Good morning, ladies and gentlemen, and welcome to the Polaris Renewable Energy Inc. Third Quarter 2022 Earnings Conference Call. At this time, all participants have been placed on a listen-only mode, and we will open the floor for your questions and comments after the presentation. It is now my pleasure to turn the floor over to your host, Anton Jelic. Sir, the floor is yours. Thanks, John. Good morning, everyone, and welcome once again to our Q3 2022 earnings call. In addition to the press release issued earlier today, you'll find our financial statements, MD&A, and quarterly information form on both SEDAR and our corporate website, PolarisREI.com. Unless noted otherwise, all amounts referred to are denominated in US dollars. I'd like to remind you that comments made during this call may include forward-looking statements within the meaning of applicable Canadian securities legislation regarding the future performance of Polaris Renewable Energy and all its subsidiaries. These statements are current expectations, and as such, are subject to a variety of risks and uncertainties that could cause actual results to differ materially from current expectations. These risks and uncertainties include the factors discussed in the company's quarterly information form for the quarter ended September 30, 2022. I'm joined this morning, as always, by Marc Murnaghan, CEO of Polaris Renewable Energy. At this time, I'll walk through our financial highlights. Power generation. During the three months ended September 30, 2022, quarterly consolidated power production was lower than the same period in 2021 due to lower hydrology in Peru and planned major maintenance performed in Nicaragua and Peru, partly offset by the additional production from the solar project in the Dominican Republic acquired on June 28, and the hydroelectric project in Ecuador acquired on September 7. During the nine months ended September 30, power production was 475,536 megawatt-hours net, compared to 480,981 megawatt hours net in the nine months ended September 30. Due to the decrease in production at the San Jacinto facility expected from the natural decline of the reservoir. The decrease was partly offset by the increase in production as mentioned by the Peruvian facilities, coupled with production contributions by Canoa 1 and HSJM, both acquired during the nine months period ended September thirtieth. Revenue. Total revenue was $14.5 million during the three months ended September thirtieth, compared to $14.8 million in the same period last year. Total revenue of $45.8 million for the nine months ended September thirtieth, compared to $44.6 million in the same period last year. Net earnings loss. The net loss attributable to owners was $1.5 million for the three months ended September thirtieth, compared to earnings of $2.2 million for the same period in 2021. Further, the net loss attributable to owners for the nine months ended September 30 was $0.5 million, compared to net earnings of $1.4 million for the same period last year. Adjusted EBITDA. Adjusted EBITDA was $10 million for the three months ended September 30, compared to $10.9 million last year. As well, adjusted EBITDA was $33 million for the nine months ended September 30, compared to $32.7 million for the same period in 2021. Cash generation. Net cash from operating activities for the nine months ended September 30 of $20.7 million, lower than the $33.9 million for the same period last year, mainly because in the 2021 period, San Jacinto collected approximately $8 million-dollar overdue receivable balance after the sign-off of the new PPA agreement. Net cash used in investing activities for the nine months ended September 30 was $57.3 million, compared to $8.6 million in the same period in 2021. The large increase resulted from the $20.3 million cash paid for the acquisition of Emerald in the Dominican Republic and $15.2 million cash paid for the acquisition of HSJM in Ecuador, net of a total cash received of $3 million from both acquisitions. In addition, the company has funded $19.9 million for the construction of the binary project in San Jacinto and $3.4 million for solar projects in Panama. Net cash used in financing activities for the nine months ended September 30 was $24.4 million, compared to net cash provided by financing activities of $14.5 million reported in the same period in 2021. The decrease was driven by the net proceeds relating to common shares issued during the first quarter of 2021, compared to higher dividends paid in the first quarter of this year, and the net impact of the repayment of debt and refinancing completed in Nicaragua in February 2022 compared to the 2021 period. Finally, dividends. We would like to highlight that we do intend on paying our 27th consecutive quarterly dividend on November 25 of $0.15 per share to shareholders of record on November 14. This continues the board and management's commitment to regular positive distributions to shareholders, coupled with an ongoing emphasis on attractively valued accretive acquisitions. With that, I'll turn the call over to Marc, who'll elaborate on current business matters as well as on our quarter-end results. Thank you. Thanks, Anton. First starting with the quarter, this third quarter was always anticipated in terms of the EBITDA and production to be a lower, maybe call it our seasonally lowest quarter, given the maintenance in Nicaragua, and it is the dry season in Peru. Although we did come in lower than anticipated for what I'd call one-time items. In terms of actual dollar estimates that I've run, I would say the dry season in Peru cost us about $500,000. For the quarter, we originally budgeted 47 megawatts net in Nicaragua. We came in at about 45, we did talk about that a little bit in the press release due to just the two wells. It took a bit longer to recover. That was about $500,000. Then actually the bigger one was on the G&A line. Some deal costs from the acquisitions, etc., in terms of the advisory fees and legal fees of about $600,000. You're looking at about $1.6 million in costs. I would say either costs incurred or lower revenue in a quarter in terms of the net impact on EBITDA that I wouldn't consider go forward. Definitely not what we're running in our numbers going forward. Give you an example. San José de Minas in October was 51.5 net, which is right on budget. The Peru plants in terms of hydrology and production are right back on budget. You know, 8 de Agosto in October did as much production as the whole Q3. Call it, the rainy season has started in the normal fashion. That's actually more important than call it having a dry season in terms of numbers to us. We're happy with that. A few other things about the quarter, the Dominican was, I would say, as expected, and that did have a full quarter contribution, EBITDA around the $1.4 ot $1.5. San José de Minas was only about a month, so that didn't really contribute anything there, but it is running as expected. Then we did have a small carbon credit sale that brought in about $427,000 in revenue. That was actually for 2015 vintages. I'll talk a little bit about that later, but we sold that at a price of $2.30. That did come in in the quarter. I think in terms of our San José de Minas current quarter, it's gonna be a full quarter. Obviously, the DR is a full quarter. Before the binary and Panama solar, though, I think the current quarter where we're running is more indicative of call it a go-forward number. I would have that in—call it a $12.5 million range ballpark for current quarter EBITDA. That does not include the binary unit nor Pana Solar in Panama. In terms of those projects, though, the binary unit we are still looking at a COD in December, the commissioning date in December. We had spent up to about $23 million at September thirtieth. There's another $2 million, so we're expected to come in on budget for that and starting in December. Q1 should be a full quarter with the binary in it. The Pana Solar and that's the big one of the development projects. The solar in Panama is moving as expected and as budgeted as well. We're looking at end of December, potentially early January, but for commissioning. Maybe a little bit of slippage, but not much there and on budget, which is great. Those should come in. Q1 next year would be again more on the what I'd call the go-forward run rate, as I just mentioned, plus a quarter of the binary, plus a quarter of PanaSolar. And likely some carbon credits as well, which are not in those numbers that I quoted there. In terms of the other development projects that we have on the go, Canoa Two would be the most important one. That's the expansion at the site. We did 2-3 weeks ago receive what is called the definitive concession for the ability to double the capacity there. That was or is necessary in order for the offtaker and us to formally do the actual power purchase agreement. We couldn't get into the pricing and term with the offtaker until this was granted by the authority, which it has been granted. We're now actually exchanging documentation in terms of the contract, and we hope to move pretty quickly. We will given that we're gonna be starting what I'd call the very sort of early-stage small-dollar site prep designs, et cetera. That's going to start moving very quickly now, which is great. That would be called our first expansion project on the backs of the acquisitions that we announced earlier. The other one that we're gonna be starting construction on either this month or first thing in December is the small expansion, brownfield expansion project at the San José de Minas site in Ecuador, which is about a $3 million project, but we think it should increase production by about 20%-30% annually. Very good payback project, and that should be started, and we're looking at about a nine-month construction there. The other that we have yet to I would say fully define, but we'll have it by end of December in terms of what the plan is, some certain acid jobs on wells in San Jacinto. We've been assessing this with a technical consultant for the greater part of the year. We think that we have some real interesting opportunities here. Principal one being one of the wells, Well Two, where we had to use a lot of mud during drilling because it was we got a lot of steam kicks during the drilling. We're getting estimates of anywhere from 3-10 MW potential there. This is something that's you know should cost us about $750,000 to do. That is something that we will hope to have. The only thing that's left is really what is the exact way of doing it, and there's a few options, but we should have that nailed down and can communicate it to it. I think this is important because as we don't see any large program drilling at the field for years now. We do see what I'd call more typical maintenance/optimization. This will probably be the first one that we will execute to kind of validate the thought that with, call it a maintenance CapEx of, you know, 1-2 a year, we can sort of change the, you know, either sustain the 0% decline or potentially even improve the production from where we're at today, which would be very economic for us. Last thing I'll mention is the carbon credits. We did get. So 8 de Agosto a month ago was finally fully verified, so that's great. We now have what I call relatively recent credits that we can sell there, and we are in the process on three other ones, which would include the Pana Solar, actually El Carmen in Peru, and the binary unit is actually being done separately. Those should all be done. We've spent a lot of time on that. Those should be done this year. We should be entering, call it, next year with around 350,000 tons annually in terms of annual production. Where we see the market today is that that is, call it what I would call recent vintages, seem to be going for $4-$5 a ton, which I think is quite a strong signal given, you know, despite the war, despite inflation, I would have expected maybe more of a pressure on those prices, but we're not seeing that. We are seeing transactions getting done. At this point, I don't see us doing anything in Q4. Given that 8 de Agosto is done, and we have actually, at San Jacinto alone from 2017 and 2018, about 300,000 just sitting there in inventory. I think a policy for us will be just to keep working off things that are four or five years dated. As I said, we sold 2015's. Things closer to today, I think we can get four to five. I think we would start in Q1, Q2 to look at starting to sell some of that older inventory and even some of the more recent, even if we're doing small bits of it. I would think that next year in terms of, as I said, the numbers that I quote, I don't put the carbon credits in, but I would expect it to represent a larger number in terms of our total revenue next year than it did this year. That's it for my comments. We can open it up for questions now. Thank you, ladies and gentlemen. The floor is open for questions. If you have any questions or comments, please indicate so by pressing star one on your touch-tone phone. Pressing star two will remove you from the queue should your question be answered. Lastly, while posing your question, please pick up your handset if listening on speakerphone to provide optimum sound quality. Please hold while we poll for questions. Once again, that's star one if you have a question or a comment. The first question is coming from Nick Boychuk with Cormark Securities. Your line is live. Hi, Nick. Hey, thanks. Morning, Marc. Just on Nicaragua first, can you please clarify the 3-10 MW that you're looking at getting out of that additional well? That's totally new capacity that we'd be adding, right? Yeah. Yeah. This is a well that when you drill, we had a steam kick, which means steam comes, and the only way before you've cased your well, you have to basically kill it. The only way to do that is you dump a lot of mud in it, and it took us 2 weeks to kill it. Then you keep drilling. We had another one. Basically, there's a lot of mud in the formation, right? This well two only produces about 1-2 MW despite how strong these kicks were. All the data suggests that there's for sure production there. The question is, you know, how effective can your acid clean it out. The good news is because it's a very shallow production zone, and we don't need a big rig to get there. Our estimates, as I said, are anywhere from 1 to even higher than 10 megawatts. That was part of the 2017-2018 drilling campaign. Right now, as I said, it's a tiny producer, but, you know, our average well in the field is about 5, 6 megawatts now. If you assume the average, then we get, like, an extra 4, let's say. That's probably a good thing to ballpark. We just need to finalize the actual process, the actual asset, and then we can communicate it and put it in the budget, probably by the end of the year. Okay. Budget by end of the year, and then roughly in terms of construction timeline, how long do you think that would take? We would do it likely midyear, but it's a one-month process. Okay, sweet. Looking into Panama, can we get a little bit of extra color on Pana Solar Three? What are you seeing in terms of the development process, cost to develop it, and then also power price market, where merchant rates in Panama sit currently and how you're thinking about PPAs versus going full spot on those two assets. In terms of the current build. Are you talking the current one that we're building or even further? I'm thinking more Pana Solar Three. Yeah, just so fundamentally, just basically, my bad, but it's technically 2 projects what we're building just because they have 2 different generation licenses. We're doing 2 and 3 now, and we're looking at doing a few more later next year. Just let me comment first on the spot market. The trailing twelve months is around 100 dollars a megawatt hour there. We definitely have interest in contracting, although given that the first projects that we're building right now that are gonna come on, call it January 1, would only represent 2%-3% of our total production. Everything else is 100% contracted. I don't think. And we've equity funded it, so we're not rushing out to get contracts. We have started conversations with people that are interested in buying. I think we'll just start the year and call it merchant there. I run my numbers at about $85 a megawatt hour. Yeah, it's at about $100 right now, or the LTM is at about $100. Okay. In terms of the cost to get there, I think our all-in will be about $9 million. It's 12.5 megawatts DC, 10 megawatts AC, which is I think very good. We executed this project with our own sort of project management team. I think that is something we would look at do going forward. It was the same with the binary, and it will likely be the same with Canoa, too. As opposed to hiring an EPC contractor, because we see about a $0.10-$0.15 per watt difference in doing that. For the smaller or expansion projects, we think we can handle that, and it does make a big difference in terms of the net return to you. Okay, that's helpful. Thanks. In Ecuador, were you guys able to submit the bids for the 7, 20, and 27 MW projects in the October 31st auction? That's not till November eighteenth is the bid date. We are reevaluating because they did publish some prices for high-max prices. Hydro is $52. It would be maybe possible to get our returns. I think very few people are gonna bid. Immediately after that, there was a change in the minister of energy for the ministry. I think they're gonna have to redo the whole thing, quite frankly, and we're gonna come back in Q1. They've already talked about two. I think we'd be very shocked if people show up at that price. And/or they basically redo the whole thing and in Q1 it's back on track. Yeah, I don't. Our plan is really gonna be to do the expansion. We can go ahead with everything at San José de Minas, but in terms of the bidding process, it's likely gonna be more of a Q1 thing now. Okay. That's helpful. Thanks. I'll hop back in the queue. Up next, we have David Quezada with Raymond James. David, your line is live. Thanks. Morning, Marc. Maybe my first one here, just maybe a longer term question, just thinking about growth opportunities across your footprint. Obviously, you've a lot of stuff on the go right now. But just curious about what, you know, what kind of potential you see for storage across your footprint and, you know, what kind of timeline would you look at there? I suspect it's a few years out. And what would you need to see in terms of contractual underpinning for something like that? Yeah, in terms of a few years out, what I would hope that actually contractually is sooner than that in terms of having something nailed down for storage. We are actually moving ahead with a very small storage project in Peru next year, but it's pure frequency regulation, so it's not really energy storage, but it's gonna be like a 1 MWh lithium project. Again, that'll, I think, will be very good. Call it knowledge for us. It's a little baby step to do it, which actually the second one, we have a solar plus battery project in Nicaragua right now at a very small scale. We're gonna do this one in Peru, and then I think the next one will be the Dominican. We've already had conversations with them. What they told us was, we really wanted to get this definitive concession for Canoa done, which we have, and now we're gonna go move ahead with that project. On the backs of that, though, what we need to do is just change our concession, which right now it is technology specific, which is solar. Technically we need an amendment. It's not actually hard, it's just taking instead of saying solar, it says solar and batteries. We can now start that process, because we are gonna start it. The nice thing with the Dominican is that they've already published reference prices for solar projects that add storage. It's an increase, and it's a material increase. They're not definitive. They use the term preferential for a reason because they're trying to guide people. I would say that the guiding that they're doing is close to making a lot of economic sense. Not quite there. They've already had a task force that's working on it. I would hope we can have that kind of amendment in the first half of next year to say that we can do it. It would get into negotiating that price and the size. You know, how big do you need to start? Can you go sort of small-medium, or do they want you to go big? That'll be a bit of a negotiation, but it will. I think it'll literally be hopefully mid-next year, we're going into them saying, "Okay, here's the price we're willing to do, like 50 megawatt hours, 100 megawatt hours of storage on the backs of Canoa 1 and 2, and we have the land for it." That's where I would hope that we would start. Maybe it's, you know, 2-3 years in terms of the actual production. In terms of project definition contracting, I would hope it is much sooner than that. With that, I think the messaging will be that is gonna be a really big focus for the company going forward. And that our call it a key growth engine for the company is going to be storage. Absolutely. Okay. Awesome. That's great color. Thanks, Mark. Maybe just one more for me. As you look to move forward on some of your expansion projects here, like Canoa 2 and in Ecuador, just curious what you're seeing in terms of supply chain. Like, are you out looking to procure panels? I think in the past you've suggested that you know, the size of projects you're looking at, it's not too much of an issue. Just curious you know, what you're seeing there and if you see that as a hurdle in any way. We just, interestingly, recently got indicative quotes on panels and inverters, and they both were lower than what our project in Panama was done at. That's obviously good. I think what we're seeing more is it tends to be more certain parts of a project do have issues, whether it's with transportation or there is some supply chain issue. Obviously, a massive percentage of the world's goods and parts flow through China, and they are still having issues. What I would see it more as timing though, necessarily than budget at this point. That's what we're seeing. It can cause delays. That's where you need to focus more so than it's causing, call it, cost increase. I would reiterate that we don't. You know, a lot of the countries we're operating in, they aren't seeing the same type of inflation levels that you're seeing in the United States and the Western world. Okay. Excellent. Appreciate those comments, Marc. I'll turn it over. Thanks. Once again, if there are any remaining comments or questions, please indicate so by pressing star one. Up next, we have Naji Baydoun with iA Capital Markets. Your line is live. Hi. Good morning. Hey, just wanted to go back to the Panama solar projects. If I understood correctly, you're comfortable operating the projects that are gonna be completed soon on a merchant basis for now. Then maybe you think about contracting for the next ones. Like, you're. There's no rush essentially to get PPAs in the door to be able to raise that financing. That's. You're okay with the way things are for now. With the current ones, absolutely. Yeah. What about, let's say, the next tranche of projects in Panama? Yeah. It really depends on which type we're doing. We have a couple on the solar side with the same developer that we think will be ready back half of next year, as well as the hydro project that we've been working on for quite some time, and had signed a deal several years ago. It's still in our queue. It actually has their contracts. If we were to move ahead with that and go no-go on that is in the next three months, as the same company, we could use those contracts. The amount of contract that is higher than what the first solar plant would produce, and it would actually be a good percentage of the next ones. It could be a good little package, in which case we wouldn't have to get new contracts if we did it that way. If we do not do the hydro project, and we just go do, call it a few more solar, we absolutely would look for a percentage of contracting such that it just makes the financing a little bit easier, even though, again, the percentages on a pro forma basis would be quite small as a company. We would wanna raise some debt locally in the market in Panama because it is actually a great market from that perspective. You know, maybe we'd try to get 40%-50% contracted as a package when you include the new ones and the current one. Right. Okay. That makes sense. I was just thinking about if you can pull any equity out of those projects, but I guess we'll hear more about Chuspa and that in a few months. I think we would in the sense that. Let's just say all we did was the solar, and let's just say each one's $10 million and we've already spent $10 million, we could probably do the next 2 on debt using local debt, but not if it was a. If the whole package was 100% merchant. You'd probably need to get 40% contracted, and then you could. We, you know, our equity quote has already been spent and invested. Oh, exactly. Okay. That's good. Just on Canoa, too, is that maybe just give us an update on the timeline and sort of milestones to get that project moving for next year. Yeah. I think, as we said, we're now into negotiations with PPA. We're gonna start doing certain land prep immediately. I think it'll take us to be truly, like, large, you know, the full construction start probably not till April or May. Next year we will have some of the works done, so I would say I don't think we would have it for a full year for 2024, likely end of Q1 ready, 2024. I guess an FID soon and then construction, call it, you know, mid to back half of next year for 2024. Yeah. Okay. Just one last question, if I can, to go back to the Ecuador bidding. I mean, just based on publicly available information, it seems like it's gonna be competitive process with a lot of interested parties. I'm just wondering if you talked about the pricing on the hydro, which I think is gonna be about 150 megawatts. Also, I think looking to add wind and solar in that RFP. Is there any more you can say about that? Is that something they're interested in? What? Let's say they come out with the awards in Q1 next year. What would be kind of the timeline to build those projects? Just on. I don't think the wind and solar is as interesting. It's not that we wouldn't do that in Ecuador, but that really wasn't what we wanted to focus on. I think partly because I think there is a little bit more competition, I don't think I'd say it's medium competitive on those, whereas it's low to mid on the hydros. I think for us, you know, one scenario would be if the hydros don't happen, there's gonna be people that get some solar and wind and that don't have the equity capital to go ahead. We'd absolutely look to work on that. Because, you know, that whole, call it dynamic of still capital-constrained small project developers, I mean, that's not only does it exist still, it's gotten a lot worse. I think that's better for us. I think we would play more of a wait and see on those. I'm sure we would get a call on the solar and the wind. In terms of the hydro, I don't think what I think would happen on a call it project win in Q1, let's say, assuming that happens, the original thinking would have been that a hydro project comes online, call it for 2025. If you had sort of Canoa 2 plus the solar Panama and maybe the hydro kind of coming on in, call it 2024, you have the hydro 2025. I don't think that's changed, but it's probably, you know, been pushed back three to six months to mid- Okay. Mid-2025. That's very helpful, and then we'll definitely sort of be a continuation of the steady pace of growth. Okay. Focused on the hydro and maybe keeping some options open, to partner with someone else on wind or solar. Yeah. That's great. Thank you very much for the update. Okay. Up next, we have Vivek Punjabi with National Bank Financial. Your line is live. Hi, Marc. This is Vivek from National Bank on behalf of Rupert Merer. Hi, Vivek. Doing good. Thank you. I just wanted to circle back on carbon credits. I know you provided some commentary on that. But just to understand, how should we think about carbon credit sales in leading into the next year? Should we see a higher run rate pace from what was in Q3? And is the strategy more dependent on pricing for the recent verifications versus the old ones? Just would love some color on that. It was a year ago or maybe a year and a half ago. CORSIA, which is the airlines' buying consortium. It's called CORSIA. They're one of the larger ones. There's also an oil and gas one called IETA. They're big buying consortiums. I think they're in the voluntary market. They would be some of the larger buyers. A year and a half ago, well, yeah, it was 2021. CORSIA came out and said, "If it's before 2016 vintage, we're not really interested." That kind of had a bit of a demarcation line in terms of pricing. Any vintages, because, again, you don't need to sell these right away. You can inventory them. That made a bit of a demarcation line. We've gotten rid of. Now, interestingly, we were able to sell some 2015s this quarter or the past quarter at $2.30, whereas call it what I call more recent vintages, so below 5 years, are seem to be in the $4-$5 range. What I think we will do is. I would view that as a risk. I think it's great that you have these buying groups dictating a little bit as to where this market goes, as opposed to the accrediting agencies. Your risk is that they say, "Okay, now we only want things that are not 5 years, but 3 years. No more than three years dated." We still have, so for instance, at San Jacinto, some remaining inventory just for 2017 and 2018 alone is like 300,000 tons. Okay? I think what our policy will be is to start moving off older inventory to remove that risk before it kind of switches into a lower pricing environment that's being dictated. And what we're seeing in the market is the $4 or $5 is being achieved with some 2017s and 2018s because it's still within that sort of five-year thing. I think where we'll start next year is doing that. I don't think we would. Let's just say we did 300,000 next year and $4-$5, you can do the math. You know, $1.5 million. That, I don't know if I'm, I don't think I can say that's sort of a guidance, but that's at least the thinking right now. I do think the thinking is that, as I said, the fact that it's still at 4 or 5 in this environment to me suggests that, you know, to the extent we do reach any form of normalization, I think that there should be more value in these, in the even more recent vintages that have that $4 or $5. Sure. Thank you for that. Just to circle back on the Panama solar that was recently acquired, I know you said December or January, but just wanted to learn if there's any risk that it could be delayed further than probably worst case early January. The risk is, well, I think it's small. I mean, it's a smart transformer from Huawei, which is the last piece of equipment. It's supposed to be delivered the last week in November. That's the last communication we had. If that slips. Now, that just to be clear, that already is later than what we thought. If that happens, we're still good. From what I said, if that's two weeks late, it might be two weeks late. We're down to kinda one key piece of equipment from, you know, a much larger set. We think we've wrestled it down to a reasonable low risk. Yeah, so technically speaking, it could get pushed out, and it's coming down to that one. Sure. Sounds good. Thanks for that. I'll leave it there for now. Thank you. If there are any final questions or comments, please indicate so now by pressing star one. Once again, that's star one if you have a question or comment. It looks like we have a follow-up from Nick Boychuk with Cormark Securities. Your line is live. Thanks. Marc, just coming back to the 8 de Agosto maintenance, can you just kinda give us a little bit of color on what work was done at the plant? If this is gonna have to be annual moving forward and if other Run-of-the-river hydro assets in Peru are gonna require similar work? You do try to do your maintenance in the dry season, obviously. It was mostly turbine blade cleaning, was the big work, and other, what I would call more routine maintenance. I do think that this should go down a lot going forward. You know, these are not big dollar capital. It's just downtime, and you try to minimize the downtime by doing it in the dry season. I would suggest that, you know, of the two, do you call it hydrology versus maintenance? It's like 90% hydrology for the quarter, not the maintenance in terms of the difference in production. Okay. I guess a follow-up into that. Is there any read-through in terms of that weak hydrology changing what this asset should be doing in the future? No. Or was this- No. I mean, you're gonna have years that are low, you're gonna have years that are high. I mean, if you look at the nine-month basis, we're actually ahead of where we were last year, right? When it's just a quarter and it's just the dry season, you're dealing with lower numbers too, but yeah, the nine-month numbers aren't that far off. As I said, I think they're a bit better. And we're running right on budget, you know, in October. No, we don't see any reason to change our numbers. Okay. Perfect. Thank you. Once again, if there are any final questions, please indicate so by pressing star one on your touch tone phone. Okay. It appears there are no further questions in queue. Okay. Thanks, everyone. Thank you. Thank you, ladies and gentlemen. This does conclude today's conference call. You may disconnect your phone lines at this time and have a wonderful day. Thank you for your participation.