Good morning, ladies and gentlemen. Thank you for standing by. Welcome to Innergex Renewable Energy's 2021 First Quarter Results Conference Call and Webcast. At this time, all participants on the phone and internet are in listen-only mode. Following the presentation, we will conduct a question and answer session for analysis and institutional investors. Instructions will be provided at that time for you to queue for questions. If anyone has any difficulties hearing the conference, please press star followed by the 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 Karine Vachon, Senior Director of Communications. Please go ahead. Hi everyone, and thank you for joining us. 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 available as we speak on the home 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 circumstances 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 measures section of the MD&A for more information. Our speakers today will be Mr. Jean-François Neault, Chief Financial Officer, who will present the Q1 results, and Mr. Michel Letellier, President and Chief Executive Officer, who will review our operational highlights. I'll turn the conference over to Mr. Neault. Thank you, Karine. Good morning, everyone. Before we start, I would like to inform you that we have prepared a supplement of information to the first quarter report that explains in detail how the February 2021 Texas events have impacted our results. I recommend that you read that section to have a complete overview of the situation, since today I will present a summary. The supplement provides a broader set of normalized table and information on the recent proceedings. As you can see on page seven, we have four operating facilities in Texas, three of which with power hedges. All of them, to a different extent, have recorded extraordinary nodal revenues derived from higher price caused by the unprecedented weather conditions with CAD 17 million for Port City, CAD 38 million for Phoebe, CAD 15 million for Flattop, and CAD 65 million for Shannon. As we said many times before, the power hedges contain virtual hourly energy obligations, which had a negative impact of CAD 71 million for Phoebe, CAD 114 million for Flattop, and CAD 93 million for Shannon. As a result, and as previously estimated in our press release in February, the net financial impact on a consolidated basis reached precisely CAD 81.2 million. On the next page, we normalize our first quarter results to exclude the Texas impact on our revenues, Adjusted EBITDA, and our loss before income tax. As you can see, Port City and Phoebe extraordinary revenues are deducted from the revenues and Adjusted EBITDA to arrive to a normalized figures of CAD 135 million and CAD 88 million, respectively. As for the negative impact of the power and basis hedge of Phoebe, it has been deducted from the change in fair value of financial instruments, whereas the net negative impact of the Texas storm on the two joint ventures, Shannon and Flattop, have been excluded from the share of loss of joint ventures. Here, the normalized loss from joint ventures remain high at CAD 144 million due to Innergex share of the impairment charges at the project level for Shannon and Flattop. In fact, as shown on page nine, following the storm, we have seen higher risk premium on Texas investments, which has caused the discount rate to increase substantially from December 2020. Therefore, the recalculation of value in use of these assets at the project level became lower than their respective carrying value on the balance sheet. Consequently, Innergex recognized in the first quarter its share of these impairment charges as part of the share of loss of joint ventures. This share of impairment charges was capped to the maximum amount equal to our investment value of those assets on our consolidated balance sheet. Consequently, the investment value at the end of March 31st, 2021, for both assets is zero. Also, in regard to the cash settlements, it is worth mentioning that as at March 31st, 2021, the Port City CAD 17 million gain recognized during the storm and recorded as accounts receivable as at the end of February, was subsequently paid in March. The liabilities for Phoebe were not settled and are still part of the consolidated balance sheet as accounts payable. As for Shannon and Flat Top, the liabilities were not settled and remain at the project-level balance sheet, which, given it is accounted for as equity pick-up method, consequently are not included in Innergex consolidated accounts payable. Now, let me comment on recent procedures with regards to Shannon and Flat Top. As implied in the press release dated February 17, Shannon and Flat Top have filed for force majeure. In order to protect our right until the hearing on force majeure takes place, we have filed a temporary injunction to prevent Flat Top and Shannon's hedge provider to exercise its remedies on the projects. The hearing has happened on May 6th and the decision should be rendered at the latest by May 20th. Now, looking ahead, the worst-case scenario following these procedures would be the foreclosure of the projects. Should this worst-case scenario happen, the recurring negative impact to the free cash flow would be at approximately CAD 4.2 million per year until the flip point. This scenario would also mean an avoided cash outflow of CAD 76 million. In other words, under this worst-case scenario, the avoided cash outflow when compared to the minor recurring loss on free cash flow make this potential foreclosure outcome a more profitable scenario for our shareholders, given the other investment opportunities the corporation is evaluating on a recurring basis. Now, to be able to compare the results of this quarter with the same period last year, we have normalized the results to remove the impact from the Texas event. Therefore, the result that I will cover today will be on a normalized basis. On page 11, for the quarter ended March 31st, 2021, on a normalized basis, production and revenues were up 6% and 2% respectively compared to the same period last year. Adjusted EBITDA was down by 3%. This decrease was mainly attributable to a lower contribution from wind facilities in France and hydroelectric facilities in BC, both due to lower revenues and by higher OPEX over lower general admin expenses. Adjusted EBITDA Proportionate was down by 2%. On page 12, for the three-month period ended March, hydroelectric power generation segment generated CAD 14.5 million in Adjusted EBITDA, representing a 12% decrease compared to the same period last year, mainly due to lower revenue derived almost exclusively from the lower production at the facilities in British Columbia. This decrease was partly offset by higher revenue from higher production over higher operational expense at the Quebec facilities. Wind power generation segment generated CAD 82.8 million in normalized Adjusted EBITDA, representing a 2% increase compared to the same period last year. This increase was mainly attributable to the Mountain Air acquisition in 2020 and to a higher contribution from the Foard City facility due to a combined effect of higher revenues and lower OPEX. These items were partly offset by a lower contribution from the wind facility in France due to lower wind regime. Solar power generation segment generated CAD 5.9 million in normalized Adjusted EBITDA, representing a 4% increase compared to the same period last year. This increase was mainly explained by the contribution of the Salvador acquisition in 2020, partly offset by lower contribution from the Phoebe Solar facility attributable to a net unfavorable impact of lower revenues due to lower selling price. On page 30, for the quarter ended March 31st, the joint ventures and associates contributed CAD 8 million to the normalized Adjusted EBITDA Proportionate, compared with a contribution of CAD 7.5 million in the same quarter last year. This increase was mainly due to a higher contribution from the Chile facilities from a combined favorable impact of lower operating expense over lower revenue despite higher production. This increase is also explained by a higher contribution from facilities in B.C. from lower operational expenses. A higher contribution from the Shannon and Flat Top facility, mostly due to higher average selling prices, and a higher contribution of the Régie de Norville wind facility in Quebec also contributed to this increase. In addition, the proportional Production Tax Credit decreased from CAD 18.1 million to CAD 17.4 million, was due to lower Production Tax Credit earned from the lower production at Shannon and Flat Top facilities. Overall, normalized Adjusted EBITDA Proportionate decreased by 2% compared to the same period last year. The increase in long-term debt is related largely to the draws made toward the construction of the Griffin Trail project. The corporate revolving credit facility was used for reimbursing the outstanding balance of the Alterra term loan on January 11, 2021. On page 15, changes in the total assets stem mainly from the reduction in value of our investment in joint ventures and associates, as mentioned before. The change in shareholder equity is explained to the dividend declared on common and preferred share totaling CAD 32.9 million, and the total comprehensive loss of CAD 172.5 million. Shown on the next page, the normalized free cash flow has decreased by CAD 2 million on a trailing 12-month basis. The unfavorable variance in free cash flow was mainly due to an increase in principal payments stemming from the Phoebe at Port City commission in late 2019, and from the Montaner acquisition from mid-2020. The BC Hydro imposed curtailment in mid-2020, and the recovery of maintenance CapEx expenditures from the sale of HS of COP. These items were partly offset by the contribution from the Phoebe and Port City facility and from the Salvador and Montaner acquisitions, and also a decrease in interest payments on the corporate revolving credit facility concurrent with the Hydro-Québec private placement. For the trailing 12 months ended March 31st, the normalized payout ratio amounted to 140% of free cash flow, compared with 113% for the corresponding period last year. Now, before I conclude, the guidance provided in February 2021 remain relevant when compared with the normalized 2021 financial performance. At the moment, despite a lower Q1 generation, we are not revising the guidance since it is still possible to reach these projections on a normalized basis before the end of Q4. In the event that the worst case scenario materializes, we will then revise our guidance at the time. On that note, I will give the floor to Michel for the operational review of the past quarter. Thank you, Jean-François. This is the type of quarter that we would rather forget, but it is making us even more committed and resolved to execute on our growth strategy and to continue to diversify our portfolio. We will not forget, and we will make our best effort so that this type of crisis will not be recurring. We have moved away from this power hedge structure and have shown that we could develop projects differently with both Port City and Griffin Trail. Both projects could benefit from future high prices in Texas. We have lived through this Texas crisis. We have learned the hard way, but now it is time to move on. Now let's focus on the bright side of the great opportunity that lies in front of us. We have had some great news in this quarter besides the crisis and the operation, so let's try to focus on this. Well, I'm glad to report that Hillcrest, just as last night, reached the COD, commercial operation date under these long-term PPAs, so we're very proud and happy to report on this. A lot of people have worked pretty hard on this project over the last months, and it was a challenging period with the COVID and the restriction on traveling for us to go on our site. So our dedicated team did a great job, and now we can sell this electricity. 200 MW of solar is being added up to our portfolio. Congrats on our team. Very happy on this. The final construction finalization will probably be towards the end of June. From there, we'll be able to do the tax equity financial close by something in the mid-July. That would conclude the final construction and tax equity contribution. We will be then reimbursing the bridge construction to tax equity. On another good note, Yonne 2, our 6.9 MW in France, has reached, again, the full commissioning. That's another good news on that quarter. Griffin Trail, as we mentioned, is now very advanced. Actually, reading the report from our construction crews, we should be topping all the 80 MW, would be totally installed by the end of this week. They should be starting producing power by the mid-June, so that full COD could be reached by beginning of July. You mean 80 towers? Yeah, 80 towers. Thank you. What did I say? Well, anyway. 80 MW. No, no. It's 225 MW. No, no, that's true. Yeah. Sorry, the towers. So that plant should be in full operation to take advantage of the high prices in Texas in summertime. We have also resumed the work in Innavik, this hydro facility in the north of Quebec. Glad to see that this year again, we can reach these construction sites, with special health and safety precautions. We have full access to the site, construction is resuming, I would say full strength in this summer for Innavik. We still forecast the COD by the end of next year. On the development activities, we're seeing some good movement in the power prices in Chile, we're still advancing our development activities there. You probably have seen the copper prices going through the roof, which is a good thing for Peru and Chile. As you know, those two countries are big producers of copper. Although their economy has been hit hard by the COVID, the future looks bright for these two countries. We're still committed to develop project in this area. As we go through the quarters, we're getting ready for starting construction in Hawaii. We have been advancing on both permitting, construction negotiation, and final engineerings on four of these projects. The first constructions should start by the middle of next fall. Very happy also, going through these engineering and construction negotiation. I think we are learning a lot. As you know, storage is a big part of our future strategy. I think that storage coupled with battery, coupled with solar, will play a big role in many area in the world to supply future electricity. Innergex is in the forefront of that new area. We also are advancing and glad to report that we have finally signed the agreement with the supply of the battery for our Tonnerre project in France. We are the first commercial customer of Hydro-Québec division, EVLO. Pretty happy to be the first, and hopefully, some other project will follow with them. We have come together and learned a lot in our team so that this is basically some investment in time and resources, so that both team can work better in the future to develop even more project. As well, as you know, storage is a big part of our strategy. We have been talking about hydrogen, green hydrogen, and we have hired now a seasoned veteran in that business, so that we are now building our team and expertise to take advantage of future government support for green hydrogen. If we are looking at our prospective project, we are still focused on our strategy, which is developing solar and wind in the United States. I would say very encouraged by the policy that are being discussed to support future project in the United States, ITC, PTC, and kind of a PTC also for hydrogen. More local support in the state of California and Washington are being discussed to support green hydrogens in the future. I think that United States is showing a great leadership in order to have more and more renewable energy in their portfolio mix. We are seeing also in Europe that those countries, France, Germany, and others, are also supporting future renewable energy project to be part of the future mix of the electrification of this economy. Very happy to have built out a stronger and stronger presence in France. We have hired and been able now to initiate some development in solar as well in France. We have now a team that is focusing as well on solar in France, and we should see some benefit from this effort in the near future. Canada or Quebec is now being studied, and we had great news in the last couple of months. We have seen that the government of Quebec, together with Hydro-Québec, is going to put forward a call for an RFP for renewable energy, anywhere between 200 and 500 MW in the end of the year or beginning of next year. That's very positive for us. As you know, we have been working in Canada and Quebec specifically. Our team are now focusing on trying to dust off some old projects that we were working on in the past. Apparently, this is the first of a few more RFPs for the future. Things look even better and better also in our core market or own market. Basically, this is what we've been doing in the last quarter. Since we had a lot of time passed on Texas, I would open up the question. Before that, I would thank our team, Jean-François's team, that have worked hard lately, as you can imagine. These numbers have been moving around, and we have these court representations that has completed the stuff. I would like also to extend my thanks to all you, the analysts, that are going through these complicated numbers. Very happy to have you support us, and I'm opening up now the floor. Thank you. Thank you. Ladies and gentlemen, if you have a question, please press star followed by the one on your touchtone phone. You will hear a tone acknowledging your request. Your questions will be pulled in the order they are received. Please ensure you lift the handset if you're using a speakerphone before pressing any keys. Your first question comes from the line of David Quezada with Raymond James. Please go ahead, sir. Thanks. Morning, everyone. My first question here, just on the offtake agreements for Shannon and Flattop. I'm just wondering where you're at with, I guess, potentially altering or unwinding those hedge contracts, and if you've had any conversations with the tax equity providers around potentially doing that. Well, David, it's a little bit difficult to discuss these things right now. We're in the middle of trying to solve that in court. I would say, David, that if we're to reinvest in those, which is, I don't know, I wouldn't say very likely, then we would try to get rid of these things. As you've seen and heard, Jean-François, I think that the worst-case scenario we have put in front of you is that we would have write off those investments completely. Anything that could come out of these negotiations would be a little bit better than actually us writing it off completely. Absolutely. Fair enough. Thank you. Just one other question, I guess, just related to the U.S. market in general. I'm just curious about when you see some pretty encouraging trends like increased commercial and industrial demand for renewable power, the more supportive regulatory backdrop. I'm wondering if you could just talk about how things have developed or any color you can share on your earlier-stage development portfolio and maybe whatever activities in terms of securing land that you're undertaking for the next, I guess, phase of projects. No, that's fair enough. We've talked a little bit, and one of our projects, a 200 MW solar development in Ohio, have been making a little bit of a press lately. It's Palomino, that's a 200 MW solar that we are advancing. We're in the middle of the permitting and, I would say, public hearing. This thing is advancing very well. Also, we have some term sheet with offtakers that have been advanced quite a bit. This is probably the most advanced, but we're working towards our target, which is around 600 MW of solar outside Texas. We have PJM, we have Pennsylvania, Kentucky, and like I said, Ohio through I'm forgetting the name. Palomino, I'm sorry. We also are advancing in the Northwest, working as well with wind. You're seeing that we have a little bit over 400 MW worth of wind in our advanced projects. Those are also advancing. I would say that the team is building up as well in different markets. We have now a new small office in the East Coast to cover the East as well. I think that we're making good strides. Hawaii will get also a third RFP, and we're getting ready also to answer these future RFPs. Batteries opportunity are being looked with Hydro-Québec, in joint venture with Hydro-Québec. We're trying to find good spots to deploy batteries in the United States. We're focusing a lot of our activities now in the U.S. because like you're saying, there's definitely a lot of political support both on federal and state level. That's great. No, thanks, Michel. I'll get back in the queue. Thank you. Your next question comes from the line of Rupert Merer with National Bank. Please go ahead. Good morning, everyone. Good morning. Good morning. Going back to Texas, have you seen any precedents in Texas where projects have been recapitalized or recontracted? What would a scenario look like where you would consider recapitalizing your assets? Would you need just to see a change to the hedge contracts or reduced liability as well? Well, we've been trying to negotiate some discount on the total liability or the invoice. So far, the hedge provider have resisted any negotiation in discounting these invoices. Of course, if court gives us a little bit more room, and we're in front of the judge, so we're waiting for the result. Hearing had happened on May 6. The judge said that he would render his decision by May 21. If we have a positive note there, we may, Rupert, have a little bit more leverage to negotiate something else. Mind you that we have both in Shannon and Flattop, we have also partners that we would have to agree or not. If they are not willing to put more capital, we would have to come up with some kind of a resolution on how we would recapitalize these things. Tax equity would have to waive also some of their economics for us to decide to go ahead. All in all, you heard also that Jean-François has mentioned that our perceived discount rate for Texas has gone up, and therefore, we would have to see some future accretive return for us to put more money in those contracts and certainly have a different power hedge. Configuration Configuration instead of having the power hedge. It's a lot of stuff to negotiate before we could put some money. That's why we wanted to give you the perspective to all the financial community that worst case, walking away from Flat Top and Shannon, and we've written it off from our books. Anything else could be positive, I would guess. Definitely, we would be very careful before putting more capital. We never know, right? If court is giving us some wind, some headroom there to negotiate with all the stakeholders, it might make sense. Definitely, we want to focus on something else. We have a great outcome. We have great opportunities in our core market, and it's very unfortunate what we have lived through Texas, as I mentioned. Me, I've turned the page, and we're forward-looking into these great other opportunities. We will not forget, like I said. We have learned, and we're not going to put ourselves in that same situation. That's about [crosstalk] Have there been any court precedents yet in Texas that might indicate where things are headed with your projects? There have been some rulings just yet, but not the full extent that we would like. We're following others, of course. Some have gone to New York, and in New York that definitely was not very successful. The fact that two judges had take in consideration our representation, it's a little bit positive. Again, I don't want to give any hope to the market on Texas. If we win something, good. Like I said, time to move on from Texas. By the way, our hearing is in Texas. Yes. I think that if we're successful there, we might have some potential capacity to make a little bit better, but I don't want to focus on this. Myself, I've moved on. Very good. I'll get back in the queue. Thank you. Thank you. Your next question comes from the line of Sean Steuart with TD Securities. Thank you. Good morning. A couple of questions just to finish off Texas. The worst-case scenario you highlighted with the CAD 4.2 million of free cash flow until the flip point, that was based on, I think, 2020 results. Do you consider that representative of what those assets are capable of in a normal environment? We were under the impression it might be a little bit higher than that. Yes. That's a good point. I've looked backward. We never did really higher than CAD 5 million at any year since their inception in COD. Those projects also carried some shape and basis was higher than the original forecast. That's a good point. We use 4.2 until the flip point. Obviously those projects were backended in terms of cash or greater cash. You can refer to our value in use that we've disclosed for the impairment and charges with higher discount rate to have a proxy figures on the valuation we're making on those projections. That may cover a different view of the valuation if you don't like the 4.2. So far, historically, that is the best proxy we can provide that we've achieved on those projects. I think that Texas has had, in the last few years, some challenging in the basis, the risk between the node and the hub that did minimize the potential revenue of these things. I would think that over time, the transmission system, that these bases would have been reduced over time. After flip point, as we all said, tax equity with a structure where theoretically after flip point, the project doesn't have that much debt and perhaps would generate a lot more cash flow. In the latest few years, as Jean-François said, Shannon particularly has not been a big producer. Flattop, which has been commissioned, had a little bit of issue with some commissioning deficiency from Vestas. Some blade repairment were on their way also, and some upgrades on those blades were supposed to be done and actually are being done by Vestas as we speak. We're sad to potentially let these assets go. The type of commitment or financial commitment that we have to look, considering the relatively poor performance of the last few years of these assets are not putting I would say that it is not necessarily a very appealing financial proposal as we speak. Of course, we would have to do something with the existing power hedge, which might also include some more capital to be put into those projects. Also, Sean, you should remember those projects are a fixed return type of tax equity investment with movable flip dates. As we disclosed in Q4, those flip dates for Shannon and Flat Top on the back of the recent years' performance were under reassessment. The flip date always move until a certain fixed return. Just to make it clear. Lots of moving pieces. Thanks for that. Second question is there any update on the timeline for the arbitration process with BC Hydro on last year's curtailments? Yeah, we're scheduled to be early September, Sean. Okay. That's all I have for now. Thanks very much. Thank you. Your next question comes from the line of Nelson Ng with RBC Capital Markets. Great. Thanks. Just to follow up on all the Texas questions. I didn't really understand the impact on Shannon. You've written it down to zero, but the net impact for Shannon was about CAD 14 million, right? If you take your share and if you net up the revenues and the power hedges. Should we be thinking that the net impact on Shannon is CAD 14 million, but if you discount the cash flows, the net amount is zero? Am I thinking about it the right way? Okay. Just for clarification. I'm hearing some noise. I don't know if you can mute, anybody can mute for now. That changes from quarter to quarter depending on their net earnings. What has happened is the Texas farm net has decreased the investment, you have the balance. The end of March. Sorry, you're cutting off there. I can't hear you very well. No, I don't know if it's on our side, but very bad noise. It seems that there's- It sounds like it's coming from Mr. Nelson's line. Oh, you know what? Let me mute while I listen to your response. Yeah. Much better. Thank you. Yes. Put the loss of Shannon. That loss of the Texas storm, the loss has decreased the beginning value on the balance sheet of the investment value, because we take the beginning value on the investment, then we decrease it by any net earnings gain or net earnings losses. After the impairment calculation, there's a totally different view of calculating. Shannon was not having so much of a room as at December 20th when we did the impairment calculation. Now with this increase in risk premium required in Texas and the increase in discount rate, that has created that the value in use calculated is lower than the carrying value on the balance sheet of that project. It's a totally separate story than the storm and the impact from the storm on the net earnings. I don't know if you got the difference. Really what has caused the impairment is the increase in discount rate on the back of higher risk premium. This is a collateral, I would qualify the impairment as being a collateral effect of the storm because the risk premium has gone up following the storm. That has triggered for accountants to make a reassessment of the impairment calculation on those assets as at Q1, which we typically do around Q3 or Q4. I don't know if it's precise enough. I think, Jean-François, what he meant is that, since we got CAD 65 million of revenue and loss of on power hedge 93, that's CAD 28, our share is CAD 14. Exactly. I think that one of the issue with Shannon is that it had, since the beginning, when it was owned by Alterra, had performed really poorly and had accumulated also a deficit in terms of the total account owed to Citi at the time. If you take that into consideration, we would have this, well, I guess, already in this liability to overcome before the flip point occurring. When you take all this into consideration, I would agree that Shannon is perhaps on a borderline for us to decide if we put more money in or not. Flat Top is definitely more difficult or easier decision to make. Shannon, I would agree that it's on a borderline situation, and depending on the outcome, Shannon might be a little bit more attractive in terms of potential reinvestment than Flat Top. Okay, that's clear. Essentially, the Shannon net impact was CAD 14 million. Yes. Yeah What you're saying is, you're kind of borderline in terms of whether to walk away from that project or not. Yeah. Whereas Flattop, it's a more definitive decision. Yes. Okay. The next question I have is about Hawaii. I just want to ask, you've given, I guess, limited notice to proceed on a few projects. Have you locked in all the project costs for those projects where you've started construction? I guess, with much higher steel prices and all the other commodity prices, copper and everything you've highlighted as well, everything's going up, but I'm just wondering how the construction costs for Hawaii is compared to what you kind of modeled in a few years ago when you bid the projects, and also what the situation is now in terms of locking in pricing? It's a good point. It's true that a lot of pressure is on the raw material and what have you. Our team is working hard with local trade, and we also, since they're not that big of a project, we have undertaken to do internally some construction management early and manage also some supply. We wouldn't have a full EPC type for the smaller project. Also on the island, there's not that many big contractor acting on the EPC range. Our team are finalizing these contractual agreement. We will disclose, I would say, the updated numbers probably in the call of Q3 either in August or in November, and give you a little bit more detail on the future revenue and total cost. It's true that it's a little bit challenging. I guess everybody is seeing some of these pressure on pricing. We had secured the battery component and also solar panel previously. Quite a bit of those prices were fixed early on. Okay, thanks. Just one last question. In the MD&A, I know it's been going on for, I think the disclosure was there the last quarter as well, but there's been a number of financial covenants that have been kind of tripped. A lot of debt's been moved as a current liability. Can you just talk about a few of them and give a bit more color in terms of, I think it's like Mesgi’g Ugju’s’n Wind? There's a French project. There's, I think, Mountain. Yeah, Mountain Air. Air as well. Yeah. Sounds good. Can you just kind of run through some of them and say, is this something that you'll have to resolve pretty quickly or Yeah. I'll just leave it there. I will. Mesgi’g Ugju’s’n has been on this for a while because you remember Senvion went bankrupt and we had to do the self-operation. We are actually now doing the operation on Mesgi’g Ugju’s’n. Remember that we are doing self-operating all through the Gaspé Peninsula. For us, it was natural, and we hired all the prior employees of Senvion, and they are now part of our team. The issue we had was to have access to the software. Resetting keys and stuff like that that were caught into the Senvion bankruptcy. We had a hard time having this given back to us. Through all kinds of negotiation, we also found out that there were another supplier that could supply these software updates, and we have now an agreement with this new supplier. I guess that by next quarter, everything should be now in normal. We have very good relationship with the existing lenders. It was a technical default. Things will be put back in order where Innergex will do the self-operating of these assets, and it will be recognized by banks to do so, and we'll finalize the agreement with this joint venture. Remember that Mesgi’g Ugju’s’n is a joint venture with the First Nation, the Mi'kmaq from the Gaspé Peninsula. Innergex will provide the O&M service for the project. That should be finalized by the next call. Things should be back in normal. As for Mountain Air, is a little bit silly. It's an insurance commitment regarding flooding out of anywhere in high altitude. There's not that many flooding. Anyway, it was overseen when the insurance policy were put back together, and that had triggered this technical default. It's now being fixed, and I don't expect any big issue there. Then in France, remember that I spoke about Vestas' problem with blades in Flat Top. Well, we have these blade deficiencies also in France. Now Vestas has come up with repair or enhancement of their blades to make them stronger. That should also solve the issue. As you know, we have been curtailed for quite a bit by the health and safety department in France after two blades had failed. That should also be settled, those are not very material. I think that MU and Mountain Air will be fixed quickly and things should get back to normal on those. Yep. Okay, thanks. Thanks for the color. I'll leave it there and get back in queue. Thanks. Your next question comes from the line of Mark Jarvi with CIBC Capital Markets. Good morning, everyone. Hello. Yep, can you hear me? Yep. Yep. Yep, okay. Well, I'll start with the last comment and just on resolving those covenant issues. Is there cash trapped at any of the project levels that will be sort of unencumbered and come back to the top of the house once those issues are resolved in the coming quarters? MU might have some that was trapped there. Also through the Senvion bankruptcy, there were a CAD 19.5 million, CAD 19.8 million letter of credit issued in favor of the project to secure some, I would say, obligation under the construction contract and supply agreement from Senvion. Since Senvion was not able to do these modifications, we actually called on this letter of credit, and now it's been sitting in the MU account, so it didn't show in the first quarter, but it will show in the second quarter. With all that money on hand, MU has enough money to cover any, I would say, deficiencies that were identified at the COD on MU. Okay. Coming back to Shannon and Flat Top. Sounds increasingly like if it doesn't go your way-Flattop, you would walk away. Is there any penalties or anything else beyond just the foregone cash in terms of repercussions from the tax equity or your partners? I guess implications that if walking away from this project and the foreclosure, if you think it has any implications on securing tax equity in the future. Well, I think that BHE is there and Citi. We've been handling this crisis with consulting with BHE and our other partner, BlackRock and Starwood, in the case of Shannon. We're doing our best. It was pretty difficult to deal with this crisis. I don't think that any tax equity investors would take us for, I would say, give us some repercussion on other stuff. We are negotiating with Wells Fargo as we speak, for Griffin Trail and Hillcrest to finalize things. They are in Phoebe. Who can blame us, given the fact that this was an extreme weather event? Tax equity was asking to have these type of power hedge structures. It's a little bit difficult for them now to tell us that it was not a good idea. Well, I agree it was not a great idea, but they were the one who were pushing for it. In the case of Shannon, actually, we were trying to reduce the power hedge exposure for more than a year, and they were being difficult about it and so forth and so forth. When Alterra had put Shannon in COD, I think they were a little bit optimistic on the long-term forecast. Since then, we had, when we acquired Alterra, reduced this long-term forecast and wanted to reduce also the amount of supplied energy under the power hedge agreement. They were the ones who reluctantly wanted us to reduce that exposure. All in all, I don't think they can put this on us in a sense that if it doesn't make any sense for us to put more money into it, we've done what we had to do. We're acting as a good operator on sites. We've been negotiating and operating these sites as the best as we can do. Putting more capital in a structure that is a loser proposal for us, that doesn't make much sense. I don't think anybody can keep us. Accountable. Yeah. Accountable for that. You don't foresee this as you go to get more tax equity for other U.S. projects this issue limiting your ability or changing who you could partner with based on this previous history? Do you think people will look through this and it'll be quite easy to find the tax equity you need going forward? Like I said, we are now with Wells Fargo, finalizing the tax equity commitment for Hillcrest, and same thing in Griffin Trail. Like I said, we're honest with everybody. We're open book. We're doing our best to try to solve this issue. We're fighting the fight that we have to fight in court. I don't know what else we can do. Griffin Trail, Mark, is a good example of a different configuration with the tax equity that made the job. We're very happy with this. I think forward, there's ways to continue on tax equity, and I think it's clearly understood by the financial community that this is a one-off, non-recurring event. I agree with you, Michel. I don't think we're the only ones. No. Got caught in there, so. No. Jean-François, you provided a few comments around pieces of the puzzle in Texas in terms of what happened in the quarter, what happened post-quarter. If you could just fast-forward to the end of Q2, maybe just on the consolidated cash balance with Phoebe, which you seem to be able to resolve. Where will your sort of consolidated cash be? What adjustments do we have to make from quarter end? Then depending on what happens, if you walk away or don't walk away at Flat Top and Shannon, how else could that impact the proportionate or sort of cash balance for Innergex? Very good question, Mark. For Phoebe, I will save my comments because we're into discussion. Phoebe, as I mentioned, the cash settlement has not happened. The cash payment resides as at end of March within our accounts payable consolidated statements. Depending on the outcome of our discussion, in that scenario, we will have the according accounting transaction in that regards. As for Shannon and Flat Top, in a worst-case scenario, what you need to understand is for the balance sheet part, the value of those two assets, as an equity taker, is zero at the end of March. No further adjustment on the balance sheet if we foreclose on those two projects. Maybe a slight adjustment. We are carrying at a consolidated level, a cumulative translation adjustment under the AOCI, the accumulated other comprehensive income. Maybe CAD 1 million or two of adjustment that we would need to finalize on our statement. Maybe some tweaking on our deferred tax in that regard as well. Really, the foreclosure of those two projects, those projects are as a standalone. The only consolidated impact we can see on the balance sheet for those assets going foreclosed in Q2 would be limited dollar impact for other comprehensive income and maybe deferred tax. Following the forecast, let's say that we foreclose 1st of June, the earnings for April and May are ours. You will see the earnings flowing as share of gain on joint ventures for April and March, no records of additional revenues for the remaining of the year. But just to make- You follow me? Just to make sure, Mark, in the case of Flat Top-Shannon, no financial commitment or cash would be thrown to Flat Top-Shannon. Exactly. There's no recourse to Innergex on that basis. In the worst case, we just hand out the keys over there, and there's no cash that Innergex would have to send to Flat Top or Shannon. Exactly. The accounts payable reside at their project level. If they foreclose, they become the edge counterpart ownership, then it's become an interco AP and interco AR. They settle on their own, but on a consolidated basis. Even for the legal fees, legal fees have been agreed in front of the judge that those are for the Flat Top and Shannon account, and the legal fees are paid out the Flat Top and Shannon accounts. Yeah. Oh, okay. There was, again, some higher prices at parts of Q2. Is that a net benefit or again, any hedge issues there in terms of what's going on with some of those higher prices? I'll leave it there, and hopefully we won't have to be talking about that this next quarter. Mark, you're referring that the comments were made under the MD&A of higher pricing in Texas. This is comparing Q1 versus Q1 a year ago. Thank you. In parts of April, we also saw some higher prices in Texas. Yeah, you're right. Foard benefited from it, CV had a little bit of a loss on those two days. Yeah. Yeah. Nothing to compare with the other price. Great. Okay. Thanks for taking all my questions. Okay. Thank you. Your next question comes from the line of Naji Baydoun with iA Capital Markets. Hi, good morning. Just first off, appreciate all the great details on the Texas situation. Just looking forward a bit, I'd like an update on the pace of organic growth and project development. Michel, you provided good details on the Palomino project. Can you just talk about some of the other advanced U.S. solar projects that you have in the pipeline? Then maybe some more color on development activities in France, particularly now with the added focus on solar. If I start with France, we have secured now enough land for a 60-MW solar. Mind you that it's a little bit early. We have to go through all the permitting, a lot of stuff. The team on the ground did very well there. I think we have an approach that can generate a few more solar projects in the near future in that same area. I won't go too much in the details, just giving you a little bit of an update of what we're doing over there. Again, in solar, I don't want to name these type of projects just yet. Palomino is a 200-MW project, and we have a few more, ranging from 75 to 150 MW spread between Pennsylvania, Kentucky, and the Northwest. The idea is to get to around the 600 MW, like we said, by 2023, 2024, to deploy the solar panel that we had previously bought, if you remember, that are guaranteeing us the full amount of the ITC, the 30% ITC commitment. That is the strategy. The other win, I rather not to disclose too much about it just yet. We're making some good headway on, not to make a joke in the wind, but we're making a good advancement on some of those wind development as well. I mentioned also Chile, where power prices are, if you look at the latest few months, have improved. Also, the shutting down of coal has accelerated. [inaudible] just announced that they are shutting down some more coal facility in Chile. I think that we are well-positioned. The good news, I think it is Quebec, potential RFPs. One thing that the minister in Hydro-Québec has made public is the fact that they are open to an extension of at least 10 years on our existing facility. Since we are the first one to have put a wind project in the Gaspé Peninsula, our projects are going to be qualifying for this extension. Remember that we have roughly 600 MW in the Gaspé Peninsula. This is very good news for us. It would create, I would say, a positive scenario where we can think about extending this project for another 10 years with, we hope, an attractive pricing. Got it. Just to follow up on the last point, so the extension, that would be with, I suppose, minimal new investments required? No. It's just a guarantee Well, a guarantee, or a program where we can prove that under a prudent maintenance CapEx, this facility can sustain another 10 years. Mind you, that we have overtaken the self-operation in Gaspé Peninsula really early on, and our team has done a great job in managing these preemptive CapEx, and we've shown that availability of these machines. We've been really proactive in catching early defect on generator bearings. All kinds of, I would say, initiatives from our team has made these machines available, and we think the majority of them can extend their life for another 10 years. We've been very aggressive in maintaining the blades. We have been creating a lot of innovation in crack detection in blades and being proactive in repairing these little cracks. A little bit like your windshield on a car. If you have a small scratch, you can go and have them repair quite effectively and very cheaply versus waiting and seeing that crack going, then suddenly you have to change your windshield. Well, we've been in the forefront of innovation by having these very powerful camera to take a look at the blades and have the software detecting these little cracks and having a very, again, innovative way to repair it from the top of the blades and having an [inaudible] going down. Having all kinds of compounds that can be used even when it's cold in Gaspé Peninsula to repair these blades. We're very confident that these 600-MW GE machine can be extended for another 10 years without major CapEx. Appreciate the great detail. I'll leave it there. Thank you. Thanks. Your last question comes from the line of Rupert Merer with National Bank. Thank you. Just a couple quick questions. I know we're getting long in this call. A follow-up on the Québec market. You're talking about recontracting the Gaspé projects. What's the opportunity for repowering those projects at the end of those contracts? We'll have the [crosstalk] You will have? Yes. We're working on it. It's the early stage discussion with the government in Hydro-Québec. They are putting that RFP together. Theoretically, they would be open up to have an extension of 10 years and having us also bid for a repowering scenario to extend the life of these assets by another 20 or 25 years. All in all, it could be an extension of 10 years plus 20 or 25 years of new contract. For us, it's a great opportunity to enhance these existing facilities and make sure that they're in the portfolio for a very long term. Great. Thanks. Then on Griffin Trail, I think you show it still as uncontracted. Just remind us, what's the long-term plan there? Are you still evaluating potential offtakes on Griffin Trail? Well, the perfect scenario would be something close to what we have in Port City. Remember that Port City has 300 MW under PPA, as produced PPA, and 50 MW being merchant. Hopefully, in the next little while. I think that the crisis now in Texas has mixed up a little bit of the offer and demand. There will be a lot of activities in Texas regarding these potential restructuring into, you have a lot of power hedges that will be looking for potential PPAs. I don't think the next six months or so will be a good opportunity to renegotiate PPA. On the other end, maybe a lot of utility and potential also some customer might have been burned on that crisis. Who knows, Rupert? The long-term game with Griffin Trail would be to reduce a little bit the exposure on merchant. Until we finalize with Phoebe still has this power hedge. We'd love to be able to have a different structure or reduce this exposure on that power hedge. Until we do, we think that Griffin Trail is a natural hedge in that area, being 225 MW fully merchant. On the long run, we would rather see less merchant exposure. For the time being, we're perfectly happy to have Griffin Trail fully merchant. Very good. Thank you. Thanks. Ms. Vachon, there are no further questions at this time. Thank you very much. Thank you, everyone, and we'll reconvene in August. Thank you. Thank you, everybody. Thank you.