Capital Power Corporation

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 2nd, 2023. I will now turn the call over to Mr. Randy Ma, the Director of Investor Relations. Please go ahead.

Good morning, and 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 Day, 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 maturely 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 two. In today's discussion, we will be referring to various non-GAAP financial measures and ratios as noted on slide three. These measures do not define 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 for management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in our second quarter 2023 MV&A. Before I turn it over to Abak, I want to acknowledge that Capital Powers 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 Abak for his remarks starting on slide four.

Thanks, Randy, and good morning. I am now three months into my tenure as CEO for the organization, and 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 future forward strategy. During the second quarter, we were negatively impacted by an untimely outage. In addition, 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 29th 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 Center, 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 megawatts 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. And 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 megawatts to a total capacity of 1,388 megawatts, 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 currents 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 MSSC limit, which received conditional ASO approval, thus saving the $195 million through cancellation of the battery storage. That results in a $73 million increase from $1.277 billion that we communicated at Investor Day in 2022 to to the $1.35 billion, which we communicated at the end of June. From an equipment perspective, the majority of materials are onsite, 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 seven, 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 five projects that will add approximately 350 megawatts of capacity to our Ontario operations with the start of commercial operations in 2025 for all projects. The successful projects include 106 megawatt natural gas expansion at our East Windsor facility and battery storage projects at both York Energy and Gorway. The combined cost of these three 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 and 38 megawatts at Gorway and York Energy that resulted in contract extensions. Overall, the achievements in Ontario continues to validate our midlife 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 eight, 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 megawatts that we are bidding into Duke's 2023 solar procurement RFP in September. To support our U.S. solar development pipeline, totaling nearly 2.4 gigawatts, we have secured our first order for one gigawatt of responsibly produced ultra-low carbon solar modules. This will help increase the competitiveness of the solar projects as the use of U.S.-made products will qualify for domestic content under the Inflation Reduction Act. Turning to slide nine, 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 negotiation. Turning to slide 10, this morning we announced our 10th consecutive year of dividend growth with a 6% dividend increase effective for the third 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 turn it over to Sandra to discuss our second 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 U.S. 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 settled 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 to 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 five hours at the price floor and 11 hours at the price cap, and daily settles ranging from $26 per megawatt hour, which was the lowest in 2023, to $548 per megawatt hour, 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 megawatt hour for Q2 of 2022. Adjusted EBITDA was $728 million, up 9%, and further benefited from six months of contribution from NCV. 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 heads positions which are shown as of June 30th, 2023. Since the end of the first quarter, our power hedge volumes for 2024 to 2026 have increased. For 2024, it has gone up from 8,000 to 8,500 gigawatt hours and from 6,500 to 7,000 gigawatt hours for 2025. For 2026, the hedge volumes have gone from 4,000 to 5,500 gigawatt hours. The weighted average hedge price are mid $70 per megawatt hour for 2024 and low $70 for 25 and 26. 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 project, we are activating our DRIP effective with the third quarter dividend in October. We expect to raise approximately 75 to 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 timeframe that aligns with the CapEx spend profile. On slide 16, I'll conclude our remarks by reviewing our six-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 six months and is on track to meet its 2023 target of $135 to $145 million. Our 2023 financial targets include $1.455 billion to $1.515 billion in adjusted EBITDA and $805 to $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 Project, we have exceeded our $600 million committed growth target 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 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 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 and 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, and we see all of those areas as significant growth opportunities in and around our critical natural gas assets, not just to expand around those particular critical assets, but build out renewables capacity.

Excellent. Thanks for that, Avik. And then maybe there's one more for me. I'm wondering if you have any recent thoughts on the opportunities at Midland Cogen, potential expansions there, and I guess in that region – How are you thinking about renewable expansion, I guess especially in the wake of your securing panels for solar?

I think 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. So the answer is absolutely yes, we're looking and evaluating at opportunities there.

Excellent. Thanks for that. I'll turn it over.

The next question comes from Robert Hope with Scotiabank. Please go ahead.

Good morning, Rob. Question on the Alberta power market structure. So the most severe, the MSFC, the most severe single contingency limit was maintained at 466. And that has allowed you to get rid of the battery project there. But as you look into kind of 25 and 26, 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 megawatts per unit and whether that would be other solutions or something along the fast net demand response that the ASO has put forward.

Thanks for the question. Yes, the ASO just announced last night that it plans to take a review of the market and the characteristics of of the market, so we will be participating in that and 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 next few weeks, we will be going through the report in detail and participating in those discussions with the ASO on market design 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. And then maybe, you know, broader and more conceptual in nature, just with Genesee 1 and 2 coming down in June and Clover, but not far enough, being able to backstop it, you know, as you move forward, Genesee 1 and 2 will be a larger percentage 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 two larger units with potential downside scenarios like we saw in June?

Yeah, so I think with respect to the hedging strategy, we intend to stay the course. As you know, one of the things that we have been doing is building out our C&I business to have more longer-term hedges in place that – would allow us to still step into hedges for the balance of that portfolio. So I think we don't see that there's a real need to change our hedging strategy, per se, from what it has been in the past, 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? And as well, on the Maple Leaf Solar contract, what would be the expected returns both on an unlevered and levered basis net of tax equity?

So firstly in Ontario, the $655 million, we're looking at those will meet our contracted hurdle rates on an unlevered basis and expect that we'll have about 20% equity to fund those. So to 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 to $60 million in adjusted EBITDA and about $65 to $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. So our contracted hurdle is around that 7% range on levered.

Okay, so 7%. And I guess being funded by issuing equity today under the DRIP, but I 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 raising dilutive equity?

So I think the equity that we're raising is on the Ontario projects, which are accretos in terms of the – The incremental cash flow is providing as well as the contract extension. So we now have contracts that run out into the 2040s, where before we had contract length of 2032. So the equity is to fund those projects, the expansion projects, as well as the up rates and at a fairly low amount of equity. Pat, so not looking to fund Maple Leaf Solar through an equity raise, consistent with how we've addressed all of our projects in the U.S. 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. And then maybe just switching gears to the CCS project. So 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, in my first three months, I've been incredibly impressed and excited to deep dive into all of the technical work that's gone into bringing the capture solution to a point where we're effectively shovel-ready. So on the commercial side, we've got three concurrent conversations going one with CIB on a loan, another with CIF on support from the CIF 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, and we don't know that we'll hit that. given where we are on the commercial piece, which is why in our guidance we said we would provide an update once we had a material progress on the commercial side. So 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 the government on finding that solution. And, you know, all messages to date have been incredibly supportive. So, you know, keep pushing ahead.

And I know you mentioned, Avik, the pre-feed study is complete, but I'm 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 plus percent revision to the previous $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 obviously learned from our previous experience on G1 and 2 repowering in a I think it's important to note also, when we FID G1 and 2 repowering, it was in 2020 at the beginning of the pandemic. So 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 all of those 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 won't FID a project that doesn't meet our return thresholds. And 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 Choi with RBC Capital Markets. Please go ahead.

Thanks, and good morning. Maybe I could start on this discussion about returns. Avik, you mentioned that the powering project returns continue to be quote-unquote strong. Even if it's not a point estimate, could you give us a rough range as to what this could be? you obviously, the company was obviously comfortable giving us an estimate of 20 plus percent levered returns back in the 2021 Investor Day. So thoughts on that, please.

So 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 levered basis. And so That estimate was done in conjunction with the assumption that we would be spending $195 million on the battery. And the battery was there simply to meet the MSSC 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 you would be looking at is just to compare the $1.35 billion that we announced in June with the $1.277 that we had at Investor Day, which is the all-in cost, including the battery. And so you're looking at about a 6% or 7% increase in costs over that base. So the return is still exceed the 30-some percent of levered returns. So basically, relatively still in line. So 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. And maybe as a follow-up to that and a comment that was made earlier, that you won't FID the CCS project until it reaches your return threshold. How would you compare your demands and 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-plus percent?

No, you wouldn't be looking at a CCS project that would have that level of return. So 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. But C is more in line with our merchant hurdle return. So as we said, it's somewhere in the low double digits would be sort of the return that would be consistent with a merchant project.

Thanks, and switching over to funding, and 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 to fund the $600 million growth capital?

Yeah, so 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. So at this point, we think that the drip over the development timeline of those projects would fund that equity need. Depending on what we do over the course of the next two years would dictate what we would do in terms of determining the drip. So 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 financing that may or may not require the drip to continue. So no real timeline sort of in our view. We continue to be flexible and nimble in terms of how we fund our projects and have the opportunity to assess several different pathways to fund our growth.

Got it. Thanks for the clarification. And maybe just finish off with your off-coal goal. Obviously, that's now pushed past the 2023 year-end. How much of any thoughts 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, so if we were to step off of coal and just run on gas in 2024, you would see The units run at a much lower level and, you know, concerns around reliability and affordability. So we will continue to run the units the same way they run today, base load by blending. And that will continue until we hit the combined cycle commissioning timelines. So there will be a year-over-year decrease in the amount of coal that we're burning in 2024. As you know, Genesee III is now fully converted, and it is off coal. But the other units will continue to optimize between the two fuel until that commissioning start for a 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. be about the same as what we have today until we have the units sort of reach commissioning, at which point there'll be an increase in megawatts. So through commissioning, you would see that step up, but not before.

Got it. Thank you very much.

The next question comes from Mark Jarby with CIBC Capital Markets. Please go ahead.

Thanks. Good morning, everyone. So coming back to the discussion around the carbon insurance with the King Growth Fund, is this just taking more time, or are you actually feeling like you might not be able to get a contract that meets your needs? And is the discussion hampered at all by your view you need a higher carbon price to offset higher costs to build?

Mark, how are you? I would say, so... 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. And at every point, there continues to be positive feedback and encouragement to advance the carbon assurance mechanism. So the cost of the mechanism hasn't been the issue. I think 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. So, 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 for difference 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 contract 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. So in trying to solve for that, the CCSD was the most transparent and clean version of accomplishing that. But 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 out one of those now.

Got it. And 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 CCS. And, you know, if you become an early mover here with the Genesee project, what's your stance on that in terms of how hard you lean in as an organization around carbon capture and how much you participate with other groups or other assets across your portfolio? Yeah.

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. So without question, in Alberta, it should be a critical part of the early days of decarbonization. So 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. So 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. So, you know, continue to be excited. But I would say we're also looking at other technologies. But, 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 France. of anyone else looking to be able to, you know, put a shovel into the ground on a material and large-scale decarbonization project.

Got it. And then we've seen some evidence in maybe renewable values where they're operating portfolios, development pipelines have come down a little bit. So I guess the question would be sort of risk return payoff for development versus acquiring portfolios. How do you see that on renewables? And just In contrasting that, what do you see in terms of the M&A market for midlife gas assets? Has valuation changed at all in the last 12 months?

So for us, Mark, I think on the renewable side, we would continue to pursue development where acquiring a portfolio is more competitive and we tend to be able to bring value in development that isn't there for us on a portfolio. So We would look at portfolios, but our experience has sort of led us to the path that 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 midlife natural gas, so we continue to look at those that are in line with our strategy. Would say that it's a mix in terms of interest in those opportunities have increased. Certainly the valuations are much higher than they would have been if you go back four or five years when there was a much weakened sentiment towards natural gas. You are seeing a recognition in many markets that value natural gas for longer than was originally expected. And so as a result of that, there is a little more interest or widespread interest, but we still see ourselves being very competitive in terms of being an operator and someone that can bring a fair bit of value in our operating expertise to those sites that certainly remain competitive in that M&A sector.

Got it. Thanks, Sandra. Thanks, Alex, for your time today.

The next question comes from John with TD Cowan. Please go ahead.

Okay, thanks. I think most of my questions have been answered, but just maybe following up on the M&A commentary a little bit, I'm just wondering how you're thinking about M&A more broadly, just given the secured pipeline you've already got in place, what you're seeing in terms of development returns versus what returns might look like on M&A investment, and just where you sit with your your funding needs and the fact that you've reactivated the DRIP to fund some of your equity needs for your projects, I guess. Does M&A fit into the potential investment picture right now?

Yeah, 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 to focus a little bit on M&A as those opportunities are much more accretive and do tend to come with stronger returns so we've always sort of balanced our renewables build out with executing on the midlife natural gas which is very supportive to the dividend in our overall strategy so 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 assets we currently own. I've talked in the past around the renewable portfolio being one where we would be able to secure a partner on that 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 the near term should there be an opportunity that we feel is on strategy and meaningful for the organization, but continue to be very disciplined in terms of assessing those opportunities.

Okay, thanks for that. And then maybe just one follow-up question on your pipeline. A large chunk of it, or a healthy share anyways, is battery storage. Are those mostly opportunities that you're looking to pair with existing assets, either on the renewable 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 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 start off with some of your comments on the funding side of things. And I guess you've added about a billion of CapEx. It looks like you're going to be funding 20% of that through the DRIP program, at least through 2025. Can you walk through other pieces of that, the 80%? I've seen there's some free cash from there, some investment tax credits. And another question I had on some of your comments is, did you say your AFFO guidance or AFFO expectation is going to be higher than the EBITDA contribution? Just double-check my notes.

So, starting with your question on funding, Ben, so, yeah, you're correct that the The projects that we had in development at the beginning of the year were being fully funded through internally generated cash flow. So we've added the $655 million in Ontario, which we will use cash flow during construction as well as the proceeds from the JIP. On Maple Leaf Solar, we'll use tax equity will be the main component there, as well as our internally generated cash flow. Halkirk II would be the other development project, and that is eligible for 30% ITCs in Canada now, which would be paid at COD. So we would receive that at the end of next year. So look at internally generated cash flow. We would use our credit facilities that has a billion available to us to fund construction. and then would look at terming out the debt on those development projects.

Okay, and then I wanted to double-check my notes on the EBITDA and AFFO. Yeah, have I flipped it or misheard it?

We expect to be above the midpoint in both adjusted EBITDA and AFFO.

Okay, but is your AFFO, do you say it's 65 to 7 and EBITDA is going to be lower than that?

On Ontario, no, the AFFO would be lower because of the sustaining CapEx component.

Okay, I got you. And then you also mentioned too around future growth opportunities and you look at extending potentially the dividend reinvestment program, but I guess that more to do with timing, how quickly new projects come around. Is that correct in a sense? And then can you maybe rank order funding opportunities outside of the DRIP? I heard partnerships. Is there anything else that you would look at?

Yeah, so it depends on what opportunity we're actually funding. So for us, if we're looking at a large project, Opportunity, like you saw with MCV, bringing in a partner 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 operating fee for that. So I think that that's a good example of where we would look at a partnership, and also just the sell-down of our renewables. We've always continued to look at the opportunity to bring in a partner 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. But, you know, we continue to look at whether or not you use a bought deal for a large M&A portfolio opportunity as well. But 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. So once again, it's going to depend on the opportunity that we see. And I'll just go back, I think, on your question on AFFO to EBITDA. There is actually, I did have that backward. The AFFO is higher because of the ITCs and tax benefits in Ontario. So while we typically see it go the other way around, your AFFO is higher because of tax credits that we would be receiving on those battery projects.

Okay. And maybe just lastly, also in terms of funding, can you remind us also, balance sheet, debt EBITDA, just where you might be peaking out during this construction period, or where you're comfortable peaking out at?

Sorry, on EBITDA or on credit facilities?

On debt EBITDA or FFO to debt.

FFO to debt, yeah. So 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 why we don't have an equity requirement this year. But as you look out, you will start to see that come back more in line with the 20%. But we always have a bit of a cushion there to be above it. So we continue to be well well above that. So, you know, with a threshold of 20%, which is your three-year average FFO to debt requirement, we sit a couple percent above that even in the dip. And as I mentioned right now, in periods of strong cash flow, we're actually closer to 30%.

Okay, that's great. Thanks, Sandra.

The next question comes from Andrew Kuski with Credit Suisse. Please go ahead.

Thank you. Good morning. I guess it's 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 with lower part pricing, but also a lot more hours of very high pricing. And when you look at the forwards and some of your presentation materials, you know, we've got dynamics where forwards around low seventies, um, 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. And I think that's where our hedging approach comes in, where we're able to lock in prices at good levels that sort of get you through the dip. So when you think about what happened in June where we were caught on the wrong side of volatility there, Locking in prices or having hedge 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 hedge price. So I think we've always reduced the volatility through our hedging program, but to your point, we are seeing much more dramatic hedging or price dynamics. So I think for us where our strategy is sort of to optimize our capacity factors and be able to run, running at those hedge prices and just being able to capture those peaks with your peaking units still remains a solid strategy that will continue to work for us. You know, when you think about the Alberta market, and as I said, the ASO is now taking an opportunity to review the impacts of renewables. They are seeing the implications of those growth or the rate of growth that renewables have had. So 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 renewables We do have a functioning market, but it certainly is a different dynamic. Part of that volatility as well is not just the renewables, but also the fact that you have a shortage of reliable, efficient baseload units, which will be resolved going forward when you have a new supply coming on with increased demand. capacity from Genesee as well as the Cascade project that are both expected in the shorter term. And so you should see the escalation of prices required for low capacity factory units sort of start to subside.

Okay. I appreciate that. And 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, private equity buyer or an infra fund buyer. Any thoughts or comments you have on 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 the energy-only market. And to echo Sandra's comments, the more volatility we see in the market caused by demand increases, higher renewable penetration, and more temperature swings, that volatility kind of gives more credence to a medium to long-term outlook of increased demand and higher pricing. So I think that's what's causing the interest in the market. So we continue seeing more players coming in, looking at greenfield as well as M&A opportunities. And I think the support for merchant assets is probably greater than what we've seen historically in this market, given that market construct.

Okay. I appreciate the color. Thank you.

The next question comes from Najee Beydoun with IA Capital Markets. Please go ahead.

Hi. Good morning. I just wanted to go back to the topic of growth and funding for a second. So, with the, between the Ontario projects and Maple Leaf, about a billion dollars 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 other developments coming down the pipeline, is the drift 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 do have enough capacity 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 the capacity on our credit facilities. At this point in time, the DRIP is incremental to what we actually need and we're sort of getting ahead of our financing needs by turning it on at this point in time. So 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. Understood. And is that really where sort of the upside comes from here, or are there other markets maybe that you're targeting for greenfield developments?

There are other markets, as we've always been sort of opportunistic, but we do have a number of sites that are within that North Carolina region that are ready from an interconnection perspective. So as far as sites that are closest to being ready for construction, they tend to be in that area, but there are other opportunities, and we would continue to look at those as well.

We have a pipeline today of 2.4 gigawatts that's in excess of 30 identified and cited projects that are across the U.S. in markets. We've been evaluating for multiple years. So when we secured the first solar contract on the gigawatt, it was really against our wrist view of that pipeline.

And maybe just one last question on going back to Alberta and sort of your comment about sort of appetite for more merchant assets. I guess from your perspective with Genesee, the repowering, and then maybe development more focused on the U.S. side, do you feel the need or do you see more opportunities to do merchant assets in Alberta, or are you sort of happy with the rest of your portfolio in the province?

I think how I would answer that is 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. That's not a pipeline we can turn off or we want to. We'll continue looking to optimize there. But, you know, we see a 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 FFOs. 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?

So for battery storage as well as other renewables, the ITCs or the tax benefits are received at COD. And so it's front-end loaded. So when we're looking at the numbers that I would have provided you, those would be five-year averages. So there would be 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 Ma 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 lines. Thank you for participating and have a pleasant day.