS decision here. Obviously one element you want to derisk is on the contract for difference. Can you just maybe update us in terms of how active the discussions are? Is it ultimately you're looking for, you know, fixed price on the credit value, not so much the reference carbon pricing? Just maybe update us on the status and the type of contract you're trying to seek there. What we're looking for is a contract, and I'll just refer to it as a strike price, associated with carbon price. What we're looking for is establishing one where we're actually turning credits into cash. A contract for difference is where upside would be shared, 90% with the government and as well, you know, any shortfall, to the tune of 90% borne by the government. Then some basically basement, I'll call it, pricing associated with those credits, which we utilize ourselves to ensure that overall the project continues to be bankable regardless of government policy risk as we move forward. That's the general structure that we're looking at. It obviously does have implications or reference to the overall carbon market. I think as we shared with you at Investor Day, our expectation is that what I'll refer to again as our strike price is well below the government stated pricing expectations of CAD 170 a ton in 2030. Just, Brian, the way you spoke about it, would Capital Power be taking some of the risk on settlement prices in terms of their credit? So- Like if there was oversupply at times or undersupply, yeah. The only risk that we'd be taking is for that small 10% interest in terms of variance away from the from the strike price. Okay. All right. I'll leave it there. Thanks. The next question comes from Robert Hope with Scotiabank. Please go ahead. Morning, everyone. Maybe a bit of a broader question, just regarding to Avik Dey being announced as the CEO, like I said, a week or two ago. Can you maybe comment on, you know, why he is the right choice and kind of the, you know, what you believe he brings to the organization? Actually, Robert, at the end of the call, I do have, I've got a couple of comments to make. I'd also say, you know, the board went through a very rigorous process for an extended period of time and concluded that, you know, Avik, and among, you know, a number of alternatives, concluded that Avik was the best individual to be moving the organization forward. I would say that I've, you know, although providing input and information into the process, I was not involved in the decision-making process, but I would say I'm fully supportive of the decision that the board made. Again, I'll have a couple of comments at the end of, at the end of this call in regards to that. Okay. I was a little early. Moving over to the renewable side of the business, you know, how does the environment look, and kind of where are we in the development timeline in terms of the targeted two announcements for 2023? The market continues to be a little bit choppy with clarification of rules and so on and so forth. We still remain confident that, you know, we'll likely have two investment decisions this year on the renewable side. We continue to move some projects forward in anticipation of again, a couple of them coming to fruition this year. All right. Thank you for that. Brian and Keith, you know, all the best in the, in retirement. Thank you. The next question comes from Maurice Choy with RBC Capital Markets. Please go ahead. Thank you and good morning. Just wanna come back to the cost pressures and the CCS as well. Any implications of the repowering cost pressures on the CCS project, or are you anticipating that much of these labor cost issues might dissipate if and when the CCS construction begins? In terms of the implications of labor costs on the CCS project, you know, that's currently something that we are discussing in depth with both Mitsubishi and Kiewit as it relates to the project. The degree to which, you know, Capital Power will be taking on, you know, some or all or none of that risk is still an item of active discussion. In any event, more to come on that. I, you know, I would expect for the next few years, and depending on specific timing, you know, there'll continue to be labor pressures in the province and, you know, as such, continuing to see some cost pressures. I would say that what we're seeing, much like we're seeing, you know, in all areas, there are some significant upward pressure on prices that are due to the recent and significant inflation that, you know, has subsided. Looking at, you know, significant cost increases being more of a one-time event as opposed to a perpetual event of, you know, quite high escalation in labor costs. Thanks. I assume that when you look at the ITCs and all the other enhancements that you have, those present to you a cost mitigation in regards to these pressures. Is that fair to say? Naturally, the ITCs are a mitigant for 50% of the cost in that if there's a cost increase, then half of that essentially is covered by ITCs. On the other side, we do anticipate there'll probably be some discussions in terms of, you know, what happens between striking the project in October and the agreements that would be in place there and, you know, any cost changes that come to pass from then to the end of the project. You know, on one end of the spectrum, that may all be owners' costs, but there may also be some avenue for mechanisms to share some of those changes in costs. Again, you know, that's subject to negotiation and discussion between now and October. Thanks for that, looking forward to those details when that's announced. Switching over to a regulatory question, the Clean Electricity Regulations. As you think about the release of the first draft legislation this spring, what would you view to be a good outcome for your company, including the benchmark and also the number of prescribed life in terms of years? In the major issue for us, or actually there's really two. There's, you know, at the, one is the end of life for, you know, existing facilities. You know, we're thinking that an outcome more in line with a 30-year or a 35-year is more in line with the physical life of the assets. Also, as we're seeing in Ontario and, you know, some emerging work in Alberta, you know, there's need for natural gas to be on longer and probably, you know, deeper. We think that those trends will, again, push some of that expected life term out a bit. There's also some provisions that we haven't seen yet or don't have clarity on, you know, what sort of avenue is there for peaking-type facilities and so on a go-forward basis, again, beyond 2035. There's still a lot to be seen in terms of post 2035, but we expect that there'll be a significant amount of consultation taking place with the release of Gazette One. You know, we've been it's been expressed to us that a lot of Gazette One will be a basis for further discussion as opposed to, you know, this is the law and without, again, expect that there'll be a significant amount of consultation taking place with the release of Gazette One. you know, we've been It's been expressed to us that a lot of Gazette One will be a basis for further discussion as opposed to, you know, this is the law and, without, again, much avenue for a discussion. We're hopeful that the results at the end of the day will be constructive for Capital Power. Great. Thank you for the color. The next question comes from John Mould with TD Cowen. Please go ahead. Thanks, good morning, everyone. Maybe just going back to the CCS project and more just the steps that we should anticipate between now and an FID. More on the government support side, you will have seen the Heidelberg announcement from about a month ago that they signed a partnership agreement with the Government of Canada, and we're working on negotiations. I mean, should we expect the CCS project at Genesee to sort of go down a similar path in terms of an initial MOU and further discussions with various government entities before we see the finalized CFD in place? How should we think about all that? What we've been attempting to do since, you know, we started talking about this project more than a year ago, is sort of move everything along at the same rate and have things come together at different points in time. Much like around Investor Day, there was a number of things that came together that pushed the project forward and made it an even more a reality. The same thing we expect to happen in July, where we'll have documentation from the different avenues of government support, including, you know, Canada Infrastructure Bank, SIF, et cetera. Also at the same time, the completion of our FEED study and a very good view of cost. As we move forward to. At that point, expect, as I indicated earlier, we'll have a we'll be approaching the board for an approval in principle of the project. That provides us, you know, greater opportunity and provides some significant initiative in terms of getting completed agreements from each of the government, the support entities, plus final commercial arrangements with the contractors on the project. Again, we're moving everything along at the same on the same schedule as opposed to sort of one piece at a time. Okay, great. Thanks for that. Maybe just on the FEED study, you know, Brian, you had said earlier in your prepared remarks that that was coming out a little bit better than expected. Are you able to give just a little more color on that and, you know, in particular, the kind of technical and operational elements and how that's coming out versus what you'd been hoping? You know, just to sort of frame up the FEED study. You know, what we put in there were elements that we, that we felt, you know, for example, dealing with the fact that, you know, the facility will have to ramp up and down. You know, we put in parameters that said, you know, the FEED study, the technology needs to meet these kinds of parameters to actually be operational for us. What we're finding is that as they've gone through the work, there's greater flexibility in the unit than we had set as minimum expectations. That's one area. Costs in terms of the operating costs, energy, et cetera, is tending to be, you know, better than what we had anticipated at the outset. Capital cost continues to be coming in, you know, very promisingly. You know, certainly a lot of the work around establishing what would be appropriate performance guarantees. The fact that Mitsubishi is going to provide a significant amount of performance guarantees is very promising for us. We weren't necessarily expecting that we would get as extensive performance guarantees as we believe we'll be getting. When we look at the numbers around those guarantees, I think we've shared that, you know, initially, we were hoping to get about a 95% performance guarantee on capture. That does seem to be what the number that Mitsubishi will guarantee. That's the guaranteed number as opposed to their expectation, which is often different. Again, getting to a number that they'll actually guarantee is very positive for us. It's, again, it's pretty much on all fronts. It's turning out to be much better than we had anticipated. Okay. Thanks for that. Maybe just one last one on the renewables projects in terms of trying to finalize those two additional projects this year. I'm just curious on the interconnect side. Can you just maybe give us more broadly an overview of the interconnection environment you're seeing in your core markets for renewables and a sense of how that's impacting the pace at which you're able to advance your pipeline? You know, you put your finger on a significant challenge for the industry. You know, if you take Alberta, for example, you know, whenever we're connecting, obviously there's an interconnection. In addition to that, there's also, you know, growing capacity constraints and so on. That's definitely an area to be mindful of. It certainly is having an impact on what projects, you know, should be moving forward and what projects should be, you know, waiting until there is some enhancements to the transmission system to allow them to connect. In the U.S., it's a very mixed bag. However, I'd say that, you know, interconnection is a problem. From an industry perspective, typically the projects that, you know, I was referring to that we're moving forward are extremely well-positioned from an interconnect perspective, whereas there's others, you know, in our portfolio of opportunities that, you know, if we went forward and, you know, applied for interconnection, you'd be looking at years before you'd be connected. You know, the wide range. The projects that I think we laid out at Investor Day as being ones that are near potential investment decision all are, you know, in process and in some cases, you know, may have interconnection arrangements already. Okay, great. I'll leave it there. Thanks very much for taking my questions and all the best to you, Brian, and also to Keith on your pending retirement. Thank you. The next question comes from Benjamin Pham with BMO. Please go ahead. Hi. Thanks. Good morning, and also, all the best in retirement, Brian. Maybe, first question on the renewable power side of things with acquisition market. Can you comment on maybe high-level trends, particularly with, how does it look on M&A for renewable versus build? Has the buyer composition changed at all, when you look at the last, say, six to 12 months? In terms of the acquisition side, you know, the biggest challenge for us as it comes to renewables is just simply, you know, our cost of capital versus a lot of the financial players out there. You know, that continues to be a significant trend, continuing to see financial interests either in their own name or supporting organizations that they would be in partnership with. There's continues to be that pressure on on the renewables side. You know, on the other hand, you know, issues that we just talked about in terms of interconnection, basis differentials, and a number of other issues, you know, seem to be, you know, creating a perception that, you know, renewables may not be as great an investment as, say, they were thought of maybe a year ago. I'd say on balance, competition is about the same as it has been historically. Maybe a bit of a shift in players, but it still is at cost of capital that we have difficulty competing with. On the development side, you know, we create our own value. We find that, you know, we continue to be, you know, well-positioned for bidding projects or bidding opportunities from a greenfield perspective. Okay. sounds like greenfield is still better than M&A. Oh, by a long shot on the renewables side. Okay, interesting. Maybe in Alberta, there's some spec that there could be some Alberta power assets for sale. Maybe you can comment on your exposure in Alberta with CCS. Do you think you're full in Alberta? Could you remind us around your market share position and how high you can go? In terms of, you know, mark assets or the appetite to acquire assets in Alberta, you know, there certainly are a couple of assets that, you know, if they ever came to the market, you know, might consider or ones like, you know, take, for example, Shepard Facility. If ENMAX was announcing that it wanted to sell its half, you know, we might well be interested in purchasing it or going along with them and selling the whole asset. There are assets that are strategic to us today that, again, we may consider going forward. In terms of, you know, assets that don't necessarily have a significant market position or anything that brings additional value other than simply megawatts, we would tend not to be interested in. You know, we're pretty comfortable with the Alberta position where we're at. You know, certainly if we grew significantly in Alberta, and, you know, there's no magic numbers around where you start running into concentration issues. There are some statements that have been made in the past, sort of around 20% or whatever. You know, where it, where you start running into some issues can well be below that depending on the types of assets you have. Or you could exceed that, but you'd be faced with dispatch requirements on some of your or all of your facilities, which certainly would impair the value of the portfolio in general. Pretty comfortable where we're at. Again, you know, certain strategic assets we may well be interested in. Okay, that's great, Colin. Thank you. The next question comes from Andrew Kuske with Credit Suisse. Please go ahead. Thanks. Good morning. I guess just with the evolution of the Alberta power market and what's sort of coming down the pipeline, with another sort of market transition with new supply coming online, how has your hedging philosophy evolved amidst all of that? You know, clearly you layered in a bunch of hedges in the quarter, but how are you thinking about the evolution of your policy and just the economics associated with it? Morning, Andrew. I think what we've been doing for the last number of quarters now and that we've spoken to is that the expectation of incremental supply will bring prices back in line with a longer-term sort of average expectation. As a result of that, we have been very active in the origination market with multiyear contracts, just thinking of the backwardation of the, of the power curve. That has been a nuance of our strategy that was prudent given the incremental length that we now have with the return of Genesee one and two. Beyond that, our philosophy and our approach to hedging remains unchanged for the balance of the book. We look at our view on where prices will move, and we'll hedge accordingly. Expect that, we'll continue to mitigate risk by laying off length at prices that we think are attractive and use the efficiency of our fleet to capitalize on those upsides. No shift in strategy, I'd say, from what we've been doing the last couple of years. Okay. Appreciate that. And then, you know, as far as structured offerings of the power from natural gas facilities and then pure renewable power, are you seeing anything sort of interesting on that front across your markets? Or are they really two distinct and very different markets from a customer standpoint? They're actually pretty distinct from a customer perspective. You know, typically those organizations, particularly the commercial ones that are pursuing long-term renewable contracts, you know, cost of energy doesn't tend to be a large component for them. You know, whereas, where you get parties stepping in to hedge, you know, 7x24 power positions, et cetera, they tend to be more, I would say, energy-intensive. So, you know, definitely different markets and looking for, you know, different attributes and benefits. Certainly they come together in terms of visibility of one to the other, but, you know, don't see a significant amount of overlap at this point in time. Okay. Appreciate that. One final one, if I can sneak it in. It's just on the hydro situation in Western Canada and also the Pac-Northwest. The data looks a bit mixed, right now from a standpoint of some places above average, some places below average. I guess, how do you think about the hydrology situation in the West, and then how that transmits back into Alberta in the summer market? We're looking at that as being somewhat neutral, as, you know, obviously the implications in BC is that, you know, it sets how much energy they may have, you know, in excess of their own requirements or available to export south or to the east. When we look in Alberta, you know, there's been some pretty good snowpack in a few places, generally speaking, you know, the moisture levels in Alberta have been a little bit lower. Again, you know, it's very dependent on the specific area in which, you know, the water catchment takes place. Again, as you say, it's a pretty mixed bag. I think what we're kind of watching quite closely, though, is as you look down the Pacific Northwest, what implications there may be in California and how that impacts on power prices in the province. Okay. Very much appreciated. Thank you. The next question comes from Naji Baydoun with iA Capital Markets. Please go ahead. Hi. Good morning. I don't know if there's something that you can disclose or maybe it's a bit too early. Do you have a target for the equity partnership on Halkirk 2? The partnership we are looking at at Halkirk is First Nations participation. That's in progress in terms of discussions. Beyond First Nations participation, we're not looking at any other partnership on Halkirk. Okay. I guess it's a bit too soon to quantify what that would mean in terms of the, like, the amount or the percentage? It's a little bit early at this point. Okay, that's fair. Just related to this, kind of a broader funding strategy, maybe tied back to the earlier question about renewables M&A. You know, not just on Halkirk, but maybe other projects going forward. Are you maybe thinking about sort of a broader funding strategy that is tied to selling down ownership stakes in renewable assets, either asset-specific sell downs or maybe like a larger portfolio monetization? Is that something that's part of the strategy going forward? Asset sell downs on renewables has sort of been in our toolkit for a while. It's nothing that we have obviously executed on at this point other than our disposal of K2 a number of years ago. I would say that that is an option that remains with us, where we feel that we could unleash some value in our renewables by bringing in a partner on it. I would say it's something that is we keep warm on the table, but there's no immediate plans to do that. We'll just weigh that against other alternatives of generating funds as we move forward. Understood. Nothing imminent that would cause you to need access to that kind of capital, but it's on the table. Maybe just about on that. Yeah, exactly. Sorry, I would just add to that. Go ahead. Partly, I would say is that when you look at our cash flow this year and the growth we have on the table, we are more than funding with internally generated cash. That, in and of itself, wouldn't drive us to execute on anything in the near term. Got it. Understood. Just maybe a final clarification question. Of the two renewable project FID targets for this year, is that separate from the rebidding of the North Carolina solar projects, or would those be a part of that? They would be potentially part of that, although I'm not sure timing would necessarily line up with those projects. Definitely, those are ones that we'll be moving forward with this year. Understood. Okay. Thank you very much. Congrats, Keith and Brian, on the retirement. Thank you. The next question comes from David Quezada with Raymond James. Please go ahead. Thanks. Morning, everyone. Maybe just a follow-up on the CCS project and specifically the hub with Enbridge. Just wondering if there's any progress on sort of the deliverables for that piece. I believe something around the geology, and I guess you're developing a sort of a commercial agreement there. Any details you could share there? In terms of the development of the hub, they have been drilling wells into the formation or a well into the formation that they would utilize for the sequestration of the carbon. That's gone well. That is also in conjunction with, you know, tests they had done years ago into the same formation. This will be very much a test well to ensure that the formation works, that it, you know, A, holds pressure and et cetera, et cetera. Things are going, I think, a little bit behind where we had expected, but no significant delay in timing at all. In addition to that, we have started in-depth commercial discussions and with expectations that we'd have be close to an agreement by July and certainly finalized agreements by the October timeframe. Excellent. Thanks, Brian. Appreciate that detail. Then maybe just one more from me on Halkirk 2. I'm just curious if you have any what your plans are for the portion of the capacity that's not under contract there? Maybe on a related note, what kind of demand you're seeing from corporate buyers in Alberta today for renewables? There continues to be demand in Alberta for, you know, renewables. You know, we do expect that, you know, given, you know, some of the earlier discussions on constraints on some of the transmission side and so on and so forth. We're actually not in a big hurry to market it, as we expect that some of the values may start improving because the competition in the market may not be quite as extensive as it has been over the last couple of years. Do expect that at some point it'll be contracted, but again, not in a rush to see it contracted in the near term. Excellent. Thanks for that. I'll reiterate the best wishes on your retirement, Brian and Keith. Thank you. Once again, if you have a question, please press star then one. The next question comes from Patrick Kenny with National Bank Financial. Please go ahead. Thank you. Good morning. Just to follow up on the Alberta power market here. I guess with the provincial election right around the corner, just wanted to check in to see if you're hearing any rumblings of any regulatory changes or revisions that could come along with either political platform, that might have an impact on either, you know, the market construct, the pace of renewables development, or perhaps your own decarbonization plans in the province. Just starting at the top, both parties have expressed support, continuing support for the energy-only market. That has been public on both fronts. The other thing that's out there, Pat, is the, there's the AESO is, or AESO has issued a report that suggests that there needs to be some modest changes to whether it be market construct or whether it be transmission or whatever, that would tend to be more supportive of natural gas, less supportive of renewables, as we go forward, and with a bit of a sense of urgency. We expect, you know, whomever wins the election will move on that. We expect the outcome of those deliberations to be positive for Capital Power or, if anything, you know, potentially slightly negative. Again, we'll see how that develops. We'd expect both parties, you know, wouldn't argue with physics and would move forward with some sort of, again, very modest adjustments. On balance, we're not seeing there's a lot of issues. Both parties have taken, when looking at cost, have taken the positions around, instead of trying to impact on the wholesale market, they have ended up with subsidies on the retail side. Again, we're not seeing anything that would cause us any great political concern. I think for once, we're actually not in the crosshairs in a political debate leading up to an election. Pretty pleased with that position. Okay. That's great color. Thanks, Brian. Just one last housekeeping item. Apologies if I missed it. Any update on the timing for potentially rebidding the North Carolina solar projects? That is sometime in the late summer, fall timeframe. Okay. Your thoughts around, I guess, potentially rebidding, based on existing market dynamics and where econs are currently sitting? We're actually, we continue to be pretty darn positive about the rebidding prospect, given that we're, you know, some of the issues that we were talking about before in terms of connections and so on. We're actually set. They've been negotiated, because again, we're rebidding. We're real comfortable with, you know, those kinds of risks and costs around the project. We're feeling pretty good about those. All right. Thank you. Brian Vaasjo, congrats on taking the company to where it is today. Thank you. This concludes the question and answer session. I would like to turn the conference back over to Mr. Brian Vaasjo for any closing remarks. Thank you. To start, I'd like to thank the investment community for working with me and supporting Capital Power over the past 14 years. I really enjoyed the respectful, candid, and constructive discussions. To the analysts on the call, thank you for the work you've done on the Capital Power name over the past number of years. I know our story has been a challenge from time to time, but I feel you've always given us the benefit of the doubt. Looking forward, I'm very comfortable leaving Capital Power in Avik Dey's hands. I've known Avik for several years, and I'm confident he is aligned with the strategy we've been talking about to you over the last number of years and is very capable of driving Capital Power forward. Avik is on the call this morning and will share some of his own thoughts with you. Avik? Thank you for the introduction, Brian. Firstly, I'd like to acknowledge Brian on his 15 years at the helm of Capital Power. The strength of the company's culture, people, and assets is a testament to his leadership and commitment to the organization. We all wish you a happy and healthy retirement, Brian. I'd also like to congratulate Keith Chisholm on her retirement and acknowledge her for her contribution and service to the company. I am honored to be selected as Capital Power's next president and chief executive officer. The company has a long-standing history of delivering reliable and affordable electricity across North America. The company's well-defined strategy of investing in critical natural gas generation, building new renewable capacity, and establishing decarbonization solutions for our fleet has established this company as a leader on energy transition. Going forward, we remain committed to this strategy. We'll look to further build upon our leadership position. I also look forward to an active and engaging dialogue with our investor community as we come off of coal in 2023 and chart our path towards becoming net zero by 2045. Our ability to deliver per-share value, growth, and performance relies on the continued support of our shareholders. I know that all of us at Capital Power are deeply appreciative of our investors' support. We look forward to furthering that relationship over the coming quarters and years. I am grateful to be joining this incredible team and dedicated and passionate professionals. Excited to get started next week. Thank you. Back over to you, Randy. Okay. Thanks, Avik. Okay, that concludes our conference call. Thank you for joining us today and for your interest in Capital Power. Have a good day, everyone. This concludes today's conference call. You may disconnect your line. Thank you for participating. Have a pleasant day.