Capital Power Corp

Good morning, and 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 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 second quarter 2020 MD&A. I'll now 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 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're 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 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 Decatur Energy Centre in Alabama, which supports our mid-life gas asset strategy and our view that natural gas generation, along with carbon capture, utilization and storage technologies will continue to play a critical role. And 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 1200 megawatts of capacity.

Turning to Slide 5, 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 and improve the heat rate and to maintain reliability.

We've increased the capacity by 60 megawatts from the upgrades on two of the three combustion turbines. The third combustion turbine will be upgraded next year, adding another 30 megawatts of capacity.

As part of the tolling agreement extension, we receive payments for 34 megawatts of additional capacity immediately and up to an additional 79 megawatts 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 re-contracting based on its history of re-contracting and the need for this facility in the region. This 10-year PPA expansion validates our acquisition strategy of acquiring mid-life contracted natural gas assets that have a positively contracting 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 6, a key part of our strategy and 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 megawatts.

We expect constructions for all three projects to begin in late 2021 or early 2022, with estimated capital cost of 260 million, with commercial operations starting in the fourth quarter of 2022. The three solar projects combined are expected to generate 23 million in adjusted EBITDA and 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 megawatts.

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 7.

Revenues and other income in the third quarter were 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 total contract. Adjusted EBITDA was 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 $0.66 per share were up 10% compared to $0.60 per share in the third quarter of 2019.

We generated 220 1 million in AFFO that was slightly below the 225 million in the third quarter of last year, and AFFO of $2.10 per share was unchanged year-over-year. Slide 8 shows our financial performance on a year-to-date basis compared to the same period in 2019.

Revenues and other income were 1.4 billion up 11% year-over-year, mainly due to stronger portfolio optimization performance, contributions from renewable additions and additional months of operations that Goreway. Adjusted even though was 735 million up 9% compared to 2019, primarily due to the acquisition of Goreway and renewable addition that was partly offset by the Arlington Valley toll decrease.

Normalized earnings of $1.09 per share was up 4% from a year ago. We continue to generate strong AFFO including 436 million in the first nine months of the year that was up 2% year-over-year.

AFFO per share was $4.14, up 1% from the same period in 2019. Turning to Side 9, overall, the third quarter financial results were in line with our expectations.

Our trading desk continues to create value by capturing real life power prices above spot power prices. In the third quarter, the average realized power price of $59 per megawatt hour was 34% higher than the average spot up $44 per megawatt hour.

The lower 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 baseload supply, strong hydro and wind generation and moderate temperatures. With respect to the Line Loss Rule proceeding, we have recorded a provision of 18 million to date.

We've received the first of three invoices and the payment of the first invoice is due by the end of 2020 and it will have a $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 11.

Following that power demand in Alberta started to decline in early April following various shutdowns in the province and continue 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 towards it's approximately 2% decline in October a year-over-year. At the current rate of recovery, we expect demand to be pre-COVID-19 levels late in 2021 and that further demand disruptions would be addressed by disciplined supply response.

Turning to Slide 11, I'll 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're 13% hedged for 2021 at an average contract price in the high $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 impacts 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 board prices for 2021 around $55 per megawatt hour compared to $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 were 18% and 12%, hedged at an average contract price in the low $50 per megawatt hour range for both years. Current forward prices are in the low $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 megawatts. This includes the acquisition of Buckthorn Wind in Texas, which was acquired in April, we're building two renewable development projects Whitla 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 $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 planned outages already completed and with the deferral of the Genesee 2 planned outage to 2021, we expect the average availability to be slightly above the annual target. Sustaining CapEx is 50 million year-to-date.

With a deferral of the Genesee 2 outage, we expect sustaining CapEx will be below the $90 million to $100 million annual target. Adjusted EBITDA is 735 million year-to-date.

Based on our current forecast we expect 2020 adjusted EBITDA will be above the midpoint of the 935 million to 985 million target range. We generated 436 million of AFFO year-to-date, compared to the 500 million to 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 proceeding. As previously highlighted, we've had an excellent year for growth with 592 million of committed capital that exceeds our annual growth capital target of 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 US 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 Centre 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 Bryan. And Felicia we're ready to take questions.

Thanks. Good 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 what have affected the returns that you expected on that acquisition at the time.

So when we acquired the Decatur facility, we certainly expected that we would be re-contracting that facility and so from that perspective, that came to fruition. And looking at that particulars although, we had expected and saw that there was an opportunity to expand the capacity of the facility, and potentially increase the - or decrease the heat rate, we weren't precisely clear as to what we expected in terms of an outcome.

So it was 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. But it is different in nature and form than we would have anticipated at the time of the acquisition.

Okay, great. Thank you for that.

And then maybe just would be great to hear your broader thoughts on further natural gas, mid contract life, M&A. I know, over the past couple quarters, you've mentioned that activity in that market has been lower, have you seen that come back at all, and just wondering what your thoughts on the state of things there.

So the market continues to be relatively slow compared to prior years and compared to our expectations, though, we continue to hear that there are a number of opportunities out there that haven't come to market yet. So 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. And also, very important element is whether or not that 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, because we do expect natural gas generation as it exists today from the State Energy perspective to the client 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 re-contracted. So we continue to look at a number of markets and anticipate various opportunities coming forward.

So do expect that there will be further mid-life natural gas acquisitions in the future.

Thank you very much for that color. I'll get back in the queue.

Yeah. Good morning everybody.

Brian, I didn't see anything in the release on your application to repower Genesee 1 and 2, so maybe just get your thoughts on how you're thinking about moving forward with construction by next summer. And bringing on another cold 600 megawatts of supply into the market, especially in the context of, I guess, Cascade coming on by 2023 as well.

Not to mention some course cogent, potentially a couple of years later. And if you have any preliminary capital cost estimates for the project that would be great.

So 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 moving forward. As we look at the market outlook and there is capacity coming into the market, but we expect there would be a significant supply response associated with new natural gas units coming into the market.

What I can say about the - 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 and their capital cost is very low, utilizing existing facilities.

So I would say you can expect that both units would be certainly below a $1 billion in terms of putting them in place. So far so good in developing the project and again, we do expect that there would be a supply response in the market and we'll be continuing to monitor and at some point, we may well announce that these two repower ends are moving forward.

Okay, that's very helpful and what role these see Genesee playing longer term in the provinces 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.

So we're still looking at that and its relation to Genesee and what can potentially be done there. So 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 $10 million in the unit, they can be as much as 95% hydrogen ready. So we'll be ready for when the economics and the value is there to move to blue hydrogen or green hydrogen, while whichever happens to be available at competitive pricing.

Right, okay, sounds like lots of good stuff on the go Genesee. I guess 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, so we continue to look at both green bonds and sustainability linked bonds and give both considerations to that.

And 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.

So 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 bouncing financing using sustainability linked metrics.

Okay, great. And I know you've previously run the math that 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 spends 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. So I think we'll continue with that for the foreseeable future.

Okay, great. Appreciate all the comments.

So I'll leave it there.

Good morning, everyone. First question is just on the Alberta power market outlook.

And just 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 kind of notional view of what 2021 looks like?

And overall is the markets behaving as you'd expect? And is it just the view that the forward markets, not reflecting the fundamentals?

Yeah, I think what our expectation was in Q3 that with the RRO options, starting in September, that we would start to see an increase in liquidity and pricing. But that didn't happen through the end of the quarter.

But as you mentioned, we are starting to see prices move forward or upwards in the last couple of weeks. So currently at $55 a megawatt hour and market participants are starting to take a price view.

But yeah, we continue to see - we would expect to continue to see forward move to be more in line with our expectations. So we still think that there's a bit of a gap even at 55, but starting to see some momentum in the right direction in Q4.

And so it kind of appears that your kind of fundamental view of 2021 is kind of what high 50 is that?

That would be generally in the range, yes.

Okay. And then just south of the border any commentary on kind of the potential to kind of extend the life of Southport just given some permanent challenges there, or kind of what is the strategy for that unit.

So as we look forward - we had for a couple of years looked at and re-contracting those facilities both Southport, Roxboro, 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. And unfortunately, neither re-contracting nor selling those assets came to fruition.

So our expectation is that next year, those facilities will likely cease operations.

All right, so including Roxboro and not just Southport?

That is correct.

All right thank you.

Yeah, thanks. Good morning everyone.

First question, just on the portfolio optimization revenue, can you just give us a split on how much come from power sales and how much money in a quarter like this lower generation? Did you resell gas for profit?

Yeah, so I think that the natural gas optimization was about $9 million in the quarter and the rest would have been from power optimization.

Okay. And just on the on the gas costs, and I guess in the disclosure you guys are substantially hedged are largely hedged on your fuel costs for 2021.

Can you give us any sort of direction of where you are relative to where gas prices are for 2021, just how much of a buffer you've created versus where the spot market has gone? And then longer term if you guys are thinking about extending the duration of any gas hedges or procurement.

So our gas procurement is dependent upon our fuel to gas conversion timing and gas usage in general. So we have locked in prices for most of next year on natural gas at a price that is below where the current forwards are, so still around that $2 gigajoule range.

Okay, that's very helpful. And then the question is around the solar projects in the Carolinas.

Can you just give us some background in terms of how you got involved in those projects? At what stage and given us obviously, competitive for renewable projects in the US, when you guys look containable, your equity interests all the way through to the end of life or when you consider like a sell down to enhance returns.

So the history behind those three solar projects is that there was a competition, an RFP out by Duke Carolina's for 600 megawatts of renewables. We through some relationships and then - we are in North Carolina and actually have a solar farm there.

So we have some profile in the stage, and 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. So from almost nine months ago started working to prepare a bit and put sort of our best foot forward and we were successful on the three projects that we've put forward.

In terms of sell down, in our view of the renewables portfolio that we have on both sides of the borders, there is significant value there. And 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 with low bar. So I 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 a lot, Brian. And then my last question, just going back to Pat's question about Genesee and re-powering, can you guys remind us what the useful life is or end of life assumption would be around conversion versus repowering and where you guys are in terms of clarity on useful life.

So when you look at the useful life, as it relates to repowering, we're kind of looking through a lens and 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 in the utilization would significantly extend that life beyond the 20 years.

So 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.

But as we've said since - 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.

Thanks. Good morning.

So 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 Jan 1, and then also related to that is just your ability to engage in longer term contracts within the province?

So with respect to the first part of the question, for natural gas prices, and the dynamic, so what we've seen coming through this year with higher natural gas it's just lower utilization of our gas facilities. But expect that at some point see rises in pricing that'll bring those spreads back and be able to utilize our plans in more historical fashion.

But 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. And certainly when we're in a dual-fuel world that 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.

And we have looked at again, from time to time, is there some portion that we could enter into a long-term hedge arrangement. And we've concluded that 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 hedged significant portions of our anticipated natural gas demand and will continue to do so.

Okay, that's helpful. And then my second question really just relates to renewable valuations we've seen on the market.

Obviously, very topical, you've got a fairly large renewable portfolio of your own. And then I guess the question is really directed to Sandra, do you think about rejigging the way you present your financials highlight that embedded value on the company to a much greater degree?

Yes, we've actually had that conversation around whether or not we start to present in that exact way and in some of our presentation decks, we do actually break out our EBITDA by fuel type. So it is something that we are sort of evolving towards and we'll give more consideration to in our MD&A and other reporting materials going forward.

That's great. Thank you.

Hi, thanks, good morning. I had a follow up question on the Gen 1 and 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 the powering as reopen to spot and then the second part of it is, is the CapEx you quoted aims at - or is dramatically lower than - with one of your peers and it's almost 30%, 40% lower. So there - it's really just the age of the facility or it your relationships with the suppliers that's driving or is it something else?

So firstly, Ben in terms of the contracting of the facilities, we would certainly, if there was an opportunity to contract them up to some portion would definitely consider that. Having said that, that wouldn't be the basis upon which we'll be moving forward.

In terms of the capital cost side, I think all I can really say is in bringing together very well-maintained Genesee units with the latest in technology results in actually a very low cost, extremely efficient unit and it sort of some of the pieces that we have actually done. [indiscernible], but there's been some very, very creative engineering that's gone into our ability to have such a low capital cost and to have, I'd say, at the end of the day, outstanding performing units.

Okay. And maybe my next question actually is for Brian or Sandra on capital recycling and maybe correct me if I'm wrong, I think for longest time, you've maybe not been against recycling, but maybe it's been more of a grow, acquire to evolve.

And so is it - especially on renewables side, so is it a subtle change in high yield capital allocation with asset sales, is that the size of the renewable portfolio getting bigger now, you can look at that or there's just simply maybe the need for CapEx like Gen 1 and 2 another opportunity that is rising in the years ahead.

So I would just comment, over time, we've always looked at recycling capital through selling assets. And a couple times in history, we've done that.

And 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, AFFO per share, certainly the sale of an asset, results in a, generally a decline is as we move forward.

So it's that modest dilution is one of the things that has impacted on our decisions of recycling capital. But again, it's always on the table and certainly with a broadening and deeper portfolio of renewable assets, it does make - it does increase the prospect that at some point we may sell all or part of an interest in facility.

Okay and you're still of the mindset 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 and then when you look at the balance of the organization, likewise, it would be significantly smaller and I think both would be challenged in the market at this point you'll certainly need considerable size before that makes sense.

Okay, great. Thanks.

Brian.

Good morning, maybe just going back to the solar projects in North Carolina, they're costing about 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 and 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 contracts life, your overall portfolio and growing renewables?

Yeah, so we certainly take all of those elements into account, but with respect to the economics you see it as being neutral or slightly positive and that it's still a couple years out, and we have to get through the construction period and finalize our actual financing on that. So expect that we would be 40% tax equity with the full ITCs at 30%, but with respect to the balance of the financing, see this is the kind of project where we could take on a partner, which would impact our economics as well.

So probably targeting at this point that it's most likely to be a few cents accretive on average in the first few years, but neutral at worst, so 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 of all as part of that decision.

Okay, thanks for that. And then on C2CNT, can you just provide an update on how nano to production is going and Shepard?

Any updates on concrete testing and how the potential start time for construction on the Carbon Conversion Centre at Genesee is evolving.

So in terms of what's happening at the Shepard site, so as I 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. So as it sits now, the facility is ramping up.

And 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 as - specific nanotube developments as well as no means of dispersing the nanotubes in concrete, which have been developed and are undergoing further testing before kind of batch is put together and sent over to Lehigh for their testing. So there's a sort of intermediate testing that's taking place right now, so 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 a 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. And then just maybe lastly on geothermal, the government Alberta is looking to put a geothermal policy in place.

Just wondering what the - what you think the prospects are for geothermal power in the province? And whether you consider dipping your toe in the right opportunity?

So geothermal, we've looked at a couple of times over the last number of years and 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 and a lot of it depends on the geology, depth and so on.

And I guess again, when we've looked at it a couple of times don't see a high probability, but again, that was based on the technology at those times, and again, yeah, it'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 volume, that it's worth making the investment in the technology.

You may recall that we were involved in small hydro's a number of years ago and had a number of them, but came to the conclusion that you actually - to take on a technology, you have to have some view that it's 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're doing. And we would be more than just a one or two site view of ours.

We'd have to believe that it's actually leading to the development of a business.

Okay, I appreciate that color. Those are my questions.

Thank you.

Thank you and good morning. My first question is about a commentary made in the reports with regards to Genesee 1 and 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 stock spreads or any other reasons?

Yeah, I think it's just simply they have the carbon tax obligation on those units. So 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.

And I guess as a follow up to that if those carbon tax costs then become yours next year. Does that mean that the production level is indicative of what you expect for you?

Yeah, so the prices going into next year, we see as being relatively higher than what we have in the forwards this year. So expect that those units would be economic at the prices that we're seeing today, even with the carbon tax obligation?

Makes sense and second question, I just want to look ahead to I guess, December when you traditionally put out your guidance for the full year, as well as potentially - so your dividend objectively on 2022? Slide 11, you've highlighted a number of uncertainties for next year.

Can you I guess, broadly discuss where you see clarity improving over the next four to five weeks ahead of early December or should we expect a different type of guidance next year - sorry, next month?

Sorry, guidance with respect to the dividend increases in particular?

In 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 '21 and '22 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. So 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.

So whether or not there's a rise in carbon tax or if it stays at 30, so 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.

So just with respect to the pandemic and where that's going and the implications on demand in the province, so some of those will start to clear some of them will be throughout 2021 before we get a better indication as things unfold.

And I guess just a final follow up on that comment that we don't expect or at least there's no view of 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?

And with that, I suppose would you expect us all to assume it'll be that for now?

Yeah, there's no indication that there's any need to cut dividends. So certainly that is not something that we would be announcing in any regard.

So 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.

And 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 increases. I think that that message is now been received.

And so you'll probably see us signal dividend increases closer to the expected time. And so right now, we still are a couple years out, so kind of see that timeline of advanced signaling compress in the coming years.

Great, thank you very much.

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? And related to that, what does the current pipeline of renewable projects look like?

So 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, and the other part is working with other developers, typically junior developers, and looking at sites and moving forward. So when you look at those two, certainly, and you look at what we have underway, it's kind of a mix of the two and we'd expect that to continue going forward.

So we have had a very good year and the year's not over yet, but 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, and I'm sure you've also given some thought to maybe accelerating that via M&A or 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 though on natural gas for now?

So 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.

But we definitely look at M&A opportunities related to renewable and then there have been actually this year. The Buckthorn acquisition is an example of one, so at all times, you can expect that we're looking at both natural gas and renewable acquisition opportunities.

Okay, thanks. So the rest of the questions were already answered.

Thank you.

All right thank you. We will be hosting our Annual Investor Day event on the morning of December 3 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.