Capital Power Corp. (CPXWF) CEO Brian Vaasjo on Q1 2020 Results - Earnings Call Transcript

Capital Power Corp. (OTCPK:CPXWF) Q1 2020 Earnings Conference Call May 4, 2020 11:00 AM ET

Company Participants

Randy Mah - Director, Investor Relations

Brian Vaasjo - President and CEO

Bryan DeNeve - Senior Vice President and CFO

Conference Call Participants

Maurice Choy - RBC Capital Markets

David Quezada - Raymond James

Patrick Kenny - National Bank Financial

Mark Jarvi - CIBC World Markets

Robert Hope - Scotiabank

Ben Pham - BMO Capital Markets

Andrew Kuske - Credit Suisse

John Mould - TD Securities

Naji Baydoun - Industrial Alliance Securities

Operator

Welcome to Capital Power’s First Quarter 2020 Results Conference Call. At this time, all participants are in listen-only mode. Following the presentation, the conference call will be opened for questions. This call is being recorded today, May 4th, 2020.

I’ll now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead.

Randy Mah

Good morning and thank you for joining us today to review Capital Power’s first quarter 2020 results, which we released earlier this morning. Our first quarter report and the presentation for this conference call are posted on our website at capitalpower.com. To help prevent the spread of COVID-19 with physical distancing, I have Brian Vaasjo, President and CEO; and Bryan DeNeve, Senior Vice President and CFO joining me on the call from their homes.

We will start with the opening comments and then open 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 number 3, these measures are not defined financial measures according to GAAP and do not have standardized meaning 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 items non-GAAP financial measures can be found in our first quarter 2020 MD&A.

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

Brian Vaasjo

Thanks, Randy and good morning. I’ll start off with high level comments on our first quarter results and our 2020 outlook. Overall, our first quarter results were solid and we’re in line with our expectations. With no material changes to our outlook, we are maintaining our financial and dividend guidance for 2020. We have a very strong financial position and liquidity that Bryan will speak to shortly.

At Capitol Power, we’ve implemented various measures to manage the risks from COVID-19. With a primary goal of keeping employees safe and healthy, reducing risks and keeping our plants operating. I’ll also review the progress made on our renewable and growth strategy which has been good so far this year.

Turning to Slide 5 in response to COVID-19, we’ve implemented our business continuity and risk management plans to ensure the continued safety and health of our employees. This includes working from home for office and all non-essential plant employees. In the plants, we have implemented numerous hygiene and social distancing protocols, while delivering reliable power. Overall, the company is functioning very well.

We’re also managing our operational risk by completing planned maintenance and enhancement outages at Southport, Roxboro, Arlington, Decatur and Goreway. With the help of our employees and contractors in mind, we’ve modified the Decatur outage and have delayed the Genesee to 2021. We have also used technology to enable us to operate our 3 simple cycle plants from a laptop. Overall, we are managing very effectively through this COVID-19 pandemic.

On Slide 6, I’ll touch on the recent progress we made on our growth and renewable strategy. This year, we’ve added 251 megawatts in renewables to our fleet. This includes the completion of Cardinal Point Wind project in Illinois that was completed on schedule and on budget in US dollars. In April, we acquired the 101 megawatt Buckthorn Wind facility in Texas that is contracted with 15 years of weighted average remaining contract life.

We have signed an agreement with Vestas that set the terms for a 10-year extension of our long-term service agreements. The extension covers fleet-wide maintenance for all of our Vestas equipment wind facilities, the LTSA covers an expanded scope of services with an expected 26% cost reduction compared to current service and maintenance agreements.

On an annual basis, the new LTSAs are expected to increase EBITDA and AFFO by $8 million and $6 million, respectively once they all take effect between 2021 and 2023. An agreement has been reached with Vestas to supply turbines Whitla 2 which will start commercial operations next year.

I’ll now turn the call over to Bryan DeNeve.

Bryan DeNeve

Thanks, Brian. I’ll review the financial highlights starting on Slide 7. Overall, first quarter financial results were in line with our expectations. The first quarter was the busiest quarter of the year for planned outages as reflected in the 91% average availability. Therefore, we expect to generate positive net cash flows for remainder of the year. As Brian mentioned, the major planned outage for Genesee 2 has been deferred to 2021 due to COVID-19.

In the first quarter, we had discussions with ENMAX, the JV partner for the Genesee 4 and 5 project and have determined that we would no longer be proceeding with that project. Accordingly, $13 million relating to the development of Genesee 4 and 5 has been recorded in the first quarter as a write-off within depreciation and amortization.

Looking now at the Alberta power market. The average spot price averaged $67 a megawatt hour in the first quarter, which was slightly lower than the $69 in the first quarter of last year. Both quarters included one month of higher pricing as a result of cold temperatures and baseload facility outages, while the other two months settled at moderate pricing with stable baseload supply. In the first quarter, our trading desk captured an average realized price of $62 a megawatt hour that was 7% lower than the average spot price.

Moving to Slide 8, revenues and other income in the first quarter were $533 million, up 34% compared to the first quarter of 2019, mainly due to the acquisition of Goreway in the second quarter of 2019. Adjusted EBITDA was $234 million, up 16% year-over-year, that was largely driven by the acquisition of Goreway and the addition of Whitla Wind 1.

Normalized earnings of $0.27 per share were slightly down compared to $0.29 per share in the first quarter of 2019. We generated $118 million in AFFO that was consistent with $117 million from the first quarter of last year. And AFFO per share was $1.12, down 3% from the first quarter of 2019.

Turning to Slide 9, I’ll provide an update on our commercial portfolio positions. For the remainder of 2020, our baseload generation is 91% hedged at an average price in the mid $50 per megawatt hour. This compares to the current forward prices of $48 per megawatt hour. At the end of the quarter, we’re 7% hedged for 2021 at an average contract price in the low $60 per megawatt hour range.

For ‘22 and ‘23 we’re 15% and 9%, hedged at an average contract price in the low $50 per megawatt hour range from both years. This compares to current forward prices of $53 a megawatt hour for 2021 and 2022 and $51 a megawatt hour for 2023.

I’ll conclude my remarks by commenting on our strong financial position and liquidity on Slide 10. Capital Power is generating strong cash flows, including over $300 million in discretionary cash flow in 2020. The pie chart on the slide shows our adjusted EBITDA forecast for the remaining nine months of 2020.

As you can see, 83% of adjusted EBITDA are under contracts with an average PPA term remaining of 10 years. The PPAs are largely with investment grade counterparties. The remaining 17% of adjusted EBITDA is from Alberta Merchant business in 13% of that is hedged, so our merchant exposure is only 4% for the balance of 2020.

For our commercial industrial customer base in Alberta, one-third of our investment grade, one-third of posted collateral and the balance have some default risk that has been recognized in a $200,000 provision.

In terms of liquidity, we have $900 billion of available capacity on the $1 billion of committed credit facilities that mature in 2024. Currently, we do not anticipate the need to access the capital markets other than to potentially refinance the $250 million in debt, maturing in November.

In April, DBRS confirmed our BBB low credit rating with stable trends that was supported by relatively stable long-term business risk and financial profile. With our expectations for 2020 unchanged, we are reaffirming our 2020 financial and dividend growth guidance.

I’ll now turn the call back to Brian.

Randy Mah

Brian, you have to unmute your call.

Brian Vaasjo

Yeah. Thanks, Bryan. I’ll review our first quarter performance versus our 2020 annual targets as shown on Slide 11. As mentioned, the first quarter was a busy quarter of planned outages, resulting in an average facility availability of 91%, compared to the 93% annual target.

Sustaining CapEx were $16 million in the first quarter, with a deferral of the Genesee 2 planned outage to 2021, we expect sustaining CapEx will be below that $90 million to $100 million annual target.

We recorded $234 million in adjusted EBITDA in the first quarter versus the $935 million to $985 million target. And we generated $118 million of AFFO in the first quarter compared to the $500 million to $550 million target range. Based on our current forecast, we are on track to be near the midpoint of the AFFO range, while continuing to monitor the impacts from COVID-19.

Slide 12 outlines our development and construction targets for 2020. This includes the construction of 2 wind projects. As mentioned earlier, we completed our Cardinal Wind project on schedule and within the US dollar budget range. Following the startup commercial operations, we received $221 million in net tax equity financing from two US financial institutions. Cardinal Point is now operating under a 12-year PPA for 85% of its output.

The other wind project under construction is Whitla 2 which is currently tracking on budget and on schedule for our COD in 2021. We have an annual target of $500 million of committed capital for growth, our performance against that target includes, the recent acquisition of Buckthorn Wind in Texas with a 15-year weighted average contract life remaining.

To wrap up, I wanted to highlight Capital Power’s investment thesis and reiterate how the long-term drivers of our business continue to be resilient. The foundation of our young fleet averaging 14 years in average life, will – we continue to beat them to demonstrate strong operational performance, while continuing to optimize our assets to enhance operations and efficiency.

We have a highly contracted and diversified portfolio by geography and by fuel mix. Our business generates strong cash flows, including more than $300 million in discretionary cash flow for 2020. We are committed to maintaining our investment grade credit rating with our two credit rating agencies, S&P and DBRS.

Our growth is focused on investing in emission-free renewables and critical natural gas generation. Our sustainability goals involve the transitioning and Genesee to natural gas and investing in carbon capture and utilization. Overall, our aspiration is to be carbon neutral on or before 2050.

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

Randy Mah

Okay. Thanks, Brian. Anastasia, we’re ready to start the question-and-answer session.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Maurice Choy with RBC Capital Markets. Please go ahead.

Maurice Choy

Thank you and good morning. My first question relates to the G 4, G 5 position. I guess my question is, why make that decision right now as opposed to just wait and see. Put differently, what’s changed in your underlying pieces?

Brian Vaasjo

So I mean, obviously, you know, there’s two partners involved in G4 and G5, you know, ourselves and ENMAX and, you know, the status of it has been, you know, as we characterize that it’s been on the shelf and permitted and in the event that there was a very rapid immediate need for generation in the province it would be available and our timeframe for implementing it, you know, was being pushed out, you know, further and further with the outlook for power in the province.

The other thing that plays into it is that, you know, as the fleet has evolved then the market has evolved, it’s turned out that for Capital Power a better choice for us at this point in deploying capital in the Alberta market would actually be repowering our existing units as opposed to building additional units. So, again and lots happened since, you know, the initiation of Genesee 4 and 5 and it’s a solution that no longer fits the market.

Maurice Choy

And I guess that there a tie into how you now view and look to, which obviously remains a merchant project as it stands?

Brian Vaasjo

No, no real unrelated to that project.

Maurice Choy

Okay. And my second question relates to Decatur. Obviously the last update we’ve had was that negotiations were ongoing any update on that as well? Could you actually elaborate on the modified outage that happened on the plant?

Brian Vaasjo

So in terms of the – where discussions are on Decatur, what’s happened is that the COVID-19 has significantly impacted on the responsiveness of the counterparty given, you know, live the level of activities that they would have had. So it’s slowed down the process, but I’m happy to say that, you know, where we are today is minor legal issues going back and forth, but you know, the frequency of going back and forth has definitely slowed down, and we are, you know, continue to be very hopeful and expecting something to be coming to resolution within the relatively near future.

In respect of Decatur, because of the issue of utilization of sometimes foreign expertise or you know, not in North America, but also the fact that we may have had to move the rotor to a facility, to a different facility as opposed to doing it on site, we did end up making the decision that that was too risky at this point in time and could be easily deferred and still go ahead with the bulk of the outage. So that’s what we have done. And the outages has gone very well and is nearing completion as we speak.

Maurice Choy

Great, thank you very much.

Operator

Our next question comes from David Quezada with Raymond James. Please go ahead.

David Quezada

Thanks. Good morning, everyone. My first question here just maybe some thoughts around your hedging strategy for 2021. I know in the past you’ve commented that you’re competent in the fundamentals for the market and that prompted the lower hedge position. Wondering if your thoughts there have evolved at all?

Bryan DeNeve

Yes, certainly given the reduction in oil prices, we have revised our outlook for 2021. Prior to the reduction in oil prices, we were seeing – we’re projecting Alberta power prices would be north of $60 a megawatt hour in 2021. A lot of that driven by the fact that there’s a large number of outages as companies look to move to additional gas-fired generation capability at their units.

With the reduction in oil demand, and a solar recovery projected over ‘21 and ‘22, we do look at 2021 as approximately 400 megawatts to 500 megawatts of less demand in the Alberta market, which has reduced our projections by approximately $7 a megawatt hour for the year. What that’s done is, brought us now more or less in line with current forward prices for the Alberta market. So to the extent opportunities rise, we would see ourselves increasing our position hedged in that year.

David Quezada

Okay, great. Thank you. That was very helpful. And then just my only other question on your $500 million of committed growth capital. You still confident that you’re on track there with the investment Buckthorn and maybe just some general commentary, I don’t know how your opportunity set is looking today, if possible?

Brian Vaasjo

Sure, you know, certainly we continue to have opportunities that we are pursuing on the development of the renewables side, and, you know, continue to be optimistic that there’ll be things developed through the year on that one. So see further investment from that perspective.

In terms of the mid-life natural gas side, basically COVID-19 stopped that transactional market pretty much overnight. We do hear rumblings, but soon opportunities will open up again and that’ll actually probably be a significant number of opportunities that are in the market. And again, you know, we’re not compelled to having to make an investment and we’ll only pull the trigger on those assets and those opportunities that continue to make sense for Capital Power.

David Quezada

Okay, great. I appreciate the color. I’ll get back in the queue.

Operator

Our next question comes from Patrick Kenny with National Bank Financial. Please go ahead.

Patrick Kenny

Hey, good morning, guys. Appreciate the financial guidance on the Buckthorn acquisition. But just wondering if you could confirm your internal IRR expectations for the deal, maybe both on an unlevered and levered basis? And then just how these returns might compare to say, Cardinal and Whitla 1?

Bryan DeNeve

Yeah, the returns on a levered basis anticipated for Buckthorn would be in the 10% to 11% range on a levered basis. And that would be consistent with our expectations for Cardinal Point and Whitla 1.

Patrick Kenny

Okay, great. And then just on the turnaround for Q2 being pushed into 2021, does this have an impact on the timing for reaching 100% dual-fuel capabilities across all three Genesee units? And at any impact on the increase in AFFO which I believe was $20 million or so for 2021?

Brian Vaasjo

So I’ll speak to the – moving Genesee 2 into 2021 still, you know, meets our statement of being a natural gas capable across the three units, you know, by 2021. Now just Bryan can comment on the AFFO impact?

Bryan DeNeve

Yeah, certainly, you know, the lift we were going to see on AFFO side is slightly lower now. And that’s been driven by an increasing natural gas prices in Western Canada. So with the decline in oil production that’s had a related effect of putting upward pressure on April prices. So certainly, that we’re not forecasting to burn as much natural gas in 2021 as we were previously.

But on the flip side, those higher natural gas prices do help us in other areas, such as putting some upward pressure on power prices in Alberta. But to your specific question, Pat certainly there will be some downward pressure on that $20 million figure stated previously.

Patrick Kenny

Okay, got it. Thanks. And then also Bryan so you mentioned DBRS reaffirmed the credit rating. Just wondering if we can get an update on any discussions you may have had recently with S&P? Whether or not the stable outlook is currently under review, given Alberta’s economic condition and in light of your upcoming debt maturity in the fall, maybe just how you’re thinking about keeping some dry powder into the back half of 2020 and into 2021 given the open position there, you know, just maybe a general comment on how you’re thinking about allocating free cash flow for the remainder of the year between M&A debt repayment and CIB activity and so on?

Bryan DeNeve

Yeah, so, you know, in terms of S&P, we typically touch base with them in the June timeframe. We’d be looking at to do so again this year. There’s been no indication from their end that there are concerns with our financial position vis-a-vis investment grade credit rating.

I can tell you, Pat that our projections for the balance of this year and next year is that we will continue to meet those credit metrics that S&P is looking for us to sustain for investment grade. So we don’t have concerns on that front.

As far as capital allocation, as I mentioned, we’re still projecting to generate over $300 million discretionary cash flow for 2020. Now part of that, of course, did go towards some of the growth activity we’ve been doing and continued development of Whitla – sorry, the Cardinal Point project. We’ll be starting to look at capital costs on Whitla 2.

As always, we look over the balance of the year at this point, not sure we’ll need to go to the debt market just given our positive cash flow position that’s something we’ll monitor and evaluate as we move through the year.

You know, in terms of allocation, the M&A activity, certainly if the right opportunity came along a strong fit that was helpful from a casual position it would be something we would consider, but certainly we do have development expenditures here are still ongoing with the construction of Whitla 2.

Patrick Kenny

That’s great. Last one for me here guys. Didn’t see much of an update on C2CNT. Maybe I missed it, but can you comment on what impact this pandemic has had on the progress over at C2CNT and, if any? But also maybe what milestones we could watch for, you know, through the back half of 2020 as it relates to the Genesee carbon conversion center?

Brian Vaasjo

Sure. What’s happened at C2CNT, as you recall it’s part of the carbon XPRIZE and is a group of interests that are working with the emissions from the Shepard facility, and one of the first closures that happened you know, in the province and obviously being run by a provincial entity, you know, that site was totally shutdown.

And the C2CNT Group were able to move a fair amount of their activities to a warehouse and continue on more the some fabrication and working on some of the technology side, but it certainly has created an impediment for them to continue to moving at the same pace.

Consistent with that, XPRIZE timing has moved out as well. So, I would characterize what’s essentially happened is a bit of a pause, although, you know, still significant development’s taking place, but in the overall timeframe, I would say, you know, at the end of the day, that pandemic will probably have caused at about a quarter in relation to timing.

So, we do shall continue to expect that, you know, we’ll continue to move forward on the Genesee carbon conversion center, do expect that it’ll be built and reach COD sometime next year. But again, probably the whole schedule has been moved by about a quarter. And don’t expect any further delays at this point.

Patrick Kenny

All right, appreciate the update. So I’ll leave it there. Thanks, guys.

Operator

Our next question comes from Mark Jarvi with CIBC World Markets. Please go ahead.

Mark Jarvi

Good morning, everyone. Just wanted to go back to the capital allocation discussion, just maybe fine-tune some responses there in terms of use of cash and would you want to hold a little bit higher liquidity right now given some uncertainty going forward, and what’s the willingness to be active on the buyback at the current levels right now?

Bryan DeNeve

So generally, the excess cash at this point in time is being used to pay down debt. And, of course, some development spend on Whitla 2. As I mentioned, we’re in good shape relative to our credit metrics, but certainly want to be mindful of maintaining that, so we wouldn’t see doing any share buybacks in the near-term. We would see that positive cash flow to pay down the credit lines and funding development activity.

Mark Jarvi

Okay. That makes sense. And then just the comments on the hedges in terms of – and even just your expectations for where power prices should net out in 2021. The fact that you didn’t add that much more to 2021 hedges, is that just a function of they’re not being liquidity in the forward market?

Bryan DeNeve

Yeah, currently there hasn’t been recently a lot of liquidity in the forward market. However, we do expect that liquidity will start to ramp up. In particular, as we get through towards sort of the August-September timeframe at that point, the regulated rate option that providers to that service start to enter the market looking for hedging. So that’s where we’ll expect liquidity increase.

But also I think as we come out of COVID-19 and reopening in the Alberta market that will also support liquidity. So given we see an alignment now between forward prices and our expectations, we would see that hedging percentage increase as we move through the year.

Mark Jarvi

Okay. And then you made your comment about where you thought maybe demand didn’t come off here. What you guys think is going to ultimately happen in terms of other people’s plans for new supply, like the Cascade project, which is quite large or some of the cogen stuff? I think all that’s been delayed or pushed out or are there any concerns from your part that people continue to go forward with adding new capacity here?

Bryan DeNeve

No, you know, certainly we saw the announcement from Suncor, which was at a minimum, they’ve pushed out that project by two years, which takes it to at least the end of 2025, if not beyond. You know, we would expect other development projects will definitely get deferred, delayed or if not, outright, just cancelled given the environment. You know, the one thing that we see is a real positive for the Alberta market as we move into the lower demand as compared to what we saw happened in 2015, is the supply side will be a lot more responsive.

So yeah, to those growth projects we see those we expect will be deferred, if not cancelled, but also all the PPAs will have expired at the end of this year. So all the output in the Alberta market will be in the hands of commercial entities which will result in supply side response to a much greater degree than what we would have seen in 2015, which will support power prices in the face of the lower demand we’re seeing.

Mark Jarvi

Okay. And just one last question just on that long-term service agreement for Vestas turbines. How does that roll out you know tops through between 2021 and 2023? Is that a steady rollout of incremental pick up every year and any other you know, color you can give on how those savings come in?

Bryan DeNeve

Yeah, you know, a reasonable assumption is that, it would phase out evenly over those years. So generally, we have our staggered renewal dates going through and that the profile would be more or less linear.

Mark Jarvi

Okay, that’s great. Thanks guys.

Operator

Our next question comes from Robert Hope with Scotiabank. Please go ahead.

Robert Hope

Hello, everyone. Just one question for me. Just want to get a sense of how you’re looking at the balance of 2020 in a world where we could see oil sands curtailments. How do you think the behind the fence generation will respond to that? Could we see that as an area which could help balance the market there?

Bryan DeNeve

Yes, we believe so. Certainly, we’ve seen some cogen units that have pulled back, some of that due to maintenance, but we believe some that due to reduced production. So yeah, we do believe that’s another element supporting our market pricing as we move forward.

Robert Hope

And then maybe you know, you did mention where you saw your view of 2021 pricing based on the forward curve. How do 2020 look for the rest of the year?

Bryan DeNeve

Yeah 2020 has come off, so slightly below $50 a megawatt hour. But for us, of course, not much of an impact given over 90% of our baseload generation is hedged. The one thing I would comment on and this goes back to a previous question is, when we look beyond 2021 into ’22 and ‘23, we do see Alberta power prices continuing to strengthen and, of course, that’s related to the fact that the Suncor cogen has been pushed out, but we believe other supply additions will also be deferred. So although we’ve seen softening of power prices for ‘21, we do see a strong outlook for ‘22 and ‘23.

Robert Hope

Appreciate the color and thank you.

Operator

Our next question comes from Ben Pham with BMO Capital Markets. Please go ahead.

Ben Pham

Hi, thanks. Good morning. On your comments around the power price strength in 2023, could you comment on your expectation on where you think the long-term Alberta power price should be? Has that changed from your Investor Day commentary?

Bryan DeNeve

No, it would be similar, if not slightly higher. So with the strengthening in natural gas prices that does put upward pressure on our view of what a long run price should be in the Alberta power market. But yet not significantly different than what we would have talked about at Investor Day.

Ben Pham

Okay. And if that’s the case, and it sounds like some of this is supply driven as well with some of your competition. When you think about Genesee 4 and 5 that it seems like your burn costs and that was probably pretty low. So I’m a little bit surprised just to your earlier commentary to Maurice that you’re not moving forward. So it sounds like [FTE] [ph] willing to honor the CapEx and there is no upfront payment near-term, then it sounds like it’s more driven by your partner then is driving this decision?

Bryan DeNeve

I would say it’s probably more driven by the fact that as Brian Vaasjo mentioned. There is a different configuration that makes more sense than standalone combined cycle facilities, which is the technology we were looking at for Genesee 4 and 5. So, we’ve done a lot more work around repowering and what that could look like. And so at that site doing the repowering of one of the existing units, which of course, would utilize the existing steam turbine and would utilize the existing generators that is a configuration that we believe makes more sense now than standalone combined cycle units.

Ben Pham

Okay, okay. And do you think ENMAX could potentially come back as a buyer from that power potentially? Are you comfortable with going spot if you were to bring it back in some different form?

Bryan DeNeve

I’ll turn that question over to Brian.

Brian Vaasjo

So you know, certainly, you know, if we cross the bridge in terms of deciding to repower one of the units, I mean, we’d definitely be looking for off takers. I would suggest that that would be unlikely other than, you know what you find in the market normally. We wouldn’t believe that ENMAX would necessarily want to participate in the project and move in that direction.

And again that’s – and that’s maybe a question better to be asked of ENMAX, but it is definitely a better technical solution and market responsive solution today for Capital Power to repower one of its units. So it just became a fact that the answer that was on the shelf and sort of the no cost option to carry it came to a point where if it was needed, it wouldn’t make sense to pull the trigger on that project anyway.

Ben Pham

Okay. And you’re off on your long term service agreements. Was there process you guys looked at on bringing some of that stuff in-house?

Bryan DeNeve

Yeah. So we did quite a bit of work behind the scenes understanding an alternative where we would self manage or self perform on our renewable facilities. And, you know, like, we have seen new entrants into North America that are willing to provide those services as an alternative to the original equipment manufacturer. So, we were looking closely at those other alternatives and actually had developed price points that we thought we could move to and perform.

What we saw happen was Vestas actually was able to meet those price points, well continuing to provide a full service. So for us, it became you know, we had a good view of that, but Vestas was able to step up in natural’s perspective, so we’re really happy where we’ve landed with Vestas in that regard.

Ben Pham

All right. Sounds like you got a good deal. Okay thanks, everybody.

Operator

Our next question comes from Andrew Kuske with Credit Suisse. Please go ahead.

Andrew Kuske

Thank you. Good morning. Obviously was a volatile quarter in Q1. But maybe you could give us some color and context on how your optimization strategies evolved over the quarter and how you’re really positioning yourself for the remainder of the year?

Brian Vaasjo

So in terms of our optimization, a lot of what we were doing was through outages, you know, through the Genesee 2 outage, through what we’re doing at Decatur in Arlington and you know, Arlington’s been completed and very happy with the work that took place there. As I mentioned earlier, we had modified the Decatur outage just from a risk management perspective. But, you know, we’ll be picking up that element later, so not really a significant impact there.

The largest one, of course, being the movement of Genesee 2 which they’ll given the work that was the upfront work that needed to be taking place at the plant and the fact that we’d be utilizing foreign expertise that would have to come to Canada and so on. At one point, we’ve moved it, you know, into and we’re working towards potentially moving it into the fall and ended up moving it into next year, because it continued to just not be practical and not being a risk worth taking.

So in terms of the overall program continue to be, you know, moving forward. Nothing’s been changed and actual fact, what’s happened because of COVID-19 and looking at different parts of the business, we’ve actually accelerated some of the developments that we had planned on moving forward.

So for example, you know, I commented that, you know, we can now operate, you know, our simple cycle units all from laptops, which is something that we were working towards and we’d actually had, you know, worked out in the technology and made some choice but that would have been taking place over you know, a couple of years, we just accelerated it. So there’s a number of things like that from a development perspective, that – yeah and optimization that we just moved ahead very quickly, not only on the facility side, but you know, on the, say, on the support services side as well.

Andrew Kuske

Okay, that’s helpful. And then I think the number that was given earlier on was your expectations and your projections were for 450 megawatt hours is effectively demand destruction in the current environment for 2020. So how do you think about just coal setting the marginal price in the market now and in the future years, like what percentage of time has that really changed in your modeling forecasts?

Bryan DeNeve

Yeah, for the balance of this year, we would see the coal units on the margin were often not able to provide a specific percentage, but certainly that would be the case. Now as we move into 2021, of course, those units will be moving to dual-fuel or conversion of 100% to natural gas. So certainly see a bit different dynamic in terms of how those units respond, it will really depend on you know, what happens with carbon pricing and natural gas prices.

Andrew Kuske

And then finally from me, and you see no change to carbon pricing as it’s been laid out by the federal government at this stage?

Bryan DeNeve

No, we don’t.

Andrew Kuske

Okay. That was great. Thank you.

Operator

Our next question comes from John Mould with TD Securities. Please go ahead.

John Mould

Good morning. So a couple of questions on the Genesee dual-fuel timing. So with the G 2 outage moved to 2021, can you clarify when each outage enabling 100% dual-fuel operations is now planned for each of the units? And can you confirm where your dual-fuel capability levels expected to be for the balance of 2020 with the G 2 had to defer, but following the completion of the Pembina-Keephills pipeline?

Bryan DeNeve

Yeah. So for 2020, we’ve continued, of course, with the interconnection of higher gas capacity at the Genesee site so that line has been completed. So with some upgrades we’ve made, we actually see a bit higher percentage gas-fired capability for the balance of 2020 is always towards the 40% range from 30%. For 2021, all those conversions would be still plan to take the units to be able to do a 100% firing on natural gas.

John Mould

Okay. And are those spread out over the balance of the year rather than weighted all towards the normal Q2 kind of outage for the season?

Bryan DeNeve

Yeah, I think if you check the outage schedule, you can kind of glean that. We do have a couple of the units in Q2 and one of them is scheduled for the fall in 2021.

John Mould

Okay. All of my other questions have been answered. Thanks very much.

Operator

[Operator Instructions] Our next question comes from Naji Baydoun with Industrial Alliance Securities. Please go ahead.

Naji Baydoun

Hi, good morning. Just one quick question for me. Can you give us your latest thoughts and expectations on the ISO’s review process in Ontario and how that might impact your portfolio in the province going forward?

Bryan DeNeve

Yeah, so, you know, the government there has put on hold their review of the capacity market design, certainly they’re still looking at bilateral contracting approaches. But of course, our thermal assets in Ontario were all hedged through to the end of the next decade. So, you know, near-term tweaks to that market generally won’t affect our financial position on those units.

But longer-term is something we’ll be engaging in and monitoring as a discussion on Ontario market design continues. But again, it’s not something that really affects us financially until the end of the next decade or the end of this decade, I guess.

Naji Baydoun

Thank you.

Operator

This concludes the question-and-answer session. I’d like to turn the conference back over to Mr. Randy Mah for any closing remarks.

Randy Mah

Okay, if there are no more further questions, we will conclude our call. Thanks again for joining us today and for your interest in Capital Power. Stay healthy and have a good day everyone.

Operator

This concludes today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.