Thank you for standing by. This is the conference operator. Welcome to Capital Power's Second Quarter 2023 Results Conference Call. As a reminder, all participants are in listen-only mode, and the conference call is being recorded today, August 2, 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 second quarter 2023 results, which we released earlier this morning. Our second quarter report and the presentation for this conference call are posted on our website at capitalpower.com. Joining me this morning are Avik Dey, President and CEO, and Sandra Haskins, Senior Vice President, Finance and CFO. We will start with opening comments and 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 will be referring to various non-GAAP financial measures and ratios, as noted on slide three. 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 second quarter 2023 MD&A. Before I turn it over to Avik, 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 Avik for his remarks starting on slide 4. Thanks, Randy. Good morning. I am now three months into my tenure as CEO for the organization. I'm grateful for the warm welcome and enthusiastic engagement from my colleagues around North America. I've also had the opportunity to meet several of you from the analyst community and look forward to connecting with those of you I have not met in the future. In my introductory comments to my colleagues a few months ago, I spoke of Capital Power embarking on an evolution, not revolution. The company's historic success has been underpinned by a determined focus on delivering reliable, affordable, and sustainable power generation solutions. This strategy has been historically grounded in a belief that owning and optimizing critical natural gas generation, building new renewables capacity, and delivering low-carbon solutions through batteries and applying decarbonization technology to our existing fleet would deliver attractive growth. This was, is, and will continue to be the bedrock of our few forward strategy. During the second quarter, we were negatively impacted by an untimely outage. We had a number of developments, all of which are firmly aligned with our long-term strategy and approach. In the slides ahead, Sandra and I will discuss these updates now. Firstly, the Genesee 1 and 2 Repowering Project is a material and impactful project for our company. Our June twenty-ninth news release outlined our update on a cost increase and schedule delay. Notwithstanding that update, the project continues to be highly attractive as the repowering project will significantly improve performance and reduce emissions. Secondly, our midlife natural gas strategy continues to deliver results. With the award of a long-term contract at East Windsor and contract extension at York Energy Centre, Capital Power has now secured extensions and/or expansions at all three of our gas power generation facilities in Ontario. This is in addition to two new battery storage awards at our existing plant sites. Combined with our existing capacity, the company will have more than 1,500 MW of capacity in Ontario. On the renewable energy side, we continue our growth of solar. We executed a 25-year PPA for our Maple Leaf Solar project in North Carolina and have well-positioned solar projects we're bidding into competition. To increase our competitiveness and support our solar development growth pipeline, we have secured a strategic sourcing solar module contract with First Solar. Notably, this solar PPA, along with the newly awarded Ontario contracts, has extended the average remaining contract term of our contracted facilities. Lastly, we remain steadfast in our ambition to decarbonize our natural gas fleet. We continue to advance decarbonization technologies with our Genesee Carbon Capture project. Let's go into the details. A key example of our leadership in the energy transition, our Genesee 1 and 2 Repowering Project, is one of the largest commercial-scale projects of its kind. The repowering project delivers incremental capacity of 500 MW to a total capacity of 1,388 MW, an increase of 63%. In addition, the pro forma site will benefit from the extension of the asset useful life and deliver long-term cash flow growth. The repowered units will have improved emission intensity, performance, and competitiveness. It will be utilizing the best-in-class natural gas combined cycle technology with a heat rate advantage over all current and announced natural gas facilities that repositions it low on the merit curve. In late June, we provided an update on the Genesee 1 and 2 Repowering Project schedule and costs. Due to construction delays, we have revised the commissioning timelines. As shown on the slide, the start of simple cycle commissioning will begin in December of this year for Unit 1, and in March 2024 for Unit 2. This will be followed by the start of combined cycle commissioning of Unit 1 in April 2024, and June 2024 for Unit 2. We expect to continue blending natural gas with coal to align with the repowering commission schedule in 2024, and ensure reliability and affordability of the Alberta power grid. Turning to slide 6, I'll touch on the Genesee Repowering Project cost. The revised budget for the project is now $1.35 billion. This is a $73 million net increase from the $1.277 billion cost that we provided at our Investor Day last December, which included the cost of repowering and the addition of battery storage. The changes from then to now include a $268 million increase from cost escalations and increased labor costs at the repowering project. On batteries, we have developed an innovative alternate solution to meet the MFSC limit, which received conditional AESO approval, thus saving the $195 million through cancellation of the battery storage. That results in the $73 million increase from $1.277 billion that we communicated at Investor Day in 2022, to the $1.35 billion, which we communicated at the end of June. From an equipment perspective, the majority of materials are on-site, and based on the progress made to date on Unit 1, we have substantially locked down the scope of project, as the learnings from Unit 1 will be applied to Unit 2. However, the project costs have been impacted by a shortage of skilled labor that is industry-wide. We are addressing this issue through competitive attraction and retention packages, which will secure the resources we need through to the completion of the project. We also continue to work with our contractors to maximize labor productivity and address absenteeism, which we believe will be effective in mitigating further labor cost increases on the project. Despite the higher project costs, the returns continue to be strong. Turning to slide 7. In Ontario, we have been an active participant in ISO's expedited call for new power generation and capacity in high-priority areas to help address ISO's forecasted shortfall. We have been successful on 5 projects bid that will add approximately 350 MW of capacity to our Ontario operations, with the start of commercial operations in 2025 for all projects. The successful projects include a 106 MW natural gas expansion at our East Windsor facility and battery storage projects at both York Energy and Goreway. The combined costs of these 3 projects are estimated at $655 million. The contract terms are approximately 15 years for the East Windsor expansion and approximately 22 years for the battery storage projects. In addition, we were successful with capacity upgrades of 40 MW and 38 MW at Goreway and York Energy that resulted in contract extensions. Overall, the achievements in Ontario continues to validate our mid-life natural gas strategy of acquiring well-positioned assets in markets with strong fundamentals, enhancing, upgrading, and expanding the facility, and extending their contracts. Furthermore, the deployment of battery storage on existing natural gas sites demonstrates the strategic value of these sites and incumbent market position to deliver low-carbon growth. Moving to slide 8, we see attractive growth opportunities for solar in North Carolina. As I mentioned earlier, we executed a 25-year fixed-price renewable PPA for our Maple Leaf Solar project with Duke for 100% of the output. The project cost is approximately $219 million, with expected commercial operations in the fourth quarter of 2026. We also have three well-positioned solar projects totaling 160 MW, that we are bidding into Duke's 2023 solar procurement RFP in September. To support our US solar development pipeline, totaling nearly 2.4 GW, we have secured our first order for 1 GW of responsibly produced ultra-low carbon solar modules. This will help increase the competitiveness of the solar projects, as the use of US-made products will qualify for domestic content under the Inflation Reduction Act. Turning to slide 9, decarbonizing Genesee with our Genesee Carbon Capture Project. We have now completed our technical assessment, including the FEED study, with positive results. We continue to advance the commercial and financing components of the carbon capture project. Productive discussions with government entities are ongoing, and there is strong support for the project to advance the decarbonization of Alberta's grid. There is also supportive funding through various programs. Discussions continue on a carbon assurance mechanism to de-risk our project from future government carbon legislation. A final investment decision will be made when the carbon assurance mechanism has been negotiated. An update on FID timing will be provided once there is a material update to commercial negotiations. Turning to slide 10. This morning, we announced our 10th consecutive year of dividend growth, with a 6% dividend increase effective for the 3rd quarter, 2023 dividend. Over the past decade, we have delivered an annual compounded dividend growth of approximately 7%, and our dividend growth guidance continues at 6% per year out to 2025. I'll now, I'll now turn it over to Sandra to discuss our 2nd quarter results and outlook for 2023. Thanks, Avik. Starting on slide 11, I'll touch on the financial highlights for the second quarter of 2023. Overall, second quarter financial results benefited from a full quarter from MCV that was acquired in September of 2022. This was partially offset by lower Alberta commercial segment results due to the coincidental unplanned outages at Genesee and Clover Bar that led to a short position during periods of high Alberta power prices, which I will elaborate on in more detail on the next slide, and reduced generation from our US assets due to mild temperatures and low wind resources. We reported Adjusted EBITDA of $327 million. That was up 3% year-over-year. AFFO of $151 million in the quarter is down 16% from a year ago, as the strong Adjusted EBITDA results were partially offset by higher current income taxes that are based on 2022 results and higher sustaining CapEx. As we have demonstrated over time, our hedging program, backed by the reliable performance of our fleet, has proven to be highly effective at reducing risk and creating incremental value. However, in early June, due to a culmination of events, the portfolio was short during high-price days, including the highest settle day of the year, which lowered the overall portfolio captured price. The graph illustrates generation from Genesee 1 and 2 during the month of June, as shown by the green area, while the blue area represents the daily Alberta pool prices in the month. As highlighted on the chart, Genesee 1 and 2 both experienced unplanned outages during June 5th to 10th. Typically, during periods of Genesee outages, our Clover Bar peaking units would run to backstop the position. However, only one of the three units was available during that time. At the same time, Alberta was experiencing record-high temperatures, which drove up demand, while supply shortages from low wind generation and competitor plant outages all contributed to high power prices, as shown by the blue bars. To cover the hedge position, our trading desk had to buy power at high spot prices. Overall, this resulted in a $20 million-$25 million negative impact on the second quarter results. The increased penetration of renewables and overall supply shortage in the market will continue to drive volatility until new supply comes online. June prices included 5 hours at the price floor and 11 hours at the price cap, daily settles ranging from $26 per MW h, which was the lowest in 2023, to $548 per MW h, which was the highest in the year, leading to the highest June settle ever. While ill-timed outages can result in losses like we saw in June, the elevated prices driven by that same volatility allow us to step into hedges at higher prices. Over the balance of the year, the downside impacts of this event are more than offset by the higher prices captured by our hedging strategy. Turning to slide 13, I'll review our financial performance for the first half of the year. The financial performance reflects strong Alberta commercial segment results, where our average realized power price was $91, compared to $84 per MW h for Q2 of 2022. Adjusted EBITDA was $728 million, up 9%, and further benefited from 6 months of contribution from MCV. AFFO of $361 million was down 5% year-over-year due to the impacts of higher current income taxes. Turning to slide 14, I'll touch on our Alberta Power and natural gas hedge positions, which are shown as of June 30, 2023. Since the end of the first quarter, our power hedge volumes for 2024-2026 have increased. For 2024, it has gone up from 8,000 to 8,500 GW h and from 6,500 to 7,000 GW h for 2025. For 2026, the hedge volumes have gone from 4,000 to 5,500 GW h. The weighted average hedge price are mid $70 per MW h for 2024 and low $70 for 2025 and 2026. 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. Our natural gas hedge volumes of 70,000 and 60,000 TJs for 2024 and 2025 are unchanged since Q1. In 2026, we have increased our natural gas hedge volumes from 35,000 to 45,000 TJs. Natural gas volumes have been hedged at favorable prices compared to current forwards. Moving to Slide 15, as Avik mentioned, we have been successful on five Ontario project bids. To fund the equity requirements of the projects, we are activating our DRIP, effective with the third quarter dividend in October. We expect to raise approximately CAD 75 million-CAD 80 million per year based on the participation level we experienced when the DRIP was last used in 2021. We view the DRIP as a cost-effective vehicle, as it is best suited to raise the smaller size of equity required over a time frame that aligns with the CapEx spend profile. On Slide 16, I'll conclude our remarks by reviewing our 6-month performance relative to our 2023 targets. On average, facility availability was 94% in the first half of the year, and we're on track to achieve the 94% availability target. Sustaining CapEx was $73 million in the first 6 months and is on track to meet its 2023 target of $135 million-$145 million. Our 2023 financial targets include $1.455 billion-$1.515 billion in Adjusted EBITDA and $805 million-$865 million in AFFO. We are currently trending to be above the midpoints of the annual financial guidance ranges. With Maple Leaf Solar and the Ontario growth projects, we have exceeded our $600 million committed growth targets for capital. Proceeds from the DRIP will provide a cushion to execute on additional growth as we continue to see a pipeline of good opportunities that are on strategy. Overall, the outlook for 2023 continues to be strong. I'll now turn the call back over to Randy. Okay, thanks, Sandra. Charisse, we're ready to take questions. Certainly. We will now begin the question-and-answer session. To join the question queue, you may press star then one 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 two. We will pause for a moment as callers join the queue. The first question comes from David Quezada with Raymond James. Please go ahead. Thanks. Morning, everyone. Maybe I could start with kind of a broader strategic question. You guys have obviously done really well recently with growth opportunities in your sort of key hubs. I'm just curious, as you look across your fleet, are there any assets you see as non-core today and any situations where you might see asset recycling as a possibility? Thanks for the question. I think we continue to evaluate the portfolio. Traditionally, asset rationalizations haven't been part of our approach, but I think as we go forward and look at growth opportunities, we'll continue to look at optimizing the portfolio. I think I'm very encouraged early on at our core positions, in particular, around Alberta, Ontario, MISO, Desert Southwest, and TVA. We see all of those areas as, as, significant growth opportunities in and around our critical natural gas assets, not just to expand, around those particular critical assets, but, you know, build out renewables capacity. Excellent. Thanks for that, Avik. Then maybe just one more for me. Wondering if you have any, any recent thoughts on the opportunities at Midland Cogen, potential expansions there? I guess in that region, you know, how are you thinking about renewable expansion, I guess, especially in the wake of that, you're securing panels for solar? I think, you know, we're completing the full integration of MCV into Capital Power. MISO continues to be a very attractive place for us to do business, and we are looking at growth opportunities there as we bring the team on board and integrate with our own business development efforts. The answer is absolutely yes, we're looking and evaluating at opportunities there. Excellent. Thanks for that. I'll, I'll turn it over. The next question comes from Robert Hope with Scotiabank. Please go ahead. Good morning, everyone. Just a question on the Alberta power market structure. The most severe, the MFSC, the most severe single contingency, limit was maintained at 466. You know, that has allowed you to get rid of the battery project there. As you look into kind of 25 and 26, you know, can you walk us through how you're thinking about potential other changes in the market, which could allow you to get Genesee to over 500 MW per unit, and whether that would be other solutions or something along the fast net demand response that the AESO has put forward? Thanks for the, the question. Yes, the AESO just announced last night that it plans to take a review of the market and the characteristics of the market. We will be participating in that. Think that the focus for that is going to be looking more at the implications of the build-out of renewables and the rate at which renewables are penetrating the market and creating a need to look at some of the products that you've mentioned. Expect that over the, the next few weeks, we will be going through the report in detail and participating in those discussions with the AESO on, on market design and, and the tweaks that might be needed to make sure we have a reliable and affordable system here in Alberta going forward. All right, appreciate that. Then maybe, you know, broader and, and more conceptual in nature, just with Genesee 1 and 2 coming down in June and Clover Bar not being able to backstop it, you know, as you move forward, Genesee 1 and 2 will be a larger percentage of your or of your merchant exposure in Alberta. You know, have you thought about any potential changes on your hedging policy, just given that you will have 2 larger units with potential downside scenarios like we saw in June? Yeah. I think with respect to the hedging strategy, we, we intend to stay the course. As you know, one of the things that we have been doing is building out our CNI business to have more longer-term hedges in place that would allow us to still step into hedges for the balance of that portfolio. I, I think we w- don't see that there's a real need to change our hedging strategy per se from what it is has been in the past, just even with the incremental megawatts from repowering. I appreciate that. Thank you. The next question comes from Patrick Kenny with National Bank Financial. Please go ahead. Thank you, good morning. Just with respect to the expected returns here to be generated from your new development projects, is there a blended IRR or cash flow build multiple that you can provide for your $600 million or so of growth CapEx in Ontario? As well, on the Maple Leaf Solar contract, you know, what would be the expected return both on an unlevered and levered basis net of tax equity? Firstly, in Ontario, the $655 million, we're looking at those, those will meet our contracted hurdle, hurdle rates on an unlevered basis, and expect that we'll have about 20% equity to fund those, so to get to the levered basis. As far as the actual contributions, we see that from a combined basis, all of those projects would contribute about $55 million-$60 million in Adjusted EBITDA and about $65 million-$70 million in AFFO. For the Maple Leaf Solar project, it does hit our contracted unlevered hurdle rate, which would include the expectation of using tax equity funding for that. Our contracted hurdle is around that 7% range unlevered. Okay, 7%. I guess being funded by issuing equity today under the DRIP at a, call it 20% free cash flow yield. I know that growth can be a little bit lumpy here as you go, but, I guess the question would be why not delay sanctioning of some of this growth, until you're in a better position to fully fund some of these low-returning projects with internal sources, as opposed to, you know, raising dilutive equity? I think the equity that we're raising is, is on the Ontario projects, which are accretive, in terms of the incremental cash flow it's providing as well as the contract extension. We now have contracts that run out to, into the 2040s, where before we had contract length of 2032. The equity is to, to fund those projects, the expansion projects, as well as the operates and at a fairly low amount of equity, Pat. Not looking to fund Maple Leaf Solar through an equity raise. Consistent with how we've addressed all of our projects in the US, we've built them and constructed them on our balance sheet, and then tax equity is the main financing mechanism there over and above our cash flow. Got it. Thank you. Then, maybe just switching gears to the CCS project. Timing appears a bit more murky here, with respect to FID date. I know you previously targeted October, so maybe just provide a bit more color on what's causing the drag there in the commercial discussion process, and also maybe, how much cushion you might have in the timing of FID, in order to stay on track for that in-service date of 2027. Thanks, Pat. On CCS, you know, in my first three months, I've been incredibly impressed and excited to, to deep dive into all of the technical work that's gone into bringing the capture solution to a point where. Effectively shovel-ready. On the commercial side, you know, we've got three concurrent conversations going. One with CIB on a loan, another with SIF, on support from the SIF program, and then the most important and material conversation around the carbon assurance mechanism with Canada Growth Fund through PSP. All three of those, we continue to have conversations, but today we don't have a date certain on when we'll get those negotiations complete, such that we can advance on the capture side to FID. On 2027 in service date, we're not in a position to comment on that today, given that the FID decision was originally projected to be in October of this year. We don't know that we'll hit that, given where we are on the commercial piece, which is why, you know, in our guidance, we said we would provide an update, once we had a material progress on the commercial side. We continue to be incredibly excited about the project. As I had mentioned in my previous comments, the controllable elements here and how much we've progressed on the technical solution is very exciting. You know, we continue to work with, with the government on finding that solution, and, you know, all messages to date have been incredibly supportive. You know, keep pushing ahead. I know you mentioned, Avik, the pre-feed study is complete, but curious how this recent cost overrun on the repowering project and specifically the pressures around labor costs might change your capital cost outlook here for the CCS project. You know, should we be expecting a similar 20%+ revision to the previous CAD 2.3 billion budget? And if so, you know, how would these cost challenges on CCS impact the overall returns of that project as well? We've, we've obviously learned from our previous experience on G 1 and 2 repowering. I, I think it's important to note also, you know, when we FID'd G 1 and 2 repowering, it was in 2020 at the beginning of the pandemic. What we hadn't predicted was the labor shortage and labor cost increases that were coming given where we were in the pandemic. On this project in particular, recognizing that as a gap and issue has been one that we've actively been mitigating as we work with our contractors. At this point, we don't have final numbers because we're not proceeding to FID at the moment, but I would say, you know, all of those have, do have a level of ambiguity around it, but we continue to track. First things first is let's, you know, finalize a commercial arrangement. We, we won't FID a project that doesn't meet our return thresholds. I think how we determine a carbon assurance mechanism and how that ties into the capital costs and the risks that we and the other parties take in this project will all be incorporated into that negotiation. Understood. I'll leave it there. Thank you. The next question comes from Maurice Choy with RBC Capital Markets. Please go ahead. Thanks, good morning. Maybe you could start on this discussion about returns. Avik, you mentioned that the repowering project returns continue to be, quote, unquote, "strong." Even if it's not a point estimate, could you give us a range, rough range as to what this could be? You obviously, the company was obviously comfortable giving us an estimate of 20+% levered returns back in the 2021 Investor Day. Thoughts on that, please? I can answer that, Maurice. You might recall at Investor Day, we did say that with actual financing, the project was in excess of 35% return on a, on a levered basis. That, that estimate was done in conjunction with the assumption that we would be spending $195 million on the battery. The battery was there simply to meet the MFSC requirements. It didn't have any other value attributed to it as part of our valuation in the form of being able to offer it in as an ancillary source of revenue. The economics that, that you would be looking at is just to compare the CAD 1.35 billion that we announced in June with the CAD 1.277 billion that we had at Investor Day, which is the all-in cost, including the battery. You're looking at about a 6% or 7% increase in costs over that base. The returns still exceed the 30%-some percent of levered returns. Basically, relatively still in line. The project, being a Brownfield project of this amount of increased generation and carbon tax avoidance, still is very deep in the money. Thank you for that, Sandra. Maybe as a follow-up to that and a comment that's made earlier, that you won't FID the CCS project until it reaches your return threshold. How would you, you know, compare your demands and then return expectations for a CCS project versus this repowering project. Obviously, different type of work, different risk. Would you expect it to be better than a 30+%? No, you wouldn't be looking at, at a CCS project that would have that level of, of return. As we sort of said, until we get the commercial agreements and those constructs in place and have an understanding of the risk, that will drive the return levels that we would look at. See it more in line with our, our merchant hurdle return. As we said, it's somewhere in the low double digits, would be sort of the, the return that would be consistent with a merchant project. Thanks, switching over to funding. Just to clarify, an earlier comment, Sandra, are you planning on suspending the DRIP once the Ontario projects are funded, or are you potentially going to keep that on, you know, to fund the CAD 600 million growth capital? Yeah. As, as you know, we have a number of different levers we can pull from a financing perspective and continue to be, you know, quite flexible. At this point, we think that, that, that DRIP over the development timeline of those projects would fund that equity need. Depending on what we do over the course of the, the next 2 years, would dictate what, what we would do in terms of determining the DRIP. There is that possibility that there would be other development projects that would lend themselves to keeping the DRIP on, but alternatively, we could see other, other things unfold on the growth side that would drive to different forms of, of financing that may or may not require the DRIP to continue. No, no real timeline sort of in our, in our view. We continue to be flexible and, and nimble in terms of, of how we fund our projects and, and have the opportunity to assess several different pathways to fund our growth. Got it. Thanks for that clarification. Maybe just to finish off with, your off coal goal. Obviously, that's now pushed past the 2023 year end. How much of any thoughts on as to when you will be off coal, or how much of it is about keeping flexibility on your coal units in case you don't move to combined cycle? Yeah. If, if we were to step off of coal and just run on, on gas in 2024, you would see the units run at a much lower level and, you know, concerns around reliability and affordability. We will continue to run the units the same way they run today, baseload by blending, and that will continue until we hit the combined cycle commissioning timeline. There will be a year-over-year decrease in the amount of coal that we're burning in 2024. As you know, Genesee Three is now fully converted, and it is off coal, the other units will continue to optimize between the two fuel until that commissioning start for combined cycle. Is it fair to say that between the coal blending unit and the single cycle, you could actually have more capacity than you currently do today? It would be about the same as what we have today, until we, until we have the units sort of reach commissioning, at which point there'll be an increase in megawatts. Through commissioning, you would see that step up, but not before. Got it. Thank you very much. The next question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead. Thanks. Good morning, everyone. Coming back to the discussions around the carbon insurance with the Canada Growth Fund, is this, is this just taking more time, or, or, or are you actually feeling like that you might not be able to get a contract that meets your needs? Is the discussions hampered at all by your view that you need a higher carbon price to offset the higher cost of those? Mark, hey, how are you? I would say you know, I've been in this role now three months. We've had a number of conversations with all parties involved in the project. At every point, there continues to be positive feedback and encouragement to advance the carbon assurance mechanism. The cost of the mechanism hasn't been the issue. I think, is, the, you know, as was announced in the federal budget early in the year, it's, you know, the appetite to put something in place is there. It's just, you know, moving towards the commercial arrangement and how do you actually negotiate and structure whether it's a CCFD or an alternative to it, which is taking longer. You know I remain optimistic that we'll get there. It's just taking longer. Got it. What would be alternative structures that you can share, with us? You know, something different than a contract or different that you'd be open to. I can't comment on that right now. I think we're in conversations on how you emulate the construct of CCFD. I think the most important tenet of this conversation has been and continues to be: How do you ensure policy certainty on the value of, of carbon post-2030? You know, in trying to solve for that, the CCFD was the most transparent and clean version of accomplishing that. You know, I think there are other options, and we've seen precedents in other countries of different constructs that would allow us to get to the same spot, but we're just starting to explore those now. Got it. Before you joined the company, I think it was at the last Investor Day, there was a comment that Capital Power could be a leader in, in CCS, and, you know, if you become an early mover here with the Genesee project, what's, what's your stance on that in terms of how hard do you lean in as an, I guess, organization around carbon capture and, and how, how much do you participate with other groups or at other assets across your portfolio? Well, I think carbon capture and sequestration, in particular, for electricity markets that rely on thermal for dispatchable generation, in many of those places, carbon capture and sequestration could be a solution. Without question, in Alberta, it, it should be a critical part of the early days of decarbonization. I, I continue to be excited about it. I've personally been involved on the carbon capture and sequestration business since 2014, and continue to see the real benefit that, that provides to Alberta to decarbonize on a optimal timeline. We are and will continue to explore options to do that. We were recently granted funding to explore that in Michigan, in and around MCV. You know, continue to be excited, but I would say we're also looking at other technologies. You know, we are a leader on CCS, as applied to thermal generation today, and I think we, you know, in spite of, you know, this delay that we're communicating, I think we're still well out in front of anyone else looking to be able to, you know, put a shovel into the ground on a, on a material and large-scale decarbonization project. Got it. Then we've seen some evidence that maybe renewable values where their operating portfolio development pipeline has come down a little bit. So I guess, I guess the question would be, sort of, risk return payoff for development versus acquiring portfolios. How do you see that on renewables? Just in contrasting that, what do you see in terms of the M&A market for, for mid-life gas assets? Has valuation changed at all in the last 12 months? For us, Mark, I think on, on the renewables side, we would continue to pursue development, where acquiring a portfolio is, is more competitive, and we tend to be able to bring value in development that, that isn't there for us on a portfolio. We would look at portfolios, but our experience has sort of led us to the path that we're, we're better on the development side than being able to compete in that market. Still seeing a number of opportunities on the M&A side with respect to mid-life natural gas. We continue to look at those that are in line with our strategy. Would say that it's, it's a mix in terms of interest in, in those opportunities have increased. Certainly, the, the valuations are much higher than they would have been if you go back, you know, four or five years when, when there was a much weakened sentiment towards natural gas. You are seeing a recognition in, in many markets that value natural gas for longer than was originally expected. So as a result of that, there is a little more interest or widespread interest. We still see ourselves being very competitive in terms of being a, an operator and someone that can bring a fair bit of value in our operating expertise to, to those sites that certainly we remain competitive in that M&A sector. Got it. Thanks, Sandra. Thanks, Alex, for your time today. The next question comes from John Mould with TD Cowen. Please go ahead. Okay, thanks. I think most of my questions have been answered, but, you know, just maybe following up on the M&A commentary, you know, a little bit. I'm just wondering how you're thinking about M&A more broadly, just given the secured, you know, pipeline you've already got in place, what you're seeing in terms of, you know, development returns versus what returns might look like on M&A investment. You know, just where you sit with your, your funding needs and, and, you know, the fact that you've reactivated the DRIP to fund some of your equity needs for your projects, I guess. You know, does M&A fit into the, into the, you know, potential investment picture right now? Yeah, I, I would say that we continue to be interested in M&A, John, and we think about the amount of activity we have on the development side, like, our capacity internally with executing on repowering as well, now adding a number of projects in Ontario, sort of leads us to focus a little bit on M&A, as those opportunities are much more accretive and do tend to come with stronger returns. We've always sort of balanced our renewables build out with executing on the midlife natural gas, which is very supportive to the dividend and our overall strategy. As I mentioned, the DRIP is a cost-effective way for us to fund at the moment for the development in Ontario, but continue to look at M&A through partnerships. We do have the ability to bring in partners on, on assets we currently own. I've talked in the past around, you know, the renewable portfolio being one where, we would be able to secure a partner on that and, and use those funds to continue to grow. I think that, just having that flexibility and those opportunities in front of us allow us to continue to, look at those opportunities and be able to execute, in, in the near term, should there be an opportunity that, that we feel is, on strategy and, and, meaningful for the organization. Continue to be very disciplined in terms of assessing those opportunities. Okay, thanks for that. Then maybe just 1 follow-up question on your pipeline. You know, a large chunk of it, or a healthy share anyways, is battery storage. You know, are those mostly opportunities that you're looking to pair with existing assets, either on the renewable or, or gas side, or I guess pair with other, greenfield renewable development initiatives, or are you considering standalone storage opportunities at this point? We are not considering standalone battery. You're, you're correct in that we'd be looking at pairing that with other assets and using existing sites to have increased value or incremental value versus standalone batteries. Okay, great. Thanks for that. Those are my questions. I'll leave it there. The next question comes from Ben Pham with BMO. Please go ahead. Hi, thanks. I wanted to just start off with, with some of the your comments on the funding side of things. I guess you've added about $1 billion of CapEx. Looks like you're going to be funding 20% of that through the DRIP program, at least through 2025. Can you walk through the other pieces that, the 80%? I assume there's, there's some free cash flow from there, some Investment Tax Credits. Another question I had on, on some of your comments is, did you say your AFFO guidance or AFFO expectation is, is going to be higher than the EBITDA contribution? Just double-check my notes. Starting with your question on funding, Ben. Yeah, you're, you're correct that the projects that we had in development at the beginning of the year were being fully funded through internally generated cash flow. We've added the $655 million in Ontario, which we, we will use cash flow during construction as well as, as the proceeds from the DRIP. On Maple Leaf Solar, we'll use tax equity will be the main component there, as well as our internally generated cash flow. Halkirk Two would be the other development project, and that is eligible for 30% ITCs in Canada now, which would be paid at COD. We would receive that at the end of next year. Look at internally generated cash flow. We would use our credit facilities that has $1 billion available to us to, to fund construction, and then would look at terming out the debt on those development projects. Okay. Then I wanted to double-check my notes on the- Oh, sure. EBITDA and AFFO. Yeah, have I, have I flipped it or maybe misheard it? We expect to be above the midpoint in both Adjusted EBITDA and AFFO. Okay. Is your AFFO, did you say it's CAD 65-CAD 70, and EBITDA is going to be lower than that? three on Ontario. No, the, the AFFO would be lower because of the sustaining CapEx component. Okay. I got you. You, you also mentioned, too, around future growth opportunities, and you look at extending potentially the, the dividend reinvestment program. I guess that, that decision is more to do with timing, how quickly new projects come around. Is, is that correct in a sense? Then can you maybe rank order funding opportunities outside of DRIP? I, I heard partnerships, so is there any- anything else that you'd look at? Yeah. It, it depends on what opportunity we're, we're actually funding. For, for us, if we're looking at a large opportunity like you saw with MCV, bringing in a partner makes, makes a lot of sense. It adds incremental value to have a partner that has a lower cost of capital for us, and then we receive the, the operating fee for that. I think that that's, that's a good example of where we would look at a partnership. Also just the sell down of our renewables. We've always continued to look at the opportunity to bring in a partner on, on whether it's a number of assets or a full portfolio of assets, depending on our financing needs. We see that as a way for us to generate cash flow that wouldn't require us to access the equity market. You know, we continue to look at whether or not you use a bought deal for a large M&A opportunity as well. You know, at this point, we think we've got a lot of other options to fund that as well. Still have high internally generated cash flow over the next couple of years as we continue to see prices remain relatively robust throughout the next number of years. Once again, it's gonna depend on the opportunity that we see. I'll just go back, I think, on your question on AFFO to EBITDA. I did have that backward. The AFFO is higher because of the ITCs and tax benefits in Ontario. While we, we typically see it go the other way around, your AFFO is always higher because of, of, tax credits that we would be receiving on those battery projects. Okay. Maybe it's philosophy also in terms of funding. Can you remind us also balance sheet that EBITDA, just where you might be peaking out during this construction period, or where you're comfortable peaking out at? On, sorry, on, on EBITDA or on credit profiles? debt to EBITDA or FFO to debt. The debt FFO to debt, yeah. Yeah. We continue to have a large degree of cushion in our FFO to debt metrics this year. We're, we're in the high 20% FFO to debt, where our threshold is 20%. So that's, you know, why we don't have an equity requirement this year. As you look, look out, we will start to see that come back more in line with, with the 20%. We always have a bit of a cushion there to be above it. We continue to be well, well above that. You know, with a threshold of 20%, which is your 3-year average AFFO to debt requirement, we, we sit a 2% above that, even in, in the dip. As I mentioned right now, in periods of strong cash flow, we're, we're actually closer to 30%. Okay, that's great. Thanks, Sandra. The next question comes from Andrew Kuske with Credit Suisse. Please go ahead. Thank you. Good morning. I, I guess as a broad question about just the health of the Alberta power market and kind of how you fit into it, is we're seeing, you know, definitely hours, a lot more hours of lower part pricing, but also a lot more hours of very high pricing. When you look at the forwards in some of your presentation materials, you know, we've got dynamics where forwards around low $70s, rising carbon prices, higher natural gas prices. Just on balance, how do you think about the market structure, average pricing versus the volatility in the market on a go-forward basis? Yeah, thanks, Andrew. I think that's where our hedging, hedging approach comes in, where we're able to lock in prices at good levels that sort of get you through the dip. When you think about what happened in June, where we were caught on the wrong side of, of volatility, locking in prices or having hedged prices means that later in the month, when you've got very strong renewables on the system that drive those periods of low prices, you're actually capturing your, your hedged price. I think we've always reduced the volatility through our hedging program. To your point, we are seeing much more dramatic hedging or price dynamics. I think for us, where our strategy is sort of to optimize our capacity factors and be able to run, running at those hedged prices and just being able to capture those, those peaks with your peaking units, still remains a solid, solid strategy that will continue to work for us. You know, when you think about the Alberta market, and as I said, the AESO's now taking an opportunity to review the impacts of renewables, they are seeing the implications of those in growth or the rate of growth that renewables have had. Expect that there will be within the construct of the energy-only market, they will be looking to refine that, just to make sure that we do have a functioning market. It certainly is a different dynamic. Part of that volatility as well is, not just the, the renewables, but also the fact that you have, a shortage of, reliable, efficient, base load units, which will be resolved going forward when you have, a new supply coming on with increased, capacity from Genesee, as well as the Cascade project that are, that are both expected in, in the shorter term. So you should see the, the, the escalation of prices required for low capacity factor units sort of, start to subside. Okay. appreciate that. Then maybe just building on the Alberta power market and the attraction of it, I don't know if you have any comments on just the recent transaction we saw, where EDF sold a portion of a wind farm in Alberta, you know, private equity buyer or an infra fund buyer. Any thoughts or comments you have on, you know, just the market dynamics and any valuation context? I don't have valuation context on that. What I would say on that one is we continue to see more interest, and activity in Alberta, given the energy-only market. To echo Sandra's comments, you know, the more volatility we see in the market, caused by demand increases, higher renewable penetration, and, you know, more temperature swings. That volatility kind of gives more credence to a medium to long-term outlook of, you know, increased demand and higher pricing. I think that's what's causing the interest in the market. We continue seeing more players coming in, looking at greenfield, as well as, and, you know, M&A opportunities. I think the, the, the support for merchant assets is probably greater than what we've seen historically in this market, given that market construct. Okay. Appreciate the color. Thank you. The next question comes from Naji Badour with iA Capital Markets. Please go ahead. Hi, good morning. I just wanted to go back to the topic of, of growth and funding for a second. With the between the Ontario projects and Maple Leaf, about $1 billion of total investments over the next couple of years, I guess when you think about the North Carolina solar projects that you might be bidding in or, or other developments coming down the pipeline, is, is the DRIP enough? Does that give you enough flexibility to finance incremental growth? Or how are you thinking about other projects that might be coming down the pipeline? Yeah, we, we do have enough capacity to, to look at something like Maple Leaf Solar. Once again, that's another project that would get funding through tax equity, at COD, and we have good capacity on our, our credit facilities. At this point in time, the DRIP is, is incremental to, to what we actually need, and, and we're sort of getting ahead of our financing needs by turning it on at this point in time. There is capacity for those projects, given that, there's a large part of tax equity, that would be financing those U.S., renewable development opportunities. Do you mean even for the other, three North Carolina solar projects? Correct. Yeah. Okay. Understood. Is that really where sort of the, the upside becomes from here, or are there other markets maybe that you're targeting for greenfield development? There, there are other markets, as we've always been sort of opportunistic, but we do have a number of, of sites that are within that North Carolina region that are, are, ready from a interconnection perspective. As far as sites that, that are, closest to being, ready for construction, they, they tend to be in, in that area. There are other opportunities, and we would continue to look at those as well. We, we have a, we have a pipeline today of 2.4 GW that's, you know, in excess of 30 identified, and cited projects that are across the U.S. in markets we've been evaluating for multiple years. you know, when we secured the First Solar, contract on the gigawatt, it was really against our risk view of that pipeline. Understood. Maybe just one last question on going back to Alberta and, and sort of, your comment about sort of appetite for more merchant assets. I guess, from your perspective, with, with Genesee, the repowering and then maybe, development more focused on the US side, do you feel the need or do you see more opportunities to do merchant assets in Alberta, or is that are you sort of happy with the rest of your portfolio in the province? I think how I would answer that is, you know, we have a very strong commercial portfolio in Alberta. We have an incumbency advantage in this market, so we're always in the flow of what's trading and what the greenfield opportunities are, and we'll continue to do that. So it's not, you know, that's not a pipeline we can turn off or we want to. We'll continue looking to optimize there. You know, we, we see tremendous opportunity to grow in these other places. Okay. Thank you. Once again, if you have a question, please press star then one. The next question comes from Robert Hope with Scotiabank. Please go ahead. Yes. Just a clarification on the Ontario EBITDA and FFO. Just as we take a look at the EBITDA walk to FFO, you did mention that there would be tax benefits there. Are those kind of front-end loaded, or how should we be thinking about kind of the shape of FFO versus EBITDA there? For battery storage as well as, as other renewables, the ITCs or the, the tax benefits are received at COD. So it's front-end loaded. When we're looking at the, the numbers that I would have provided you, those would be five-year averages, so there would be shape, shape to that, to your point. All right. Appreciate that. This concludes the question and answer session. I would like to turn the conference back over to Mr. Randy Mah for closing remarks. Okay, if there are no more questions, we will conclude our conference call. Thanks again for joining us 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, and have a pleasant day.