Welcome to Capital Power's third quarter 2020 results conference call. Currently, all participants are in listen-only mode. Following the presentation, the conference call will be open for questions. This call is being recorded today, November 2nd, 2020. I will now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead, sir.
Good morning. Thank you for joining us today to review Capital Power's third quarter 2020 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 is 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 the call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on slide number 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 2020 MD&A. I will now turn the call over to Brian Vaasjo for his remarks, starting on slide four.
Thanks, Randy. Good morning. I'll start off with the highlights in the quarter. First, I want to recognize the efforts of our employees who work at our facilities and those who continue to work remotely during the COVID-19 pandemic in helping to achieve strong operating performance and financial results that were in line with management's expectations. With no material changes to our outlook, we are maintaining our financial guidance for 2020 that was announced at our Investor Day last December. We continue to execute our growth strategy with continued progress on renewables and sustainability. In October, we signed a 20-year PPA for three new solar projects in North Carolina in support of our goal to be net carbon neutral before 2050, which I'll discuss shortly.
We've increased our investment in C2CNT from 9% to 25% following our due diligence that demonstrates C2CNT technology produces quality carbon nanotubes on a consistent basis and is scalable. C2CNT is a strategic investment that creates environmental benefits in line with our sustainability strategy. We have an equity option to further increase our equity investment to 40% at the end of 2020. We completed three initiatives that provide the company with financial stability. We completed our longest-dated and lowest-coupon transaction in the Canadian market when we raised CAD 350 million from a very successful 12-year medium-term note offering at very attractive interest rates of 3.147%. This successful MTN transaction signals market confidence in our credit quality and long-term strategy.
In August, we executed a 10-year tolling agreement for our Decatur Energy Center in Alabama, which supports our mid-life gas asset strategy in our view that natural gas generation, along with carbon capture, utilization, and storage technologies, will continue to play a critical role. We reduced our wind service and maintenance costs by an estimated 26% compared to our current agreements by completing the transition to 10-year long-term service agreements with Vestas for the maintenance of our Vestas-equipped wind facilities, which totals over 1,200 MW of capacity. Turning to slide five. As mentioned, we've extended the tolling agreement on our Decatur facility for an additional 10 years, which now expires in December 2032. Since our acquisition of Decatur in 2017, we commenced upgrading the combustion turbines to increase capacity, reduce emissions, improve the heat rate, and to maintain reliability.
We've increased the capacity by 60 MW from the upgrades on two of the three combustion turbines. The third combustion turbine will be upgraded next year, adding another 30 MW of capacity. As part of the tolling agreement extension, we receive payments for 34 MW of additional capacity immediately and up to an additional 79 MW of capacity in 2021. The expected financial contribution from the contract extension will add significant value in the remaining years of the current contract that expires in 2022 and during the 10-year extension. When we acquired Decatur, we believed we had a high probability of recontracting based on its history of recontracting and the need for this facility in the region.
This 10-year PPA extension validates our acquisition strategy of acquiring mid-life contracted natural gas assets that have a positive recontracting outlook and have value beyond the current contract term. We focus on the right assets in the right markets, providing the right service. Turning to slide six, a key part of our strategy in meeting our goal of being net carbon neutral before 2050 is growing our renewable assets. We continue to demonstrate our competitiveness in renewable development projects and the execution of 20-year PPAs. In October, for three new solar development projects in North Carolina with Duke Energy Carolinas. The projects are Hornet Solar, Hunter's Cove Solar, and Bear Branch Solar, with a combined capacity of 160 MW.
We expect constructions for all three projects to begin in late 2021 or early 2022, with an estimated capital cost of CAD 260 million, with commercial operations starting in the fourth quarter of 2022. The three solar projects combined are expected to generate CAD 23 million in adjusted EBITDA and CAD 5 million of AFFO annually on average in the first five years. The 20-year contracts strengthen our contracted cash flows and will increase the overall average remaining life of our contracted facilities. We currently have six renewable projects in advanced development or under construction, totaling approximately 350 MW. By the end of 2022, our renewables capacity will grow to 23%, compared to 16% at the end of 2019. I'll now turn the call over to Sandra.
Thanks, Brian. I'll review our third quarter financial results starting on slide seven. Revenues and other income in the third quarter were CAD 453 million, down 12% compared to the third quarter of 2019, mainly due to the unrealized changes in fair value of commodity derivatives and emission credits and the lower Arlington Valley toll contract. Adjusted EBITDA was CAD 284 million, unchanged from a year ago. The additions of Cardinal Point, Whitla Wind 1, Buckthorn Wind, and strong trading performance were offset by the Arlington Valley toll decrease. Normalized earnings of CAD 0.66 per share were up 10% compared to CAD 0.60 per share in the third quarter of 2019. We generated CAD 221 million in AFFO that was slightly below the CAD 225 million in the third quarter of last year, and AFFO of CAD 2.10 per share was unchanged year-over-year.
Slide eight shows our financial performance on a year-to-date basis compared to the same period in 2019. Revenues and other income were CAD 1.4 billion, up 11% year-over-year, mainly due to stronger portfolio optimization performance, contributions from renewable additions, and additional months of operations at Goreway. Adjusted EBITDA was CAD 735 million, up 9% compared to 2019, primarily due to the acquisition of Goreway and renewable additions that was partly offset by the Arlington Valley toll decrease. Normalized earnings of CAD 1.09 per share was up 4% from a year ago. We continue to generate strong AFFO, including CAD 436 million in the first nine months of the year. That was up 2% year-over-year. AFFO per share was CAD 4.14, up 1% from the same period in 2019. Turning to slide nine, overall, the third quarter financial results were in line with our expectations.
Our trading desk continues to create value by capturing realized power prices above spot power prices. In the third quarter, the average realized power price of CAD 59 per megawatt hour was 34% higher than the average spot of CAD 44 per megawatt hour. The low spot price in the third quarter reflected lower market demand from reduced oil and gas production and the impacts from COVID-19 and softer pricing from a stable base load supply, strong hydro and wind generation, and moderate temperatures. With respect to the Line Loss Rule proceeding, we have recorded a provision of CAD 18 million to date. We have received the first of three invoices, and the payment for the first invoice is due by the end of 2020, and it will have a CAD 6 million impact to AFFO. The payments for the second and third invoices will be due in the first half of 2021.
I'll discuss the Alberta Power market in more detail with respect to the COVID-19 pandemic, as shown on slide 10. The chart shows the year-over-year comparison of the internal load demand based on the actual 30-day rolling averages, and therefore, has not been normalized for weather or other events. For example, the higher demand in February 2019 was driven by extreme cold temperatures in Alberta. As you can see in the chart, COVID-19 was declared a pandemic on March 11th. Following that, power demand in Alberta started to decline in early April following various shutdowns in the province and continued to decline throughout the month of May. The largest year-over-year decline in power demand was about 7%. Demand started to recover in June as the economy reopened and closed the gap to where it's approximately 2% decline in October year-over-year.
At the current rate of recovery, we expect demand to be at pre-COVID-19 levels late in 2021. That further demand disruptions would be addressed by disciplined supply response. Turning to slide 11, I will provide an update on our commercial portfolio positions. For the remainder of 2020, our baseload generation is substantially hedged. At the end of September, we are 13% hedged for 2021 at an average contract price in the high CAD 50 per megawatt-hour range. The lower hedge position in 2021 is due to lower than normal liquidity and the gap between our fundamental pricing view and forward prices. The low liquidity for next year relates to the uncertainty from the expiry of the Alberta Balancing Pool PPAs and corresponding transfer of market share offer control to commercial entities, the continued impact of COVID-19 and oil price reduction on demand and carbon pricing.
With low liquidity, forward prices have been slow to respond. However, since the end of the quarter, liquidity has started to improve and forward prices are strengthening. Current forward prices for 2021 are around CAD 55 per megawatt-hour, compared to CAD 51 throughout Q3. Therefore, if we see forward prices continue to rise, we would increase our hedging activity in the fourth quarter, but expect the percentage hedged entering into next year will be lower than it has been in recent years. For 2022 and 2023, we're 18% and 12% hedged at an average contract price in the low CAD 50 per megawatt-hour range for both years. Current forward prices are in the low CAD 50 per megawatt-hour for both 2022 and 2023. I'll now turn the call back to Brian.
Thanks, Sandra. Slide 12 highlights the progress on our committed capital for growth. To date, we've announced six renewable projects this year that will add 355 MW. This includes the acquisition of Buckthorn Wind in Texas, which was acquired in April. We're building two renewable development projects, Whitla Wind 3 and Strathmore Solar in Alberta, and we're building the three solar projects in North Carolina, which I mentioned earlier. Overall, we've committed CAD 592 million in capital for growth this year in the renewable space. Solid growth and a step towards our goal of being net carbon neutral before 2050. I'll conclude with an update on our performance versus our 2020 annual targets, as shown on slide 13.
Our average facility availability in the first nine months is 94%, compared to the 93% annual target, with major plant outages already completed and with the deferral of the Genesee 2 plant outage to 2021. We expect the average availability to be slightly above the annual target. Sustaining CapEx is CAD 50 million year to date. With the deferral of the Genesee 2 outage, we expect sustaining CapEx will be below the CAD 90 million-CAD 100 million annual target. Adjusted EBITDA is CAD 735 million year to date. Based on our current forecast, we expect 2020 adjusted EBITDA will be above the midpoint of the CAD 935 million-CAD 985 million target range. We generated CAD 436 million of AFFO year to date, compared to the CAD 500 million-CAD 550 million target range.
We are on track to be near the midpoint of the AFFO range, excluding the impacts of the Line Loss Rule proceedings. As previously highlighted, we've had an excellent year for growth, with CAD 592 million of committed capital that exceeds our annual growth capital target of CAD 500 million. Finally, we've developed construction targets for the Cardinal Point and Whitla 2 projects. We completed the Cardinal Wind project on schedule in March and within the U.S. dollar budget range. For the Whitla 2 project, it's currently tracking on budget and on schedule for commercial operation in the fourth quarter of 2021. In summary, a strong quarter of operations and financial results by the Decatur Center 10-year PPA extension and excellent strategic growth in renewable development projects. I'll now turn the call back over to Randy.
All right. Thanks, Brian. Anastasia, we're ready to take questions.
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 David Quezada with Raymond James. Please go ahead.
Thanks. Morning, everyone. My first question here, just on the Decatur contract extension. I'm just wondering if you can just provide maybe some perspective on how the terms worked out, maybe compared to what you had expected at the time of the acquisition back in 2017, and any commentary, I guess, specifically on how it would have affected the returns that you expected on that acquisition at the time.
When we acquired the Decatur facility, we certainly expected that we would be recontracting that facility. From that perspective, that came to fruition. In looking at the particulars, although we had expected and saw that there was an opportunity to expand the capacity of the facility and potentially decrease the heat rate. We weren't precisely clear as to what we expected in terms of an outcome. It's identified as a possibility. As you can appreciate, we've put a lot of capital into that facility, and what I can say is overall, the return on our existing investment and with the additional facilities is consistent with our general expectation of returns on the project. It is different in nature and form than we would have anticipated at the time of the acquisition.
Okay, great. Thank you for that. Maybe just be great to hear your broader thoughts on further natural gas mid-contract life M&A. I know over the past couple of quarters, you've mentioned that activity in that market has been lower. Have you seen that come back at all? Just wondering what your thoughts are on the state of things there.
The market continues to be relatively slow compared to prior years and compared to our expectations. We continue to hear that there are a number of opportunities out there that haven't come to market yet. We'll wait to see what happens. In terms of our view, as I said earlier in the presentation, it boils down to, is there an asset opportunity out there that makes sense in markets that work for us and that one can have a view of long-term contracted ability? Also a very important element is whether or not the particular power facility has the attributes that are either unique in the market or are very deep in terms of if there is a stack of facilities providing that same service.
We do expect natural gas generation as it exists today from the straight energy perspective to decline a bit over time, and certainly we don't want to have one of those facilities that is simply generating electrons because at some point in time, it won't be recontracted. We continue to look at a number of markets and anticipate various opportunities coming forward. Do expect that there will be further mid-life natural gas acquisitions in our future.
Thank you very much for that color . I'll get back in the queue.
The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
Yeah. Good morning, everybody. Brian, I didn't see anything in the release on your application to repower Genesee 1 and 2, maybe just to get your thoughts on how you're thinking about moving forward with construction by next summer and bringing on another call it 600 MW of supply into the market, especially in the context of, I guess, Cascade coming on by 2023 as well, not to mention Suncor's cogen potentially a couple of years later. If you have any preliminary capital cost estimates for the project, that would be great.
As you know, the first step in moving forward on a project like this is to go ahead on the permitting side, which we've done. We're continuing to develop the project, develop the capital costs, although we're getting much closer to having all the necessary pieces of a project in order to do things like seek board approval and announce it's moving forward. As we look at the market outlook, and there is capacity coming into the market, but we expect that there would be a significant supply response associated with new natural gas units coming into the market. What I can say about what we're looking at in terms of the assets is they are extremely efficient. We expect that they'll be the most efficient in the market. Their capital cost is very low utilizing existing facilities.
I would say you can expect that both units would be certainly below CAD 1 billion in terms of putting them in place. So far so good in developing the project. Again, we do expect that there would be a supply response in the market. We'll be continuing to monitor, and at some point, we may well announce that these two repowerings are moving forward.
Okay. That's very helpful. What role do you see Genesee playing longer term in the province's goal of becoming a leading producer of blue hydrogen? I know it's still early days, but maybe you can just confirm if you'll be applying for the 12% capital cost grants that were announced on Friday.
We're still looking at that and its relation to Genesee and what can potentially be done there. It's definitely in a repowering scenario. It can make a lot of sense a lot sooner. The two units that we're looking at repowering, out of the box will be 30% carbon ready, and with a very modest investment of less than CAD 10 million a unit, they can be as much as 95% hydrogen ready. We'll be ready for when the economics and the value is there to move to blue hydrogen or green hydrogen, whichever happens to be available at competitive pricing.
Right. Okay. Sounds like lots of good stuff on the go at Genesee. Maybe just for Sandra here, on the back of your recent successful bond refinancing, how are you thinking about tapping the green bond market going forward, just given some of your recent and, I guess, upcoming investments into new renewables? Could you look at green bonds for, say, refinancing your 2021s next year?
Thanks, Pat. Yeah, we continue to look at both green bonds and sustainability-linked bonds and give both considerations to that. I think as we continue to build out our integrated reporting and our ESG targets, that fits very nicely with being able to execute fairly seamlessly on a sustainability-linked bond. We have had some discussions around the refinancing next year and whether that would be an opportunity to do it. We'll continue to monitor that. We do see that that will be in our future, whether it is a project-level green bond or a balance sheet financing using sustainability-linked metrics.
Okay, great. I know you previously run the math at looking to crystallize the value of your off-coal payments. Have you taken another look at that recently just to see if that might make sense and allow you to potentially turn the DRIP back off?
We haven't looked at that recently, but I think we would be of the same view that there's not a lot of upside to crystallizing that. With the DRIP, we do have a lot of internal spend on our current assets as well as some development projects, so that just seemed to be an efficient way to generate equity to fund that. I think we'll continue with that for the foreseeable future.
Okay, great. Appreciate all the comments. I'll leave it there.
The next question comes from Robert Hope with Scotiabank. Please go ahead.
Morning, everyone. First question is just on the Alberta power market outlook and we did see you increase your overall hedge position there. As we've moved through October with the volatility and the pricing that we've seen, are we getting towards your notional view of what 2021 looks like? Overall, is the market behaving as you'd expect, and is it just a view that the forward market's not reflecting the fundamentals?
I think what our expectation was in Q3, that with the RRO auction starting in September, that we would start to see an increase in liquidity and pricing. That didn't happen through the end of the quarter. As you mentioned, we are starting to see prices move forward or upwards in the last couple of weeks. It's currently at CAD 55 a megawatt hour. Market participants are starting to take a price view. We would expect to continue to see forwards move to be more in line with our expectations. We still think that there's a bit of a gap even at CAD 55, starting to see some momentum in the right direction in Q4.
It kind of appears that your kind of fundamental view of 2021 is kind of, what, high 50s?
That would be generally in the range, yes.
Okay. Then just south of the border, any commentary on the potential to extend the life of Southport, just given some permitting challenges there, or what is the strategy for that unit?
As we look forward, and we had for a couple of years looked at recontracting those facilities, both Southport and Roxboro, as well as there were other entities in the market who were looking at potentially buying those assets and utilizing a different nature of fuel and so on. Unfortunately, neither recontracting nor selling those assets came to fruition. Our expectation is that next year, those facilities will likely cease operations.
All right. Including Roxboro, not just Southport?
That is correct.
All right. Thank you.
The next question comes from Mark Jarvi with CIBC. Please go ahead.
Yeah. Thanks. Good morning, everyone. First question, just on the portfolio optimization revenue. Can you give us a split of how much comes from power sales and how much maybe in a quarter like this, lower generation, did you resell gas for profit?
Yeah, I think that the natural gas optimization was about CAD 9 million in the quarter, and the rest would have been from power optimization.
Okay. Just on the gas cost, I think it says as close as you guys are substantially hedged or largely hedged on your fuel cost for 2021, can you give us any sort of direction of where you are relative to where gas forward prices are for 2021, just how much of a buffer you've created versus where the spot market has gone? Then longer term, if you guys are thinking about extending the duration of any gas hedges or procurement?
Our gas procurement is dependent upon our coal-to-gas conversion timing and gas usage in general. We have locked in prices for most of next year on natural gas at a price that is below where the current forwards are. Still around that CAD 2 gigajoule range.
Okay. That's very helpful. The question is around the solar projects in the Carolinas. Can you just maybe give us some background in terms of how you got involved in those projects, at what stage? Given that it's obviously competitive for renewable projects in the U.S., would you guys look to continue to hold your equity interest all the way through to the end of life or would you consider like a sell-down to enhance return?
The history behind those three solar projects is that there was a competition, an RFP out by Duke Carolinas for 600 MW of renewables. We, through some relationships, and we are in North Carolina and actually have a solar farm there. We have some profile in the state. We teamed up with a junior developer who had some projects, and we went through due diligence and came to the conclusion that these two projects had a very good probability of moving forward. From almost nine months ago, started working to prepare a bid and put sort of our best foot forward, and we were successful on the three projects that we put forward. In terms of sell-down, and our view of the renewables portfolio that we have on both sides of the border is there is significant value there.
At times, whether it's looking for a source of capital or when we look at optimizing the returns that we get from assets, we would certainly consider selling down projects to a lower level of interest. In all likelihood, if we were going in that direction, we'd bundle one or two projects together and have those as a package, because we would, again, look for more of a strategic purchaser, somebody who, obviously a financial entity that would work with us on a couple of projects and as we move forward would be somebody who would be a natural buyer of other interests of ours. Do believe that sometime in our future we will look to selling down our interests again when there's a capital requirement or, as you say, to optimize the returns associated with a particular project.
Okay. Thanks for that, Brian. My last question, just going back to Pat's question about Genesee Repowering. Can you guys remind us what the useful life is or end-of-life assumption would be around a conversion versus repowering and where you guys are in terms of clarity on useful life?
When you look at the useful life as it relates to repowering, we're kind of looking through a lens at maybe another 20 years in terms of the economics of that kind of a facility. However, I would have to emphasize that moving to hydrogen or carbon capture and utilization would significantly extend that life beyond the 20 years. Again, just in a kind of a status quo world, we would see a 20-year life as a reasonable economic expectation. When you look at dual-fuel, we would see that as being potentially a little bit shorter. As we've said for the last couple of years, our view is that eventually those units would turn into repowered facilities at some point in time, and it was just a matter of when.
Okay. Thank you.
The next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Thanks. Good morning. Probably a two-part question to start, and it's really with just natural gas prices rising. How do you think that changes market dynamics with the market transition on January 1? Also related to that is just your ability to engage in longer-term contracts within the province.
With respect to the first part of the question for natural gas prices and the dynamics. What we've seen coming through this year with higher natural gas is just lower utilization of our gas facilities. I expect that at some point, we'll see rises in pricing that'll bring those spreads back and be able to utilize our plants in more historical fashion. As far as long-term natural gas hedging, I don't know, Brian, if you want to answer that question.
We've looked at long-term hedging associated with natural gas. Certainly when we're in a dual-fuel world, that can make that a little bit difficult, because what we don't want to do is just straight speculate on the price of natural gas as opposed to hedging natural gas for what we expect to be our own use. We have looked at, again, from time to time, is there some portion that we could enter into a long-term hedge arrangement. We've concluded that at least for the time being, that's a strategy that with the volatility in the market, doesn't necessarily work in our favor. Having said that, we have gone out two and three years and can hedge significant portions of our anticipated natural gas demand, and we'll continue to do so.
Okay. That's helpful. My second question really just relates to renewable valuations we've seen in the market. Obviously very topical. You've got a fairly large renewable portfolio of your own. I guess the question is really directed to Sandra. Do you think about rejigging the way you present your financials to highlight that embedded value in the company to a much greater degree?
Yes, we've actually had that conversation around whether or not we start presenting in that exact way. In some of our presentation decks, we do actually break out our EBITDA by fuel type. It is something that we are sort of evolving towards and will give more consideration to in our MD&A and other reporting materials going forward.
That's great. Thank you.
The next question comes from Ben Pham with BMO. Please go ahead.
Hi. Thanks. Good morning. I had a follow-up question on the Gen 1-2 repowering. Obviously, you're going through the public stakeholder process now. You're filing an application late this year. I'm wondering, is the plan similar to peers where you look to layer on some contracts on these repowerings, or you're open to spot? The second part of it is the CapEx you quoted seems or is dramatically lower than with one of your peers. I think it's almost 30%, 40% lower. Is this really just the age of the facility, or is it your relationships with the suppliers that's driving that, or is it something else?
Firstly, Ben, in terms of the contracting up the facilities, we would certainly, if there was an opportunity to contract them up for some portion, would definitely consider that. Having said that wouldn't be the basis upon which we'd be moving forward. In terms of the capital cost side, I think all I can really say is in bringing together a very well-maintained Genesee units with the latest in technology, results in actually a very low-cost, extremely efficient unit. It sort of is the sum of the pieces. We've actually done, not me for sure, but there's been some very creative engineering that's gone into our ability to have such a low capital cost and to have, I would say at the end of the day, outstanding performing units.
Okay. Maybe my next question, I am not sure if it's for you, Brian or Sandra, on capital recycling, and maybe correct me if I'm wrong, is I think for the longest time you've maybe not been against recycling, but maybe it's been more of a grow, acquire, develop. Is this, especially on the renewables side, so is this a subtle change in how you view capital allocation with asset sales? Is it the size of the renewable portfolio getting bigger now you can look at that? Is this just simply maybe the need for CapEx like Gen 1 and 2 and other opportunities is rising in years ahead?
I would just comment. Over time, we've always looked at recycling capital through selling assets. A couple of times in history, we've done that. Certainly as we look forward, the sale of assets is certainly something that will be considered at the time when we're looking at specific needs for capital. What's been a bit of an impediment over the last couple of years is, as we look forward to the EBITDA expectations or expectations around AFFO for shares, certainly the sale of an asset results in generally a decline as we move forward. That modest dilution is one of the things that has impacted on our decisions of recycling capital. Again, it's always on the table.
Certainly with a broadening and deeper portfolio of renewable assets, it does increase the prospect that at some point we may sell all or part of an interest in a facility.
Okay. You're still of the mindset that it doesn't make sense to carve out the renewables into a public entity?
I think still at this point, it's just too small. There wouldn't be enough market traction. When you look at the balance of the organization, likewise, it would be significantly smaller. I think both would be challenged in the market at this point. You certainly need considerable size before that makes sense.
Okay, great. Thanks, Brian.
Once again, if you have a question, please press star then one. The next question comes from John Mould with TD Securities. Please go ahead.
Good morning. Maybe just going back to the solar projects in North Carolina. They're costing about CAD 260 million, but have neutral AFFO accretion in the first five years, clearly with other benefits like 20-year PPAs and growing your renewables platform. When deciding to proceed with investments of this nature, how are you approaching the balance between driving growth in per-share metrics like AFFO, returns relative to your hurdle rates, which I know you do meet on this investment, and other benefits like lengthening contract life, your overall portfolio, and growing renewables?
Yeah. We certainly take all of those elements into account. With respect to the economics, we see it as being neutral or slightly positive in that it's still a couple years out, and we have to get through the construction period and finalize our actual financing on that. Expect that we'd be 40% tax equity with the full ITCs at 30%. With respect to the balance of the financing, see this as the kind of project where we could take on a partner, which would impact our economics as well. Probably targeting at this point that it's most likely to be a few cents accretive, on average in the first few years. Neutral at worst.
I think that we've characterized it conservatively in our communications, but we would balance the ESG impacts as well as the average contract life and the economics all as part of that decision.
Okay. Thanks for that. On C2CNT, can you just provide an update on how nanotube production is going at Shepard? Any updates on concrete testing and how the potential start time for construction on the Carbon Conversion Centre at Genesee is evolving?
In terms of what's happening at the Shepard site, as I had indicated in prior quarters, COVID and other things have slowed down progress on the site in general, not just with us, but XPRIZE, et cetera. As it sits now, the facility is ramping up. When I mean ramping up physically, pieces are being put in place for it to get to full anticipated production, and that process is going well. In terms of the cement side of it, there's been a couple of different nanotube developments as well, specific nanotube developments as well as means of dispersing the nanotubes in concrete, which have been developed and are undergoing further testing before a batch is put together and sent over to Lehigh for their testing. There's a sort of an intermediate testing that's taking place right now.
Things are going well from that perspective. As we look forward, again, with everything being kind of pushed off, not sure when we'd necessarily put the shovel in the ground, but our expectation is sometime in the fourth quarter of next year, we'd start production out of the Genesee Carbon Conversion Centre.
Okay. Great. Just maybe lastly, on geothermal. As you know, the government of Alberta is looking to put a geothermal policy in place. Just wondering what you think the prospects are for geothermal power in the province, and whether you consider dipping your toe in the right opportunity.
Geothermal, we've looked at a couple of times over the last number of years. We understand there's a pretty good geothermal regime in southern Saskatchewan and certainly some good geothermal prospects in British Columbia. Our understanding is in Alberta, maybe not as much. A lot of it depends on the geology and depth and so on. I guess, again, when we've looked at it a couple of times, don't see a high probability. Again, that was based on the technology at those times. Again, that's a little bit dated. Would we look at it? We would certainly consider it if it turned out to be a viable technology and one that could generate, obviously, renewable energy at significant volumes, that it's worth making the investment in the technology.
You may recall that we were involved in small hydros a number of years ago and had a number of them, but came to the conclusion that to take on a technology, you have to have some view that it is going to be a significant volume of that technology, because to operate and manage those facilities and develop them, you actually need to know what you are doing. It would be more than just a one or two-site view of ours. We would have to believe that it is actually leading to the development of a business.
Okay. I appreciate that color . Those are my questions. Thank you.
The next question comes from Maurice Choy with RBC Capital Markets. Please go ahead.
Thank you. Good morning. My first question is about a commentary you made in the reports, with regards to Genesee 1-2 having a lower dispatch by the Balancing Pool this year, even though there's been no planned outages. Any thoughts as to why this is so? Do you see that this is the Balancing Pool acting more commercially, their view of dark spreads or any other reason?
Yeah, I think it's just simply that they have the carbon tax obligation on those units. As we saw spot prices being relatively low in the province, it got to the point where they were looking at it commercially and dispatching it down would be our assumption on what they were doing there.
I guess just to follow up to that, if those carbon tax costs then become yours as of next year, does that mean that the production levels is indicative of what you expect for the full year?
The prices going into next year we see as being relatively higher than what we have in the forwards this year. Expect that those units would be economic at the prices that we're seeing today, even with the carbon tax obligation.
Second question, I just want to look ahead to, I guess, December when you traditionally put out your guidance for the following year, as well as potentially set out your dividend objective beyond 2022. Slide 11, you've highlighted a number of uncertainties for next year. Can you broadly discuss where you see clarity improving over the next four to five weeks ahead of early December? Should we expect a different type of guidance next month?
Sorry, guidance with respect to the dividend increases in particular?
With regards to 2021 earnings as well as dividend guidance beyond 2022.
Yeah, I think at this point our view would be that we would not be extending the dividend guidance beyond what we have given out to 2021 and 2022, until we start to see that we've got the growth to support incremental increases and just look at some of the other uncertainties going forward. With respect to the uncertainties that we speak about for 2021, I think we're starting to see some clarity around power prices this past month, so we'll continue to monitor that throughout the next number of weeks, and as well with carbon taxes, whether or not there's a rise in carbon tax or if it stays at CAD 30.
We will be looking at our financial impacts of both those scenarios going forward, but I'd say those are sort of the two greatest uncertainties around next year and of course, demand in the province as well. Just with respect to the pandemic and where that's going and the implications on demand in the province. Some of those will start to clear, some of them will be throughout 2021 before we get a better indication as things unfold.
I guess just a final follow-up on that comment that we don't expect, or at least there's no view of an increase beyond 2022 until you see growth to support such an increase. Would you at least be able to reaffirm that dividends won't be cut? With that, I suppose, would you expect us all to assume it'll be flat for now?
There's no indication that there's any need to cut dividends, certainly that is not something that we would be announcing in any regard. Still maintain the guidance that we've given. It's just a matter of seeing growth that would support increases beyond that. In the past, we've given guidance quite far out with respect to dividend increases. That was just to give the market an indication that we didn't see this as a one and done, and that we did expect continuation of the increases. I think that that message has now been received, you'll probably see us signal dividend increases closer to the expected time. Right now we still are a couple of years out, so kind of see that timeline of advanced signaling compress in the coming years.
Great. Thank you very much.
The next question comes from Naji Baydoun with Industrial Alliance Securities. Please go ahead.
Yes. Hi, good morning. Just on the pace of growth in renewable projects, certainly accelerated this year. Do you think this is something you can repeat going into 2021 and beyond? Related to that, what does the current pipeline of renewable projects look like?
As we look forward and recognize, and I think as we've discussed before, we have two sources of renewable projects. One is associated with the existing pipeline we have that comes to fruition. The other part is working with other developers, typically junior developers, in looking at sites and moving forward. When you look at those two, certainly, and you look at what we have underway, it's kind of a mix of the two. We would expect that to continue going forward. We have had a very good year, and the year's not over yet. We do anticipate that we'll have continued success as we move through the next couple of years on developing and building renewable projects.
Okay. I'm sure you've also given some thought to maybe accelerating that via M&A. Are you currently looking at any either acquisitions of junior developers or late-stage renewable projects to really sort of push on the renewables front? Or is the M&A focus still on natural gas for now?
We do look at M&A opportunities on the renewable side. Typically what we find is that, just simply because of the nature of the acquisitions and where there's a significant amount of financial interest, we tend not to be competitive. No, we definitely look at M&A opportunities related to renewables. There have been, actually this year, the Buckthorn acquisition is an example of one. At all times you can expect that we're looking at both natural gas and renewable acquisition opportunities.
Okay, thanks for that. The rest of my questions were already answered. Thank you.
This concludes the question and answer session. I would like to turn the conference back over to the presenters for any closing remarks.
All right, thank you. We will be hosting our annual investor day event on the morning of December the 3rd, and it will be a conference call and webcast. More details will be announced in the coming weeks. Thanks 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.