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 two.
In today's discussion, we will be referring to various non-GAAP financial measures as noted on slide three. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures which are provided in the analysis of the company's results 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'll turn the call over to Brian Vaasjo for his remarks, starting on slide four.
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 seven renewable development projects that I'll comment on in greater detail later, but briefly, we're seeing cost pressures on our two Alberta solar projects. Also, the completion date for our three North Carolina projects have been extended due to delays in the interconnection process. With our strong financial position, performance and our positive outlook, we are suspending our dividend reinvestment 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 five. 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 six. We continue to see strong prices with an average power price of CAD 100 per MWh 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 CAD 44 per MWh in the third quarter of 2020. In the third quarter, our trading desk captured an average realized price of CAD 75 per MWh that was 27% higher than the CAD 59 per MWh a year ago. The market outlook for the balance of this year continues to be strong with a CAD 99 per MWh 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-CAD 60 per MWh range. For 2023, we're 38% hedged at a contract price in the mid-CAD 50 per MWh. For 2024, we're 21% hedged in the mid-CAD 50 per MWh. This compares to current forward prices of CAD 91 per MWh for 2022, CAD 73 per MWh for 2023, and CAD 62 per MWh in 2024. In addition to the baseload assets, we have approximately 500 MW of gas peaking and wind facilities available to capture upside from higher power prices and price volatility in 2022. On slide seven, 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 CAD 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 were up 7% due to strong performance from the Alberta commercial facilities. Adjusted EBITDA was CAD 286 million in the third quarter, a slight increase of 1% compared to a year ago. We generated CAD 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 eight, I'll discuss the accounting treatment of the Genesee 2 outage and associated insurance recovery. Approximately CAD 25 million of capital costs were incurred in the third quarter, of which CAD 23 million, net of CAD 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 CAD 2 million dollar 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.
An 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 nine shows our third quarter year-to-date performance. Adjusted EBITDA of CAD 830 million was up 13% compared to CAD 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 CAD 75 per MWh compared to CAD 59 per MWh a year ago. Lower corporate expenses also contributed to the higher adjusted EBITDA, mainly due to the acceleration of coal compensation revenue. AFFO was CAD 456 million, up 5% compared to CAD 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 accessed the capital markets this year, raising CAD 288 million in equity and $150 million in debt that we'll 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 nine 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 our 93% availability target at year-end. Sustaining CapEx was CAD 99 million in the first nine months compared to the CAD 80 million-CAD 90 million annual target. We've exceeded the annual target largely due to the Genesee 2 outage and an unplanned rotor purchase at the Arlington facility during a planned outage in the second quarter, of which the latter will cause us to exceed our sustaining CapEx target for the full year. After nine months, we reported CAD 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 CAD 1.1 billion. We generated CAD 456 million of AFFO as for this year and expect full-year results to be modestly above the midpoint of the revised guidance range of CAD 570 million-CAD 620 million. On slide 11, I'll provide a status update on our growth projects. We continue to make progress on approximately CAD 1.7 billion of growth projects under development. This includes developing and constructing seven 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 CAD 57 million compared to CAD 53 million budgeted for Strathmore Solar. While the project costs for Enchant Solar is now CAD 119 million compared to CAD 102 million budget. We have three 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 CAD 500 million committed capital growth target, we continue to explore opportunities with a potential growth announcement 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 a 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 the 2nd. We were 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 the 2nd. All right, Cherise, we can start taking the questions.
Thank you. We will now begin the question-and-answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. The first question comes from Maurice Choy with RBC Capital Markets. Please go ahead.
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?
I guess maybe going to the essence of your question. You know, when we look at our outlook in terms of regulatory stability and in particular, you know, where the 0.37 tCO₂/MWh stringency is going. You know, we've been reassured, you know, again, by the Alberta government, as you know, from direction from the Premier that the 0.37 tCO₂/MWh 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, you know, our peer's decision to basically suspend moving forward with one project and shutting down two other facilities.
Would have to admit the shutting down of the other two facilities is actually a little bit in advance of what we thought when they'd actually be shut down. 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, you know, the stack in the Alberta market. It would have been, you know, one of the most efficient natural gas combined cycles in the province. Since then, Genesee 1 and 2 repowering and, you know, there's been an additional announcement in Alberta, the Cascade project that's going ahead.
All of a sudden there's, you know, 2,500 MW of capacity, much more efficient, that's been put in the queue. That project not going forward was not a surprise to us whatsoever. Didn't believe that with those other results that it was it would be economic even with our outlook. Not a big surprise. And again, you know, in the face of constant reassurance from the Alberta government that the 0.37 tCO₂/MWh will hold, we continue to be positive. Now, the second part of your question is, you know, what happens if it changed or what happens if it if there was a change in the 0.37 tCO₂/MWh?
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, you know, it will reach zero, and it's fully within our economics that over a reasonable period of time, post-2030 that it will get there. If at worst, it's a timing difference. The shorter-term impact, of course, is that, you know, it will impact to a degree on power prices in the province, given the dominance of natural gas generation. You know, the economics of Genesee 1 and 2 would continue to be very solid.
Thanks. 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 CAD 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 cost for the project.
Thanks. 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 slightly above your CAD 80 million-CAD 90 million range. So despite this higher sustaining CapEx, AFFO is still expected to be not just at a midpoint, but modestly above that. What is causing this AFFO to go higher?
There's a few things in there. We are seeing lower financing costs this year. Some of the below-the-line items, but just seeing strong performance in Alberta driving up the cash flow. There are some timing difference in some below-the-line items that impact that differential, if you will.
Okay. Thank you very much.
The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
Thank you. Good morning. Brian, just a follow-up on the Genesee investment. Curious if there's 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.
Where we are in respect of the CCS opportunity is, you know, 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. Results there have been, you know, on balance positive, a slight increase in capital costs, but operating costs and the degree to which it needs power is declining. You know, that's that on balance, the economics of the project are improving. Of course, we move to a FEED study, which we expect to go through next year.
I would say the earliest that we'd be sanctioning the project and given you know that we would require government support and clear indication of government support before we would get into you know approving the project and moving forward, we would expect that to happen you know late next year or early in 2023. In terms of the government activities, the Alberta government's moving forward on the hub concept and looking at different parties to provide carbon sequestration hubs. 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 Canada Infrastructure Bank.
Bringing into play something like Section 45Q before the election was identified by the federal government as, you know, something that they would be doing. We are looking forward to hearing the next steps in terms of that development. They have been receiving, you know, comments from many parties as to what it should look like. 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 that color. Maybe also on C2CNT, do you still expect to have Board approval for the carbon conversion project by year end? Maybe just an update on how the technology continues to prove out here since the last update.
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, 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 three- quarters or 2/3 of the way there.
The challenge that we run into, and I think I've commented on it before, is that there's actually a very long regulatory process to actually get you know, 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, you know, within a material, et cetera. We have to be almost you know, complete, say, for example, with our cement exploration and development. At that point, we start basically you know, a minimum one-year process to get it approved. We can clearly build a Genesee carbon conversion facility within that timeframe.
You know, until we have the precise product nailed down, it just you know is creating a delay for us in building the carbon conversion center. 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. 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, you know, even if you were to secure, say, the CAD 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 shutoff until you're able to secure a couple more developments?
I view this more as a sustained turnoff of the DRIP at this, Pat. 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 CAD 1.7 billion of projects that are currently under development. We've achieved that. To the extent that we have growth, we're seeing strong cash flows, very strong credit metrics. We 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. Going forward with a bit of a story with respect to it.
At this point in time, don't see the need for incremental funding or incremental equity from that in that regard. See it as being a sustained turn off of the DRIP.
Okay, that's great. I'll jump back in the queue. Thank you.
The next question comes from Rob Hope with Scotiabank. Please go ahead.
Hello, everyone. Maybe just in terms of kind of your outlook for the gas market and how you're managing that exposure. You know, can I 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 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. Seeing a lot of volatility as you've alluded to, and have sort of taken that risk off the table by hedging that out materially. Looking at optimizing our fuel and the burn of coal as we optimize the mine plan as we wind down in 2023. Look to sort of lock down those positions and close that exposure.
All right. Thanks for that. Kind of just more perspective in nature. We're seeing some cost pressures, you know, in terms of the renewable power development projects. You know, when you're looking at that, you know, next phase of growth, whether it's that CAD 500 million, how are you bidding into those projects just given the potential that you could see additional or sustained cost pressures?
You know, as we look at you know, various projects, that definitely weighs into it. You know, 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, the, you know, 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. You know, as we approach projects and consider the cycle time, we are cautious on the solar side and definitely consider where the costs are going.
You know, 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. We are expecting this as a relatively short- term excursion in pricing and transportation costs. You know, depending on how far out a project procurement is can have an impact on definitely you know how cautious we are around the bidding process.
All right. Excellent. Thank you.
The next question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead.
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?
You know, I can't, I'm just trying to, you know, a number doesn't come to mind, but, you know, we will be talking about it, you know, in depth at Investor Day. We'll be sure to comment on that element as well, unless you'd like us to follow up with a number.
No, I would assume at this point some of the large lead items you've kind of locked in, you've already spent, you know, CAD 100 million in the quarter. Is it just ongoing labor costs and balance of plant? I'm like, 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 established. Don't see a lot of forward cost pressures on those materials.
Got it. Coming back to the solar projects in Alberta with the cost increases. Any comment in terms of, you know, obviously there'd be some return erosion, you know, whether or not they're still meeting your hurdles and whether or not they become assets, you think about a sell down strategy if you feel like the returns have been compromised a little bit.
We always, you know, as we go through projects and consider projects, we always have in mind, you know, the potential sell down strategy, you know, associated with them. When we look at those two projects, we had in both of them some headroom in terms of returns of, you know, above our hurdle rates. As they're developing now and where we expect them to come in from a cost perspective, you know, they would be coming in, you know, I'll say modestly below our hurdles, but definitely above our WACC. They're not, there isn't any erosion of shareholder value associated with those projects as they sit today.
Got it. That's helpful, Brian. One more on Island Generation. Just the commentary around the medium term, but also sort of highlighting, I think in the MD&A about the book value that you carry in that and some of the, you know, the policy changes that BC Hydro is looking to in terms of phasing out gas-fired generation. Is the assumption sort of now you could get a sort of a three, four-year contract, and at that point Island probably has to be decommissioned and taken offline. Is that what you're trying to kind of outline to us today here?
You know, a lot of this depends on obviously, you know, 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. You know, our view, and this is actually supported in what's been produced by BC Hydro. They have no plans on increasing their capacity to the island or on the island until, you know, 2033. You know, that longer term need is still there.
Not much has changed in terms of our perspective. The recent, you know, indications from the B.C. government about, you know, phasing out natural gas and so on and so forth. You know, that is, you know, that's a position open for comment. We think just as we go through the resource plan of BC Hydro, you know, it'll become clear. We're convinced that in the plans, they are expecting for there to be brownouts in B.C. or, you know, on Vancouver Island because they don't have capacity. That's not good planning. You know, that's not apparent to the citizens on Vancouver Island.
You know, 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. There will be a 10-year contract. Even with the latest indication from the B.C. government in terms of moving off natural gas in terms of power generation, that would provide for an eight-year contract. You know, we're still very optimistic on the back end. Certainly, you know, what we're seeing in terms of the lack of reliability associated with these undersea lines, you know, I think is becoming extremely evident.
One of the things that's, I guess, not 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. 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, Brian. Maybe just one quick follow-up on that then. If the view is that the IRP or the updated IRP or final IRP will be filed by the end of this year, at that point, would you be in a position you think to, you know, come to the table and have an agreement? Or like, would there be negotiations that would take this into mid-2022 before you would actually have a resolution on Island Generation?
So in terms of the medium-term contract, you know, we again, that ends up being a process of negotiation that will take, you know, may well take into next year. A lot of it just depends on how the negotiation goes and you know, I would say, you know, the discussions are positive, but they are infrequent right now. Again, we'll see how that develops. It is as you can appreciate, you know, we're ready to move and negotiate at whatever pace. We're not setting that pace.
Got it.
When it comes to if there's any further extension or that won't be until the IRP is approved or, you know, modified by the BCUC, which isn't expected until, you know, 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.
The next question comes from John Mould with TD Securities. Please go ahead.
Thanks. Good morning, everybody. Maybe just starting with the CAD 500 million target for committed growth. You know, we're 10 months into the year, and I know you noted you could have an announcement before year-end. You know, what has made it challenging to I guess get closer to this target? Is it that you're holding really tight to your return targets? Is it opportunities have been maybe more competitive than you'd hoped? Have you seen some gas-fired deals that might make sense but had some hesitation, you know, just given ESG considerations? You know, can you provide some color on the growth targets?
John, you know, we always sort of hold tight to, you know, our hurdle rates. You know, we don't end up because we're coming to the end of the year and so on. We don't relax. You know, I think as we've always said, you know, that's a target that's out there. You know, 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. You know, it's happened before where we have not hit the CAD 500 million target. From our perspective, you know, that's fine. You know, in the longer term, you know, our average has been, you know, CAD 700 million a year, you know, having set the CAD 500 million target.
The last year was, you know, well over CAD 1 billion, well, CAD 1.7 billion almost in terms of achieving that CAD 500 million target. 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 natural gas opportunities. You know, the market is there, but certainly the traffic isn't. On the natural gas side, there's been, you know, definitely fewer opportunities than we've seen historically in a calendar year. Likewise, from a renewable M&A perspective, there's been, you know, fewer opportunities.
From a development perspective, you know, we continue to be very active from that perspective. You know, actually, frankly, we see where that'll be a lot of our growth coming from in terms of the future from actual development opportunities as opposed to M&A-type opportunities. Just simply the way the market's developing and where we're able to create value is on the development side. You know, especially from a wind perspective or a solar perspective, they're not on the M&A side.
Okay, that's great. Thanks for that context. Maybe just circling back to the Genesee Repowering and CCUS plans. The federal government ran on net zero electricity by 2035. You know, if that moves ahead, that implies there most likely will need to be CCUS in place at Genesee for it to run beyond then. You've pointed out that the CCUS initiative at that project needs government support. If that support isn't of 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, you know, absent some revolution in long-term storage or commercialized small nuclear?
How are you thinking about the repowering project overall, you know, in a case where the CCUS funding picture doesn't pan out the way you and really, you know, industry overall in Alberta is hoping?
I mean, you know, if you take CCUS off the table, you know, the fact of the matter is technology's not here, nor are the policies outside of Alberta here that would make it even possible, technically possible to eliminate natural gas by 2035. I mean, you've seen the recent work by the ISO in Ontario that's saying that, you know, being off natural gas by 2030 is just not in any way, shape, or form practical. You know, they're now being tasked to, you know, what might it look like? When might you know, you be off natural gas?
I think you'll find that, you know, that work will show, you know, probably beyond 2035 is feasible in Ontario, where natural gas is a much smaller component of the overall mix of energy. In Alberta, just it's just not practical. When you see government pronouncements on, you know, being, you know, even off coal by 2030. You know, in Canada, through the equivalency agreements, there are exceptions to that. There are gonna be coal plants operating in Canada beyond 2030. You know, again, the there's a practical element associated with any of these pronouncements. You know, there seems to have been good discussions, not only in Alberta but, you know, across Canada in terms of, you know, what's really a practical solution.
Aggressive solutions, you know, moving forward from a carbon mitigation perspective. You know, what makes sense in each province is different. 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, you know, continue to be there because it meets 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. Then just maybe one accounting clarification for Sandra on the Genesee 2 outage. Just as far as the business interruption insurance timing, I know you won't, you know 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, you know, possible that that doesn't get resolved by the time you report your Q4 results?
You know, our expectation is that we would be able to reflect it. From an accounting perspective, there has to be reasonable certainty around the amount. If that's the case, then you can accrue, you know, all of that expected or a portion of it. At this point, we have confirmation from the insurers that it is a recoverable event. That's the first step. Then the second part of that is just landing on the amount. The complexity 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. It does look at it from a portfolio perspective.
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. It is a difficult modeling exercise, but we've already started that on our side, as has the insurer. We see that progressing quite well. 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.
The next question comes from Ben Pham with BMO Capital Markets. Please go ahead.
Hi. Thanks. Good morning. I have a couple more follow-up questions. On a gas price, you mentioned your hedge over the near term. I'm wondering, have you changed your gas price assumptions long term when you're modeling Genesee 1 and 2 or any other facilities in the province?
When we're modeling out power prices and gas prices, we do continually update those as the fundamentals change. 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. We 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. It's something we continually refresh in our modeling.
Okay. Were you assuming CAD 2 at one point at a time in your models?
At one point in time, yes. We would have been seeing natural gas in just over CAD 2, I think, coming into this year. Yeah.
Okay. You would say then the way you project the gas, you kind of 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. Primarily looking at forwards and other fundamental forecasts from third parties.
Okay. On some of the Alberta solar stuff, I know I had a couple of questions from other folks. I mean, on a project like Strathmore, I mean, you spent a lot of CapEx on it already. On something like Enchant, you only spent about CAD 6 million or so, but you got the contract for that. I mean, can you actually technically walk and shelf that project, or is it pretty much too late given the contract?
Well, you definitely can walk. There are penalties associated with walking. So, you know, that. You know, even without walking, or even without those penalties, it would be a tough decision for us to shelf that project. Just simply as I said, you know, it's still above our WACC. You know, it could be delayed. You could do other things to mitigate some of the cost exposure. No, it's still in our mind remains a viable project.
Okay. All right. Okay. Thank you very much.
The next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Thanks. Good morning. I guess the question really focuses on, you know, the power market in Alberta, and it's been more coming up on 11 months since we've had the new market structure. Could you give us some color on just how the dialogues have changed with counterparties sort of existing and then prospective 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, you know, to take more spot exposure.
It's, Andrew, it's a very interesting dynamic. 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, you know, before 2014, you know, into 2015. People who, again, were comfortable hedging out positions and so on and so forth, you know, looking at, you know, supply-demand balance in the future and anticipating where power prices are going. This is sort of back to normal as opposed to, you know, the last few years. Those people, you know, continue to look at hedging. They continue to look at, you know, the forward market.
As well, again, their views is, you know, supply-demand. As I think, you know, everyone knows, there's significant supply that's going to be coming into the market, you know, in mid part of this decade. Again, you know, looking forward, they come up with their own expectations. New people in the market, people who are, you know, are just recently looking for power supply in Alberta. You know, I would say they're still, you know, continue to be fairly hesitant, seeing, you know, higher power prices. You know, particularly in light of, you know, more recent, quite a bit lower power prices and trying to sort out a little bit more of what's going on.
Those people who are experienced, again, do recognize this as a relatively simple market based on, you know, supply and demand, economics, plus, you know, inputs such as things like natural gas price and, you know, increase in carbon tax.
Okay, thank you for that. 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. 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.
You know, if you went back, you know, a couple of years in talking about Alberta, you know, in particular, you know, 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, you know, longer-term, you know, carbon sales contracts. A lot of that has slowed down significantly, just simply because there is a little bit more uncertainty. There ends up being, you know, if you take the posted price of carbon today versus what the market price is, you know, there tends to be, you know, a discount that ranges from, you know, 10%-25%, depending on, you know, when trades may have taken place.
You know, the market is, I would say, a little bit more uncertain now. Again, because of that, we're seeing a little less activity in terms of people developing carbon credits. But also in terms of people, you know, willing to necessarily buy them. Because they aren't at, you know, nobody today is going to pay, you know, CAD 120 for a carbon credit, you know, out a couple of years. That's just not, you know, sort of in where people are feeling comfortable in terms of paying for carbon credits.
Again, there's discounts in the market, and as time moves on, you know, and higher prices are being realized. I think you'll start seeing, you know, the market coming back and 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.
Once again, if you have a question, please press star then one. The next question comes from Naji Baydoun with iA Capital Markets. Please go ahead.
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 it not long after it was turned on. I guess the question is, Is this really a reflection of slowing development maybe relative to what 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 turned the DRIP on in the middle of 2020, at that point in time, we still weren't seeing the forward prices that we're seeing today. We were well moving forward with a number of renewable projects as well as repowering. Certainly, wanted to be in a position where we were raising equity in advance of that spend in order to maintain our credit metrics. 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.
You know, historically, you may have seen a look-through period when you're 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. That certainly is not the case that they look for. We knew that maintaining our credit metrics was very important as we embarked on that construction. 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. You know, we had discussed how else we would fund the equity side of those projects and opted to do an offering.
At the point that the DRIP is turned off, it'll raise approximately CAD 80 million of funding as well with the CAD 288 million offering. That's in the range of the amount of equity we felt that we needed. 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. At this point, don't need any more equity for the growth that we have. 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.
Keeping the DRIP on was just being dilutive at this point. There was just no reason to turn it on. It has nothing to do with the plans on asset sales or anything else. It's more 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 great detail. Thank you, Sandra. And maybe just going back to Island Generation for a minute. I know, Brian, you said BC Hydro is not looking to build new capacity. Let's say the recontracting discussions don't really go the way you want them to or even if it's, you know, only a shorter-term contract. Have you had any discussions with them about installing new generation capacity sooner to replace Island Generation?
You know, the IRP is very clear that they're not looking at installing, you know, whether it be batteries, whether it be. By the way, battery technology obviously can't replace the capability of Island Generation to run for six months. You can't possibly do that with a battery. No, their plans are to just remove island capacity. I mean, they have some hopes around reduced demand in the province, across the province. You know, conservation efforts on Vancouver Island. On the other hand, they've got great expectations around electrification of vehicles and other things. You know, I don't see the demand on Vancouver Island going down yet. The capacity that they needed historically, they are willing to abandon.
That's why I'm suggesting that, you know, in their detailed modeling, which hasn't seen the light of day yet, we would expect they fully are expecting to have, you know, increased outages on Vancouver Island when there are, you know, constraints or problems on the transmission system. Periods of high heat or, you know, extreme cold or, you know, dry years from a hydro perspective all create strains on Vancouver Island. I mean, we just don't get it. We just don't out and out understand how you'd be planning for significant increase in outages. In any event, 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.
This concludes the question- and- answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.
Okay. If there are no more questions, we'll conclude our conference call. Thank you again for joining us today and for your interest in Capital Power. Have a good day, everyone.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.