Capital Power Corp

Good morning. And thank you for joining us today to review Capital Power's third quarter 2021 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 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 up the lines to 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 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 third quarter 2021 MD&A.

With that, I will turn the call over to Brian Vaasjo for his remarks starting on Slide 4.

Thanks, Randy, and good morning. I'll start off with the highlights of the third quarter and comment on our 2021 outlook.

The third quarter results were generally in line with our expectations. The unplanned outage at the Genesee 2 facility will be longer than originally anticipated, with a return to service now expected at the end of November 2021.

We continue to make progress on our 7 renewable development projects, that I'll comment on in greater detail later. But briefly, we're seeing cost pressures on our 2 Alberta solar projects.

Also the completion date for our 3 North Carolina projects have been extended due to delays in the interconnection process. With a strong financial position, performance and our positive outlook, we are suspending our Dividend Re-investment Plan or DRIP, effective with the fourth quarter 2021 dividend.

In the second quarter, we provided higher 2021 financial guidance, largely driven by the positive Alberta power outlook. That outlook has not changed as the market continues to be robust.

Despite the extended Genesee 2 outage, we continue to be on track to achieve annual financial results consistent with our revised higher guidance. Turning to Slide 5, as you may recall, Genesee 2 experienced a forced outage in mid-July, that was caused by a generator failure and the physical damage is covered by insurance.

The unit is undergoing repairs to replace the generator. And as I mentioned, it's expected to return to operation at the end of next month.

We continue to utilize our Clover Bar peaking facility to backstop Genesee 2 when it's appropriate. The loss of revenue qualifies for business interruption insurance after 60 days.

And Sandra will cover the accounting impacts of the Genesee 2 outage in her comments. I'll now turn the call over to Sandra.

Thanks, Brian. I'll start with a review of the Alberta power market on Slide 6.

We continue to see strong prices with an average power price of $100 per megawatt hour in the third quarter, due to hot temperatures, facility outages and year-over-year weather-adjusted demand growth of approximately 4% in the third quarter. The strong average power price more than doubled the average price of $44 per megawatt hour in the third quarter of 2020.

In the third quarter, our trading desk captured an average realized price of $75 per megawatt hour, that was 27% higher than the $59 per megawatt hour a year ago. The market outlook for the balance of this year continues to be strong with a $99 per megawatt hour forward price for the fourth quarter.

With the strengthening of the forward prices, we have increased our hedge positions for 2022 to 2024 since the second quarter. Our Alberta baseload generation is now 67% hedged in 2022, at an average contract price in the mid-$60 per megawatt hour range.

For 2023, we're 38% hedged at a contract price in the mid-$50 per megawatt hour. And for 2024, we're 21% hedged in the mid-$50 per megawatt hour.

This compares to current forward prices of $91 per megawatt hour for 2022, $73 for 2023 and $62 in 2024. In addition to the baseload assets, we have approximately 500 megawatts of gas peaking and wind facilities available to capture upside from higher power prices and price volatility in 2022.

On Slide 7, I'll review our financial results for the third quarter. As Brian mentioned, financial results were in line with our expectations.

Consolidated revenues and other income were $377 million in the third quarter, down 17% from a year ago, largely due to unrealized changes in fair value of commodity derivatives and emission credits. Excluding the mark-to-market impacts, consolidated revenues and other income are up 7% due to strong performance from the Alberta commercial facilities.

Adjusted EBITDA was $286 million in the third quarter, a slight increase of 1% compared to a year ago. We generated $206 million in AFFO that was 7% lower than a year ago.

The decrease in AFFO was due to the lower AFFO contributions from the U.S. contracted facilities and higher sustaining CapEx due to maintenance work performed for the Genesee 2 outage that was originally scheduled for the fourth quarter.

On Slide 8, I'll discuss the accounting treatment of the Genesee 2 outage and associated insurance recovery. Approximately $25 million of capital costs were incurred in the third quarter, of which $23 million net of $2 million deductible was accrued to be recovered through insurance.

The net recovery is reflected in the third quarter income statement in the gains on disposal and other transactions line, and not as an offset to the capital cost. In AFFO, we see the net impact of the $2 million deductible, while there is no impact to adjusted EBITDA.

From an operational perspective, business interruption coverage is effective 60 days after the start of the outage, which would be as of mid-September. And accrual for business interruption was not recorded in the third quarter, primarily as the final amount of the claim which will take into consideration mitigation across the portfolio will not be fully known until the unit returns to service.

Slide 9 shows our third quarter year-to-date performance. Adjusted EBITDA of $830 million was up 13% compared to $735 million for the same period in 2020.

The main driver for the increase was higher Alberta power prices, where our realized power price was $75 per megawatt hour, compared to $59 per megawatt hour a year ago. Lower corporate expenses also contributed to the higher adjusted EBITDA mainly due to the acceleration of coal compensation revenue.

AFFO was $456 million, up 5% compared to $436 million a year ago. Overall, we're seeing strong year-to-date performance in our key financial metrics.

As Brian mentioned, we have suspended the DRIP due to our strong financial performance and outlook. We also access the capital markets this year, raising $288 million in equity and US$150 million in debt that will fund later this month.

These successful financings have reduced our financing risk and the need for additional equity for current growth projects. I'll now turn the call back over to Brian.

Thanks, Sandra. Turning to Slide 10, I'll review our performance for the first 9 months of the year compared to 2021 targets.

Year-to-date, the average facility availability was 90%. The extended Genesee 2 outage will impact our annual performance and we expect to be below or 93% availability target at year-end.

Sustaining CapEx was $99 million in the first 9 months compared to the $80 million to $90 million annual target. We've exceeded the annual target largely due to the Genesee 2 outage and an unplanned order purchase at the Arlington facility during the planned outage in the second quarter, of which the latter will cause us to exceed our sustaining CapEx target for the full year.

After 9 months, we reported $830 million in adjusted EBITDA, based on our current outlook we expect full year results to be in line with the midpoint of the revised guidance of approximately $1.1 billion. We generated $456 million of AFFO for this year, and expect full year results to be modestly above the midpoint of the revised guidance range of $570 million to $620 million.

On Slide 11, I'll provide a status update on our growth projects. We continue to make progress on approximately $1.7 billion of growth projects under development.

This includes developing and constructing 7 renewable projects and the repowering of Genesee 1 and 2. Our Whitla Wind 2 and 3 projects in Alberta are on budget and on schedule for commercial operations later this year.

The Strathmore and Enchant Solar projects in Alberta are experiencing higher costs due to significant increase in transportation costs and higher costs from supply chain pressures. The revised project cost is estimated to be $57 million compared to $53 million budgeted for Strathmore Solar.

While the project costs were Enchant Solar is now $119 million compared to the $102 million budget. We have 3 solar projects in North Carolina with an original commercial operations date of Q4 2022.

However, due to delays in the interconnection process, commercial operation is now expected to be Q4 2023 or Q1 2024. Construction on the repowering of Genesee 1 and 2 commenced in the third quarter.

There are no changes to the budget or target operations date of late 2023 for Genesee 1, and 2024 for Genesee 2. For our $500 million committed capital growth target, we continue to explore opportunities with potential growth announcements later this year.

To wrap up, I'll comment on other activities that we have going on as outlined on Slide 12. COVID-19 continues to be well managed with no impact on our operations.

Our plans to build the world's largest commercial-scale production facility for carbon nanotubes at the Genesee Carbon Conversion Centre continues to be on the slower development path. We continue to work through the regulatory registration of our carbon nanotubes necessary for commercial operation.

For Island Generation, we continue to believe the facility is needed to ensure secure and reliable power supply for Vancouver Island and Metro Vancouver. We're currently negotiating on a medium-term agreement with BC Hydro, before the current PPA expires in April of next year.

Finally, the CCS pre-feed study is nearing completion. And overall, the project looks increasingly promising.

We plan on providing more details on our decarbonization strategies at our Investor Day. I'll now turn the call back over to Randy.

Okay, thanks, Brian. Before we take your questions, I would like to announce that we will be hosting our Annual Investor Day event on the morning of December 2, where we're hoping to hold a live event in Toronto, but it will be a virtual event again this year.

More details on the event will be announced shortly and we hope that you're able to join us virtually on December 2. All right, [Shree] [ph], we can start taking the questions.

Thank you and good morning. My first question is on the repowering project.

Just wanted to get some updated thoughts on this project. Obviously, you would have heard that one of your peers opted to suspend their project, highlighting some of the potential regulatory and financial headwinds for new gas, including repowering.

How would you characterize these risks, and what plans do you have should these risks materialize?

So, I guess, maybe going to, I guess, the essence of your question, when we look at our outlook in terms of regulatory stability, and in particular, where the 0.37 stringency is going, we've been reassured again by the Alberta government, as you know, from direction from the Premier, that the 0.37 will hold. The province is very confident in their equivalency from a federal perspective.

And so, don't really see that element changing. In terms of our peers' decision to basically suspend moving forward with 1 project and shutting down 2 other facilities, we'd have to admit the shutting down of the other 2 facilities is actually a little bit in advance of what we thought when they'd actually be shut down.

And in terms of advancing on a new facility, I think if you look back to when that facility was announced, initially what's happened since is that there's been - and if you think of the STACK in the Alberta market, it would have been one of the most efficient natural gas combined cycles in the province. Since then, Genesee wanted to repowering.

And, there's been an additional announcement in Alberta, the Cascade Project, that's going ahead. So, all of a sudden, there is 2,500 megawatts of capacity, much, much more efficient, that's been put in the queue.

So that project not going forward was not a surprise to us whatsoever, didn't believe that with those other results that it would be economic even with our outlook. So not a big surprise.

And again, in the face of constant reassurance from the Alberta government that the 0.37 will hold, we continue to be positive. Now, the second part of your question is, what happens if it changed or what happens if there was a - well, a change in the 0.37.

We actually, in our projections for the repowering of Genesee 1 and 2, we actually have it after 2030 declining. At some point in time, it will reach 0.

And it's fully within our economics, that over a reasonable period of time, post 2030, that it will get there. So, if at worst, it's a timing difference.

The shorter-term impact, of course, is that it will impact to a degree on power prices in the province, given the dominance of natural gas generation. So, the economics of Genesee 1 and 2 would continue to be very solid.

Thanks. And maybe just a follow-up to that.

You said a few cost pressures for some of your Alberta solar projects. Any pressures or similar pressures to the $997 million budget for this project?

No. I mean, we are seeing some very, very modest cost pressures, but nothing that is moving the needle on the costs for the project.

Thanks. And just a final question on guidance.

You've pointed to midpoint of EBITDA on a guidance range. But you also highlighted that sustaining CapEx is likely to be above your $80 million to $90 million range.

So despite this higher sustaining CapEx, AFFO is still expected to be not just at the midpoint, but modestly above that. What is causing this AFFO to go higher?

So there is a few things in there. We are seeing lower financing costs this year.

So it's some of the below-the-line items, but just seeing strong performance in Alberta driving up the cash flow. So there are some timing difference and some below-the-line items that impacts that differential if you will.

Okay. Thank you very much.

Thank you. Good morning.

Brian, just a follow-up on the Genesee investment. Curious if there is any update on your carbon sequestration opportunity at the site, when you might have more clarity on the level of government support, both provincially and federally?

And I guess, when you think you might be in a position to sanction the opportunity?

So where we are in respect of the CCS opportunity is we continue to be pursuing it and actually with increasing bullishness. In terms of the development process, we're close to finishing our pre-feed study.

And results there have been, on balance, positive, slight increase in capital costs. But operating costs and the degree to which it needs power is declining.

So, that's that on balance. The economics of the project are improving.

And so then, of course, we move to a feed study, which we expect to go through next year. And I will say the earliest that we would be sanctioning the project, and given that we would require government support and then clear indication of government support before we would get into approving the project and moving forward, we would expect that to happen late next year or early in 2023.

And in terms of the government activities, the Alberta government is moving forward on the hub concept, and looking at different parties to provide carbon sequestration hubs. And from what we've seen and the parties we've talked to, that's moving along quite well.

The other front is with the federal government, and discussions continue to go from our perspective, well, with the Canadian Infrastructure Bank, and the - bringing into play something like 45Q before the election was identified by the federal government as something that they would be doing. And so, we are looking forward to hearing the next steps in terms of that development.

They have been receiving comments from many parties as to what it should look like. But as we put all the pieces together, we continue to believe that CCS is definitely economic, for Capital Power on the top of Genesee 1 and 2.

Great. Thanks for the color.

And then, maybe also on C2CNT, do you still expect to have board approval for the carbon conversion project by yearend, and maybe just an update on how the technology continues to prove out here since the last update?

So given the timing opportunities for Board approval of that project, wouldn't see it happening before the end of this year. In terms of the development of the technology, it continues, the actual development of the technology continues to go very well.

The testing of the carbon nanotubes, as it relates to cement has been moving along, albeit slowly, very much in a positive direction. I'd characterize it that we're 3 quarters or 2/3rds of the way there.

The challenge that we've run into, and I think I've commented on it before, is it there is actually a very long regulatory process to actually get each and every carbon nanotube approved as a new material, which requires in-depth analysis and description of not only the process, but the mediums, for example, for distribution, within a material, et cetera. So we have to be almost complete, say, for example, with our cement exploration and development.

And then, at that point, we start basically a minimum 1-year process to get it approved. And we can clearly build a Genesee carbon-conversion facility within that timeframe.

So, until we have the precise product nailed down, it just is creating a delay for us in building the Carbon Conversion Centre. So that's the general outline of what we're looking at and where we expect to be going with the project.

Got it. That's helpful.

Thanks, Brian. And then, last one for me if I could, maybe for Sandra, on the suspension of the DRIP.

Do you view this as being more of a sustained suspension, in that even if you were to secure, say, the $500 million of committed capital projects for 2021 over the next couple months, you wouldn't need to turn the DRIP back on at that point? Or is this more of a temporary shut-off until you're able to secure a couple of more developments?

I view this more as a sustained turn off of the DRIP at this, Pat. So when you look at the capital that we raised, the equity we raised this year, as well as the contributions that we'll receive from the DRIP, it does equate to the amount of equity that we indicated we would need for the $1.7 billion of projects that are currently under development.

So we've achieved that, to the extent that we have growth. We're seeing strong cash flows, very strong credit metrics, feel that we would be able to fund development.

If there was an acquisition of any size, that would need equity, we would probably look to approach the market with an offering for that. So, go forward with a bit of a story with respect to it.

So at this point in time, don't see the need for incremental funding or incremental equity from that, in that regard. So see it as being a sustained turn off of the DRIP.

Okay, that's great. I'll jump back in the queue.

Thank you.

Hello, everyone. Maybe just in terms of kind of your outlook for the gas market and how you're managing that exposure, can you kind of just remind us where you are in terms of gas procurement, and how you're viewing kind of the rise of gas pricing in terms of your operations for the rest of the year and then into 2022?

Yeah, for 2022, the balance of this year 2022, and even out into 2023, and well into 2024, we have hedged a large portion of our gas, or substantially all of our gas in the near-term, seen a lot of volatility, as you've alluded to, and have sort of taken that risk off the table by hedging that out materially. So, looking at optimizing our fuel, and the burn of coal as we optimize the mine plan as we wind down in 2023, so look to sort of lock down those positions and close that exposure.

All right, thanks for that. And then, kind of just more perspective in nature.

So we're seeing some cost pressures, in terms of the renewable power development projects. When you're looking at that next phase of growth, whether it's that $500 million, how are you bidding into those projects, just given the potential that you could see additional or sustained cost pressures?

So, as we look at various projects, that definitely weighs into it. Certainly, the greatest cost pressure that exists today is on solar.

There isn't the same cost pressures associated with the wind business. There is some, but it's not a case - again, solar production or production of solar panels and so on is largely Asian at this point in time.

So it gets hit with both increasing commodity prices plus transportation costs, which are dramatically higher than they were previously. So as we approach projects and consider the cycle-time, due or are cautious on the solar side, and definitely consider where the costs are going.

But I would say that what we see going on today, we're starting to see the curves going down. We're starting to see transportation costs inching down.

We're starting to see some of the commodity costs or the forwards declining. So we are expecting this as a relatively short-term excursion in pricing and transportation costs.

So depending on how far out a project procurement is, can have an impact on definitely how cautious we are around the bidding process.

Excellent. Thank you.

Thanks. Good morning, everyone.

Maybe just going back to the Genesee repowering, can you guys share anything in terms of how much of the costs have been locked in at this point?

I can't. I'm just trying.

A number doesn't come to mind. But we will be talking about it in depth at Investor day.

So we'll be sure to comment on that element as well, unless you like us to follow up with a number.

No, I'm just, I would assume at this point in the large lead items, you kind of locked in, you already spent $100 million in the quarter. Is it just ongoing labor costs and balance the plant?

I'm just curious of where you would maybe still have some exposure to variable costs or things that are not fully priced in yet?

Well, there'd still be definitely some material being procured. But definitely the major elements have been procured and the costs for those have been have been established, so don't see a lot of forward cost pressures on those materials.

Got it. And then coming back to the solar projects in Alberta with the cost increases, any comment in terms of - obviously, there'd be some return erosion, whether or not they're still meeting your hurdles, and whether or not they become assets and you think about the sell-down strategy, if you feel like the returns have been compromised a little bit?

So as we go through projects and consider projects, we always have in mind, the potential sell down strategy associated with them. So, but when we look at those 2 projects, we had in both of them some headroom in terms of returns above our hurdle rates, as they're developing now, and where we expect them to come in from a cost perspective.

They would be coming in, I'll say modestly below our hurdles, but definitely above our WACC. So they're not - there isn't any erosion or shareholder value associated with those projects, as they sit today.

Got it. That's helpful, Brian.

And then one more on Island Generation, just the commentary on the medium term, but also sort of highlighting, I think, in the MD&A, [the book value you're carrying at] [ph] and some of the policy changes that BC Hydro is looking into the phasing of gas-fired generation. If the assumptions that are now you could get a 3, 4 year contract?

And at that point, Ireland probably has to be decommissioned and taken offline is that what they're trying to kind of outline to us there?

So, a lot of this depends on, obviously, where the BC Hydro goes, and where things go generally in respect of power supply or capacity on Vancouver Island. We still are extremely convinced, and there's nothing that has been brought forward or anything that would suggest that our position is not correct in terms of the needing Island Generation to support the capacity requirements of Vancouver Island.

Our view, and this is actually supported in the - what's been produced by BC Hydro. They have no plans on increasing their capacity to the island or on the island until 2033.

So, that longer term need is still there, so not much has changed in terms of our perspective. The recent indications from the BC government about phasing out natural gas, and so on and so forth, that's a position, open for comment, and we think just as we go through the resource plan, BC Hydro.

It will become clear, and we're convinced that in the plans, they are expecting for there to be brownouts in BC, or on Vancouver Island, because they don't have capacity. And that's not good planning and that's not apparent to the citizens on Vancouver Island.

So we think that our position of having ultimately a 10-year contract although there are different perspectives of the government that are coming out. We still think that good planning will ultimately prevail.

And there will be a 10-year contract, even with the latest indication from the BC government in terms of moving off natural gas in terms of power generation that would provide from an 8-year contract. So, we're still very optimistic on the backend.

And, certainly, what we're seeing in terms of the lack of reliability associated with these undersea lines, I think, is becoming extremely evident. And one of the things, I guess, now well-known is the work that BC Hydro is doing on the lines is not increasing the capacity at all.

It's just improving the reliability. So, again, the need for additional capacity or the capacity of Island Generation continues to be the same as it always has.

That's helpful context, Brain. Maybe just one quick follow-up on that.

And if you guys get that IRP, or the updated IRP or final IRP will be filed within this year, at that point, would you be able to listen, do you think that they'll come to the table and can have an agreement, or like would there be negotiations that would take us into mid-2022 before you'd actually have a resolution on Island Generation?

So in terms of the medium-term contract, we - again, that ends up being a process of negotiation that will take into - may well take into next year. A lot of it just depends on how the negotiation goes.

And, I would say, the discussions are positive, but they are infrequent right now. So, again, we'll see how that develops it.

As you can appreciate, we're ready to move in negotiated at whatever pace. We're not setting that pace.

When it comes to if there's any further expansion, or that won't be until the IRP is approved, or modified by the BCUC, which isn't expected until probably at least a year from now. So that's where there might be or that's where a further extension to be negotiated would commence happening.

Got it. That's all I had.

Thanks for taking my question.

Thanks. Good morning, everybody.

Maybe just starting with the $500 million target for Canadian growth, we're 10 months into the year, and I don't know that you can have an announcement before year-end. What has made it challenging to, I guess, get closer to this target?

Is that you're holding really tight to your return targets? Is that opportunities have been made more competitive than you'd hoped?

Have you seen some gas-fired deals that might make sense that had some type of hesitation just given ESG considerations? Can you provide some color on the growth targets?

So, John, we always sort of hold tight to our hurdle rates. We don't end up, because we're coming to the end of the year, and so on.

We don't relax in them. I think, as we've always said, that's a target that's out there, if we hit it tremendous.

If we don't that just means that we didn't see any opportunities that were right for Capital Power. And, it's happened before where we have not hit the $500 million target.

And from our perspective, that's fine. In the longer-term, our average has been $700 million a year, having said the $500 million target.

So, it averages out and the last year was well over $1 billion, well $1.7 billion almost in terms of achieving that $500 million target. So we're not fussed and we feel no pressure to actually we have to do something.

Now, in terms of what we've seen, we've been in second rounds on both renewables and on natural gas opportunities, so the market is there. But certainly that traffic isn't.

On the natural gas side, there's been definitely fewer opportunities than we've seen historically in a calendar year, and likewise, from a renewable M&A perspective, there's been fewer opportunities. And from a development perspective, we continue to be very active from that perspective.

And actually frankly see where that'll be a lot of our growth coming from in terms of the future is from actual development opportunities, as opposed to M&A type opportunities, just simply the way the market is developing and where we're able to create value is on the development side, and especially from a wind perspective, or a solar perspective, not on the M&A side.

Okay, that's great. Thanks for that context.

And then maybe just circling back to the Genesee repowering and CCUS plans. The federal government ran on net-zero electricity by 2035.

So if that moves ahead, that implies there most likely will need to be CCUS in place of Genesee for it to run beyond that. And you've pointed out that the CCUS initiative of that project needs government support.

So if that support isn't the magnitude that you're hoping for, do you see a path to recovering some of those costs in the power market over the long-term, given the lack of any real technological alternative to gas, absent some revolution in long-term storage or commercialized small nuclear? How are you thinking about the repowering project overall in a case where the CCUS funding picture doesn't pan out the way, you and really industry overall in Alberta is holding.

I mean, if you take CCUS off the table, the fact of the matter is, technology is not here, nor are the policies outside of Alberta here, that would make it even technically possible to eliminate natural gas by 2035. I mean, you've seen the recent work by the ISO in Ontario, that saying that being off natural gas by 2030 is just not in any way shape or form practical.

And, now think as to, what might it look like when might you'll be off natural gas. I think, you'll find that work will show probably beyond 2035 is feasible in Ontario, where natural gas is a much smaller component of the overall mix of energy.

So in Alberta, it's just not practical in when you see government pronouncements on being - even off coal by 2030. In Canada through the equivalency agreements, there are acceptance to that, there are going to be coal plants operating in Canada beyond 2030.

So, again, there's a practical element associated with any of these pronouncements. And, there seems to have been good discussions, not only in Alberta, but across Canada in terms of what's really a practical solution, aggressive solutions moving forward from carbon mitigation perspective.

But what makes sense in each province is different, and thus far, the federal government has respected that. Again, that's why there's the agreement for the tier program in Alberta to stand and continue to be there, because it needs the federal objectives in a way that is different for Alberta, and suits Alberta, just like there are equivalency agreements in most of the other provinces.

Okay, thanks very much for all that context. And then just maybe one accounting clarification for Sandra on the Genesee 2 outage.

Just as far as the business interruption insurance timing on what the final claim is until that returns to service. Are you expecting to be able to reflect that figure in your 2021 AFFO, or is it possible, though, that doesn't get resolved by the time you report your Q4 results?

Our expectation is that we would be able to reflect it from an accounting perspective. There has to be reasonable certainty around the amount.

And if that's the case, then you can accrue all of that expected or a portion of it. But at this point, we have confirmation from the insurers that it is a recoverable event.

So that's the first step. And then the second part of that is just landing on the amount.

And the complexities with that is just looking at modeling what your results would have been, if there hadn't been an outage, and compare that to what you actually achieved. And it does look at it from a portfolio perspective, so not just the loss from the asset.

But to the extent other assets in your portfolio are able to pick up some of that offsetting benefit from having that outage that comes into play. So it is a difficult modeling exercise.

But we've already started that on our side, as has the insurer. So see that progressing quite well.

So expectation is that when we get to the end of the year, we'll be in a position to accrue it, similar to what we did with the property side this quarter.

Okay, great. I'll leave it there.

Thank you very much.

Hi, thanks. Good morning.

I had more couple of follow-up questions. On a gas price, you mentioned you're hedged of near-term.

I'm wondering have you changed here your gas price assumptions long-term when you're modeling Genesee 1 and 2 or any better facilities in the province?

Yeah, so when we're modeling out power prices and gas prices, we do continually update those as the fundamentals change. So similar to other third parties, we do see sustained higher natural gas prices over the next year or two before they start to come down.

But do see that it is probably higher than it would have been at the beginning of the year, even when you get out to the back end of the plan. But it's something we continually refresh in our modeling.

Okay. And what are you assuming $2 at one point in time, any other models?

At one point in time, yeah, we would have been seeing natural gas and just over $2, I think, coming into this year. Yeah.

Okay. And you would say then, the way you project the gaps you tend to lean on third parties when you're doing that, I would assume?

We do look at multiple third-party forecasts as well as coming up with our own internal view on that as well, yeah, but primarily looking at forwards and other fundamental forecasts from third party.

Okay. And on some of the [British source] [ph], I've had a couple of questions from other folks that, I mean, on a project like Strathmore, you spent a lot of CapEx on it already.

But on something like Enchant, you've only spent about $6 million or so. You got the contract with that.

I mean, can you actually technically walk and shelf that project or is it pretty much [too white, given] [ph] the contract?

Well, you definitely can walk, there are penalties associated with walking. So that even without walking, or even without those penalties, it would be a tough decision for us to shelve that project.

Just simply, as I said, it's still above our WACC. You could be delayed, you could do other things to mitigate some of the cost exposure, but no, it's still in our mind remains a viable project.

Okay. All right.

Okay. Thank you very much.

Thanks. Good morning.

I guess the question really focuses on the power market in Alberta has been more coming up on 11 months since we've had the new market structure. Can you give us some color on just how the dialogues have changed with counterparties sort of existing and then perspective on just their understanding of the market?

Maybe the things you were telling them a year ago, which they were not so sure about what has been the flavor from customers and just the willingness to lock in the contracts on a longer-term basis within the province, or to take more spot exposure?

So, Andrew, it's a very interesting dynamic. And the reason why it's an interesting dynamic is, when you look at parties who have been in Alberta for a long time, really the - what's new, isn't what's going on today, this takes us back to the power market that existed before 2014 into 2015.

So, people who, again, were comfortable hedging out positions, and so on and so forth. And, looking at supply demand balance in the future, and anticipating where power prices are going.

This is sort of back to normal, as opposed to the last few years. So those people continue to look at hedging, they continue to look at the forward market, but as well, again, their views as supply demand, I think, everyone knows there's significant supply that's going to be coming into the market in mid part of this decade.

And so, again, looking forward, they come up with their own expectations, new people in the market, people who are - I just recently looking for power supply in Alberta. I would say, there's still continue to be fairly hesitant, seeing higher power prices, and particularly in light of more recent quite a bit lower power prices, and trying to sort out a little bit more of what's going on, but those people who are experienced, again, do recognize this is a relatively simple market, and based on supply and demand economics, plus inputs such as things like natural gas price, and increasing carbon tax.

Okay, thank you for that. And then maybe just on the carbon tax, and really the credits market in general, and any insights you have, or market flavor by jurisdiction would be appreciated, but just the desire for certain customers or even yourselves to effectively buy credits in the market, or effectively engage in activities that are going to give you more offsets versus paying carbon taxes outright.

I know, it gets very technical on all of this, but any flavor you can provide would be helpful.

If you went back, a couple of years in talking about Alberta, in particular, there was a very active market, a lot of trading taking place, a lot of projects and developers who were looking for people to support longer-term carbon sales contracts, a lot of that has slowed down significantly, just simply because there is a little bit more uncertainty. And there ends up being, if you take the poster price of carbon today versus what the market price is, there tends to be discount the ranges from 10% to 25% depending on, when trades may have taken place.

So, there's the market is, I would say, a little bit more uncertain now. And, again, because of that we're seeing a little less activity in terms of people developing carbon credits.

But also in terms of people willing to necessarily buy them, because they aren't at nobody today is going to pay $120 for carbon credit, how to a couple of years that's just not sort of in where people are feeling comfortable in terms of paying for carbon credits. So, again, there is discount in the market and as time gets moves on, and higher prices are being realized.

I think, you'll start seeing the market coming back in more and more activities associated with trying to find ways to produce carbon credits and capitalize on them.

Okay. Thank you.

That's very helpful.

Hi, good morning. Just wanted to go back to a couple of points, starting with the DRIP, I guess, if you can give us just a bit more color on why it made sense to suspend now long after it was turned on.

I guess the question is, is this really a reflection of slowing development maybe relative to where you're able to source last year? Or is it more that you expect maybe asset sales or other financing options to fill future funding needs?

Yeah, thanks for that. If you go back to when we turn the DRIP on in the middle of 2020, if that point in time, we still weren't seeing the forward prices that we're seeing today, we were really moving forward with a number of renewable projects as well as repowering.

So certainly wanted to be in a position where we were raising equity in advance of that spend in order to maintain our credit metrics. So, when you're looking at our FFO to debt with S&P, for example, there is a 17% threshold.

There is a requirement to achieve that even if you are in a period of prolonged construction like repowering. Historically, you may have seen a look-through period when you are in construction, where they would allow you to go below your threshold and take a view as to what the impact of the construction would be.

And that certainly is not the case that they look for. So we knew that maintaining our credit metrics was very important, as we embarked on that construction.

So when you were coming through the middle of last year, still looking at power prices in Alberta for 2022 and 2023, that are well below where we are today, it was prudent for us to include the DRIP to build up that equity. And we had discussed how else we would fund the equity side of those projects and opted to do an offering.

And at this point, that the DRIP is turned off, it'll raise approximately $80 million of funding as well with the $288 million offering. That's in the range of the amount of equity we felt that we needed.

And with cash flows and internally generated cash being much stronger than anticipated, we just don't have the need. Our current FFO to debt is well above 20%.

So we're maintaining a lot of cushion. So at this point, don't need any more equity for the growth that we have, and even have enough balance sheet strength that if we did do incremental funding, not seeing that we would need to access equity to be able to do that.

So, keeping the DRIP on was just being dilutive at this point. So there was just no reason to turn it on and has nothing to do with the plans on asset sales or anything else.

It's more of the internally generated cash flow that's so strong that takes away the need for us to maintain the DRIP.

Okay, got it. That's good detail.

Thank you, Sandra. And maybe just going back to Island Generation for a minute, I know, Brian, you said [because does not looking to] [ph] build new capacity.

But let's say the re-contracting discussions don't really go the way you want them to or even if it's only a shorter-term contract, have you had any discussions with them about installing new generation capacity sooner to replace Island Generation?

So there, the IRP is very clear that they're not looking at installing, whether it'd be batteries, whether it'd be - and then, by the way, battery technology obviously can't replace the capability of Island Generation to run for 6 months. You can't possibly do that with a battery.

So their plans are to just remove Island capacity. I mean, they have some hopes around reduced demand in the province or, well, across the province, but conservation efforts on Vancouver Island.

But on the other hand, they've got great expectations around electrification of vehicles and other things. So, don't see the demand on Vancouver Island going down.

Yet, the capacity that they needed historically they are willing to abandon. And that's why I'm suggesting that in their detailed modeling, which hasn't seen the light of day yet, they are - we would expect they fully are expecting to have increased outages on Vancouver Island, when there are constraints or problems on transmission system, and periods of high heat or extreme cold or dry years from a hydro-perspective, all create strains on Vancouver Island.

I mean, we just don't get it. We just don't understand how you'd be planning for significant increase in outages.

But in any event, and there isn't, there's no indicated path in any way shape or form to replace Island Generation until 2033.

Okay, understood. I mean, it sounds like something has to give at some point one way or another.

So we'll wait for more details on that in the next few months. Thanks.

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

Have a good day, everyone.