Article Republished By Javier Troconis
Innergex Renewable Energy, Inc. (OTCPK:INGXF) Q1 2022 Earnings Conference Call May 10, 2022 5:30 PM ET
Karine Vachon – Senior Director, Communications
Jean Trudel – CFO
Michel Letellier – President, CEO & Director
Conference Call Participants
David Quezada – Raymond James
Nelson Ng – RBC Capital Markets
Rupert Merer – National Bank Financial
Sean Steuart – TD Securities
Andrew Kuske – Crédit Suisse
Naji Baydoun – IA Capital Markets
Benjamin Pham – BMO Capital Markets
Good afternoon, ladies and gentlemen, and thank you for standing by. Welcome to Innergex Renewable Energy’s 2022 First Quarter Results Conference Call and Webcast. [Operator Instructions].
I would like to remind everyone that this conference call is being recorded.
I will now turn the conference over to Karine Vachon, Senior Director of Communications. Please go ahead.
Thank you. Hello, everyone, and thank you for joining us today. I’d like to specify that this conference will be held in English. Members of the media are invited to ask their questions by phone after this call.
The presentation supporting today’s discussion is available as we speak on the page of our website at www.innergex.com.
This call contains forward-looking statements within the meaning of applicable securities laws. Although the corporation believes that the expectations and assumptions on which forward-looking statements are based are reasonable under the current circumstances, listeners are cautioned not to rely unduly on these forward-looking statements as no assurance can be given that it will prove to be correct. Forward-looking information contained herein is made as of the date of this call and the corporation does not undertake any obligation to update or revise any forward-looking information, whether as a result of events or circumstance occurring after the date hereof, unless so required by law.
During this call, we will refer to financial measures that are not recognized according to International Financial Reporting Standards. Please refer to the non-IFRS section of the MD&A for more information.
Our speakers today will be Mr. Jean Trudel, Chief Financial Officer; who will present Q1 results; and Mr. Michel Letellier, President and Chief Executive Officer, who will review our operational highlights.
I’ll now turn the conference over to Mr. Trudel.
All right. Thank you, Karine, and hello, everyone. It’s a pleasure to be back on this call after a 7-year absence or about. I look forward to the Q&A session that will follow, but before, I will give you a bit of the financial highlights.
So the corporation’s financial performance posted strong growth for the 3 months ended March 31, 2022, compared to the same period last year. Production was up 29% at 2,304 gigawatt hour, and revenues were up 40% at $188.7 million versus normalized comparative figures.
This increase was mainly explained by the contribution to the 2021 and 2022 acquisitions, namely the remaining 50% interest in EnergÃa Llaima for which results are now included in Innergex’ consolidated performance; the Lican Hydro Facility; Curtis Palmer Hydro Facility as well as the San Andres Solar Facility; the commissioning of the Griffin Trail Wind Farm and the Hillcrest Solar Facility as well as higher production mainly from the Quebec Wind Facility.
Also in the quarter, we received a settlement payment from BC Hydro regarding the May 2020 curtailment notice that we disputed and resolved to our satisfaction. For Innergex in the industry, and I’m thinking also about the lenders to our industry, it was very important to demonstrate the validity of our long-term take-or-pay contracts that are fundamental to the economic viability of our projects. So this win in D.C. was very important, and we were very glad to see that the reversal of revenues in our favor. The items previously mentioned were partly offset by lower average selling prices at the Fort City Facility during the quarter.
Operating, general administrative and prospective project expenses were up 25% at $58.2 million. The increase is mainly attributable to higher corporate general and administrative expenses to support the business’ higher maintenance cost at some of the British Columbia hydro facilities as well as the 2021 and 2022 acquisitions and assets commissioning that we — that I mentioned earlier.
These items were partly offset by lower variable expenses following lower revenues at the Fort City Facility. So as a result, adjusted EBITDA for the 3 months period ended March 31, 2022, reached $130.5 million, which represents a 48% increase compared to the same normalized period last year.
So moving to the next slide. Our proportionate financial performance also posted growth for the 3-month period ended March 31, 2022. The increase in proportionate metrics was largely driven by the variances explained on the previous slide, and in addition to the PTC contribution from the commissioning of the Griffin Trail Wind Facility.
Continuing to the next slide. For the trailing 12 months ended March 31, 2022, the corporation generated free cash flow of $129.4 million compared with $89.6 million for the corresponding period last year after excluding the impact of the February 2021 Texas events. This increase was primarily explained by the incremental contribution from the acquisitions and asset commissioning activities mentioned earlier from the full year impact of the Mountain Air and Salvador acquisitions realized in 2020 as well as the BC Hydro curtailment payment received during the quarter.
These items were partly offset by the higher debt principal repayment stemming from the EnergÃa Llaima acquisition, the beginning of debt repayments for the Upper Lillooet and Boulder Creek project loans, an increase in free cash flow attributed to noncontrolling interests stemming mainly from the Curtis Palmer acquisition and the full year impact of the Mountain Air acquisition as well as unfavorable differences between sales at the PB node and purchases at the ERCOT South hub.
The increase in free cash flow versus 2021 resulted in a 34% point improvement to our payout ratio, which amounted to 106% for the 12 months ended March 31, 2022, compared with 140% for the same normalized period last year. When excluding prospective expenses of $25.6 million, the adjusted free cash flow stood at $155 million versus $108.4 million for the same normalized period last year. So the adjusted payout ratio consequently reached 89% compared to 116% last year, which is a great improvement.
On the next slide, I would like to remind you that on February 22 of this year, Innergex has successfully completed its bad-deal equity financing and concurrent private placement with Hydro-Quebec for aggregate gross proceeds of approximately $210 million. These proceeds were immediately used to repay part of the corporate revolving facility, which will then be drawn back at the closing of the Aela acquisition.
So this leads me to the next slide to talk to you about our continued expansion to our Chilean operations through the acquisitions of the San Andres Solar Facility on January 28 and the Aela wind facilities on February 3, 2022. These acquisitions did not only double our existing capacity footprint in Chile, but they also contributed to further diversifying the geographic coverage and energy mix of our Chilean operations.
Furthermore, these acquisitions allowed for rereading of our Chilean portfolio, which opened the way for — or helped actually optimize the capital structure. And this additional leverage that we secured — or that we will secure will be used to finance our 2 best projects that we announced earlier today without requiring new equity investments.
As you all know, I guess — next slide, as you all know, the absurd and unfortunate war in Ukraine has rocked the market and geopolitics of energy driving oil and gas prices to their highest levels in nearly a decade. These macro events, coupled with the governments’ increasing desire to decarbonate and to achieve a greater level of energy self-sufficiency have created a backdrop from which the corporation benefited in the form of higher-than-anticipated spot prices and more favorable PPA or contracting environment in the majority of our markets.
And as an example, and subsequently to the first quarter period end, the corporation successfully re-contracted on April 29, 2020 3 power purchase agreements for the AntoignÃ©, the Porcien and Vallottes French wind farms in France, of course, at favorable energy prices. And we also extended the contracted term to December 31, 2025. We also believe that global decarbonization targets as well as national energy security concerns will continue to support high energy prices for green and renewable electricity in the years to come.
Finally, on May 10, 2022, in order to add greater balance sheet flexibility and efficiency in supporting our growth activities, the corporation successfully increased the size of the corporate revolving facility, adding an additional $250 million to the borrowing limit, now standing at $950 million. And we also, at the same token, extended the term by 4 years to 2027.
So I will now give the floor to you, Michel, for the operational review of the past quarter.
Thank you, Jean. It’s good to have you back, and you’ve done well. Thank you.
Construction activities that we have done in the quarter. And I know that you guys have a lot of questions regarding the Hawaii project and the fact that the U.S. government, the commerce — the Department of Commerce have started an investigation on panel coming from South Asia. So we’ll cover that as best as we can, and I’m sure you’ll have a few more questions.
But I guess, in general, the development in Hawaii has been challenged, as you know, with the crisis regarding the logistics and availability of equipment. We were supported by the fact that we had a contract — or we have a contract with Tesla. But unfortunately, Tesla has had so much difficulties to have supply in order to provide us with their — I would say, the full package that they have designed initially.
They have sent us a force majeure saying that they have to change the design or some part of the design, and that would basically delay the project for 4 or 5 months. Over and above that, we had, as you know, the infamous inquiry now from the Department of Commerce that has put the — all industry dealing with solar in the U.S. in a very difficult spot where we don’t know when and how much duty could be imposed on imported panel.
So what we have done, and I think talking with Jean over the last few days and with the team, I think it’s an opportunity for us to sit down with ECO and the PUC over there and to look into the economics of this project and the challenge we’re facing. All of the known developer in Hawaii have done the same thing as far as we know. We have initiated some discussions with ECO reaching out regarding these challenges. We also have flowed through our force majeure for the [indiscernible] Kauai project under construction to them. They have accepted it.
So I think we have an opportunity to reset a little bit the economics of all these 4 projects. We’ll take our time to negotiate. We think that we will be working in open-book fashion with ECO and the PUC. I think that they are concerned, of course, and they understand the challenge that all the IPP are facing in a while. I think that they need more than ever these projects, especially in the solar with battery, they need capacity, they need renewable energy. As you know, diesel is going through the roof and a lot of avoided costs in Hawaii is based on diesel.
So there’s a logic for them and for PUC to sit down with us and come up with a resolution that would permit these projects to go ahead. The other alternative, if we cannot agree on a revised price and revised schedule is to basically rebid these projects in RFP3 or RFP4. Hawaii has to come up with future RFP. They have this commitment. They have to shut down their fossil fuel projects. So I think that the price for RFP3 wouldn’t be very different from a renegotiated price from the initial RFP1 and 2. And matter of fact in the RFP1, there were an ITC local state tax credit that would not be available for RFP3.
So I think that the economics are guiding towards having them being reasonable with us and find a solution. So I’ll be happy to answer your questions which are at the end. But the idea there is to pause and basically minimize the equity that we are putting in the next few months and making sure that we are coming up with a better case for the viability of these projects, given the different challenge regarding the supply on the island.
On the other hand, Innavik is going fairly well. Construction has restarted as spring has come to the — even to the north. And we have announced just a slight move from the late 2022 or the fourth quarter 2022 to the first quarter of 2023 due to some small delay given the latest or — well, some difficulties to access the site last year at the end of the year with the COVID. So I think that it’s only a few months, and we should be okay to be in full operation by the end of the first quarter of 2023.
Tonnerre is getting very close to being full commissioning. We’ve been testing, we’ve been using the battery in some circumstances. Some tests are yet to be finalized completely. We expect that all those tests and full COD release should be done by the end of June.
Now for the development activities, I guess that this is the — besides the issue with Hawaii, I think we can treat the 4 projects that we have in Hawaii in the same basket, as I mentioned. For the rest, I think that it’s very, very positive. We’ve been making great progress in the development activities. Proud to remind you that Auxy Bois Regnier in France is our first project coming from our greenfield initiative that has PPA. So thanks to the team there. It’s the first, certainly not the last, but it’s always nice to see one of our own getting through all the process in France.
Also big move from the development perspective is Boswell and Palomino. Boswell in Wyoming. We are in final discussions with PacifiCorp. It’s long, but they’re a tough negotiator in some ways, and they’re facing also some delay themselves for their transmission line project. So everything is linked together. But we’re sitting down with them, and I think that we’re also advancing on some updated cost there for a little bit of a flow-through, but we managed also to change the turbine supplier, as we mentioned earlier on. That makes it more efficient in terms of utilization of the space.
So we’re all in good shape for Boswell. We just need a little bit of adjustment in finalizing the detail of the power purchase agreement. It’s going well.
Palomino, we have shown in our MD&A that we’re moving that project potentially in 2025. Just to be sure, we have signed a term sheet with First Solar to supply the panel. Those panel will not be subject to the inquiry from the commerce — the Department of Commerce in the U.S. We’re working hard trying to find another solution to have a panel a little bit earlier so that we can put the Palomino project in 2024, working on it.
We have some leads, but we have secured the supply of the panel with First Solar as a, I would say, a plan B. We don’t mind being long on panel to some degree because we’re advancing also quite a bit in the development activities in the U.S. We have talked about Wautoma, which is the Northwest and also, Last Mile, which is another project. So we’re advancing quite well in solar. So we’re very confident that we’ll need panel to supply these projects down the road.
Also, as you know, we have announced 2 best projects, as Jean has mentioned. This is a strategy in Chile that is adding up to the diversification of our portfolio in Chile. I think that Chile will benefit from those battery going forward. It’s a great flexibility addition to our portfolio. You know that Chile will and have quite a bit of solar production and can have also in the future a lot more. So we think that having battery established and interconnected to the grid is a great tool for us to take advantage of the capacity payment. I’m stressing about this notion.
Chile new system to recognize capacity for battery is very generous and could represent anywhere between 40% and 50% of the revenue for that system. And the rest is going to be making arbitrage between the day and the night or the evening or it’s going to put us into a position to be able to sign firm contracts to be delivered complementary with the rest of our portfolio.
Just to give you a heads up a little bit on what’s happening in Chile in terms of pricing. Remember that we have talked about the pricing in Chile being quite robust lately, still very strong. But the best thing, I think, is the fact that corporate PPAs are now coming from $38, $40 1.5 years ago for term from 5 to 10 years. Now they’re reaching almost 50 megawatts per hour.
So for us, it’s just the timing, and we will secure longer PPA. We just need to have the sweet spot and take the full value of the long-term value of our agreement in Chile. So we’re very upbeat on the pricing capacity in Chile, so that makes quite a bit of turn around our development activities.
And then prospective project, you will see that some pieces have moved there. But I think that the biggest move here is the fact that we have put some effort lately to answer future RFP in Quebec. I think that this is a great turnaround for Quebec. For people that have followed numerous RFP have been announced for supply of renewable energy in Quebec, so that’s a fantastic news for us. It’s a great opportunity to take advantage of the good relationship that we have across Quebec.
We have just put about 1 point — well, 1,700 megawatts of new wind opportunity in Quebec, and we intend to add some more for the future. So it’s — and I think that this is only an indication that perhaps Ontario and BC will do the same in the near future. We’ve seen ISO making a call for disparate RFP for capacity between 2025 and 2027. And now we are seeing a big gap also for 2029, which can lead to about 8,000 megawatts. So it’s only a matter of, I guess, time also to see BC waking up.
So we’re very upbeat also on our ability to redeploy resources in Canada, and you’ll see the prospective project coming in the next few years adding into the Canada possibility, but that doesn’t mean that we will go down in our other markets, France and the U.S. and Chile. As you see, there’s also great opportunity in Europe with the pricing. Jean has mentioned that we have now reached out for corporate PPA extension.
And you’ll see the number, they’re huge. And it only represents the disparate situation in the energy sector in Europe. I think that Europe or France will — we will see also some good signal from corporate PPA offtakers. So we have also initiated some discussions for long-term PPA with corporate party also in France.
All in all, I think that our industry, as you know, is facing some challenge. A lot of you have asked questions about the inflation cost and availability of services and component. Yes, we’re facing that. But on the other hand, we’re also seeing great opportunity and price escalation.
So as I mentioned earlier, I think that we have seen this turnaround now in our ability now to price our product with a premium. And I think it looks promising for the future. And hopefully, our industry will be disciplined also in future calls so that margin will improve also in the development sector.
So on this, I think I will open up the question period.
[Operator Instructions]. And your first question will be from David Quezada at Raymond James.
My first question here, just — I appreciate the commentary around the challenges in Hawaii. I’m just curious about the Paeahu project. Specifically, what the challenge was there with respect to the Circuit Court decision, and how you see that resolving going forward?
Well, I think that we have engaged in the mediation process now. Things are going okay, but of course it’s not easy. I think that we’ll go through that process and answer the question and make good faith mediation session. And if it’s not working, we’ll come back and resubmit. There is a limit of what we can do, and I think that our team did a great job in designing and making compromise in the design of the project to a certain limit.
We’re listening — I guess that in any project, even if you think that you have done everything you can, it doesn’t hurt to listen and maybe find solution that can work on both sides. But we’re getting there with good faith and hope to find a solution.
That’s great color. And then maybe just another one on — just on the PPA renegotiation at Boswell. I’m just curious if — I mean, it certainly sounds like things are going well. I’m just curious if there are still any material hurdles before you would successfully renegotiate that PPA and just a measure of your confidence on that going forward.
Yes. We don’t want to share too much, but there’s some issue about the schedule also on the COD date. And Pacific Corp. has also some issue in their own permitting and building of the transmission lines. So there’s a little bit of back and forth on this flexibility for both of us. So there’s cost also to have flexibility, and we want to see that recognized in that PPA. And like I said, I think it’s very reasonable what we’re asking, but I don’t want to get too much in detail. We’re in the middle of the negotiation with them.
I think also that some of their RFP supply were coming from solar project in order to feed that line. And as you know, these projects are facing some challenges as well. So I think that our project is very well positioned. I think it’s very competitive. We have all the other permits, and we think that we can deliver that project to the satisfaction of Pacific Corp. So we’re positive, but negotiations are ongoing.
Next question will be from Nelson Ng at RBC Capital Markets.
Just a follow-up on the Hawaiian projects. So are you able to essentially walk away from all four projects right now? Is there any — I know you received a force majeure notice and you passed it on. So does that mean you’ve essentially pressed the reset button and there’s like no liability? Or can Tesla 1 one day say, “Hey, we can deliver everything now? Like are you obliged to accept these batteries? And do you still need to deliver any of these projects by a certain date?”
I think that through our legal department, we feel very comfortable that we can — especially from the side of our PPA that given the force majeure and the — all the issues and challenges that we’re facing that we wouldn’t have to pay penalty to walk away from PPA. Now there is some contract regarding the Tesla, as an example. We think that they changed the contract quite a bit.
So I don’t think we — if we decide not to go forward with this contract that we would have to pay big penalty, same with ESON panel, I think we can certainly claim that it’s not us who changed the design or the duty because our contract with ESON was very clear that they were responsible for all the duty, and it was to be delivered on premises in Hawaii.
So I think we’re in a very good place. But the idea here is to trying to protect also the schedule and the availability of components. So this is a big part, I think, on our good faith negotiation with Pacific — not Pacific, but ECO there and the PUC. Because if we’re asking new money but we were presenting huge delay, that’s not going to fix their problem of having capacity on the island quickly.
So I think that if we can secure a good schedule with the supplier that we have under contract now and arrange for an adjustment in price, that has better chance than us just canceling everything and just hoping to have a settlement with them. But I think we’re there in a sense that we’re positive that Hawaii needs these projects. They really need these projects. And I think we’re there in a strategy to protect our investment and to make a reasonable return on our equity on these projects.
Okay. And then you mentioned earlier that you want to kind of pause the projects and, I guess, stop or pause any additional contributions going to the project. Are you able to give a rough sense of how much is being invested into at least the project that was under construction?
Under construction and development, I think you can find it in the MD&A. It’s something around…
We had $25 million on the project under construction. And there is another — I think it’s another $17 million in development. It’s about roughly $47 million, $48 million investment so far in Hawaii.
Okay, got it. All right. And then next question is the French PPAs. In terms of breaking the PPAs, like I noticed that I think they were originally the original PPAs were supposed to expire in 2025 and then you broke the PPAs and then you have new contracts that also expire I guess, at the end of 2025. And was there a break fee you had to pay? And I guess the other question is, why does it end in 2025? And why don’t you extend the term of those projects?
It’s just that there is a very sweet spot in the next 4 years, 3.5 years. Price were like close to €300 per megawatt the first year, then declining proportionately to roughly €100 on the last year. So we took that advantage to secure this. It was also we needed the agreement of the banks to do so. We think that through that period of time, we’ll have time to rethink on the long-term offtake. We can resubmit some of these projects. We’ve committed to corporate PPA.
But it was — I guess, it was an opportunity to take advantage of the huge pricing right now. And there were no penalty, actually, on those we could walk and canceled it. We had to give 3 months’ notice.
Okay, pretty favorable contract. And then I’ll try to squeeze in one more question, if I may. In terms of the BC Hydro settlements, Obviously, the settlement wasn’t disclosed. But was it close to the, I guess, lost revenues and maybe you recovered some legal costs as well? Can you give a bit of color as to whether you are fully made whole?
Pretty much. Yes, the only concession we’ve made with the average downtime that those projects experienced in that period of time, but we did receive interest and legal fees.
And we have signed a nondisclosure agreement, but you can understand that we’re happy with that.
That’s a great outcome.
Next question will be from Rupert Merer at National Bank.
Just to quickly follow up on the answer to the last question on France. So did you say the revenue you can get on your new contracts is close to €300 a megawatt hour declining to €100 a megawatt hour in the final year?
So is this something consistent with the future prices in France, I imagine?
Yes. And it’s short term, and it’s not a full corporate. It’s with a trader with very good credit. But it’s — we were amazed to see these pricing.
So do you think that it’s possible you may see some corporates come forward that could be looking for longer-term contracts. I imagine you probably need something up to 10 years to convince you to walk away from some of your other contracts. But is that possible? Is that something you’re investigating?
In that range of pricing, we haven’t seen it yet. So that’s why we have not yet secured longer term. But we’re in discussion with the solar project that 2 corporate PPA are kind of early discussion. But they’re willing to go 15 for years, but certainly not at that $300 per — obviously, but at a very competitive pricing and without a direct negotiation.
And we’re looking to do this for the development assets that we have outside of potentially the RFPs in France and to go straight with corporates in more favorable pricing environment.
And also, corporate doesn’t necessarily have the same — in France, we call it [Foreign Language], some restriction on panel, origination and land qualification. So probably easier to develop projects that way also in France.
Okay. And just — sorry, just to be clear, I think you had said €300 once and $300. It’s €300, is that correct?
No, no, €300. I’m sorry, €300.
That’s okay. All right, moving on to the battery facility in Chile, you talked about the revenue split you anticipated between capacity markets and arbitrage. How much revenue do you think you need to underwrite this investment? And what are the assumptions around the life of the battery, whether it’s cycle life or a number of years that you need this battery to be working to give you the returns that you need?
Sure. We have 20 years life expectancy with that battery with a contract with Mitsubishi in trying to maintain these battery in a good sense. Mind you that they’re not doing a lot of cycles, these battery. We anticipate only 1 cycle a day. We could be surprised and have more opportunity to cycle them a little bit more. Typically, we need anywhere between $35- and $45-ish per megawatt hour in arbitrage and the rest would be covered by the capacity payment that Chile is putting together for battery.
The system in Chile for recognizing the capacity is sometimes the equivalent of RFP that are going on in New York or some other places just for capacity. So it’s — for us, it’s something I think of a great interest because almost half of your revenue is already secured through this capacity payment process — not process, or regulation. It’s not new in a sense that Hydro has some capacity recognition. Wind, same thing.
Solar will see their capacity payment diminish over time as solar is building up. But it’s not new. And the fact that the rules there apply for a battery that have 5 hours, and if you have 5 hours then they’re fairly generous because they perceive that, that system is flexible enough to meet the critical hours of the grid. And hence, they’re giving a fairly good number. But Jean, maybe you have specific numbers.
Yes, I guess we’ve established our base case on more conservative number than what you see today in the market. So as Michel said, I mean, if you have 45 — a spread of USD 45, I guess, that does it. But right now, we see spreads that are much wider than this. So actually, in effect, as soon as we can be online. And if the pricing environment stays the way it is, it would be a lot more beneficial to us.
But so yes, and the capacity payments, I guess, we’re estimating a $7 kilowatt month dollar — payment. And that’s also, I think, a conservative number in our base case. So that was sufficient for us to actually purchase the battery, install them at our sites, and make a good business case out of it.
And maybe one thing to add, Rupert, also is that we were right on time in the purchasing of these batteries. If you see the, I guess, the price we paid for these batteries compared to the price today, even if we’ve announced them earlier, we started the negotiation some months ago. And I think that benefits also our case study here because we entered the market at the right time. The price of batteries now have kind of come up like quite significantly, I guess, to by about 30% in the last 1.5 month or 2 months.
Great. And on the market dynamic there, and you talked about the fact that you could see more solar coming online, and I suppose that’s a risk to your existing solar plants. Do you see any risk that you could see more batteries as well, which may really, let’s say, reduce the attractiveness of the economics for your battery? What is the market dynamic? How much visibility do you have on what’s coming online?
Rupert, there will be a lot more battery because there are a lot less coal. So whatever you’re taking out as coal, you have to replace it somehow by capacity for the evening and the night. Also, the system operator has been calculating the demand and offer or the balance of the market based on historical hydrology going back 30, 40 years.
And we know that the hydrology into has changed probably for the worst. And we have calculated that when we’re making our investment thesis on hydro, we’re taking the last 10 years instead of looking at for the last 40 years. So maybe eventually, the hydrology will come back. But lately, the hydro contribution is not as high as historically.
So if you take out the coal, you’re reducing permanently some of the hydrology in Chile and you’re taking into consideration that natural gas will be expensive for the next near future in Chile. Even if you — well, still needs a lot more battery because right now, they are taking some diesel capacity under coal and the price are fairly high. We’ve seen $200, $300 per megawatt hour fairly often in the marketplace.
So yes, there will be more battery. The [indiscernible] is there. We are an early adopter with a fairly good price, and we don’t have much exposure in solar anymore because these have translated the solar project into evening or even night projects. So we’re feeding our own every with our own solar, and we have probably only 20 megawatts in excess — 20, 25 megawatts in excess in solar energy. We just under-designed a little bit the battery just to make sure that we have a little bit more solar capacity.
Next question will be from Sean Steuart at TD.
A couple of questions. I want to talk about your prospective pipeline for wind in Canada and the 1.6 gigawatts that you’ve moved to your mid-stage development bucket presumably all in Quebec ahead of the RFP. Can you speak to the bidding strategy there, if you’re able to or willing to? The total capacity that you have would be most of what’s, I guess, being envisioned by Hydro-Quebec right now, and your expectations on community and First Nations participation in those types of projects?
Well, Sean, there’s a lot more that have been announced. You have the 300-megawatt only wind, then 480 megawatts all renewable.
It’s actually like a 4.2 terawatt hour, not 480 megawatts, right?
So that’s a lot more. And then they call for another 1,000. And another — there’s another…
1,300 and 1,000.
And the plan for Hydro-Quebec calls for the creation of a portfolio of projects of 3,000 megawatts on top of the RFPs that will be issued.
They’ll need a lot of future energy in Quebec for wind. And electrification is serious. In Quebec, it’s advancing. The only solution for Quebec to really reduce — to decarbonize Quebec is not going into reducing electricity carbon emission, is to go to transportation and big industrial, and some buildings that need oil or natural gas due to heat, but not that great. So Quebec will need quite a bit more in the next 20 years.
Okay. Understood. And the 4 projects that you’ve moved to your mid-stage bucket, the First Nations and community involvement is already thought through with respect to those projects, I suppose?
Not completely, but a big part of it, yes.
Okay. Second question is on your broader U.S. prospective solar pipeline, which I think is about 20% of your overall prospective capacity that you talk about. And the question is, appreciating that a lot of what’s happened in Hawaii is related to the force majeure from Tesla and temporary presumably supply issues. Do the developments there, though, change any of your thought process on the longer-term opportunity for solar in the U.S.? Anything that tempers your ambition for that prospective pipeline at all?
No. Sean, we’re looking into alternatives to have supply of panel in the states. I think that they’ll come up with some kind of a resolution, I guess. But I understand why these rules are in place and to favor the fabrication of solar model into the states. I think it’s fair game to have that in, in a sense that whenever you’re developing your renewable energy, it’s great if you can support some jobs.
But I think there’s an equilibrium between how fast you want to develop and deploy renewable energy in a certain market, together with creating a manufacturing job in the same area. It’s not easy, and I think that the equilibrium will swing back and forth a little bit. And we’ll have — U.S. is known to have these crisis here, right?
I mean when it’s not ITC or PTC cliff, it’s this inquiry. There’s always something in the U.S. that makes people nervous. On the long run, U.S. has shown resiliency in their ability to have more and more renewable energy being built. And they still have this ITC and PTC support program that the market are trying to pass. I don’t know if they’ll be successful before the midterms.
But remember that the last package was a bipartisan package. So we’re confident that somehow, somewhere, the U.S. will come up with support for renewable energy. In the meantime, like I said, we have secured the panel for Palomino. We have, if you remember, 125 megawatts of panel that we bought for ITC purposes. We have paid a premium a few years ago for them.
Now that premium has disappeared in the sense that they will keep compared to some pricing that we’ve seen lately. So I think we’re in good shape. We also will and the industry will eventually put a right price to the future RFP. Mind you that with the ITC, long-term PPA — Hillcrest long-term PPA was signed around $32, $34 per megawatt hour. So that’s pretty cheap, too. So even if people have to sign at $40, $45, it’s not that expensive to have green energy either.
So I think that one has to put that all in perspective. I think that the U.S. has benefited from really dirt-cheap renewable energy project. And I think that the corporate America has the room to pay up the reasonable and the fair price to have renewable energy.
If I can add just on the DUC investigation. There is senatorial support, it’s bipartisan as well, from both Republicans and Democrats right now to put pressure on the DUC so that they have a preliminary determination faster than what is anticipated. So it could also be determined as early as mid-May that we — that’s what we hear. So the schedule could be advanced to have a determination here.
So the whole renewable industry is supported by both Democrats and Republicans. I think it’s important to note that. Because whenever there’s an issue facing the industry, it’s always been supported and they found ways to move forward.
The last thing, I guess, the Build Back Better is a large build, but the components that are regarding renewable support, there’s also bipartisan support. So maybe they will I guess, cut the bill in smaller pieces. And one piece that is one of the most certain to move — I mean, if they have time, obviously, in Congress and Senate to pass this before midterms, would be the support for the renewable energy program.
So I mean the industry is pushing back very hard on this and actually making it — putting a lot of pressure, and the response is pretty positive so far.
[Operator Instructions]. And your next question will be from Andrew Kuske at Credit Suisse.
I guess just given the broader energy market dynamics that are happening in Europe and then some of the specific issues in France around the nuclear units that EDF has. How do you think about just your prospective project pipeline, in particular, just what you have in the queue in France? Do you believe that, that pipeline is going to expand and maybe grow more rapidly than we’d see in some of your other areas of exposure?
Well, I’d love to. But as you know, France is not easy to [indiscernible]. I think that solar, we may see a little bit of, I would say, more flexibility in some of the process to get permitting in France. That — I think that the agencies in France understand this. It’s not easy to change those rules, but there is definitely some area where they could speed up the process.
Like I said, maybe if we can have direct negotiation with corporate offtaker, some constraint on land might be easier for us to meet. So we’re looking into all this. But obviously, given the pricing, we may have some ability to give perhaps some more compensation for the project to landowner and to potentially municipality.
So the team is really aware of that any project that we can bring will find a home in France for sure. It’s not a lack of demand. It’s a lack of project and the difficulties to bring project to determination and then being able to start construction.
That’s very helpful perspective. And then maybe if you look across your geographies where do you think you have the best risk-adjusted returns at this point in time?
That’s a good one, it’s interesting. It’s always — it’s easy to say, not easy to adjust in some ways. But we’ve been active in Chile in ways. I think that has been great in the last couple of years. But I think Canada, in Quebec is showing great, great opportunity. We’re very well positioned in Quebec and BC.
Like I said, BC will wake up and smell the coffee. BC Hydro is sleeping on the road right now and is going to crash. Ontario is waking up as we speak. We have seen Quebec turnaround in less than 3 years from surplus to, “Oh, my god. We need a lot of megawatt”. And I think this — we’ll see that in some other markets.
It’s happening everywhere. The carbonation in France in sales efficiency is top of mind right now. So they’re trying to cut the duration of developments, and there’s renewed interest for onshore wind and solar, and obviously, uptown, which we were not present there. But the nuclear is not going to replace the demand. It’s not going to come from nuclear, because nuclear takes too much time. And there’s already issues with the existing nuclear.
So France, I guess all over the world right now, like there’s a lot of demand and decarbonation is a reality. Legislatively, they have to meet their targets. And yes, I think it’s very — I think there’s a lot of opportunity. And we risk adjust each investment that we make because every project is different. The reality is not always — it’s not so similar in some cases. So we try to risk adjust each time.
But I would say that the best surprise for us Canada, lately. It’s Canada. Quebec is waking up and the rest of Canada. It’s just a matter of maybe time zone. They’re late a little bit, but they’ll wake up eventually in the West.
Next question will be from Naji Baydoun at IA Capital.
Just wanted to follow up on that last comment in Quebec. I guess, contrary to Chile or your pain market dynamics, pricing signals in Canada and in Quebec are going the other way. How does that necessarily impact sort of the returns on the projects that you’re looking at in the province?
I think it was true a few months, even a few years ago, I don’t think that Quebec thinks that they’re going to get wind at $0.03 per kilowatt hour in Quebec anymore. I think you’ll see decent pricing being put forward.
Perhaps in the past, we’ve seen really, really aggressive pricing in Alberta and Saskatchewan with very little size. Only 200 megawatts in Saskatchewan, and perhaps a 10x subscriber RFP brought the pricing really low. But remember, that was about 18 years ago when bonds were at 1% and wind turbine were — give it away. I think that things have changed big time now.
And actually, even the CEO of Hydro-Quebec, as we previously mentioned that the next megawatt that they could prepare in Quebec, if you include capacity, distribution and production, would be ranging — would be at about $0.11 a kilowatt hour. So they’re very mindful of that. The date of — the time where pricing was around $30 a megawatt hour is gone. It’s long gone.
Yes. It’s gone now. And I think that the industry also is waking up to the fact that discounting the price curve and hoping to see discount and discount I think the — well, anyway, they’re serious player in our industry, I think we’ll be more disciplined in the RFP to come.
That’s very helpful detail. And just on Palomino, if you can give us an update on how the discussions are going with current offtaker or if you maybe are looking at somebody else, and you didn’t get the price that you were looking for?
Yes, we will be in a position this summer to — I guess, to shop that project. Although the 2 existing term sheet participants are very eager to continue, and they have requested more time. In the meantime, we’re looking at the market, and the market has improved in that area for corporate PPA big time. So we’re very confident that it was a great — the best strategy for us is to have this window of reopen negotiation.
And we’re in good shape. I think that Palomino will be a great project. We just need to have — to find a solution to have panel made in the U.S. or not subject to this inquiry. Like I said, we have the first solar alternative being delivered very early 2025, but we’re — our team is looking hard to find a solution to have panel that could be delivered early so that we could continue putting this project in service by 2024. But on the economics, we feel very comfortable with Palomino.
Okay, got it. Just one last question for me on Chile. Just specifically on the portfolio refinancing initiatives. Just thinking about the debt that you already wanted to raise and now you’re saying you could take out more equity to fund the best projects. How far along is that process? Is your cost of capital assumption there changed at all? Or is it still sort of in line with what you’re expecting?
Well, Jean will give you more color. But we were lucky enough to fully hedge that loan as we had announced the acquisition. When we signed the purchase sale agreement, we did put a hedge strategy. So we’re protected from the last run into the interest rate.
Matter of fact, we kind of catch the low end when the war in Ukraine started, and we benefited from a little bit of a dip into the long-term interest rates. So we’re in good shape in terms of having fixed the economics there. And Jean, maybe the negotiation is going well?
Yes. The negotiation is going well. It’s a rated private placement that we intend to put in place. And obviously, secured on the entirety of the portfolio in Chile, including the Aela projects. And we also are putting in the new best projects within the financing as well. So no, it’s advancing very well, and we expect this to close in Q2. So by the end of Q2.
And as Michel mentioned, I guess, the macroeconomics hasn’t changed. I mean we were hedged. So it’s still — we didn’t — we weren’t impacted from macroeconomic movements here at all.
Okay. So the refinancing and the Aela acquisition is still on track, no changes there?
Next question will be from Ben Pham at BMO.
I had two cleanup questions. I wasn’t sure of my first question is on the 2022 guidance, whether it’s EBITDA, free cash flow. I wasn’t sure if you mentioned it. Were you reaffirming that guidance?
For 2022? Yes. But what we said is that — I’m mixing maybe when the annual meeting that I gave the guidance on 2022. Yes, we’re maintaining our guidance for 2022. It may improve because we haven’t included the Aela acquisition. We are forecasting it to be in first of June — 1st of July, right?
Well, we will reaffirm guidance in Q2, I guess, or at the closing of the Aela because it’s a significant impact, and the refinancing. So once we close and we have certainty on refinancing Aela and — so I guess at the end of Q2, we’ll reaffirm guidance for the year.
Okay, got it. And do you think this year on your payout ratio, there’s a potential for it to come in to 100% because you’ve made some good progress this quarter, looking at the percentages. I’m just curious how that’s trending for the rest of the year.
If weather keeps for being on P50 or long-term average, we see no reason why we shouldn’t be below 100%. We’re thinking that we’re going to be below 100%.
Thank you. And at this time, we have no further questions. Please proceed.
Thank you very much, everyone.
Yes, thank you, all.
Ladies and gentlemen, this concludes the conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.