Capital Power Corp

Good morning. And thank you for joining us today to review Capital Power's second quarter 2021 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 on the call 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 and take your questions. Before we start, I would like to remind everyone that certain statements about future events made on this 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 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 compliment 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 2021 MD&A.

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

Thanks, Randy. And good morning.

I'll start off with the highlights of the second quarter and comment on our 2021 outlook. We delivered strong second quarter results that significantly exceeded our expectations, largely driven by our performance in Alberta, where the Alberta power market continues to be robust with a positive outlook.

Accordingly, we've updated our 2021 financial guidance which ranges above the top end of our original targets for adjusted EBITDA and AFFO. Despite the impacts from the Genesee to forced outage that started in mid-July, that I'll comment on shortly.

In line with our dividend growth guidance, we've announced an approximate 7% dividend increase that is effective with the third quarter of 2021 dividend. We also continue to make solid progress on our approximately $1.7 billion in growth projects.

As part of our goal to be net carbon neutral by 2050, we continue to advance our CO2 reduction initiatives. This includes carbon capture and storage at Genesee, where there is significant government support and the development is going very well.

With the Genesee carbon conversion center, we continue to investigate the commercial opportunities for carbon nanotubes and board approval for the project facility is expected later this year. Turning to slide five, Genesee 2 experienced the forced outage in mid-July caused by a generator failure.

The others is expected to last six weeks, with return to operations anticipate in the third quarter of this year. We plan to utilize our Clover Bar peaking facility to partially mitigate the Genesee 2 impact.

The three-week planned outage for Genesee is scheduled for October will be advanced and completed during this outage. Moving to Slide 6.

This chart shows our solid track record of dividend growth with eight consecutive years of dividend increases averaging 7% per year. As mentioned, we've increased the common share dividend by approximately 7% to $2.19 per year or $2.19 per year starting in the third quarter.

We're also maintaining our dividend guidance for a 5% annual increase in 2022. As you can see the AFFO payout ratio continues to track below our long-term payout targets 45% to 55%.

Turning to Slide 7, last month BC Hydro released its draft integrated resource plan. In that draft IRP as stated that BC Hydro is not currently intending to renew the long term electricity purchase agreement or Island Generation facility that expires in April of 2022.

We are actively participating in the IRP review process including retaining technical experts for familiar with BC Hydro's utility resource planning and transmission systems operations to support the review of the draft IRP. Comments are due at the end of this month with the final IRP expected to be filed by the end of this year.

We're also engaging with BC and local government officials and other stakeholders. We continue to believe Island Generation's dispatchable generation remains critical to the reliability of the BC system, particularly on Vancouver Island as again charmed by recent weather and system events.

With the current transmission difficulties, they're experiencing on Vancouver Island. Island Generation has been continuously dispatched since July 9.

I'll now turn the call over to Sandra.

Thanks, Brian. In the second quarter, we completed a successful equity offering of approximately 7.5 million common shares, including the overallotment that raised gross proceeds of $288 million.

Following the closing on June 2, share price rebounded from the issue price of $38.45 and is currently trading approximately 9% above the issue price. On the debt side, we executed a US$150 million private placement of 12-year senior notes.

The notes have a coupon rate of 3.24%, which with the inclusion of a forward starting flux settlements that was put in place for the issuance equates to an effective interest rate closer to 2.5%. 12-year notes demonstrate investors continued confidence in our long-term outlook.

Transaction is scheduled to fund in late October to better align with the cash flow profile of our growth projects. These also have recent affirmations of our investment grade credit ratings and stable outlook by both S&P and DBRS.

Earlier this month, we announced the closing of our inaugural $1 billion sustainability linked credit facilities or SLC. This involves amending our existing credit facilities, including a two-year extension to transition them into five-year SLC.

Pricing is in line with our pre COVID pricing grid. The FLCs are structured with one KPI tied to our CO2 emission intensity reduction targets of 65% by 2030 based on 2005 levels.

The agreements are structured such that foreign costs increase or decrease based on annual performance against the targets. These financings have reduced the financing risk of our capital program and the need for additional equity offering for current growth projects.

Turning to Slide 9, the Alberta power market continues to be very robust. Above average temperatures in June contributed to an average power price of $105 per megawatt hour in the second quarter that was 3.5 times higher than the $30 per megawatt hour in the second quarter of 2020.

In the second quarter, our trading desk captured an average realized price of $75 per megawatt hour or 42% higher than a year ago. Positive market outlook is reflected in forward prices of approximately $94 per megawatt hour for the last half of the year.

For our Alberta commercial portfolio, our baseload generation is 42% hedged in 2022, at an average contract price in the high $50 per megawatt hour range. 2023 and '24 were 30% and 15% hedged respectively, at an average contract price in the mid $50 per megawatt hour in both years.

This compares to current forward prices of $72 per megawatt hour for 2022 and $61 for 2023 and $52 in 2024. On Slide 10, I'll review our financial results for the quarter.

As Brian mentioned, financial results compared to budget significantly exceeded our expectations. Adjusted EBITDA was $241 million in the second quarter, up 11% from a year ago.

Increase was due to higher Alberta power prices that resulted in a 28% increase in adjusted EBITDA for the Alberta commercial segment. However, this increase was partially offset by the impacts of planned outages at our Decaturs and Arlington facilities in the U.S., lower wind resource at most of our wind facilities and a stronger Canadian dollar.

Due to seasonality, the second quarter is generally the lowest quarter for AFFO. This year we generated $91 million in the second quarter down 6% from a year ago as stronger plant performance was offset by $11 million of higher sustaining CapEx scheduled in Q2 2021.

And the Milner line loss AFFO impact of $7 million in the quarter. AFFO per share of $0.83 was down 10% from the second quarter of 2020.

Slide 11 shows our performance for the first six months. Adjusted EBITDA of $544 million was up 21% compared to $451 million for the same period in 2020.

The main driver for the increase with the higher Alberta power prices where our realized power price was $76 per megawatt hour compared to $58 a megawatt hour a year ago. Lowered corporate expenses also contributed to the higher adjusted EBITDA, mainly due to the acceleration of coal compensation revenue.

The FFO was $250 million, up 16% compared to $215 million a year ago. Higher plant performance from strong Alberta results were partially mitigated by higher sustaining CapEx in the first six months of 2021 and $13 million in Milner line loss ruling impacts to AFFO.

Overall, we're seeing strong performance in our key financial metrics in the first half of the year. I'll now turn the call back to Brian.

Thanks, Sandra. Turning to Slide 12, I'll review our performance for the first half of the year compared to 2021 targets.

For the first six months average availability was 90%, including outages at our Decatur, Arlington and Shepherd facilities. As mentioned, Genesee 2 is currently offline with a forced outage, but it's not expected to materially impact the 93% annual availability target as Genesee 2 had a major planned outage scheduled in the fourth quarter that will no longer be required.

Sustaining CapEx was $47 million in the first half of the year compared to the $80 million to $90 million annual target. Based on our current outlook, we've increased our adjusted EBITDA and AFFO annual targets, largely due to the strength of the Alberta power market.

Of note, the updated guidance range is higher than the top end of the original guidance ranges and reflects the estimated impacts from the Genesee 2 outage. In the first six months, we reported $544 million in adjusted EBITDA compared to the revised annual target range of $1.09 billion to $1.14 billion.

Lastly, we generated $250 million of AFFO compared to the revised $570 million to $620 million annual target range. To wrap up, I'll cover our growth targets as highlighted on Slide 13.

We continue to make progress on all of our renewable projects. This includes developing and constructing seven renewable projects on budget and on time for commercial operation starting between the fourth quarter of this year and the fourth quarter of 2022.

For the repowering of Genesee 1 and 2 all regulatory approvals have been received, and construction is expected to begin in the third quarter of this year. Targeted operational dates are late 2023 for Genesee 1, and 2024 for Genesee 2.

With our major projects underway in the strength of our balance sheet from recent financings and our performance, we are positioned very well to pursue our $500 million committed capital target. This could be continuing to grow our renewable assets and or acquiring midlife contracted natural gas assets.

I'll now turn the call back over to Randy.

All right, thanks, Brian. Anastasia, we're ready to take questions.

Thank you and good morning. Maybe I'll start off with a follow up to one of the points you made in the prepared remarks.

You discuss the Genesee carbon conversion center as well as CCUS. More broadly, can you discuss what you need to see in order to commit to these two projects, specifically what is within your control and what isn't?

As well if you can compare the returns from these projects that you expect versus the range of development assets that you currently have on a go? That would be great.

Okay, thank you for the question. In terms of the two projects, when we look at CCUS, I will start with that one.

It continues to go well and what we need to see in terms of proceeding is, firstly, the government programs that we see have not changed our view, nor has the government changes the view in terms of the kinds of support that would be available for this kind of approach. And so, obviously, that needs to come to fruition.

And I would say, those are those funds things continue to be quite positive. Secondly, obviously, the technology needs to work itself out in terms of both costs and in terms of flexibility.

And we are looking at relatively stable technologies at this point. And so, we don't see that that would necessarily be a difficulty.

So, from the CCUS standpoint, we can see it being very positive and moving forward. Now, depending on the types of government support that we're looking at, can have a significant impact on what we see as a hurdle rate.

So, for example, if part of an overall packages support given to these kinds of projects is, say, a guarantee of carbon price for 10 years, then that certainly takes an element of risk out of the project. But having said that, when we look at what would be an appropriate hurdle rate for this kind of a project, we would start from a merchant perspective.

That end of the spectrum and then adjust it depending on what we see as various kinds of support for the project. And in particular, the commodity risk associated with CO2.

So that's the general framework for CCUS. The other thing sorry, in terms of CCUS that we'd have to see is obviously, the Alberta government is pursuing track of carbon hub and spokes associated with the pipeline access to what might be the spots to the bury the carbon.

That needs of course, to move along and to come to fruition. We certainly wouldn't want to get ahead of that development, we would like to see that move along very quickly and be in place from a number of different perspectives, before we would move too quickly to commit our dollars to the CCUS facilities.

In regards to GC3, the design work continues to go very well. And so, we're not saying that there's any technical issues associated with moving forward with it.

What we continue to do evaluating, and more or less finding, what are the different markets to be utilizing these carbon nanotubes in the short term, and continue to explore that. The cement testing continues to be ongoing.

In fact, there's a significant cement testing that is being kicked off as we speak. And so, we'll continue to be bullish from that perspective.

So, when we need to see some significant commercial step forward in terms of people actually signing up for carbon nanotubes or a clear identification of a variable vibrant market that it can tap into before we actually start construction of GC3. Likewise, we look at that from probably a merchant plus hurdle rate, given that it is largely more speculative than merchant markets.

So, we'd be looking for some pretty robust long-term returns associated with that project. I might also comment that just in terms of the way of looking at our development going forward, there is a fairly long process associated with getting carbon nanotubes and variations of carbon nanotubes approved from a both Canadian and U.S.

regulatory perspective has a quote unquote, new material. And that takes about 12 to say, 15 months.

And we're in a situation now that where do we find the carbon nanotubes a sort of putting through this process, that gives us more than enough time to finish, polish up the design parameters associated with GC3 and to complete it, so that we'll have regulatory approvals and completion of a project happening simultaneously.

Thanks. And to be clear, while we start at a merchant return level or merchant plus, is the ideal end goal to have more than 50% or maybe even 70% contracted?

Or are you happy to have it merchant and then backfill the contracted bits with other developments that you may go for?

Well, the nature of the market and this is the same with any sort of quote unquote material. It's not typical for there to be long term contracts associated with the supply of materials.

So, it would be good to have long term contracts. And but we don't believe that that is practical.

There may be shorter term contracts for a year or two or something of that nature. But we don't believe the nature of the market is such that long term supply contracts would be available.

Thanks. And on my final question and keeping the theme contracted.

Amidst your discussions with BC Hydro, with regards to Island Generation, maybe more broadly, how do you view your current re-contracting profile? And more specifically, does it change your desire to acquire MetLife natural gas generation assets?

Actually, no. And the reason is, as I indicated in the comments thus far, we see that that facility is definitely needed on Vancouver Island.

And I would say the IRP that was put out by BC Hydro doesn't have the same level of diligence or analysis behind it, that IRPs in previous years have had. So, it's very much, I would say, incomplete from that perspective.

And I think as their work is complete and as parties like ourselves have input, I think we will see a different answer, if not, in the IRP itself when it's out in December. Ultimately, as it goes through process with BC Hydro or BCUC.

So, we definitely continue to believe that that will not - that that facility will be re-contracted. When we look across the other re-contracting situations and in the near term the next one is Arlington, which comes up I think in 2024 or 2025.

The outlook for that has been recently strengthened significantly. And that's because we're seeing significantly high prices in the Arizona market.

We're seeing new supply constraints starting to evolve. And the niche the refill is particularly strained.

So, the outlook for re-contracting in the Arlington, which is the next one is very, very strong. When we look at what's the next series of re-contracts, which is at the end of this decade 2029 in Ontario, the recent outlook that was published by the ISO shows that all three facilities will be very much needed as we go of the decade.

There's a significant demand for generation or new generation in Ontario. And even under scenarios where everything gets re-contracted, there's still a very significant demand.

And there are increasing constraints on the system, and how the three facilities are on the right side of those constraints. So, they are continuing to be extremely well situated or being needed in the Ontario market.

So, our outlook for re-contracting existing assets is very - is actually stronger now than it had been before. When we look at new assets, obviously, we continue to have to scrutinize not only the current contracts and current circumstances, but definitely continue to make sure that anything that we bring forward has a very valuable market positioning, either physically or is particular niche that it feels.

So, we continue to be very bullish on that market.

Great, thank you very much.

Yeah, thanks. Good morning everyone.

Mentioned Brian that budgets and timelines are named for projects are going as planned. Can you just maybe give us a bit of a rundown in terms of exposure to some of these inflationary pressures we're only hearing about in terms of Genesee repowering, and risk in liberal projects in terms of how much of the build costs are locked in and equipment costs are locked in at this point for those different projects?

So, it very much varies, obviously, by project. A lot of the repowering is locked in, I don't have a specific [Indiscernible] in mind.

But the general sourcing of it, materials and so on, is largely at risk from a GE perspective Outland Mitsubishi perspective, depending on the elements of the project that they're working on. So, I'd say very major components from a cost perspective.

The other thing that, when the pressures are up, there's two components one is the actual cost of material and supply demand balance, but where we're seeing the major pressure on cost is on transportation. And the general perception is that right now there has been a significant increase in terms of a couple 100% in terms of transportation costs, but that will subside.

And a lot of the deliveries associated with the Genesee repowering, would be on the other side of that delivery. And a lot of that project is actually being sourced out of the United States.

So don't really expect that element of pressure to the impact on that project. When we look at the renewable projects, the ones in Alberta, a lot of the backing per se was done prior to cost pressures.

So, we do see some delivery costs factors impacting on the Alberta projects. We think that those are permits or unexpected that the impact would be relatively modest on a project, we don't see any costs going sort of out of control and continue to be pretty bullish on those.

When we look at the U.S. renewable projects, the contracting for those is still somewhat open.

We do have some supply elements in place. And as we move forward, we do expect that the particularly again, as I've mentioned earlier the costs associated with transportation to be declining, which is where we're seeing the greatest cost pressure in terms of supply chain associated with our facilities.

And then with those solar projects in the Carolinas, do you have some flex in terms of start date or COD? If you do kind of move away from some of these are transient effects that you're talking about?

Yes, we do. And we've been - even with the Alberta project, within the construction schedule, we're able to move around some dates and change the way in which we're executing on that project to minimize the impact of some of these pressures.

Got it. I wanted to come back to the Alberta market and talk about hedging in the forwards, maybe just on the on the forwards, 2022 has come up nicely as of obviously this year.

2023 starting to move up a little bit, but not nearly as much as 2022. And I get the view would be that there's new supply coming in.

But when we look at your repowering work that's more late 2023, your assumption that there's still a chance at 23 forwards have room to move higher when you think about supply demand?

Yeah, I think, Mark with respect to looking out as far as '23 and '24, there's less liquidity out there. And certainly, as we get closer to that date, you'll start to see more reflective forwards of where they will.

You're correct with respect to increased supply during those periods of time. But we also expect higher carbon taxes as well.

So, do think there is upside to those years, but we won't see that until we get to another year out or so sort of similar to what you're seeing in 2022. It's starting to be more representative currently, but the other years need to see more liquidity before it'll start to fully reflect where we would see it settling in those years.

Okay. And then when I look at the 2022 hedge position taking it up, the average prices are gone a little higher and closer now turn the lock in some floors in the $60 range, at least.

That's still below what forwards are like, would you still want to keep adding more forwards here into '22? Or like, could you start to slow down here as you push 50% hedging because obviously prices on the forward curve are $70 right now?

Yeah, if you've seen prices go up, it doesn't form our view as to incremental hedges. So, we would be very opportunistic in terms of adding positions at a price that we see being in line with where we think things will settle.

So, we have locked in. We'd like to get hedges in place to protect the downside, if you will, but certainly our strategy has been to be less hedged and be very opportunistic to get only hedging at prices that we think are more representative of forward.

So.

First thing that you did - if you didn't see more really good opportunities to lock in price, and you'll still be comfortable having this year 50% hedge going into next year? [Indiscernible]

Yeah, no, absolutely. I think, historically, we've been somewhere between 50% to 100% hedge under the previous market dynamics, and we're very comfortable to be less hedge in the current market environment.

So, no expectation of having to increase that hedge position if we don't feel we're going to be seeing prices that are competitive.

Got it. And I just wanted to ask question about the updated guidance in terms of the changes in the midpoint of the EBITDA and AFFO.

So, if I take the new midpoint and what you've done year to date, and kind of look between the cascade from EBITDA to AFFO. So, the cash outflows for the second half implied to midpoints about $226 million and it was $294 million and you think of interest expense and press dividends and whatnot in the first half.

So instead of a $70 million lower sort of cash outflow between EBITDA and AFFO in the back half, aside from maybe, say, lower interest expense, and I guess the line loss not being there, what else would contribute to that and for maybe it's just the ranges and using the midpoint maybe not the most appropriate thing to do. So, any sort of commentary around that sort of thinking between the below the EBITDA line cash expenses in the back half of the year?

Yeah, I think if you're looking at - you're looking at the difference between adjusted EBITDA and AFFO, is that correct?

Yeah, yeah.

Yeah. So, in adjusted EBIT, we have the coal compensation acceleration.

And that's about $20 million a quarter of incremental year over year recognition, where in AFFO it's still on a cash basis, which is $50 million a year. And that's all in Q3.

So, there is some distortion in the timing as well as the amount of that component. And that's both the biggest difference between those two metrics.

Okay, that's helpful. Thanks for clarifying.

And I guess Mark just the other thing too is below the line is the impact of taxes as well. So, on EBITDA to the extensive, we were seeing higher plant performance.

You've just seen the margin there where an AFFO, that's tax affected as well. So, that will be another difference between the two.

Hi morning, everybody. Maybe just starting with the forced outage of Genesee to meaningful forced outages at Genesee, in general, pretty unusual.

And I know it's still ongoing and is reflected in your guidance. I was just wondering if there any lessons learned there from the generator failure?

So, I'm sorry, John. I didn't catch the last part of the question.

Just I'm just wondering, if there any lessons learned from the failure of the generator there? Could this maybe have been mitigated if you hadn't had to defer?

I think the outage was originally scheduled for 2020. But I think it was delayed for COVID understandable reasons.

Are there any takeaways from the others there?

So, actually, I mean the way that things have come about, although obviously, it's in outage, we've been very pleased with the way that we've been managing those assets. So, there's a major rewind expected that even at normal course continue in co-operations existing facilities, there was a major rewind, expected around the mid-decade this year or this decade.

So, there was an expectation that the rotor itself was going to be in need of major refit. And the expectation that that's sort of signaling to you that there, you may be running into troubles, even earlier than that, we actually have packages on site quote unquote strategic spares, that will significantly reduce where would otherwise ban the outage experience with this kind of a failure.

So, the combination of being able to be somewhat conservative and ensuring that we have those kinds of spare materials around such that, when we have these kinds of failures, if this failure happened, and when we weren't well positioned, it could have been six months. So, we're again very pleased with how we are positioned to deal with this kind of a situation.

So, it confirms the need to ensure that you have the right strategic spares, that when you're looking at major maintenance happening sometime in the future that, again, you should be prepared to move quickly and deal with it in a more timely manner than otherwise would have been the case.

Okay, thanks. That's very helpful context.

And then maybe just move into your development outlook, and just wondering if you can give us a bit of an update on beyond the stuff that's in the construction pipeline, and update on your renewable power development activities in Canada and U.S. and whether you're seeing interesting opportunities to either move forward with any new projects, or to increase the size of your potential U.S.

deployment pipeline through additional early-stage acquisitions?

So, my answer to that is all of the above, we are seeing some positive developments from Alberta, and the Canadian perspective, and see some opportunities moving forward. We also on the U.S.

side have some opportunities that we believe may come to fruition in the relatively near term. But in addition to that we are looking at opportunities to expand our pipelines on both sides of the border.

On renewable perspective, and there's where we've been successful in the past is being aligned or acquiring, I'll call smaller developers as one off or a series of developments back continues to be fruitful in terms of some opportunities out there. We're also looking at the fundamental ground up development of our own projects and we've been quite successful with that where we've undertaken it.

So, we're looking at markets, where it makes sense for us actually from the ground up from securing the leases through to design and develop. So, our pipeline will be getting built out from a number of different perspectives.

But even without what we have today, and what we're seeing, we continue to see some significant opportunities in the near term.

Okay, thanks for that. And then a just one follow up question on Island.

Appreciating you may not want to get too much in the contract discussions, and there's an active review process for the IRP. If you had any follow up from BC Hydro, since the transmission issues and cable bulging problems started early in July that recognize the operations of the IRP just may not reflect the reality of the grid on Vancouver Island and its needs?

So, our discussions thus far have been with the government and the BC government, largely because for logistical reasons in time, we haven't had a good opportunity to directly discuss it with BC Hydro. But that is being scheduled and those discussions will take place outside of the IRP process.

So, we do have a number of questions, and we've informed BC Hydro, these are the questions that we have, and just old and out don't understand their conclusion based on the facts. But, again, we'll see where that gets to.

We don't believe that when you look at the IRP, we don't believe that that is their final any stretch of the imagination. We do believe that it is a work in progress in recent information suggests that they still have work to do in terms of that assessment.

So, we don't believe that we're talking to deaf ears. We do believe that there will be a significant receptivity to having discussions around the re-contracting of the Island facility.

Okay, I'll leave it there. Thank you for taking my questions.

Hello, everyone. Just kind of two follow up questions.

The first is that, we have six months or I guess, seven months under the belt regarding the Alberta power market in the New World Order. Have your view of patent market participants act or what the long run sustainable pricing is changed over the last six months?

Yeah, so I think the environment that you're seeing now in 2021 is reflective of the market going forward in terms of the dynamics and setting price. I would temper that with, in 2021 what we've seen so far is some extreme weather both in February and in June, which has driven prices above where I would say you would expect them to be longer run.

And wind availability is something else that impacts on that volatility when you've got extreme weather. So, I think generally speaking, the dynamics are what you will see going forward.

This is the supply demand sort of fundamentals, but artificially high, I would say for 2021 when you're looking at $105 per megawatt hour, but when you look at the forwards going into next year, I think that's a little more representative of where you would expect it to be given where the market tightness might be in any given year.

Okay, great. Then just in particular 2021 guidance, what kind of range of power pricing are you assuming there?

Or is it kind of relatively centered around where the forward curve is?

Yeah, so it's based on both our positions and the hedges we have on place as well as our outlook for forwards for the balance of the year on our open position.

Thank you.

Thanks. Good morning.

And I guess the question really revolves around the Alberta power market and just your trading desk philosophy and how things changed the dollars that have really been the same and maybe given a dichotomy of are you focused on capturing returns that are really acceptable to the capital you've put in the business? Or is it really a focus on capture and close to market price?

Yeah, Andrew, I think it's a combination of both. When you look at where prices are, it's expected to be a return of a return on capital for our investments in the market, but also in any given year, you know, that there is volatility depending on supply demand dynamics.

So, you're looking to optimize the price in a given year based on where you're seeing prices settles. So, it's sort of a combination of both in terms of the strategy.

You're always trying to realize that the best price that you can and balancing that with volume as well. So, it's really two pieces of that strategy, if you will.

So, in theory, the market dynamics are allowing for appropriate level of returns on investment.

Okay, that's helpful. And then maybe putting aside weather anomalies and other things.

If you just looked maybe from last year to where we are now and the evolution of dispatch behavior, are there any major surprises that have happened in the market versus how you thought it was going to pan out?

No, I think it's generally in line. There was certainly some uncertainty around how it would unfold, there was sort of a range, if you will, of prices that you could expect.

And so, you don't have a clear crystal ball, but directionally I think it is lining up with what we would expect in terms of market participants behavior and just the commercial being a much more rational market in terms of how assets are being dispatched.

Okay, that's very helpful. Thank you.

Thank you. Yeah, good morning.

Just on the natural gas price side of the equation and I guess, thinking about the upward bias narrative that's out there right now, not only into this winter, but perhaps longer term. Curious how you're thinking about mitigating your margin exposure there?

And especially once our prices eventually come back down to earth and the Genesee repowering comes online. Are you looking at strategic partnerships, investments, or long-term supply agreements that could lock in the natural gas cost side of the Alberta merchant margin equation?

And if so, what might those structures look like?

Yes, Patrick, I mean we have for a considerable period of time looked that is there a strategic relationship out there in which we could access natural gas supply at, let's say, something other than market, them getting some security of market and median return. And what we found is that, generally speaking, the natural gas market isn't very reasonable.

What they'd like you to do is lock in a very high forecast price and guarantees that kind of a cost, so we haven't found the market that receptive. And certainly, in that environment, it's very difficult to establish a mechanism that is responsive to power with increasing natural gas and especially now when we'll be half coal, natural gas price will have a significant impact on the margin.

So, as natural gas prices go up, that would be a variable cost for increasingly more and more generation in the province and they would have an impact of increasing power prices as it goes up. So, we're a little bit naturally hedged by the pricing mechanism in the marketplace for power.

So, traditional wisdom is that unless you really have an ability to walk in both sides of natural gas price and the long-term price of power, you're probably better off to let it float with the price of the electricity prices that you're seeing. So, we continue to look at those opportunities and where we can find somebody that has the right sensitivity.

And there's some value share between the power generation side and the natural gas side, in terms of sensitivity to where power prices go. It likely doesn't make sense to just lock in one side.

Again, unless you're locking in the side, and the other side is longer term power price commitments.

Thanks, Brian. Yeah, appreciate all the color and how you're thinking about that.

And maybe just back to the Island Generation situation, or, I guess, the contracting process. Can you maybe just provide a bit more color on how this experience has changed your approach in looking at other mid merit acquisition opportunities, either in terms of recalibrating your hurdle rates, or perhaps taking certain jurisdictions right off the table?

It is, I mean, we're definitely going to taking away some perspectives from this experience. Certainly, we often with investors and with you folks have utilized Island Generation as this is the one that gives the illustration of why something probably position makes a lot of sense.

So, again big surprise to us. And when we look at these, again, in the longer term we do have to consider that there can be just out and out mistakes made in terms of assessments of utilization and part of what's underlying some of the thinking from in the IRP, is they're going to have very, very substantial and pretty quick reduction of power utilization through conservation methods, and so on and so forth which still are far away from regulatory approvals, et cetera.

So, just there are things that they can enter into the equation that aren't, that are new or different. So, it'll probably broaden our perspective when we're looking at new natural gas acquisitions, considering, perhaps maybe some of the more outlier possibility.

So, I would say the hurdle rate per se, again, may adjust depending on the particular risk profile you see in an area may in some future possible acquisition have an impact on hurdle rate. I think where it will have probably more of an impact is on the breadth of our assessment.

Got it. Okay.

And then last one for me if I could just, I guess, to finish off on a positive here, but the follow up on the new renewables opportunities that we're of course, seeing big demand from pipeline companies and other infrastructure players looking to electrify their systems. I know, they're running very competitive bidding processes, but just given your relationships with some of the larger players in Alberta, your development track record, how should we be thinking about the size of your backlog of opportunities today related to corporate PPAs either wind, solar or other relative to even say six months ago?

We continue to have number of opportunities that we are pursuing and some also are probably pretty close to fruition. And some of those to a degree are relationship based.

But I would say, when you look at the very large PPAs that are out there, those tend not to be relationship based. There are certain advantages that we and other developers might have such as investment grade credit rating, track record of delivery.

There's been a number of PPAs in the Alberta market that have failed where a commercial entity has signed up with an organization. And when the organization has got into the more detail for planning find that, they can't move forward on the project we've seen a handful of failed projects in the province.

So, the fact that when we say we're going to do something we do it is very helpful. So, there's a number of those kinds of elements that favor us and other substantial developers.

So, but relationship I'm not so sure in the larger ones, whether they actually will make a difference. A lot of it is just what's the cost.

One of the other things, though, that does help us in the market is we tend to be a lot more - we can bring a lot more to the table in terms of people's load and being able to manage it. For example, we can provide both wind and solar combination right now.

We've got a lot of flexibility. We can actually round up somebody's overall power demands.

So, there's a lot again that we can do that a number of different developers may not be able to do. We can bring in [ph] Rex from other provinces, because we've got quite a broad trading footprint, whereas a lot of the other developers don't.

So, there's more tools we can bring to the table, depending on what the specific requirements are of [Indiscernible]. But they're pretty, they're getting increasingly sophisticated.

And it's becoming a very, very dynamic market. But again, we continue to be bullish in terms of our success in securing some PPAs.

Excellent. Well, again appreciate all the color.

Thanks, Brian.

Hi. Good morning.

The first question is around, I guess portfolio optimization and it's sort of related to the previous questions about Island Generation or your gas assets more broadly. You've talked in the past about potentially monetizing renewable assets, if there were investment opportunities presented themselves.

I guess the question is, would you ever consider monetizing some of your gas assets at the right price, of course, instead of renewable ones?

We're certainly looking at assets and depending on how much capital that we're looking for, and so on and so forth, there are certainly some of our natural gas assets that would be relatively easy to be monetized. Part of the challenge that we face is that when you monetize a renewable asset, long term contractor asset, what you receive in the AFFO you give up have a particular relationship.

When you look at a natural gas asset typically, you're getting less proceeds for the same level of AFFO that you are giving up in terms of the sale. So that's one of the things that comes into consideration.

But absolutely with the reasonable pricing, we'd consider selling natural gas assets as well.

Understood. Trade-offs that you're thinking about between immediate financial contributions versus a contractor profile and realtors profile and maybe diversification.

Okay, that's helpful. Maybe just a couple of questions for Sandra.

Can you provide any color on the sustainability liked with credit facilities, on either the terms or the incentives versus the previous structure goes to service?

Yeah, so most of the details around that aren't are disclosed. What I can say is that it's plus or minus 5 basis points for our performance relative to the targets.

And the targets are based on our emissions intensity, and align with our trajectory to be 65% below our 2005 level by 2030. So, that it is an annual target.

So, it's not where we are at the end of the five years. It is consistent with most other SLPs we've seen out there.

There are annual targets that need to be met in order to keep the pricing or to have it move downwards or upwards in the case of not achieving that level of intensity. One other element of that structure that I can share is just around the treatment of structural changes.

So, to the extent that we acquire an asset that was already in operations, we would have that adjustment made to the intensity targets and you look at it very holistically in terms of overall emissions. So, to the extent that asset was already in operations.

It then impacts your targets. And likewise, to your earlier question, if we were to divest of something that had an emissions profile, our targets would be adjusted to reflect that as well.

So, there is that rebase lining component in the structure.

Okay, got it. That's very interesting and very helpful color.

Just last question on the private placement of the U.S. notes.

Do you see any other opportunities for similar favorable debt financings?

Yeah, I think it's been very favorable, like the market has been favorable in both the U.S. private placement market and the Canadian market as well.

At this point in time, don't see ourselves going to the market absent any growth, but feel very confident that the market is there for us if we did have to raise capital.

Okay, that's perfect. Thank you very much.

Okay, if there are no more questions, we will conclude our conference call. Thanks again for joining us today and for your interest in Capital Power.

Have a good long weekend everyone.