Capital Power Corp

TSX:CPX

Earnings Call Transcript 2022-Q3

[Operator]

Thank you for standing by. This is the conference operator. Welcome to Capital Power's Third Quarter 2022 Results Conference Call. [Operator Instructions]

I will now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead.

[Randy Mah, executive]

Good morning, and thank you for joining us today to review Capital Power's Third Quarter 2022 Results, which we released earlier this morning. Our third 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 the [ generous ] GAAP measures can be found in our third quarter 2022 MD&A.

I will now turn the call over to Brian for his remarks starting on Slide 4.

[Brian Vaasjo, executive]

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 the 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 as the lands on which we live and work. Overall, our third-quarter results were strong, and we set a record quarter for adjusted EBITDA. We had strong operational performance with a 96% average availability that enabled a 15% increase in generation compared to a year ago. On the strength of Alberta power prices that averaged $221 per megawatt hour in the quarter, our Alberta commercial facilities generated strong results. Outside of Alberta, our Goreway facility in Ontario and Decatur in Alabama also delivered strong results with double-digit percentage increases in adjusted EBITDA in the third quarter.

At the end of September, we closed the acquisition of the Midland Cogen facility. We've executed a partnership and management services agreement with our joint venture partner, Manulife Investment Management. Capital Power is responsible for the operations and maintenance and asset management of the Midland Cogen facility. Work continues to integrate Midland into our commercial portfolio and transition operational and business systems interfaces into our networks. We are forecasting $35 million plus in adjusted EBITDA for Q4 of this year. Although the in-service date for a Genesee 1 has been revised from late 2023 to 2024 due to delays in the interconnection. The overall project continues to progress well, and we remain on track to be off-coal in 2023. Feed study activities for the Genesee CCUS project continues and moving forward as expected. We continue to pursue other growth opportunities, including in Ontario, where we are very optimistic with the competitiveness of our 3 natural gas facilities. I look forward to sharing more details on our growth opportunities at our upcoming Investor Day.

Turning to Slide 5. Recently, there have been numerous favorable policy announcements that are a continuation of supportive market dynamics for our strategy. Alberta Environment and Parks initiated consultations on potential changes to the TIER framework that Alberta expects will maintain equivalency with the Federal backstop framework and preserve provincial jurisdiction over carbon pricing. It includes the proposal to commit Alberta to adopt the federal Alberta price schedule through 2030, introducing a 2% year reduction in the electricity stringency from 0.37 tonnes per megawatt hour performance standard until 2030. The AEP is targeting to finalize the recommendation by fall of 2022 and have the enabling regulations completed by December 31, 2022. Overall, we are supportive of the proposed changes by AEP. The AESO has initiated consultation on potential changes to the current MSSC limit of 466 megawatts.

The current limit impacts the Genesee refilling project at each combined cycle unit would exceed the current level. However, battery storage could alleviate many constraints the existing MSSC limit may present. We are supportive of AESO increasing this limit. The U.S. Inflation Reduction Act enacted in August is the most significant legislation to invest in clean energy and address climate change in the U.S. history. It includes an extension of PTCs and ITCs until the end of 2024. Where most forms of renewable energy, including energy storage technology.

Overall, the [ IRE ] provides strong support for our renewable asset growth plans in the United States. In Ontario, the Ministry of Environment, Conservation and Parks, issued proposed changes to the emissions performance standard program for 2023 to 2030. It includes a proposal to change the performance standard from 0.37 to 0.31 tons of CO2 per megawatt hour starting in 2023 and remain constant until 2030. For our Ontario natural gas facilities, there are contract provisions that will limit the impact of proposed EPS benchmark changes to Capital Power.

I'll now turn it over to Sandra.

[Sandra Haskins, executive]

Thanks, Brian. Starting on Slide 6, I'll briefly comment on our inaugural green hybrid bond issuance that we completed in September. It was a successful $350 million offering that replaced our Series 7 and 9 preferred shares. The notes have an initial interest rate reset in September of 2032 and every 5 years thereafter and has a 60-year term maturing in September 2082. The green hybrid bond provides cost-effective financing relative to the preferred shares with economic savings of approximately $5 million per year on an after-tax basis for the initial 10 years compared to the reset rates of the preferred shares.

Prior to the bond offering, we entered into interest rate swap hedges on the underlying. With the positive mark-to-market settlement of the hedges, the effective interest rate on the bond is approximately 6.7%, which is 125 basis points below the coupon rate of 7.95. This green hybrid bond, the first of its kind issued in the Canadian marketplace was issued under our green financing framework, where the net proceeds of the offering will be used to finance or refinance new or existing eligible green investments.

Turning to Slide 7. I'll touch on the financial highlights for the third quarter. We saw a continuation of strong company-wide performance that led to the financial results exceeding our expectations. Alberta power prices averaged $221 per megawatt hour in the third quarter, where the strong price was driven by competitive bidding behaviors on seasonally hot weather and outages from natural gas units and tie-lines. We generated adjusted EBITDA of $383 million, which benefited from higher generation and favorable spark spreads from the Canadian commercial facilities with a realized power price of $101 per megawatt hour compared to $75 a megawatt hour a year ago. In Ontario, Goreway had a 59% increase in generation as it was dispatched more frequently to supplement the supply shortage driven by nuclear refurbishment and other outages, combined with warmer temperatures.

Our Decatur facility also contributed to strong financial performance from significantly higher generation compared to a year ago due to higher availability and increased demand. In addition, Decatur recorded higher incentive payments given improvements in the facilities heat rate with the upgrades that were completed last year, along with terms of the extended tolling arrangement announced in 2021. And corporate expenses of $19 million this quarter were higher than past quarters primarily due to higher business development activity and increased share-based incentive expense. We reported AFFO of $328 million in the quarter, up 59% from a year ago, attributable to the factors mentioned above and favorable finance expense. This was partially offset by higher current income tax expense driven by the cash tax impact from prior year's results. Overall, we saw significant year-over-year increases in AFFO and adjusted EBITDA from higher generation and strong Alberta power prices.

On Slide 8, I'll review our year-to-date financial performance where the drivers of the 9-month outperformance are similar to the third-quarter commentary. Adjusted EBITDA of $1.05 billion was up 27% and benefited from higher generation across the fleet and stronger Alberta power prices that averaged $145 per megawatt hour. We have generated $708 million in AFFO year-to-date, up 55% from a year ago. Overall, we saw double-digit percentage increases in all key financial metrics.

Turning to Slide 9. I'll touch on our Alberta power and natural gas hedge position. For 2023, we are 72% hedged in the low $70 per megawatt-hour range. For 2024, we are 55% hedged in the low $60 per megawatt-hour range. And for 2025, we are 36% hedged in the low $60 range. This compares to forward prices of $114, $82, and $76 per megawatt hour for 2023 to 2025 respectively. The update from Q2 reflects both additional hedging activity during the quarter, where we took the opportunity to sell forward additional power length at favorable prices as well as updated expectations with respect to baseload generation.

Overall, our long-term hedging program continues to provide a strong balance between managing commodity exposure while providing flexibility to capture upside from higher power prices and price volatility. Our exposure to rising natural gas prices for the Alberta fleet has been effectively hedged in the short term. Our expected natural gas burn is over 80% hedged for 2023, over 70% in 2024 and over 50% hedged in 2025. Our average hedge price is between $1.50 to $2 per GJ in 2023 and 2024 and between $2.50 and $3 per GJ in 2025. This compares favorably to the higher forward gas prices at the end of the third quarter.

Moving to Slide 10. The chart shows our expected annual Alberta carbon cost compliance obligations from 2022 to 2024. The dark shaded area on the bar represents the Alberta emission expense, while the lighter shade is the savings from using carbon offsets. With higher than forecast generation in 2022, the change in the Genesee repowering schedule and the expected increase in stringency under Alberta's TIER beginning in 2023, overall compliance obligations have increased since the beginning of the year. Management has optimized the available carbon emission credit inventory from 2022 to 2024 to align with the expected increase in TIER stringency requirements with carbon compliance price increases. The impact is a reduction in adjusted EBITDA and AFFO in 2022 of approximately $50 million. However, the optimization results in an estimated net savings of more than $7 million over the 3 years.

On Slide 11, I'll cover our year-to-date performance and highlight the changes to our 2022 targets. After 9 months, average facility availability was 94%, slightly higher than the full-year target of 93%. Sustaining CapEx was $75 million year-to-date compared to the original annual target of $105 million to $115 million. We have revised the target to $130 million to $140 million due to higher LTSA costs from increased generation and spend on shutdown work as well as an additional sustaining CapEx for the Midland Cogen facility.

We have also increased our 2022 financial guidance ranges that are driven by higher year-to-date results, the acquisition of Midland Cogen and our outlook for the remainder of the year, including the optimization of the Alberta offset credits inventory that I previously discussed. This results in a 16% increase to adjusted EBITDA based on the midpoint of the guidance ranges. The revised guidance range is $1.3 billion to $1.345 billion. As we start looking ahead into 2023, the current forward prices would project adjusted EBITDA to be generally in line with our revised 2022 guidance. More information about our 2023 financial targets will be shared at our coming Investor Day.

Lastly, I'll review our updated AFFO guidance, as shown on Slide 12. Year-to-date, we have generated $708 million in AFFO. We have revised our annual guidance range to $770 million to $810 million, which represents a 31% increase when comparing the midpoint to our original guidance. We have provided a chart to illustrate the main drivers between the higher revised AFFO guidance. Overall, we expect operational performance to once again be very strong in the fourth quarter with adjusted EBITDA in line with Q4 2021 prior to the increase in carbon compliance costs discussed on Slide 10. Our guidance, therefore, has been revised to $770 million to $810 million, which also includes higher sustaining CapEx in the fourth quarter.

I'll now turn the call back to Randy.

[Randy Mah, executive]

Okay. Thanks, Sandra. Operator, we're ready to start the Q&A.

[Operator]

[Operator Instructions] The first question comes from David Quezada with Raymond James.

[David Quezada, analyst]

Congrats on the really strong results. Maybe my first question, Brian, I wonder if you have any updated comments or thoughts around capital allocation or any freedom, the strong profitability that you've shown so far this year gives you.

[Brian Vaasjo, executive]

Well, obviously, with the strong results and increasingly strong results and the strong results we had last year, all contributing to a pretty strong balance sheet and allowing us to move forward with capital commitments that we otherwise would have been a little bit more concerned about in terms of capital allocation. As we look forward, we do see, as you know, a number of projects that are -- have very high potential, CCUS being one of them as well as the various renewable projects that we have in play. We do see that we have adequate capital to pretty much cover what we're looking at today, as we've said before, any new initiatives that we have likely will require additional equity capital from the markets. But as always, we look for the best opportunities for Capital Power shareholders and not really driven to one particular either form of generation or one particular type of market. We're in a very good position today to, again, look for the best opportunities for the company.

[David Quezada, analyst]

Excellent. Maybe just one more for me and it relates to your natural gas generation footprint. Obviously, now that you've close the Midland acquisition. I'm just curious if you have any thoughts you can provide on the opportunities that you can get around having a fleet of gas power plants in multiple regions. Are there any efficiencies or opportunities that provides?

[Brian Vaasjo, executive]

Well, certainly, there's -- there are learnings and as you have a larger and larger fleet, your knowledge becomes greater and greater. You have greater flexibility and bargaining power, so to speak, with OEMs. So we're certainly seeing those positive attributes coming into play. But in addition to that, although a number of our assets may seem to be in different regions, we see definitely the Midland facility playing fairly heavily into different opportunities in Ontario, particularly on the natural gas side. When you think of the transportation storage, et cetera, of natural gas between -- I'll call it our 4 facilities in that region. We see some very, very positive implication. Even looking longer term for carbon mitigation strategies on either side of the border, we think those assets will work together very, very well in our portfolio. So we're seeing a tremendous amount of benefits of having, again, a number of natural gas facilities in a region, similar to what we have operating in Alberta.

[Operator]

The next question comes from Rob Hope with Scotiabank.

[Robert Hope, analyst]

First question is just on the change in timing on the Genesee unit there with the transmission delay. Can you give us a little bit more color on what drove that as well as when in 2024, you could see Genesee return to service? And does that change the interim generation plan at all?

[Brian Vaasjo, executive]

So what – the delay is being driven by the timing on the interconnection. And the importance of the interconnection is that signals the availability of energy for commissioning associated with the facility. So that's the primary driver behind that. And again, as that interconnection is turning out to have a bit more of a problem character to it. It has caused a delay in the project. Now in terms of the actual timing, you may recall that there's actually 4 CODs associated with that activity. The combined cycle being the later ones, and the original schedule had the combined cycle – 1 combined cycle completed in 2023 and the other one in early 2024. The impact is to move those later into 2024 while the initial 400 megawatts a unit will be in place through 2023. So not a lot of impact at all on 2023, and there will be some timing implications for 2024. The precise timing and outages, et cetera, associated with moving to combined cycle is still under investigation, and we should have some additional information for you on Investor Day.

[Robert Hope, analyst]

All right. And then maybe just as a [ pretty poor ] Investor Day. As we take a look at 2024, the initial outlook for -- sorry, as we look out to 2023 guidance of being flat with 2022, can you maybe just walk us through the main drivers there? I'm imagining Midland is a key driver upwards and then based on the numbers, it does look like you continue to assume very strong utilization of the Alberta merchant plants and good revenue capture there.

[Sandra Haskins, executive]

Yes. So we'll certainly have more details when we come into Investor Day on December 1st, but you're correct. A big driver of the results next year is a continuation of forward prices in Alberta as well as the full year from Midland and a full year from Enchant Solar little COD at the end of this year. So those would be the key drivers, but more details to come in a month's time.

[Operator]

The next question comes from John Mould with TD Securities.

[John Mould, analyst]

Maybe going to the CCUS initiative and the question of carbon pricing certainly there, and there's been lots of talk about carbon contracts are different, but also about perhaps a need to further augment the existing legislative support for CCUS, given what's being offered in the U.S. Are you still thinking that this broader question as it pertains to your initiative can be resolved by late 2022 or maybe early 2023? And what structure for carbon pricing certainty is looking more likely right now from your perspective?

[Brian Vaasjo, executive]

So in terms of broad timing, we do in conversations with the government do believe that they are working on it and have strategies and processes in place to move forward and basically provide support around the carbon pricing. What we have said and what seems to be gaining traction is the utilization of something like a CCFD contract for differences associated with the carbon price for a longer period of time. Our understanding and point of reference in a conference last – or week before last, the Prime Minister and 2 ministers all refer to the CCMD. So believe that's absolutely the track that they're on. We are hopeful that we'll see more information and more indication of the federal government direction in the fall economic update. So more to come, but we're seeing everything continuing to be on track and being very positive.

[John Mould, analyst]

Okay. Great. And then maybe just moving on the ISO procurement. And given it's competitive, I appreciate you won't want to talk too much about your bidding plans, but more high level, are you expecting that 1.5-gigawatt gas cap is going to be reached just given the system situation? And do you see more opportunity for Capital Power on the hybrid gas storage solutions side of things or more from a pure gas perspective, such as up rates or new units at your existing sites? What insights can you give on how you're thinking about that procurement?

[Brian Vaasjo, executive]

So what -- how we're actually looking at it is that what we'll endeavor to do and what we've been talking about so far is to actually provide the ISO choices. We see natural gas opportunities and battery opportunities or – battery opportunities at every site, and we see natural gas opportunities at 2 sites were a significant increase in generation. And then we see upgrades potentially across all 3 sites. So there's a lot of options. And I think the real issue will be which of these options fits with the ISO strategy is what's optimal for the various regions and the capacity requirements they have. So that's the approach that we're taking. But we're very optimistic that between the flexibility and the competitiveness of our sites. And our sites being in those regions that require increasing capacity, we're feeling pretty optimistic about our chances even though it is in a competitive situation, but we're positioned extremely well from that perspective.

[John Mould, analyst]

Okay. Great. And maybe just one housekeeping question on [ Jaffrey ]. Just from what seems to be happening in the grid so far. In October, it looks like there hasn't been a lot of sales into the grid so far. Just can you provide any insights on how that asset is performing so far on the quarter?

[Brian Vaasjo, executive]

So we'll have to get back to you on that. They did have an outage that was there and was extended. But in any event, we'll get back to you with some more detail on it.

[Operator]

The next question comes from Mark Jarvi with CIBC Capital Markets.

[Mark Jarvi, analyst]

Brian, you brought up the TIER review and obviously, the stringency standards is a big item. But what else is there in the TIER framework and review and consultations that are a real focus for you and things that might change potentially?

[Brian Vaasjo, executive]

So in terms of the TIER review, as you can appreciate it, it's -- there's a lot of different elements and different moving pieces that could happen. But the focus so far and the exclusive focus has been around those 2 issues as it relates to Capital Power. So we're not seeing that there's other issues actually on the table at this point. But again, it is a complex negotiation and certainly looking to drive a significant reduction in emissions in Alberta. So again, from that capital power and power generation perspective, it's looking very favorably. And there isn't something else, again, in play that impacts on us today.

[Mark Jarvi, analyst]

And just a follow-up. When are you expecting clarity on that?

[Brian Vaasjo, executive]

We're expecting clarity over the next month or so directionally, but the Alberta government is focused on having it actually in place by the end of this year.

[Mark Jarvi, analyst]

Okay. And then if we just look at the hedging, I'm not sure if this is for Sandra or someone else. But you've increased some of your hedges for 2024, but the price really hasn't moved up yet forward half. Can you maybe reconcile those 2 items? Is that implying that you think the $82 [ forwards ] you've shown in the presentation is maybe a little lofty or maybe just some commentary on that?

[Sandra Haskins, executive]

Yes. So when you look at the hedges that we've stepped into since the last update, they are well above our average contract price. So we're seeing that the new hedges are at a higher level, which would be consistent with our view. But the percentage hedge is also driven by the expectation around generation, which has been tempered a little bit as well. So that's also driving up your hedge position from a percentage perspective. So we do view prices to be more in line with the forwards as opposed to below.

[Mark Jarvi, analyst]

Okay. And then can you just clarify again that comment about the generation levels? When you look at '22 and then '23, '24 as Genesee goes through its evolution here, can you clarify what baseload looks like in terms of generation assumptions?

[Sandra Haskins, executive]

Yes. So we do expect that our baseload plants will still be generating at high levels. But overall, the capacity factors are somewhat below what we had used in a previous forecast. So it's not a material change, but it does drive that ratio to some extent.

[Mark Jarvi, analyst]

Those reductions -- yes, sorry about that. Go ahead.

[Sandra Haskins, executive]

At Investor Day, we'll have our most recent view, which will be refined through our budget process here that will realign those to our most current thinking around our production levels and our hedge position.

[Mark Jarvi, analyst]

Okay. And just one last follow-up just on the Genesee Unit 1. In terms of the delay, was that 1 to 2 months or 4 to 6? I'm not sure what -- how long this delay in the combined cycle unit would be for at least for Genesee 1.

[Brian Vaasjo, executive]

It's more in the order of 4 or 5 months.

[Operator]

The next question comes from Maurice Choy with RBC Capital Markets.

[Maurice Choy, analyst]

My first question is to follow up on the capital allocation comment you made, Brian. You said that you have adequate capital for what you're looking at today, but you also said that anything you will require capital. Now obviously, you're clearly looking at CCUS right now. But just to clarify, where does CCUS fall within these 2 buckets? Do you need capital for that or not? Or does it depend on what the ITC and CFDs look like from the federal government and how cash flow looks like next year?

[Brian Vaasjo, executive]

So that was just around CCUS as a broad comment about the kinds of projects that we see coming forward. In respect of the CCUS itself, I actually don't see a lot of capital being deployed in that direction next year. We're looking at a final investment decision around next summer. And based on that, again, we see some capital being deployed next year. But certainly, none that would be requiring any equity capital. We could definitely deal with that within the scope of our existing balance sheet. My comment was more along the lines of trying to suggest, which obviously, I missed the mark -- was that from time to time, as we've evolved, there are times when we're actually very focused on either natural gas or very focused on renewables or long-term contracts a position where we're sitting right now, we have the luxury that we're not -- we don't have a favored nature of investment. We can look for the one that provides the greatest value to shareholders and stakeholders.

[Maurice Choy, analyst]

Understood. So just to clarify, your comment about having sufficient capital that relates to the 2023 limited capital that you put for CCUS and if and when you do FID on that, you'll tackle that again?

[Brian Vaasjo, executive]

That's correct.

[Maurice Choy, analyst]

Perfect. And second question and just a follow-up on the opportunities [ with CCUS ] with regards to the U.S. IRA. Can you talk a little bit more about your pipeline of opportunities there? And with regards to that, do you see a need to acquire renewable platforms that come with development projects?

[Brian Vaasjo, executive]

No, we don't see a need to be acquiring platforms. We're pretty pleased with both the resources we have in the U.S., which we are expanding and the sites that we have in place that will have definitely, it represents a tremendous platform for growth. And that doesn't mean that we won't be acquiring sites or looking at sites. But it's a pretty competitive market out there and the degree to which you acquire sites that are either complete or getting close to moving forward in terms of having, say, a contract, et cetera, a lot of the value is going into other people. The best thing that we can do is being -- is developing sites as early as practical and creating greater and greater shareholder value. And that's with the position we have now in the U.S., in particular, it provides a, as I say, a great opportunity for growth over the next number of years.

[Operator]

The next question comes from Ben Pham with BMO.

[Benjamin Pham, analyst]

I'm wondering on the Genesee 1 or 2 units and maybe 3. What's the max percentage of gas you can burn on those units? Is it 30% to 50%? Maybe just a quick reminder on that.

[Sandra Haskins, executive]

Yes. So while they're still on coal, it's about 25% of their generation that they can burn natural gas. With G3, it's actually going through its outage now where it will be converting to be 100% natural gas going forward.

[Benjamin Pham, analyst]

Okay. And I know this -- I know you said unit 1, it's pushed to 2024. Is Unit 2, is that still a late '24 in service?

[Sandra Haskins, executive]

No, it's earlier '24.

[Benjamin Pham, analyst]

So you're going to put both of them? Okay. So unit 1 is delayed, but unit 2 is now earlier.

[Sandra Haskins, executive]

That's right. It used to be late 2023 for 1 unit and the other one was early '24. As Brian mentioned, those have shifted about 4 to 5 months, so for unit 1. So they're both expected to hit combined cycle in 2024 but in the early part.

[Benjamin Pham, analyst]

Okay. I got you. And then maybe more of a housekeeping. I'm looking at your slide on the emissions expense for ‘23 in particular. I noticed that's actually up quite a bit since your last presentation. It looks like it's doubled to $300 million. It just seems like such a big number given some of the factors that you pulled into 2023.

[Sandra Haskins, executive]

Sorry, for 2023 or 2022, are you looking at?

[Benjamin Pham, analyst]

This is 2023. The Alberta emissions expense, it's $300 million right now. I think that's what I've seen in your slide, and you look at your last presentation, it was only 150. It just seems like a big change of expense with a 4- to 5-month timing change on Gen 1.

[Sandra Haskins, executive]

So a couple of things. Yes, there is the timing change. There's also the expectation around higher generation as we've seen coming through 2022. Our units are running a fair bit more than had been expected. So we do expect that next year with where we are in the merit order that will run more baked into that as well as the expectation of a reduction in the stringency under TIER that could come into effect in 2023. So that has been included as well, and that drives up your carbon compliance obligation as well. The offset, of course, to that would be that we would see an increase in carbon -- or sorry, in power prices as well. And as we know with our units as power prices reflect higher cost of carbon being more efficient units, it ends up being a net benefit. Also in there is just with the delay in Genesee 1 and 2, we will be burning more coal for part of 2023 relative to our initial forecast as the repowering is pushed out a bit, and that would be part of that increase as well that you're seeing for 2023.

[Operator]

The next question comes from Naji Baydoun with iA Capital Markets.

[Naji Baydoun, analyst]

Just wanted to start on the growth outlook. You talked a bit about the Ontario market. Just wondering if you can give us an update on the pipeline of solar prospects you acquired last year. I think the plan was trying to move some of those projects forward maybe in the next few years. Maybe just an update on that, how that's progressing.

[Sandra Haskins, executive]

So our view continues to be the same, and we are moving a number of those projects forward. We have a number of opportunities that are, I'll say, in process. And I think in our last call, I suggested that we were looking to potentially have something move forward or announce something this year. Likely that right now is a little bit optimistic, not that any of those opportunities have fallen off the table, it's more that they're just simply taking a little bit longer. So actually quite bullish on the development pipeline and what we'll bring to fruition over the next little while.

[Naji Baydoun, analyst]

Okay. Got it. So just a question of timing, that's helpful. And then I just wanted to maybe get your updated thoughts on power prices and your hedging strategies. It's been a very strong couple of years in the Alberta market, where maybe it's paid to be a bit more dynamic on the hedging side. Do you think it still makes sense to maybe be a bit less hedge short term as prices are still high? Just wondering if the changes your ports to the hedging strategy at all.

[Sandra Haskins, executive]

Yes. We consistently take a view on where we think prices will be and hedge around our expectations. But what we've seen in 2022 is very high power prices. We think that as you look into the early part of 2023, you're going to see the same fundamentals in the market. But as the year progresses, the expectation is around supply additions and over -- that will start the movement towards supply-demand balance that we'll see over the next 18 months following that, where you've got Cascade as well as our repowering units coming online as well as the number of renewables. So expect that you'll see prices come down from this high watermark starting sometime in the back half of next year, but continue to see a lot of volatility. We have a fair bit of baseload length. So our view is that we derisk the portfolio by stepping into hedges and have that stability and derisk, but still have about 500 megawatts in peaking facilities or non-baseload plants that capture that upside. So that would be our approach to managing the portfolio.

[Operator]

The next question comes from Andrew Kuske with Crédit Suisse.

[Andrew Kuske, analyst]

Maybe if you just give us some high-level context on your thoughts of natural gas plant valuations in the U.S. And I asked the question in part with all the attention that the IRA gives for renewables, do you see a market developing or maybe becoming more enhanced for natural gas plants that you've historically gone after, whether it be Decatur, Arlington and so on and so forth?

[Brian Vaasjo, executive]

So our view is that those obviously were very sound investments. And actually, as time is playing out, they are exceeding our expectations in terms of value. And a large part of that, Andrew, which is I think it goes to the focus of your question is the increasing view and perception that -- and I'll say reality that natural gas is -- continues to be a very critical fuel in North America and will continue to be necessary depending on the region in significant amounts for a considerable period of time. You see that unfolding in Ontario right now where there's a need for natural gas. And we can see potentially some new natural gas facilities being contracted out to 2040.

You're seeing the federal government in Canada, having an evolving view from a few years ago where natural gas was not good to a point where the focus is on emissions and a belief that -- and a clear belief that natural gas is going to be around for, again, a considerable period of time. And again, very similar in the U.S. with the administration -- by the administration is stating again. Their focus is not on eliminating natural gas. Their focus is on eliminating emissions. And so you're seeing that narrative, resulting in, I would say, increasing values around natural gas, both in terms of long-term contracted natural gas and in terms of merchant natural gas, again, very dependent on the market and very dependent on how your assets are situated in that market. So it's where we were facing headwinds from a natural gas perspective. Now a few years ago, the wind tends to be at our back now.

[Andrew Kuske, analyst]

That's helpful color and context. And maybe just looking across your portfolio of natural gas assets. Do you have selected opportunities to effectively enhance some of the positioning from a market standpoint, whether it be with supplementary solar battery technologies, whatever the case may be around specific plants that could drive maybe even more value and really benefit more directly from IRA in the U.S.?

[Brian Vaasjo, executive]

So around the specific sites, we do see some opportunities. We have looked from -- and are looking at the potential of batteries on some of the existing wind and natural gas facilities. Obviously, we look at batteries. There's existing opportunities today in Arizona and with our Arlington facility to add capacity without having to go through an approval process from a contract perspective. So there's a tremendous amount of upside there. But the other thing as things develop and as we're seeing the landscape, again, a number of the sites that I was referring to earlier are very, very well positioned to actually not only have deployment of either at – or either solar or wind, but also the deployment of batteries as well.

So the combination of these things come into play quite well. And I think one of the things where we have some concentration like Alberta, and we see some possibility in Arizona. Again, maybe striking a bit to the heart of your question, we can see where we can provide a complete package, not only just here or renewables that combination of batteries and renewables can lead you into maybe as much as 80% truly green power, but we've got the ability to back up the other 20%. But further to that, with the trading that we do with renewable attributes were able to synthesize basically 100% clean products. So there's a lot of moving pieces. And as we're looking at our opportunities, we're pulling on all levers to see where we can combine our assets and our knowledge and our sights to provide those kinds of opportunities. Again, with the Midland acquisition, we see some opportunities to combine with existing wind facilities plus new facilities as well to provide some of these kinds of opportunities.

[Operator]

[Operator Instructions] The next question comes from Patrick Kenny with National Bank Financial.

[Patrick Kenny, analyst]

I just wanted to clarify on the proposed changes to the 0.37 performance standard going down 2% per year, whether or not this could have any material impact on the economics for your CCUS investment. And maybe you can also provide a quick update on whether or not these inflationary pressures being experienced here year-to-date on construction in the province can still be absorbed within the initial $2 billion budget?

[Brian Vaasjo, executive]

So in terms of the 0.37, as we were putting together the business case, we were anticipating some significant drop in stringency. So that doesn't really impact on our business case, so to speak, or impact the economics from what we had anticipated. I'm sorry. And what was the second part of your question?

[Patrick Kenny, analyst]

Yes. Second part was just given the inflationary pressures that have been experienced, I guess, in the province.

[Brian Vaasjo, executive]

Right So we do expect that -- well, we are actually in the midst of a touch point on the CCUS project that will look at capital operating, where we are in the government. I think we've talked a number of times about looking to having unlimited notice to proceed sometime around the end of this year beginning of next year. So that will be a touch point, and then we will be addressing what a rebid view of capital costs are. There's a number of pluses and minus. And certainly, there will be inflationary impacts to take into consideration. But the other side of it is with a FEED study, they're actually looking at the design of the system. And so there's -- where you may see some inflationary pressures. You may also see where some changes to design parameters may well result in decreasing capital cost. So we're looking anxiously at what might be the net effect of some of these elements coming together.

[Patrick Kenny, analyst]

Okay. That's great. And then just given the record power prices in the quarter and the impact that's having on affordability, I guess in light of some recent comments by Premier Smith, just looking to reduce electricity costs for Albertans. I know the $999 price cap has been in the market forever. But do you see any political risk on the horizon for generators in the province as it relates to affordability and potential political interference and how the merchant market currently operates?

[Brian Vaasjo, executive]

So there's a couple of things to maybe point out just broadly politically. If you look at actual actions to -- in the short term to actually impact on consumer costs. We've seen both the NDP and the UCP under Premium Kenny and also even now under the new premier, what they've looked at is ways to actually reduce the cost to consumers without necessarily impacting on the wholesale market. And we'll be certainly that premium has voice concern and not any different concern than the prior government where she has historically had a strong view is around the regulated rate option, which if you impact on it, that is what directly impacts on the costs to consumers, the cost to voters who haven't hedged their power bills through retail offering. So we would speculate that and given a relatively short time frame than anything could get done that would be politically impactful, we would suspect that that's probably something that may well get done or a direction that they'll pursue.

[Patrick Kenny, analyst]

Got it. Okay. And then last one for me, if I could, just on the outlook for 2023. Obviously, the forward market for next year, that's a tailwind along with the carbon offsets being pushed out into next year as well. But just thinking longer term here, are there any other tailwinds that you might point out that could be considered a little bit more structural in nature, whether it's recent asset optimization initiatives or cost reduction achievements, such that your outlook for, say, run rate EBITDA and AFFO even beyond 2023 might also benefit?

[Sandra Haskins, executive]

Yes. So we continually look at how to commercially improve our assets year-over-year. There's a number of things we are looking at on the cost side across the organization through optimization -- sorry, artificial intelligence and automation that would help as well. But I don't think I can point to any one thing that would be material at this point, but we just continue to look for those small wins and the biggest piece is probably around what comes out of Ontario and looking at what we can do with those assets as part of the Ontario process are probably the biggest opportunity for us in the next couple of years.

[Operator]

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.

[Randy Mah, executive]

Okay. Thanks, Shari. Please mark your calendars for our Annual Investor Day event that we mentioned. It will be held on December 1st in Brampton, Ontario and will include a tour of our Goreway Power Station. Chris Benedetti, Managing Partner of the Sussex Strategy Group will be the guest luncheon speaker and will share his views on the outlook for Ontario. More information on the event, including registration details will be announced later this week. Thanks again for joining us 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.