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spk00: Welcome to Capital Power's second quarter 2022 results conference call. As a reminder, all participants are in listen-only mode and the conference is being recorded today, August 2nd, 2022. I will now turn the call over to Mr. Randy Ma, the Director of Investor Relations. Please go ahead.
spk08: Good morning. Thank you for joining us today to review Capital Power's second quarter 2022 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 Brian Vazio, President and CEO, and Sandra Haskins, Senior Vice President, Finance and CFO. We'll 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 of 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 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 gap measures which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-gap financial measures to their nearest gap measures can be found in our second quarter 2022 MD&A. I will now turn the call over to Brian for his remarks starting on slide four.
spk04: Thanks, Randy, and good morning. Capital Powers head office in Edmonton is located within the traditional and contemporary home of many indigenous peoples of the Treaty 6 region and Métis Nation of Alberta Region 4. We acknowledge the diverse indigenous communities that are located 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. In the second quarter, there were notable developments that took place that are very supportive of our natural gas strategy. I'll briefly touch on these developments and comment further later in my remarks. First, we continued our successful track record of recontracting with the recent four and a half year contract renewal on our island generation facility in BC. In July, we announced an agreement to acquire a 50% interest in the Midland Cogen facility the largest natural gas cogeneration facility in North America. This acquisition checks all the boxes of our natural gas strategy, including being well positioned for recontracting beyond 2030. The Ontario ISO has identified significant incremental capacity needs as early as 2025. This provides a positive outlook for our three natural gas facilities that are well positioned in the province. And last month, the federal government released its proposed frame for its clean electricity regulation. Under the proposed frame, it recognizes the continued role of natural gas generation in supporting reliability and integrating renewables. All these developments are positive as we continue executing on our natural gas strategy going forward. As mentioned, Sorry, turning to slide five. As mentioned, we announced an agreement to acquire the Midland Cogen facility with our partner, Manulife Investment Management. Midland is right down the middle of the fairway relative to our midlife acquisition strategy. This includes its competitive operational features, the potential to add value by leveraging its existing site, its accretive and contracted, and its advantaged location where it's well positioned for future recontracting. The purchase price is approximately $894 million U.S. that includes $521 million U.S. of project-level debt. We plan to finance our portion of the $186 million U.S. with cash on hand in utilizing our credit facilities. No equity will be required to finance this transaction. The five-year average AFFO accretion per share is forecast to be $0.30 U.S. or 7%. Approximately 85% of the capacity is under long-term contracts with high-quality counterparties with contract expiries in 2030 and 2035. Midland Cogen is a critical asset to support grid reliability during the transition to renewables in Michigan and is extremely well positioned for recontracting beyond 2030. The closing of the transaction is expected to be in the third quarter of this year. Slide six highlights our track record of recontracting natural gas assets after they've been required. This includes recontracting two U.S. facilities with financial upside compared to the previous PPAs. At Decatur in Alabama, the 10-year extension included immediate enhancements for additional capacity before the previous contract expired. And for Arlington in Arizona, we executed a six-year extension with materially higher AFFO over the extended term. And most recently, we executed a four and a half year renewal for island generation in BC. We continue to advance for longer term recontracting as part of our BCUC's IRP review process. In Ontario, the ISO's future forecast of additional capacity and energy needs are significant over the next two decades. To meet this demand, they have announced their intention to run procurement processes with contract awards being made as early as Q1 2023. Our three natural gas facilities, Gorway, York Energy, and East Windsor, all fall in these areas of Ontario that the ISO has signaled as high-need zones. All three sites have capacity for future new-build developments such as batteries, and our peaking facilities, as well as potential upgrades. And we've been working to get all three sites ready to be positioned to bid into the procurement processes. Providing additional capacity may require extending the existing contracts. Turning to slide seven, I'll discuss the recent update to the Clean Energy Standard in March 2022. The federal government initiated consultations on CES design principles and considerations with a commitment to manage the transition to maintain reliability and affordability. In July, the proposed frame for the clean energy regulation was released. One of the key elements in this classification of new and existing units. New units defined as those with a COD in 2025 or later would be subject to the near zero intensity base performance standard starting in 2035. Existing units defined as those with a COD before 2035 would be subject to the performance standard either in 2035 or linked to its end of life. Consultation with stakeholders will continue and the Environment and Climate Change Canada is targeting the end of 2022 for the release of its draft Clean Electricity Standard Regulation. One of the key takeaways is the recognition that our Canadian thermal fleet, including Genesee Repowering, would qualify as existing units and not new units. The framework would accommodate regional differences and mitigate potential for market disruption. It would leave it to provinces to develop detailed pathways reflective of their particular market structure and resource endowment. It also affirms a continued role for natural gas generation within a net zero framework. The framework recognizes a larger and long-term role for abated natural gas generation and does not reflect a ban on natural gas generation. Overall, the proposed frame is positive and enhances the value of our natural gas fleet. Turning to slide eight. This morning, we announced our ninth consecutive year of dividend growth with a 6% dividend increase. Based on the strength of our contracted cash flows from Midland Cogen acquisition, we announced an increase to our annual dividend growth guidance through 2025 from 5% to 6%. From 2022 to 2025, the average AFFO payout ratio based on a higher dividend increase is forecasted to be approximately 40%, and below our target of 45 to 55%. I'll now turn it over to Sandra.
spk01: Thanks, Brian. On slide nine, I'll touch on the financial highlights for the second quarter. Strong company-wide performance led to the financial results that exceeded our expectations. Revenues and other income before unrealized changes in fair value of commodity derivative and emission credits was $697 million in the second quarter, a 33% increase year over year. Adjusted EBITDA of $319 million benefited from higher generation and favorable margins from the Alberta commercial facilities and a full quarter of contributions from the additional phases of Whitlow Wind and Strathmore Solar. In Ontario, we saw one and a half times higher generation from Gorway from increased dispatch, mainly due to nuclear outages that required additional baseload generation and warmer temperatures in the province. And in the U.S., there were significantly higher contributions from Decatur and Arlington facilities due to higher dispatch, largely due to the timing impacts of planned outages year over year. We reported AFFO of $180 million in the second quarter, nearly double that of last year. Overall, higher generation and availability across the fleet contributed to significant year-over-year increases in AFFO and adjusted EBITDA. Turning to slide 10, I'll review our financial performance for the first half of the year. The year-over-year explanations for the six-month outperformance are similar to the second quarter commentary. Revenues and other income before unrealized changes in fair value of commodity derivative and emission credits were up 28% to $1.4 billion. Adjusted EBITDA of $667 million was up 23%, and benefited from higher generation and a strong Alberta power price that averaged $106 per megawatt hour and was partially offset by higher current income taxes and higher sustaining CapEx. AFFO was $380 million, up 52% from a year ago. Overall, we saw double-digit percentage increases in all key financial metrics. In the second quarter, we executed a new energy purchase agreement for island generation. Unlike the previous agreement, the new EPA is classified as a finance lease for accounting purposes, and while it does not impact AFFO, it reduces adjusted EBITDA by approximately $3 million per quarter. On slide 11, we have split out the key drivers of our outperformance in the first half of the year relative to our original guidance expectations. As you can see from the illustrative pie chart, It was higher generation in the Alberta commercial segment that included generation due to the deferral of the Genesee III planned outage to the back half of this year, and better performance from the non-Alberta facilities that were the two main drivers for the outperformance, contributing more than two-thirds of the total. To a lesser degree, higher Alberta power prices and natural gas trading optimization were also key contributors. Moving to slide 12, I'll touch on the Alberta power market and our hedge positions. The average Alberta spot price in the second quarter was $122 per megawatt hour compared to $105 a megawatt hour a year ago. The higher power price reflects the impact of higher natural gas costs, lower imports, and an overall increase in demand, along with an increase in carbon compliance pricing from $40 a ton to $50 a ton. Colder temperatures in the early part of the spring and outages in the oil sands contributed to higher demand for power in the second quarter. Our hedge positions for power and natural gas for 2023 to 2025 are shown on the slide. For 2023, we are 70% hedged in the high $60 per megawatt hour range. In 2024, we are 45% hedged in the low $60 per megawatt hour range, and 2025, we are 27% hedged in the low $60 range. This compares to forward prices of $95, $69, and $65 per megawatt hour for 2023 to 2025, respectively. Outside of our hedges, we continue to capture upside from higher power prices and price volatility with our clover bar gains gas peaking units, and our Halkirk and Whitlow wind facilities. Our exposure to rising natural gas prices for the Alberta fleet has been effectively hedged over the next few years. For 2023 and 2024, our expected natural gas burn is over 80% hedged and over 50% hedged in 2025. The average hedge prices for all three years is between $2.00 and $2.50 per GJ, which is much lower than the forward prices. Turning to slide 13, I'll conclude by reviewing our year-over-year performance and highlighting our higher revised financial guidance for 2022. After six months, facility availability was 93% and consistent with the full-year target, which reflects the planned outage for Genesee III scheduled later in the year. Sustaining CapEx was $55 million in the first half of the year and is expected to be above the $105 million to $115 million target range due to increased work planned for the remainder of the year and the timing of work. Driven by our stronger Alberta commercial performance, higher contributions from the contracted Ontario and US facilities, and the acquisition of Midland Cochrane facility, we have increased our 2022 financial guidance. The revised targets represent an 11% and 19% increase to the midpoints of the guidance ranges for adjusted EBITDA and AFFO respectively. The revised guidance range for adjusted EBITDA is $1.24 billion to $1.28 billion and $700 million to $740 million in AFSO. Lastly, we exceeded our $500 million growth target with the Midland Cogen acquisition. However, this does not preclude us from continuing to look for good opportunities. Similar to other years, we have the ability to do more than the target. I'll now turn the call back over to Randy.
spk08: All right. Thanks, Sandra. Charisse, we're ready to start taking questions.
spk00: Absolutely. 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 Casado with Raymond James. Please go ahead.
spk02: Thanks. Morning, everyone. My first question here just on the feed study for the Genesee CCS project. Just curious if there's any color or context you could provide on the parameters you're looking for in terms of performance and capital costs? Any specific items there that you'll look to learn as you approach FID in that process?
spk04: So Brian here. It's a typical feed study associated with CCUS. And as you know, we've been through this a couple of times before. So firstly, obviously the capital costs need to be you know, firmed up in terms of our estimate of about $2 billion. In addition to that, the technical viability is proved out as well, given that, you know, this is a significantly larger CCUS project than generally exists in the world today. But we believe that in the preliminary work. I don't believe that that's a challenge. The other thing is there's other operating parameters that are important. So, for example, as you can appreciate, we do need the facility to ramp to a limited degree to parallel what's happening with Genesee 1 and 2 as it's operating. The other parameter is around a degree of capture that we're looking for, and typically that's also backstopped by guarantees from the technology provider. And so those are the main parameters that we're looking for. We expect that we'll have some good preliminary view near the end of this year as sort of a checkpoint, and then the study will continue with more detailed engineering as it goes through the first half of next year.
spk02: That's great, Culler. Thank you. Maybe just one more for me, just thinking about – the solar supply chain and now that there's the waiver on the tariffs from certain countries in Asia. I'm just curious if you've seen any movement on pricing on the solar side and if availability has improved for you there noticeably.
spk04: No, we haven't seen any material changes. There continues to be a lot of discussion and a lot of sort of repositioning in the market, but You know, forward curves continue to be sort of pointing down a bit, but nonetheless don't really see any material changes in the situation for solar panels.
spk02: Okay, great. Thank you.
spk00: The next question comes from Rob Hope with Scotiabank. Please go ahead.
spk11: Good morning, everyone. A more conceptual question, you know, with you having a partner for the Midland acquisition, does this change the size of any opportunities that you could be confident going forward with in the future? Or could we see you go after additional acquisitions knowing that you have this, you know, call it secondary source of capital available to you?
spk04: So over the past, I'll say, half a dozen years, we have looked at large opportunities with what I call a financial partner. So this isn't new to us in terms of potentially larger kinds of transactions. This is one of the first ones, obviously, or the first one that's come to fruition. Manulife is already our partner at York and very familiar with them and relatively easy partnership. We could certainly see doing more with them in the future, but it always has expanded our view as to the size of acquisition that we could take on.
spk11: All right, that's helpful. And then the follow-up question there, you know, can you give an update, you know, if there's any other attractive opportunities in the mid-life gas acquisition space? And then I guess, secondly, would you look to kind of integrate and kind of, you know, reap some synergies at Midland before going after another one?
spk04: So, you know, there continues to be a fair number of opportunities in terms of natural gas acquisitions out there that are, you know, consistent with our strategy. So, you know, we continue to look at them and certainly would not wait to, you know, quote, unquote, integrate Midland before we'd move on another one. But, you know, again, it's a... continues to be a relatively high traffic market and so we're pretty optimistic about being able to find similar kinds of opportunities. But again, we've got the financial capability to move fairly quickly and certainly I'll say the people capacity to take on a couple of acquisitions at the same time. In fact, I think in our history we've demonstrated that a few times. Thank you.
spk00: The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
spk05: Thank you. Good morning, everyone. Just on the Midland acquisition, and I know it's early days, but can you expand on what sort of operational efficiencies as well as capacity expansion potential you think you might be able to go after on-site? and then how much upside this might represent to your base return or accretion guidance?
spk04: So, Pat, when we're looking at an opportunity like Midland, you know, there's always elements that you look at in terms of potential efficiencies and different things that as Capital Power we stand back and look at and say, you know, we may well be able to to create an optimization here or there. But it's been a very well-run plant. And so there aren't glaring opportunities to fix things that are wrong. Nothing's broken there. So as we look forward to it, we believe there's elements like natural gas optimization that might be available. We haven't gotten in that close to be able to fully assess that. As well as capacity expansions, there certainly is some opportunities around potentially additional natural gas and batteries at that location. But again, that takes a much more complete market assessment. And just to kind of put some color around it, when we looked at the acquisition and looked at the potential and looked at values in terms of expansion or value, ongoing value of this site beyond the recontracting that we've assumed. We've only attributed a couple of percent in value, so we don't see it or haven't paid for a significant amount, although we do see that there should be some significant potential there, but an assessment of to what degree at this point would be totally arbitrary.
spk05: Okay, thanks for that, Brian. And then maybe just switching gears to the CCS project, any update on timing for a contract for differences with the federal government related to the carbon tax or any progress expected to be made here through the back half of the year?
spk04: So we do expect a significant amount of progress through the back half of the year, particularly on the contract for differences. There hasn't been a lot of feedback yet to the market. We do understand that the federal government is looking at it and considering it, but again, not a lot of feedback, not a lot of discussion taking place, but they do realize that that that is likely going to be the one element that holds up progress, not just with us, but across anyone looking at CCUS.
spk05: Okay, thanks. Then maybe just a housekeeping question here for Sandra. Just back to your natural gas hedging update on slide 12 there. Now representing over 80% of your base load needs. I think that's down from just over 90% previously. wondering if you can reconcile the the difference there and maybe confirm if you've been active in monetizing any natural gas positions and if so if you expect to crystallize more value from the hedge book going forward thanks pat yeah you're right we were reporting over 90 percent last quarter that's now down to just over 80 percent and that's just based on
spk01: the desk doing exactly what you indicated. We are crystallizing value on some of those trades, and that's being driven by a review of our expected gas burn. So that's the operational profile of the facility. So as we get closer to the beginning of 2023, we'll continue to optimize both our gas and power positions, and to the extent that there is incremental gas in periods where We're not forecasting burn. We are able to crystallize those trades given where gas is trading today at a profitable margin.
spk05: Okay. Thank you. I'll leave it there. Appreciate it.
spk00: The next question comes from Mark Jarvie with CIBC Capital Markets. Please go ahead.
spk10: Thanks. Good morning, everyone. Brian Neal on the carbon capture and investment tax credit. I know some of there's some language around the use for post combustion and whether or not it can be compliance needs just updated views in terms of how you see that playing on eligibility. You know, maybe the framework for tier equivalency and then federal path on carbon or emission standards went forward. So just maybe your updated views on your ability to get that tax credit.
spk04: So definitely see that we are fully eligible for that tax credit in terms of, you know, there is a little bit of discussion as to, you know, what might be a level of capture that one might have to meet in order to be eligible. And also, you know, the emissions profile going forward. And in fact, I would say the federal government has worked very cooperatively across the federal bodies looking at these different elements, because from our reading of it, there's clearly a path there for Genesee 1 and 2 combined with CCUS to have a physical life well beyond, or economic life well beyond 2035. So for us, the actual proposed regulations and discussions are actually dovetailing definitely to the favor of our CCUS project.
spk10: Great. And then Sandra, maybe something to use in terms of other sources of funding, you know, the debt market, press market. You obviously talked about earlier in the call about appetite for more capital deployment. Just how do you guys see those markets right now? Would you be able to access them right now? Does that give you any pause to wait for the market volatility to settle down?
spk01: Yeah, thanks, Mark. So when we're looking at the financing on the debt side, as we've signaled, we do have a PREF redemption that is coming up. And we've hedged the underlying on that and feel that we could look to upsize that if we needed to increase our debt. Also feel we could access the equity market if we were to do another transaction that was a larger size. So feel that Both markets are well open to us at this point in time on the back of a transaction. So I feel that we've got a fair bit of flexibility. And given our cash flow this year and going into next year, also have flexibility around timing of doing any kind of an offering to make sure that we're able to take advantage of constructive windows to execute on any deals that we do.
spk10: Okay, and then just a last one for me, just on Gorway, you mentioned in the sort of slides about some upside you're seeing there. You know, if the market is tight, as you expect it to be in Ontario, how big of an impact is that for Gorway or any of their MTO gas assets on existing contracts? And then, I guess, how has Gorway done relative to your sort of base case underwriting scenario when you guys acquired the asset a couple years ago?
spk04: Starting with the last question, first, Gourway has done very well relative to our expectation. Today, as you're seeing in our results, it's being dispatched more, which illustrates its value to the ISO in terms of the Ontario power situation. So the degree to which we think the developments in Ontario will impact on our assets, just to maybe make a short story long, what's occurring is that they're foreseeing a shortage of 2,500 megawatts by 2025 that the ISO and the government are in agreement that they need to fill. And there's a couple of different alternatives, obviously. There's expanding some natural gas at existing sites. There's upgrades at existing facilities. And there's also batteries. And so they'll be looking at different opportunities at different sites to enable filling that 2,500 megawatts. and we believe we are extremely well positioned. They've identified two zones in particular that are problematic. One is called the West Zone, which is where East Windsor is, and then the other two are in the Toronto region, or the other issue is in the Toronto region, and that's where Gorway and York are. So we see significant opportunities at all our three sites and have been actively pursuing them. In fact, we started the environmental process for permitting different alternatives back this spring. It's a very real opportunity for us, and we're pursuing it very vigorously.
spk10: Thanks for that comment.
spk00: The next question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
spk03: Thank you, and good morning. My first question is about capital allocation, and I believe on the last conference call, you mentioned that you intended for access-free cash flow to be allocated towards acquisitions and development capex, and that you weren't leaning towards any buybacks and or changing of dividend growth targets. So I guess with the upgrade to 6% dividend growth, could you just refresh us on your view of how you plan to allocate what obviously appears to be solid excess free cash flows moving forward?
spk01: Yeah, thanks, Marie. So we did indicate that we were comfortable with our guidance at Investor Day for dividend increases. However, on the back of Midland and continued very strong outlook for this year and into next year, felt that a 6% dividend guidance was in line with our cash flow projections. And as you know, we tend to do dividend increases on the back of contracted growth, so that being the catalyst. From a capital allocation perspective going forward, you look at our payout ratio, and with this dividend increase, we do continue to be below our target and the objective is to be at or below that target and redeploy the rest into growth. As we've spoken to, we see a fair bit of opportunity for us in Ontario and Alberta with respect to growth, so looking to have that cash flow available to fund those opportunities as well as other M&A and the build out of our renewable platform. As far as our dividend itself, we feel that the increase in our dividend yield are very competitive when we look at that relative to our peers. So at this point, I feel that the capital allocation that we've targeted right now is an appropriate level.
spk03: Understood. And maybe a follow-on from that in terms of growth capex. If I remember correctly, you mentioned that you were hoping to progress at least one renewable project this year. Given that we have a two-year pause in tariff exemptions for solar from certain countries and maybe with the U.S. Inflation Reduction Act being introduced, do you see yourself positioned to progress more than just one this year and or for next year as well?
spk04: So I think there's still a little bit of churn in the market taking place. You know, we still are hopeful that we'll have a project come to fruition this year that we could announce. I think increasing that expectation would probably be a bit too aggressive, but certainly see next year a number of opportunities may well come to fruition.
spk03: Great. Thank you very much.
spk00: The next question comes from John Mould with TD Securities. Steve, go ahead.
spk06: Thanks. Thanks. Good morning. Maybe just going back to the clean electricity regulations, in the context of potential Canadian gas acquisitions, as you noted, the federal government's recently given us some more details on what that structure could look like you know how does this update inform your willingness to look at acquisitions of more midlife gas assets specifically in canada where you know policies specifically targeting carbon emissions look like they'll be much stronger than in the u.s or you know are you do you anticipate the most if not all of the gas facilities you'll seriously look at acquiring will most likely be located in the united states what are your thoughts on all that
spk04: So I think just naturally with a number of natural gas assets in the U.S. versus Canada, there will be more opportunities in the U.S. than Canada. So in the longer term, I think you'd see, whether it's that, whether it's development, whether it's acquisition of renewable projects, I think you'd expect to see more activity in the U.S. than Canada. When it comes to the regulations in Canada and them being somewhat, I'll call it stricter than in the U.S. from an environmental perspective, we certainly see with what's happening with the Clean Electricity Standard as being on balance very positive for the natural gas strategy. The backdrop that has been there for the last couple of years on the natural gas side has been one where there's expectations, broad expectations, that there'd be a significant increase in stringencies, significant increases in actions on provincial and federal levels, including potentially even prohibitions against natural gas. What this actually represents, and what seems to be developing in Alberta, is a broad recognition that natural gas is going to be a critical fuel as we move forward, and not just for the next five years or ten years, but it's going to have a critical element even beyond that. So in terms of our natural gas strategy, and if you think of acquiring assets that are particularly well-positioned, for the long-term future. This evolution of thinking and policy in Canada has been tremendous for us.
spk06: Okay, that's great context. Thanks. And then maybe just moving to your coal costs, can you maybe just provide a bit of insight and and how you're expecting those coal costs to trend through the rest of 2022 and 2023 relative to where they are now as you transition Genesee to fully running off of gas by the end of next year.
spk01: Thanks, Johnny. We're not expecting a material shift in the cost per ton in coal, but it's something that we continue to work through as we get a clear line of sight of when we're completely off coal. So see that There has been an increase in the cost per ton going back to a few years ago when we would have expected to be continuing on coal for a longer time, but the uptick in pricing isn't something I would view as being a material increase in our costs as we run out through 2023.
spk06: Okay, I'll get back in the queue. Thank you very much for taking my questions.
spk00: The next question comes from Ben Pham with BMO. Please go ahead.
spk09: Hi, thanks. Good morning. I wanted to go back to the CES and especially some of your commentary around the Alberta Power Price Outlook and the middle part of the decade. I'm wondering with this proposed CES, are you expecting or still expecting a decline in pricing in the middle part of the decade?
spk04: Yes, it is consistent with that. I would say, well, maybe I should step back. If you had a view of much higher levels of stringency, potentially even greater elevation in natural gas prices, you would see a scenario where you would have higher power prices. So I'd say with this CES, or at least, you know, the initial discussions and where it seems to be going, you would see, you know, potentially slightly softer power prices as we move forward, but wouldn't dramatically change the expectations or, you know, certainly not the forward curve in the short run, but in the longer run, it would be signaling, you know, slightly more moderate power costs. You know, I think that was one of the huge differences in the, I would say, in the considerations in terms of the CES and tier and basically the whole fabric as it goes forward is there's a much greater consideration around reliability and cost. And so that's why I think, in part, you're seeing some of the actions that are being taken today.
spk09: Okay, and do you still expect, and maybe linked to that, just maybe more where my question is going, do you expect the flood to supply? It's just a long queue of gas plants because it looks like the CES is looking at the new units, how you've defined it. I mean, a lot of these gas plants are coming in the 2025-2026 timeframe.
spk04: So, obviously, the ones that are in process now we see coming in don't really see that it would create a flood of supply. What's clear in the regulations is that anything complete after 2025 would end up facing relatively significant environmental implications starting in 2035, so a relatively short economic life. I don't see the window of opportunity being big enough for, again, a significant number of facilities coming into Alberta.
spk09: Okay. And maybe my last one, switching to island generation, you highlighted the EBITDA impact. Is that from an accounting change impact, or is that the impact from the recontracting?
spk01: That's an accounting change. As you may recall, earlier this year, we did take an impairment on island generation and wrote down the book value of that plant. That was taking a view of what we expected the recontracting would be on island at that time. So as that contract was executed under accounting rules you look at the present value of those contract payments and compare that to the book value and if substantially all of the value of the contract is equal to the book value of the plant then it's considered a finance lease as opposed to an operating lease and therefore the Impact on the income statement is through the finance expense line as finance income versus hitting EBITDA or lease revenue, which it would if it was an operating lease, which it was prior to execution of this contract.
spk09: Okay. And you have a benefit of lease liabilities run off for that.
spk01: That's right. Is that right? That's right. So you set up your lease receivable and it runs off over the four and a half years of the contract term.
spk09: Okay, got it. Okay, thank you.
spk00: The next question comes from Andrew Cusk with Credit Suisse. Please go ahead.
spk07: Thanks. Good morning. I guess maybe if you could give us some context on just Midland and Cognizant hasn't closed, but when you think about just positioning with the portfolio of development opportunities you have, in particular in MISO, To what degree do you think Midland will help you really pursue some of those opportunities with just greater market knowledge and then an ability to have a greater interaction among various pieces of generation equipment in the region?
spk04: So, Andrew, you're actually bang on in terms of your question. I mean, we have facilities already in the broader area that we think we may be able to look at different ways to leverage the technology the two facilities. As you know, Midland does have a small portion of merchant capacity, so utilization of that may well complement assets in the area. But we also have other opportunities in the region in terms of renewables. But we see that, particularly that region, as being A very, very positive place to be from a North American perspective. You know, there's significant coal retirements that'll be taking place. There's just recently it was a nuclear retirement, and we expect further nuclear retirement. So there's a significant increase or decrease in supply that'll be taking place, increasing demand in general. And we've got a site and a facility that's extremely well positioned with some very close significant industrial loads. So it's very well positioned for a whole range of different kinds of opportunities. So very pleased with that acquisition and see it as being integral to other opportunities in the region over time. There's even natural gas swapping opportunities with Ontario. as its position. So, I mean, we just see a tremendous amount of capability there.
spk07: That's helpful context, and then maybe just backing up and looking even further at the top of the house, how do you think of just capital allocation opportunities, say, MISO, the Southeast, which you've been sort of building up from an opportunity standpoint and also have, you know, effectively assets generating power, and Alberta, if we just think of, like, those three major areas?
spk04: So typically, we can continue to look at the best opportunities as they come forward from a value creation. And the view of value creation is expanding as we go forward. Certainly, one of them is the environmental implications is very significant in terms of what we look at, but also whether or not it provides a bit of a platform with further development or adding assets to an area. Certainly, we're seeing that kind of positive reflection in Ontario, Alberta. We're seeing it every day, the value of having a combination of excellent assets. You're quite right. We'll certainly see MISO and with the the Crown Jewel being the Midland asset as being a significant area to grow. We wouldn't necessarily, in the longer term, our longer term view, allocate capital to those regions. What we end up doing more is allocating resources looking at opportunities in regions. So, you know, we will be putting more effort into the MISO area given our position, but likewise, tremendous effort will be taking place in Ontario, Alberta, and to a lesser degree, the balance of our footprint.
spk07: Okay. Very much appreciated. Thank you.
spk00: Once again, if you have a question, please press star, then 1. The next question comes from Najee Bejoon with IA Capital Markets. Please go ahead.
spk12: Hi, good morning. Just a couple of questions. Maybe if you can give us a bit more color on the strategy around midland over the long term, just given the age of the asset and maybe some previous attempts to expand capacity there. Just wondering how you're thinking about that.
spk04: So when we look at the asset, you know, specifically, you know, it is true that it is an aging asset. But certainly we see opportunities there, A, from a footprint perspective and potentially adding generation, but there's also, you know, there's different levels of, you know, quote-unquote repowering that could take place on the existing assets. So the real value there for potential future growth is the site itself and the services to it, natural gas assets, you know, access, position on the grid, etc. And again, we see that as being, you know, very, very favorable at that site.
spk12: Okay, and just, I guess, similar to this, with Midland, you're going to be adding some management fees into your revenue or cash flow streams. Do you see other opportunities to go after those same types of revenues that arguably, you know, maybe are lower risk, more asset light and something that you could replicate with other facilities?
spk04: So we could see, you know, certainly, you know, through partnership structures and so on, you know, work from that perspective. If you're thinking of would we go and operate without a significant ownership position somewhere, no. We very much see great value in owning assets, and if we're putting in the effort to add value, we'd like to reap that value and not just earn fees. So that is something that we would not do, is simply operate assets for fees.
spk12: Okay, and maybe just to clarify, when you say an ownership stake in an asset, is there a minimum threshold? Does that have to be a majority stake or even on a minority basis?
spk04: I think we'd consider it on a minority basis. It all depends on the partners and the structuring and, you know, what that reflects. But, you know, certainly something like a 25% interest in a significant asset would be, you know, might have some appeal to us. But it boils down to the overall quantum of investment. I mean, you may recall when we had, I don't know, 15 cogens all around North America that were relatively small investments for us. And it just took a tremendous amount of effort. And so we would have some significant minimums that we'd consider if we were looking at a minority interest but an operating position in an asset. Certainly, we'd have to have an investment opportunity of a couple hundred million before we'd look at something like that.
spk12: Okay. That makes sense. Thank you very much.
spk00: This concludes the question and answer session. I would like to turn the conference back over to Mr. Randy Ma for any closing remarks.
spk08: Okay, if there are no more questions, we will conclude our conference call. Thanks for joining us this morning and for your interest in capital power. Have a good day, everyone.
spk00: This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.
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