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 2, 2022. I will now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead.
Good morning. Thank you for joining us today to review Capital Power's second quarter 2022 results, which we release 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 Vaasjo, 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 on forward-looking information on slide two.
In today's discussion, we'll be referring to various non-GAAP financial measures and ratios as noted on slide three. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures which are provided in the analysis of the company's results for management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP 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.
Thanks, Randy, and good morning. Capital Power's head office in Edmonton is located within the traditional and contemporary home of many indigenous peoples of the Treaty six 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 IESO 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. Last month, the federal government released its proposed framework for its Clean Electricity Regulations. Under the proposed framework, 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. 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 mid-life 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, that includes $521 million of project-level debt. We plan to finance our portion of $186 million with cash on hand and 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 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 expired. 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. For Arlington in Arizona, we executed a six year extension with materially higher AFFO over the extended term. Most recently, we executed a four and a half year renewal for our Island Generation in B.C.
We continue to advance for longer-term recontracting as part of our BCUC's IRP review process. In Ontario, the IESO'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, Goreway, York Energy, and East Windsor, all fall in these areas of Ontario that the IESO has signaled as high-need zones. All three sites have capacity for future new build developments such as batteries and/or 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 Electricity 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 Electricity Regulations 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-based 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 Regulations. 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 framework 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%-55%. I'll now turn it over to Sandra.
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 derivatives and emission credits was CAD 697 million in the second quarter, a 33% increase year-over-year. Adjusted EBITDA of CAD 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 Whitla Wind and Strathmore Solar. In Ontario, we saw 1.5x higher generation from Goreway from increased dispatch, mainly due to nuclear outages that required additional baseload generation and warmer temperatures in the province.
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 CAD 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 CAD 1.4 billion.
Adjusted EBITDA of CAD 667 million was up 23% and benefited from higher generation and a strong Alberta power price that averaged CAD 106 per megawatt hour and was partially offset by higher current income taxes and higher sustaining CapEx. AFFO was CAD 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 CAD 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 3 unplanned outage to the back half of this year. 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 CAD 122 per MWh compared to CAD 105 per MWh 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 CAD 40 a ton to CAD 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 CAD 60 per MWh range.
In 2024, we are 45% hedged in the low CAD 60 per MWh range, and in 2025, we are 27% hedged in the low CAD 60 range. This compares to forward prices of CAD 95, CAD 69, and CAD 65 per MWh for 2023 to 2025 respectively. Outside of our hedges, we continue to capture upside from higher power prices and price volatility with our Cloverbar gas peaking units and our Halkirk and Whitla 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 CAD 2 and CAD 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 3 scheduled later in the year. Sustaining CapEx was CAD 55 million in the first half of the year and is expected to be above the CAD 105 million-CAD 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 U.S. facilities, and the acquisition of Midland Cogen 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 CAD 1.24 billion-CAD 1.28 billion and CAD 700 million-CAD 740 million in AFFO. Lastly, we exceeded our CAD 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.
All right. Thanks, Sandra. Charisse, we're ready to start taking questions.
Absolutely. We will now begin the question-and-answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. The first question comes from David Quezada with Raymond James. Please go ahead.
Thanks. Morning, everyone. My first question here, just on the FEED study for the Genesee CCS project. Just curious, if there's any color or context you can 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?
Brian here. You know, it's a typical FEED study associated with CCUS. As you know, we've been through this a couple of times before. Firstly, obviously the capital costs need to be firmed up in terms of our estimate of about CAD 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. We believe that in the preliminary work, don't believe that that's a challenge. The other thing is there's other operating parameters that are important.
For example, as you can appreciate, you know, 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. 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. You know, the study will continue with a few more detailed engineering as it goes through the first half of next year.
That's great color. Thank you. Maybe just one more from 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 for the solar side and if availability has improved for you there noticeably.
No, we haven't seen any material changes. You know, there continues to be a lot of discussion and a lot of sort of repositioning in the market. 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.
Okay, great. Thank you.
The next question comes from Rob Hope with Scotiabank. Please go ahead.
Good morning, everyone. A more conceptual question. You know, with you adding a partner for the Midland acquisition, does this change the size of M&A 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?
You know, over the past, I'll say half a dozen years, we have looked at large opportunities with what I call a financial partner. This isn't new to us in terms of potentially larger kinds of transactions. This is, you know, 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, you know, relatively easy partnership. We could certainly see doing more with them in the future, but it does, it always has expanded our view as to the size of acquisition that we could take on.
All right. That's helpful. A follow-up question there. You know, can you give an update that, you know, you know, if there's any other attractive opportunities in the mid-life gas acquisition space? 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?
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. 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. Y ou know, again, it continues to be a relatively high traffic market. You know, we're pretty optimistic about, you know, being able to find, you know, similar kinds of opportunities. A gain, you know, we've got the financial capability to move fairly quickly and certainly the, 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.
The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
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? How much, you know, upside this might represent to your base return or accretion guidance?
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 create an optimization here or there. You know, it's been a very well-run plant. There aren't glaring opportunities to you know, fix things that are wrong. Nothing's broken there. As we look forward to it, you know, we believe there's elements like natural gas optimization that might be available. You know, we haven't gotten in that close to be able to fully assess that. As well as capacity expansions.
You know, there certainly is some opportunities around potentially additional natural gas and batteries at that location. Again, you know, that takes a much more complete market assessment. You know, just to kind of put some color around it, you know, when we looked at the acquisition and looked at the potential and, you know, looked at values in terms of, you know, expansion or, you know, value, ongoing value of the site beyond, you know, the recontracting that we've assumed, you know, we've only attributed a couple of percent in value. It's not. 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. An assessment of to what degree at this point would be totally arbitrary.
Okay, thanks for that, Brian. 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?
We do expect a significant amount of progress through the back half of the year, particularly on the contract for differences. You know, 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. A gain, not a lot of feedback, not a lot of discussion taking place, but they do realize that that is likely gonna be the one element that holds up progress, not just with us, but, you know, across anyone looking at CCUS.
Okay, thanks. T hen 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. Just wondering if you can reconcile the difference there and maybe confirm if you've been active in monetizing any natural gas positions. I f 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% last quarter. That's now down to just over 80%, and that's just based on 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. That's the operational profile of the facility. As we get closer to the beginning of 2023, we'll continue to optimize both our gas and power positions. 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.
Okay. Thank you. I'll leave it there. Appreciate it.
The next question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead.
Thanks. Good morning, everyone. Brian, on the carbon capture and the investment tax credit, I know there's some language around the use for post combustion and whether or not it's going to be compliance needs. Just updated views in terms of how you see that playing on eligibility, you know, maybe framework for tier equivalency and then the federal path, on carbon or emission standards going forward. Just maybe your updated views on your ability to get that tax credit.
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. 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.
For us, the actual proposed regulations and discussions are actually dovetailing definitely to the favor of our CCUS project.
Great. Sandra, maybe some updated views in terms of other sources of funding, you know, the debt market, pref market. You obviously talked about earlier in the call the appetite for more capital deployment. Just how 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?
Yeah. Thanks, Mark. Yeah, 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. 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. Feel that both markets are well open to us at this point in time on the back of a transaction. Feel that we've got a fair bit of flexibility.
Given our cash flows this year and going into next year, also have timing around or 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.
Okay. Just last one for me, just on Goreway. It was 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 Goreway or any of their Ontario gas assets on existing contracts? I guess, how has Goreway done relative to your sort of base case underwriting scenario when you guys acquired the asset a couple years ago?
Starting with the last question first, Goreway has done very well relative to our expectation. You know, today, as you're seeing, you know, in our results, it's being dispatched more, you know, which illustrates, you know, its value to the IESO in terms of the Ontario power situation. The degree to which we think the developments in Ontario will impact on our assets, you know, just to maybe make a short story long, you know, what's occurring is that, you know, they're foreseeing a shortage of 2,500 MW by 2025 that the IESO and the government are in agreement that they need to fill. There's a couple different alternatives. Obviously, there's expanding, you know, some natural gas at existing sites.
There's upgrades at existing facilities, and there's also batteries. They'll be looking at different opportunities at different sites to enable, you know, filling that 2,500 MW. 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 issue is in the Toronto region, and that's where Goreway and York are. We see significant opportunities at all our three sites and have been actively pursuing them. In fact, we started the environmental process for, you know, for permitting different alternatives, you know, back this spring. It's a very real opportunity for us and we're pursuing it very vigorously.
Okay. Thanks for that commentary.
The next question comes from Maurice Choy with RBC Capital Markets. Please go ahead.
Thank you, and good morning. My first question is about capital allocation. I believe in the last conference call, you mentioned that you intended for excess 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. 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?
Yeah. Thanks, Maurice. We did indicate that, you know, 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. As you know, we tend to do dividend increases on the back of contracted growth. 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. The objective is to be at or below that target and redeploy the rest into growth.
You know, as we've spoken to, we see a fair bit of opportunity for us in Ontario and Alberta with respect to growth. Looking to have that cash flow available to fund those opportunities as well as other M&A in the build-out of our renewable platform. As far as our dividend itself, we feel that the increase and our dividend yield are very competitive when we look at that relative to our peers. At this point, feel that the capital allocation that we've targeted right now is an appropriate level.
Understood. Maybe 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?
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. Certainly see next year a number of opportunities may well come to fruition.
Great. Thank you very much.
The next question comes from John Mould with TD Securities. Please go ahead.
Thanks. Good morning. Maybe just going back to the Clean Electricity Regulations. In the context of potential Canadian gas acquisitions, you know, 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 mid-life 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, or do you anticipate that 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?
I think just naturally with a number of, you know, natural gas assets in the U.S. versus Canada, you know, there'll be more opportunities in the U.S. than Canada. In the longer term, I think you'd see, you know, 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 so much, I'll call it stricter than in the U.S. from an environmental perspective, you know, we certainly see, you know, with what's happening with the Clean Electricity Standard, as being on balance very positive for the natural gas strategy.
You know, the backdrop that you know 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 stringency significant you know increases in actions on provincial and federal levels you know including you know potentially even prohibitions against natural gas. What this actually represents and you know what seems to be developing in TIER in Alberta is a broad recognition that natural gas is gonna be a critical fuel as we move forward and not just for you know the next five years or 10 years but it's gonna have a critical element even beyond that.
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.
Okay. That's great context. Thanks. Maybe just moving to your coal costs. Can you maybe just provide a bit of insight in 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?
Thanks, John. Yeah. We're not expecting a material shift in the cost per ton in coal, but that's something that we continue to work through as we get a clear line of sight of when we're completely off coal. 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. The uptick in pricing isn't something I would view as being a material increase in our costs as we run out through 2023.
Okay. I'll get back in the queue. Thank you very much for taking my questions.
The next question comes from Ben Pham with BMO. Please go ahead.
Hi. Thanks. Good morning. I wanted to go back to the CES and especially some of your commentary around the Alberta power price outlook in the middle part of the decade. I'm wondering, with this proposed CES, are you expecting or still expecting that the decline in pricing the middle part of the decade?
Yes. It is consistent with that. I would say. Well, maybe I should step back. If you had a view of, you know, much higher levels of stringency, potentially, you know, even greater elevation in natural gas prices, you would see a scenario where you would have higher power prices. I 'd say, you know, 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. It 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. That's why I think in part you're seeing some of the actions that are being taken today.
Okay. Do you still expect, and maybe linked to that, this may be more where my question is going, do you expect a flood of supply? It's just that long queue of gas plants, 'cause it looks like the CES is looking at the new units, how you've defined it, I mean, all these gas plants that come in the 2025-2026 timeframe.
You know, obviously the ones that are in process now we see coming in don't really see that it would create a flood of supply. I mean, what's clear in the regulations is that anything you know complete after 2025 would end up facing relatively significant you know environmental implications starting in 2035. 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.
Okay. Maybe my last one. Switching to island generation. You highlighted the EBITDA impact. Just wanna clarify, is that from an accounting change impact, or is that the impact from the recontracting?
No, 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. 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. 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. 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.
Okay. You have a benefit of lease liabilities run off for that.
That's right.
Is that right?
You set up your lease receivable, and it runs off over the four and a half years of the contract term.
Okay. Got it. Okay. Thank you.
The next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Thanks. Good morning. I guess maybe if you could give us some context on just Midland, and Cogen 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, you know, various pieces of generation equipment in the region?
Andrew , you're actually bang on in terms of your question. I mean, we have facilities already, in the broader area that, we think, you know, we may be able to look at different ways to leverage the two facilities. As you know, Midland does have a small portion of merchant capacity, so utilization of that may well, you know, complement assets in the area. Y ou know, we also have other opportunities in the region in terms of renewables. Y ou know, we see that, particularly that region, as being 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. There's a significant increase or decrease in supply that'll be taking place, increasing demand in general. We've got a site and a facility that's extremely well-positioned with some, you know, very close significant industrial loads. It's very well positioned for a whole range of different kinds of opportunities. Very pleased with that acquisition and see it as being integral to, you know, other opportunities in the region over time. There's even natural gas swapping opportunities with Ontario as it's positioned. I mean, we just see a tremendous amount of capability there.
That's helpful context. 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?
You know, typically we can continue to look at, you know, the best opportunities as they come forward from a value creation. You know, 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, you know, whether or not it provides a bit of a platform with, you know, further development or, you know, adding assets to an area. You know, 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.
You know, we'll certainly see, you know, MISO and with the crown jewel being the Midland asset as being a significant area to grow. We wouldn't necessarily, in the longer term view, allocate capital to those regions. What we end up doing more is allocating resources, looking at opportunities in regions. 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, you know, Alberta, and to a lesser degree, you know, the balance of our footprint.
Okay. Very much appreciated. Thank you.
Once again, if you have a question, please press star then one. The next question comes from Naji Beydoun with iA Capital Markets. Please go ahead.
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.
When we look at the asset, you know, specifically, you know, it is true that it is an aging asset. C ertainly we see opportunities there from a footprint perspective and potentially adding generation. There's also, you know, different levels of, you know, quote-unquote, repowering that could take place on the existing assets. The real value there for potential future growth is the site itself and the services to it, natural gas, you know, access, position on the grid, et cetera. Again, we see that as being, you know, very favorable at that site.
Okay. Just, I guess similar to this, with Midland, you're gonna 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 in other, with other facilities?
We could see, you know, certainly, you know, through partnership structures and so on, you know, work from that perspective. You know, if you're thinking of, you know, would we, you know, go and operate without, you know, significant ownership position somewhere? No. You know, we very much see great value in owning assets. I f we're putting in the effort to add value, we'd like to reap that value and not just earn fees. That is something that we would not do, is simply operate assets for fees.
Okay. Maybe just to clarify, when you say an ownership stake in an asset, is there a minimum threshold? Is it after the majority stake or even on a minority basis?
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. You know, certainly something like a 25% interest in a significant asset would be, you know, might have some appeal to us. You know, 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, you know, relatively small investments for us. It just, you know, took a tremendous amount of effort. You know, 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. You know, certainly, you know, we'd have to be having an investment opportunity of CAD 200 million before we'd look at something like that.
Okay. That makes sense. Thank you very much.
This concludes the question and answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.
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.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.