CA - Capital Power Corporation (CPXWF) CEO Brian Vaasjo on Q2 2022 Results - Earnings Call Transcript
Capital Power Corporation (CPXWF)
Q2 2022 Earnings Conference Call
August 02, 2022 11:00 AM ET
Company Participants
Randy Mah - Director of Investor Relations
Brian Vaasjo - President and CEO
Sandra Haskins - Senior Vice President, Finance and CFO
Conference Call Participants
David Quezada - Raymond James
Rob Hope - Scotiabank
Patrick Kenny - National Bank Financial
Mark Jarvi - CIBC Capital Markets
Maurice Choy - RBC Capital Markets
John Mould - TD Securities
Ben Pham - BMO
Andrew Kuske - Credit Suisse
Naji Baydoun - IA Capital Markets
Presentation
Operator
Thank you for standing by. This is the conference operator. Welcome to Capital Power's Second Quarter 2022 Results Conference Call. [Operator Instructions] and the conference is being recorded today, August 2, 2022.
I will now turn the call over to Mr. Randy Mah, Director of Investor Relations. Please go ahead.
Randy Mah
Good morning, and 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 Vaasjo, President and CEO; and Sandra Haskins, Senior Vice President, Finance and CFO. We will start with opening comments and then open the lines to take your questions.Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business.
Please refer to the cautionary statement on forward-looking information on Slide 2.In today's discussion, we will be referring to various non-GAAP financial measures and ratios as noted on Slide 3. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures, which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in our second quarter 2022 MD&A.I will now turn the call over to Brian for his remarks, starting on Slide 4.
Brian Vaasjo
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 6 region and Metis 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 4.5-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 IESO has identified significant incremental capacity needs as early as 2025. This provides a positive outlook for our 3 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 that 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 5.
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. It's accretive and contracted in its advantaged location where it's well-positioned for future recontracting. The purchase price is approximately USD 894 million that includes USD 521 million of project-level debt.
We plan to finance our portion of the USD 186 million with cash on hand in utilizing our credit facilities. No equity will be required to finance this transaction. The 5-year average AFFO accretion per share is forecast to be USD 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 6 highlights our track record of recontracting natural gas assets after they've been required. This includes recontracting 2 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 6-year extension with materially higher AFFO over the extended term.
And most recently, we executed a 4.5-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 IESO's future forecast of additional capacity and energy needs are significant over the next 2 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 3 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 3 sites have capacity for future new build developments such as batteries, and are peaking facilities as well as potential upgrades. And we've been working to get all 3 sites ready to be positioned to bid into the procurement processes. Providing additional capacity may require extending the existing contracts.
Turning to Slide 7. 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 0 intensity-based performance standard starting in 2035. Existing units defined as those with the 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 growth for natural gas generation within a net 0 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 8. 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.
Sandra Haskins
Thanks, Brian. On Slide 9, 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 $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 contribution 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. 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 6-month outperformance are similar to the second quarter commentary. Revenues and other income before unrealized changes in fair value of commodity derivatives 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 3 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 2/3 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 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 stand 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 gas peaking units in our Halkirk and wind -- 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 3 years is between $2 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 6 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 $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 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 $1.24 billion to $1.28 billion, and $700 million to $740 million in AFFO. 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.
Randy Mah
All right. Thanks, Sandra. [Judy], we're ready to start taking questions.
Question-and-Answer Session
Operator
[Operator Instructions] The first question comes from David Quezada with Raymond James.
David Quezada
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 Vaasjo
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 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 this is a significantly larger CCUS project than generally exists in the world today. So then -- 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.
David Quezada
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?
Brian Vaasjo
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 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.
Operator
And the next question comes from Rob Hope with Scotiabank.
Rob Hope
A more conceptual question. 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, call it, secondary source of capital available to you?
Brian Vaasjo
So,, over the past, I'll say, half a dozen years, we have looked at large opportunities with what I'd 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. And Manulife has -- is already our partner at York, and very familiar with them and relatively easy partnership. So, 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.
Rob Hope
And then a follow-up question there. Can you give an update if there's any other attractive opportunities in the midlife gas acquisition space? And then I guess, secondly, would you look to kind of integrate and kind of reap some synergies at Midland before going after another one?
Brian Vaasjo
So, there continues to be a fair number of opportunities in terms of natural gas acquisitions out there, that are consistent with our strategy. So, we continue to look at them and certainly would not wait to integrate Midland before we'd move on another one. But again, it's -- it 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, 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.
Operator
The next question comes from Patrick Kenny with National Bank Financial.
Patrick Kenny
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 do 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?
Brian Vaasjo
So Pat, when we're looking at an opportunity like Midland, there's always elements that you look at in terms of potential efficiencies and different things that has capital power. We stand back and look at it and say, we may well be able to create an optimization here or there. But it's been a very well-run plant, and so there isn't -- there aren't glaring opportunities to fix things that are -- nothing is 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 the site beyond the recontracting that we've assumed, we've only attributed a couple of percent in value. So, 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, but an assessment of to what degree, at this point would be totally arbitrary.
Patrick Kenny
Okay. 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?
Brian Vaasjo
So we do expect a significant amount of progress through the back half of the year, particularly on the contract with 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 is likely going to be the one element that holds up progress, not just with us, but across anyone looking at CCUS.
Patrick Kenny
Okay. And 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.
So just wondering if you can reconcile 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?
Sandra Haskins
Yes, 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. 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.
Operator
The next question comes from Mark Jarvi with CIBC Capital Markets.
Mark Jarvi
Brian, on the carbon capture and the investment tax credit. I know some of -- there's some language around the use for post combustion and whether or not it's new compliance needs. Just updated views in terms of how you see that playing on eligibility, but maybe the framework for -- to your equivalency? And then it's a federal path on carbon or emission standards going forward. So just maybe your updated views on your ability to get that tax credit.
Brian Vaasjo
So, definitely see that we are fully eligible for that tax credit in terms of -- there is a little bit of discussion as to what might be a level of capture that one might have to meet in order to be eligible, and also 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 economically well beyond 2035. So, for us, the actual proposed regulations and discussions are actually dovetailing to -- definitely to our -- the favor of our CCUS project.
Mark Jarvi
And then, Sandra, maybe updated views in terms of other sources of funding in the debt market, cash market. You obviously talked about early in the call the appetite for more capital deployment. Just -- how do you see those markets right now? Could you be able to access them right now? Does that give you any pause for the market volatility to settle down?
Sandra Haskins
So yes, 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 under -- 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, I 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 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.
Mark Jarvi
Okay. And then just last one for me, just on Goreway. You mentioned in the sort of slides about some upside you're seeing there. If the market is tight, as you expect it to be in Ontario, how big of an impact that is that for Goreway either into your gas assets, on the existing contracts? And then, I guess, how has Goreway done relative to your sort of base case underwriting scenario when you guys acquired the asset a couple of years ago?
Brian Vaasjo
So starting with the last question first. Goreway has done very well relative to our expectation. And today, as you're seeing in our results, it's being dispatched more, which illustrates its value to the IESO 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 -- therefore seeing a shortage of 2,500 megawatts by 2025, that the IESO 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 2 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 Goreway and York are. So, we see significant opportunities at all our 3 sites, and have been actively pursuing them. In fact, we started the environmental process for permitting different alternatives back this spring, is a very real opportunity for us, and we're pursuing it very vigorously.
Operator
The next question comes from Maurice Choy with RBC Capital Markets.
Maurice Choy
My first question is about capital allocation. And I believe on 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 target. So, I guess with the upgrade to 6% dividend growth, could you just refresh us on the view of how you plan to allocate what obviously appears to be solid excess free cash flows, moving forward?
Sandra Haskins
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 too, 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, feel that the capital allocation that we've targeted right now, is on appropriate level.
Maurice Choy
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 2-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?
Brian Vaasjo
So, I think there's still a little bit of churn in the market taking place. 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.
Operator
The next question comes from John Mould with TD Securities.
John Mould
Maybe just going back to the clean electricity regulations. In the context of potential Canadian gas acquisitions, you noted the federal government has recently given us some more details on what that structure could look like. How does this update inform your willingness to look at acquisitions of more midlife gas assets, specifically in Canada where policy is specifically targeting carbon emissions look like they'll be much stronger than in the U.S.? 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?
Brian Vaasjo
So, I think just naturally -- with a number of natural gas assets in the U.S. versus Canada, there'll 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 then 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 interior 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 5 years or 10 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.
John Mould
And then 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 on gas by the end of next year?
Sandra Haskins
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.
Operator
And the next question comes from Ben Pham with BMO.
Ben Pham
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 in the middle part of the decade?
Brian Vaasjo
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 the initial discussions and where it seems to be going, you would see potentially slightly softer power prices as we move forward, but wouldn't dramatically change the expectations, or certainly not the forward curve in the short run.
But in the longer run, it would be signaling slightly more moderate power cost. 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.
Ben Pham
Okay. And do you still expect -- and maybe linked to that, just maybe where my question is going. Do you expect a flood of supply? It's just a long queue of gas plants, because it looks like the CES is looking at the new units. How you defined it -- I mean [ indiscernible ] gas plants are coming in the '25-'26 timeframe?
Brian Vaasjo
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. I mean what's clear in the regulations is that, anything completed after 2025 would end up facing a relatively significant environmental implications starting in 2035. So, a relatively short economic life. Don't see the window of opportunity being big enough for, again, a significant number of facilities coming into Alberta.
Ben Pham
Okay. And maybe my last one, switching to Island generation. You highlighted the EBITDA impact. Is that from -- I just want to clarify, is that some an accounting change impact? Or is that the impact from the recontracting?
Sandra Haskins
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 level -- book -- sorry, the book value of that plant. So, when we -- and 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.
Ben Pham
Okay. And you have a benefit of lease liabilities wrong [indiscernible]
Sandra Haskins
That's right.
Ben Pham
Is that right?
Sandra Haskins
So, you set up your lease receivable and it runs off over the 4.5 years of the contract term.
Operator
The next question comes from Andrew Kuske with Credit Suisse.
Andrew Kuske
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?
Brian Vaasjo
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 2 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. There's significant coal retirements that will be taking place. There's -- just recently, it was a [nuclear] retirement, and we expect further nuclear retirements. So, there's a significant increase or decrease in supply that will be taking place, increasing demand in general. And we've got a site in 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, even natural gas swapping opportunities with Ontario as its position. So, I mean, we just see a tremendous amount of capability there.
Andrew Kuske
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 effectively assets generating power, and Alberta, if we just think of like those 3 major areas?
Brian Vaasjo
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.
So, you're quite right. We'll certainly see 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 -- our longer-term view, allocate capital to those regions. What we end up doing more is allocating resources looking at opportunities in regions. So, 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.
Operator
The next question comes from Naji Baydoun with IA Capital Markets.
Naji Baydoun
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?
Brian Vaasjo
So, when we look at the assets specifically, it is true that it is an ageing asset. But certainly, we see opportunities there, a, from a footprint perspective and potentially adding generation, but there's also -- there's different levels of [coal] 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 natural gas access position on the grid, et cetera. And again, we see that as being very, very favorable at that site.
Naji Baydoun
Okay. And just, I guess, similar to this wood Midland, you're going to be adding some management fees into revenue or cash flow streams. Do you see other opportunities to go after those same types of revenues that arguably maybe are lower risk, more asset-light and something that you could replicate in other -- with other facilities?
Brian Vaasjo
So, we could see certainly through partnership structures and so on, work from that perspective. If you're thinking of, would we go and operate without 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, simply operate assets for fees.
Naji Baydoun
Okay. And maybe just to clarify, when you say -- I know ownership's taken an asset, is there a minimum threshold? Is that to be majority stake or even on a minority basis?
Brian Vaasjo
I think we'd consider it on a minority basis. It all depends on the partners and the structuring and what that reflects. But certainly, something like a 25% interest in a significant asset would be -- 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, you'd be -- we'd have to be having an investment opportunity of a couple of hundred million before we'd look at something like that.
Operator
This concludes the question-answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.
Randy Mah
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.
Operator
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.
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Capital Power Corporation (CPXWF) CEO Brian Vaasjo on Q2 2022 Results - Earnings Call Transcript