Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Innergex Renewable Energy 2022 second quarter results conference call and webcast. At this time, all lines on the phone and Internet are in a listen-only mode. Following the presentation, we will conduct a question and answer session for analysts and institutional investors, and instructions will be provided at that time for you to queue up for questions. If anyone has any difficulties hearing the conference, please press star followed by zero for operator assistance at any time. I would like to remind everyone that this conference call is being recorded. I will now turn the conference over to Adam Belayache, Director, Investor Relations. Please go ahead, sir. 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. A presentation supporting today's discussion is also available as we speak on the homepage 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 circumstances occurring after the date hereof, unless so required by law. Also, during this call, we will refer to financial measures that are not recognized according to the International Financial Reporting Standards. Please refer to the non-IFRS measure section of the MD&A for more information. Our speakers today will be Monsieur Jean-François Neault, Chief Financial Officer, who will present Q2 results, and Monsieur Michel Letellier, President and Chief Executive Officer, who will review our operational highlights. I now turn the conference over to Mr. Neault. Good morning, everyone. Thank you, Adam. I'm very pleased to be here again for Q2. Just the financial highlights. The corporation's financial performance posted actually very strong growth for the three months ended June 30, 2022 compared to the same period last year. Production was up 19% at 2.8 terawatt-hours, and revenues were up 29% at CAD 219.7 million compared with the same period last year. This increase was mainly explained by the contribution of the 2021 and 2022 acquisitions, namely the remaining 50% interest in Energía Llaima, for which results are now included in Innergex's consolidated performance, the Curtis Palmer Hydro facility, the San Andrés Solar facility, as well as the Aela Wind projects recently acquired. The commissioning of the Griffin Trail and Hillcrest facilities also contributed, as well as higher selling prices at the Phoebe Solar facility and higher production at the Quebec Wind facilities. These items previously mentioned were partly offset by lower revenues at the BC Hydro facilities, stemming from lower water flows, basically due to a cooler season, so delaying the melting season to later on, and also lower wind regimes and lower exchange rate at the French wind facilities. Operating, general, administrative, and prospective project expenses were up 40% at CAD 66.9 million. The increase is mainly attributable to the 2021 and 2022 acquisitions and asset commissionings, as mentioned earlier, as well as higher maintenance costs at some of our BC Hydro facilities. As a result, adjusted EBITDA for the three-month period ended June 30, 2022 reached CAD 152.9 million, which represents a 25% increase compared to the same period last year. Although net income is not a measure typically in focus, it's important to note that this quarter the net loss is mainly explained by a CAD 45 million decrease in recovery of income tax related to the disposal of the Shannon and Setup facilities and a CAD 35.6 million unfavorable realized and unrealized changes in the fair market value of financial instruments. Our proportionate financial performance also posted growth for the three-month period ended June 30, 2022, and the increase in proportionate metrics was largely driven by the variances explained in the previous slide, in addition to the PTC contribution from the commissioning of the Griffin Trail wind facilities. Continuing to the next slide. For the trailing twelve months ended June 30, 2022, the corporation generated free cash flow of CAD 149 million, compared with CAD 92.5 million for the corresponding period last year, normalized to exclude the impacts of the February 2021 Texas event. This increase was primarily explained by the incremental contribution from the 2021 and 2022 acquisitions and the asset commissioning activities, as mentioned earlier, and the BC Hydro curtailment payment that we received during the quarter, the first quarter. These items were partly offset by higher debt principal repayments stemming from the Energía Llaima acquisition, the beginning of debt repayments for the Upper Lillooet and Boulder Creek project loans. An increase in free cash flow attributed to the non-controlling interest stemming mainly from the Curtis Palmer acquisition and unfavorable differences between sales at the Phoebe node and purchases at the Arcot south hub. The increase in free cash flow versus 2021 resulted in a 40 percentage point improvement to our payout ratio, which amounted to 96% for the trailing twelve months ended June 30, 2022, compared with 136% for the same normalized period last year, which is, in my view, a great improvement, and we're very pleased about the turnaround in our payout ratio. When excluding prospective project expenses of CAD 24.7 million, the adjusted free cash flow stood at CAD 173.6 million versus CAD 113.3 million for the same normalized period last year. The adjusted payout ratio consequently reached 82%, compared to 111% last year. Like again, a great improvement. Next slide. I would like to remind everyone that the 2022 performance projections communicated at the beginning of the year did not take into consideration the potential acquisitions that could be achieved in 2022. We have since then revised our performance guidelines subsequent to the closing of the San Andrés and the Aela acquisitions. The projections were also revised to take into consideration the below average water flows, wind regimes, and solar irradiation at some of our facilities in the first six-month period. Consequently, and compared to 2021, the normalized actual performance, the corporation is projecting a 22% increase in production year- over- year, a 25% increase in revenues, a 25% increase in Adjusted EBITDA, as well as a 21% increase in Adjusted EBITDA proportionate. Also, we revised the free cash flow per share target, which is now projected at CAD 0.75 per share, which represents a CAD 0.02 per share increase versus the CAD 0.73 per share target that we communicated at the beginning of the year. On the next slide, subsequently to the first quarter period end on July 25, 2022, the corporation settled the interest rate swap, which were intended to mitigate interest rate fluctuations in connection with its Chilean facilities non-recourse debt refinancing. Basically, we ended a portion of our swaps that we had put in place to protect ourselves from interest rate movements at the time when we fixed actually the interest rate, the pricing of the debt that is gonna be concluded imminently. The net settlement in our favor amounted to CAD 53 million, which was captured upfront. Also, on July 25, 2022, the corporation sent a notification of cancellation to Longueval PPA offtaker in France in order to take advantage of current favorable energy pricing environment. This will become effective on November 1st, and we hope to take advantage of the high pricing environment in France for this asset. The corporation will leave this facility merchant until such time where we deem appropriate to fix the rate for the future. We're consistent with what we did at Antoigné, Porcien, and Vallottes, where we actually did fix under a new power purchase agreement the rate that took effect actually on August first. As concluding remarks, we're very pleased with the corporation's performance over the second quarter versus the same period last year, and especially the reversal in our payout ratio profile. The past few months were very fruitful with the execution of various initiatives, and I'm glad to give the floor now to Michel, who will go through the operational review and these initiatives that we've put forward. Thank you, Jean, and good morning, everybody. I guess that the last quarter was pretty busy finalizing the acquisition of Aela. As mentioned by Jean, the refinancing. The team is working hard. We should announce imminently the closing of the transaction. As Jean mentioned, we did protect ourself when we announced the transaction, the acquisition in the beginning of the year. We were protected from the movement of the interest rate, which amount almost to 100 basis points. We were very. I wouldn't say lucky. It was a good thing for us to put that hedge in place. Aela is completing well, is adding to the portfolio in Chile. As we mentioned, the strategy there is to build a portfolio with all the renewable technology that is available in Chile, meaning hydro, wind, solar, and also, we're adding all the battery system to two of our solar asset in Chile that will enable us to be flexible to deliver the electricity in the evening and during the night. As we mentioned in the past, Chile has a fairly good system to compensate for capacity, and we think that the mix with capacity and arbitrage between the day and evening is very attractive to have battery in Chile. These will be the biggest battery in Chile for the time being. We think it's a very good timing. We were able to secure the price of the battery early in the year. Since then, the price of battery went up materially, so I think we have a very competitive and compelling proposal with these two battery system in Chile. Also, if we flip the page to construction activities, we have advanced the discussion with HECO regarding our activities in Hawaii. As you know, this is the challenge of the industry. We've seen people that had the long-term PPA already signed before what we have seen, the result of the COVID, the rapid inflation, and the difficulties to have access to component have made the industry, I guess, searching for solution in demanding increase in PPA. This is also true for our Boswell project. I'll talk about it. I think that we've seen in the HECO and the PUC in Hawaii some willingness to enter into fair negotiation to take into consideration these conditions for the market. I think that this is becoming an industry-wide challenge that utilities have recognized and have accepted to enter into fair negotiation to support these early project or early development stage project in terms of negotiation and coming to an acceptable price. We haven't settled yet in Hawaii, working towards presenting these demands. Inuvik is going great in the sense that we have restarted construction. We're still maintaining that the project will be in service next year, so a little bit of potential delay, but all in all, we're pretty happy in the advancement this summer. The idea is to make sure that the power is finished before the winter, so we can continue commissioning the project inside the powerhouse. So far, this schedule is going to be met. I just spoke about also the Salvador battery storage. Construction has started mainly all the civil installation are on the way, and the production of the batteries are also on schedule. So far, this project is going well, even if China had some closure this early summer, late spring. I think we'll be able to manage to have all the component we needed to finalize. Mitsubishi is working hard on the schedule. Development activities, we have, as we mentioned, the other project in Hawaii. We have Barbers Point, Kanaha, and Paeahu. Same story here. We're gathering information and data to support the demand to increase the PPA price. Same here. I think we have a willing utility on the other side to understand that PPA price has to go up in order to have these project to be built. Under negotiation there as well. San Andrés battery storage, I mentioned, is also in our development activities. As soon as Salvador is advanced, we will continue on San Andrés. The team that works on the civil will switch to San Andrés, and we'll have a delivery of the battery just shortly after that. I think that these two projects will be a great success in terms of delivery and timing. As you know, Chile market is pretty hot these days. We are seeing a lot of high pricing. I think that the battery will be very effective down the road. Continuing on Chile, we have the small Rucacura project that we had delayed a little bit because of the supply chain issues. Now things are settling and we are re-engaging with the supplier to have the equipment delivered probably next year. Frontera is still under negotiation with the potential offtake. Just take a moment to talk about the last RFP of the DisCos in Chile. Very funny story there. I don't know, guys, if you have looked at it, but the DisCos are the utilities and the different utilities across Chile every now and then has to come and make an RFP for the retail customers that they're serving. This RFP was looking for 5,000 GWh, and they only awarded about 700, just shy of 800 GWh. The reason is that they had established a ceiling around $41 per MWh, which was way short of the offer. It's a good, very good sign actually. That means that they would have to come back in December and add to the previous announced call of 2,000 MW. They would then have to add up the 4,000 MW that they haven't been able to fulfill. The next call will be something around 6,000 GW. The average price that the producer submitted was closer to $50 per MWh, up from the 38 at $38 that was submitted last year. There's definitely a good trend in Chile showing strong number for the electricity. As you know, we all have been waiting for this to happen to advance Frontera and San Carlos, and potentially signing also some of our electricity instead of it being on the spot market. This DisCos needs the electricity in 2027, so that would give us the time to build and to take advantage also the, on the high pricing right now in the, in the merchant. All looks good in terms of strong price signal in Chile. Now if we come back to the U.S., we've been very active with Boswell. As you know, PacifiCorp is a very sophisticated utility. They are taking care of their supply very, very closely. We have been negotiating with them. We have came to a settlement. We cannot disclose the pricing. They're finalizing their presentation to their board, and we're hoping to have the signing document of our PPA very soon. Things have been, I guess, intense, but we're happy with the outcome. I think that it's in line with the industry demand these days. You've seen some price increase here and there across the United States that have ranged from 15%-30% increase in pricing. Without taking, you know, divulging any specific, we're happy with the numbers that we got. We're happy with the re-engineering as we mentioned early on with GE machine. I think we have a very strong project now and looking to start the construction as early as this late fall if things are being signed and go according to the plan. Palomino is the same thing. We have advanced, and actually the development is going well. We have the Ohio Power Siting Board that has recommended Palomino for obtaining their environmental certificate. We have engaged also with some potential off-taker. As you know, we have two off-taker in line, but we have the ability also to have a check on the market. Price has gone up very, very strongly in that area. As you might know, Ohio doesn't have a lot of renewable energy, and in this area, because of PJM constraint in interconnection, we're grandfathered there to interconnect, so there's not a lot offer of renewable energy in that part of the world. I think we have a very good position to finalize a good price of our PPA for Palomino. Still looking to start construction late next year and potentially delivering electricity before 2025 to meet the ITC. Very good news there. Boswell Springs, just to give you also, I forgot to tell, but Boswell has all its permitting, even the line. We're ready to go as soon as we have the final PPA documentation and the board approval. Pretty good advancement actually on those two. Now if we go to France, as you know, France is really, Europe is really hot these days, given the energy crisis. We're trying to accelerate what we can in France. You know that we have now Oxy Bois-Roget, our first greenfield project that have been advanced. We're trying to take advantage of the new legislation or proposed legislation that are aimed to speed up all the permitting in France. We will be looking towards taking advantage of any of those and advancing also on project that we have. Hopefully, we'll be able to speed up some of our existing project. If we flip to the prospects page here, what is interesting is that you see that we've been moving project towards the advancement stage and to the mid stage. We've been very active in Canada. Actually in the last quarter, some of you know that we have an RFP going on in Quebec. We have submitted the project. It's about a 100 MW extension of our MU project. We intend also to advance a lot more projects, a lot more megawatts in the next year RFP. Working on a pretty big project in west, on the North Shore, but south of Lac-Saint-Jean, with the Atikamekw and potentially the Innu First Nation. Working hard on developing some very strong portfolio. Also, possibility of further expansion on MU. A lot of megawatts will be available for the next RFP, and it will be a bigger. There will be some competition, but I think that, those projects have very good resources and are very, well-positioned to interconnect as well. In terms of solar and wind in the States, as you might, have seen, the industry is, quite, interested to understand what will be the final package that Biden and Manchin have negotiated. So far it's not passed, so we don't wanna get too excited about it. If it's passed, I think it will be also very positive for the future development of United States. ITC and PTC will be extended. Little disappointment on the fact that, we will not have a direct pay for IPP. Some direct pay will be available for Co-op and First Nation promoter. Nonetheless, I think that the package is promoting renewable energy all over, promoting also more electrification of transportation. All good in terms of promoting the consumption of electricity and green electricity in the States. Some ITC have been also updated for a battery storage, standalone, so that's a good things also. Some provision for hydrogen, green hydrogen has been introduced as well. All in all, very positive package. We don't know if it'll pass or not, but nonetheless, if you remember, we have our strategy of owning solar panels that will qualify up to 600 MW or even a little bit more than 600 MW of solar. We have now a lot of good perspective. One I mentioned in the last call was Wautoma. It's in the state of Washington. This project is actually advancing very well. We have a lot of traction for corporate PPA for offtake in that area. We think that this one will actually speed up pretty fast. Also, we understand that PacifiCorp will be looking for more RFP in the near future. Remember that we have also a project called Wind Dancer, that is just under the transmission line of Boswell. That's a 400 MW wind farm that could be well positioned to be proposed in future RFP of PacifiCorp. We're positioning ourself to be in a position to answer future call in the West, working in New England for solar and battery option as well. All in all, I think that we have our development team have been very busy in advancing the advanced project and development project, but they also have been very well positioned to put more early stage project and advanced stage project in the pipeline so that the future goal will be strong for us. Subsequent event, we have finally put the Tonnerre battery in service. It was quite an achievement. It's a first, fairly big battery in France to be able to add to the auxiliary system, not only the power and discharge, but also helping on the microgrid, the grid. Pretty good. I think that Devlo did a great job. Took a little bit more time than we had expected, but we have a very strong system now. It's been in operation for a few weeks with no flaws, so we're very happy of this outcome and looking forward to do some more in France. I think that France will be looking for a little bit more of those in the near future. On that, I guess that we can open up for the question period. Thank you. Ladies and gentlemen, if you have a question, please press star followed by one on your touchtone phone. You will hear a tone acknowledging your request. Your questions will be pulled in the order that they are received. Please ensure you lift the handset if you're using a speakerphone before pressing any keys. Your first question will be from Sean Steuart at TD Securities. Please go ahead. Thank you. Good morning, everyone, and thanks as always for the detailed run-through. Two questions. The 2022 guidance ranges that you've given for the various metrics, can you give us a sense for the second half of the year, any base assumptions that are going into that? Are you assuming LTA generation? Are you adjusting that based on what you've seen so far? Third quarter, any context on some of the assumptions that are building up those growth rate targets? Yeah, sure. I'll take it and maybe Michel, if you wanna add. Basically we're taking the first six months as they came in and adding the next six months on an LTA basis. What we didn't adjust is the pricing environment. We took basically what we had foreseen in terms of pricing in Chile, for example, or at Griffin Trail. There's actually quite a bit of potential upside to that number. We were, in a way, conservative, Sean. Anyway, we kept, like, the inflation outlook the same. We didn't change the inflation outlook for that, except for the new assets that were purchased, like Aela, for example, well, actually, they were purchased in the year. But still our, I mean, there's still probably power pricing power upside on the on the Aela for the portion that is not contracted. Pretty comfortable with these assumptions. I mean, pretty conservative, I think. It includes the Aela refinancing that is really imminent to close. It does include the fact that through this financing, we finance entirely the Salvador BESS project, so that's also part of it. I don't know if it's clearer or if you have other questions regarding that. That helps. Maybe just following on that. Maybe we'll just wait for the announcement, which sounds like it's imminent. The refinancing in Chile, can you give us some broader updates on dollar figures attached to that? How you expect that to flow through in terms of your available liquidity and your financing costs going forward as well? Yeah. It's a good question 'cause you've seen on Q2 and end of quarter, the usage under the revolving line of credit is pretty high. There's a fair amount of cash that comes back up that will reduce the usage under the revolver. The financing. Well, rates increased, but we hedged ourselves as we explained. Also, we're replacing debts that will actually have a mark-to-market positive in our favor. We have to look at it as a whole, right? Like, it's the financing that we put in place, which will be above $700 million. It's very imminent, right? We would have liked to announce it today or, like, yesterday, but we couldn't. It's coming in very, very shortly. All in all, I mean, we're refinancing all the debt in Chile. We're also including a fair LC facility to help us in our operations. We are financing the Salvador BESS project in its entirety, and we're gonna flow back up roughly CAD 150 million upstream. We realize on the gains on the hedges that will total roughly $60 million. Yeah, around, like, everything is unlocked obviously soon, so we will have the final numbers. It's a rated green bond. What's interesting is that it actually puts a lot of, I guess, credibility on our investment thesis in Chile 'cause it's been rated investment grade. Lenders looked at it as a portfolio, obviously. I think that's what we, you know, we told the market for the last three years now that we're building a portfolio that is diversified and that can answer 24/7, that can actually attract interest from, you know, from a power off-taker perspective. With risk diversified in the way we, you know, we produce revenues by the three different segments, but also with the battery systems being now included in 2023. You know, we're very pleased by that. I think it's a great outcome. We'll build on it, right? The idea is to keep building on this and on that foundation. Understood. I don't know if that. That's great detail, Jean. I will get back in the queue and open it up. Thanks. All right. Thanks, Sean. Next question will be from Nelson Ng at RBC Capital Markets. Great, thanks, and congrats on a strong quarter. Just a quick follow-up on Sean's question on the Chilean refi. Is there any flexibility on the refi for future growth in terms of, like, upsizing debt at a later date or adding additional tranches? Yeah, there is, but it's a private placement, right? It's as any other private placement, there is obviously an interest from the syndicate of lenders to increase their position. We need to make it in the construct that exists already. We need to remain, you know, to remain BBB- or triple investment grade, and we'll need to abide by the ratio that set the loan amounts. Yeah, there is a possibility of that. It's not—We don't have to, but there is a possibility of that, to add tranches to it. I think the lenders that are joining in. Actually, it was oversubscribed, and so we scaled down all the lenders. There was definitely a lot of interest to participate. I would anticipate that if we were coming back to with an additional tranche in the future, they would participate. Okay, thanks for the clarification. For Michel, in terms of the PPA discussions and settlements, can you just confirm for Boswell Springs, you said that PPA is finalized and that's consistent within the industry range of 15%-30% improvement? Yes, that's what I said. It has to go to the Board of PacifiCorp, and they're quite concerned because I think they still have some negotiating going on with other proponents. We cannot talk about the price. You know, it's consistent with the activities that have been going on in the States. For us, we're happy with the result. It's a win-win, I think, for PacifiCorp and ourself. We were very active with the pre-engineering with our team to select GE, and GE did a lot of effort in putting their best proposal both in terms of pricing and long-term operation of the site, and also providing the right turbine to extract the maximum energy on that site. We're very excited on the outcome. Very proud of all the team that worked hard to develop the project and does the engineering. We have also the balance of plant a contractor aligned. We have all the pricing in place, so we're ready to go, ready to fire. It's all good. Maybe I can add something, Nelson, just to give you more, a bit more color. I mean, it's 320 MW under long-term 30-year PPA that is busbar, so meaning no shape, no basis risk, and it's gonna yield us like mid-teen, like IR returns, levered returns. It's a great turnaround story, like the phoenix rising from the ashes, honestly. As you know, it was a difficult project back in the days. We had to take a small write-off at one point, but it's a nice turnaround. As Michel said, the team worked very hard. Nice turnaround, and we got enough pricing power at the end to lock in, and we're just waiting for them to. They packaged it up with other proponents, so we're waiting for that package to go through their approval process. Another thing that we would have liked to mention in greater detail today, you know, maybe we'll be a couple days short or weeks. I don't know, like, how long still, but yeah. Okay. That's great. That's the part we cannot control. It's the final process of PacifiCorp. So we've done our job and waiting for their process to go through. Okay. Then just moving to Palomino, like, is from that perspective, the PPA discussions. I think you guys have given an offer to the current offtakers, and they are still deciding on whether to accept the bid, or has that all been accepted and sorted? No, they still have a first right of refusal at the end, but the market has moved a lot. In this case, I think we can discuss a little bit more freely. We were around. It depends if it's a bundle with the REC or just the electricity and then the REC separately. As a bundle, if you take the REC and the electricity without the CapEx payment, because the CapEx payment has been a little bit of a deception in PJM lately. The price of the bundle, both REC and the electricity, has gone up materially from the mid-30 to the, you know, low 50. That's a big step. That's the market today, and I think it can even be improved a little bit. Okay. That's great color. Then just one last question, switching over to France. So you've canceled a few contracts to get exposure to the strong merchant power prices. Are you in the process of reviewing additional projects to cancel contracts? I presume if you are, you'd probably want to do that relatively soon, given that the winter prices in France are really high? Yeah. We're looking into the fine print of those contracts and what are the intentions of the regulator regarding these contracts. Yeah, we probably could. We're trying to assess if it's practical, if it makes sense. Given the forward pricing, we're surprised to see the forward pricing. What we've seen for December is something close to EUR 800. We thought we had a great deal with the first three earlier this year around EUR 200. That's why we're staying merchant on the last one. You know, if those price signals are still there for a fairly long period of time, I guess any penalty can be absorbed fairly shortly with these pricing conditions. Yeah, we're looking into it. Okay, thanks. I'll leave it there. Thank you. Next question will be from Ben Pham at BMO. Please go ahead. Hi. Thanks, good morning. You mentioned the strong French spot prices, and I assume that ERCOT is also helping you guys as well. I'm wondering then, have you seen any change in how your lenders view spot pricing? Are they more willing to give you more length in the debt or just take on more debt? Has there been any change from their perspective? We were able. That's the first green bond in Chile was the first to have been rated with merchant exposure. We have a mix of PPA and merchant. The lender have accepted to take those type of risks. That's a little bit of an improvement on the side. I guess if you heard me talking about the timing to sign PPA. For a while, Innergex was seen to be taking risk in being exposed in Chile in the merchant exposure. What I said at that time, remember guys, is that we could have locked PPA. It's not a problem locking PPA at low pricing. The thing is that you wanna make sure that there's a good price signal that makes sense on the long term, and then we would be willing to sign more PPA. It's just that we felt that the price was not strong enough. To answer your question, I guess that the lenders might be more willing to take merchant price exposure, but merchants are volatile, right? I mean, everybody are really happy to see what's happening in France. But you know, it's sad it takes a war to have these type of price. I mean, it's not necessarily the long-term view that this will last forever. We wanna be cautious, but we wanna be also prudent and smart in firming up some PPA down the road. I guess that in Chile, you know, we saw that the industry is becoming, in the last RFP, more disciplined. I like that. I've seen, you know, in the last few RFP in Chile, some people bidding ridiculous pricing. You know, Canadian Solar did a 24-hour blocks at $13. I mean, I don't wanna say that. But I mean, this is silly. This is really silly. This time, there were no such silly bid. You know, all the guys that are serious went over $40, you know, even $60 bids were in. I think that it shows that the industry hopefully is starting to be a little bit more disciplined. We're seeing that also in Ohio. We've seen what's happening also in other corporates are willing to buy at a reasonable price, but at a decent price. We have to make good margin. I guess to back to your question, yes, banks will probably be a little bit more flexible in terms of merchant exposure. It all depends on the type of long-term forecast you're using with those pricing. I think that we're prudent in our approach when we take the risk of merchant, when we acquire some asset. It's just a matter of making sure that you're not too optimistic and you don't put too much leverage on something that can be volatile. Okay, understood. Maybe a follow-up on your payout ratio. I'm wondering, can you remind me your adjusted payout ratio? What are your key adjustments? I know last year you had the Texas storm in 2021. Can you remind me the adjustment again? I'm not sure I understand your question. No, it's just between the adjusted payout. The adjusted payout is just a. We take out the prospective project expenses from the calculation. We took the last trailing twelve months prospective. I think it's about CAD 24 million in the last trailing. When you take that out, 'cause it's really an independent decision from management to reinvest money, so it brings down. The actual payout ratio is 82%. Then we decide to invest in prospective, which once that was done, the final payout ratio was 96%. And, also, Ben, as you can remember, our payout ratio include all our repayment of capital in all our projects. I mean, it's a real cash flow availability that we're talking about. Okay, understood. Okay, thank you. Thank you. Next question will be from Mark Jarvi at CIBC. Please go ahead. Thanks. Good morning, everyone, and thanks, Jean and Michel, for all the details through the call so far. It's been great. Jean, just going back to the free cash flow per share guidance of CAD 0.75. You talked about some of the potential upside on spot. What is baked into that assumption around the refinancing, any interest rate saving, if at all, on the refinancing in Chile? Yeah. The refinancing is baked into this number. But the thing is that the refinancing in Chile, there's a three-year interest-only period. But the effect of that is not really seen in 2022 because most of the existing debt in Chile already did their scheduled principal payment, 'cause it's semi-annual payments. What we revised is the 2022 guidance, right? At the Investor Day in September, we'll bring a bit more color again, like, to our forecast, I guess long-term forecast, and we'll then be in a better position to maybe guide you guys on the 2025 forecast, if I can say it that way. At that time, we'll make other assumptions in terms of power prices, but also inflation. The inflation is positive on us. Right now it's pretty conservative because we've assumed just a 2% inflation typical. Once we revise that for the Investor Day, we will have a bit more color for the 2023 and beyond. Mark, maybe there's something that will be a little bit hard for you guys to re-engineer is the fact that as Jean said, we hedge ourselves since the day we acquired the Aela and planned the financing. We got the net upfront cash flow of $60 million that could theoretically be amortized over the time of those loans against the interest rate. You will not see an economy on the interest rate if the interest rate has gone up. But we got $60 million upfront in the hedge strategy. We kind of benefit from this, you know, from this. It's not an interest rate saving on the loan on the amortization period of this. We got it upfront. Okay. Yeah, that's helpful. You talked about the high spot prices in Chile, and maybe you choose to bid some of your existing capacity in RFP, but are there other mechanisms by which you can lock in prices or is the RFP with the DisCos really the only avenue? Is there a hedge market down there or anything else you can do? No, there's not a hedge, but the DisCos are only a monopoly on the retail market, but then the market is completely open for small commercial and big industrial, and there's a strong market for commercial PPAs. Mining is always looking for PPAs. As a matter of fact, they have a bunch of waves of future needs. The big mining companies will have to come back to RFPs. They do their own RFPs or very small RFPs. They're on invitation. But it's even bigger than the DisCos actually. There's a big free market where you can sign PPAs. Historically, mines would agree to sign up to 10, sometimes 15 years PPAs. There's plenty of smaller commercial outfit that would sign five years PPA. The big mines, anywhere between 7% and 15%, seven and 15 years. There's a lot of opportunity. Of course, the mining these days with ESG component or pressure are looking for renewable energy supply, which we are very well positioned. Guys, the strategy in Chile has been since the beginning to have a diversified portfolio to be able to be attractive for the industrial PPA. We're very well positioned now with the wind, the hydro with some storage capacity with our hydro, remember, and also the solar with the battery. We have now the ability to be firm, to be able to deliver firm energy to these clients. Michel, how I guess maybe if there's recent transactions in the industrial PPA market, how would that compare to where you think pricing might clear on the DisCos RFP? Well, they're pretty similar actually. We have incoming calls in our office now to have other distributors that have already some contracts with mining industry that needs to fulfill that production. They're floating $48-$52. The market seems to be for 10 years, 15 years right now around that price. Remember, those DisCos and all the PPAs in Chile are usually signed with full flow-through on inflation. It's U.S. dollars. It's always U.S. dollar, both for the DisCos and for the commercial and industrial PPA. Okay. My last question is just on suppliers, OEMs, wind turbine suppliers. We hear lots of them, you know, suffering from margin supply chains. I'm sure they'd like to pass through the cost to developers like yourselves. I guess my one question is, you see high spot prices in Europe. How does that flow through other geographies? Like, is the pricing different? Do they reverse engineer your IRRs in Europe versus North America versus South America? I'm just wondering their ability to try to pass through costs and if it's different across different markets you're looking at. Well, of course they were caught with, like us, and that's why we had to go back in Hawaii and in Boswell as an example because they definitely needed to have some price adjustment. In the case of GE, remember that we had Vestas as the preferred supplier for Boswell. We used an RFP and then good negotiation to have a better price. We let go of Vestas, and we selected GE. GE had the better proposal, although it was probably higher than two years ago, the price, but the machine was better suited to Boswell. We got a good combination of reasonable increase in their price offer and higher output in terms of production. We were able to make the pain of asking a price increase from our part to PacifiCorp to be reasonable, and I think that's why PacifiCorp were willing to accept our price increase. To your point, I don't know if they are that sophisticated in the sense that the supply chain is a little bit different in the States than in Europe. The machines are not necessarily the same. GE has some specific machines for Europe and some specific machines that they prefer to deliver in the States. It would be hard for us to understand if they do this reverse engineering to ask more margin in Europe versus in the- Well, Yeah. Too much competitive pressure in my view to do reverse engineering because of the pricing. I think they manage their cost structure because of the inflation pressures the same as we would all do. They pitch their best price and It's not that. It's very different. U.S. is volume-oriented. Like Boswell, it's 300 MW. You're doing projects in France in the range of 20, 30 MW, so it's four or five machines. Where in Boswell, you get to have 100, yeah, 75, 80 machines. Not the same market, right? I couldn't say how they beat us. Okay. I guess maybe the sort of main question here is just that when you look at where power prices, PPA prices are now being able to reset your costs on the supply chain, are you seeing returns hold steady, or are you seeing opportunities to expand returns right now? It all depends, and I don't want to brag about it because, of course, our customer wouldn't be happy, but it depends, right? I mean, in some cases. In the case of Boswell, I think that our team worked really hard, and it's combination of good engineering, good selection of the turbine that help us being a little bit more competitive and perhaps increase a little bit our position in terms of return. But obviously the customer is willing to talk to you and agree, but they don't wanna be taken advantage of. So, you know, usually they want you to be fair and say, "What's your real increase in cost?" That's what HECO is trying to establish with us. They wanna see some evidence of the difference increases, and we have to document it so that they can be comfortable that we're not trying to take advantage of the situation. We're just trying to pass through the increased cost. Yeah. Maybe another way to see it also is that I think off-takers are, they understand that the risk profile will be different in the future. Like the IPPs, like Innergex, I think we are very mindful of inflationary pressures, future inflationary pressures. To sign fixed rate, no CPI, no flow-through, suddenly like, that discussion has opened up again with off-takers so that they are mindful that, you know, people will want to have a price that adjusts over time. I would say the expanding return, yes, I think in some cases, but also probably the risk profile of our off-take agreements might be different in the future as well because of what we've been through. Great. Thanks for those comments. Thank you. Next question will be from Andrew Kuske at Credit Suisse. Thanks. Good morning. I guess. Good morning. Maybe just a big picture question. When you think about the success you've had in putting projects into the advanced stage of development on a prospective basis, when you look at the regions that you started to build up, you know, Chile in particular, and just what you've done in France more recently, do you feel you're at this tipping point in certain geographies where you could maybe accelerate growth even faster than what you've laid out in the past? That's a very good question, Andrew, and I think Canada will see a lot of growth. We have forgotten about Canada, and Canada is awakening. Québec, I think I said it last time, we were surprised how fast the surplus of energy in Québec went and how fast Hydro-Québec needs new energy. I think that this is great news for us. I think that the Maritimes will also see some activities. I think the Fed in Canada will be trying to help the Maritimes reducing their carbon footprint. The Maritimes are not in good shape. I mean, they rely still on coal. They rely on very heavy diesel. They need to do something. I think that the Fed will try to equalize some payment that they're committing to the West by providing a lot of incentive for capturing carbon for oil and gas industry. They have to be fair, and they have to share the economic support for decarbonization the country. I think the Maritime will wake up as well. We're very well-positioned in New Brunswick. We have about 1,000 MW of wind site secured. We're hoping to be a player there as well. Ontario, it's just a matter of time where this market will explode in terms of need for renewable energy. Industrial customer will need You know that Ontario is one of the most heavily industrialized provinces in terms of heavy industrial footprint, and they have not done that much yet. Still the grid there relies a lot on natural gas. Ontario is poised to see a lot of growth. BC is just a matter of time when BC Hydro will start waking up to the shock with their mindset of hiding the cost of Site C, which is the disaster. Remember that Site C is 1,000 MW. It was supposed to cost CAD 8 billion. The last number they gave was CAD 16 billion, and that was before the effect of the COVID. I wouldn't be surprised to see that number going over CAD 20 billion. I hope that's the last time BC Hydro is spending the money of the taxpayer that way. They have not even taken into consideration the decarbonization of the transportation, and they're still heating the homes with natural gas. So, I think that Canada will definitely see a big comeback. The U.S., I mean, if the Biden proposal goes through, we'll see a lot of megawatt being built in the U.S., a lot of megawatt. France is a great place, and Europe is a great place as well. It's just it's difficult to develop the project. Unless France sped up the permitting process, they'll have a hard time getting the renewable energy, the new project that they are seeking and rely upon in order to meet the electricity demand. Offshore will definitely be a big play in Europe. We're not necessarily a player in the offshore, so I think we'll definitely see our focus being perhaps a little bit more on solar in France. There seems to be some willingness to ease some rules to have solar on farmlands. I think that we may see a little bit more activities in solar in France. Chile is a nice place. You know, it's a small market. We have been very active in taking advantage of very good acquisition at a good pricing. We have two hydro facility that we can develop if we can secure a long-term PPA that makes sense. We have Frontera and San Carlos. San Carlos is even more interesting. It's now getting close to being advanced stage, where we have finalized all the permitting process. It's just a matter of having the authority to go through and make their decision. It's 150 MW hydro facility with four or five hours of storage. That could be a very good tool to play in the market over there. I'm very excited about the outcome, not only for Innergex, I think for renewable energy as a whole. We haven't seen that many opportunities in the last decade. I mean, it's every jurisdiction will see very nice growth. I think that's why also we can hope to have some bargaining power in terms of pricing. I think that the market with all these opportunities will discipline itself, and we should see fair market and good returns in the deployment of these projects. Andrew, if I may add, I mean, we've never been positioned that way in the past. We've populated offices in each of these countries that Michel described with very talented people looking out for new projects. That's never. It was not like this two years, three years ago. Right now, it's poised for great growth everywhere. At the same time, I mean, I think we're positioned with like in-country offices with the right talent at the right place to do this. That's true for wind, solar, hydro, more in Chile, but also battery systems or hydrogen. I mean, we've expanded also our reach in you know in all these categories. I think it's a great intersection point like for us at this moment. We're building on this, so we're adding also to it. Yeah, so. Appreciate the color, and maybe just an extension of that. Are you at a point where you can either get better margins on some of the projects you can win, in part because of the network effect and having the boots on the ground as you just outlined, or is it more of a function of you have a higher probability to win RFPs and just win projects so that the margins might not be greater, but you just have a greater probability to, say, higher percentage ball, or is it a combination of both of those things? Well, we'll expose ourselves to more RFPs, right? Where we were more inclined to participate in the Canadian RFPs in the past, for example, now we're exposed to many more RFPs and more corporate PPAs RFPs. When you have a good site, that's where you can leverage it. For example, Palomino is in a great area of Ohio. It's very much in demand, and there aren't that many projects as advanced as this one at that specific place, right? In that sense, you can get, you know, pricing power, but it's still a very competitive market, right? We'll feel the competition in many of the other markets. When you enter a large RFP, and it's very sought after, obviously it's hard to differentiate your product, and so competitive pressures will still be there. In some cases, we can position ourselves on the grid, like with grid interconnection points that are taken up. Like it's a game of interconnection points in many cases. It's true. I think that our industry, you know, we used to be exposed to only a few RFP. If you wouldn't be able to select the project, then you had to. Wait You had to wait two, three years. Now, I think the industry is confident that if you don't win this one, next year will be another chance. I think that the industry is becoming more patient in terms of pricing. There will be just more and more opportunity. Of course, there's more competition. There's always been competition, but I think that the demand is so big these days that our job is always been complicated, but the customer needs and wants green energy. Okay. Very much appreciated. Thank you. Thank you. Next question is from Naji Baydoun at iA Capital Markets. Please go ahead. Hi, good morning. Just wanted to come back on the same sort of line of thinking, particularly in the U.S., given all the good news that we've seen recently. Just, you know, conceptually, how quickly can you accelerate your development in that market, especially all of the projects that you mentioned already on this call? Like, what's a good run rate that you think you can velocity, let's say, of development that you can hit? It's a good point. I think that the U.S. is designed to have some bigger project, you know, 200 MW, 300 MW type of project, even 400 MW solar project as Wautoma is. So at least one of those per year on a run rate would be an acceptable target for us. You know, if we're lucky, maybe one and a half or two of those. Then in France, we said we wanted to have two or three smaller project, but on a recurrent basis. That's the trend in the forecast that the team in France is building on. Chile once in a, you know, one project every now and then. Canada on the wind side, project can be 100, 200, 300 MW in some cases. If we can win one of those also, you know, it's adding up to 500, 600 MW fairly easy. It is possible. I'm not saying that it's easy to achieve, but if we win one project in all of the places we're active per year, it can add up quickly. Just on Canada and Quebec, more specifically, your development pipeline there continues to grow quite nicely. I think it went up by about 800 MW in one quarter. Is there a reason why you didn't necessarily bid more projects into the last RFP? Maybe you can give us some more color on how much you expect to be ready to bid into Yeah into the next RFP? Yeah, we were caught short a little bit, and I think the industry was caught short. Usually, Hydro-Québec RFP are usually overfilled by 3 times, 4 times, and this time was only 1.5 times. I think that the industry was not necessarily ready for that quick of an RFP. I think Hydro-Québec got the industry a little bit by surprise. We had some more project that we could have submitted. For all kinds of reason, we decided not to. We're getting really ready for the next few ones that are coming that will be bigger. Interconnection was an issue. There were some strategy by some other players that had somehow complicated the interconnection process, so that made it a little bit more difficult to bid project. I think that we adapted our strategy to it and we applied the same strategy. I think that this time next year we'll be in a much better position. Naji, there's also in Québec we've also put a lot of effort in the bilateral discussions with Hydro-Québec on. As you know, like, they wanna form a portfolio of 3,000 MW that was announced in their strategic plan, so I'm not making this up. We also pivoted that way forward where we have a good proximity with Hydro-Québec. You know, we understand what their need is, and I think that's gonna yield also great results that is not necessarily going to go through an RFP. Mm-hmm. Maybe just at a high level, if you can expand on that. In your view, what's the pros and the cons of the RFP versus the direct negotiations? The RFP, it depends which one. The RFP that the 300 MW, as an example, has stringent obligation to have local content. That could be a little bit of a challenge to meet. Bilateral negotiation with Hydro-Québec might not have this, those rules, so that could somehow be a little bit more flexible. I think a good mix because the social license in Quebec on wind rely also on the fact that a lot of economic benefit went to the local communities. I think it's important also to have that in mind in Quebec and making sure that any project that would be developed would take into consideration either First Nation or local community in the mix. Okay. On delivery also, right? In an RFP, there's a set delivery date, I guess you would like. You bid your projects for a certain date. In this case, it was 2026, so it made it maybe a bit more difficult. In the case of a bilateral, you can be more flexible. I guess the off-taker or the partner can be more flexible also in the way you procure the energy and the way you build out your phases and you bring the energy to the grid. That, that's also another advantage. Got it. That's good detail. Just maybe one last quick question. You also talked a lot about merchant power pricing exposure. I'm just wondering if you can give us an updated thoughts on Griffin Trail, just given what we've seen in Texas in the last few months or so. I think prices have almost more than doubled since last year. Does that change your view on maybe contracting a portion or all of Griffin Trail over the near term? No, Griffin Trail is the right tool for the crazy market of Texas. We like the way it is set up. We're actually very happy this year on both the volume of production and the price. For the time being, we like what we have in Griffin Trail. We have a different setup in Foard City, which has suffered a little bit on the basis and could have been a better producer in the last quarter. We like what we have. Texas is a very strange market. As you know, we've learned the hard way, and I certainly will never again be caught in being firm in Texas and exposed to basis. That's. We've done that, been there, done that. Got it. Very clear. Thank you, Michel. Thank you, Jean. Thanks. Thank you. Thank you. Your next question will be from Luca Nada at National Bank. Please go ahead. Good morning. A quick follow-up on the Texas market. Are you seeing big impacts from congestion in the market, or are you fully benefiting from the high power prices? depends what the structure, and that's what I'm referring to. PB is being plagued by congestion. It's a little bit of a sad story in the sense that, you know, just before the COVID, that region was actually needing a net importer of energy because the rig activities in that area was at their highest. Therefore, ERCOT managed to build a line and interconnect the northwest wind into that area of Odessa, as an example. Since then, the rig activity has gone down. It's picking up now, but it takes a little bit of time to have the industry oil and gas extraction being at full strength. Just to give you an example, before the COVID, there were 550 active rigs in the Odessa area. At the height of the crisis of the COVID, that has gone down to 150. Now it's back to something close to 400. By the time the demand is picking up, of course, the energy coming into the area is greater. Hence, sometimes we have economic curtailment, and sometimes we have a hard time in having ability to deliver in the South Hub, just as Jean has mentioned in the call. This is why I'm saying we don't want that anymore, ever again. ERCOT, to some degree, is less of an issue. It's just that a line around Foard City was down. It took a bit of time to rebuild it. I think that in the next few weeks this will be settled. The thing, if you want to play Texas, I think that Griffin is the right tool. We don't have any basis exposure. We don't have to produce if the price goes negative, and we can take advantage of the high-price event that we have seen. We'll be probably seeing in the next few weeks. Texas has seen some heat wave out of the ordinary. I don't know how many days. I was reading an article. I think it's 20 days over 40 degrees since the beginning of the summer. It's terrible, and it's probably going to be like that in the next few years. I mean, the global warming is affecting a lot of weather patterns, and Griffin is the tool to take advantage of that. To some degree, Foard has also some exposure. Remember that we have 300 MW of PPA as produced and 50 MW merchant in Foard. Those two are great. CB is still a little bit of our sore point in Texas. We'll be looking to fix that problem, like I said in the past, once and for all in the near future. Good. Thank you very much for the color. Switching to Chile, there's demand for new generation from DisCos. Does this mean there could be changes to your forecasted delivery under the new Aela PPA versus your initial forecast? I think you were hinting at 58% of the generation would be sold under PPA. No, that's a good point. The delivery on the DisCos are scheduled to be in 2027. If you remember in Aela, there were two components for the portion of our energy being sold under the PPA or the demand of the DisCos going up is that first, the demand is scheduled to go up. But the biggest portion was the fact that all PPAs were getting kicked out of the portfolio. They were just getting close to their expiration date. It's twofold. It's the retirement of the early PPAs that was part of the portfolio of the DisCo and also the increase of the demand from the economic recovery post COVID. That's why we had that forecast from something around 60% going to something around 85, 88% of the volume. What Jean was referring to is that it would seem to be, I would say, a slight negative aspect for Aela, having only 60% of its PPA volume being taken by the DisCo. Given the price of the market these days, the price, the spot market is higher than the PPA price, so we actually don't suffer. As Jean said, we haven't taken that into consideration in our next six months forecast guidance. We kept the original price of electricity, which was probably around $45, $50, $55. Right now, the average price that we're seeing on 24 hours, seven days a week is closer to $140. Awesome. Thank you. One last one, if I may. We saw that new French incentives would allow you to earn merchant pricing on new generating assets for 18 months just before the feed-in premium contract start. I'd like to know if this would apply to you, the two new wind farms you're building. Theoretically, yes. That's what we understand. Okay. It means you could accelerate the construction of those and try to get them to benefit from this for as long as possible? We are putting the pedal to the metal on the development side. The team in France knows what they have to do, but I mean, it's not even if you wanna go fast in France, it's not always easy. Okay. Good. Thanks for the color. I'll leave it there. Thank you. Thank you very much. Thank you. At this time, we have no further questions. Please proceed with closing remarks. All right. Thank you. Thank you very much, everybody. Yep. Thank you. Thank you. Ladies and gentlemen, this does conclude your conference call for today. Once again, thank you for attending. At this time, we do ask that you please disconnect your-